UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
 
FORM 10-K
 
(Mark One)

T
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2013

o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from __________ to_________

Commission
File Number
 
Registrants; States of Incorporation;
Address and Telephone Number
 
I.R.S. Employer
Identification Nos.
 
1-3525
 
AMERICAN ELECTRIC POWER COMPANY, INC.  (A New York Corporation)
 
13-4922640
 
1-3457
 
APPALACHIAN POWER COMPANY (A Virginia Corporation)
 
54-0124790
 
1-3570
 
INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)
 
35-0410455
 
1-6543
 
OHIO POWER COMPANY (An Ohio Corporation)
 
31-4271000
 
0-343
 
PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)
 
73-0410895
 
1-3146
 
SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation)
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 716-1000
 
72-0323455

Securities registered pursuant to Section 12(b) of the Act:

 
Registrant
 
 
Title of each class
 
Name of Each Exchange
on Which Registered
American Electric Power Company, Inc.
 
Common Stock, $6.50 par value
 
New York Stock Exchange
Appalachian Power Company
 
None
   
Indiana Michigan Power Company
 
None
   
Ohio Power Company
 
None
   
Public Service Company of Oklahoma
 
None
   
Southwestern Electric Power Company
 
None
   

Securities registered pursuant to Section 12(g) of the Act:  None

 
 

 



Indicate by check mark if the registrant American Electric Power Company, Inc. is a well-known seasoned issuer, as defined in Rule 405 on the Securities Act.
Yes   T
No   o
     
Indicate by check mark if the registrants Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company, are well-known seasoned issuers, as defined in Rule 405 on the Securities Act.
Yes   o
No   T
     
Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.
Yes   o
No   T
     
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
Yes   T
No   o
     
Indicate by check mark whether American Electric Power Company, Inc., Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company have submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
 
Yes   T
No   o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
T
 
     
Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See definitions of ‘large accelerated filer’, ‘accelerated filer’ and ‘smaller reporting company’ in Rule 12b-2 of the Exchange Act.  (Check One)
   
 
   
 
   
Large accelerated filer
T
Accelerated filer
o
Non-accelerated filer
o  (Do not check if a smaller reporting company)
Smaller reporting company o
 
Indicate by check mark whether Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers or smaller reporting companies.  See definitions of ‘large accelerated filer’, ‘accelerated filer’ and ‘smaller reporting company’ in Rule 12b-2 of the Exchange Act.  (Check One)
 
 
Large accelerated filer
o
 Accelerated filer
o
Non-accelerated filer
T  (Do not check if a smaller reporting company)
 Smaller reporting company o
 
Indicate by check mark if the registrants are shell companies, as defined in Rule 12b-2 of the Exchange Act.
Yes   o
No   T

Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) to such Form 10-K.

 
 

 


   
Aggregate Market Value of Voting and Non-Voting Common Equity Held by Non-Affiliates of the Registrants as of June 30, 2013, the Last Trading Date of the Registrants’ Most Recently Completed Second Fiscal Quarter
 
Number of Shares of Common Stock Outstanding of the Registrants at
December 31, 2013
American Electric Power Company, Inc.
 
$21,842,670,718
 
487,777,372
       
($6.50 par value)
Appalachian Power Company
 
None
 
13,499,500
       
(no par value)
Indiana Michigan Power Company
 
None
 
1,400,000
       
(no par value)
Ohio Power Company
 
None
 
27,952,473
       
(no par value)
Public Service Company of Oklahoma
 
None
 
9,013,000
       
($15 par value)
Southwestern Electric Power Company
 
None
 
7,536,640
       
($18 par value)

Note On Market Value Of Common Equity Held By Non-Affiliates

American Electric Power Company, Inc. owns all of the common stock of Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company (see Item 12 herein).

 
 

 

Documents Incorporated By Reference

Description
 
Part of Form 10-K into which Document is Incorporated
     
Portions of Annual Reports of the following companies for
the fiscal year ended December 31, 2013:
 
 
Part II
American Electric Power Company, Inc.
   
Appalachian Power Company
   
Indiana Michigan Power Company
   
Ohio Power Company
   
Public Service Company of Oklahoma
   
Southwestern Electric Power Company
   
     
Portions of Proxy Statement of American Electric Power Company, Inc. for 2014 Annual Meeting of Shareholders.
 
Part III

This combined Form 10-K is separately filed by American Electric Power Company, Inc., Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company.  Information contained herein relating to any individual registrant is filed by such registrant on its own behalf.  Except for American Electric Power Company, Inc., each registrant makes no representation as to information relating to the other registrants.

You can access financial and other information at AEP’s website, including AEP’s Principles of Business Conduct (which also serves as a code of ethics applicable to Item 10 of this Form 10-K), certain committee charters and Principles of Corporate Governance.  The address is www.AEP.com.  AEP makes available, free of charge on its website, copies of its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC.


 
 

 


TABLE OF CONTENTS
Item
     
Page
Number
     
Number
 
Glossary of Terms
i
 
Forward-Looking Information
iii
PART I
1
Business
   
   
General
 
1
   
Business Segments
14
   
Vertically Integrated Utilities
14
   
Transmission and Distribution Utilities
23
   
Generation & Marketing
24
   
AEP Transmission Holdco
27
   
AEP River Operations
30
   
Executive Officers of AEP
31
1A
Risk Factors
 
32
1B
Unresolved Staff Comments
45
2
Properties
 
45
   
Generation Facilities
45
   
Transmission and Distribution Facilities
48
   
Title to Property
48
   
System Transmission Lines and Facility Siting
49
   
Construction Program
49
   
Potential Uninsured Losses
49
3
Legal Proceedings
49
4
Mine Safety Disclosure
49
         
PART II
5
Market for Registrants’ Common Equity, Related Stockholder Matters
 
 
    and Issuer Purchases of Equity Securities
50
6
Selected Financial Data
50
7
Management’s Discussion and Analysis of Financial Condition and
 
 
    Results of Operations
50
7A
Quantitative and Qualitative Disclosures about Market Risk
50
8
Financial Statements and Supplementary Data
51
9
Changes In and Disagreements with Accountants on Accounting
 
 
    and Financial Disclosure
51
9A
Controls and Procedures
51
9B
Other Information
51
         
PART III
10
Directors, Executive Officers and Corporate Governance
52
11
Executive Compensation
52
12
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
53
13
Certain Relationships and Related Transactions and Director Independence
53
14
Principal Accounting Fees and Services
53
     
PART IV
15
Exhibits and Financial Statement Schedules
55
 
Financial Statements
55
 
Signatures
 
56
 
Index of Financial Statement Schedules
S-1
 
Reports of Independent Registered Public Accounting Firm
S-2
 
Exhibit Index
 
E-1

 
 

 

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:

Term
 
Meaning
     
AEGCo
 
AEP Generating Company, an AEP electric utility subsidiary.
AEP or Parent
 
American Electric Power Company, Inc., an electric utility holding company.
AEP East Companies
 
APCo, I&M, KPCo and OPCo.
AEP River Operations
 
AEP’s inland river transportation subsidiary, AEP River Operations LLC, operating primarily on the Ohio, Illinois and lower Mississippi rivers.
AEP System
 
American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP Utilities
 
AEP Utilities, Inc., a subsidiary of AEP, formerly, Central and South West Corporation.
AEP West Companies
 
PSO, SWEPCo, TCC and TNC.
AEPSC
 
American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AEPTCo
 
AEP Transmission Company, LLC, a subsidiary of AEPTHCo, is an intermediate holding company that owns seven wholly-owned transmission companies.
AEPTHCo
 
AEP Transmission Holding Company, LLC, a subsidiary of AEP, is an intermediate holding company that owns our transmission operations joint ventures and AEPTCo.
AFUDC
 
Allowance for Funds Used During Construction.
AGR
 
AEP Generation Resources Inc, a nonregulated AEP subsidiary that acquired the generation assets and liabilities of OPCo.
APCo
 
Appalachian Power Company, an AEP electric utility subsidiary.
APSC
 
Arkansas Public Service Commission.
Buckeye
 
Buckeye Power, Inc., a nonaffiliated corporation.
CAA
 
Clean Air Act.
CO 2
 
Carbon dioxide and other greenhouse gases.
Cook Plant
 
Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M.
CRES provider
 
Competitive Retail Electric Service providers under Ohio law that target retail customers by offering alternative generation service.
CSPCo
 
Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.
EPACT
 
The Energy Policy Act of 2005.
ERCOT
 
Electric Reliability Council of Texas regional transmission organization.
ESP
 
Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
ETT
 
Electric Transmission Texas, LLC, an equity interest joint venture between AEP and MidAmerican Energy Holdings Company Texas Transco, LLC formed to own and operate electric transmission facilities in ERCOT.
Federal EPA
 
United States Environmental Protection Agency.
FERC
 
Federal Energy Regulatory Commission.
I&M
 
Indiana Michigan Power Company, an AEP electric utility subsidiary.
Interconnection Agreement
 
An agreement by and among APCo, I&M, KPCo and OPCo, that defined the sharing of costs and benefits associated with their respective generation plants.  This agreement was terminated January 1, 2014.
IURC
 
Indiana Utility Regulatory Commission.
KGPCo
 
Kingsport Power Company, an AEP electric utility subsidiary.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
kV
 
Kilovolt.
LPSC
 
Louisiana Public Service Commission.
 
 
i

 
MISO
 
Midwest Independent Transmission System Operator.
MMBtu
 
Million British Thermal Units.
MPSC
 
Michigan Public Service Commission.
MW
 
Megawatt.
NO x
 
Nitrogen oxide.
Nonutility Money Pool
 
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
NRC
 
Nuclear Regulatory Commission.
OATT
 
Open Access Transmission Tariff, filed with FERC.
OCC
 
Corporation Commission of the State of Oklahoma.
OHTCo
 
AEP Ohio Transmission Company, Inc.
OKTCo
 
AEP Oklahoma Transmission Company, Inc.
OPCo
 
Ohio Power Company, an AEP electric utility subsidiary.
Operating Agreement
 
Agreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third party sales.  AEPSC acts as the agent.
OVEC
 
Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PJM
 
Pennsylvania – New Jersey – Maryland regional transmission organization.
PM
 
Particulate Matter.
PSO
 
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO
 
Public Utilities Commission of Ohio.
PUCT
 
Public Utility Commission of Texas.
REP
 
Texas Retail Electric Provider.
Rockport Plant
 
A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana.  AEGCo and I&M jointly-own Unit 1.  In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
RTO
 
Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine
 
Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo.
SEC
 
U.S. Securities and Exchange Commission.
SO 2
 
Sulfur dioxide.
SPP
 
Southwest Power Pool regional transmission organization.
SWEPCo
 
Southwestern Electric Power Company, an AEP electric utility subsidiary.
TA
 
Transmission Agreement, effective November 2010, among APCo, CSPCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent.
TCA
 
Transmission Coordination Agreement dated January 1, 1997, by and among, PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two public utility subsidiaries.
TCC
 
AEP Texas Central Company, an AEP electric utility subsidiary.
TNC
 
AEP Texas North Company, an AEP electric utility subsidiary.
Utility Money Pool
 
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
Virginia SCC
 
Virginia State Corporation Commission.
WPCo
 
Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC
 
Public Service Commission of West Virginia.


 
ii

 

FORWARD-LOOKING INFORMATION

This report made by AEP and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations,” but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, we undertake no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

·
The economic climate, growth or contraction within and changes in market demand and demographic patterns in our service territory.
·
Inflationary or deflationary interest rate trends.
·
Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.
·
The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
·
Electric load, customer growth and the impact of retail competition, particularly in Ohio.
·
Weather conditions, including storms and drought conditions, and our ability to recover significant storm restoration costs through applicable rate mechanisms.
·
Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·
Availability of necessary generation capacity and the performance of our generation plants.
·
Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·
Our ability to build or acquire generation capacity and transmission lines and facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are cancelled) through applicable rate cases or competitive rates.
·
New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation, cost recovery and/or profitability of our generation plants and related assets.
·
Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
·
A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers.
·
Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
·
Resolution of litigation.
·
Our ability to constrain operation and maintenance costs.
·
Our ability to develop and execute a strategy based on a view regarding prices of electricity and other energy-related commodities.
·
Prices and demand for power that we generate and sell at wholesale.
·
Changes in technology, particularly with respect to new, developing or alternative sources of generation.
·
Our ability to recover through rates or market prices any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.
·
Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas.
 
 
iii

 
·
Changes in utility regulation and the allocation of costs within regional transmission organizations, including PJM and SPP.
·
The transition to market generation in Ohio, including the implementation of ESPs.
·
Our ability to successfully and profitably manage our Ohio generation assets in a startup, nonregulated merchant business.
·
Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
·
Actions of rating agencies, including changes in the ratings of our debt.
·
The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact on future funding requirements.
·
Accounting pronouncements periodically issued by accounting standard-setting bodies.
·
Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.

The forward looking statements of AEP and its Registrant Subsidiaries speak only as of the date of this report or as of the date they are made.  AEP and its Registrant Subsidiaries expressly disclaim any obligation to update any forward-looking information.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of this report.

 
iv

 

PART I

ITEM 1.   BUSINESS

GENERAL

Overview and Description of Material Subsidiaries

AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925. It is a public utility holding company that owns, directly or indirectly, all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries.

The service areas of AEP’s public utility subsidiaries cover portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. The transmission facilities of AEP’s public utility subsidiaries are interconnected and their operations are coordinated.  Transmission networks are interconnected with extensive distribution facilities in the territories served. The public utility subsidiaries of AEP have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers. Restructuring laws in Michigan, Ohio and the ERCOT area of Texas have caused AEP public utility subsidiaries in those states to unbundle previously integrated regulated rates for their retail customers.  In Ohio, AEP’s regulated utility recently separated its generation assets from its distribution and transmission assets.

The member companies of the AEP System have contractual, financial and other business relationships with the other member companies, such as participation in the AEP System savings and retirement plans and tax returns, sales of electricity and transportation and handling of fuel. The companies of the AEP System also obtain certain accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost from a common provider, AEPSC.

As of December 31, 2013, the subsidiaries of AEP had a total of 18,521 employees. Because it is a holding company rather than an operating company, AEP has no employees. The material subsidiaries of AEP are:

APCo

Organized in Virginia in 1926, APCo is engaged in the generation, transmission and distribution of electric power to approximately 960,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. APCo owns 7,885 MW of generating capacity, including 867 MW which acquired it from OPCo in a year-end transaction.  APCo uses its generation to serve its retail and other customers.  As of December 31, 2013, APCo had 1,967 employees. Among the principal industries served by APCo are paper, rubber, coal mining, textile mill products and stone, clay and glass products. In addition to its AEP System interconnections, APCo is interconnected with the following nonaffiliated utility companies: Carolina Power & Light Company, Duke Carolina and Virginia Electric and Power Company. APCo has several points of interconnection with Tennessee Valley Authority (TVA) and has entered into agreements with TVA under which APCo and TVA interchange and transfer electric power over portions of their respective systems. APCo is a member of PJM.  APCo is part of AEP’s vertically integrated utility business segment.

I&M

Organized in Indiana in 1907, I&M is engaged in the generation, transmission and distribution of electric power to approximately 587,000 retail customers in northern and eastern Indiana and southwestern Michigan, and in supplying and marketing electric power at wholesale to other electric utility companies, rural electric cooperatives, municipalities and other market participants.  I&M owns or leases 4,518 MW of generating capacity, which it uses to serve its retail and other customers.  As of December 31, 2013, I&M had 2,582 employees. Among the principal industries served are primary metals, transportation equipment, electrical and electronic machinery, fabricated metal products, rubber and chemicals and allied products, rubber products and transportation equipment.  In addition to its AEP System interconnections, I&M is interconnected with the following nonaffiliated utility companies: Central Illinois Public Service Company, Duke Energy Ohio, Inc., Commonwealth Edison Company, Consumers Energy
 
 
1

 
Company, Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, Duke Indiana and Richmond Power & Light Company.  I&M is a member of PJM.  I&M is part of AEP’s vertically integrated utility business segment.

KPCo

Organized in Kentucky in 1919, KPCo is engaged in the generation, transmission and distribution of electric power to approximately 172,000 retail customers in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants.  KPCo owns 1,858 MW of generating capacity, including 780 MW which acquired it from OPCo in a year-end transaction.  KPCo uses its generation to serve its retail and other customers.  As of December 31, 2013, KPCo had 642 employees. Among the principal industries served are petroleum refining, coal mining and chemical production. In addition to its AEP System interconnections, KPCo is interconnected with the following nonaffiliated utility companies: Kentucky Utilities Company and East Kentucky Power Cooperative Inc.  KPCo is also interconnected with TVA.  KPCo is a member of PJM.  KPCo is part of AEP’s vertically integrated utility business segment.

KGPCo

Organized in Virginia in 1917, KGPCo provides electric service to approximately 47,000 retail customers in Kingsport and eight neighboring communities in northeastern Tennessee. KGPCo does not own any generating facilities and is a member of PJM. It purchases electric power from APCo for distribution to its customers. As of December 31, 2013, KGPCo had 57 employees. KGPCo is part of AEP’s vertically integrated utility business segment.

OPCo

Organized in Ohio in 1907 and re-incorporated in 1924, OPCo is engaged in the transmission and distribution of electric power to approximately 1,464,000 retail customers in Ohio.  OPCo purchases energy and capacity to serve remaining generation service customers.  Effective December 31, 2013, OPCo transferred all of its generation assets at net book value to AGR, a newly formed competitive generation affiliate.  As of December 31, 2013, OPCo had 1,542 employees.  Among the principal industries served by OPCo are primary metals, chemicals and allied products, health services, electronic machinery, petroleum refining, and rubber and plastic products. In addition to its AEP System interconnection, OPCo is interconnected with the following nonaffiliated utility companies: Duke Ohio, The Cleveland Electric Illuminating Company, Dayton Power and Light Company, Duquesne Light Company, Kentucky Utilities Company, Monongahela Power Company, Ohio Edison Company, The Toledo Edison Company and West Penn Power Company. OPCo is a member of PJM.  OPCo is part of AEP’s transmission and distribution utility business segment.

PSO

Organized in Oklahoma in 1913, PSO is engaged in the generation, transmission and distribution of electric power to approximately 540,000 retail customers in eastern and southwestern Oklahoma, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants.  PSO owns 4,427 MW of generating capacity, which it uses to serve its retail and other customers.  As of December 31, 2013, PSO had 1,148 employees. Among the principal industries served by PSO are paper manufacturing and timber products, natural gas and oil extraction, transportation, non-metallic mineral production, oil refining and steel processing. In addition to its AEP System interconnections, PSO is interconnected with Empire District Electric Company, Oklahoma Gas and Electric Company, Southwestern Public Service Company and Westar Energy, Inc. PSO is a member of SPP.  PSO is part of AEP’s vertically integrated utility business segment.

SWEPCo

Organized in Delaware in 1912, SWEPCo is engaged in the generation, transmission and distribution of electric power to approximately 526,000 retail customers in northeastern and panhandle of Texas, northwestern Louisiana and western Arkansas and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities, rural electric cooperatives and other market participants. SWEPCo owns 5,724 MW of generating capacity, which it uses to serve its retail and other customers.  As of December 31, 2013, SWEPCo had 1,449
 
 
2

 
employees. Among the principal industries served by SWEPCo are natural gas and oil production, petroleum refining, manufacturing of pulp and paper, chemicals, food processing and metal refining. The territory served by SWEPCo also includes several military installations, colleges and universities. SWEPCo also owns and operates a lignite coal mining operation. In addition to its AEP System interconnections, SWEPCo is interconnected with Central Louisiana Electric Company, Empire District Electric Company, Entergy Corp. and Oklahoma Gas & Electric Company. SWEPCo is a member of SPP.  SWEPCo is part of AEP’s vertically integrated utility business segment.

TCC

Organized in Texas in 1945, TCC is engaged in the transmission and distribution of electric power to approximately 806,000 retail customers through REPs in southern Texas. TCC sold all of its generation assets. As of December 31, 2013, TCC had 1,021 employees. Among the principal industries served by TCC are chemical and petroleum refining, chemicals and allied products, oil and natural gas extraction, food processing, metal refining, plastics and machinery equipment. In addition to its AEP System interconnections, TCC is a member of ERCOT. TCC is part of AEP’s transmission and distribution utility business segment.

TNC

Organized in Texas in 1927, TNC is engaged in the transmission and distribution of electric power to approximately 188,000 retail customers through REPs in west and central Texas. TNC’s generating capacity has been transferred to an affiliate at TNC’s cost pursuant to an agreement effective through 2027. As of December 31, 2013, TNC had 312 employees. Among the principal industries served by TNC are petroleum refining, agriculture and the manufacturing or processing of cotton seed products, oil products, precision and consumer metal products, meat products and gypsum products. The territory served by TNC also includes several military installations and correctional facilities. In addition to its AEP System interconnections, TNC is a member of ERCOT.  TNC is part of AEP’s transmission and distribution utility business segment.

WPCo

Organized in West Virginia in 1883 and reincorporated in 1911, WPCo provides electric service to approximately 41,000 retail customers in northern West Virginia. WPCo does not own any generating facilities. WPCo is a member of PJM. It purchases electric power from AGR for distribution to its customers. As of December 31, 2013, WPCo had 47 employees.  WPCo is part of AEP’s vertically integrated utility business segment.

AEGCo

Organized in Ohio in 1982, AEGCo is an electric generating company. AEGCo owns 2,496 MW of generating capacity.  AEGCo sells power at wholesale to AGR, I&M and KPCo. As of December 31, 2013, AEGCo had 79 employees.  AEGCo is part of AEP’s vertically integrated utility business segment.

AGR

Organized in Delaware in 2011, AGR is a nonregulated AEP subsidiary that acquired OPCo’s generation assets and liabilities at net book value as of December 31, 2013.  AGR is a competitive generation company that generates power that it sells into the market.  AGR also engages in power trading activities.  Pursuant to a Power Supply Agreement (PSA) between AGR and OPCo, AGR supplies capacity for OPCo’s switched and non-switched retail load for the period January 1, 2014 through May 31, 2015.  AGR also supplies the energy needs of OPCo’s non-switched retail load that is not acquired through auctions from January 1, 2014 through December 31, 2014 under the PSA.  AGR owns 10,002 MW of generating capacity, with rights to an additional 1,186 MW pursuant to a unit power agreement with AEGCo. As of December 31, 2013, AGR had 929 employees.  AGR is part of AEP’s Generation & Marketing business segment.

 
3

 

AEPTHCo

Organized in Delaware in 2012, AEPTHCo is a holding company for AEP’s transmission operations joint ventures.  AEPTHCo also owns AEPTCo, a holding company for seven FERC-regulated transmission-only electric utilities, each of which is geographically aligned with our existing utility operating companies. The transmission companies develop and own new transmission assets that are physically connected to AEP’s system.  Individual transmission companies have obtained the approvals necessary to operate in Indiana, Kentucky, Michigan, Ohio, Oklahoma and West Virginia, subject to any applicable siting requirements, and are authorized to submit projects for commission approval in Virginia.  Applications for transmission companies are pending with the applicable commissions in Arkansas and Louisiana.  Neither AEPTCo nor the transmission companies have any employees. Instead, AEPSC and certain of our utility subsidiaries provide the services required by these entities. AEPTCo is part of the AEP Transmission Holdco business segment.

Service Company Subsidiary

AEP also owns a service company subsidiary, AEPSC. AEPSC provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to the AEP affiliated companies. The executive officers of AEP and certain of its public utility subsidiaries are employees of AEPSC. As of December 31, 2013, AEPSC had 5,392 employees.

The following table illustrates certain regulatory information with respect to the states in which the public utility subsidiaries of AEP operate:

Jurisdiction
 
Percentage of AEP System Retail Revenues (a)
 
AEP Utility Subsidiaries Operating in that Jurisdiction
 
Authorized Return on Equity (b)
 
 
 
 
 
 
 
Ohio
 
26%
 
OPCo
 
10.2% (c)
 
 
 
 
 
 
 
Texas
 
14%
 
TCC
 
9.96%
 
 
 
TNC
 
9.96%
 
 
 
SWEPCo
 
9.65%
 
 
 
 
 
 
 
West Virginia
 
12%
 
APCo
 
10.00%
 
 
 
WPCo
 
10.00%
 
 
 
 
 
 
 
Virginia
 
13%
 
APCo
 
10.90%
 
 
 
 
 
 
 
Oklahoma
 
10%
 
PSO
 
10.15%
 
 
 
 
 
 
 
Indiana
 
10%
 
I&M
 
10.20%
 
 
 
 
 
 
 
Louisiana
 
5%
 
SWEPCo
 
10.00%
 
 
 
 
 
 
 
Kentucky
 
5%
 
KPCo
 
10.50%
 
 
 
 
 
 
 
Arkansas
 
2%
 
SWEPCo
 
10.25%
 
 
 
 
 
 
 
Michigan
 
2%
 
I&M
 
10.20%
 
 
 
 
 
 
 
Tennessee
 
1%
 
KGPCo
 
12.00%

(a)
Represents the percentage of public utility subsidiaries revenue from sales to retail customers to total public utility subsidiaries revenue for the year ended December 31, 2013.
(b)
Identifies the predominant authorized return on equity and may not include other, less significant, permitted recovery.  Actual return on equity varies from authorized return on equity.
(c)
OPCo’s authorized return on equity for distribution rates is 10.2%.  OPCo’s generation revenues are governed by its Electric Security Plan (ESP) as approved by the PUCO.

 
4

 



CLASSES OF SERVICE

The principal classes of service from which the public utility subsidiaries of AEP derive revenues and the amount of such revenues during the years ended December 31, 2013, 2012 and 2011 are as follows:

 
 
 
 
 
 
Years Ended December 31,
Description
 
2013 
 
2012 
 
2011 
 
 
(in millions)
Vertically Integrated Utilities Segment
 
 
 
 
 
 
 
 
 
 
Retail Revenues
 
 
 
 
 
 
 
 
 
 
 
Residential Sales
 
$
 3,216 
 
$
 2,993 
 
$
 3,061 
 
 
Commercial Sales
 
 
 2,002 
 
 
 1,886 
 
 
 1,884 
 
 
Industrial Sales
 
 
 2,029 
 
 
 1,951 
 
 
 1,905 
 
 
PJM Net Charges
 
 
 10 
 
 
 (25)
 
 
 (43)
 
 
Provision for Rate Refund
 
 
 (16)
 
 
 (3)
 
 
 1 
 
 
Other Retail Sales
 
 
 172 
 
 
 164 
 
 
 164 
 
 
 
Total Retail Revenues
 
 
 7,413 
 
 
 6,966 
 
 
 6,972 
 
Wholesale Revenues
 
 
 
 
 
 
 
 
 
 
 
Off-System Sales
 
 
 1,671 
 
 
 1,583 
 
 
 1,788 
 
 
Transmission
 
 
 133 
 
 
 103 
 
 
 43 
 
 
 
Total Wholesale Revenues
 
 
 1,804 
 
 
 1,686 
 
 
 1,831 
 
Other Electric Revenues
 
 
 90 
 
 
 98 
 
 
 87 
 
Other Operating Revenues
 
 
 39 
 
 
 35 
 
 
 52 
 
Sales to Affiliates
 
 
 646 
 
 
 633 
 
 
 760 
Total Revenues Vertically Integrated Utilities Segment
 
 
 9,992 
 
 
 9,418 
 
 
 9,702 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Transmission and Distribution Utilities Segment
 
 
 
 
 
 
 
 
 
 
Retail Revenues
 
 
 
 
 
 
 
 
 
 
 
Residential Sales
 
 
 2,164 
 
 
 2,121 
 
 
 2,146 
 
 
Commercial Sales
 
 
 1,161 
 
 
 1,331 
 
 
 1,435 
 
 
Industrial Sales
 
 
 549 
 
 
 821 
 
 
 1,048 
 
 
PJM Net Charges
 
 
 21 
 
 
 22 
 
 
 45 
 
 
Provision for Rate Refund
 
 
 22 
 
 
 (3)
 
 
 6 
 
 
Other Retail Sales
 
 
 39 
 
 
 41 
 
 
 40 
 
 
 
Total Retail Revenues
 
 
 3,956 
 
 
 4,333 
 
 
 4,720 
 
Wholesale Revenues
 
 
 
 
 
 
 
 
 
 
 
Off-System Sales
 
 
 31 
 
 
 57 
 
 
 34 
 
 
Transmission
 
 
 228 
 
 
 205 
 
 
 153 
 
 
 
Total Wholesale Revenues
 
 
 259 
 
 
 262 
 
 
 187 
 
Other Electric Revenues
 
 
 56 
 
 
 58 
 
 
 70 
 
Other Operating Revenues
 
 
 8 
 
 
 6 
 
 
 5 
 
Sales to Affiliates
 
 
 199 
 
 
 159 
 
 
 174 
Total Revenues Transmission and Distribution
 
 
 
 
 
 
 
 
 
 
Utilities Segment
 
 
 4,478 
 
 
 4,818 
 
 
 5,156 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Generation and Marketing Segment
 
 
 
 
 
 
 
 
 
 
Generation Revenues
 
 
 
 
 
 
 
 
 
 
 
Affiliated
 
 
 2,457 
 
 
 2,584 
 
 
 3,331 
 
 
Nonaffiliated
 
 
 314 
 
 
 282 
 
 
 258 
 
Trading, Marketing and Retail Revenues
 
 
 
 
 
 
 
 
 
 
 
Affiliated
 
 
 - 
 
 
 1 
 
 
 1 
 
 
Nonaffiliated
 
 
 868 
 
 
 572 
 
 
 278 
 
Wind Generation Revenues
 
 
 
 
 
 
 
 
 
 
 
Nonaffiliated
 
 
 26 
 
 
 28 
 
 
 27 
Total Revenues Generation and Marketing Segment
 
$
 3,665 
 
$
 3,467 
 
$
 3,895 


 
5

 



APCo
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
Description
 
2013 
 
2012 
 
2011 
 
 
 
 
 
 
(in thousands)
Retail Revenues
 
 
 
 
 
 
 
 
 
 
Residential Sales
 
$
 1,219,649 
 
$
 1,159,576 
 
$
 1,107,199 
 
Commercial Sales
 
 
 583,835 
 
 
 576,153 
 
 
 535,040 
 
Industrial Sales
 
 
 697,043 
 
 
 701,603 
 
 
 638,854 
 
PJM Net Charges
 
 
 4,998 
 
 
 (13,049)
 
 
 (23,696)
 
Other Retail Sales
 
 
 77,182 
 
 
 72,455 
 
 
 64,741 
 
 
Total Retail Revenues
 
 
 2,582,707 
 
 
 2,496,738 
 
 
 2,322,138 
Wholesale Revenues
 
 
 
 
 
 
 
 
 
 
Off-System Sales
 
 
 433,575 
 
 
 409,527 
 
 
 504,955 
 
Transmission
 
 
 21,049 
 
 
 14,059 
 
 
 (19,723)
 
 
Total Wholesale Revenues
 
 
 454,624 
 
 
 423,586 
 
 
 485,232 
Other Electric Revenues
 
 
 22,246 
 
 
 28,438 
 
 
 29,649 
 
Total Electric Generation, Transmission and Distribution Revenues
 
 
 3,059,577 
 
 
 2,948,762 
 
 
 2,837,019 
Sales to Affiliates
 
 
 347,484 
 
 
 318,199 
 
 
 358,264 
Other Revenues
 
 
 10,345 
 
 
 9,970 
 
 
 9,942 
Total Revenues
 
$
 3,417,406 
 
$
 3,276,931 
 
$
 3,205,225 

I&M
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
Description
 
2013 
 
2012 
 
2011 
 
 
 
 
 
 
(in thousands)
Retail Revenues
 
 
 
 
 
 
 
 
 
 
Residential Sales
 
$
 565,822 
 
$
 505,142 
 
$
 503,554 
 
Commercial Sales
 
 
 400,810 
 
 
 377,302 
 
 
 369,471 
 
Industrial Sales
 
 
 455,067 
 
 
 430,042 
 
 
 412,562 
 
PJM Net Charges
 
 
 3,318 
 
 
 (9,003)
 
 
 (14,485)
 
Provision for Rate Refund
 
 
 - 
 
 
 - 
 
 
 (461)
 
Other Retail Sales
 
 
 6,945 
 
 
 6,508 
 
 
 6,693 
 
 
Total Retail Revenues
 
 
 1,431,962 
 
 
 1,309,991 
 
 
 1,277,334 
Wholesale Revenues
 
 
 
 
 
 
 
 
 
 
Off-System Sales
 
 
 571,802 
 
 
 481,000 
 
 
 499,291 
 
Transmission
 
 
 4,145 
 
 
 2,092 
 
 
 (14,531)
 
 
Total Wholesale Revenues
 
 
 575,947 
 
 
 483,092 
 
 
 484,760 
Other Electric Revenues
 
 
 14,348 
 
 
 16,986 
 
 
 8,353 
 
Total Electric Generation, Transmission and Distribution Revenues
 
 
 2,022,257 
 
 
 1,810,069 
 
 
 1,770,447 
Sales to Affiliates
 
 
 341,686 
 
 
 385,460 
 
 
 429,237 
Other Revenues
 
 
 2,916 
 
 
 4,582 
 
 
 15,086 
Total Revenues
 
$
 2,366,859 
 
$
 2,200,111 
 
$
 2,214,770 

OPCo
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
Description
 
2013 
 
2012 
 
2011 
 
 
 
 
 
 
(in thousands)
Retail Revenues
 
 
 
 
 
 
 
 
 
 
Residential Sales
 
$
 1,676,138 
 
$
 1,636,808 
 
$
 1,680,179 
 
Commercial Sales
 
 
 763,820 
 
 
 945,233 
 
 
 1,077,742 
 
Industrial Sales
 
 
 468,358 
 
 
 742,235 
 
 
 979,424 
 
PJM Net Charges
 
 
 6,916 
 
 
 (18,831)
 
 
 (30,768)
 
Provision for Rate Refund
 
 
 22,091 
 
 
 (2,577)
 
 
 6,035 
 
Other Retail Sales
 
 
 15,881 
 
 
 18,113 
 
 
 17,714 
 
 
Total Retail Revenues
 
 
 2,953,204 
 
 
 3,320,981 
 
 
 3,730,326 
Wholesale Revenues
 
 
 
 
 
 
 
 
 
 
Off-System Sales
 
 
 563,040 
 
 
 661,513 
 
 
 667,593 
 
Transmission
 
 
 17,699 
 
 
 10,114 
 
 
 (26,697)
 
 
Total Wholesale Revenues
 
 
 580,739 
 
 
 671,627 
 
 
 640,896 
Other Electric Revenues
 
 
 28,281 
 
 
 29,508 
 
 
 36,008 
 
Total Electric Generation, Transmission and Distribution Revenues
 
 
 3,562,224 
 
 
 4,022,116 
 
 
 4,407,230 
Sales to Affiliates
 
 
 1,184,994 
 
 
 886,695 
 
 
 1,005,486 
Other Revenues
 
 
 15,397 
 
 
 19,385 
 
 
 18,395 
Total Revenues
 
$
 4,762,615 
 
$
 4,928,196 
 
$
 5,431,111 


 
6

 



PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
Description
 
2013 
 
2012 
 
2011 
 
 
 
 
 
 
(in thousands)
Retail Revenues
 
 
 
 
 
 
 
 
 
 
Residential Sales
 
$
 530,446 
 
$
 512,372 
 
$
 572,404 
 
Commercial Sales
 
 
 351,521 
 
 
 331,125 
 
 
 364,701 
 
Industrial Sales
 
 
 234,072 
 
 
 209,446 
 
 
 241,026 
 
Provision for Rate Refund
 
 
 - 
 
 
 - 
 
 
 (158)
 
Other Retail Sales
 
 
 73,649 
 
 
 70,894 
 
 
 78,722 
 
 
Total Retail Revenues
 
 
 1,189,688 
 
 
 1,123,837 
 
 
 1,256,695 
Wholesale Revenues
 
 
 
 
 
 
 
 
 
 
Off-System Sales
 
 
 34,636 
 
 
 37,484 
 
 
 42,241 
 
Transmission
 
 
 36,393 
 
 
 30,669 
 
 
 31,903 
 
 
Total Wholesale Revenues
 
 
 71,029 
 
 
 68,153 
 
 
 74,144 
Other Electric Revenues
 
 
 16,994 
 
 
 14,593 
 
 
 14,713 
 
Total Electric Generation, Transmission and Distribution Revenues
 
 
 1,277,711 
 
 
 1,206,583 
 
 
 1,345,552 
Sales to Affiliates
 
 
 14,246 
 
 
 22,603 
 
 
 14,192 
Other Revenues
 
 
 3,565 
 
 
 3,752 
 
 
 3,644 
Total Revenues
 
$
 1,295,522 
 
$
 1,232,938 
 
$
 1,363,388 

SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31,
Description
 
2013 
 
2012 
 
2011 
 
 
 
 
 
 
(in thousands)
Retail Revenues
 
 
 
 
 
 
 
 
 
 
Residential Sales
 
$
 586,517 
 
$
 512,578 
 
$
 554,663 
 
Commercial Sales
 
 
 472,264 
 
 
 404,204 
 
 
 411,652 
 
Industrial Sales
 
 
 316,282 
 
 
 298,604 
 
 
 288,474 
 
Provision for Rate Refund
 
 
 (16,110)
 
 
 (1,207)
 
 
 1,604 
 
Other Retail Sales
 
 
 8,360 
 
 
 8,074 
 
 
 8,118 
 
 
Total Retail Revenues
 
 
 1,367,313 
 
 
 1,222,253 
 
 
 1,264,511 
Wholesale Revenues
 
 
 
 
 
 
 
 
 
 
Off-System Sales
 
 
 294,594 
 
 
 247,118 
 
 
 259,877 
 
Transmission
 
 
 59,097 
 
 
 48,404 
 
 
 47,782 
 
 
Total Wholesale Revenues
 
 
 353,691 
 
 
 295,522 
 
 
 307,659 
Other Electric Revenues
 
 
 21,571 
 
 
 20,758 
 
 
 22,022 
 
Total Electric Generation, Transmission and Distribution Revenues
 
 
 1,742,575 
 
 
 1,538,533 
 
 
 1,594,192 
Sales to Affiliates
 
 
 51,812 
 
 
 37,441 
 
 
 57,615 
Other Revenues
 
 
 1,416 
 
 
 1,860 
 
 
 2,019 
Total Revenues
 
$
 1,795,803 
 
$
 1,577,834 
 
$
 1,653,826 

(a)
Intercompany transactions have been eliminated for the years ended December 31, 2013 , 2012 and 2011.


 
7

 


FINANCING

General

Companies within the AEP System generally use short-term debt to finance working capital needs.  Short-term debt may also be used to finance acquisitions, construction and redemption or repurchase of outstanding securities until such needs can be financed with long-term debt.  In recent history, short-term funding needs have been provided for by cash on hand, borrowing under AEP's revolving credit agreements and AEP’s commercial paper program.  Funds are made available to subsidiaries under the AEP corporate borrowing program.  Certain public utility subsidiaries of AEP also sell accounts receivable to provide liquidity.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 2013 Annual Reports, under the heading entitled Financial Condition for additional information concerning short-term funding and our access to bank lines of credit, commercial paper and capital markets.

AEP’s revolving credit agreements (which backstop the commercial paper program) include covenants and events of default typical for this type of facility, including a maximum debt/capital test and, for AEP and its significant subsidiaries, a $50 million cross-acceleration provision.  As of December 31, 2013, AEP was in compliance with its debt covenants.  With the exception of a voluntary bankruptcy or insolvency, any event of default has either or both a cure period or notice requirement before termination of the agreements.  A voluntary bankruptcy or insolvency of AEP or one of its significant subsidiaries would be considered an immediate termination event.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 2013 Annual Reports, under the heading entitled Financial Condition for additional information with respect to AEP’s credit agreements.

AEP’s subsidiaries have also utilized, and expect to continue to utilize, additional financing arrangements, such as securitization financings and leasing arrangements, including the leasing of coal transportation equipment and facilities.

ENVIRONMENTAL AND OTHER MATTERS

General

AEP’s subsidiaries are currently subject to regulation by federal, state and local authorities with regard to air and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities.  The environmental issues that we believe are potentially material to the AEP system are outlined below.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control mobile and stationary sources of air emissions.  The major CAA programs affecting our power plants are described below.  The states implement and administer many of these programs and could impose additional or more stringent requirements.

The Acid Rain Program

The 1990 Amendments to the CAA include a cap-and-trade emission reduction program for SO 2 emissions from power plants.  By 2000, the program established a nationwide cap on power plant SO 2 emissions of 8.9 million tons per year, and required further reductions in 2010.  The 1990 Amendments also contain requirements for power plants to reduce NO x emissions through the use of available combustion controls.

The success of the SO 2 cap-and-trade program encouraged the Federal EPA and the states to use it as a model for other emission reduction programs.  We continue to meet our obligations under the Acid Rain Program through the installation of controls, use of alternate fuels and participation in the emissions allowance markets.  Subsequent programs developed by the Federal EPA have imposed more stringent SO 2 and NO x emission reduction requirements than the Acid Rain Program on many of our facilities.  We have installed additional controls and taken other actions to achieve compliance with these programs.

 
8

 


National Ambient Air Quality Standards

The CAA requires the Federal EPA to review the available scientific data for criteria pollutants periodically and establish a concentration level in the ambient air for those substances that is adequate to protect the public health and welfare with an extra safety margin.  The Federal EPA also can list additional pollutants and develop concentration levels for them.  These concentration levels are known as national ambient air quality standards (NAAQS).

Each state identifies the areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (nonattainment areas).  Each state must develop a state implementation plan (SIP) to bring nonattainment areas into compliance with the NAAQS and maintain good air quality in attainment areas.  All SIPs are submitted to the Federal EPA for approval.  If a state fails to develop adequate plans, the Federal EPA develops and implements a plan.  As the Federal EPA reviews the NAAQS and establishes new concentration levels, the attainment status of areas can change and states may be required to develop new SIPs.  In 2008, the Federal EPA issued revised NAAQS for both ozone and fine particulate matter (PM 2.5 ).  The PM 2.5 standard was remanded by the D.C. Circuit Court of Appeals, and a new rule was signed by the administrator in December 2012 that lowers the annual standard.  A new ozone standard is also under development.  The Federal EPA also adopted a new short-term standard for SO 2 in 2010 , a lower standard for NO x in 2010, and a lower standard for lead in 2008.  The existing standard for carbon monoxide was retained in 2011.  The states will develop new SIPs for these standards, which could result in additional emission reductions being required from our facilities.

In 2005, the Federal EPA issued the Clean Air Interstate Rule (CAIR), which requires additional reductions in SO 2 and NO x emissions from power plants and assists states developing new SIPs to meet the NAAQS.  For additional information regarding CAIR, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues – Clean Air Act Requirements.  In August 2011, the Federal EPA issued a final rule to replace CAIR (the Cross State Air Pollution Rule (CSAPR)) that would impose new and more stringent requirements to control SO 2 and NO x emissions from fossil fuel-fired electric generating units in 27 states and the District of Columbia.  Petitions for review were filed with the U.S. Court of Appeals for the District of Columbia Circuit, and CSAPR was vacated.  That decision is currently under review by the U.S. Supreme Court. CAIR remains in effect until the Federal EPA develops a replacement rule.  For additional information regarding CSAPR, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues – Clean Air Act Requirements.

Hazardous Air Pollutants

As a result of the 1990 Amendments to the CAA, the Federal EPA investigated hazardous air pollutant (HAP) emissions from the electric utility sector and submitted a report to Congress, identifying mercury emissions from coal-fired power plants as warranting further study.  In 2011, the Federal EPA issued a final rule setting Maximum Achievable Control Technology (MACT) standards for new and existing coal and oil-fired utility units and New Source Performance Standards (NSPS) for emissions from new and modified power plants.  For additional information regarding MACT, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues – Clean Air Act Requirements.

Regional Haze

The CAA establishes visibility goals for certain federally designated areas, including national parks, and requires states to submit SIPs that will demonstrate reasonable progress toward preventing impairment of visibility in these areas (Regional Haze program).  In 2005, the Federal EPA issued its Clean Air Visibility Rule (CAVR), detailing how the CAA’s best available retrofit technology requirements will be applied to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.

PSO is in the process of implementing a settlement with the Federal EPA in order to comply with the Regional Haze program requirements in that state.  For additional information regarding CAVR and the Regional Haze program requirements, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues – Clean Air Act Requirements.

 
9

 


CO 2 Regulation

In the absence of comprehensive climate change legislation, the Federal EPA has taken action to regulate CO 2 emissions under the existing requirements of the CAA.  Such actions are being legally challenged by numerous parties.  For additional information regarding the Federal EPA action taken to regulate CO 2 emissions, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues – Clean Air Act Requirements.

Our fossil fuel-fired generating units are large sources of CO 2 emissions.  If substantial CO 2 emission reductions are required, there will be significant increases in capital expenditures and operating costs which would hasten the ultimate retirement of older, less-efficient, coal-fired units.  To the extent we install additional controls on our generation plants to limit CO 2 emissions and receive regulatory approvals to increase our rates, return on capital investment would have a positive effect on future earnings.  Prudently incurred capital investments made by our subsidiaries in rate-regulated jurisdictions to comply with legal requirements and benefit customers are generally included in rate base for recovery and earn a return on investment.  We would expect these principles to apply to investments made to address new environmental requirements.  However, requests for rate increases reflecting these costs can affect us adversely because our regulators could limit the amount or timing of increased costs that we would recover through higher rates. For our sales of energy based on market rate authority, however, there is no such recovery mechanism.

Several states have adopted programs that directly regulate CO 2 emissions from power plants, but none of these programs are currently in effect in states where we have generating facilities.  Some of our states have established mandatory or voluntary programs to increase the use of energy efficiency, alternative energy, or renewable energy sources (Arkansas, Indiana, Louisiana, Michigan, Ohio, Oklahoma, Texas, Virginia, and West Virginia).  We are taking steps to comply with these requirements primarily through entering into power supply agreements giving us access to power generated by wind turbines.  Federal EPA has been consulting with states to see whether and how such programs might become part of a CO 2 emission reduction program for existing utility generating units.  For additional information, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues – Clean Air Act Requirements.
 
Clean Water Act Requirements
 
Our operations are also subject to the Federal Clean Water Act, which prohibits the discharge of pollutants into waters of the United States except pursuant to appropriate permits, and regulates systems that withdraw surface water for use in our power plants.  In April 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement.  Compliance with this standard is required within eight years of the effective date of the final rule.  The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment.  We submitted comments on this proposal and we expect the Federal EPA to issue revised rules in 2014.

The Federal EPA is also engaged in rulemaking to update the technology-based standards that govern discharges from new and existing power plants under the Clean Water Act’s National Pollutant Discharge Elimination System program.  These standards were last updated over 20 years ago, and the Federal EPA has issued two rounds of information collection requests to inform its rulemaking.  In October 2009, the Federal EPA issued a final report for the power plant sector and determined that revisions to its existing standards are necessary.  The Federal EPA  proposed revised standards in 2013.  For additional information, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues.

Coal Ash Regulation

Our operations produce a number of different coal combustion products, including fly ash, bottom ash, gypsum and other materials. The Federal EPA completed an extensive study of the characteristics of coal ash in 2000 and concluded that combustion wastes do not warrant regulation as hazardous waste.  In December 2008, the breach of a dike at the Tennessee Valley Authority’s Kingston Station resulted in a spill of several million cubic yards of ash
 
 
10

 
into a nearby river and onto private properties, prompting federal and state reviews of ash storage and disposal practices at many coal-fired electric generating facilities, including ours.  AEP operates 37 ash ponds and we manage these ponds in a manner that complies with state and local requirements, including dam safety rules designed to assure the structural integrity of these facilities.  We also operate a number of dry disposal facilities in accordance with state standards, including ground water monitoring and other applicable standards.  In June 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units.  For additional information regarding the Federal EPA action taken to regulate the disposal and beneficial re-use of coal combustion residuals and the potential impact on our operations, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues – Coal Combustion Residual Rule.

Climate Change – Position and Strategy

We continue to support a federal legislative approach to energy policy as the most effective means of reducing emissions of  CO 2 and other greenhouse gases (generally referred to as CO 2 ) that recognizes that a reliable and affordable electricity supply is vital to economic recovery and growth.  We do not believe regulating CO 2 emissions under the Clean Air Act is the appropriate solution.  During the past decade, we have taken voluntary actions to reduce and offset our CO 2 emissions.  Unfortunately, two of the voluntary programs that helped businesses such as AEP to set quantitative commitments no longer exist.  The Federal EPA’s Climate Leaders Program and the Chicago Climate Exchange both ended their reduction obligations at the end of 2010.  However, through these programs and others, we voluntarily reduced our CO 2 emissions by approximately 96 million metric tons during the 2003 to 2010 period.

We expect our emissions to continue to decline over time as we diversify our generating sources and operate fewer coal units.  The projected decline in coal-fired generation is due to a number of factors, including the ongoing cost of operating older units, the relative cost of coal and natural gas as fuel sources, increasing environmental regulations requiring significant capital investments and changing commodity market fundamentals.  Our strategy for this transformation is to protect the reliability of the electric system and reduce our emissions by pursuing multiple options.  These include diversifying our fuel portfolio and generating more electricity from natural gas, increasing energy efficiency and investing in renewable resources, where there is regulatory support.  Meanwhile, the Federal EPA began regulating CO 2 emissions from large stationary sources such as power plants in 2012 under the New Source Review prevention of significant deterioration and Title V operating permit programs.

In September 2013, the Federal EPA reproposed a Carbon Pollution Standard for New Power Plants. This regulation, based on EPA authority under section 111(b) of the Clean Air Act, would establish New Source Performance Standards for CO 2 for new fossil-fueled-fired electric generating units.  The proposed regulation would limit the ability to construct new coal-fired facilities in the future due to strict emission limits if they are finalized. AEP does not currently have plans to permit or construct any new coal-fired facilities and the proposed rule does not directly impact existing facilities. The EPA is scheduled to propose standards, regulations or guidelines, as appropriate, for CO 2 from existing fossil fuel units in June 2014, though the scope and extent of the standards is currently unknown.

For additional information on legislative and regulatory responses to greenhouse gases, including limitations on CO 2 emissions, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the headings entitled Environmental Issues – Climate Change.  Specific steps taken to reduce CO 2 emissions include the following:

Renewable Sources of Energy

Some of the states we serve have established mandatory or voluntary programs to increase the use of energy efficiency, alternative energy, or renewable energy sources (Arkansas, Indiana, Louisiana, Michigan, Ohio, Oklahoma, Texas, Virginia and West Virginia).  At the end of 2013 and in support of our goals or requirements, our operating companies had long-term contracts for 1,984 MW of wind and 10 MW of solar power. When additional contracts for projects under construction and/or pending regulatory approval are added and netted against one wind contract that is expiring at the end of 2015, the total renewable portfolio will be 2,698 MW to serve our regulated operating company customers.  We actively manage our compliance position and are on pace to meet the relevant requirements or benchmarks in each applicable jurisdiction.

 
11

 


End Use Energy Efficiency

In 2008, AEP ramped up efforts to reduce energy consumption and peak demand through the introduction of additional energy efficiency and demand response programs.  These programs, commonly and collectively referred to as demand side management, were implemented in jurisdictions where appropriate cost recovery was available.  Since that time, AEP Operating Companies have implemented over 100 programs across the AEP service territory and in most of the states we serve.  For the period 2008 through 2013, these programs have reduced annual consumption by over 4,000,000 megawatt hours and peak demand by over 1,200 MW.  To achieve these levels, AEP Operating Companies invested approximately $540 million during the same period.   These results are preliminary and subject to independent third party evaluation and verification of savings, as required.

Energy efficiency and demand reduction programs have received regulatory support in most of the states we serve, and appropriate cost recovery will be essential for us to continue and expand these consumer offerings. Appropriate recovery of program costs, lost revenues, and an opportunity to earn a reasonable return ensures that energy efficiency programs are considered equally with supply side investments.  Going forward, we will work closely with regulators to ensure that plans are in place to meet specific regulatory and legislative energy efficiency and/or demand reduction targets present in the respective jurisdictions.

Current and Projected CO 2 Emissions

Our total CO 2 emissions in 2012 (not including our ownership in the Kyger Creek and Clifty Creek plants) were approximately 122 million metric tons.  Our 2013 emissions decreased to approximately 114  million metric tons.  We expect overall increases in CO 2 emissions during the next few years to be small, if any, as our sales and generation rebound somewhat from recession lows in 2009.  However, over much of the remainder of the decade we expect emissions to decline as modest sales growth is offset by retirements of older, less efficient coal-fired units and increased utilization of natural gas.

Corporate Governance

In response to environmental issues and in connection with its assessment of our strategic plan, our Board of Directors continually reviews the risks posed by our actions.  The Board of Directors is informed of any new material issues, including changes to environmental regulations and proposed legislation that could affect the Company.  The Board’s Committee on Directors and Corporate Governance oversees the Company’s annual Corporate Accountability Report, which includes information about the Company’s environmental, financial and social performance.

Other Environmental Issues and Matters

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 imposes costs for environmental remediation upon owners and previous owners of sites, as well as transporters and generators of hazardous material disposed of at such sites.  See Note 6 to the consolidated financial statements entitled Commitments, Guarantees and Contingencies, included in the 2013 Annual Reports, under the heading entitled The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation for further information.

Environmental Investments

Investments related to improving AEP System plants’ environmental performance and compliance with air and water quality standards during 2011, 2012 and 2013 and the current estimates for 2014, 2015 and 2016 are shown below, in each case excluding equity AFUDC.  Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends and the ability to access capital.  AEP expects to make substantial investments in future years in addition to the amounts set forth below in connection with the modification and addition of facilities at generation plants for environmental quality controls.  Such future investments are needed in order to comply with air and water quality standards that have been adopted and have deadlines for compliance after 2013 or have been proposed and may be adopted.  Future investments could be significantly greater if emissions reduction requirements are accelerated or otherwise become more onerous or if CO 2 becomes regulated at existing facilities.  The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the AEP System.  We typically recover costs of complying with environmental standards from
 
 
12

 
customers through rates in regulated jurisdictions.  For our sales of energy based on market rate authority, however, there is no such recovery mechanism.  Failure to recover these costs could reduce our future net income and cash flows and possibly harm our financial condition.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading entitled Environmental Issues and Note 6 to the consolidated financial statements, entitled Commitments, Guarantees and Contingencies, included in the 2013 Annual Reports, for more information regarding environmental expenditures in general.

Historical and Projected Environmental Investments
                                   
   
2011
 
2012
 
2013
 
2014
 
2015
 
2016
   
Actual
 
Actual
 
Actual
 
Estimate
 
Estimate
 
Estimate
                         
   
(in thousands)
Total AEP (a)
$
186,800
 
$
235,400
 
$
415,000
 
$
588,000
 
$
644,000
 
$
447,000
APCo
 
68,900
   
50,800
   
44,500
   
48,000
   
67,000
   
68,000
I&M
 
5,900
   
30,400
   
27,300
   
55,000
   
42,000
   
52,000
OPCo (b)
 
63,000
   
66,200
   
123,900
   
-
   
-
   
-
PSO
 
6,500
   
26,100
   
55,500
   
66,000
   
75,000
   
49,000
SWEPCo
 
11,000
   
23,800
   
134,000
   
217,000
   
312,000
   
118,000
 
 
(a) Includes expenditures of the subsidiaries shown and other subsidiaries not shown. The figures reflect construction expenditures, not investments in subsidiary companies.  Excludes discontinued operations.
(b) Estimates for 2014, 2015 and 2016 reflect the transfer of all of OPCo generation assets which occurred on December 31, 2013.
 
Electric and Magnetic Fields (EMF)

EMF are found everywhere there is electricity.  Electric fields are created by the presence of electric charges.  Magnetic fields are produced by the flow of those charges.  This means that EMF are created by electricity flowing in transmission and distribution lines, electrical equipment, household wiring and appliances.  A number of studies in the past have examined the possibility of adverse health effects from EMF.  While some of the epidemiological studies have indicated some association between exposure to EMF and health effects, none has produced any conclusive evidence that EMF does or does not cause adverse health effects.

Management cannot predict the ultimate impact of the question of EMF exposure and adverse health effects.  If further research shows that EMF exposure contributes to increased risk of cancer or other health problems, or if the courts conclude that EMF exposure harms individuals and that utilities are liable for damages, or if states limit the strength of magnetic fields to such a level that the current electricity delivery system must be significantly changed, then the results of operations and financial condition of AEP and its operating subsidiaries could be materially affected unless these costs can be recovered from customers.


 
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BUSINESS SEGMENTS

During the fourth quarter of 2013, we realigned our business segments as a result of corporate separation and plant transfers.  See Note 9 to the consolidated financial statements entitled Business Segments, included in the 2013 Annual Reports, for additional information on our operating segments.  Our reportable segments and their related business activities are outlined below:

Vertically Integrated Utilities

·  
Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

·  
Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC.
·  
OPCo purchases energy and capacity to serve remaining generation service customers.

Generation & Marketing

·  
Nonregulated generation in ERCOT and PJM.
·  
Marketing, risk management and retail activities in ERCOT, PJM and MISO.

AEP Transmission Holdco

·  
Development, construction and operation of transmission facilities through investments in our wholly-owned transmission only subsidiaries and transmission only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.

AEP River Operations

·  
Commercial barging operations that transport liquid, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.

VERTICALLY INTEGRATED UTILITIES

GENERAL

AEP’s vertically integrated utility operations are engaged in the generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.  AEPSC, as agent for AEP’s public utility subsidiaries, performs marketing, generation dispatch, fuel procurement and power-related risk management and trading activities on behalf of each of these subsidiaries.

ELECTRIC GENERATION

Facilities and Coordination

As of December 31, 2013, AEP’s vertically integrated public utility subsidiaries owned or leased approximately 26,900 MW of domestic generation.  See Item 2 – Properties for more information regarding the generation capacity of vertically integrated public utility subsidiaries.

 
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Interconnection Agreement

Until January 1, 2014, AEPSC, APCo, I&M, KPCo and OPCo were parties to the Interconnection Agreement. This agreement defined how the member companies shared the costs and benefits associated with their generation plants.  The agreement required the deficit companies to make monthly capacity equalization payments to the surplus companies based on the surplus companies' average fixed cost of generation.  All member companies shared off-system sales margins based upon each member company's member load ratio.   As of December 31, 2013, the member-load-ratios were as follows:

 
Peak Demand
 
Member-Load Ratio
 
(MWs)
 
(%)
APCo
6,839
 
31
 
I&M
4,540
 
21
 
KPCo
1,409
 
6
 
OPCo
9,385
 
42
 

APCo, I&M, KPCo and OPCo were also parties to the AEP System Interim Allowance Agreement (Allowance Agreement), that provided, among other things, for the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement.  The following table shows the net (credits) or charges allocated among the parties under the Interconnection Agreement during the years ended December 31, 2013, 2012 and 2011:

 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(in thousands)
APCo
$
637,300
 
$
494,400
 
$
632,100
I&M
 
(36,500)
   
(118,400)
   
(183,700)
KPCo
 
124,200
   
93,200
   
48,400
OPCo
 
(725,000)
   
(469,200)
   
(496,800)

Termination of the Interconnection Agreement

Effective as of January 1, 2014, the Interconnection Agreement and the Allowance Agreement were each terminated.  The transfer of OPCo’s generation assets and related liabilities to AGR occurring on December 31, 2013 removed a large proportion of the pooled generation resources governed under the Interconnection Agreement and Allowance Agreement.  As a result of these transfers, which were approved by the PUCO and the FERC, the parties terminated the Interconnection Agreement and the Allowance Agreement.  See Notes 1 and 4 to the consolidated financial statements, included in the 2013 Annual Reports, for additional information regarding the termination of the Interconnection Agreement and Corporate Separation.

Operating Agreement

AEPSC, PSO and SWEPCo are parties to the Operating Agreement which has been approved by the FERC.  The Operating Agreement requires PSO and SWEPCo to maintain adequate annual planning reserve margins and requires that capacity in excess of the required margins be made available for sale to other operating companies as capacity commitments.  Parties are compensated for energy delivered to the recipients based upon the deliverer’s incremental cost plus a portion of the recipient’s savings realized by the purchaser that avoids more costly alternatives.  Revenues and costs arising from third party sales are generally shared based on the amount of energy PSO or SWEPCo contributes that is sold to third parties.

In January 2014, the FERC approved the modification of the Operating Agreement to address changes resulting from the anticipated March 2014 implementation of a “Day-Ahead” power market by the SPP.

 
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The following table shows the net (credits) or charges allocated among the parties under the Operating Agreement during the years ended December 31, 2013, 2012 and 2011:

 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(in thousands)
PSO
$
46,171 
 
$
42,555 
 
$
33,091 
SWEPCo
 
(46,171)
   
(42,555)
   
(33,091)

Power generated by or allocated or provided under the Operating Agreement to any public utility subsidiary is primarily sold to customers by such public utility subsidiary at rates approved by the public utility commission in the jurisdiction of sale.

Power that is not needed to serve the native load of our vertically integrated public utility subsidiaries is sold in the wholesale market by AEPSC on behalf of that subsidiary.  See Risk Management and Trading, below, for a discussion of the trading and marketing of such power.

Counterparty Risk Management

Counterparties and exchanges may require cash or cash related instruments to be deposited on transactions as margin against open positions.  As of December 31, 2013, counterparties posted approximately $11 million in cash, cash equivalents or letters of credit with AEPSC for the benefit of AEP’s public utility subsidiaries (while, as of that date, AEP’s public utility subsidiaries posted approximately   $59 million with counterparties and exchanges).  Since open trading contracts are valued based on market prices of various commodities, exposures change daily.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 2013 Annual Reports, under the heading entitled Quantitative and Qualitative Disclosures About Market Risk for additional information.

Fuel Supply

The following table and fuel supply presentation under “Fuel Supply”, “Coal and Lignite” and “Natural Gas” include the results of the fuel used and transported by OPCo, a utility subsidiary that is not part of the vertically integrated utility segment.  OPCo’s results appear here because it retained its generation until year-end 2013 at which point all of its generation was transferred to AGR which transferred portions to APCo and KPCo.

The table shows the sources of fuel used by the AEP System:

   
2013
 
2012
 
2011
Coal and Lignite
 
75%
 
71%
 
78%
Natural Gas
 
13%
 
17%
 
11%
Nuclear
 
11%
 
11%
 
10%
Hydroelectric and other
 
<1%
 
<1%
 
<1%

A price increase/decrease in one or more fuel sources relative to other fuels may result in the decreased/increased use of other fuels.  AEP’s overall 2013 fossil fuel costs increased approximately 9% on a dollar per MMBtu basis from 2012 due primarily to an increase in natural gas prices.

Coal and Lignite

AEP’s public utility subsidiaries procure coal and lignite under a combination of purchasing arrangements including long-term contracts, affiliate operations and spot agreements with various producers and coal trading firms.  Coal consumption in 2013 was down slightly from the same period in 2012, but coal inventories ended the year at target levels on a system basis.

Management believes that AEP’s public utility subsidiaries will be able to secure and transport coal and lignite of adequate quality and in adequate quantities to operate their coal and lignite-fired units.  Through subsidiaries, AEP owns, leases or controls more than 5,700 railcars, approximately 600 barges, 15 towboats, and a coal handling
 
 
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terminal with approximately 18 million tons of annual capacity to move and store coal for use in our generating facilities.  See AEP River Operations for a discussion of AEP’s for-profit liquid, coal and other dry-bulk commodity transportation operations that are not part of this business segment.

Spot market prices for coal remained relatively flat throughout 2013, and decreased for certain coals used by AEP.  The relatively flat spot coal price performance during the year can be attributed to weak European coal demand, a persistently sluggish domestic economy, and relatively inexpensive natural gas.  Approximately half of the coal purchased by AEP is procured through term contracts.  As those contracts expire, they are replaced with contracts at current market prices.  The price impact of this process is reflected in subsequent periods.  The price paid for coal delivered in 2013 increased from the prior year primarily due to an increase in rail rates for western coal.

The following table shows the amount of coal and lignite delivered to the AEP System plants during the past three years and the average delivered price of coal purchased by AEP System companies:

   
2013
 
2012
 
2011
Total coal delivered to AEP System plants (thousands of tons)
   
51,057
   
60,054
   
62,956
Average cost per ton of coal delivered
 
$
51.31
 
$
49.22
 
$
46.76

The coal supplies at AEP System plants vary from time to time depending on various factors, including, but not limited to, demand for electric power, unit outages, transportation infrastructure limitations, space limitations, plant coal consumption rates, availability of acceptable coals, labor issues and weather conditions, which may interrupt production or deliveries. At December 31, 2013, the System’s coal inventory was approximately 34 days of full load burn.

Natural Gas

Through its public utility subsidiaries, AEP consumed over 158 billion cubic feet of natural gas during 2013 for generating power. This represents a decrease of 28% from 2012 and reverses a trend that began in 2010.  While AEP’s natural gas-fired generating capacity has increased over the past several years with the addition of the Stall and Dresden units, the increase in natural gas prices in 2013 led to a decrease in demand for natural gas-fired generation.  Despite the availability of natural gas due to the increased shale supply, the U.S. pipeline infrastructure remains a limiting factor in the expansion of natural gas-fired generation.  Several of AEP’s natural gas-fired power plants are connected to at least two pipelines, however, which allows greater access to competitive supplies and improves delivery reliability. A portfolio of term, monthly, seasonal firm and daily peaking purchase and transportation agreements (that are entered into on a competitive basis and based on market prices) supplies natural gas requirements for each plant, as appropriate.

The following table shows the amount of natural gas delivered to the AEP System plants during the past three years and the average delivered price of natural gas purchased by AEP System companies:

   
2013
 
2012
 
2011
Total natural gas delivered to AEP System plants (billion cubic feet)
   
158.3
   
220.0
   
166.8
Average price per MMBtu of purchased natural gas
 
$
4.01
 
$
3.01
 
$
4.48

Nuclear

I&M has made commitments to meet the current nuclear fuel requirements of the Cook Plant.  I&M has made and will make purchases of uranium in various forms in the spot, short-term and mid-term markets.  I&M also continues to lease a portion of its nuclear fuel.

For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M completed modifications to its spent nuclear fuel storage pool more than 10 years ago.  I&M entered into an agreement to provide for onsite dry cask storage of spent nuclear fuel to permit normal operations to continue.  I&M is scheduled to conduct further dry cask loading and storage projects on an ongoing periodic basis.  I&M began and completed its initial loading of spent nuclear fuel into the dry casks in 2012, which consisted of 12 casks (32 spent nuclear fuel assemblies contained within each).  The second loading of spent nuclear fuel into dry casks is expected to occur in 2015.

 
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Nuclear Waste and Decommissioning

As the owner of the Cook Plant, I&M has a significant future financial commitment to dispose of spent nuclear fuel and decommission and decontaminate the plant safely.  The cost to decommission a nuclear plant is affected by NRC regulations and the spent nuclear fuel disposal program.  The most recent decommissioning cost study was completed in 2012.  In it, the estimated cost of decommissioning and disposal of low-level radioactive waste for the Cook Plant ranged from $1.3 billion to $1.7 billion in 2012 non-discounted dollars.  As of December 31, 2013, the total decommissioning trust fund balance for the Cook Plant was approximately $1.6 billion. The balance of funds available to decommission Cook Plant will differ based on contributions and investment returns.  The ultimate cost of retiring the Cook Plant may be materially different from estimates and funding targets as a result of the:

·  
Type of decommissioning plan selected.
·  
Escalation of various cost elements (including, but not limited to, general inflation and the cost of energy).
·  
Further development of regulatory requirements governing decommissioning.
·  
Technology available at the time of decommissioning differing significantly from that assumed in studies.
·  
Availability of nuclear waste disposal facilities.
·  
Availability of a United States Department of Energy facility for permanent storage of spent nuclear fuel.

Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant will not be significantly different than current projections.  We will seek recovery from customers through our regulated rates if actual decommissioning costs exceed our projections.  See Note 6 to the consolidated financial statements, entitled Commitments, Guarantees and Contingencies under the heading Nuclear Contingencies, included in the 2013 Annual Reports, for information with respect to nuclear waste and decommissioning.

Low-Level Radioactive Waste

The Low-Level Waste Policy Act of 1980 mandates that the responsibility for the disposal of low-level radioactive waste rests with the individual states.  Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials.  Michigan does not currently have a disposal site for such waste available.  I&M cannot predict when such a site may be available. However the states of Utah and Texas have licensed low level radioactive waste disposal sites which currently accept low level radioactive waste from Michigan waste generators.  There is currently no set date limiting I&M’s access to either of these facilities.  The Cook Plant has a facility onsite designed specifically for the storage of low level radioactive waste.  In the event that low level radioactive waste disposal facility access becomes unavailable, then low level radioactive waste can be stored onsite at this facility.

Certain Power Agreements

I&M

The Unit Power Agreement between AEGCo and I&M, dated March 31, 1982, provides for the sale by AEGCo to I&M of all the capacity (and the energy associated therewith) available to AEGCo at the Rockport Plant.  Whether or not power is available from AEGCo, I&M is obligated to pay a demand charge for the right to receive such power (and an energy charge for any associated energy taken by I&M).  The agreement will continue in effect until the last of the lease terms of Unit 2 of the Rockport Plant has expired (currently December 2022) unless extended in specified circumstances.

Pursuant to an assignment between I&M and KPCo, and a unit power agreement between AEGCo and KPCo, AEGCo sells KPCo 30% of the capacity (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant.  KPCo has agreed to pay to AEGCo the amounts that I&M would have paid AEGCo under the terms of the Unit Power Agreement between AEGCo and I&M for such entitlement.  The KPCo unit power agreement expires in December 2022.

 
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OVEC

AEP and several nonaffiliated utility companies jointly own OVEC.  The aggregate equity participation of AEP in OVEC is 43.47%.  Until 2001, OVEC supplied from its generation capacity the power requirements of a uranium enrichment plant near Portsmouth, Ohio owned by the United States Department of Energy.  The sponsoring companies are entitled to receive and are obligated to pay for all OVEC capacity (approximately 2,200 MW) in proportion to their respective power participation ratios.  The aggregate power participation ratio of APCo, I&M and OPCo is 43.47%.  The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and to provide a return on its equity capital.  The Inter-Company Power Agreement, which defines the rights of the owners and sets the power participation ratio of each, was extended by the owners in 2011 from the termination date of March 2026 until June 2040.  AEP and the other owners have authorized environmental investments related to their ownership interests.  OVEC’s Board of Directors authorized capital expenditures totaling $1.4 billion in connection with the engineering and construction of flue gas desulfurization projects and the associated scrubber waste disposal landfills at its two generation plants.  OVEC has completed the financing of the $1.4 billion required for these projects through debt issuances, including tax-advantaged debt issuances.  Both OVEC generation plants are operating with the new environmental controls in service.  OPCo attempted to assign its rights and obligations under the Inter-Company Power Agreement to an affiliate as part of its transfer of its generation assets and liabilities in keeping with corporate separation required by Ohio law.  OPCo failed to obtain the consent to assignment from the other owners of OVEC and therefore filed a request with the PUCO seeking authorization to maintain its ownership of OVEC. In December 2013, the PUCO approved OPCo’s request, subject to the condition that energy from the OVEC entitlements are sold into the day-ahead or real-time PJM energy markets, or on a forward basis through a bilateral arrangement.

ELECTRIC DELIVERY

General

Other than AEGCo, AEP’s vertically integrated public utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power.  See Item 2 – Properties for more information regarding the transmission and distribution lines.  Most of the transmission and distribution services are sold to retail customers of AEP’s vertically integrated public utility subsidiaries in their service territories.  These sales are made at rates approved by the state utility commissions of the states in which they operate, and in some instances, approved by the FERC.  See Item 1 – Vertically Integrated Utilities – Regulation – Rates.  The FERC regulates and approves the rates for wholesale transmission transactions.  See Item 1 – Vertically Integrated Utilities – Regulation – FERC.  As discussed below, some transmission services also are separately sold to non-affiliated companies.

Other than AEGCo, AEP’s vertically integrated public utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas.  In some cases, these franchises provide the utility with the exclusive right to provide electric service.  These franchises have varying provisions and expiration dates.  In general, the operating companies consider their franchises to be adequate for the conduct of their business.  For a discussion of competition in the sale of power, see Item 1 – Vertically Integrated Utilities – Competition.

The use and the recovery of costs associated with the transmission assets of the AEP vertically integrated public utility subsidiaries are subject to the rules, protocols and agreements in place with PJM, SPP and ERCOT, and as approved by the FERC.

Transmission Agreement

APCo, I&M, KGPCo, KPCo and WPCo own and operate transmission facilities that are used to provide transmission service under the PJM OATT and are parties to the TA.  OPCo, a subsidiary in our transmission and distribution utility segment, is also a party to the TA.  The TA defines how the parties to the agreement share the revenues associated with their transmission facilities and the costs of transmission service provided by PJM.  The TA has been approved by the FERC.

 
19

 


The following table shows the net charges allocated among the certain parties to the TA during the years ended December 31, 2013, 2012 and 2011:

     
Years Ended December 31,
Company
 
2013 
 
2012 
 
2011 
   
(in thousands)
APCo
 
$
40,609 
 
$
20,264 
 
$
4,608 
I&M
   
 19,947 
   
 5,689 
   
 1,538 

TCA, OATT, and ERCOT Protocols

PSO, SWEPCo and AEPSC are parties to the TCA.  Under the TCA, a coordinating committee is charged with the responsibility of (a) overseeing the coordinated planning of the transmission facilities of the parties to the agreement, including the performance of transmission planning studies, (b) the interaction of such subsidiaries with independent system operators and other regional bodies interested in transmission planning and (c) compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such tariff.  Pursuant to the TCA, AEPSC has responsibility for monitoring the reliability of their transmission systems and administering the OATT on behalf of the other parties to the agreement.  The TCA also provides for the allocation among the parties of revenues collected for transmission and ancillary services provided under the OATT.  These allocations have been determined by the FERC-approved OATT for the SPP.

The following table shows the net (credits) or charges allocated pursuant to the TCA and SPP OATT protocols as described above for the years ended December 31, 2013, 2012 and 2011:

 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(in thousands)
PSO
$
14,700 
 
$
12,300 
 
$
9,000 
SWEPCo
 
(14,700)
   
(12,300)
   
(9,000)

Transmission Services for Non-Affiliates

In addition to providing transmission services in connection with their own power sales, AEP’s vertically integrated public utility subsidiaries through RTOs also provide transmission services for non-affiliated companies.  See Item 1 – Vertically Integrated Utilities – Electric Transmission and Distribution – Regional Transmission Organizations, below.  Transmission of electric power by AEP’s public utility subsidiaries is regulated by the FERC.

Coordination of East and West Zone Transmission

AEP’s System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP East Companies and AEP West Companies.  The System Transmission Integration Agreement functions as an umbrella agreement in addition to the TA and the TCA.  AEP’s System Transmission Integration Agreement contains two service schedules that govern:

·  
The allocation of transmission costs and revenues.
·  
The allocation of third-party transmission costs and revenues and System dispatch costs.

The System Transmission Integration Agreement contemplates that additional service schedules may be added as circumstances warrant.

Regional Transmission Organizations

AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM, and PSO and SWEPCo are members of the SPP (both FERC-approved RTOs).  RTOs operate, plan and control utility transmission assets in a manner designed to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not.

 
20

 


REGULATION

General

AEP’s vertically integrated public utility subsidiaries’ retail rates and certain other matters are subject to traditional cost-based regulation by the state utility commissions.  AEP’s vertically integrated public utility subsidiaries are also subject to regulation by the FERC under the Federal Power Act with respect to wholesale power and transmission service transactions.  I&M is subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant.  AEP and its vertically integrated public utility subsidiaries are also subject to the regulatory provisions of EPACT, much of which is administered by the FERC.

Rates

Historically, state utility commissions have established electric service rates on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service.  A utility’s cost of service generally reflects its operating expenses, including operation and maintenance expense, depreciation expense and taxes.  State utility commissions periodically adjust rates pursuant to a review of (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment.  Absent a legal limitation, such as a law limiting the frequency of rate changes or capping rates for a period of time, a state utility commission can review and change rates on its own initiative.  Some states may initiate reviews at the request of a utility, customer, governmental or other representative of a group of customers.  Such parties may, however, agree with one another not to request reviews of or changes to rates for a specified period of time.

Public utilities have traditionally financed capital investments until the new asset is placed in service.  Provided the asset was found to be a prudent investment, it was then added to rate base and entitled to a return through rate recovery.  Given long lead times in construction, the high costs of plant and equipment and volatile capital markets, we are actively pursuing strategies to accelerate rate recognition of investments and cash flow.  AEP representatives continue to engage our state commissioners and legislators on alternative ratemaking options to reduce regulatory lag and enhance certainty in the process.  These options include pre-approvals, a return on construction work in progress, rider/trackers, formula rates and the inclusion of future test-year projections into rates.

The rates of AEP’s vertically integrated public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service).  Historically, the state regulatory frameworks in the service area of the AEP vertically integrated public utility subsidiaries reflected specified fuel costs as part of bundled (or, more recently, unbundled) rates or incorporated fuel adjustment clauses in a utility’s rates and tariffs.  Fuel adjustment clauses permit periodic adjustments to fuel cost recovery from customers and therefore provide protection against exposure to fuel cost changes.

The following state-by-state analysis summarizes the regulatory environment of certain major jurisdictions in which AEP operates.  Several public utility subsidiaries operate in more than one jurisdiction.  See Note 4 to the consolidated financial statements, entitled Rate Matters, included in the 2013 Annual Reports, for more information regarding pending rate matters.

Indiana

I&M provides retail electric service in Indiana at bundled rates approved by the IURC, with rates set on a cost-of-service basis.  Indiana provides for timely fuel and purchased power cost recovery through a fuel cost recovery mechanism.

Oklahoma

PSO provides retail electric service in Oklahoma at bundled rates approved by the OCC.  PSO’s rates are set on a cost-of-service basis.  Fuel and purchased energy costs above or below the amount included in base rates are recovered or refunded by applying fuel adjustment and other factors to retail kilowatt-hour sales.  The factors are generally adjusted annually and are based upon forecasted fuel and purchased energy costs.  Over or under collections of fuel and purchased energy costs for prior periods are returned to or recovered from customers in the year following when new annual factors are established.

 
21

 


Virginia

APCo currently provides retail electric service in Virginia at unbundled rates approved by the Virginia SCC.  Virginia generally allows for timely recovery of fuel costs through a fuel adjustment clause.  Transmission services are provided at OATT rates based on rates established by the FERC.  In addition to base rates and fuel cost recovery, APCo is permitted to recover a variety of costs through rate adjustment clauses.

West Virginia

APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a cost-of-service basis.  West Virginia generally allows for timely recovery of fuel costs through an expanded net energy cost which trues-up to actual expenses.

FERC

Under the Federal Power Act, the FERC regulates rates for interstate power sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects.  The FERC regulations require AEP’s vertically integrated public utility subsidiaries to provide open access transmission service at FERC-approved rates.  The FERC also regulates unbundled transmission service to retail customers.  The FERC also regulates the sale of power for resale in interstate commerce by (a) approving contracts for wholesale sales to municipal and cooperative utilities and (b) granting authority to public utilities to sell power at wholesale at market-based rates upon a showing that the seller lacks the ability to improperly influence market prices.  Except for wholesale power that AEP delivers within its balancing area of the SPP, AEP’s vertically integrated public utility subsidiaries have market-rate authority from the FERC, under which much of their wholesale marketing activity takes place.  The FERC requires each public utility that owns or controls interstate transmission facilities to, directly or through an RTO, file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system.  The FERC also requires all transmitting utilities, directly or through an RTO, to establish an Open Access Same-time Information System, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees.

The FERC oversees RTOs, entities created to operate, plan and control utility transmission assets.  Order 2000 also prescribes certain characteristics and functions of acceptable RTO proposals.  AEGCo, APCo, I&M, KGPCo, KPCo and WPCo are members of PJM.  PSO and SWEPCo are members of SPP.

The FERC has jurisdiction over the issuances of securities of most of our public utility subsidiaries, the acquisition of securities of utilities, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company.  In addition, both the FERC and state regulators are permitted to review the books and records of any company within a holding company system.  EPACT gives the FERC increased utility merger oversight.

Competition

The vertically integrated public utility subsidiaries of AEP, like the electric industry generally, face competition in the sale of available power on a wholesale basis, primarily to other public utilities and power marketers.  The Energy Policy Act of 1992 was designed, among other things, to foster competition in the wholesale market by creating a generation market with fewer barriers to entry and mandating that all generators have equal access to transmission services.  As a result, there are more generators able to participate in this market.  The principal factors in competing for wholesale sales are price (including fuel costs), availability of capacity and power and reliability of service.

AEP’s vertically integrated public utility subsidiaries also compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil and coal, within their service areas.  The primary factors in such competition are price, reliability of service and the capability of customers to utilize sources of energy other than electric power.  With respect to competing generators and self-generation, the public utility subsidiaries of AEP believe that they generally maintain a favorable competitive position.  With respect to alternative sources of energy, the vertically integrated public utility subsidiaries of AEP believe that the reliability of their service and the limited ability of customers to substitute other cost-effective sources for electric power place them in a favorable competitive position, even though their prices may be higher than the costs of some other sources of energy.

 
22

 
Significant changes in the global economy have led to increased price competition for industrial customers in the United States, including those served by the AEP System.  Some of these industrial customers have requested price reductions from their suppliers of electric power.  In addition, industrial customers that are downsizing or reorganizing often close a facility based upon its costs, which may include, among other things, the cost of electric power.  The vertically integrated public utility subsidiaries of AEP cooperate with such customers to meet their business needs through, for example, providing various off-peak or interruptible supply options pursuant to tariffs filed with, and approved by, the various state commissions.  Occasionally, these rates are negotiated with the customer, and then filed with the state commissions for approval.

Seasonality

The sale of electric power is generally a seasonal business.  In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time.  In other areas, power demand peaks during the winter.  The pattern of this fluctuation may change due to the nature and location of AEP’s facilities and the terms of power sale contracts into which AEP enters.  In addition, AEP has historically sold less power, and consequently earned less income, when weather conditions are milder.  Unusually mild weather in the future could diminish AEP’s results of operations and may impact its financial condition.  Conversely, unusually extreme weather conditions could increase AEP’s results of operations.

TRANSMISSION AND DISTRIBUTION UTILITIES

General

This business segment consists of the transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC. OPCo is engaged in the transmission and distribution of electric power to approximately 1,464,000 retail customers in Ohio.  TCC is engaged in the transmission and distribution of electric power to approximately 806,000 retail customers through REPs in southern Texas. TNC is engaged in the transmission and distribution of electric power to approximately 188,000 retail customers through REPs in west and central Texas.

AEP’s transmission and distribution utility subsidiaries own and operate transmission and distribution lines and other facilities to deliver electric power.  See Item 2 – Properties for more information regarding the transmission and distribution lines.  Most of the transmission and distribution services are sold to retail customers of AEP’s transmission and distribution utility subsidiaries in their service territories.  These sales are made at rates approved by the PUCT for TCC and TNC and by the PUCO and the FERC for OPCo.  The FERC regulates and approves the rates for wholesale transmission transactions.  As discussed below, some transmission services also are separately sold to non-affiliated companies.

AEP’s transmission and distribution utility subsidiaries hold franchises or other rights to provide electric service in various municipalities and regions in their service areas.  In some cases, these franchises provide the utility with the exclusive right to provide electric service.  These franchises have varying provisions and expiration dates.  In general, the operating companies consider their franchises to be adequate for the conduct of their business.

The use and the recovery of costs associated with the transmission assets of the AEP transmission and distribution utility subsidiaries are subject to the rules, protocols and agreements in place with PJM and ERCOT, and as approved by the FERC.  In addition to providing transmission services in connection with power sales in their service areas, AEP’s transmission and distribution utility subsidiaries through RTOs also provide transmission services for non-affiliated companies.

Transmission Agreement

OPCo, together with APCo, I&M, KGPCo, KPCo and WPCo, is a party to the TA.  The TA defines how the parties to the agreement share the cost of their transmission facilities.  The TA has been approved by the FERC.  OPCo’s net charges allocated to it under the TA during the years ended December 31, 2013, 2012 and 2011 were $8.9 million, $6.1 million and $17.2 million, respectively.

 
23

 
Regional Transmission Organizations

OPCo is a member of PJM, a FERC-approved RTO.  RTOs operate, plan and control utility transmission assets in a manner designed to provide open access to such assets in a way that prevents discrimination between participants owning transmission assets and those that do not.  TCC and TNC are members of ERCOT.

REGULATION

OPCo provides distribution and transmission services to retail customers within its service territory at cost-based rates approved by the PUCO or by the FERC.  TCC and TNC provide transmission and distribution service on a cost-of-service basis at rates approved by the PUCT and wholesale transmission service under tariffs approved by the FERC consistent with PUCT rules.  Transmission and distribution rates are established on a cost-of-service basis, which is designed to allow a utility an opportunity to recover its cost of providing service and to earn a reasonable return on its investment used in providing that service.  The cost of service generally reflects operating expenses, including operation and maintenance expense, depreciation expense and taxes.  Utility commissions periodically adjust rates pursuant to a review of (a) a utility’s adjusted revenues and expenses during a defined test period and (b) such utility’s level of investment.

FERC

Under the Federal Power Act, the FERC regulates rates for transmission of electric power, accounting and other matters.  The FERC regulations require AEP to provide open access transmission service at FERC-approved rates.  The FERC also regulates unbundled transmission service to retail customers.  The FERC requires each public utility that owns or controls interstate transmission facilities to, directly or through an RTO, file an open access network and point-to-point transmission tariff that offers services comparable to the utility’s own uses of its transmission system.  The FERC also requires all transmitting utilities, directly or through an RTO, to establish an Open Access Same-time Information System, which electronically posts transmission information such as available capacity and prices, and requires utilities to comply with Standards of Conduct that prohibit utilities’ transmission employees from providing non-public transmission information to the utility’s marketing employees. In addition, both the FERC and state regulators are permitted to review the books and records of any company within a holding company system.  EPACT gives the FERC increased utility merger oversight.

Seasonality

The delivery of electric power is generally a seasonal business.  In many parts of the country, demand for power peaks during the hot summer months.  In other areas, power demand peaks during the winter months.  The pattern of this fluctuation may change due to the nature and location of AEP’s transmission and distribution facilities.  In addition, AEP transmission and distribution has historically delivered less power, and consequently earned less income, when weather conditions are milder.  Unusually mild weather in the future could diminish AEP transmission and distribution’s results of operations and may impact its financial condition.  Conversely, unusually extreme weather conditions could increase AEP transmission and distribution’s results of operations.

GENERATION & MARKETING

Our Generation & Marketing segment subsidiaries consist of competitive nonutility generating assets, a wholesale energy trading and marketing business and a retail supply and energy management business.  The largest subsidiary in our Generation & Marketing segment is AGR.  On December 31, 2013, AGR acquired the generation assets and related liabilities at net book value of OPCo in a series of transactions approved by the PUCO and the FERC.  AGR transferred a portion of the generation assets and liabilities   at net book value that it received to APCo and KPCo.  As a result of these transactions, AGR owns 10,002 MW of generating capacity, with rights to an additional 1,186 MW pursuant to a unit power agreement (see below).  Other subsidiaries in this segment own or have the right to receive power from additional generation assets.  See Item 2 – Properties for more information regarding the generation assets of the Generation & Marketing segment. AGR is a competitive generation subsidiary.

With respect to our wholesale energy trading and marketing business, we enter into short and long-term transactions to buy or sell capacity, energy and ancillary services primarily in ERCOT, MISO and PJM.  We sell power into the market and engage in power, natural gas, coal and emissions allowances risk management and trading activities.  
 
 
24

 
These activities primarily involve the purchase and sale of electricity (and to a lesser extent, natural gas, coal and emissions allowances) under forward contracts at fixed and variable prices.  These contracts include physical transactions, exchange-traded futures, and to a lesser extent, over-the-counter swaps and options.  The majority of forward contracts are typically settled by entering into offsetting contracts.  These transactions are executed with numerous counterparties or on exchanges.

With respect to our retail supply and energy management business, our subsidiary AEP Energy is a retail electricity supplier that supplies electricity to residential, commercial, and industrial customers.  AEP Energy provides an array of energy solutions and is operating in Illinois, Pennsylvania, Delaware, Maryland, New Jersey, Ohio and Washington, D.C.  AEP Energy also provides demand-side management solutions nationwide.  AEP Energy had approximately 215,000 customer accounts as of December 31, 2013.

REGULATION

AGR is a public utility under the Federal Power Act, and is subject to FERC’s exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Under the Federal Power Act, FERC has the authority to grant or deny market-based rates for sales of energy, capacity and ancillary services to ensure that such sales are just and reasonable.  FERC granted AGR market-based rate authority in December 2013.  FERC’s jurisdiction over ratemaking also includes the authority to suspend the market-based rates of utilities (including AGR, which is a public utility as defined by the FERC) and set cost-based rates if FERC subsequently determines that such utility can exercise market power, create barriers to entry or engage in abusive affiliate transactions.  As a condition to the order granting AGR market-based rate authority, every three years AGR is required to file a market power update to show that it continues to meet FERC’s standards with respect to generation market power and other criteria used to evaluate whether it continues to qualify for market-based rates.  Other matters subject to FERC jurisdiction include, but are not limited to, third-party financings; review of mergers; and dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility.

Specific operations of AGR are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including Federal and state environmental protection agencies.  We are also regulated by the PUCT for transactions inside ERCOT.  Additionally, AGR is subject to mandatory reliability standards promulgated by the NERC, with the approval of FERC.  We are also regulated by the PUCT for transactions inside ERCOT.

COMPETITION

The generation and marketing subsidiaries of AEP face competition for the sale of available power, capacity and ancillary services.  The principal factors impacting us are electricity and fuel prices, new market entrants, construction or retirement of generating assets by others and technological advances in power generation. It is possible that changes in regulatory policies or advances in newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells will reduce costs of new technology to levels that are equal to or below that of most central station electricity production.  Our ability to maintain relatively low cost, efficient and reliable operations is a significant determinate of our competitiveness.

With over 70% of our generation fleet fueled by coal, our overall competitive position is impacted by the price of natural gas relative to coal.  While higher relative natural gas prices generally favor our competitive position, lower relative natural gas prices will favor our competitors that have a higher concentration of natural gas fueled generation.  Other factors impacting our competitiveness include transmission congestion or transportation constraints at or near our generation facilities, inoperability or inefficiencies, outages and deactivations and retirements at our generation facilities.

Seasonality

The sale of electric power is generally a seasonal business.  In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time.  In other areas, power demand peaks during the winter months.  The pattern of this fluctuation may change.

 
25

 
Counterparty Risk Management

Counterparties and exchanges may require cash or cash related instruments to be deposited on these transactions as margin against open positions.  As of December 31, 2013, counterparties posted approximately $14 million in cash, cash equivalents or letters of credit with AEP for the benefit of AEP’s generation and marketing subsidiaries (while, as of that date, AEP’s generation and marketing subsidiaries posted approximately   $165 million with counterparties and exchanges).  Since open trading contracts are valued based on market prices of various commodities, exposures change daily.  See Management’s Discussion and Analysis of Financial Condition and Results of Operations, included in the 2013 Annual Reports, under the heading entitled Quantitative and Qualitative Disclosures About Market Risk for additional information.

Fuel Supply

AEP’s generation and marketing subsidiaries procure coal under a combination of purchasing arrangements including long-term contracts, affiliate operations and spot agreements with various producers and coal trading firms.  Management believes that AEP’s generation and marketing subsidiaries will be able to secure and transport coal of adequate quality and in adequate quantities to operate their coal-fired units. Through subsidiaries, AEP owns, leases or controls more than 5,700 railcars, approximately 600 barges and 15 towboats to move and store coal for use in our generating facilities.

Most of the coal purchased by AEP is procured through term contracts.  As those contracts expire, they can be replaced at the new market price with an impact in subsequent periods.  Several of AEP’s natural gas-fired power plants are connected to at least two pipelines, which allows greater access to competitive supplies and improves delivery reliability. A portfolio of term, monthly, seasonal firm and daily peaking commodity and transportation agreements (that are entered into on a competitive basis and based on market prices) supplies natural gas requirements for each plant, as appropriate.

Certain Power Agreements

AEGCo

The Unit Power Agreement between AEGCo and AGR (assigned from OPCo) dated March 15, 2007, provides for the sale by AEGCo to AGR of all the capacity and associated unit contingent energy and ancillary services available to AGR from the Lawrenceburg Plant, a 1,186 MW natural gas-fired unit owned by AEGCo.  AGR is obligated to pay a capacity charge (whether or not power is available from the Lawrenceburg Plant), and the fuel, operating and maintenance charges associated with the energy dispatched by AGR, and to reimburse AEGCo for other costs associated with the operation and ownership of the Lawrenceburg Plant.  The agreement will continue in effect until December 31, 2017 unless extended.

OPCo

Pursuant to a Power Supply Agreement (PSA) between AGR and OPCo, AGR supplies capacity for OPCo’s switched and non-switched retail load for the period January 1, 2014 through May 31, 2015.  AGR also supplies the energy needs of OPCo’s non-switched retail load that is not acquired through auctions from January 1, 2014 through December 31, 2014 under the PSA.

Other

As of December 31, 2013, the assets utilized in this segment included approximately 310 MW of company-owned domestic wind power facilities, 177 MW of domestic wind power from long-term purchase power agreements and 377 MW of coal-fired capacity which was obtained through an agreement effective through 2027 that transfers TNC’s interest in the Oklaunion power station to AEP Energy Partners, Inc.  The power obtained from the Oklaunion power station is marketed and sold in ERCOT.

 
26

 


AEP TRANSMISSION HOLDCO (AEPTHCO)

AEPTHCO OVERVIEW

AEPTHCo is a holding company for AEPTCo and for AEP’s transmission joint ventures.  AEPTCo is a holding company for seven wholly-owned FERC-regulated transmission-only electric utilities (Transcos), each of which is geographically aligned with our existing utility operating companies.  Transmission development through the Transcos is primarily driven by:

·  
Improvements to local area reliability by upgrading, rebuilding or replacing existing, aging infrastructure.
·  
Construction of new facilities to support customer points of delivery, generation interconnections, new facilities to provide transmission service directed by the RTOs, and new facilities required to maintain grid reliability.
·  
Projects assigned as a result of the regional planning initiatives conducted by PJM and SPP.  PJM and SPP identify the need for transmission in support of regional reliability, congestion reduction and the integration of supply-side resources (primarily renewable) and retirements of generation facilities.

AEPTCo’s seven Transcos are:

AEP East Transmission Companies (all located within PJM)

·  
AEP Appalachian Transmission Company, Inc. (APTCo) (covering Virginia)
·  
AEP Indiana Michigan Transmission Company, Inc. (IMTCo)
·  
AEP Kentucky Transmission Company, Inc. (KTCo)
·  
AEP Ohio Transmission Company, Inc. (OHTCo)
·  
AEP West Virginia Transmission Company, Inc. (WVTCo)

AEP West Transmission Companies (all located within SPP)

·  
AEP Oklahoma Transmission Company, Inc. (OKTCo)
·  
AEP Southwestern Transmission Company, Inc. (SWTCo) (covering Arkansas and Louisiana)

The Transcos develop, own and operate transmission assets that are physically connected to AEP’s existing system.  They are regulated for rate-making purposes exclusively by the FERC and employ a forward-looking formula rate tariff design.  The Transcos are independent of but overlay AEP’s existing vertically-integrated utility operating companies and the transmission operations of OPCo.  IMTCo, KTCo, OHTCo, OKTCo and WVTCo have received approvals for formation or did not require state commission approval to operate.  IMTCo, OHTCo, OKTCo and WVTCo currently own and operate transmission assets or have assets under construction.  Applications for regulatory approvals have been filed for SWTCo and are currently under consideration in Arkansas and Louisiana.  As of December 31, 2013, AEPTCo had $991 million of transmission assets in-service with plans to construct nearly $2 billion of additional transmission assets through 2016.

JOINT VENTURE INITIATIVES

AEP has established joint ventures with other electric utility companies for the purpose of developing, building, and owning transmission assets that seek to improve reliability and market efficiency and provide transmission access to remote generation sources in North America.  Transource Energy, LLC (Transource) is a joint venture between AEPTHC (86.5%) and Great Plains Energy (13.5%). Transource was formed to pursue competitive projects resulting from FERC Order No. 1000 described further below under the heading Competition.  Our other joint ventures are at various stages of regulatory and RTO approval.

 
27

 



We are currently participating in the following joint venture initiatives:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Estimated
 
 
AEP's
 
 
 
 
 
 
Projected
 
 
 
 
Project Costs
 
 
Investment at
 
Approved
Project
 
 
 
Completion
 
 
Owners
 
at
 
 
December 31,
 
Return on
Name
 
Location
 
Date
 
 
(Ownership %)
 
Completion
 
 
2013 (h)
 
Equity
 
 
 
 
 
 
 
 
 
 
(in thousands)
 
 
 
 
ETT
 
Texas 
 
2023 
 
 
MidAmerican  
 
$
 3,057,000 
(a)
 
$
 440,719 
 
 9.96 
%
 
 
 
(ERCOT) 
 
 
 
 
Energy (50%) 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
AEP (50%) 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prairie Wind
 
Kansas 
 
2014 
 
 
Westar Energy (50%) 
 
 
 170,000 
 
 
 
 11,533 
 
 12.8 
%
 
 
 
 
 
 
 
 
MidAmerican Energy 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(25%) (b) 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
AEP (25%) (b) 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pioneer
 
Indiana 
 
2018 
(c)
 
Duke Energy (50%) 
 
 
 1,100,000 
(c)
 
 
 2,466 
 
 12.54 
%
 
 
 
 
 
 
 
 
AEP (50%) 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
RITELine IN
 
Indiana 
 
2026 
 
 
Exelon (12.5%) (d) 
 
 
 400,000 
 
 
 
 685 
(e)
 11.43 
%
 
 
 
 
 
 
 
 
AEP (87.5%) (d) 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
RITELine IL
 
Illinois 
 
2026 
 
 
Commonwealth 
 
 
 1,200,000 
 
 
 
 13 
(e)
 11.43 
%
 
 
 
 
 
 
 
 
Edison (75%) 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exelon (12.5%) (d) 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
AEP (12.5%) (d) 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Transource
 
Missouri 
 
2017 
 
 
Great Plains Energy 
 
 
 398,000 
(g) 
 
 
 2,275 
 
11.1 
%
(g)
Missouri
 
 
 
 
 
 
(13.5%) (f) 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
AEP (86.5%) (f) 
 
 
 
 
 
 
 
 
 
 
 

(a)
ETT’s investment in completed, current and future projects in ERCOT over the next ten years is expected to be $3.057 billion.  Future projects will be evaluated on a case-by-case basis.
(b)
AEP owns 25% of Prairie Wind Transmission, LLC (Prairie Wind) through its ownership interest in ETA.  ETA is a 50/50 joint venture with MidAmerican Energy and AEP.
(c)
The Pioneer project consists of approximately 286 miles of new 765 kV transmission lines, which is estimated to cost $1.1 billion at completion.  Pioneer is developing the first 66-mile segment jointly with Northern Indiana Public Service Company at a total estimated cost of $330 million.  The projected completion date for the first 66-mile segment is 2018.  The projected completion dates for the remaining segments have not been determined.
(d)
AEP owns 87.5% of RITELine Indiana, LLC (RITELine IN) through its ownership interest in RITELine Transmission Development, LLC (RTD) and AEP Transmission Holding Company, LLC (AEPTHC).  AEP owns 12.5% of RITELine Illinois, LLC (RITELine IL) through its ownership interest in RTD.  RTD is a 50/50 joint venture with Exelon Transmission Company, LLC and AEPTHC.
(e)
RITELine IN is a consolidated variable interest entity.  RTD received an order from the FERC in October 2011 granting incentives for the RITELine IN and RITELine IL projects.  The projects and other segments that are electrically equivalent in nature are currently under consideration for inclusion in the interregional planning process between PJM and MISO.
(f)
AEP owns 86.5% of Transource Missouri through its ownership interest in Transource Energy, LLC (Transource).  Transource is a joint venture with AEPTHC and Great Plains Energy formed to pursue competitive transmission projects.  AEPTHC and Great Plains Energy own 86.5% and 13.5% of Transource, respectively.
(g)
The ROE represents the weighted average approved return on equity based on the projected costs of two projects currently under development by Transource Missouri:  the $65 million Iatan-Nashua project (10.3%) and the $333 million Sibley-Nebraska City project (11.3%).
(h)
RITELine IN and Transource Missouri are consolidated joint ventures by AEP.  Therefore, the investment value listed reflects applicable income taxes that are the responsibility of AEP.  All other investments in this schedule are joint ventures that are not consolidated by AEP.  Therefore, these investment values listed do not reflect income taxes that are the responsibility of AEP.

In August 2012, the PJM board cancelled the Potomac-Appalachian Transmission Highline Project (PATH Project), our transmission joint venture with FirstEnergy, and removed it from the 2012 Regional Transmission Expansion Plan.  In September 2012, the PATH Project companies submitted an application to the FERC requesting authority
 
 
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to recover prudently-incurred costs associated with the Project.  In November 2012, the FERC issued an order accepting the PATH Project's abandonment cost recovery application, subject to settlement procedures and hearing.  The settlement proceedings are on-going.  AEP’s investment in the PATH Project as of December 31, 2013 was $25 million.

Our joint ventures do not have employees.  Business services for the joint ventures are provided by AEPSC and other AEP subsidiaries and the joint venture partners.

REGULATION

The Transcos and Joint Ventures located outside of ERCOT establish transmission rates annually through forward looking formula rate filings with the FERC pursuant to FERC-approved implementation protocols.  The protocols include a transparent, formal review process to ensure the updated transmission rates are prudently incurred and reasonably calculated.

The Transcos’ and Joint Ventures’ (where applicable) rates are included in the respective Open Access Transmission Tariff (OATT) for PJM and SPP.  An OATT is the FERC rate schedule that provides the terms and conditions for transmission and related services on a transmission provider’s transmission system.  The FERC requires transmission providers such as PJM and SPP to offer transmission service to all eligible customers (for example, load-serving entities, power marketers, generators and customers) on a non-discriminatory basis.

The FERC-approved formula rates establish the annual transmission revenue requirement (ATRR) and transmission service rates for transmission owners.  The formula rates establish rates for a one-year period based on the current projects in-service and proposed projects for a defined timeframe.  The formula rates also include a true-up calculation for the previous year’s billings, allowing for over- and under-recovery of the transmission owner’s ATRR.  PJM and SPP pay the transmission owners their ATRR for use of their facilities and bill transmission customers taking service under the PJM and SPP OATTs, based on the terms and conditions in the respective OATT for the service taken.

The rates of ETT, which is located in ERCOT, are determined by the PUCT.  ETT sets its rates through a combination of base rate cases and interim Transmission Costs of Services (TCOS) filings.  ETT may file interim TCOS filings semi-annually to update its rates to reflect changes in its net invested capital.

Our joint ventures have approved returns on equity ranging from 9.96% to 12.8% based on equity capital structures ranging from 40% to 60%.

The Transcos collectively filed rate base totals of $776 million in 2013, $283 million for 2012 and $104 million for 2011.  The total transmission revenue requirement filed in the ATRR for 2013, 2012 and 2011 was $99 million, $35 million and $13 million, respectively.

The formula rate mechanism allows for a return on equity of 11.49% based on a capital structure of up to 50% equity for the AEP East Transmission Companies.  The AEP West Transmission Companies are allowed a return on equity of 11.20% based on a capital structure of up to 50% equity. The authorized returns on equity for the Transcos are commensurate with the FERC-authorized returns on equity in the PJM and SPP OATTs, respectively, for AEP’s utility subsidiaries.

COMPETITION

One of the most significant provisions of FERC Order No. 1000 is the removal of the federal right of first refusal for incumbent utilities within tariffs and agreements for certain regional transmission projects. Historically, vertically integrated public utilities had the right to build and own transmission lines proposed by the region’s planning processes when those lines connected to facilities within their respective retail service territories.  FERC Order No. 1000 eliminates the federal right of first refusal in regional transmission organization (RTO) tariffs for incumbent utilities to construct certain regional transmission projects within their own service territories, thereby creating the opportunity for any qualified entity to build and own regional transmission facilities in any service territory.  Transource was created to respond to FERC Order No. 1000 competitive processes at the RTO level as described above.

 
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AEP RIVER OPERATIONS

Our AEP River Operations segment transports liquid, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi rivers.  Almost all of our customers are nonaffiliated third parties who obtain the transport of coal and dry bulk commodities for various uses.  We charge these customers market rates for the purpose of making a profit.  Depending on market conditions and other factors, including barge availability, we permit AEP utility subsidiary affiliates to use certain of our equipment at rates that reflect our cost.  Our affiliated utility customers procure the transport of coal for use as fuel in their respective generation plants.  AEP River Operations includes approximately 2,300 barges, 36 towboats and 20 harbor boats that we own or lease. In 2014, River Operations will add at least 20 ten thousand barrel tank barges.  Those barges will provide an entry into the tank barge business which will serve both current and new customers that transport liquid commodities.  These assets are separate from the barges and towboats dedicated exclusively to transporting coal for use as fuel in our own generating facilities discussed under the prior segment.  See Item 1 – Vertically Integrated Utilities – Electric Generation – Fuel Supply – Coal and Lignite.

Competition within the barging industry for major commodity contracts is intense, with a number of companies offering transportation services in the waterways we serve.  We compete with other carriers primarily on the basis of commodity shipping rates, but also with respect to customer service, available routes, value-added services (including scheduling convenience and flexibility).  The industry continues to experience consolidation.  The resulting companies increasingly offer the widespread geographic reach necessary to support major national customers.  Demand for barging services can be seasonal, particularly with respect to the movement of harvested agricultural commodities (beginning in the late summer and extending through the fall).  Cold winter weather, water levels and inefficient older river locks operated by others may also limit our operations when certain of the waterways we serve are closed or commercial traffic is limited.

Our transportation operations are subject to regulation by the U.S. Coast Guard, federal laws, state laws and certain international conventions.  Legislation has been proposed that could make our towboats subject to inspection by the U.S. Coast Guard.

 
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EXECUTIVE OFFICERS OF AEP as of February 25, 2014

The following persons are executive officers of AEP.  Their ages are given as of February 1, 2014.  The officers are appointed annually for a one-year term by the board of directors of AEP.

Nicholas K. Akins
Chairman of the Board, President and Chief Executive Officer
Age 53
Chairman of the Board since January 2014, President since January 2011 and Chief Executive Officer since November 2011. Was Executive Vice President-Generation from September 2006 to December 2010.

Lisa M. Barton
Executive Vice President – Transmission
Age 48
Executive Vice President-Transmission of AEPSC since August 2011. Was Senior Vice President-Transmission Strategy and Business Development of AEPSC from November 2010 to July 2011, Vice President-Transmission Strategy and Business Development of AEPSC from October 2007 to November 2010.

David M. Feinberg
Executive Vice President, General Counsel and Secretary
Age 44
Executive Vice President since January 2013.  Was Senior Vice President, General Counsel and Secretary from January 2012 to December 2012 and  Senior Vice President and General Counsel of AEPSC from May 2011 to December 2011. Previously served as Vice President, General Counsel and Secretary of Allegheny Energy, Inc. from 2006 to 2011.

Lana L. Hillebrand
Senior Vice President and Chief Administrative Officer
Age 53
Senior Vice President and Chief Administrative Officer since December 2012.  Previously served as South Region leader-Senior Partner at Aon Hewitt since 2010.  Was U.S. Consulting Client Development leader-managing principal at Aon Hewitt from 2008-2010.

Mark C. McCullough
Executive Vice President – Generation
Age 54
Executive Vice President-Generation of AEPSC since January 2011.  Was Senior Vice President-Fossil & Hydro Generation of AEPSC from February 2008 to December 2010.

Robert P. Powers
Executive Vice President and Chief Operating Officer
Age 59
Executive Vice President and Chief Operating Officer since November 2011.  Was President-Utility Group from April 2009 to November 2011, President-AEP Utilities from January 2008 to April 2009.

Brian X. Tierney
Executive Vice President and Chief Financial Officer
Age 46
Executive Vice President and Chief Financial Officer since October 2009.  Was Executive Vice President-AEP Utilities East of AEPSC from January 2008 to October 2009.

Dennis E. Welch
Executive Vice President and Chief External Officer
Age 62
Executive Vice President and Chief External Officer since January 2013.  Was Executive Vice President and Chief Administrative Officer from October 2011 to December 2012.  Was Executive Vice President-Environment, Safety & Health and Facilities from January 2008 to September 2011.

 
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ITEM 1A.   RISK FACTORS

GENERAL RISKS OF OUR REGULATED OPERATIONS

We may not be able to recover the costs of our substantial planned investment in capital improvements and additions. – Affecting each Registrant

Our business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades and retrofits, construction of additional transmission facilities, modernizing existing infrastructure as well as other initiatives.  Our public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions.  If these regulatory commissions do not approve adjustments to the rates we charge, we would not be able to recover the costs associated with our planned extensive investment.  This would cause our financial results to be diminished.

Approval of the June 2012 through May 2015 ESP order in Ohio may be overturned and is subject to appeal. – Affecting AEP and OPCo

In August 2012, the PUCO issued an order which adopted and modified an ESP through May 2015 (the “2012 ESP”).  The 2012 ESP allowed the continuation of the fuel adjustment clause, maintained recovery of several previous ESP riders and approved a storm damage recovery mechanism.  The 2012 ESP further established (a) a non-bypassable Distribution Investment Rider effective September 2012 through May 2015 to recover certain distribution investment, and (b) a non-bypassable Retail Stability Rider (RSR), a portion of which provides for the collection of deferred capacity costs.  The deferred capacity costs may exceed the amount we will collect under the RSR.  In January 2013, the PUCO issued an order on rehearing for the 2012 ESP which generally upheld its prior order.  Intervenors are challenging various parts of these orders at the PUCO and with the Supreme Court of Ohio.  In parallel proceedings, the PUCO addressed certain issues around the energy auctions while other issues were deferred to a separate docket.  The PUCO has agreed to issue a request for an independent auditor in the fuel adjustment clause proceeding to separately examine the recovery of the fixed fuel costs.  If all or part of 2012 ESP is overturned by the PUCO or the Supreme Court of Ohio, or if deferred capacity and other costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Our request for an ESP from June 2015 through May 2018 may not be approved in its entirety. – Affecting AEP and OPCo

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, effective June 2015 through May 2018.  The proposal includes a return on common equity of 10.65% for certain riders.  Additionally, the application identifies OPCo’s intention to submit a separate application to continue the RSR in which the unrecovered portion of the deferred capacity costs will continue to be collected until the balance of the capacity deferrals has been collected.  If the PUCO denies all or part of the requested ESP, it could reduce future net income and cash flows and impact financial condition.

Ohio may require us to refund revenue that we have collected. – Affecting AEP and OPCo

Ohio law requires that the PUCO determine on an annual basis if rate adjustments included in prior orders resulted in significantly excessive earnings.  If the PUCO determines there were significantly excessive earnings, the excess amount could be returned to customers.  In November 2013, OPCo filed its 2011 and 2012 significantly excessive earnings filings with the PUCO.  If the PUCO determines that OPCo’s earnings were significantly excessive, and requires OPCo to return a portion of its revenues to customers, it could reduce future net income and cash flows and impact financial condition.

We may not recover deferred fuel costs. – Affecting AEP and OPCo

In August 2012, the PUCO ordered recovery of deferred fuel costs beginning September 2012 through the Phase-In Recovery Rider.  The August 2012 order was upheld by the PUCO in October 2012.  OPCo and intervenors have filed appeals at the Supreme Court of Ohio.  If the Supreme Court of Ohio does not permit full recovery of OPCo’s deferred fuel costs, it would reduce future net income and cash flows and impact financial condition.

 
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Ohio may require us to refund additional fuel costs. – Affecting AEP and OPCo

In January 2012, the PUCO ordered that proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance and that an outside consultant be hired to review our fuel procurement through 2011.  The audit by the outside consultant included recommendations that would limit some of our fuel recovery or require us to refund certain fuel costs already incurred.  In addition, an intervenor filed an appeal with the Supreme Court of Ohio challenging the recovery of certain fuel costs.  Any reduction to our fuel recovery by the PUCO and/or the Supreme Court of Ohio could reduce future net income and cash flows and impact financial condition.

We may not fully recover all of the investment in and expenses related to the Turk Plant – Affecting AEP and SWEPCo

In December 2012, SWEPCo placed the Turk Plant in Arkansas into commercial operation.  SWEPCo holds a 73% ownership interest in the 600 MW coal-fired generating facility.  SWEPCo had originally intended that the Arkansas jurisdictional share of the Turk Plant (approximately 20%) would become part of the rate base for its retail customers in Arkansas.  Following a proceeding at the Arkansas Supreme Court, the APSC issued an order which reversed and set aside a previously granted Certificate of Environmental Compatibility and Public Need.  The Arkansas portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market.  In addition, in February 2013, the LPSC granted recovery for the Louisiana portion of the Turk Plant costs in a formula rate filing, subject to refund based on the staff review of the cost of service and prudence review of the Turk Plant.  If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant either through retail rates or sales into the wholesale market, it could reduce future net income and cash flows and impact financial condition.

Request for rate recovery in Indiana may be overturned on appeal. – Affecting AEP and I&M

In February 2013, the IURC issued an order granting an annual increase in base rates.  In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal of the order with the Indiana Court of Appeals.  In September 2013, the OUCC filed a brief on appeal that included objections to certain aspects of the rate case.  If any part of the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.

Approved recovery related to enabling the useful life of the Cook Plant may be overturned on appeal or further consideration. – Affecting AEP and I&M

In April and May 2012, I&M filed petitions with the IURC and the MPSC, respectively, for approval of the Cook Plant Life Cycle Management Project (LCM Project), which consists of a group of capital projects for Cook Plant, Units 1 and 2 intended to ensure the safe and reliable operation of the plant through its extended licensed life (2034 for Unit 1 and 2037 for Unit 2).  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project.  In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project.  In July 2013, the IURC approved I&M’s proposed project apart from a minor exception which the IURC stated I&M could seek recovery in a base rate case.  I&M was granted recovery through an LCM Project Rider to be determined in a series of proceedings beginning in the fourth quarter of 2013 and then semi-annually thereafter.  If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.

Request for rate recovery in Texas may not be approved in its entirety and could be overturned. – Affecting AEP and SWEPCo

In July 2012, SWEPCo filed a request with the PUCT for an increase in Texas base rates.  In October 2013, the PUCT issued an order that granted part of the requested rate recovery.  Additionally, the PUCT determined that it would defer consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2.  If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Turk Plant transmission lines or Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.

 
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Request for rate recovery in Oklahoma may not be approved in its entirety. – Affecting AEP and PSO

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity.  If PSO cannot ultimately recover its costs that are the subject of this request, it could reduce future net income and cash flows and impact financial condition.

Our transmission investment strategy and execution bears certain risks associated with these activities. – Affecting AEP

We expect that a growing portion of our earnings in the future will derive from the transmission investments and activities of AEPTCo and our transmission joint ventures.  FERC policy currently favors the expansion and updating of the transmission infrastructure within its jurisdiction.  If FERC were to adopt a different policy or if transmission needs do not continue or develop as projected, our strategy of investing in transmission could be curtailed.  We believe our experience with transmission facilities construction and operation gives us an advantage over other competitors in securing authorization to install, construct and operate new transmission lines and facilities.  However, there can be no assurance that PJM, SPP or other RTOs will authorize any new transmission projects or will award any such projects to us.  If the FERC were to lower the rate of return it has authorized for our transmission investments and facilities, it could reduce future net income and cash flows and impact financial condition.

We may not recover costs incurred to begin construction on projects that are canceled. – Affecting each Registrant

Our business plan for the construction of new projects involves a number of risks, including construction delays, nonperformance by equipment and other third party suppliers, and increases in equipment and labor costs.  To limit the risks of these construction projects, we enter into equipment purchase orders and construction contracts and incur engineering and design service costs in advance of receiving necessary regulatory approvals and/or siting or environmental permits.  If any of these projects is canceled for any reason, including our failure to receive necessary regulatory approvals and/or siting or environmental permits, we could incur significant cancellation penalties under the equipment purchase orders and construction contracts.  In addition, if we have recorded any construction work or investments as an asset, we may need to impair that asset in the event the project is canceled.

Rate regulation may delay or deny full recovery of capital improvements, additions, storm damage operations and maintenance expense repairs and other costs. – Affecting each Registrant

Our public utility subsidiaries currently provide service at rates approved by one or more regulatory commissions.  These rates are generally regulated based on an analysis of the applicable utility’s expenses incurred in a test year.  Thus, commission-approved rates may or may not match a utility’s expenses at any given time.  There may also be a delay between the timing of when these costs are incurred and when these costs are recovered.  We often finance the operations and maintenance expense to repair facilities damaged by storms or other severe weather events until the operations and maintenance storm costs, including any deferred regulatory assets, are recovered in rates.  We have also traditionally financed capital investments and improvements until the new asset was placed in service.  Provided the asset was found to be a prudent investment, the asset was then added to rate base and entitled to a return through rate recovery.  Similarly, long lead times in construction and scheduled repairs, the high costs of plant and equipment and volatile capital markets have heightened the risks involved in our capital investments, repairs and improvements.  While we are actively pursuing strategies to accelerate rate recognition of investments and cash flow, including pre-approvals, a return on construction work in progress, rider/trackers, formula rates and the inclusion of future test-year projections into rates, there can be no assurance that these will be adopted, that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will be done in a timely manner.

 
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Certain of our revenues and results of operations are subject to risks that are beyond our control. – Affecting each Registrant

Our operations are structured to comply with all applicable federal and state laws and regulations and we take measures to minimize the risk of significant disruptions. Material disruptions at one or more of our operational facilities, however, could negatively impact our revenues, operating and capital expenditures and results of operations.  Such events may also create additional risks related to the supply and/or cost of equipment and materials.  We could experience unexpected but significant interruption due to several events, including, but not limited to:

·  
Major facility or equipment failure.
·  
An environmental event such as a serious spill or release.
·  
Fires, floods, droughts, earthquakes, hurricanes, tornados or other natural disasters.
·  
Wars, terrorist acts (including cyber-terrorism) or threats and other catastrophic events.
·  
Significant health impairments or disease events.
·  
Other serious operational problems.

We are exposed to nuclear generation risk. – Affecting AEP and I&M

Through I&M, we own the Cook Plant.  It consists of two nuclear generating units for a rated capacity of 2,191 MW, or about 6% of the generating capacity in the AEP System.  We are, therefore, subject to the risks of nuclear generation, which include the following:

·  
The potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials such as spent nuclear fuel.
·  
Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations.
·  
Uncertainties with respect to contingencies and assessment amounts triggered by a loss event (federal law requires owners of nuclear units to purchase the maximum available amount of nuclear liability insurance and potentially contribute to the losses of others).
·  
Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

There can be no assurance that I&M’s preparations or risk mitigation measures will be adequate if and when these risks are triggered.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities.  In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved.  Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants such as ours.  In addition, although we have no reason to anticipate a serious nuclear incident at our plants, if an incident did occur, it could harm our results of operations or financial condition.  A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit.  Moreover, a major incident at any nuclear facility in the U.S. could require us to make material contributory payments.

Costs associated with the operation (including fuel), maintenance and retirement of nuclear plants continue to be more significant and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards, availability of nuclear waste disposal facilities and experience gained in the operation of nuclear facilities.  Costs also may include replacement power, any unamortized investment at the end of the useful life of the Cook Plant (whether scheduled or premature), the carrying costs of that investment and retirement costs.  Our ability to obtain adequate and timely recovery of costs associated with the Cook Plant is not assured.

 
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The different regional power markets in which we compete or will compete in the future have changing market and transmission structures, which could affect our performance in these regions. – Affecting each Registrant

Our results are likely to be affected by differences in the market and transmission structures in various regional power markets.  The rules governing the various regional power markets, including SPP and PJM, may also change from time to time which could affect our costs or revenues.  Because the manner in which RTOs will evolve remains unclear, we are unable to assess fully the impact that changes in these power markets may have on our business.

We could be subject to higher costs and/or penalties related to mandatory reliability standards. – Affecting each Registrant

As a result of EPACT, owners and operators of the bulk power transmission system are subject to mandatory reliability standards promulgated by the North American Electric Reliability Corporation and enforced by the FERC.  The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles.  Compliance with new reliability standards may subject us to higher operating costs and/or increased capital expenditures.  While we expect to recover costs and expenditures from customers through regulated rates, there can be no assurance that the applicable commissions will approve full recovery in a timely manner.  If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which likely would not be recoverable from customers through regulated rates.

RISKS RELATED TO MARKET, ECONOMIC OR FINANCIAL VOLATILITY AND OTHER RISKS

Our financial performance may be adversely affected if we are unable to successfully operate our facilities or perform certain corporate functions. – Affecting each Registrant

Our performance is highly dependent on the successful operation of our generation, transmission and distribution facilities.  Operating these facilities involves many risks, including:

·  
Operator error and breakdown or failure of equipment or processes.
·  
Operating limitations that may be imposed by environmental or other regulatory requirements.
·  
Labor disputes.
·  
Compliance with mandatory reliability standards, including mandatory cyber security standards.
·  
Information technology failure that impairs our information technology infrastructure or disrupts normal business operations.
·  
Information technology failure that affects our ability to access customer information or causes us to lose confidential or proprietary data that materially and adversely affects our reputation or exposes us to legal claims.
·  
Fuel or water supply interruptions caused by transportation constraints, adverse weather such as drought, non-performance by our suppliers and other factors.
·  
Catastrophic events such as fires, earthquakes, explosions, hurricanes, tornados, ice storms, terrorism (including cyber-terrorism), floods or other similar occurrences.

Hostile cyber intrusions could severely impair our operations, lead to the disclosure of confidential   information and damage our reputation. – Affecting each Registrant

We own assets deemed as critical infrastructure, the operation of which is dependent on information technology systems. Further, the computer systems that run our facilities are not completely isolated from external networks. Parties that wish to disrupt the U.S. bulk power system or our operations could view our computer systems, software or networks as targets for cyber attack.  In addition, our business requires that we collect and maintain sensitive customer data, as well as confidential employee and shareholder information, which is subject to electronic theft or loss.

 
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A successful cyber attack on the systems that control our generation, transmission, distribution or other assets could severely disrupt business operations, preventing us from serving customers or collecting revenues. The breach of certain business systems could affect our ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and repair security breaches or system damage and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to our reputation. In addition, the misappropriation, corruption or loss of personally identifiable information and other confidential data could lead to significant breach notification expenses and mitigation expenses such as credit monitoring. We maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by potential cyber security incidents.  However, other damage and claims arising from such incidents may not be covered or may exceed the amount of any insurance available. For these reasons, a significant cyber incident could reduce future net income and cash flows and impact financial condition.

In an effort to reduce the likelihood and severity of cyber intrusions, we have a comprehensive cyber security program designed to protect and preserve the confidentiality, integrity and availability of data and systems. In addition, we are subject to mandatory cyber security regulatory requirements. However, cyber threats continue to evolve and adapt, and, as a result, there is a risk that we could experience a successful cyber attack despite our current security posture and regulatory compliance efforts.

If we are unable to access capital markets on reasonable terms, it could reduce future net income and cash flows and impact financial condition. – Affecting each Registrant

We rely on access to capital markets as a significant source of liquidity for capital requirements not satisfied by operating cash flows.  Volatility and reduced liquidity in the financial markets could affect our ability to raise capital and fund our capital needs, including construction costs and refinancing maturing indebtedness.  In addition, if capital is available only on less than reasonable terms or to borrowers whose creditworthiness is better than ours, capital costs could increase materially.  Restricted access to capital markets and/or increased borrowing costs could reduce future net income and cash flows and impact financial condition.

Downgrades in our credit ratings could negatively affect our ability to access capital and/or to operate our power trading businesses. – Affecting each Registrant

The credit ratings agencies periodically review our capital structure and the quality and stability of our earnings.  Any negative ratings actions could constrain the capital available to us and could limit our access to funding for our operations.  Our business is capital intensive, and we are dependent upon our ability to access capital at rates and on terms we determine to be attractive.  In periods of market turmoil, access to capital is difficult for all borrowers.  If our ability to access capital becomes significantly constrained, our interest costs will likely increase and could reduce future net income and cash flows and impact financial condition.

Our power trading business relies on the investment grade ratings of our individual public utility subsidiaries’ senior unsecured long-term debt or on the investment grade ratings of AEP.  Most of our counterparties require the creditworthiness of an investment grade entity to stand behind transactions.  If those ratings were to decline below investment grade, our ability to operate our power trading business profitably would be diminished because we would likely have to deposit cash or cash-related instruments which would reduce our profits.

AEP has no income or cash flow apart from dividends paid or other obligations due it from its subsidiaries. – Affecting AEP

AEP is a holding company and has no operations of its own.  Its ability to meet its financial obligations associated with its indebtedness and to pay dividends on its common stock is primarily dependent on the earnings and cash flows of its operating subsidiaries, primarily its regulated utilities, and the ability of its subsidiaries to pay dividends to, or repay loans from, AEP.  Its subsidiaries are separate and distinct legal entities that have no obligation (apart from loans from AEP) to provide AEP with funds for its payment obligations, whether by dividends, distributions or other payments.  Payments to AEP by its subsidiaries are also contingent upon their earnings and business considerations.  AEP indebtedness and common stock dividends are structurally subordinated to all subsidiary indebtedness.

 
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Our operating results may fluctuate on a seasonal or quarterly basis and with general economic and weather conditions. – Affecting each Registrant

Electric power generation is generally a seasonal business.  In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time.  In other areas, power demand peaks during the winter.  As a result, our overall operating results in the future may fluctuate substantially on a seasonal basis.  The pattern of this fluctuation may change depending on the terms of power sale contracts that we enter into.  In addition, we have historically sold less power, and consequently earned less income, when weather conditions are milder.  Unusually mild weather in the future could diminish our results of operations and harm our financial condition.  Conversely, unusually extreme weather conditions could increase AEP’s results of operations in a manner that would not likely be sustainable.

Further, deteriorating economic conditions generally result in reduced consumption by our customers, particularly industrial customers who may curtail operations or cease production entirely, while an expanding economic environment generally results in increased revenues.  As a result, our overall operating results in the future may fluctuate on the basis of prevailing economic conditions.

Failure to attract and retain an appropriately qualified workforce could harm our results of operations. – Affecting each Registrant

Certain events, such as an aging workforce without appropriate replacements, mismatch of skillset or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs.  The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development.  In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise.  Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate our business.  If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be negatively affected.

Parties we have engaged to provide construction materials or services may fail to perform their obligations, which could harm our results of operations. – Affecting each Registrant

Our business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades, construction of additional generation units and transmission facilities as well as other initiatives.  We are exposed to the risk of substantial price increases in the costs of materials used in construction.  We have engaged numerous contractors and entered into a large number of agreements to acquire the necessary materials and/or obtain the required construction related services.  As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us.  Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and almost certainly cause delays in that and related projects.  Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions.  This would cause our financial results to be diminished, and we might incur losses or delays in completing construction.

Changes in commodity prices and the costs of transport may increase our cost of producing power or decrease the amount we receive from selling power, harming our financial performance. – Affecting each Registrant

We are exposed to changes in the price and availability of coal and the price and availability to transport coal.  We have existing contracts of varying durations for the supply of coal, but as these contracts end or otherwise are not honored, we may not be able to purchase coal on terms as favorable as the current contracts.  Similarly, we are exposed to changes in the price and availability of emission allowances.  We use emission allowances based on the amount of coal we use as fuel and the reductions achieved through emission controls and other measures.  As long as current environmental programs remain in effect, we have sufficient emission allowances to cover the majority of our projected needs for the next two years and beyond.  If the Federal EPA is able to create a replacement rule to reduce interstate transport, and it is acceptable by the courts, additional costs may be incurred either to acquire additional allowances or to achieve further reductions in emissions.  If we need to obtain allowances under a
 
 
38

 
replacement rule, those purchases may not be on as favorable terms as those under the current environmental programs.  Our risks relative to the price and availability to transport coal include the volatility of the price of diesel which is the primary fuel used in transporting coal by barge.

We also own natural gas-fired facilities which exposes us to market prices of natural gas.  Historically, natural gas prices have tended to be more volatile than prices for other fuel sources. Recently however, the availability of natural gas from shale production has lessened price volatility. Our ability to make off-system sales at a profit is highly dependent on the price of natural gas.  As the price of natural gas falls, other market participants that utilize natural gas-fired generation will be able to offer electricity at increasingly competitive prices relative to our off-system sales prices, so the margins we realize from sales will be lower and, on occasion, we may need to curtail operation of marginal plants.  We expect the availability of shale natural gas and issues related to its accessibility will have a long-term material effect on the price and volatility of natural gas.

Prices for coal, natural gas and emission allowances have shown material upward and downward swings in the past.  Changes in the cost of coal, emission allowances or natural gas and changes in the relationship between such costs and the market prices of power will affect our financial results.

In addition, actual power prices and fuel costs will differ from those assumed in financial projections used to value our trading and marketing transactions, and those differences may be material.  As a result, our financial results may be diminished in the future as those transactions are marked to market.

Our AEP River Operations business segment is subject to risks that are beyond our control. – Affecting AEP

Our AEP River Operations business segment transports liquid, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi rivers.  These activities can be hazardous and depend on natural conditions and forces.  Our river transport operations could result in an environmental event such as a serious spill or release.  In addition, if drought conditions or other factors cause the water levels of one or more of these rivers to drop below the amount necessary to permit commercial barging traffic, it would prevent our AEP River Operations from transporting cargo on the affected river.  Conversely, if unusually high amounts of precipitation or other factors cause the water levels of one or more of these rivers to be too high to permit commercial barging traffic, it would prevent our AEP River Operations from transporting cargo on the affected river.  Extreme water levels that do not close river basin commercial traffic can still harm our business if the levels curtail the total volume permitted to move on the affected river. The levels on portions of the Mississippi River in 2013 have been reported as remaining at or approaching the lowest since the levels caused by severe drought in 1988.  Any reduction in the commercial activities of our AEP River Operations due to low water levels could reduce future net income and cash flows.

We are subject to physical and financial risks associated with climate change. – Affecting each Registrant

There is a growing consensus on the evidence of global climate change.  Climate change creates physical and financial risk.  Physical risks from climate change include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events.  Our customers’ energy needs vary with weather conditions, primarily temperature and humidity.  For residential customers, heating and cooling represent their largest energy use.  To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.
 
Increased energy use due to weather changes may require us to invest in additional generating assets, transmission and other infrastructure to serve increased load.  Decreased energy use due to weather changes may affect our financial condition, through decreased revenues.  Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stress, including service interruptions.  Weather conditions outside of our service territory could also have an impact on our revenues.  We buy and sell electricity depending upon system needs and market opportunities.  Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers.

 
39

 

Severe weather impacts our service territories, primarily when thunderstorms, tornadoes, hurricanes and snow or ice storms occur.  To the extent the frequency of extreme weather events increases, this could increase our cost of providing service.  Changes in precipitation resulting in droughts or water shortages could adversely affect our operations, principally our fossil generating units.  A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy.  We may not recover all costs related to mitigating these physical and financial risks.

To the extent climate change impacts a region’s economic health, it may also impact our revenues.  Our financial performance is tied to the health of the regional economies we serve.  The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of our communities.

We cannot predict the outcome of the legal proceedings relating to our business activities. – Affecting each Registrant

We are involved in legal proceedings, claims and litigation arising out of our business operations, the most significant of which are summarized in Note 6 of the Combined Notes to Consolidated Financial Statements entitled Commitments, Guarantees and Contingencies.  Adverse outcomes in these proceedings could require significant expenditures that could have a material adverse effect on our results of operations.

RISKS RELATING TO STATE RESTRUCTURING

Customers are choosing alternative electric generation service providers, as allowed by Ohio law and regulation. – Affecting AEP

Under current Ohio law, electric generation is sold in a competitive market in Ohio and native load customers in Ohio have the ability to switch to alternative suppliers for their electric generation service.  CRES providers are targeting retail customers by offering alternative generation service.  Through a short term agreement, AGR provides capacity and a decreasing portion of power to the Ohio customers that have not switched.  As customer switching in Ohio continues, it could reduce AGR’s future net income and cash flows and impact financial condition.

Collection of our revenues in Texas is concentrated in a limited number of REPs. – Affecting AEP

Our revenues from the distribution of electricity in the ERCOT area of Texas are collected from REPs that supply the electricity we distribute to their customers.  Currently, we do business with approximately one hundred REPs.  In 2013, TCC’s largest REP accounted for 29% of its operating revenue and its second largest REP accounted for 16% of its operating revenue; TNC’s largest REP accounted for 12% of its operating revenues and its second largest REP accounted for 7% of its operating revenues.  Adverse economic conditions, structural problems in the Texas market or financial difficulties of one or more REPs could impair the ability of these REPs to pay for our services or could cause them to delay such payments.  We depend on these REPs for timely remittance of payments.  Any delay or default in payment could reduce future cash flows and impact financial condition.


 
40

 


RISKS RELATED TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER

Our costs of compliance with existing environmental laws are significant. – Affecting each Registrant

Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety.  Approximately 90% of the electricity generated by the AEP System is produced by the combustion of fossil fuels.  Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generation plants are subject to increased regulations, controls and mitigation expenses.  Compliance with these legal requirements requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees and permits at all of our facilities and could cause us to retire generating capacity prior to the end of its estimated useful life.  These expenditures have been significant in the past and we expect that they will continue to be significant in order to comply with the current and proposed regulations.  Costs of compliance with environmental regulations could reduce future net income and impact financial condition, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed and additional substances become regulated.  If we retire generation plants prior to the end of their estimated useful life, there can be no assurance that we will recover the remaining costs associated with such plants.  We typically recover our expenditures for pollution control technologies, replacement generation and associated operating costs from customers through regulated rates in regulated jurisdictions.  Failure to recover these costs could reduce our future net income and cash flows and possibly harm our financial condition.   For our sales of energy from our competitive units, there is no such cost-recovery mechanism.   As a result, we may not recover our costs through the market and we may be forced to shut competitive units down.  The costs of compliance for our competitive units could reduce our future net income and cash flows and possibly harm our financial condition. 

Regulation of CO 2 emissions, either through legislation or by the Federal EPA, could materially increase costs to us and our customers or cause some of our electric generating units to be uneconomical to operate or maintain. – Affecting each Registrant

The U.S. Congress has not taken any significant steps toward enacting legislation to control CO 2 emissions since 2009.  In December 2009, the Federal EPA issued a final endangerment finding under the CAA regarding emissions from motor vehicles.  The Federal EPA also finalized CO 2 emission standards for new motor vehicles, and issued a rule that implements a permitting program for new and modified stationary sources of CO 2 emissions in a phased manner.  Several groups have filed challenges to the endangerment finding and the Federal EPA’s subsequent rulemakings.  The Supreme Court has agreed to review whether EPA reasonably determined that establishing standards for new motor vehicles automatically triggered regulation of stationary sources through the prevention of significant deterioration and Title V permitting programs.

In 2012, the Federal EPA issued a proposed CO 2 emissions standard for new power generation sources with a CO 2 limit equivalent to a natural gas unit.  In response to the comments submitted on this proposed rule, and in accordance with a directive from the President, EPA withdrew the April 2012 proposed rule and has issued a new proposal.  This proposed rule includes separate, but equivalent, standards for natural gas and coal-fired units, based on the use of partial carbon capture and storage at coal units.  We do not believe that carbon capture and storage has been adequately demonstrated, and intend to submit comments on the proposed rule.  The President has also directed Federal EPA to issue standards for modified and reconstructed units, and a guideline for the development of state implementation plans that would reduce carbon emissions from existing utility units by June 2014, to finalize those standards by June 2015, and to require states to submit implementation plans no later than June 2016.  Management believes some policy approaches being discussed would have significant and widespread negative consequences for the national economy and major U.S. industrial enterprises, including AEP and our customers.

If CO 2 and other emission standards are imposed, the standards could require significant increases in capital expenditures and operating costs which would impact the ultimate retirement of older, less-efficient, coal-fired units.  We typically recover costs of complying with new requirements such as the potential CO 2 and other greenhouse gases emission standards from customers through regulated rates in regulated jurisdictions.  For our sales of energy based on market rate authority, however, there is no such recovery mechanism.  Failure to recover these costs, should they arise, could reduce our future net income and cash flows and possibly harm our financial condition.


 
41

 

Amounts we receive from the results of PJM capacity auctions associated with our nonregulated generation assets could fail to adequately compensate us. – Affecting AEP

At the end of last year, AGR acquired most of the generation formerly owned by OPCo.  Recovery of AGR’s generation capacity is subject to the results of annual PJM capacity auctions.  Recent auction results indicate a great deal of volatility and the possibility of clearing prices substantially lower than the cost of such capacity.  We formed a coalition with other utility companies to address mutual concerns related to the auction process and PJM has made filings with the FERC seeking modification of that process.  Additional filings are expected.  We can give no assurance that the FERC will approve any modifications to the annual PJM capacity auctions.  If the annual PJM capacity auctions continue to result in clearing prices lower than the cost of our capacity, it could reduce our future net income and cash flows and impact financial condition.

Courts adjudicating nuisance and other similar claims against us may order us to pay damages or to limit or reduce our CO 2 emissions. – Affecting each Registrant

In the past, there have been several cases seeking damages based on allegations of federal and state common law nuisance in which we, among others, were defendants.  In general, the actions allege that CO 2 emissions from the defendants’ power plants constitute a public nuisance due to impacts of global warming and climate change.  The plaintiffs in these actions generally seek recovery of damages and other relief.  If the pending or other future actions are resolved against us, substantial modifications of our existing coal-fired power plants could be required and we might be required to limit or reduce CO 2 emissions.  Such remedies could require us to purchase power from third parties to fulfill our commitments to supply power to our customers.  This could have a material impact on our costs.  In addition, we could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay damages or penalties and/or halt operations.  While management believes such costs should be recoverable from customers as costs of doing business in our jurisdictions where generation rates are set on a cost of service basis, without such recovery those costs could reduce our future net income and cash flows and harm our financial condition.  Moreover, our results of operations and financial position could be reduced due to the timing of recovery of these investments and the expense of ongoing litigation.

Changes in technology and regulatory policies may cause our generating facilities to be less competitive.  – Affecting each Registrant

We primarily generate electricity at large central facilities. This method results in economies of scale and lower costs than newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in technologies or changes in regulatory policies will reduce costs of new technology to levels that are equal to or below that of most central station electricity production, which could have a material adverse effect on our results of operations.

Our profitability is impacted by our continued authorization to sell power at market-based rates.  – Affecting each Registrant

FERC has granted AEGCo, AGR, APCo, I&M, KPCo, OPCo, PSO, and SWEPCo authority to sell electricity at market-based rates (except in our balancing authority area of the SPP where our wholesale power transactions are cost-capped by FERC). FERC reserves the right to revoke or revise this market-based rate authority if it subsequently determines that one or more of these companies can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions.  Each company that has obtained market-based rate authority from FERC must file a market power update every three years to show that they continue to meet FERC’s standards with respect to generation market power and other criteria used to evaluate whether entities qualify for market-based rates.  The loss of market-based rate authority by any of these entities, especially by AGR, could have a material adverse effect on our results of operations.

Our revenues and results of operations from selling power are subject to market risks that are beyond our control. – Affecting each Registrant

We sell power from our generation facilities into the spot market and other competitive power markets on a contractual basis.  We also enter into contracts to purchase and sell electricity, natural gas, emission allowances and coal as part of our power marketing and energy trading operations.  With respect to such transactions, the rate of
 
 
42

 
return on our capital investments is not determined through mandated rates, and our revenues and results of operations are likely to depend, in large part, upon prevailing market prices for power in our regional markets and other competitive markets.  These market prices can fluctuate substantially over relatively short periods of time.  Trading margins may erode as markets mature and there may be diminished opportunities for gain should volatility decline.  In addition, the FERC, which has jurisdiction over wholesale power rates, as well as RTOs that oversee some of these markets, may impose price limitations, bidding rules and other mechanisms to address some of the volatility in these markets.  Power supply and other similar agreements entered into during extreme market conditions may subsequently be held to be unenforceable by a reviewing court or the FERC.  Fuel and emissions prices may also be volatile, and the price we can obtain for power sales may not change at the same rate as changes in fuel and/or emissions costs.  These factors could reduce our margins and therefore diminish our revenues and results of operations.  Volatility in market prices for fuel and power may result from:

·  
Weather conditions, including storms.
·  
Economic conditions.
·  
Outages of major generation or transmission facilities.
·  
Seasonality.
·  
Power usage.
·  
Illiquid markets.
·  
Transmission or transportation constraints or inefficiencies.
·  
Availability of competitively priced alternative energy sources.
·  
Demand for energy commodities.
·  
Natural gas, crude oil and refined products and coal production levels.
·  
Natural disasters, wars, embargoes and other catastrophic events.
·  
Federal, state and foreign energy and environmental regulation and legislation and/or incentives.

Commodity trading and marketing activities are subject to inherent risks which can be reduced and controlled but not eliminated. – Affecting each Registrant

We attempt to manage the exposure of or power trading activities by establishing and enforcing risk limits and risk management procedures.  These risk limits and risk management procedures may not work as planned and cannot eliminate the risks associated with these activities.  As a result, we cannot predict the impact that our energy trading and risk management decisions may have on our business, operating results or financial position.

We routinely have open trading positions in the market, within guidelines we set, resulting from the management of our trading portfolio.  To the extent open trading positions exist, fluctuating commodity prices can improve or diminish our financial results and financial position.

Our power trading risk management activities, including our power sales agreements with counterparties, rely on projections that depend heavily on judgments and assumptions by management of factors such as the future market prices and demand for power and other energy-related commodities.  These factors become more difficult to predict and the calculations become less reliable the further into the future these estimates are made.  Even when our policies and procedures are followed and decisions are made based on these estimates, results of operations may be diminished if the judgments and assumptions underlying those calculations prove to be inaccurate.

We may not successfully manage the uncertainty involved with our power trading (including coal, natural gas and emission allowances trading and power marketing). – Affecting each Registrant

Our power trading activities also expose us to risks of commodity price movements.  To the extent that our power trading does not hedge the price risk associated with the generation it owns, or controls, through long-term power purchase agreements, we would be exposed to the risk of rising and falling spot market prices.

For example, the use of new technologies to recover natural gas from shale deposits has increased natural gas supply and reserves, placing further downward pressure on natural gas prices and has reduced the need for our coal-fired generation. Further, in the event that alternative generation resources, such as wind and solar, are mandated or otherwise subsidized or encouraged through climate legislation or regulation and added to the available generation supply, such resources could displace a higher marginal cost fossil plant, which could reduce the price at which
 
 
43

 
market participants sell their electricity. This occurrence could then reduce the market price at which all generators in that region would be able to sell their output. These events could adversely affect our financial condition, results of operations and cash flows, and could also result in an impairment of certain long-lived assets.

In connection with these trading activities, we routinely enter into financial contracts, including futures and options, over-the counter options, financially-settled swaps and other derivative contracts.  These activities expose us to risks from price movements.  If the values of the financial contracts change in a manner we do not anticipate, it could harm our financial position or reduce the financial contribution of our trading operations.

Parties with whom we have contracts may fail to perform their obligations, which could harm our results of operations. – Affecting each Registrant

We are exposed to the risk that counterparties that owe us money or power could breach their obligations.  Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices that may exceed our contractual prices, which would cause our financial results to be diminished and we might incur losses.  Although our estimates take into account the expected probability of default by a counterparty, our actual exposure to a default by a counterparty may be greater than the estimates predict.

We rely on electric transmission facilities that we do not own or control.  If these facilities do not provide us with adequate transmission capacity, we may not be able to deliver our wholesale electric power to the purchasers of our power. – Affecting each Registrant

We depend on transmission facilities owned and operated by other nonaffiliated power companies to deliver the power we sell at wholesale.  This dependence exposes us to a variety of risks.  If transmission is disrupted, or transmission capacity is inadequate, we may not be able to sell and deliver our wholesale power.  If a region’s power transmission infrastructure is inadequate, our recovery of wholesale costs and profits may be limited.  If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure.

The FERC has issued electric transmission initiatives that require electric transmission services to be offered unbundled from commodity sales.  Although these initiatives are designed to encourage wholesale market transactions, access to transmission systems may in fact not be available if transmission capacity is insufficient because of physical constraints or because it is contractually unavailable.  We also cannot predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.

Financial derivatives reforms could increase the liquidity needs and costs of our commercial trading operations. – Affecting each Registrant

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was signed into law (Dodd-Frank Act).  The federal legislation was enacted to reform financial markets and significantly alter how over-the-counter (OTC) derivatives are regulated.  The law increased regulatory oversight of OTC energy derivatives, including: (a) imposing pervasive regulation by the Commodity Futures Trading Commission (CFTC) on dealers and traders who hold significant positions in swaps, (b) requiring certain standardized OTC derivatives to be traded on registered exchanges as directed by CFTC, (c) imposing new and potentially higher capital and margin requirements on swap dealers and traders who hold significant positions in swaps and (d) increasing the monitoring and compliance obligations of parties who engage in swaps, including new recordkeeping and reporting requirements with governmental entities.  The CFTC has issued regulations exempting certain end users of energy commodities from being required to clear OTC derivatives, provided that they (a) are using the swaps to hedge or mitigate commercial risk and (b) satisfy certain other requirements.  To the extent we meet such requirements, the end user exemption could reduce the effect of the law's clearing requirements on our hedging activity.  Pursuant to authority granted under the Dodd-Frank Act, the CFTC has also issued rules that, among other things, further define the OTC derivative products and entities subject to additional regulatory oversight, which recently became effective.  These requirements could subject us to additional regulatory oversight related to our OTC derivative transactions, cause our OTC derivative transactions to be more costly and have an impact on financial condition due to additional capital requirements.  In addition, as these reforms aim to standardize OTC products it could limit the effectiveness of our hedging programs because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to manage.

 
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ITEM 1B.   UNRESOLVED STAFF COMMENTS

None.

ITEM 2.   PROPERTIES

GENERATION FACILITIES

As of December 31, 2013, and after giving effect to the year-end affiliate disposition and acquisition of the former generation assets and related liabilities of OPCo, the AEP System owned (or leased where indicated) generation plants, all situated in the states in which our electric utilities serve retail customers, where applicable, with net maximum power capabilities (winter rating) shown in the following tables:

Vertically Integrated Utilities Segment

AEGCo
                   
                   
Year Plant
               
Net Maximum
 
or First Unit
Plant Name
 
Units
 
State
 
Fuel Type
 
Capacity (MWs)
 
Commissioned
Rockport, Units 1 and 2 – 50% of each (a)
 
2
 
IN
 
Steam - Coal
 
1,310
 
1984
Lawrenceburg (b)
 
6
 
IN
 
Natural Gas
 
1,186
 
2004
Total MWs
             
2,496
   
                     
(a)
Rockport, Unit 2 is leased.
(b)
The capacity and output of this plant is under contract to (and its financial impact is included with) AGR through 2017.
   
APCo
                     
                   
Year Plant
 
               
Net Maximum
 
or First Unit
 
Plant Name
 
Units
 
State
 
Fuel Type
 
Capacity (MWs)
 
Commissioned
 
Buck
 
3
 
VA
 
Hydro
 
9
 
1912
 
Byllesby
 
4
 
VA
 
Hydro
 
22
 
1912
 
Claytor
 
4
 
VA
 
Hydro
 
76
 
1939
 
Leesville
 
2
 
VA
 
Hydro
 
50
 
1964
 
London
 
3
 
WV
 
Hydro
 
14
 
1935
 
Marmet
 
3
 
WV
 
Hydro
 
14
 
1935
 
Niagara
 
2
 
VA
 
Hydro
 
2
 
1906
 
Reusens
 
5
 
VA
 
Hydro
 
13
 
1904
 
Winfield
 
3
 
WV
 
Hydro
 
15
 
1938
 
Ceredo
 
6
 
WV
 
Natural Gas
 
516
 
2001
 
Dresden
 
3
 
OH
 
Natural Gas
 
608
 
2012
 
Smith Mountain
 
5
 
VA
 
Pumped Storage
 
586
 
1965
 
Amos
 
3
 
WV
 
Steam - Coal
 
2,900
 
1971
 
Clinch River
 
3
 
VA
 
Steam - Coal
 
705
 
1958
 
Glen Lyn
 
2
 
VA
 
Steam - Coal
 
335
 
1918
 
Kanawha River
 
2
 
WV
 
Steam - Coal
 
400
 
1953
 
Mountaineer
 
1
 
WV
 
Steam - Coal
 
1,320
 
1980
 
Sporn
 
2
 
WV
 
Steam - Coal
 
300
 
1950
 
Total MWs
             
7,885
     

 
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I&M
                   
                   
Year Plant
               
Net Maximum
 
or First Unit
Plant Name
 
Units
 
State
 
Fuel Type
 
Capacity (MWs)
 
Commissioned
Berrien Springs
 
12
 
MI
 
Hydro
 
7
 
1908
Buchanan
 
10
 
MI
 
Hydro
 
4
 
1919
Constantine
 
4
 
MI
 
Hydro
 
1
 
1921
Elkhart
 
3
 
IN
 
Hydro
 
3
 
1913
Mottville
 
4
 
MI
 
Hydro
 
2
 
1923
Twin Branch
 
6
 
IN
 
Hydro
 
5
 
1904
Rockport (Units 1 and 2, 50% of each) (a)
 
2
 
IN
 
Steam - Coal
 
1,310
 
1984
Tanners Creek
 
4
 
IN
 
Steam - Coal
 
995
 
1951
Cook
 
2
 
MI
 
Steam - Nuclear
 
2,191
 
1975
Total MWs
             
4,518
   
                     
(a)  Rockport, Unit 2 is leased.

The following table provides operating information related to the Cook Plant:

 
Cook Plant
 
Unit 1
 
Unit 2
       
Year Placed in Operation
1975
 
1978
Year of Expiration of NRC License
2034
 
2037
Nominal Net Electrical Rating in Kilowatts
1,084,000
 
1,107,000
Annual Capacity Utilization
     
   2013
82.7%
 
86.9%
2012
96.9%
 
87.4%
2011
81.3%
 
99.4%
2010
82.2%
 
80.8%

KPCo
                   
                   
Year Plant
               
Net Maximum
 
or First Unit
Plant Name
 
Units
 
State
 
Fuel Type
 
Capacity (MWs)
 
Commissioned
Big Sandy
 
2
 
KY
 
Steam - Coal
 
1,078
 
1963
Mitchell (a)
 
2
 
WV
 
Steam - Coal
 
780
 
1971
Total MWs
             
1,858
   

(a)   
KPCo owns a 50% interest in the Mitchell Units.  AGR owns the remaining 50%.


PSO
                   
                   
Year Plant
               
Net Maximum
 
or First Unit
Plant Name
 
Units
 
State
 
Fuel Type
 
Capacity (MWs)
 
Commissioned
Comanche
 
3
 
OK
 
Natural Gas
 
266
 
1973
Riverside, Units 3 and 4
 
2
 
OK
 
Natural Gas
 
151
 
2008
Southwestern, Units 4 and 5
 
2
 
OK
 
Natural Gas
 
170
 
2008
Tulsa
 
2
 
OK
 
Natural Gas
 
307
 
1956
Weleetka
 
3
 
OK
 
Natural Gas
 
200
 
1975
Northeastern, Units 3 and 4
 
2
 
OK
 
Steam - Coal
 
940
 
1979
Oklaunion (a)
 
1
 
TX
 
Steam - Coal
 
101
 
1986
Northeastern, Units 1 and 2
 
2
 
OK
 
Steam - Natural Gas
 
918
 
1961
Riverside, Units 1 and 2
 
2
 
OK
 
Steam - Natural Gas
 
908
 
1974
Southwestern, Units 1, 2 and 3
 
3
 
OK
 
Steam - Natural Gas
 
466
 
1952
Total MWs
             
4,427
   
 
(a) Jointly-owned with TNC and non-affiliated entities.  Figures presented reflect only the portion owned by PSO.

 
46

 


SWEPCo
                   
                   
Year Plant
               
Net Maximum
 
or First Unit
Plant Name
 
Units
 
State
 
Fuel Type
 
Capacity (MWs)
 
Commissioned
Mattison
 
4
 
AR
 
Natural Gas
 
313
 
2007
Stall
 
1
 
LA
 
Natural Gas
 
534
 
2010
Flint Creek (a)
 
1
 
AR
 
Steam - Coal
 
264
 
1978
Turk (a)
 
1
 
AR
 
Steam - Coal
 
477
 
2012
Welsh
 
3
 
TX
 
Steam - Coal
 
1,584
 
1977
Dolet Hills (a)
 
1
 
LA
 
Steam - Lignite
 
257
 
1986
Pirkey (a)
 
1
 
TX
 
Steam - Lignite
 
580
 
1985
Arsenal Hill
 
1
 
LA
 
Steam - Natural Gas
 
110
 
1960
Knox Lee
 
4
 
TX
 
Steam - Natural Gas
 
475
 
1950
Lieberman
 
4
 
LA
 
Steam - Natural Gas
 
242
 
1947
Lone Star
 
1
 
TX
 
Steam - Natural Gas
 
50
 
1954
Wilkes
 
3
 
TX
 
Steam - Natural Gas
 
838
 
1964
Total MWs
             
5,724
   
                     
(a)
Jointly-owned with nonaffiliated entity(ies).  Figures presented reflect only the portion owned by SWEPCo.

Generation & Marketing Segment

AGR (formerly owned by OPCo)
                   
                   
Year Plant
               
Net Maximum
 
or First Unit
Plant Name
 
Units
 
State
 
Fuel Type
 
Capacity (MWs)
 
Commissioned
Racine
 
2
 
OH
 
Hydro
 
48
 
1982
Darby
 
6
 
OH
 
Natural Gas
 
507
 
2001
Waterford
 
4
 
OH
 
Natural Gas
 
840
 
2003
Beckjord (a)
 
1
 
OH
 
Steam - Coal
 
53
 
1969
Cardinal
 
1
 
OH
 
Steam - Coal
 
595
 
1967
Conesville (a)
 
3
 
OH
 
Steam - Coal
 
1,139
 
1957
Gavin
 
2
 
OH
 
Steam - Coal
 
2,640
 
1974
Kammer
 
3
 
WV
 
Steam - Coal
 
630
 
1958
Mitchell (b)
 
2
 
WV
 
Steam - Coal
 
780
 
1971
Muskingum River
 
5
 
OH
 
Steam - Coal
 
1,440
 
1953
Picway
 
1
 
OH
 
Steam - Coal
 
100
 
1926
Sporn
 
2
 
WV
 
Steam - Coal
 
300
 
1950
Stuart (a)
 
4
 
OH
 
Steam - Coal
 
600
 
1971
Zimmer (a)
 
1
 
OH
 
Steam - Coal
 
330
 
1991
Total MWs (c)
             
10,002
   
 
(a)
Jointly-owned with nonaffiliated entities.  Figures presented reflect only the portion owned by AGR.
(b)
AGR owns a 50% interest in the Mitchell Units.  KPCo owns the remaining 50%.
(c)
AGR has contractual rights through 2017 to a natural gas-fired 1,186 MW generating unit located in Lawrenceburg, IN.

Domestic Independent Power
                   
               
Net Maximum
 
Year Plant
Plant Name
 
Units
 
State
 
Fuel Type
 
Capacity (MWs)
 
Commissioned
Trent Mesa
 
100
 
TX
 
Wind
 
150
 
2001
Desert Sky
 
107
 
TX
 
Wind
 
161
 
2001
Total MWs
             
311
   

In addition to the AGR and Domestic Independent Power generation set forth above, a subsidiary in the Generation & Marketing segment has contractual rights through 2027 from TNC to 355 MWs from the Oklaunion Generating Plant, a coal-fired unit located in Vernon, TX.  TNC co-owns the Oklaunion Generating Plant with PSO and several non-affiliated entities.

 
47

 


TRANSMISSION AND DISTRIBUTION FACILITIES

The following table sets forth the total overhead circuit miles of transmission and distribution lines of the AEP System and its operating companies and that portion of the total representing 765kV lines:

Vertically Integrated Utilities Segment

 
Total Overhead Circuit Miles of Transmission and Distribution Lines
 
Circuit Miles of 765kV Lines
APCo
51,594
 
731
I&M
21,869
 
614
KGPCo
1,404
 
-
KPCo
11,159
 
257
PSO
20,822
 
-
SWEPCo
27,372
 
-
WPCo
1,728
 
-

Transmission and Distribution Utilities Segment

 
Total Overhead Circuit Miles of Transmission and Distribution Lines
 
Circuit Miles of 765kV Lines
OPCo (a)
45,530
 
508
TCC
29,355
 
-
TNC
17,046
 
-
       
(a)
Includes 766 miles of 345,000 volt jointly owned lines.

AEP Transmission Holdco Segment

The following table sets forth the total overhead circuit miles of transmission lines of ETT, OHTCo and OKTCo:

 
Total Overhead Circuit Miles of Transmission Lines
ETT
1,340
IMTCo
19
OHTCo
47
OKTCo
217

TITLE TO PROPERTY

The AEP System’s generating facilities are generally located on lands owned in fee simple.  The greater portion of the transmission and distribution lines of the AEP System has been constructed over lands of private owners pursuant to easements or along public highways and streets pursuant to appropriate statutory authority.  The rights of AEP’s public utility subsidiaries in the realty on which their facilities are located are considered adequate for use in the conduct of their business.  Minor defects and irregularities customarily found in title to properties of like size and character may exist, but such defects and irregularities do not materially impair the use of the properties affected thereby.  AEP’s public utility subsidiaries generally have the right of eminent domain which permits them, if necessary, to acquire, perfect or secure titles to or easements on privately held lands used or to be used in their utility operations.  Recent legislation in Ohio and Virginia has restricted the right of eminent domain previously granted for power generation purposes.

 
48

 


SYSTEM TRANSMISSION LINES AND FACILITY SITING

Laws in the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Tennessee, Texas, Virginia and West Virginia require prior approval of sites of generating facilities and/or routes of high-voltage transmission lines.  We have experienced delays and additional costs in constructing facilities as a result of proceedings conducted pursuant to such statutes and in proceedings in which our operating companies have sought to acquire rights-of-way through condemnation.  These proceedings may result in additional delays and costs in future years.

CONSTRUCTION PROGRAM

With input from its state utility commissions, the AEP System continuously assesses the adequacy of its generation, transmission, distribution and other facilities to plan and provide for the reliable supply of electric power and energy to its customers.  In this assessment process, assumptions are continually being reviewed as new information becomes available and assessments and plans are modified, as appropriate.  AEP forecasts approximately $3.8 billion of construction expenditures for 2014, excluding equity AFUDC and assets acquired under leases.  Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  For additional information on our construction program, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading entitled Budgeted Construction Expenditures for each Registrant.

POTENTIAL UNINSURED LOSSES

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to our generation plants and costs of replacement power.  Unless allowed to be recovered through rates, future losses or liabilities which are not completely insured could reduce net income and impact the financial conditions of AEP and other AEP System companies.  For risks related to owning a nuclear generating unit, see Note 6 to the consolidated financial statements entitled Commitments, Guarantees and Contingencies under the heading Nuclear Contingencies for information with respect to nuclear incident liability insurance.

ITEM 3.   LEGAL PROCEEDINGS

For a discussion of material legal proceedings, see Note 6 to the consolidated financial statements, entitled Commitments, Guarantees and Contingencies, incorporated by reference in Item 8.

ITEM 4.    MINE SAFETY DISCLOSURE

The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations.  The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters.  SWEPCo, through its ownership of Dolet Hills Lignite Company (DHLC), a wholly-owned lignite mining subsidiary of SWEPCo, and AGR, through its use of the Conner Run fly ash impoundment, is subject to the provisions of the Mine Act.

The Dodd-Frank Wall Street Reform and Consumer Protection Act and the regulations promulgated thereunder require companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act.  Exhibit 95 “Mine Safety Disclosure Exhibit” contains the notices of violation and proposed assessments received by DHLC and Conner Run under the Mine Act for the year ended December 31, 2013.

 
49

 

PART II

ITEM 5.    MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

AEP

In addition to the discussion below, the remaining information required by this item is incorporated herein by reference to the material under AEP Common Stock and Dividend Information and Note 14 to the consolidated financial statements entitled Financing Activities under the heading Dividend Restrictions in the 2013 Annual Report.

APCo, I&M, OPCo, PSO and SWEPCo

The common stock of these companies is held solely by AEP.  The information regarding the amounts of cash dividends on common stock paid by these companies to AEP during 2013, 2012 and 2011 are incorporated by reference to the material under Statements of Changes in Common Shareholder’s Equity and Note 14 to the consolidated financial statements entitled Financing Activities under the heading Dividend Restrictions in the 2013 Annual Reports.

During the quarter ended December 31, 2013, neither AEP nor its publicly-traded subsidiaries purchased equity securities that are registered by AEP or its publicly-traded subsidiaries pursuant to Section 12 of the Exchange Act.

ITEM 6.    SELECTED FINANCIAL DATA

AEP

The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the 2013 Annual Reports.

APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(a). Management’s narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2013 Annual Reports.

ITEM 7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

AEP

The information required by this item is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2013 Annual Reports .

APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(a).  Management’s narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2013 Annual Reports.

ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

AEP, APCo, I&M, OPCo, PSO and SWEPCo

The information required by this item is incorporated herein by reference to the material under Management’s Discussion and Analysis of Financial Condition and Results of Operations – Quantitative and Qualitative Disclosures about Market and Credit Risk in the 2013 Annual Reports.

 
50

 


ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

AEP, APCo, I&M, OPCo, PSO and SWEPCo

The information required by this item is incorporated herein by reference to the financial statements and financial statement schedules described under Item 15 herein.

ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

AEP, APCo, I&M, OPCo, PSO and SWEPCo

None.

ITEM 9A.    CONTROLS AND PROCEDURES

During 2013, management, including the principal executive officer and principal financial officer of each of American Electric Power Company, Inc. (“AEP”), Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company (each a “Registrant” and collectively the “Registrants”) evaluated each respective Registrant’s disclosure controls and procedures.  Disclosure controls and procedures are defined as controls and other procedures of the Registrant that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized, and reported within the time periods specified in the Commission’s rules and forms.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to each Registrant’s management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of December 31, 2013, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.  The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

The only change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter 2013 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting, relates to Ohio Power Company’s corporate separation.  On December 31, 2013, Ohio Power Company transferred its generation assets and related liabilities to AEP Generation Resources Inc, a subsidiary of AEP.  Certain of those generation assets and related liabilities were subsequently transferred to Appalachian Power Company and Kentucky Power Company.  In addition to the transfer of the generation assets and related liabilities, the Interconnection Agreement among AEP’s East zone public utility subsidiaries was terminated and replaced with a new Power Coordination Agreement among Appalachian Power Company, Kentucky Power Company and Indiana Michigan Power Company.  In connection with these activities, American Electric Power Company, Inc., Appalachian Power Company, Indiana Michigan Power Company and Ohio Power Company implemented or modified a number of business processes and controls.

Management assessed and reported on the effectiveness of its internal control over financial reporting as of December 31, 2013.  As a result of that assessment, management determined that there were no material weaknesses as of December 31, 2013 and, therefore, concluded that each Registrant’s internal control over financial reporting was effective.

Additional information required by this item of the Registrants is incorporated by reference to Management’s Report on Internal Control over Financial Reporting, included in the 2013 Annual Report of each Registrant.
 
ITEM 9B.   OTHER INFORMATION
 
None.

 
51

 


PART III

ITEM 10.   DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(c).

AEP

Directors, Director Nomination Process and Audit Committee

Certain of the information called for in this Item 10, including the information relating to directors, is incorporated herein by reference to AEP's definitive proxy information statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to 2014 Annual Meeting of Shareholders (the 2014 Annual Meeting) including under the captions “Election of Directors,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “AEP's Board of Directors and Committees,” “Directors,” "Involvement by Mr. Hoaglin in Certain Legal Proceedings" and “Shareholder Nominees for Directors.”

Executive Officers

Reference also is made to the information under the caption Executive Officers of the Registrants in Part I, Item 4 of this report.

Code of Ethics

AEP’s Principles of Business Conduct is the code of ethics that applies to AEP’s Chief Executive Officer, Chief Financial Officer and principal accounting officer.  The Principles of Business Conduct is available on AEP’s website at www.aep.com.  The Principles of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Investor Relations, American Electric Power Company, Inc., 1 Riverside Plaza, Columbus, Ohio  43215.

If any substantive amendments to the Principles of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Principles of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or principal accounting officer, AEP will disclose the nature of such amendment or waiver on AEP’s website, www.aep.com, or in a report on Form 8-K.

Section 16(a) Beneficial Ownership Reporting Compliance

The information required by this item is incorporated herein by reference to information contained in the definitive proxy statement of AEP for the 2014 Annual Meeting.

ITEM 11.    EXECUTIVE COMPENSATION

APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(c).

AEP

The information called for by this Item 11 is incorporated herein by reference to AEP's definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2014 Annual Meeting including under the captions “Compensation Discussion and Analysis,” “Executive Compensation”, “Director Compensation” and “2013 Director Compensation Table”.  The information set forth under the subcaption “Human Resources Committee Report” and “Audit Committee Report” should not be deemed filed nor should it be incorporated by reference into any other filing under the Securities Act of 1933, as amended, or the Exchange Act except to the extent we specifically incorporate such report by reference therein.

 
52

 


ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(c).

AEP

The information relating to Security Ownership of Certain Beneficial Owners is incorporated herein by reference to AEP’s definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to 2014 Annual Meeting under the caption “Share Ownership of Certain Beneficial Owners and Management" and "Share Ownership of Directors and Executive Officers."

EQUITY COMPENSATION PLAN INFORMATION

The following table summarizes the ability of AEP to issue common stock pursuant to equity compensation plans as of December 31, 2013:

Plan Category
 
Number of Securities to be Issued upon Exercise of Outstanding Options Warrants and Rights
 
Weighted Average Exercise Price of Outstanding Options, Warrants and Rights
 
Number of Securities Remaining
Available for Future Issuance under Equity Compensation Plans (a)
Equity Compensation Plans Approved by Security Holders
 
 
-
 
$
NA
 
15,972,699
Equity Compensation Plans Not Approved by Security Holders
 
-
   
-
 
-
Total
 
-
 
$
NA
 
15,972,699

(a)
AEP deducts equity compensation granted in stock units that are paid in cash, rather than AEP common shares, such as AEP’s performance units and deferred stock units, from the number of shares available for future grants under the Amended and Restated American Electric Power System Long-Term Incentive Plan.  The number of shares available under this plan would be 2,687,883 higher if equity compensation that is paid in cash were not deducted from this column.
NA
Not applicable.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

APCo, I&M, OPCo, PSO and SWEPCo

Omitted pursuant to Instruction I(2)(c).

AEP

The information called for by this Item 13 is incorporated herein by reference to AEP's definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2014 Annual Meeting under the captions “Transactions with Related Persons” and “Director Independence.”

ITEM 14.    PRINCIPAL ACCOUNTING FEES AND SERVICES

AEP

The information called for by this Item 14 is incorporated herein by reference to AEP's definitive proxy statement (which will be filed with the SEC pursuant to Regulation 14A under the Exchange Act) relating to the 2014 Annual Meeting under the captions “Audit and Non-Audit Fees,” "Audit Committee Report" and “Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of the Independent Auditor.”

 
53

 


APCo, I&M, OPCo, PSO and SWEPCo

Each of the above is a wholly-owned subsidiary of AEP and does not have a separate audit committee.  A description of the AEP Audit Committee pre-approval policies, which apply to these companies, is contained in the definitive proxy statement of AEP for the 2014 Annual Meeting of shareholders.  The following table presents directly billed fees for professional services rendered by Deloitte & Touche LLP for the audit of these companies’ annual financial statements for the years ended December 31, 2013 and 2012, and fees directly billed for other services rendered by Deloitte & Touche LLP during those periods.  Deloitte & Touche LLP also provides additional professional and other services to the AEP System, the cost of which may ultimately be allocated to these companies though not billed directly to them.  For a description of these fees and services, see the description of principal accounting fees and services for AEP, above.

   
APCo
 
I&M
 
OPCo
   
2013
 
2012
 
2013
 
2012
 
2013
 
2012
                                   
Audit Fees
 
$
2,342,744
 
$
2,026,590 
 
$
1,552,346
 
$
1,447,948 
 
$
3,119,885
 
$
2,459,868 
Audit-Related Fees
   
104,923
   
57,556 
   
51,488
   
47,022 
   
128,535
   
60,901 
Tax Fees
   
22,556
   
22,623 
   
16,677
   
16,806 
   
278,029
   
28,842 
Total
 
$
2,470,223
 
$
2,106,769 
 
$
1,620,511
 
$
1,511,776 
 
$
3,526,449
 
$
2,549,611 

   
PSO
 
SWEPCo
   
2013
 
2012
 
2013
 
2012
                     
Audit Fees
 
$
641,720
 
$
612,686 
 
$
1,131,155
 
$
1,014,601 
Audit-Related Fees
   
21,920
   
25,125 
   
102,633
   
778,130 
Tax Fees
   
7,100
   
7,177 
   
12,505
   
11,413 
Total
 
$
670,740
 
$
644,988 
 
$
1,246,293
 
$
1,804,144 


 
54

 

PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 
The following documents are filed as a part of this report:

1.  FINANCIAL STATEMENTS:
 
The following financial statements have been incorporated herein by reference pursuant to Item 8.
 
   
AEP and Subsidiary Companies:
 
Reports of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting; Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2013, 2012 and 2011; Consolidated Statements of Changes in Equity for the years ended December 31, 2013, 2012 and 2011; Consolidated Balance Sheets as of December 31, 2013 and 2012; Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011; Notes to Consolidated Financial Statements.
 
   
APCo, I&M and OPCo:
 
Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2013, 2012 and 2011; Consolidated Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2013, 2012 and 2011; Consolidated Balance Sheets as of December 31, 2013 and 2012; Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011; Notes to Financial Statements of Registrant Subsidiaries; Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting.
 
   
PSO:
 
Statements of Income for the years ended December 31, 2013, 2012 and 2011; Statements of Comprehensive Income (Loss) for the years ended December 31, 2013, 2012 and 2011; Statements of Changes in Common Shareholder’s Equity for the years ended December 31, 2013, 2012 and 2011; Balance Sheets as of December 31, 2013 and 2012; Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011; Notes to Financial Statements of Registrant Subsidiaries; Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting.
 
   
SWEPCo:
 
Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011; Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2013, 2012 and 2011; Consolidated Statements of Changes in Equity for the years ended December 31, 2013, 2012 and 2011; Consolidated Balance Sheets as of December 31, 2013 and 2012; Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011; Notes to Financial Statements of Registrant Subsidiaries; Report of Independent Registered Public Accounting Firm; Management’s Report on Internal Control over Financial Reporting.
 

 
Page
2.  FINANCIAL STATEMENT SCHEDULES:
Number
Financial Statement Schedules are listed in the Index of Financial Statement Schedules.  (Certain schedules have been omitted because the required information is contained in the notes to financial statements or because such schedules are not required or are not applicable). Reports of Independent Registered Public Accounting Firm.
S-1
   
3.  EXHIBITS:
 
Exhibits for AEP, APCo, I&M, OPCo, PSO and SWEPCo are listed in the Exhibit Index beginning on page E-1 and are incorporated herein by reference.
E-1

 
55

 

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 
American Electric Power Company, Inc.
     
     
 
By:
/s/   Brian X. Tierney
   
(Brian X. Tierney, Executive Vice President
   
and Chief Financial Officer)

Date: February 25, 2014

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature
 
Title
 
Date
         
(i)                                                              Principal Executive Officer:        
         
 
/s/   Nicholas K. Akins
 
Chairman of the Board,
Chief Executive Officer and Director
 
February 25, 2014
(Nicholas K. Akins)
       
         
         
(ii)                                                             Principal Financial Officer:
       
         
/s/   Brian X. Tierney
 
Executive Vice President and
 
February 25, 2014
(Brian X. Tierney)
 
Chief Financial Officer
   
         
(iii)                                                            Principal Accounting Officer:
       
         
/s/   Joseph M. Buonaiuto
 
Senior Vice President, Controller and
 
February 25, 2014
(Joseph M. Buonaiuto)
 
Chief Accounting Officer
   
         
(iv)                                                             A Majority of the Directors:
       
         
*Nicholas K. Akins
       
*David J. Anderson
       
* J. Barnie Beasley, Jr.
       
* Ralph D. Crosby, Jr.
       
*Linda A. Goodspeed
       
*Thomas E. Hoaglin
       
*Sandra Beach Lin
       
*Michael G. Morris
       
*Richard C. Notebaert
       
*Lionel L. Nowell, III
*Stephen S. Rasmussen
*Oliver G. Richard, III
       
*Richard L. Sandor
       
*Sara Martinez Tucker
       
*John F. Turner
       
         
           
*By:                                                                /s/   Brian X. Tierney      
February 25, 2014
 
                                         (Brian X. Tierney, Attorney-in-Fact)
       


 
56

 

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.  The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 
Appalachian Power Company
 
Ohio Power Company
 
Public Service Company of Oklahoma
 
Southwestern Electric Power Company
     
 
By:
/s/   Brian X. Tierney
   
(Brian X. Tierney, Executive Vice President
   
and Chief Financial Officer)

Date: February 25, 2014

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.  The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature
 
Title
 
Date
         
(i)                                                              Principal Executive Officer:
       
         
               /s/   Nicholas K. Akins
 
Chairman of the Board,
 
February 25, 2014
(Nicholas K. Akins)
 
Chief Executive Officer and Director
   
         
(ii)                                                             Principal Financial Officer:
       
         
                /s/   Brian X. Tierney
 
Vice President,
 
February 25, 2014
             (Brian X. Tierney)
 
Chief Financial Officer and Director
   
         
(iii)                                                            Principal Accounting Officer:
       
         
                /s/   Joseph M. Buonaiuto
 
Controller and
 
February 25, 2014
             (Joseph M. Buonaiuto)
 
Chief Accounting Officer
   
         
(iv)                                                             A Majority of the Directors:
       
         
              *Nicholas K. Akins
       
               *Lisa M. Barton
       
              *David M. Feinberg
              *Lana L. Hillebrand
       
              *Mark C. McCullough
       
              *Robert P. Powers
       
               *Dennis E. Welch
       
         
*By:                                                                                      /s/   Brian X. Tierney      
February 25, 2014
                                                             (Brian X. Tierney, Attorney-in-Fact)        


 
57

 

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.  The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

 
Indiana Michigan Power Company
     
     
 
By:
/s/   Brian X. Tierney
   
(Brian X. Tierney, Executive Vice President
   
and Chief Financial Officer)

Date: February 25, 2014

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.  The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature
 
Title
 
Date
         
(i)                                                        Principal Executive Officer:
       
         
/s/   Nicholas K. Akins
 
Chairman of the Board,
 
February 25, 2014
(Nicholas K. Akins)
 
Chief Executive Officer and Director
   
         
(ii)                                                       Principal Financial Officer:
       
         
/s/   Brian X. Tierney
 
Vice President,
 
February 25, 2014
(Brian X. Tierney)
 
Chief Financial Officer and Director
   
         
(iii)                                                      Principal Accounting Officer:
       
         
/s/   Joseph M. Buonaiuto
 
Controller and
 
February 25, 2014
(Joseph M. Buonaiuto)
 
Chief Accounting Officer
   
         
(iv)                                                      A Majority of the Directors:
       
         
*Nicholas K. Akins
       
*Lisa M. Barton
       
*Sarah L. Bodner
       
*Paul Chodak, III
       
*Thomas A. Kratt
       
*Marc E. Lewis
       
*Mark C. McCullough
       
*Robert P. Powers
       
*Carla E. Simpson
       
         
*By:                                                                    /s/   Brian X. Tierney      
February 25, 2014
                                                         (Brian X. Tierney, Attorney-in-Fact)        


 
58

 

INDEX OF FINANCIAL STATEMENT SCHEDULES

   
Page
Number
Reports of Independent Registered Public Accounting Firm
 
S-2
     
The following financial statement schedules are included in this report on the pages indicated:
 
     
American Electric Power Company, Inc. (Parent):
   
 
Schedule I – Condensed Financial Information
 
S-3
 
Schedule I – Index of Condensed Notes to Condensed Financial Information
 
S-7
     
American Electric Power Company, Inc. and Subsidiary Companies:
   
 
Schedule II – Valuation and Qualifying Accounts and Reserves
 
S-10
       
Appalachian Power Company and Subsidiaries:
   
 
Schedule II – Valuation and Qualifying Accounts and Reserves
 
S-10
       
Indiana Michigan Power Company and Subsidiaries:
   
 
Schedule II – Valuation and Qualifying Accounts and Reserves
 
S-10
       
Ohio Power Company and Subsidiaries:
   
 
Schedule II – Valuation and Qualifying Accounts and Reserves
 
S-10
       
Public Service Company of Oklahoma:
   
 
Schedule II – Valuation and Qualifying Accounts and Reserves
 
S-11
       
Southwestern Electric Power Company Consolidated:
   
 
Schedule II – Valuation and Qualifying Accounts and Reserves
 
S-11

 
S-1

 


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
American Electric Power Company, Inc.

We have audited the consolidated financial statements of American Electric Power Company, Inc. and subsidiary companies (the “Company”) as of December 31, 2013 and 2012, and for each of the three years in the period ended December 31, 2013, and the Company's internal control over financial reporting as of December 31, 2013, and have issued our reports thereon dated February 25, 2014; such consolidated financial statements and reports are included in the Company’s 2013 Annual Report and are incorporated herein by reference.  Our audits also included the financial statement schedules of the Company listed in Item 15.  These financial statement schedules are the responsibility of the Company's management.  Our responsibility is to express an opinion based on our audits.  In our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/  Deloitte & Touche LLP

Columbus, Ohio
February 25, 2014



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of
Appalachian Power Company
Indiana Michigan Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company

We have audited the financial statements of Appalachian Power Company and subsidiaries, Indiana Michigan Power Company and subsidiaries, Ohio Power Company and subsidiaries, Public Service Company of Oklahoma and Southwestern Electric Power Company Consolidated (collectively the “Companies”) as of December 31, 2013 and 2012, and for each of the three years in the period ended December 31, 2013, and have issued our reports thereon dated February 25, 2014; such financial statements and reports are included in the Companies’ 2013 Annual Reports and are incorporated herein by reference.  Our audits also included the financial statement schedule of each of the Companies listed in Item 15.  These financial statement schedules are the responsibility of the Companies’ management.  Our responsibility is to express an opinion based on our audits.  In our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/  Deloitte & Touche LLP

Columbus, Ohio
February 25, 2014


 
S-2

 


SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED STATEMENTS OF INCOME
For the Years Ended December 31, 2013, 2012 and 2011
(in millions, except per-share and share amounts)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
2013 
 
2012 
 
2011 
REVENUES
 
 
 
 
 
 
 
 
 
Affiliated Revenues
 
$
 4 
 
$
 4 
 
$
 5 
 
 
 
 
 
 
 
 
 
 
 
EXPENSES
 
 
 
 
 
 
 
 
 
Other Operation
 
 
 21 
 
 
 22 
 
 
 23 
 
 
 
 
 
 
 
 
 
 
OPERATING LOSS
 
 
 (17)
 
 
 (18)
 
 
 (18)
 
 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 21 
 
 
 22 
 
 
 19 
Interest Expense
 
 
 (17)
 
 
 (90)
 
 
 (42)
 
 
 
 
 
 
 
 
 
 
LOSS BEFORE INCOME TAX CREDIT AND
 
 
 
 
 
 
 
 
 
 
EQUITY EARNINGS
 
 
 (13)
 
 
 (86)
 
 
 (41)
 
 
 
 
 
 
 
 
 
 
Income Tax Credit
 
 
 - 
 
 
 - 
 
 
 2 
Equity Earnings of Unconsolidated Subsidiaries
 
 
 1,493 
 
 
 1,345 
 
 
 1,980 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME
 
 
 1,480 
 
 
 1,259 
 
 
 1,941 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss)
 
 
 217 
 
 
 133 
 
 
 (89)
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
 
$
 1,697 
 
$
 1,392 
 
$
 1,852 
 
 
 
 
 
 
 
 
 
 
 
WEIGHTED AVERAGE NUMBER OF BASIC AEP
 
 
 
 
 
 
 
 
 
 
COMMON SHARES OUTSTANDING
 
 
 486,619,555 
 
 
 484,682,469 
 
 
 482,169,282 
 
 
 
 
 
 
 
 
 
 
 
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE
 
 
 
 
 
 
 
 
 
 
TO AEP COMMON SHAREHOLDERS
 
$
 3.04 
 
$
 2.60 
 
$
 4.02 
 
 
 
 
 
 
 
 
 
 
 
WEIGHTED AVERAGE NUMBER OF DILUTED AEP
 
 
 
 
 
 
 
 
 
 
COMMON SHARES OUTSTANDING
 
 
 487,040,956 
 
 
 485,084,694 
 
 
 482,460,328 
 
 
 
 
 
 
 
 
 
 
 
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE
 
 
 
 
 
 
 
 
 
 
TO AEP COMMON SHAREHOLDERS
 
$
 3.04 
 
$
 2.60 
 
$
 4.02 
 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Information beginning on page S-7.

 
S-3

 


SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED BALANCE SHEETS
ASSETS
December 31, 2013 and 2012
(in millions)
 
 
 
 
 
 
 
 
 
December 31,
 
 
2013 
 
2012 
CURRENT ASSETS
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 36 
 
$
 166 
Other Temporary Investments
 
 
 2 
 
 
 2 
Advances to Affiliates
 
 
 539 
 
 
 650 
Accounts Receivable:
 
 
 
 
 
 
 
General
 
 
 - 
 
 
 71 
 
Affiliated Companies
 
 
 11 
 
 
 36 
 
 
Total Accounts Receivable
 
 
 11 
 
 
 107 
Prepayments and Other Current Assets
 
 
 6 
 
 
 5 
TOTAL CURRENT ASSETS
 
 
 594 
 
 
 930 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
General
 
 
 1 
 
 
 1 
Total Property, Plant and Equipment
 
 
 1 
 
 
 1 
Accumulated Depreciation and Amortization
 
 
 1 
 
 
 1 
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET
 
 
 - 
 
 
 - 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
Investments in Unconsolidated Subsidiaries
 
 
 16,353 
 
 
 15,679 
Affiliated Notes Receivable
 
 
 80 
 
 
 285 
Deferred Charges and Other Noncurrent Assets
 
 
 57 
 
 
 54 
TOTAL OTHER NONCURRENT ASSETS
 
 
 16,490 
 
 
 16,018 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 17,084 
 
$
 16,948 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Information beginning on page S-7.
 
 
 
 
 
 

 
S-4

 


SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31, 2013 and 2012
(dollars in millions)
 
 
 
 
 
 
 
 
 
December 31,
 
 
2013 
 
2012 
CURRENT LIABILITIES
 
 
Advances from Affiliates
 
$
 41 
 
$
 - 
Accounts Payable:
 
 
 
 
 
 
 
General
 
 
 - 
 
 
 1 
 
Affiliated Companies
 
 
 13 
 
 
 435 
Long-term Debt Due Within One Year
 
 
 4 
 
 
 5 
Short-term Debt
 
 
 57 
 
 
 321 
Other Current Liabilities
 
 
 5 
 
 
 74 
TOTAL CURRENT LIABILITIES
 
 
 120 
 
 
 836 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
Long-term Debt
 
 
 836 
 
 
 847 
Deferred Credits and Other Noncurrent Liabilities
 
 
 43 
 
 
 28 
TOTAL NONCURRENT LIABILITIES
 
 
 879 
 
 
 875 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 999 
 
 
 1,711 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMMON SHAREHOLDERS' EQUITY
 
 
 
 
 
 
Common Stock – Par Value – $6.50 Per Share:
 
 
 
 
 
 
 
 
 
2013 
 
2012 
 
 
 
 
 
 
 
 
Shares Authorized
600,000,000 
 
600,000,000 
 
 
 
 
 
 
 
 
Shares Issued
508,113,964 
 
506,004,962 
 
 
 
 
 
 
 
(20,336,592 Shares were Held in Treasury as of December 31, 2013 and 2012)
 
 
 3,303 
 
 
 3,289 
Paid-in Capital
 
 
 6,131 
 
 
 6,049 
Retained Earnings
 
 
 6,766 
 
 
 6,236 
Accumulated Other Comprehensive Income (Loss)
 
 
 (115)
 
 
 (337)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY
 
 
 16,085 
 
 
 15,237 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY
 
$
 17,084 
 
$
 16,948 
 
 
 
  
 
 
  
See Condensed Notes to Condensed Financial Information beginning on page S-7.
 
 
 
 
 
 

 
S-5

 


SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
CONDENSED FINANCIAL INFORMATION
CONDENSED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2013, 2012 and 2011
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
2013 
 
2012 
 
2011 
OPERATING ACTIVITIES
 
 
 
 
 
 
 
 
 
Net Income
 
 1,480 
 
 1,259 
 
 1,941 
Adjustments to Reconcile Net Income to Net Cash Flows
 
 
 
 
 
 
 
 
 
 
from Operating Activities:
 
 
 
 
 
 
 
 
 
 
 
Equity Earnings of Unconsolidated Subsidiaries
 
 
 (1,493)
 
 
 (1,345)
 
 
 (1,980)
 
 
Cash Dividends Received from Unconsolidated Subsidiaries
 
 
 1,027 
 
 
 1,294 
 
 
 1,113 
 
 
Change in Other Noncurrent Assets
 
 
 2 
 
 
 13 
 
 
 2 
 
 
Change in Other Noncurrent Liabilities
 
 
 16 
 
 
 22 
 
 
 20 
 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 96 
 
 
 (47)
 
 
 72 
 
 
 
Accounts Payable
 
 
 (423)
 
 
 (10)
 
 
 (103)
 
 
 
Other Current Liabilities
 
 
 (73)
 
 
 72 
 
 
 (3)
Net Cash Flows from Operating Activities
 
 
 632 
 
 
 1,258 
 
 
 1,062 
 
 
 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
 
 
 
Purchases of Investment Securities
 
 
 - 
 
 
 - 
 
 
 (69)
Sales of Investment Securities
 
 
 - 
 
 
 - 
 
 
 166 
Change in Advances to Affiliates, Net
 
 
 111 
 
 
 294 
 
 
 (388)
Capital Contributions to Unconsolidated Subsidiaries
 
 
 (358)
 
 
 (325)
 
 
 (99)
Return of Capital Contributions from Unconsolidated Subsidiaries
 
 
 375 
 
 
 - 
 
 
 - 
Repayments of Notes Receivable from Affiliated Companies
 
 
 205 
 
 
 5 
 
 
 5 
Net Cash Flows from (Used for) Investing Activities
 
 
 333 
 
 
 (26)
 
 
 (385)
 
 
 
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
 
 
 
Issuance of Common Stock, Net
 
 
 84 
 
 
 83 
 
 
 92 
Issuance of Long-term Debt
 
 
 199 
 
 
 843 
 
 
 - 
Commercial Paper and Credit Facility Borrowings
 
 
 - 
 
 
 - 
 
 
 429 
Change in Short-term Debt, Net
 
 
 (264)
 
 
 (646)
 
 
 769 
Retirement of Long-term Debt
 
 
 (200)
 
 
 (558)
 
 
 - 
Change in Advances from Affiliates, Net
 
 
 41 
 
 
 - 
 
 
 (295)
Commercial Paper and Credit Facility Repayments
 
 
 - 
 
 
 - 
 
 
 (881)
Dividends Paid on Common Stock
 
 
 (949)
 
 
 (911)
 
 
 (892)
Other Financing Activities
 
 
 (6)
 
 
 (4)
 
 
 (3)
Net Cash Flows Used for Financing Activities
 
 
 (1,095)
 
 
 (1,193)
 
 
 (781)
 
 
 
 
 
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 (130)
 
 
 39 
 
 
 (104)
Cash and Cash Equivalents at Beginning of Period
 
 
 166 
 
 
 127 
 
 
 231 
Cash and Cash Equivalents at End of Period
 
 36 
 
 166 
 
 127 
 
 
 
 
 
 
 
 
 
 
See Condensed Notes to Condensed Financial Information beginning on page S-7.
 
 
 
 
 
 
 
 
 

 
S-6

 


SCHEDULE I
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL INFORMATION

1.   Summary of Significant Accounting Policies
   
2.   Commitments, Guarantees and Contingencies
   
3.   Financing Activities
   
4.   Related Party Transactions

 
S-7

 

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The condensed financial information of AEP (Parent) is required as a result of the restricted net assets of consolidated subsidiaries exceeding 25% of consolidated net assets as of December 31, 2013.  Parent is a public utility holding company that owns all of the outstanding common stock of its public utility subsidiaries and varying percentages of other subsidiaries, including joint ventures and equity investments.  The primary source of income for Parent is equity in its subsidiaries’ earnings.  Its major source of cash is dividends from the subsidiaries.  Parent borrows the funds for the money pool that is used by the subsidiaries for their short-term cash needs.

Income Taxes

Parent files a consolidated federal income tax return with its subsidiaries.  AEP System’s current consolidated federal income tax is allocated to AEP System companies so that their current tax expense reflects a separate return result for each company in the consolidated group.  The tax benefit of Parent is allocated to its subsidiaries with taxable income.
 

2.   COMMITMENTS, GUARANTEES AND CONTINGENCIES

Parent and its subsidiaries are parties to environmental and other legal matters.  For further discussion of commitments, guarantees and contingencies, see Note 6 in the 2013 Annual Reports.

3.   FINANCING ACTIVITIES

The following details long-term debt outstanding as of December 31, 2013 and 2012:

Long-term Debt
 
 
 
 
 
 
 
 
 
 
 
Weighted Average
 
Interest Rate Ranges as of
 
Outstanding as of
 
 
 
Interest Rate as of
 
December 31,
 
December 31,
 
Type of Debt and Maturity
 
December 31, 2013
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
 
 
 
 
 
 
(in millions)
 
Senior Unsecured Notes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2017-2022
 
2.11%
 
1.65% - 2.95%
 
1.65% - 2.95%
 
$
 850 
 
$
 850 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Interest Rate Hedges
 
 
 
 
 
 
 
 
 (9)
 
 
 3 
 
Unamortized Discount, Net
 
 
 
 
 
 
 
 
 (1)
 
 
 (1)
 
Total Long-term Debt Outstanding
 
 
 
 
 
 
 
 
 840 
 
 
 852 
 
Long-term Debt Due Within One Year
 
 
 
 
 
 
 
 
 4 
 
 
 5 
 
Long-term Debt
 
 
 
 
 
 
 
$
 836 
 
$
 847 

Long-term debt outstanding as of December 31, 2013 is payable as follows:

 
 
 
 
 
 
 
 
 
 
 
After
 
 
 
2014 
 
2015 
 
2016 
 
2017 
 
2018 
 
2018 
 
Total
 
(in millions)
Principal Amount
$
 4 
 
$
 1 
 
$
 (4)
 
$
 540 
 
$
 - 
 
$
 300 
 
$
 841 
Unamortized Discount, Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (1)
Total Long-term Debt Outstanding
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$
 840 


 
S-8

 



Short-term Debt
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Parent's outstanding short-term debt was as follows:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31,
 
 
 
 
2013 
 
2012 
 
 
 
 
Outstanding
 
Weighted Average
 
Outstanding
 
Weighted Average
 
Type of Debt
Amount
Interest Rate
 
Amount
Interest Rate
 
 
 
(in millions)
 
 
 
 
(in millions)
 
 
 
 
Commercial Paper
 
$
 57 
 
 0.29 
%
 
$
 321 
 
 0.42 
%
 
Total Short-term Debt
 
$
 57 
 
 
 
 
$
 321 
 
 
 

4.   RELATED PARTY TRANSACTIONS

Payments on Behalf of Subsidiaries

Due to occasional time sensitivity and complexity of payments, Parent makes certain insurance, tax and benefit payments on behalf of subsidiary companies.  Parent is then fully reimbursed by the subsidiary companies.

Short-term Lending to Subsidiaries

Parent uses a commercial paper program to meet the short-term borrowing needs of subsidiaries.  The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries.  In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  The program also allows some direct borrowers to invest excess cash with Parent.

Interest expense related to Parent’s short-term borrowing is included in Interest Expense on Parent’s statements of income.  Parent incurred interest expense for amounts borrowed from subsidiaries of $7 thousand, $11 thousand and $199 thousand for the years ended December 31, 2013, 2012 and 2011, respectively.

Interest income related to Parent’s short-term lending is included in Interest Income on Parent’s statements of income.  Parent earned interest income for amounts advanced to subsidiaries of $4 million, $5 million and $3 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Global Borrowing Notes

Parent issued long-term debt, portions of which were loaned to its subsidiaries.  Parent pays interest on the global notes, but the subsidiaries accrue interest for their share of the global borrowing and remit the interest to Parent.  Interest income related to Parent’s loans to subsidiaries is included in Interest Income on Parent’s statements of income.  Parent earned interest income on loans to subsidiaries of $15 million, $15 million and $15 million for the years ended December 31, 2013, 2012 and 2011, respectively.


 
S-9

 


SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
 
AEP
 
 
 
Additions
 
 
 
 
 
 
 
 
Balance at
 
Charged to
 
Charged to
 
 
 
Balance at
 
 
 
 
Beginning
 
Costs and
 
Other
 
 
 
End of
Description
 
of Period
 
Expenses
 
Accounts (a)
 
Deductions (b)
 
Period
 
 
(in millions)
Deducted from Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated Provision for Uncollectible
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Accounts:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2013
 
$
 36 
 
$
 51 
 
$
 21 
 
$
 48 
 
$
 60 
 
 
Year Ended December 31, 2012
 
 
 32 
 
 
 53 
 
 
 3 
 
 
 52 
 
 
 36 
 
 
Year Ended December 31, 2011
 
 
 41 
 
 
 37 
 
 
 2 
 
 
 48 
 
 
 32 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Recoveries offset by reclasses to other liabilities.
(b)
Uncollectible accounts written off.

APCo
 
 
 
Additions
 
 
 
 
 
 
 
 
Balance at
 
Charged to
 
Charged to
 
 
 
Balance at
 
 
 
 
Beginning
 
Costs and
 
Other
 
 
 
End of
Description
 
of Period
 
Expenses
 
Accounts (a)
 
Deductions (b)
 
Period
 
 
(in thousands)
Deducted from Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated Provision for Uncollectible
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Accounts:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2013
 
$
 6,087 
 
$
 4,737 
 
$
 1,768 
 
$
 10,149 
 
$
 2,443 
 
 
Year Ended December 31, 2012
 
 
 5,289 
 
 
 15,652 
 
 
 1,689 
 
 
 16,543 
 
 
 6,087 
 
 
Year Ended December 31, 2011
 
 
 6,667 
 
 
 6,041 
 
 
 1,535 
 
 
 8,954 
 
 
 5,289 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Recoveries offset by reclasses to other liabilities.
(b)
Uncollectible accounts written off.

I&M
 
 
 
Additions
 
 
 
 
 
 
 
 
Balance at
 
Charged to
 
Charged to
 
 
 
Balance at
 
 
 
 
Beginning
 
Costs and
 
Other
 
 
 
End of
Description
 
of Period
 
Expenses
 
Accounts (a)
 
Deductions (b)
 
Period
 
 
(in thousands)
Deducted from Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated Provision for Uncollectible
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Accounts:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2013
 
$
 229 
 
$
 (40)
(c)
$
 - 
 
$
 5 
 
$
 184 
 
 
Year Ended December 31, 2012
 
 
 1,750 
 
 
 20 
 
 
 - 
 
 
 1,541 
 
 
 229 
 
 
Year Ended December 31, 2011
 
 
 1,692 
 
 
 151 
 
 
 - 
 
 
 93 
 
 
 1,750 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Recoveries offset by reclasses to other liabilities.
(b)
Uncollectible accounts written off.
(c)
Recoveries on previous reserve balance.

OPCo
 
 
 
Additions
 
 
 
 
Distribution
 
 
 
 
 
 
Balance at
 
Charged to
 
Charged to
 
 
 
 
of OPCo
 
Balance at
 
 
 
 
Beginning
 
Costs and
 
Other
 
 
 
 
Generation
 
End of
Description
 
of Period
 
Expenses
 
Accounts (a)
 
Deductions (b)
 
 
to Parent
 
Period
 
 
(in thousands)
Deducted from Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated Provision for Uncollectible
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Accounts:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2013
 
$
 129 
 
$
 15,722 
 
$
 19,191 
 
$
 51 
 
$
 (7)
 
$
 34,984 
 
 
Year Ended December 31, 2012
 
 
 3,563 
 
 
 (9)
(c)
 
 43 
 
 
 3,468 
 
 
 - 
 
 
 129 
 
 
Year Ended December 31, 2011
 
 
 3,768 
 
 
 59 
 
 
 (10)
 
 
 254 
 
 
 - 
 
 
 3,563 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Recoveries offset by reclasses to other liabilities.
(b)
Uncollectible accounts written off.
(c)
Recoveries on previous reserve balance.

 
S-10

 



PSO
 
 
 
Additions
 
 
 
 
 
 
 
 
Balance at
 
Charged to
 
 
Charged to
 
 
 
Balance at
 
 
 
 
Beginning
 
Costs and
 
 
Other
 
 
 
End of
Description
 
of Period
 
Expenses
 
 
Accounts (a)
 
Deductions (b)
 
Period
 
 
(in thousands)
Deducted from Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated Provision for Uncollectible
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Accounts:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2013
 
$
 872 
 
$
 (122)
(c)
 
$
 - 
 
$
 288 
 
$
 462 
 
 
Year Ended December 31, 2012
 
 
 777 
 
 
 95 
 
 
 
 - 
 
 
 - 
 
 
 872 
 
 
Year Ended December 31, 2011
 
 
 971 
 
 
 (194)
(c)
 
 
 - 
 
 
 - 
 
 
 777 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Recoveries on accounts previously written off.
(b)
Uncollectible accounts written off.
(c)
Recoveries on previous reserve balance.

SWEPCo
 
 
 
Additions
 
 
 
 
 
 
 
 
Balance at
 
Charged to
 
 
Charged to
 
 
 
Balance at
 
 
 
 
Beginning
 
Costs and
 
 
Other
 
 
 
End of
Description
 
of Period
 
Expenses
 
 
Accounts (a)
 
Deductions (b)
 
Period
 
 
(in thousands)
Deducted from Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated Provision for Uncollectible
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Accounts:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2013
 
$
 2,041 
 
$
 (143)
(c)
 
$
 2 
 
$
 482 
 
$
 1,418 
 
 
Year Ended December 31, 2012
 
 
 989 
 
 
 71 
 
 
 
 981 
 
 
 - 
 
 
 2,041 
 
 
Year Ended December 31, 2011
 
 
 588 
 
 
 149 
 
 
 
 376 
 
 
 124 
 
 
 989 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Recoveries on accounts previously written off.
(b)
Uncollectible accounts written off.
(c)
Recoveries on previous reserve balance.




 
S-11

 

EXHIBIT INDEX

The documents listed below are being filed or have previously been filed on behalf of the Registrants shown and are incorporated herein by reference to the documents indicated and made a part hereof.  Exhibits (“Ex”) not identified as previously filed are filed herewith.  Exhibits designated with a dagger (†) are management contracts or compensatory plans or arrangements required to be filed as an Exhibit to this Form.  Exhibits designated with an asterisk (*) are filed herewith.

Exhibit
Designation
 
Nature of Exhibit
 
Previously Filed as Exhibit to:
     
AEP‡   File No. 1-3525
   
         
3(a)
 
Composite of the Restated Certificate of Incorporation of AEP, dated April 28, 2009.
 
2009 Form 10-K, Ex 3(a)
         
3(b)
 
Composite By-Laws of AEP, as amended as of September 25, 2012.
 
Form 8-K, Ex 3.1 dated September 26, 2012
         
4(a)
 
Indenture (for unsecured debt securities), dated as of May 1, 2001, between AEP and The Bank of New York, as Trustee.
 
Registration Statement No. 333-86050, Ex 4(a)(b)(c)
Registration Statement No. 333-105532, Ex 4(d)(e)(f)
         
4(b)
 
Company Order and Officer’s Certificate to The Bank of New York Mellon Trust Company, N.A. dated  December 3, 2012 establishing terms  1.65% Senior Notes, Series E, due 2017 and 2.95% Senior Notes, Series F, due 2022.
 
Form 8-K, Ex. 4(a) dated December 3, 2012.
         
4(c)
 
$1.75 Billion Second  Amended and Restated Credit Agreement, dated as of February 13, 2013, among AEP, the banks, financial institutions and other institutional lenders listed on the signature pages thereof, and JP Morgan Chase Bank, N.A., as Administrative Agent.
 
2012 Form 10-K, Ex 4(c)
         
4(d)
 
$1.75 Billion Amended and Restated Credit Agreement, dated as of February 13, 2013, among AEP, the banks, financial institutions and other institutional lenders listed on the signature pages thereof, and Barclays Bank PLC as Administrative Agent.
 
2012 Form 10-K, Ex 4(d)
         
4(e)
 
$1 Billion Term Credit Agreement, dated as of July 17, 2013, among AEP, APCo, OPCo, AEP Generation Resources Inc., the banks, financial institutions and other institutional lenders listed on the signature pages thereof, and Wells Fargo Bank, National Association, as Administrative Agent.
 
Form 10Q, Ex 4, June 30, 2013
         
[10(a)
 
Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, OPCo and I&M and with AEPSC, as amended.
 
Registration Statement No. 2-52910, Ex 5(a)
Registration Statement No. 2-61009, Ex 5(b)
1990 Form 10-K, Ex 10(a)(3)]
         
*10(b)
 
Restated and Amended Operating Agreement, among PSO, SWEPCo and AEPSC, effective as of March 1, 2014.
   
 
 
E-1

 
Exhibit
Designation
   
Nature of Exhibit
   
Previously Filed as Exhibit to:
         
*10(c)
 
Transmission Agreement, effective November 2010, among APCo, CSPCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent.
   
         
10(d)
 
Transmission Coordination Agreement dated January 1, 1997, restated and amended by and among PSO, SWEPCo and AEPSC.
 
2009 From 10-K, Ex 10(d)
         
10(e)
 
Amended and Restated Operating Agreement dated as of June 2, 1997, of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, KGPCo and WPCo.
 
2004 Form 10-K, Ex 10(e)(1)
         
10(e)(1)
 
PJM West Reliability Assurance Agreement, dated as of March 14, 2001, among Load Serving Entities in the PJM West service area.
 
2004 Form 10-K, Ex 10(e)(2)
         
10(e)(2)
 
Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, KGPCo and WPCo.
 
2004 Form 10-K, Ex 10(e)(3)
         
10(f)
 
Lease Agreements, dated as of December 1, 1989, between AEGCo or I&M and Wilmington Trust Company, as amended.
 
Registration Statement No. 33-32752, Ex 28(c)(1-6)(C)
Registration Statement No. 33-32753, Ex 28(a)(1-6)(C)
AEGCo 1993 Form 10-K, Ex 10(c)(1-6)(B)
I&M 1993 Form 10-K, Ex 10(e)(1-6)(B)
         
[10(g)
 
Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.
 
1996 Form 10-K, Ex 10(l)]
         
10(h)
 
Consent Decree with U.S. District Court dated October 9, 2007, as modified.
 
Form 8-K, Ex 10.1 dated October 9, 2007
Form 10-Q, Ex 10, June 30, 2013
         
†10(i)
 
AEP Accident Coverage Insurance Plan for Directors.
 
1985 Form 10-K, Ex 10(g)
         
†10(j)
 
AEP Retainer Deferral Plan for Non-Employee Directors, effective January 1, 2005, as amended February 9, 2007.
 
2007 Form 10-K, Ex 10(j)(i)
         
†10(k)
 
 
Amended and Restated AEP Stock Unit Accumulation Plan for Non-Employee Directors effective January 1, 2013.
 
 
Form 10-Q, Ex 10, March 31, 2012
         
†10(l)
 
AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2008.
 
2008 Form 10-K, Ex 10(l)(1)(A)
         
†10(l)(1)
 
Guaranty by AEP of AEPSC Excess Benefits Plan.
 
1990 Form 10-K, Ex 10(h)(1)(B)
         
†10(l)(2)
 
AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2011 (Non-Qualified).
 
2010 Form 10-K, Ex 10(l)(2)
         
†10(l)(3)
 
AEPSC Umbrella Trust for Executives.
 
1993 Form 10-K, Ex 10(g)(3)
         
†10(l)(3)(A)
 
First Amendment to AEPSC Umbrella Trust for Executives.
 
2008 Form 10-K, Ex   10(l)(3)(A)
 
 
E-2

 
Exhibit
Designation
   
Nature of Exhibit
   
Previously Filed as Exhibit to:
         
†10(m)
 
Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers.
 
2002 Form 10-K, Ex 10(m)(4)
         
†10(m)(1)(A)
 
Amendment to Employment Agreement dated December 9, 2008 between AEPSC and Robert P. Powers.
 
2008 Form 10-K, Ex 10(m)(4)(A)
         
†10(n)
 
 
 
AEP System Senior Officer Annual Incentive Compensation Plan amended and restated as of February 26, 2013.
 
Form 10-Q, Ex 10, June 30, 2012
 
 
         
†10(o)
 
AEP System Survivor Benefit Plan, effective January 27, 1998.
 
Form 10-Q, Ex 10, September 30, 1998
         
†10(o)(1)(A)
 
First Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 31, 2000.
 
2002 Form 10-K, Ex 10(o)(2)
         
†10(o)(2)(A)
 
Second Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 1, 2008.
 
2008 Form 10-K, Ex 10(o)(1)(B)
         
†10(p)
 
AEP System Incentive Compensation Deferral Plan Amended and Restated as of January 1, 2008.
 
2008 Form 10-K, Ex 10(p)
         
†10(p)(1)(A)
 
First Amendment to AEP Incentive Compensation Deferral Plan Amended and Restated as of January 1, 2008.
 
2011 Form 10-K, Ex 10(p)(1)(A)
         
†10(q)
 
AEP System Nuclear Performance Long Term Incentive Compensation Plan dated August 1, 1998.
 
2002 Form 10-K, Ex 10(r)
         
†10(r)
 
Nuclear Key Contributor Retention Plan Amended and Restated as of January 1, 2008.
 
2008 Form 10-K, Ex 10(r)
         
†10(r)(1)(A)
 
First Amendment to Nuclear Key Contributor Retention Plan Amended and Restated as of January 1, 2008.
 
2011 Form 10-K, Ex 10(r)(1)(A)
         
*†10(s)
 
AEP Change In Control Agreement, effective January 14, 2014.
   
         
†10(t)
 
Amended and Restated AEP System Long-Term Incentive Plan as of September 25, 2012.
 
Form 10-Q, Ex 10, September 30, 2010
         
†10(t)(1)(A)
 
Performance Share Award Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.
 
2011 Form 10-K, Ex 10(t)(1)(A)
         
†10(t)(2)(A)
 
Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan Amended and Restated effective January 1, 2013.
 
2012 Form 10-K, Ex 10 (t)(2)(A)
         
†10(u)
 
AEP System Stock Ownership Requirement Plan Amended and Restated effective January 1, 2010.
 
2010 Form 10-K, Ex 10(u)
 
 
E-3

 
Exhibit
Designation
   
Nature of Exhibit
   
Previously Filed as Exhibit to:
         
†10(u)(1)(A)
 
First Amendment to AEP System Stock Ownership Requirement Plan as Amended and Restated effective January 1, 2010.
 
2011 Form 10-K, Ex 10(u)(1)(A)
         
†10(v)
 
Central and South West System Special Executive Retirement Plan Amended and Restated effective January 1, 2009.
 
2008 Form 10-K, Ex 10(v)
         
†10(w)
 
AEP Executive Severance Plan effective January 1, 2014.
 
Form 8-K, Ex 10.1 dated January 15, 2014
         
*†10(x)
 
Letter Agreement dated November 20, 2012 between AEPSC and Lana Hillebrand
   
         
*12
 
Statement re: Computation of Ratios.
   
         
*13
 
Copy of those portions of the AEP 2013 Annual Report (for the fiscal year ended December 31, 2013) which are incorporated by reference in this filing.
   
         
*21
 
List of subsidiaries of AEP.
   
         
*23
 
Consent of Deloitte & Touche LLP.
   
         
*24
 
Power of Attorney.
   
         
*31(a)
 
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
         
*31(b)
 
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
         
*32(a)
 
Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
   
         
*32(b)
 
Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
   
         
101.INS
 
XBRL Instance Document.
   
         
101.SCH
 
XBRL Taxonomy Extension Schema.
   
         
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase.
   
         
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase.
   
         
101.LAB
 
XBRL Taxonomy Extension Label Linkbase.
   
         
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase.
 
   
 
 
E-4

 
Exhibit
Designation
   
Nature of Exhibit
   
Previously Filed as Exhibit to:
         
APCo‡   File No. 1-3457
   
         
2(a)
 
Agreement and Plan of Merger dated as of December 31, 2013 by and between Newco Appalachian Inc. and Appalachian Power Company.
 
Form 8-K, Ex 2.1 dated December 31, 2013
         
3(a)
 
Composite of the Restated Articles of Incorporation of APCo, amended as of March 7, 1997.
 
1996 Form 10-K, Ex 3(d)
         
3(b)
 
Composite By-Laws of APCo, amended as of February 26, 2008.
 
 
2007 Form 10-K, Ex 3(b)
         
4(a)
 
Indenture (for unsecured debt securities), dated as of January 1, 1998, between APCo and The Bank of New York, As Trustee.
 
 
Registration Statement No. 333-45927, Ex 4(a)(b)
Registration Statement No. 333-49071, Ex 4(b)
Registration Statement No. 333-84061, Ex 4(b)(c)
Registration Statement No. 333-100451, Ex 4(b)(c)(d)
Registration Statement No. 333-116284, Ex 4(b)(c)
Registration Statement No. 333-123348, Ex 4(b)(c)
Registration Statement No. 333-136432, Ex 4(b)(c)(d)
Registration Statement No. 333-161940, Ex 4(b)(c)(d)
Registration Statement No. 333-182336, Ex 4(b)(c)
         
4(b)
 
 
 
 
Company Order and Officer’s Certificate to The Bank of New York Mellon Trust Company, N.A., dated August 16, 2012 establishing terms of Floating Rate Notes due 2013.
 
Form 8-K, Ex 4(a) dated August 16, 2012
         
4(c)
 
$1 Billion Term Credit Agreement, dated as of July 17, 2013, among AEP, APCo, OPCo, AEP Generation Resources Inc., the banks, financial institutions and other institutional lenders listed on the signature pages thereof, and Wells Fargo Bank, National Association, as Administrative Agent.
 
Form 10Q, Ex 4, June 30, 2013
         
*10(a)
 
Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended September 10, 2010.
   
         
[10(b)
 
Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, OPCo and I&M and with AEPSC, as amended.
 
Registration Statement No. 2-52910, Ex 5(a)
Registration Statement No. 2-61009, Ex 5(b)
1990 Form 10-K, Ex 10(a)(3), File No. 1-3525]
         
*10(c)
 
Transmission Agreement, effective November 2010, among APCo, CSPCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent.
   
         
10(d)
 
Amended and Restated Operating Agreement of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, KGPCo and WPCo.
 
2004 Form 10-K, Ex 10(d)(1)
 
 
E-5

 
Exhibit
Designation
   
Nature of Exhibit
   
Previously Filed as Exhibit to:
         
10(d)(1)
 
PJM West Reliability Assurance Agreement among Load Serving Entities in the PJM West service area.
 
2004 Form 10-K, Ex 10(d)(2)
         
10(d)(2)
 
Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, KGPCo and WPCo.
 
2004 Form 10-K, Ex 10(d)(3)
         
[10(e)
 
Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.
 
1996 Form 10-K, Ex 10(l), File No. 1-3525]
         
10(f)
 
Consent Decree with U.S. District Court, as modified
 
Form 8-K, Ex 10.1 dated October 9, 2007
Form 10-Q, Ex 10, June 30, 2013
         
*12
 
Statement re: Computation of Ratios.
   
         
*13
 
Copy of those portions of the APCo 2013 Annual Report (for the fiscal year ended December 31, 2013) which are incorporated by reference in this filing.
   
         
*23
 
Consent of Deloitte & Touche LLP.
   
         
*24
 
Power of Attorney.
   
         
*31(a)
 
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
         
*31(b)
 
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
         
*32(a)
 
Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
   
         
*32(b)
 
Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
   
         
101.INS
 
XBRL Instance Document.
   
         
101.SCH
 
XBRL Taxonomy Extension Schema.
   
         
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase.
   
         
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase.
   
         
101.LAB
 
XBRL Taxonomy Extension Label Linkbase.
   
         
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase.
   
     
I&M‡   File No. 1-3570
   
 
 
E-6

 
Exhibit
Designation
   
Nature of Exhibit
   
Previously Filed as Exhibit to:
         
3(a)
 
Composite of the Amended Articles of Acceptance of I&M, dated of March 7, 1997.
 
1996 Form 10-K, Ex 3(c)
         
3(b)
 
Composite By-Laws of I&M, amended as of February 26, 2008.
 
2007 Form 10-K, Ex 3(b)
         
4(a)
 
Indenture (for unsecured debt securities), dated as of October 1, 1998, between I&M and The Bank of New York, as Trustee.
 
Registration Statement No. 333-88523, Ex 4(a)(b)(c)
Registration Statement No. 333-58656, Ex 4(b)(c)
Registration Statement No. 333-108975, Ex 4(b)(c)(d)
Registration Statement No. 333-136538, Ex 4(b)(c)
Registration Statement No. 333-156182, Ex 4(b)
Registration Statement No. 333-185087, Ex 4(b)
         
4(b)
 
Company Order and Officers Certificate to The Bank of New York Mellon dated March 18, 2013 of 3.20% Series J due 2023.
 
Form 8-K, Ex 4(a) dated March 18, 2013
         
*10(a)
 
Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended September 10, 2010.
   
         
10(b)
 
Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, I&M, and OPCo and with AEPSC, as amended.
 
Registration Statement No. 2-52910, Ex 5(a)
Registration Statement No. 2-61009, Ex 5(b)
1990 Form 10-K, Ex 10(a)(3), File No. 1-3525
         
10(b)(1)
 
Unit Power Agreement dated as of March 31, 1982 between AEGCo and I&M, as amended.
 
Registration Statement No. 33-32752,
Ex 28(b)(1)(A)(B)
         
*10(c)
 
Transmission Agreement, effective November 2010, among APCo, CSPCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent.
   
         
10(d)
 
Amended and Restated Operating Agreement of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, KGPCo and WPCo.
 
2004 Form 10-K, Ex 10(d)(1)
         
10(d)(1)
 
PJM West Reliability Assurance Agreement among Load Serving Entities in the PJM West service area.
 
2004 Form 10-K, Ex 10(d)(2)
         
10(d)(2)
 
Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, KGPCo and WPCo.
 
2004 Form 10-K, Ex 10(d)(3)
         
[10(e)
 
Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.
 
1996 Form 10-K, Ex 10(l), File No. 1-3525]
         
10(f)
 
Consent Decree with U.S. District Court, as modified.
 
Form 8-K, Ex 10.1 dated October 9, 2007
Form 10-Q, Ex 10, June 30, 2013
         
10(g)
 
Lease Agreements, dated as of December 1, 1989, between I&M and Wilmington Trust Company, as amended.
 
Registration Statement No. 33-32753, Ex 28(a)(1-6)(C)
1993 Form 10-K, Ex 10(e)(1-6)(B)
         
*12
 
Statement re: Computation of Ratios.
   
 
 
E-7

 
Exhibit
Designation
   
Nature of Exhibit
   
Previously Filed as Exhibit to:
         
*13
 
Copy of those portions of the I&M 2013 Annual Report (for the fiscal year ended December 31, 2013) which are incorporated by reference in this filing.
   
         
*23
 
Consent of Deloitte & Touche LLP.
   
         
*24
 
Power of Attorney.
   
         
*31(a)
 
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
         
*31(b)
 
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
         
*32(a)
 
Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
   
         
*32(b)
 
Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
   
         
101.INS
 
XBRL Instance Document.
   
         
101.SCH
 
XBRL Taxonomy Extension Schema.
   
         
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase.
   
         
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase.
   
         
101.LAB
 
XBRL Taxonomy Extension Label Linkbase.
   
         
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase.
   
     
OPCo‡   File No.1-6543
   
         
2(a)
 
Asset Contribution Agreement effective as of December 31, 2013 by and between Ohio Power Company and AEP Generation Resources Inc.
 
Form 8-K, Ex 2.1 dated December 31, 2013
         
2(b)
 
Agreement and Plan of Merger of Ohio Power Company and Columbus Southern Power Company entered into as of December 31, 2012.
 
Form 8-K, Ex 2.1 dated January 6, 2012
         
3(a)
 
Composite of the Amended Articles of Incorporation of OPCo, dated June 3, 2002.
 
Form 10-Q, Ex 3(e), June 30, 2002
         
3(b)
 
Amended Code of Regulations of OPCo.
 
Form 10-Q, Ex 3(b), June 30, 2008
 
 
E-8

 
Exhibit
Designation
   
Nature of Exhibit
   
Previously Filed as Exhibit to:
         
4(a)
 
Indenture (for unsecured debt securities), dated as of September 1, 1997, between OPCo and Bankers Trust Company (now Deutsche Bank Trust Company Americas), as Trustee.
 
Registration Statement No. 333-49595, Ex 4(a)(b)(c)
Registration Statement No. 333-106242, Ex 4(b)(c)(d)
Registration Statement No. 333-75783, Ex 4(b)(c)
Registration Statement No. 333-127913, Ex 4(b)(c)
Registration Statement No. 333-139802, Ex 4(a)(b)(c)
Registration Statement No. 333-139802, Ex 4(b)(c)(d)
       
Registration Statement No. 333-161537, Ex 4(b)(c)(d)
         
4(b)
 
Company Order and Officer’s Certificate to Deutsche Bank Trust Company Americas, dated September 24, 2009, establishing terms of 5.375% Senior Notes, Series M due 2021.
 
Form 8-K, Ex 4(a) dated September 24, 2009
         
4(c)
 
Indenture (for unsecured debt securities), dated as of February 1, 2003, between OPCo and Bank One, N.A., as Trustee.
 
Registration Statement No. 333-127913, Ex 4(d)(e)(f)
         
4(d)
 
Indenture (for unsecured debt securities), dated as of September 1, 1997, between CSPCo (predecessor in interest to OPCo) and Bankers Trust Company, as Trustee.
 
Registration Statement No. 333-54025, Ex 4(a)(b)(c)(d)
Registration Statement No. 333-128174, Ex 4(b)(c)(d)
Registration Statement No. 333-150603. Ex 4(b)
         
4(e)
 
Indenture (for unsecured debt securities), dated as of February 1, 2003, between CSPCo (predecessor in interest to OPCo) and Bank One, N.A., as Trustee.
 
Registration Statement No. 333-128174, Ex 4(e)(f)(g)
Registration Statement No. 333-150603 Ex 4(b)
         
4(f)
 
First Supplemental Indenture, dated as of December 31, 2012, by and between OPCo and Deutsche Bank Trust Company Americas, as trustee, supplementing the Indenture dated as of September 1, 1997 between CSPCo (predecessor in interest to OPCo) and the trustee.
 
Form 8-K, Ex 4.1 dated January 6, 2012
         
4(g)
 
Third Supplemental Indenture, dated as of December 31, 2012, by and between OPCo and The Bank of New York Mellon Trust Company, N.A., as trustee, supplementing the Indenture dated as of February 14, 2003 between CSPCo (predecessor in interest to OPCo) and the trustee.
 
Form 8-K, Ex 4.2 dated January 6, 2012
         
4(h)
 
CSPCo (predecessor in interest to OPCo) Company Order and Officer’s Certificate to Deutsche Bank Trust Company Americas, dated May 16, 2008, establishing terms of 6.05% Senior Notes, Series G, due 2018.
 
Form 8-K, Ex 4(a), dated May 16, 2008
         
4(i)
 
$1 Billion Term Credit Agreement, dated as of July 17, 2013, among AEP, APCo, OPCo, AEP Generation Resources Inc., the banks, financial institutions and other institutional lenders listed on the signature pages thereof, and Wells Fargo Bank, National Association, as Administrative Agent.
 
Form 10Q, Ex 4, June 30, 2013
         
*10(a)
 
 
Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended September 10, 2010.
   
 
 
E-9

 
Exhibit
Designation
   
Nature of Exhibit
   
Previously Filed as Exhibit to:
         
[10(b)
 
Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, I&M and OPCo and with AEPSC, as amended.
 
Registration Statement No. 2-52910, Ex 5(a)
Registration Statement No. 2-61009, Ex 5(b)
1990 Form 10-K, Ex 10(a)(3), File 1-3525]
         
*10(c)
 
Transmission Agreement, effective November 2010, among APCo, CSPCo, I&M, KGPCo, KPCo, OPCo and WPCo with AEPSC as agent.
   
         
10(d)
 
Unit Power Agreement, dated March 15, 2007 between AEGCo and CSPCo (predecessor in interest to OPCo).
 
2007 Form 10-K, Ex 10(b)(2)
         
10(e)
 
Amended and Restated Operating Agreement of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, KGPCo and WPCo.
 
2004 Form 10-K, Ex 10(d)(1)
         
10(f)
 
PJM West Reliability Assurance Agreement among Load Serving Entities in the PJM West service area.
 
2004 Form 10-K, Ex 10(d)(2)
         
10(g)
 
Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, KGPCo and WPCo.
 
2004 Form 10-K, Ex 10(d)(3)
         
10(h)
 
Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.
 
1996 Form 10-K, Ex 10(l), File No. 1-3525
         
10(i)
 
Consent Decree with U.S. District Court, as modified.
 
Form 8-K, Item Ex 10.1 dated October 9, 2007
Form 10-Q, Ex 10, June 30, 2013
         
10(i)(1)
 
Amendment No. 9, dated July 1, 2003, to Station Agreement dated January 1, 1968, among OPCo, Buckeye and Cardinal Operating Company, and amendments thereto.
 
Form 10-Q, Ex 10(a), September 30, 2004
         
10(j)
 
Amendment No. 1, dated October 1, 1973, to Station Agreement dated January 1, 1968, among OPCo, Buckeye and Cardinal Operating Company, and amendments thereto.
 
1993 Form 10-K, Ex 10(f)
2003 Form 10-K, Ex 10(e)
         
*12
 
Statement re: Computation of Ratios.
   
         
*13
 
Copy of those portions of the OPCo 2013 Annual Report (for the fiscal year ended December 31, 2013) which are incorporated by reference in this filing.
   
         
*24
 
Power of Attorney.
   
         
*31(a)
 
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
 
 
E-10

 
Exhibit
Designation
   
Nature of Exhibit
   
Previously Filed as Exhibit to:
         
*31(b)
 
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
         
*32(a)
 
Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
   
         
*32(b)
 
Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
   
         
*95
 
Mine Safety Disclosure.
   
         
101.INS
 
XBRL Instance Document.
   
         
101.SCH
 
XBRL Taxonomy Extension Schema.
   
         
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase.
   
         
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase.
   
         
101.LAB
 
XBRL Taxonomy Extension Label Linkbase.
   
         
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase.
   
     
PSO‡   File No. 0-343
   
         
3(a)
 
Certificate of Amendment to Restated Certificate of Incorporation of PSO.
 
Form 10-Q, Ex 3(a), June 30, 2008
         
3(b)
 
Composite By-Laws of PSO amended as of February 26, 2008.
 
2007 Form 10-K, Ex 3 (b)
         
4(a)
 
Indenture (for unsecured debt securities), dated as of November 1, 2000, between PSO and The Bank of New York, as Trustee.
 
 
Registration Statement No. 333-100623, Ex 4(a)(b)
Registration Statement No. 333-114665, Ex 4(b)(c)
Registration Statement No. 333-133548, Ex 4(b)(c)
Registration Statement No. 333-156319, Ex 4(b)(c)
 
         
4(b)
 
Eighth Supplemental Indenture, dated as of November 13, 2009 between PSO and The Bank of New York Mellon, as Trustee, establishing terms of the 5.15% Senior Notes, Series H, due 2019.
 
Form 8-K, Ex 4(a), dated November 13, 2009
         
4(c)
 
Ninth Supplemental Indenture, dated as of January 19, 2011 between PSO and The Bank of New York Mellon Trust Company, N.A., as Trustee, establishing terms of 4.40% Senior Notes, Series I, due 2021.
 
Form 8-K, Ex 4(a) dated January 20, 2011
         
*10(a)
 
Restated and Amended Operating Agreement, among PSO, SWEPCo and AEPSC, effective as of March 1, 2014.
   
 
 
E-11

 
Exhibit
Designation
   
Nature of Exhibit
   
Previously Filed as Exhibit to:
         
10(b)
 
Third Restated and Amended Transmission Coordination Agreement Between PSO, SWEPCo and AEPSC dated February 18, 2011.
 
2012 Form 10-K, Ex 10(b)
         
*12
 
Statement re: Computation of Ratios.
   
         
*13
 
Copy of those portions of the PSO 2013 Annual Report (for the fiscal year ended December 31, 2013) which are incorporated by reference in this filing.
   
         
*24
 
Power of Attorney.
   
         
*31(a)
 
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
         
*31(b)
 
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
         
*32(a)
 
Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
   
         
*32(b)
 
Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
   
         
101.INS
 
XBRL Instance Document.
   
         
101.SCH
 
XBRL Taxonomy Extension Schema.
   
         
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase.
   
         
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase.
   
         
101.LAB
 
XBRL Taxonomy Extension Label Linkbase.
   
         
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase.
   
     
SWEPCo‡   File No. 1-3146
   
         
3(a)
 
Composite of Amended Restated Certificate of Incorporation of SWEPCo.
 
2008 Form 10-K, Ex 3(a)
         
3(b)
 
Composite By-Laws of SWEPCo amended as of February 26, 2008.
 
2007 Form 10-K, Ex 3(b)
         
4(a)   Indenture (for unsecured debt securities), dated as of February 4, 2000, between SWEPCo and The Bank of New York, as Trustee.   Registration Statement No. 333-96213
Registration Statement No. 333-87834, Ex 4(a)(b)
Registration Statement No. 333-100632, Ex 4(b)
Registration Statement No. 333-108045, Ex 4(b)
Registration Statement No. 333-145669, Ex 4(c)(d)
Registration Statement No. 333-161539, Ex 4(b)(c)
 
 
E-12

 
Exhibit
Designation
   
Nature of Exhibit
   
Previously Filed as Exhibit to:
         
4(b)
 
Eighth Supplemental Indenture dated as of March 1, 2010 between SWEPCo and The Bank of New York Mellon establishing terms of 6.20% Senior Notes, Series H, due 2040.
 
Form 8-K, Ex 4(a), dated March 8, 2010
         
4(c)
 
Ninth Supplemental Indenture dated as of February 1, 2012 between SWEPCo and The Bank of New York Mellon Trust Company, N.A. establishing terms of 3.55% Senior Notes, Series I, due 2022.
 
Form 8-K, Ex 4(a), dated February 3, 2012
         
*10(a)
 
Restated and Amended Operating Agreement, among PSO, SWEPCo and AEPSC, effective as of March 1, 2014.
   
         
10(b)
 
Third Restated and Amended Transmission Coordination Agreement Between PSO, SWEPCo and AEPSC dated February 18, 2011.
 
2012 Form 10-K, Ex 10(b)
         
*12
 
Statement re: Computation of Ratios.
   
         
*13
 
Copy of those portions of the SWEPCo 2013 Annual Report (for the fiscal year ended December 31, 2013) which are incorporated by reference in this filing.
   
         
*24
 
Power of Attorney.
   
         
*31(a)
 
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
         
*31(b)
 
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
         
*32(a)
 
Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
   
         
*32(b)
 
Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
   
         
*95
 
Mine Safety Disclosure.
   
         
101.INS
 
XBRL Instance Document.
   
         
101.SCH
 
XBRL Taxonomy Extension Schema.
   
         
101.CAL   XBRL Taxonomy Extension Calculation Linkbase.    
         
101.DEF   XBRL Taxonomy Extension Definition Linkbase.    
         
101.LAB   XBRL Taxonomy Extension Label Linkbase.    
 
 
E-13

 
 
Exhibit
Designation
   
Nature of Exhibit
   
Previously Filed as Exhibit to:
         
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase.
   

 
‡ Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants.  The registrants hereby agree to furnish a copy of any such omitted instrument to the SEC upon request.

 
E-14

 

Exhibit 10(a)
 
 


 
 
 
 
 
 
 
 
 
 
AMENDED AND RESTATED
 
INTER-COMPANY POWER AGREEMENT
 
DATED AS OF SEPTEMBER 10, 2010
 
AMONG
   
  OHIO VALLEY ELECTRIC CORPORATION,
  ALLEGHENY ENERGY SUPPLY COMPANY, L.L.C.
 
APPALACHIAN POWER COMPANY,
 
BUCKEYE POWER GENERATING, LLC,
 
COLUMBUS SOUTHERN POWER COMPANY,
  THE DAYTON POWER AND LIGHT COMPANY,
  DUKE ENERGY OHIO, INC.,
  FIRSTENERGY GENERATION CORP.,
  INDIANA MICHIGAN POWER COMPANY,
  KENTUCKY UTILITIES COMPANY,
  LOUISVILLE GAS AND ELECTRIC COMPANY,
  MONONGAHELA POWER COMPANY,
  OHIO POWER COMPANY,
  PENINSULA GENERATION COOPERATIVE, and
  SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
 
 
 
 
 
 
 

 
 
 
 

 

 
AMENDED AND RESTATED
 
INTER-COMPANY POWER AGREEMENT
 
 _____________________________
 
THIS AGREEMENT, dated as of September 10, 2010 (the “Agreement”), by and among Ohio Valley Electric Corporation (herein called OVEC), A llegheny E nergy S upply C ompany , L.L.C. (herein called Allegheny), Appalachian Power Company (herein called Appalachian), Buckeye Power Generating, LLC (herein called Buckeye), Columbus Southern Power Company (herein called Columbus), The Dayton Power and Light Company (herein called Dayton), Duke Energy Ohio, Inc. (formerly known as The Cincinnati Gas & Electric Company and herein called Duke Ohio), FirstEnergy Generation Corp. (herein called FirstEnergy), Indiana Michigan Power Company (herein called Indiana), Kentucky Utilities Company (herein called Kentucky), Louisville Gas and Electric Company (herein called Louisville), Monongahela Power Company (herein called Monongahela), Ohio Power Company (herein called Ohio Power), Peninsula Generation Cooperative (herein called Peninsula), and Southern Indiana Gas and Electric Company (herein called Southern Indiana, and all of the foregoing, other than OVEC, being herein sometimes collectively referred to as the Sponsoring Companies and individually as a Sponsoring Company) hereby amends and restates in its entirety, the Inter-Company Power Agreement dated as of March 13, 2006, as amended by Modification No. 1, dated as of March 13, 2006 (herein called the Current Agreement), by and among OVEC and the Sponsoring Companies.
 
Witnesseth That :
 
Whereas , the Current Agreement amended and restated the original Inter-Company Power Agreement, dated as of July 10, 1953, as amended by Modification No. 1, dated as of June 3, 1966; Modification No. 2, dated as of January 7, 1967; Modification No. 3, dated as of November 15, 1967; Modification No. 4, dated as of November 5, 1975; Modification No. 5, dated as of September 1, 1979; Modification No. 6, dated as of August 1, 1981; Modification No. 7, dated as of January 15, 1992; Modification No. 8, dated as of January 19, 1994; Modification No. 9, dated as of August 17, 1995; Modification No. 10, dated as of January 1, 1998; Modification No. 11, dated as of April 1, 1999; Modification No. 12, dated as of November 1, 1999; Modification No. 13, dated as of May 24, 2000; Modification No. 14, dated as of April 1, 2001; and Modification No. 15, dated as of April 30, 2004 (together, herein called the Original Agreement); and
 
W hereas , OVEC designed, purchased, and constructed, and continues to operate and maintain two steam-electric generating stations, one station (herein called Ohio Station) consisting of five turbo-generators and all other necessary equipment, at a location on the Ohio River near Cheshire, Ohio, and the other station (herein called Indiana Station) consisting of six turbogenerators and all other necessary equipment, at a location on the Ohio River near Madison,
 
 
 

 
 
Indiana, (the Ohio Station and the Indiana Station being herein called the Project Generating Stations); and
 
Whereas , OVEC also designed, purchased, and constructed, and continues to operate and maintain necessary transmission and general plant facilities (herein called the Project Transmission Facilities) and OVEC established or cause to be established interconnections between the Project Generating Stations and the systems of certain of the Sponsoring Companies; and
 
Whereas , OVEC entered into an agreement, attached hereto as Exhibit A, with Indiana-Kentucky Electric Corporation (herein called IKEC), a corporation organized under the laws of the State of Indiana as a wholly owned subsidiary corporation of OVEC, which has been amended and restated as of the date of this Agreement and embodies the terms and conditions for the ownership and operation by IKEC of the Indiana Station and such portion of the Project Transmission Facilities which are to be owned and operated by it; and
 
Whereas , transmission facilities were constructed by certain of the Sponsoring Companies to interconnect the systems of such Sponsoring Companies, directly or indirectly, with the Project Generating Stations and/or the Project Transmission Facilities, and the Sponsoring Companies have agreed to pay for Available Power, as hereinafter defined, as may be available at the Project Generating Stations; and
 
Whereas , the parties hereto desire to amend and restate in their entirety, the Current Agreement to define the terms and conditions governing the rights of the Sponsoring Companies to receive Available Power from the Project Generating Stations and the obligations of the Sponsoring Companies to pay therefor.
 
Now, Therefore , the parties hereto agree with each other as follows:
 
 
ARTICLE 1
 
Definitions
 
1.01.   For the purposes of this Agreement, the following terms, wherever used herein, shall have the following meanings:
 
1.011   “Affiliate” means, with respect to a specified person, any other person that directly or indirectly through one or more intermediaries controls, is controlled by, or is under common control with, such specified person; provided that “control” for these purposes means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a person, whether through the ownership of voting securities, by contract or otherwise .
 
 
2

 
1.012   “Arbitration Board” has the meaning set forth in Section 9.10.
 
1.013   “Available Energy” of the Project Generating Stations means the energy associated with Available Power.
 
1.014   “Available Power” of the Project Generating Stations at any particular time means the total net kilowatts at the 345-kV busses of the Project Generating Stations which Corporation in its sole discretion will determine that the Project Generating Stations will be capable of safely delivering under conditions then prevailing, including all conditions affecting capability.
 
1.015   “Corporation” means OVEC, IKEC, and all other subsidiary corporations of OVEC.
 
1.016   “Decommissioning and Demolition Obligation” has the meaning set forth in Section 5.03(f) hereof.
 
1.017   “Effective Date” means September 10, 2010, or to the extent necessary, such later date on which Corporation notifies the Sponsoring Companies that all conditions to effectiveness, including all required waiting periods and all required regulatory acceptances or approvals, of this Agreement have been satisfied in form and substance satisfactory to the Corporation.
 
1.018   “Election Period” has the meaning set forth in Section 9.183(a) hereof.
 
1.019   “Minimum Generating Unit Output” means 80 MW (net) for each of the Corporation’s generation units; provided that such “Minimum Generating Unit Output” shall be confirmed from time to time by operating tests on the Corporation’s generation units and shall be adjusted by the Operating Committee as appropriate following such tests.
 
1.0110    “Minimum Loading Event” means a period of time during which one or more of the Corporation’s generation units are operating at below the Minimum Generating Output as a result of the Sponsoring Companies’ failure to schedule and take delivery of sufficient Available Energy.
 
1.0111   “Minimum Loading Event Costs” means the sum of the following costs caused by one or more Minimum Loading Events: (i) the actual costs of any of the Corporation’s generating units burning fuel oil; and (ii) the estimated actual additional costs to the Corporation resulting from Minimum Loading Events, including without limitation the incremental costs of additional emissions allowances, reflected in the schedule of charges prepared by the Operating Committee and in effect as of the commencement of any Minimum Loading Event, which schedule may be adjusted from time to time as necessary by the Operating Committee.
 
 
3

 
1.0112   “Month” means a calendar month.
 
1.0113    “Nominal Power Available” means an individual Sponsoring Company’s Power Participation Ratio share of the Corporation’s current estimate of the maximum amount of Available Power available for delivery at any given time.
 
1.0114   “Offer Notice” means the notice required to be given to the other Sponsoring Companies by a Transferring Sponsor offering to sell all or a portion of such Transferring Sponsor’s rights, title and interests in, and obligations under this Agreement.  At a minimum, the Offer Notice shall be in writing and shall contain (i) the rights, title and interests in, and obligations under this Agreement that the Transferring Sponsor proposes to Transfer; and (ii) the cash purchase price and any other material terms and conditions of such proposed transfer.  An Offer Notice may not contain terms or conditions requiring the purchase of any non-OVEC interests.
 
1.0115   “Permitted Assignee” means a person that is (a) a Sponsoring Company or its Affiliate whose long-term unsecured non-credit enhanced indebtedness, as of the date of such assignment, has a Standard & Poor’s credit rating of at least BBB- and a Moody’s Investors Service, Inc. credit rating of at least Baa3 (provided that, if the proposed assignee’s long-term unsecured non-credit enhanced indebtedness is not currently rated by one of Standard & Poor’s or Moody, such assignee’s long-term unsecured non-credit enhanced indebtedness, as of the date of such assignment, must have either a Standard & Poor’s credit rating of at least BBB- or a Moody’s Investors Service, Inc. credit rating of at least Baa3); or (b) a Sponsoring Company or its Affiliate that does not meet the criteria in subsection (a) above, if the Sponsoring Company or its Affiliate that is assigning its rights, title and interests in, and obligations under, this Agreement agrees in writing (in form and substance satisfactory to Corporation) to remain obligated to satisfy all of the obligations related to the assigned rights, title and interests to the extent such obligations are not satisfied by the assignee of such rights, title and interests; provided that , in no event shall a person be deemed a “Permitted Assignee” if counsel for the Corporation reasonably determines that the assignment of the rights, title or interests in, or obligations under, this Agreement to such person could cause a termination, default, loss or payment obligation under any security issued, or agreement entered into, by the Corporation prior to such transfer.
 
1.0116   “Postretirement Benefit Obligation” has the meaning set forth in Section 5.03(e) hereof.
 
1.0117   “Power Participation Ratio” as applied to each of the Sponsoring Companies refers to the percentage set forth opposite its respective name in the tabulation below:
 
 
  Power Participation
Company Ratio—Percent
 
 
4

 
 
 
  Allegheny........................................................... 3.01
  Appalachian....................................................... 15.69
  Buckeye............................................................ 18.00
  Columbus.......................................................... 4.44
  Dayton............................................................... 4.90
  Duke Ohio......................................................... 9.00
  FirstEnergy........................................................ 4.85
  Indiana...............................................................                                                               7.85
  Kentucky...........................................................                                                                          2.50
  Louisville............................................................                                                                          5.63
  Monongahela.....................................................                                                                          0.49
  Ohio Power.......................................................  15.49
  Peninsula............................................................                                                                          6.65
  Southern Indiana................................................ 1.50
       Total.............................................................                                                                   100.0
 
1.0118   “Tariff” means the open access transmission tariff of the Corporation, as amended from time to time, or any successor tariff, as accepted by the Federal Energy Regulatory Commission or any successor agency.
 
1.0119   “Third Party” means any person other than a Sponsoring Company or its Affiliate.
 
1.0120   “Total Minimum Generating Output” means the product of the Minimum Generating Unit Output times the number of the Corporation’s generation units available for service at that time.
 
1.0121   “Transferring Sponsor” has the meaning set forth in Section 9.183(a) hereof.
 
1.0122   “Uniform System of Accounts” means the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission as in effect on January 1, 2004.
 
 
ARTICLE 2
 
Transmission Agreement and Facilities
 
2.01.   Transmission Agreement .  The Corporation shall enter into a transmission service agreement under the Tariff, and the Corporation shall reserve and schedule transmission service, ancillary services and other transmission-related services in accordance with the Tariff to provide for the delivery of Available Power and Available Energy to the applicable delivery point under this Agreement.
 
 
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2.02.   Limited Burdening of Corporation’s Transmission Facilities.   Transmission facilities owned by the Corporation, including the Project Transmission Facilities, shall not be burdened by power and energy flows of any Sponsoring Company to an extent which would impair or prevent the transmission of Available Power.
 
 
ARTICLE 3
 
[Reserved]
 
ARTICLE 4
 
Available Power Supply
 
4.01.   Operation of Project Generating Stations.   Corporation shall operate and maintain the Project Generating Stations in a manner consistent with safe, prudent, and efficient operating practice so that the Available Power available from said stations shall be at the highest practicable level attainable consistent with OVEC’s obligations under Reliability First Reliability Standard BAL-002-RFC throughout the term of this Agreement.
 
4.02.   Available Power Entitlement.   The Sponsoring Companies collectively shall be entitled to take from Corporation and Corporation shall be obligated to supply to the Sponsoring Companies any and all Available Power and Available Energy pursuant to the provisions of this Agreement.  Each Sponsoring Company’s Available Power Entitlement hereunder shall be its Power Participation Ratio, as defined in subsection 1.0117, of Available Power.
 
4.03.   Available Energy.   Corporation shall make Available Energy available to each Sponsoring Company in proportion to said Sponsoring Company’s Power Participation Ratio. No Sponsoring Company, however, shall be obligated to avail itself of any Available Energy. Available Energy shall be scheduled and taken by the Sponsoring Companies in accordance with the following procedures:
 
4.031   Each Sponsoring Company shall schedule the delivery of all or any portion (in whole MW increments) of its entitlement to Available Energy in accordance with scheduling procedures established by the Operating Committee from time to time.
 
4.032   In the event that any Sponsoring Company does not schedule the delivery of all of its Power Participation Ratio share of Available Energy, then each such other Sponsoring Company may schedule the delivery of all or any portion (in whole MW increments) of any such unscheduled share of Available Energy (through successive allotments if necessary) in proportion to their Power Participation Ratios.
 
 
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4.033   Notwithstanding any Available Energy schedules made in accordance with this Section 4.03 and the applicable scheduling procedures, (i) the Corporation shall adjust all schedules to the extent that the Corporation’s actual generation output is less than or more than the expected Nominal Power Available to all Sponsoring Companies, or to the extent that the Corporation is unable to obtain sufficient transmission service under the Tariff for the delivery of all scheduled Available Energy; and (ii) immediately following a Minimum Loading Event, any Sponsoring Company causing (in whole or part) such Minimum Loading Event shall have its Available Energy schedules increased after the schedules of the Sponsoring Companies not causing such Minimum Load Event, in accordance with the estimated ramp rates associated with the shutdown and start-up of the Corporation’s generation units as reflected in the schedules prepared by the Operating Committee and in effect as of the commencement of any Minimum Loading Event, which schedules may be adjusted from time to time as necessary by the Operating Committee.
 
4.034     Each Sponsoring Company availing itself of Available Energy shall be entitled to an amount of energy (herein called billing kilowatt-hours of Available Energy) equal to its portion, determined as provided in this Section 4.03, of the total Available Energy after deducting therefrom such Sponsoring Company’s proportionate share, as defined in this Section 4.03, of all losses as determined in accordance with the Tariff incurred in transmitting the total of such Available Energy from the 345-kV busses of the Project Generating Stations to the applicable delivery points, as scheduled pursuant to Section 9.01, of all Sponsoring Companies availing themselves of Available Energy.  The proportionate share of all such losses that shall be so deducted from such Sponsoring Company’s portion of Available Energy shall be equal to all such losses multiplied by the ratio of such portion of Available Energy to the total of such Available Energy.  Each Sponsoring Company shall have the right, pursuant to this Section 4.03, to avail itself of Available Energy for the purpose of meeting the loads of its own system and/or of supplying energy to other systems in accordance with agreements, other than this Agreement, to which such Sponsoring Company is a party.
 
4.035   To the extent that, as a result of the failure by one or more Sponsoring Companies to take its respective Power Participation Ratio share of the applicable Total Minimum Generating Output during any hour, a Minimum Loading Event shall occur, then such one or more Sponsoring Companies shall be assessed charges for any Minimum Loading Event Costs in accordance with Section 5.05.
 
 
ARTICLE 5
 
Charges for Available Power and Minimum Loading Event Costs
 
5.01.   Total Monthly Charge.   The amount to be paid to Corporation each month by the Sponsoring Companies for Available Power and Available Energy supplied under this
 
 
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Agreement shall consist of the sum of an energy charge, a demand charge, and a transmission charge, all determined as set forth in this Article 5.
 
 
5.02.   Energy Charge.   The energy charge to be paid each month by the Sponsoring Companies for Available Energy shall be determined by Corporation as follows:
 
5.021   Determine the aggregate of all expenses for fuel incurred in the operation of the Project Generating Stations, in accordance with Account 501 (Fuel), Account 506.5 (Variable Reagent Costs Associated With Pollution Control Facilities) and 509 (Allowances) of the Uniform System of Accounts.
 
5.022   Determine for such month the difference between the total cost of fuel as described in subsection 5.021 above and the total cost of fuel included in any Minimum Loading Event Costs payable to the Corporation for such month pursuant to Section 8.03.  For the purposes hereof the difference so determined shall be the fuel cost allocable for such month to the total kilowatt-hours of energy generated at the Project Generating Stations for the supply of Available Energy.  For Available Energy availed of by the Sponsoring Companies, each Sponsoring Company shall pay Corporation for each such month an amount obtained by multiplying the ratio of the billing kilowatt-hours of such Available Energy availed of by such Sponsoring Company during such month to the aggregate of the billing kilowatt-hours of all Available Energy availed of by all Sponsoring Companies during such month times the total cost of fuel as described in this subsection 5.022 for such month.
 
5.03.   Demand Charge .  During the period commencing with the Effective Date and for the remainder of the term of this Agreement, demand charges payable by the Sponsoring Companies to Corporation shall be determined by the Corporation as provided below in this Section 5.03.  Each Sponsoring Company's share of the aggregate demand charges shall be the percentage of such charges represented by its Power Participation Ratio.
 
The aggregate demand charge payable each month by the Sponsoring Companies to Corporation shall be equal to the total costs incurred for such month by Corporation resulting from its ownership, operation, and maintenance of the Project Generating Stations and Project Transmission Facilities determined as follows:
 
As soon as practicable after the close of each calendar month the following components of costs of Corporation (eliminating any duplication of costs which might otherwise be reflected among the corporate entities comprising Corporation) applicable for such month to the ownership, operation and maintenance of the Project Generating Stations and the Project Transmission Facilities, including additional facilities and/or spare parts (such as fuel processing plants, flue gas or waste product processing facilities, and facilities reasonably required to enable the Corporation to limit the emission of pollutants or the discharge of wastes in compliance with governmental requirements) and
 
 
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replacements necessary or desirable to keep the Project Generating Stations and the Project Transmission Facilities in a dependable and efficient operating condition, and any provision for any taxes that may be applicable to such charges, to be determined and recorded in the following manner:
 
(a)   Component (A) shall consist of fixed charges made up of (i) the amounts of interest properly chargeable to Accounts 427, 430 and 431, less the amount thereof credited to Account 432, of the Uniform System of Accounts, including the interest component of any purchase price, interest, rental or other payment under an installment sale, loan, lease or similar agreement relating to the purchase, lease or acquisition by Corporation of additional facilities and replacements (whether or not such interest or other amounts have come due or are actually payable during such Month), (ii) the amounts of amortization of debt discount or premium and expenses properly chargeable to Accounts 428 and 429, and (iii) an amount equal to the sum of (I) the applicable amount of the debt amortization component for such month required to retire the total amount of indebtedness of Corporation issued and outstanding, (II) the amortization requirement for such month in respect of indebtedness of Corporation incurred in respect of additional facilities and replacements, and (III) to the extent not provided for pursuant to clause (II) of this clause (iii), an appropriate allowance for depreciation of additional facilities and replacements.
 
(b)   Component (B) shall consist of the total operating expenses for labor, maintenance, materials, supplies, services, insurance, administrative and general expense, etc., properly chargeable to the Operation and Maintenance Expense Accounts of the Uniform System of Accounts (exclusive of Accounts 501, 509, 555, 911, 912, 913, 916, and 917 of the Uniform System of Accounts), minus the total of all non-fuel costs included in any Minimum Loading Event Costs payable to the Corporation for such month pursuant to Section 8.03, minus the total of all transmission charges payable to the Corporation for such month pursuant to Section 5.04, and plus any additional amounts which, after provision for all income taxes on such amounts (which shall be included in Component (C) below), shall equal any amounts paid or payable by Corporation as fines or penalties with respect to occasions where it is asserted that Corporation failed to comply with a law or regulation relating to the emission of pollutants or the discharge of wastes.
 
(c)   Component (C) shall consist of the total expenses for taxes, including all taxes on income but excluding any federal income taxes arising from payments to Corporation under Component (D) below, and all operating or other costs or expenses, net of income, not included or  
 
 
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  specifically excluded in Components (A) or (B) above, including tax adjustments, regulatory adjustments, net losses for the disposition of property and other net costs or expenses associated with the operation of a utility.
 
(d)   Component (D) shall consist of an amount equal to the product of $2.089 multiplied by the total number of shares of capital stock of the par value of $100 per share of Ohio Valley Electric Corporation which shall have been issued and which are outstanding on the last day of such month.
 
(e)   Component (E) shall consist of an amount to be sufficient to pay the costs and other expenses relating to the establishment, maintenance and administration of life insurance, medical insurance and other postretirement benefits other than pensions attributable to the employment and employee service of active employees, retirees, or other employees, including without limitation any premiums due or expected to become due, as well as administrative fees and costs, such amounts being sufficient to provide payment with respect to all periods for which Corporation has committed or is otherwise obligated to make such payments, including amounts attributable to current employee service and any unamortized prior service cost, gain or loss attributable to prior service years (“Postretirement Benefit Obligation”); provided that , the amount payable for Postretirement Benefit Obligations during any month shall be determined by the Corporation based on, among other factors, the Statement of Financial Accounting Standards No. 106 (Employers’ Accounting For Postretirement Benefits Other Than Pensions) and any applicable accounting standards, policies or practices as adopted from time to time relating to accruals with respect to all or any portion of such Postretirement Benefit Obligation.
 
(f)   Component (F) shall consist of an amount that may be incurred in connection with the decommissioning, shutdown, demolition and closing of the Project Generating Stations when production of electric power and energy is discontinued at such Project Generating Stations, which amount shall include, without limitation the following costs (net of any salvage credits): the costs of demolishing the plants’ building structures, disposal of non-salvageable materials, removal and disposal of insulating materials, removal and disposal of storage tanks and associated piping, disposal or removal of materials and supplies (including fuel oil and coal), grading, covering and reclaiming storage and disposal areas, disposing of ash in ash ponds to the extent required by regulatory authorities, undertaking corrective or remedial action required by regulatory authorities, and any other costs incurred in putting the facilities
 
 
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  in a condition necessary to protect health or the environment or which are required by regulatory authorities, or which are incurred to fund continuing obligations to monitor or to correct environmental problems which result, or are later discovered to result, from the facilities’ operation, closure or post-closure activities (“Decommissioning and Demolition Obligation”) provided that , the amount payable for Decommissioning and Demolition Obligations during any month shall be calculated by Corporation based on, among other factors, the then-estimated useful life of the Project Generating Stations and any applicable accounting standards, policies or practices as adopted from time to time relating to accruals with respect to all or any portion of such Decommissioning and Demolition Obligation, and provided further that , the Corporation shall recalculate the amount payable under this Component (F) for future months from time to time, but in no event later than five (5) years after the most recent calculation.
 
 
5.04.   Transmission Charge .  The transmission charges to be paid each month by the Sponsoring Companies shall be equal to the total costs incurred for such month by Corporation for the purchase of transmission service, ancillary services and other transmission-related services under the Tariff as reserved and scheduled by the Corporation to provide for the delivery of Available Power and Available Energy to the applicable delivery point under this Agreement.  Each Sponsoring Company's share of the aggregate transmission charges shall be the percentage of such charges represented by its Power Participation Ratio.
 
5.05.   Minimum Loading Event Costs.   To the extent that, as a result of the failure by one or more Sponsoring Companies to take its respective Power Participation Ratio share of the applicable Total Minimum Generating Output during any hour, a Minimum Loading Event shall occur, then the sum of all Minimum Loading Event Costs relating to such Minimum Loading Event shall be charged to such Sponsoring Company or group of Sponsoring Companies that failed take its respective Power Participation Ratio share of the applicable Total Minimum Generating Output during such period, with such Minimum Loading Event Costs allocated among such Sponsoring Companies on a pro-rata basis in accordance with such Sponsoring Company’s MWh share of the MWh reduction in the delivery of Available Energy causing any Minimum Loading Event.  The applicable charges for Minimum Loading Event Costs as determined by the corporation in accordance with Section 5.05 shall be paid each month by the applicable Sponsoring Companies.
 
 
ARTICLE 6
 
Metering of Energy Supplied
 
6.01.   Measuring Instruments.   The parties hereto shall own and maintain such metering equipment as may be necessary to provide complete information regarding the delivery of power and energy to or for the account of any of the parties hereto; and the ownership and
 
 
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expense of such metering shall be in accordance with agreements among them.  Each party will at its own expense make such periodic tests and inspections of its meters as may be necessary to maintain them at the highest practical commercial standard of accuracy and will advise all other interested parties hereto promptly of the results of any such test showing an inaccuracy of more than 1%.  Each party will make additional tests of its meters at the request of any other interested party.  Other interested parties shall be given notice of, and may have representatives present at, any test and inspection made by another party.
 
 
ARTICLE 7
 
Costs of Replacements and Additional Facilities;
Payments for Employee Benefits;
Decommissioning, Shutdown, Demolition and Closing Charges
 
7.01.   Replacement Costs. The Sponsoring Companies shall reimburse Corporation for the difference between (a) the total cost of replacements chargeable to property and plant made by Corporation during any month prior thereto (and not previously reimbursed) and (b) the amounts received by Corporation as proceeds of fire or other applicable insurance protection, or amounts recovered from third parties responsible for damages requiring replacement, plus provision for all taxes on income on such difference; provided that, to the extent that the Corporation arranges for the financing of any replacements, the payments due under this Section 7.01 shall equal the amount of all principal, interest, taxes and other costs and expenses related to such financing during any month.  Each Sponsoring Company’s share of such payment shall be the percentage of such costs represented by its Power Participation Ratio.  The term cost of replacements, as used herein, shall include all components of cost, plus removal expense, less salvage.
 
7.02.   Additional Facility Costs.   The Sponsoring Companies shall reimburse Corporation for the total cost of additional facilities and/or spare parts purchased and/or installed by Corporation during any month prior thereto (and not previously reimbursed), plus provision for all taxes on income on such costs; provided that, to the extent that the Corporation arranges for the financing of any additional facilities and/or spare parts, the payments due under this Section 7.02 shall equal the amount of all principal, interest, taxes and other costs and expenses related to such financing during any month.  Each Sponsoring Company’s share of such payment shall be the percentage of such costs represented by its Power Participation Ratio.
 
7.03.   Payments for Employee Benefits .   Not later than the effective date of termination of this Agreement, each Sponsoring Company will pay to Corporation its Power Participation Ratio share of additional amounts, after provision for any taxes that may be applicable thereto, sufficient to cover any shortfall if the amount of the Postretirement Benefit Obligation collected by the Corporation prior to the effective date of termination of the Agreement is insufficient to permit Corporation to fulfill its commitments or obligations with respect to both postemployment benefit obligations under the Statement of Financial Accounting Standards No. 112 and postretirement benefits other than pensions, as determined by Corporation
 
 
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with the aid of an actuary or actuaries selected by the Corporation based on the terms of the Corporation’s then-applicable plans.
 
 
7.04.   Decommissioning, Shutdown, Demolition and Closing .   The Sponsoring Companies recognize that a part of the cost of supplying power to it under this Agreement is the amount that may be incurred in connection with the decommissioning, shutdown, demolition and closing of the Project Generating Stations when production of electric power and energy is discontinued at such Project Generating Stations.  Not later than the effective date of termination of this Agreement, each Sponsoring Company will pay to Corporation its Power Participation Ratio share of additional amounts, after provision for any taxes that may be applicable thereto, sufficient to cover any shortfall if the amount of the Decommissioning and Demolition Obligation collected by the Corporation prior to the effective date of termination of the Agreement is insufficient to permit Corporation to complete the decommissioning, shutdown, demolition and closing of the Project Generating Stations, based on the Corporation’s recalculation of the Decommissioning and Demolition Obligation in accordance with Section 5.03(f) of this Agreement no earlier than twelve (12) months before the effective date of termination of this Agreement.
 
 
ARTICLE 8
 
Billing and Payment
 
8.01.   Available Power, and Replacement and Additional Facility Costs.   As soon as practicable after the end of each month Corporation shall render to each Sponsoring Company a statement of all Available Power and Available Energy supplied to or for the account of such Sponsoring Company during such month, specifying the amount due to the Corporation therefor, including any amounts for reimbursement for the cost of replacements and additional facilities and/or spare parts incurred during such month, pursuant to Articles  5 and 7 above.  Such Sponsoring Company shall make payment therefor promptly upon the receipt of such statement, but in no event later than fifteen (15) days after the date of receipt of such statement.  In case any factor entering into the computation of the amount due for Available Power and Available Energy cannot be determined at the time, it shall be estimated subject to adjustment when the actual determination can be made.
 
8.02.   Provisional Payments for Available Power .  The Sponsoring Companies shall, from time to time, at the request of the Corporation, make provisional semi-monthly payments for Available Power in amounts approximately equal to the estimated amounts payable for Available Power delivered by Corporation to the Sponsoring Companies during each semi-monthly period.  As soon as practicable after the end of each semi-monthly period with respect to which Corporation has requested the Sponsoring Companies to make provisional semi-monthly payments for Available Power, Corporation shall render to each Sponsoring Company a separate statement indicating the amount payable by such Sponsoring Company for such semi-monthly period.  Such Sponsoring Company shall make payment therefor promptly upon receipt of such statement, but in no event later than fifteen (15) days after the date of receipt of such
 
 
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statement and the amounts so paid by such Sponsoring Company shall be credited to the account of such Sponsoring Company with respect to future payments to be made pursuant to Articles 5 and 7 above by such Sponsoring Company to Corporation for Available Power.
 
 
8.03.   Minimum Loading Event Costs.   As soon as practicable after the end of each month, Corporation shall render to each Sponsoring Company a statement indicating any applicable charges for Minimum Loading Event Costs pursuant to Section 5.05 during such month, specifying the amount due to the Corporation therefor pursuant to Article  5 above.  Such Sponsoring Company shall make payment therefor promptly upon the receipt of such statement, but in no event later than fifteen (15) days after the date of receipt of such statement.  In case the computation of the amount due for Minimum Loading Event Costs cannot be determined at the time, it shall be estimated subject to adjustment when the actual determination can be made, and all payments shall be subject to subsequent adjustment.
 
8.04.   Unconditional Obligation to Pay Demand and Other Charges.   The obligation of each Sponsoring Company to pay its specified portion of the Demand Charge under Section 5.03, the Transmission Charge under Section 5.04, and all charges under Article 7 for any Month shall not be reduced irrespective of:
 
(a)   whether or not any Available Power or Available Energy are supplied by the Corporation during such calendar month and whether or not any Available Power or Available Energy are accepted by any Sponsoring Company during such calendar month;
 
(b)   the existence of any claim, set-off, defense, reduction, abatement or other right (other than irrevocable payment, performance, satisfaction or discharge in full) that such Sponsoring Company may have, or which may at any time be available to or be asserted by such Sponsoring Company, against the Corporation , any other Sponsoring Company, any creditor of the Corporation or any other Person (including, without limitation, arising as a result of any breach or alleged breach by either the Corporation, any other Sponsoring Company, any creditor of the Corporation or any other Person under this Agreement or any other agreement (whether or not related to the transactions contemplated by this Agreement or any other agreement) to which such party is a party); or
 
(c)   the validity or enforceability against any other Sponsoring Company of this Agreement or any right or obligation hereunder (or any release or discharge thereof) at any time.
 
 
 
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ARTICLE 9
 
 
General Provisions
 
9.01.   Characteristics of Supply and Points of Delivery.   All power and energy delivered hereunder shall be 3-phase, 60-cycle, alternating current, at a nominal unregulated voltage designated for the point of delivery as described in this Article 9.  Available Power and Available Energy to be delivered between Corporation and the Sponsoring Companies pursuant to this Agreement shall be delivered under the terms and conditions of the Tariff at the points, as scheduled by the Sponsoring Company in accordance with procedures established by the Operating Committee and in accordance with Section 9.02, where the transmission facilities of Corporation interconnect with the transmission facilities of any Sponsoring Company (or its successor or predecessor); provided that, to the extent that a joint and common market is established for the sale of power and energy by Sponsoring Companies within one or more of the regional transmission organizations or independent system operators approved by the Federal Energy Regulatory Commission in which the Sponsoring Companies are members or otherwise participate, then Corporation and the Sponsoring Companies shall take such action as reasonably necessary to permit the Sponsoring Companies to bid their entitlement to power and energy from Corporation into such market(s) in accordance with the procedures established for such market(s).
 
9.02.    Modification of Delivery Schedules Based on Available Transmission Capability.   To the extent that transmission capability available for the delivery of Available Power and Available Energy at any delivery point is less than the total amount of Available Power and Available Energy scheduled for delivery by the Sponsoring Companies at such delivery point in accordance with Section 9.01, then the following procedures shall apply and the Corporation and the applicable Sponsoring Companies shall modify their delivery schedules accordingly until the total amount of Available Power and Available Energy scheduled for delivery at such delivery point is equal to or less than the transmission capability available for the delivery of Available Power and Available Energy: (a) the transmission capability available for the delivery of Available Power and Available Energy at the following delivery points shall be allocated first on a pro rata basis (in whole MW increments) to the following Sponsoring Companies up to their Power Participation Ratio share of the total amount of Available Energy available to all Sponsoring Companies (and as applicable, further allocated among Sponsoring Companies entitled to allocation under this Section 9.02(a) in accordance with their Power Participation Ratios): (i) to Allegheny, Appalachian, Buckeye, Columbus, FirstEnergy, Indiana, Monongahela, Ohio Power and Peninsula (or their successors) for deliveries at the points of interconnection between the Corporation and Appalachian, Columbus, Indiana or Ohio Power, or their successors; (ii) to Duke Ohio (or its successor) for deliveries at the points of interconnection between the Corporation and Duke Ohio or its successor; (iii) to Dayton (or its successor) for deliveries at the points of interconnection between the Corporation and Dayton or its successor; and (iv) to Kentucky, Louisville and Southern Indiana (or their successors) for deliveries at the points of interconnection between the Corporation and Louisville or Kentucky, or their successors; and (b) any remaining transmission capability available for the delivery of
 
 
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Available Power and Available Energy shall be allocated on a pro rata basis (in whole MW increments) to the Sponsoring Companies in accordance with their Power Participation Ratios.
 
9.03.   Operation and Maintenance of Systems Involved.   Corporation and the Sponsoring Companies shall operate their systems in parallel, directly or indirectly, except during emergencies that temporarily preclude parallel operation.  The parties hereto agree to coordinate their operations to assure maximum continuity of service from the Project Generating Stations, and with relation thereto shall cooperate with one another in the establishment of schedules for maintenance and operation of equipment and shall cooperate in the coordination of relay protection, frequency control, and communication and telemetering systems.  The parties shall build, maintain and operate their respective systems in such a manner as to minimize so far as practicable rapid fluctuations in energy flow among the systems.  The parties shall cooperate with one another in the operation of reactive capacity so as to assure mutually satisfactory power factor conditions among themselves.
 
The parties hereto shall exercise due diligence and foresight in carrying out all matters related to the providing and operating of their respective power resources so as to minimize to the extent practicable deviations between actual and scheduled deliveries of power and energy among their systems.  The parties hereto shall provide and/or install on their respective systems such communication, telemetering, frequency and/or tie-line control facilities essential to so minimizing such deviations; and shall fully cooperate with one another and with third parties (such third parties whose systems are either directly or indirectly interconnected with the systems of the Sponsoring Companies and who of necessity together with the parties hereto must unify their efforts cooperatively to achieve effective and efficient interconnected systems operation) in developing and executing operating procedures that will enable the parties hereto to avoid to the extent practicable deviations from scheduled deliveries.
 
In order to foster coordination of the operation and maintenance of Corporation’s transmission facilities with those facilities of Sponsoring Companies that are owned or functionally controlled by a regional transmission organization or independent system operator, Corporation shall use commercially reasonable efforts to enter into a coordination agreement with any regional transmission organization or independent system operator approved by the Federal Energy Regulatory Commission that operates transmission facilities that interconnect with Corporation’s transmission facilities, and to enter into a mutually agreeable services agreement with a regional transmission organization or independent system operator to provide the Corporation with reliability and security coordination services and other related services.
 
9.04.   Power Deliveries as Affected by Physical Characteristics of Systems.   It is recognized that the physical and electrical characteristics of the transmission facilities of the interconnected network of which the transmission systems of the Sponsoring Companies, Corporation, and other systems of third parties not parties hereto are a part, may at times preclude the direct delivery at the points of interconnection between the transmission systems of one or more of the Sponsoring Companies and Corporation, of some portion of the energy supplied under this Agreement, and that in each such case, because of said characteristics, some
 
 
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of the energy will be delivered at points which interconnect the system of one or more of the Sponsoring Companies with systems of companies not parties to this Agreement.  The parties hereto shall cooperate in the development of mutually satisfactory arrangements among themselves and with such companies not parties hereto whereby the supply of power and energy contemplated hereunder can be fulfilled.
 
9.05.   Operating Committee.   There shall be an “Operating Committee” consisting of one member appointed by the Corporation and one member appointed by each of the Sponsoring Companies electing so to do; provided that, if any two or more Sponsoring Companies are Affiliates, then such Affiliates shall together be entitled to appoint only one member to the Operating Committee.  The “Operating Committee” shall establish (and modify as necessary) scheduling, operating, testing and maintenance procedures of the Corporation in support of this Agreement, including establishing: (i) procedures for scheduling delivery of Available Energy under Section 4.03, (ii) procedures for power and energy accounting, (iii) procedures for the reservation and scheduling of firm and non-firm transmission service under the Tariff for the delivery of Available Power and Available Energy, (iv) the Minimum Generating Unit Output, and (v) the form of notifications relating to power and energy and the price thereof.  In addition, the Operating Committee shall consider and make recommendations to Corporation’s Board of Directors with respect to such other problems as may arise affecting the transactions under this Agreement.  The decisions of the Operating Committee, including the adoption or modification of any procedure by the Operating Committee pursuant to this Section 9.04, must receive the affirmative vote of at least two-thirds of the members of the Operating Committee, regardless of the number of members of the Operating Committee present at any meeting.
 
9.06.   Acknowledgment of Certain Rights.   For the avoidance of doubt, all of the parties to this Agreement acknowledge and agree that (i) as of the effective date of the Current Agreement, certain rights and obligations of the Sponsoring Companies or their predecessors under the Original Agreement were changed, modified or otherwise removed, (ii) to the extent that the rights of any Sponsoring Company or their predecessors were thereby changed, modified or otherwise removed as of the effective date of the Current Agreement, such Sponsoring Company may be entitled to rights under applicable law, regulation, rules or orders under the Federal Power Act or otherwise adopted by the Federal Energy Regulatory Commission (“FERC”), (iii) as a result of the elimination as of the effective date of the Current Agreement of the firm transmission service previously provided during the term of the Original Agreement to Sponsoring Companies or their predecessors whose transmission systems were only indirectly connected to the Corporation’s facilities through intervening transmission systems by certain Sponsoring Companies or their predecessors whose transmission systems were directly connected to the Corporation’s facilities, such Sponsoring Companies or their predecessors whose transmission systems were only indirectly connected to the Corporation’s facilities through intervening transmission systems shall have been entitled to such “roll over” firm transmission service for delivery of their entitlement to their Power Participation Ratio share of Surplus Power and Surplus Energy under this Agreement, to the border of such Sponsoring Company system and intervening Sponsoring Company system, as would be accorded a long-
 
 
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term firm point-to-point transmission service reservation under the then otherwise applicable FERC Open Access Transmission Tariff (“OATT”), (iv) the obligation of any Sponsoring Company to maintain or expand transmission capacity to accommodate another Sponsoring Company’s “roll over” rights to transmission service for delivery of their entitlement to their Power Participation Ratio share of Surplus Power and Surplus Energy under this Agreement shall be consistent with the obligations it would have for long-term firm point-to-point transmission service provided pursuant to the then otherwise applicable OATT, and (v) the parties shall cooperate with any Sponsoring Company that seeks to obtain and/or exercise any such rights available under applicable law, regulation, rules or orders under the Federal Power Act or otherwise adopted by the FERC.
 
9.07.   Term of Agreement.   This Agreement shall become effective upon the Effective Date and shall terminate upon the earlier of: (1) June 30, 2040 or (2) the sale or other disposition of all of the facilities of the Project Generating Stations or the permanent cessation of operation of such facilities; provided that , the provisions of Articles 5, 7 and 8, this Section 9.07 and Sections 9.08, 9.09, 9.10, 9.11, 9.12, 9.14, 9.15, 9.16, 9.17 and 9.18 shall survive the termination of this Agreement, and no termination of this Agreement, for whatever reason, shall release any Sponsoring Company of any obligations or liabilities incurred prior to such termination.
 
9.08.   Access to Records.   Corporation shall, at all reasonable times, upon the request of any Sponsoring Company, grant to its representatives reasonable access to the books, records and accounts of the Corporation, and furnish such Sponsoring Company such information as it may reasonably request, to enable it to determine the accuracy and reasonableness of payments made for energy supplied under this Agreement.
 
9.09.   Modification of Agreement.   Absent the agreement of all parties to this Agreement, the standard for changes to provisions of this Agreement related to rates proposed by a party, a non-party or the Federal Energy Regulatory Commission (or a successor agency) acting sua sponte shall be the “public interest” standard of review set forth in United Gas Pipeline Co. v. Mobile Gas Serv. Corp., 350 U.S. 332 (1956) and Federal Power Comm’n v. Sierra Pacific Power Co., 350 U.S. 348 (1956).
 
9.10.   Arbitration.   Any controversy, dispute or claim arising out of this Agreement or the refusal by any party hereto to perform the whole or any part thereof, shall be determined by arbitration, in the City of Columbus, Franklin County, Ohio, in accordance with the Commercial Arbitration Rules of the American Arbitration Association or any successor organization, except as otherwise set forth in this Section 9.10.
 
The party demanding arbitration shall serve notice in writing upon all other parties hereto, setting forth in detail the controversy, dispute or claim with respect to which arbitration is demanded, and the parties shall thereupon endeavor to agree upon an arbitration board, which shall consist of three members (“Arbitration Board”).  If all the parties hereto fail so to agree within a period of thirty (30) days from the original notice, the party demanding
 
 
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arbitration may, by written notice to all other parties hereto, direct that any members of the Arbitration Board that have not been agreed to by the parties shall be selected by the American Arbitration Association, or any successor organization.  No person shall be eligible for appointment to the Arbitration Board who is an officer, employee, shareholder of or otherwise interested in any of the parties hereto or in the matter sought to be arbitrated.
 
The Arbitration Board shall afford adequate opportunity to all parties hereto to present information with respect to the controversy, dispute or claim submitted to arbitration and may request further information from any party hereto; provided, however, that the parties hereto may, by mutual agreement, specify the rules which are to govern any proceeding before the Arbitration Board and limit the matters to be considered by the Arbitration Board, in which event the Arbitration Board shall be governed by the terms and conditions of such agreement.
 
The determination or award of the Arbitration Board shall be made upon a determination of a majority of the members thereof.  The findings and award of the Arbitration Board shall be final and conclusive with respect to the controversy, dispute or claim submitted for arbitration and shall be binding upon the parties hereto, except as otherwise provided by law.  The award of the Arbitration Board shall specify the manner and extent of the division of the costs of the arbitration proceeding among the parties hereto.
 
9.11.   Liability.   The rights and obligations of all the parties hereto shall be several and not joint or joint and several.
 
9.12.   Force Majeure.   No party hereto shall be held responsible or liable for any loss or damage on account of non-delivery of energy hereunder at any time caused by an event of Force Majeure.  “Force Majeure” shall mean the occurrence or non-occurrence of any act or event that could not reasonably have been expected and avoided by exercise of due diligence and foresight and such act or event is beyond the reasonable control of such party, including to the extent caused by act of God, fire, flood, explosion, strike, civil or military authority, insurrection or riot, act of the elements, or failure of equipment.  For the avoidance of doubt, “Force Majeure” shall in no event be based on any Sponsoring Company’s financial or economic conditions, including without limitation (i) the loss of the Sponsoring Company’s markets; or (ii) the Sponsoring Company’s inability economically to use or resell the Available Power or Available Energy purchased hereunder.
 
9.13.   Governing Law.   This Agreement shall be governed by, and construed in accordance with, the laws of the State of Ohio.
 
9.14.   Regulatory Approvals.   This Agreement is made subject to the jurisdiction of any governmental authority or authorities having jurisdiction in the premises and the performance thereof shall be subject to the following:
 
(a)   The receipt of all regulatory approvals, in form and substance satisfactory to Corporation, necessary to permit Corporation to perform all the duties and obligations to be performed by Corporation hereunder.
 
 
19

 
(b)   The receipt of all regulatory approvals, in form and substance satisfactory to the Sponsoring Companies, necessary to permit the Sponsoring Companies to carry out all transactions contemplated herein.
 
9.15.   Notices.   All notices, requests or other communications under this Agreement shall be in writing and shall be sufficient in all respects: (i) if delivered in person or by courier, upon receipt by the intended recipient or an employee that routinely accepts packages or letters from couriers or other persons for delivery to personnel at the address identified above (as confirmed by, if delivered by courier, the records of such courier), (ii) if sent by facsimile transmission, when the sender receives confirmation from the sending facsimile machine that such facsimile transmission was transmitted to the facsimile number of the addressee, or (iii) if mailed, upon the date of delivery as shown by the return receipt therefor.
 
9.16.   Waiver .  Performance by any party to this Agreement of any responsibility or obligation to be performed by such party or compliance by such party with any condition contained in this Agreement may by a written instrument signed by all other parties to this Agreement be waived in any one or more instances, but the failure of any party to insist in any one or more instances upon strict performance of any of the provisions of this Agreement or to take advantage of any of its rights hereunder shall not be construed as a waiver of any such provisions or the relinquishment of any such rights, but the same shall continue and remain in full force and effect.
 
9.17.   Titles of Articles and Sections.   The titles of the Articles and Sections in this Agreement have been inserted as a matter of convenience of reference and are not a part of this Agreement.
 
9.18.   Successors and Assigns.   This Agreement may be executed in any number of counterparts, all of which shall constitute but one and the same document.
 
9.181   This Agreement shall inure to the benefit of and be binding upon the parties hereto and their respective successors and assigns, but a party to this Agreement may not assign this Agreement or any of its rights, title or interests in or obligations (including without limitation the assumption of debt obligations) under this Agreement, except to a successor to all or substantially all the properties and assets of such party or as provided in Section 9.182 or 9.183, without the written consent of all the other parties hereto.
 
9.182   Notwithstanding the provisions of Section 9.181, any Sponsoring Company shall be permitted to, upon thirty (30) days notice to the Corporation and each other Sponsoring Company, without any further action by the Corporation or the other Sponsoring Companies, assign all or part of its rights, title and interests in, and obligations under this Agreement to a Permitted Assignee, provided that , the assignee and assignor of the rights, title and interests in, and obligations under, this Agreement have executed an assignment agreement in form and substance acceptable to the Corporation
 
 
20

 
  in its reasonable discretion (including, without limitation, the agreement by the Sponsoring Company assigning such rights, title and interests in, and obligations under, this Agreement to reimburse the Corporation and the other Sponsoring Companies for any fees or expenses required under any security issued, or agreement entered into, by the Corporation as a result of such assignment, including without limitation any consent fee or additional financing costs to the Corporation under the Corporation’s then-existing securities or agreements resulting from such assignment).
 
9.183   Notwithstanding the provisions of Section 9.181, any Sponsoring Company shall be permitted to, subject to compliance with all of the requirements of this Section 9.183, assign all or part of its rights, title and interests in, and obligations under this Agreement to a Third Party without any further action by the Corporation or the other Sponsoring Companies.
 
(a)   A Sponsoring Company (the “Transferring Sponsor”) that desires to assign all or part of its rights, title and interests in, and obligations under this Agreement to a Third Party shall deliver an Offer Notice to the Corporation and each other Sponsoring Company.  The Offer Notice shall be deemed to be an irrevocable offer of the subject rights, title and interests in, and obligations under this Agreement to each of the other Sponsoring Companies that is not an Affiliate of the Transferring Sponsor, which offer must be held open for no less than thirty (30) days from the date of the Offer Notice (the “ Election Period ”).
 
(b)   The Sponsoring Companies (other than the Transferring Sponsor and its Affiliates) shall first have the right, but not the obligation, to purchase all of the rights, title and interests in, and obligations under this Agreement described in the Offer Notice at the price and on the terms specified therein by delivering written notice of such election to the Transferring Sponsor and the Corporation within the Election Period; provided that, irrespective of the terms and conditions of the Offer Notice, a Sponsoring Company may condition its election to purchase the interest described in the Offer Notice on the receipt of approval or consent from such Sponsoring Company’s Board of Directors; provided further that, written notice of such conditional election must be delivered to the Transferring Sponsor and the Corporation within the Election Period and such conditional election shall be deemed withdrawn (as if it had never been provided) unless the Sponsoring Company that delivered such conditional election subsequently delivers written notice to the Transferring Sponsor and the Corporation on or before the tenth (10 th ) day after the expiration of the Election Period that all necessary approval or consent of such Sponsoring Company’s Board of Directors have been obtained .  To the extent that more than one Sponsoring Company exercises its right to purchase all of the rights, title and interests in, and obligations under this Agreement described in the Offer Notice in accordance with the previous sentence, such rights, title and interests in, and
 
 
21

 
  obligations under this Agreement shall be allotted (successively if necessary) among the Sponsoring Companies exercising such right in proportion to their respective Power Participation Ratios.
 
 
(c)   Each Sponsoring Company exercising its right to purchase any rights, title and interests in, and obligations under this Agreement pursuant to this Section 9.183 may choose to have an Affiliate purchase such rights, title and interests in, and obligations under this Agreement; provided that , notwithstanding anything in this Section 9.183 to the contrary, any assignment to a Sponsoring Company or its Affiliate hereunder must comply with the requirements of Section 9.182.
 
(d)   If one or more Sponsoring Companies have elected to purchase all of the rights, title and interests in, and obligations under this Agreement of the Transferring Sponsor pursuant to the Offer Notice, the assignment of such rights, title and interests in, and obligations under this Agreement shall be consummated as soon as practical after the delivery of the election notices, but in any event no later than fifteen (15) days after the filing and receipt, as applicable, of all necessary governmental filings, consents or other approvals and the expiration of all applicable waiting periods.  At the closing of the purchase of such rights, title and interests in, and obligations under this Agreement from the Transferring Sponsor, the Transferring Sponsor shall provide representations and warranties customary for transactions of this type, including those as to its title to such securities and that there are no liens or other encumbrances on such securities (other than pursuant to this Agreement) and shall sign such documents as may reasonably be requested by the Corporation and the other Sponsoring Companies.  The Sponsoring Companies or their Affiliates shall only be required to pay cash for the rights, title and interests in, and obligations under this Agreement being assigned by the Transferring Sponsor.
 
(e)   To the extent that the Sponsoring Companies have not elected to purchase all of the rights, title and interests in, and obligations under this Agreement described in the Offer Notice, the Transferring Sponsor may, within one-hundred and eighty (180) days after the later of the expiration of the Election Period or the deemed withdrawal of a conditional election by a Sponsoring Company under Section 9.183(b) hereof (if applicable), enter into a definitive agreement to, assign such rights, title and interests in, and obligations under this Agreement to a Third Party at a price no less than 92.5% of the purchase price specified in the Offer Notice and on other material terms and conditions no more
 
 
22

 
  favorable to the such Third Party than those specified in the Offer Notice; provided that such purchases shall be conditioned upon: (i) such Third Party having long-term unsecured non-credit enhanced indebtedness, as of the date of such assignment, with a Standard & Poor’s credit rating of at least BBB- and a Moody’s Investors Service, Inc. credit rating of at least Baa3 (provided that, if such Third Party’s long-term unsecured non-credit enhanced indebtedness is not currently rated by one of Standard & Poor’s or Moody, such Third Party’s long-term unsecured non-credit enhanced indebtedness, as of the date of such assignment, must have either a Standard & Poor’s credit rating of at least BBB- or a Moody’s Investors Service, Inc. credit rating of at least Baa3); (ii) the filing or receipt, as applicable, of any necessary governmental filings, consents or other approvals; (iii) the determination by counsel for the Corporation that the assignment of the rights, title or interests in, or obligations under, this Agreement to such Third Party would not cause a termination, default, loss or payment obligation under any security issued, or agreement entered into, by the Corporation prior to such transfer; and (iv) such Third Party executing a counterpart of this Agreement, and both such Third Party and the Sponsoring Company which is assigning its rights, title and interests in, and obligations under, this Agreement executing such other documents as may be reasonably requested by the Corporation (including, without limitation, an assignment agreement in form and substance acceptable to the Corporation in its reasonable discretion and containing the agreement by such Sponsoring Company to reimburse the Corporation and the other Sponsoring Companies for any fees or expenses required under any security issued, or agreement entered into, by the Corporation as a result of such assignment, including without limitation any consent fee or additional financing costs to the Corporation under the Corporation’s then-existing securities or agreements resulting from such assignment).  In the event that the Sponsoring Company and a Third Party have not entered into a definitive agreement to assign the interests specified in the Offer Notice to such Third Party within the later of one-hundred and eighty (180) days after the expiration of the Election Period or the deemed withdrawal of a conditional election by a Sponsoring Company under Section 9.183(b) hereof (if applicable) for any reason or if either the price to be paid by such Third Party would be less than 92.5% of the purchase price specified in the Offer Notice or the other material terms of such assignment would be more favorable to such Third Party than the terms specified in the Offer Notice, then the restrictions provided for herein shall again be effective, and no assignment of any rights, title and interests in, and obligations under this Agreement may be made thereafter without again offering the same to Sponsoring Companies in accordance with this Section 9.183.
 
 
23

 
 
ARTICLE 10
 
Representations and Warranties
 
10.01.   Representations and Warranties .  Each Sponsoring Company hereby represents and warrants for itself, on and as of the date of this Agreement, as follows:
 
(a)   it is duly organized, validly existing and in good standing under the laws of its state of organization, with full corporate power, authority and legal right to execute and deliver this Agreement and to perform its obligations hereunder;
 
(b)   it has duly authorized, executed and delivered this Agreement, and upon the execution and delivery by all of the parties hereto, this Agreement will be in full force and effect, and will constitute a legal, valid and binding obligation of such Sponsoring Company, enforceable in accordance with the terms hereof, except as enforceability may be limited by applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium or other similar laws affecting the enforcement of creditors’ rights generally;
 
(c)   Except as set forth in Schedule 10.01(c) hereto, no consents or approvals of, or filings or registrations with, any governmental authority or public regulatory authority or agency, federal state or local, or any other entity or person are required in connection with the execution, delivery and performance by it of this Agreement, except for those which have been duly obtained or made and are in full force and effect, have not been revoked, and are not the subject of a pending appeal; and
 
(d)   the execution, delivery and performance by it of this Agreement will not conflict with or result in any breach of any of the terms, conditions or provisions of, or constitute a default under its charter or by-laws or any indenture or other material agreement or instrument to which it is a party or by which it may be bound or result in the imposition of any liens, claims or encumbrances on any of its property.
 
 
ARTICLE 11
 
Events of Default and Remedies

11.01.   Payment Default .  If any Sponsoring Company fails to make full payment to Corporation under this Agreement when due and such failure is not remedied within ten (10) days after receipt of notice of such failure from the Corporation, then such failure shall constitute a “Payment Default” on the part of such Sponsoring Company.  Upon a Payment Default, the
 
 
24

 
Corporation may suspend service to the Sponsoring Company that has caused such Payment Default for all or part of the period of continuing default (and such Sponsoring Company shall be deemed to have notified the Corporation and the other Sponsoring Companies that any Available Energy shall be available for scheduling by such other Sponsoring Companies in accordance with Section 4.032).   The Corporation’s right to suspend service shall not be exclusive, but shall be in addition to all remedies available to the Corporation at law or in equity.  No suspension of service or termination of this Agreement shall relieve any Sponsoring Company of its obligations under this Agreement, which are absolute and unconditional.
 
11.02.   Performance Default.   If the Corporation or any Sponsoring Company fails to comply in any material respect with any of the material terms, conditions and covenants of this Agreement (and such failure does not constitute a Payment Default under Section 11.01), the Corporation (in the case of a default by any Sponsoring Company) and any Sponsoring Company (in the case of a default by the Corporation) shall give the defaulting party written notice of the default (“Performance Default”).  To the extent that a Performance Default is not cured within thirty (30) days after receipt of notice thereof (or within such longer period of time, not to exceed sixty (60) additional days, as necessary for the defaulting party with the exercise of reasonable diligence to cure such default), then the Corporation (in the case of a default by any Sponsoring Company) and any Sponsoring Company (in the case of a default by the Corporation) shall have all of the rights and remedies provided at law and in equity, other than termination of this Agreement or any release of the obligation of the Sponsoring Companies to make payments pursuant to this Agreement, which obligation shall remain absolute and unconditional.
 
11.03.   Waiver.   No waiver by the Corporation or any Sponsoring Company of any one or more defaults in the performance of any provision of this Agreement shall be construed as a waiver of any other default or defaults, whether of a like kind or different nature.
 
11.04.   Limitation of Liability and Damages.   TO THE FULLEST EXTENT PERMITTED BY LAW, NEITHER THE CORPORATION, NOR ANY SPONSORING COMPANY SHALL BE LIABLE UNDER THIS AGREEMENT FOR ANY CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST REVENUES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, OR OTHERWISE.
 

[ Signature pages follow ]

 
25

 
 
 

 

IN WITNESS WHEREOF, the parties hereto have caused this Amended and Restated Inter-Company Power Agreement to be duly executed and delivered by their proper and duly authorized officers as of September 10, 2010.
 

OHIO VALLEY ELECTRIC CORPORATION
 
 
By   /s/ Michael G. Morris
Its   President
ALLEGHENY ENERGY SUPPLY COMPANY, L.L.C.
 
 
By   /s/ Thomas J. Kalup
Its   Vice President
 
APPALACHIAN POWER COMPANY
 
 
 
By   /s/ Nicholas K. Akins
Its   Vice President
 
BUCKEYE POWER GENERATING, LLC
 
 
By   /s/ Anthony J. Ahern
Its   President
   
COLUMBUS SOUTHERN POWER COMPANY
 
 
By   /s/ Carl L. English
Its   Vice President
 
THE DAYTON POWER AND LIGHT COMPANY
 
 
By   /s/ Gary G. Stephenson
Its   Vice President
   
DUKE ENERGY OHIO, INC.
 
 
By   /s/ Charles Whitlock
Its  Vice President
 
FIRSTENERGY GENERATION CORP.
 
 
By   /s/ Gary R. Leidich
Its   President
 
   
INDIANA MICHIGAN POWER COMPANY
 
 
By /s/ Marc E. Lewis
Its   Vice President
 
 
KENTUCKY UTILITIES COMPANY
 
 
By   /s/ Paul W. Thompson
Its   Vice President
 
 
 
 

 
LOUISVILLE GAS AND ELECTRIC COMPANY
 
 
By   /s/ John N. Voyles, Jr.
Its   Vice President
 
 
MONONGAHELA POWER COMPANY
 
 
By   /s/ R. B. Reeping
Its   General Manager
 
OHIO POWER COMPANY
 
 
By   /s/ Carl L. English
Its   Vice President
SOUTHERN INDIANA GAS AND ELECTRIC COMPANY
 
 
By   /s/ Ronald E. Christian
Its   President
 
   
   

PENINSULA GENERATION COOPERATIVE


By   /s/ Daniel B. DeCoeur
Its   President
Exhibit 10(b)
 
RATE SCHEDULE NO.  25

RESTATED AND AMENDED OPERATING AGREEMENT

AMONG

PUBLIC SERVICE COMPANY OF OKLAHOMA,
SOUTHWESTERN ELECTRIC POWER COMPANY

AND

AMERICAN ELECTRIC POWER SERVICE CORPORATION

AS AGENT






 
 



Tariff Submitter: Public Service Company of Oklahoma
FERC Program Name:   FERC FPA Electric Tariff
Tariff Title:   PSO Rate Schedules and Service Agreements Tariffs
Tariff Proposed Effective Date :  03/01/2014
Tariff Record Title:   Restated and Amended Operating Agreement
Option Code: A
Record Content Description:   Rate Schedule No. 25

 
1

 

RESTATED AND AMENDED OPERATING AGREEMENT
           
TABLE OF CONTENTS
           
ARTICLE I DEFINITIONS
 
6
           
 
1.1
 
Agreement
 
6
 
1.2
 
Capacity Commitment
 
6
 
1.3
 
Capacity Commitment Charge
 
6
 
1.4
 
Generating Unit
 
6
 
1.5
 
Industry Standards
 
6
 
1.6
 
Load
 
6
 
1.7
 
Operating Committee
 
6
 
1.8
 
Party or Parties
 
7
 
1.9
 
Pool Energy
 
7
 
1.1
 
Service Schedules
 
7
 
1.11
 
Seller's Incremental Energy Cost
7
 
1.12
 
System Emergency
 
7
 
1.13
 
System
 
7
 
1.14
 
Variable Cost
 
7
           
ARTICLE II TERM OF AGREEMENT
 
7
           
 
2.1
 
Term
 
7
           
ARTICLE III OBJECTIVES
 
8
 
3.1
 
Purpose
 
8
           
ARTICLE IV SCOPE AND RELATIONSHIP TO  OTHER  AGREEMENTS AND
 
 
 SERVICES
   
8
           
 
4.1
 
Scope
 
8
 
4.2
 
Transmission
 
9
           
ARTICLE V AGENT
   
9
           
 
5.1
 
Agent's Functions
 
9
 
5.2
 
Appointment of Agent
 
10
 
5.3
 
Delegation of Duties
 
10
           
ARTICLE VI COMPOSITION AND DUTIES OF THE OPERATING COMMITTEE
10
           
 
6.1
 
Operating Committee
 
10
 
6.2
 
Meeting Dates
 
11
 
6.3
 
Duties
 
11
           
ARTICLE VII COORDINATED PLANNING AND OPERATIONS
12
           
 
7.1
 
Coordinated System Planning
 
12
 
7.2
 
Coordinated System Dispatch
 
13
 
7.3
 
Capacity Sales
 
13
 
7.4
 
Energy Sales
 
14
 
7.5
 
Emergency Response
 
14
 
 
2

 
           
ARTICLE VIII ASSIGNMENT OF COSTS AND BENEFITS  OF COORDINATED
15
 
OPERATIONS
   
           
 
8.1
 
Service Schedules
 
15
           
ARTICLE IX BILLING PROCEDURES
 
15
           
 
9.1
 
Records
 
15
 
9.2
 
Monthly Statements
 
15
 
9.3
 
Billings and Payments
 
16
 
9.4
 
Taxes
 
16
 
9.5
 
Billing Errors
 
16
 
9.6
 
Billing Omissions
 
17
 
9.7
 
Billing Disputes
 
17
           
ARTICLE X FORCE MAJEURE
 
17
           
 
10.1
 
Events Excusing Performance
 
17
           
ARTICLE XI DELIVERY POINTS
 
18
           
 
11.1
 
Delivery Points
 
18
           
ARTICLE XII GENERAL
   
18
         
 
12.1
 
Adherence to Reliability Criteria
18
 
12.2
 
No Third Party Beneficiaries
 
19
 
12.3
 
Waivers
 
19
 
12.4
 
Successors and Assigns
 
19
 
12.5
 
Liability and Indemnification
 
20
 
12.6
 
Headings
 
20
 
12.7
 
Notice
 
20
 
12.8
 
Effect on Other Agreements
 
21
 
12.9
 
Interpretation
 
21
           
ARTICLE XIII REGULATORY APPROVAL
 
22
           
 
13.1
 
Regulatory Authorization
 
22
 
13.2
 
Changes
 
22
           
SCHEDULE A POOL ENERGY
 
24
           
 
14.1
 
Duration
 
24
 
14.2
 
Purpose
 
24
 
14.3
 
Receipts and Payments
 
24
           
SCHEDULE B DISTRIBUTION OF BENEFITS AND COSTS OF OFF-SYSTEM
25
 
SALES AND PURCHASES
   
           
 
15.1
 
Duration
 
25
 
15.2
 
Purpose
 
25
 
15.3
 
Direct Assignment
 
25
 
15.4
 
System Participation
 
26
 
15.5
 
Other Distributions
 
26
           
SCHEDULE C CAPACITY COMMITMENT CHARGE
 
27
 
 
3

 
 
16.1
 
Duration
 
27
 
16.2
 
Purpose
 
27
 
16.3
 
Basis for Capacity Commitment
 
27
 
16.4
 
Provisions for Capacity Commitment Charge
27
 
16.5
 
Provision for Energy Charge
 
28
           
SCHEDULE D CAPACITY COMMITMENT UNITS
 
29
           
 
17.1
 
Duration
 
29
 
17.2
 
Purpose
 
29
 
17.3
 
Commitment Units
 
29

 
4

 
RESTATED AND AMENDED OPERATING AGREEMENT

THIS AGREEMENT is made and entered into as of the 1 st day of March, 2014 by and among Public Service Company of Oklahoma (“PSO”), Southwestern Electric Power Company (“SWEPCO”),  and American Electric Power Service Corporation (“AEPSC”) as Agent to PSO and SWEPCO, and supersedes the Restated and Amended Operating Agreement issued on February 2, 2009.
 
RECITALS:
 
WHEREAS , PSO and SWEPCO (collectively the “Operating Companies” or individually "Operating Company") are the owners and operators of interconnected electric generation, transmission, and distribution facilities with which they are engaged in the business of generating, transmitting, and selling electric power to the general public and to other electric utilities; and
 
WHEREAS , the Operating Companies achieve and believe that they can continue to achieve economic benefits for their customers through coordinated planning, operation and maintenance of their electric supply facilities; and
 
WHEREAS , the achievement of the foregoing will be facilitated by the performance of certain services by an agent;
 
WHEREAS , AEPSC is the service company affiliate of the Operating Companies and as such performs a variety of services on their behalf in accordance with applicable rules and regulations of the Federal Energy Regulatory Commission (“Commission”); and
 
WHEREAS , AEPSC is qualified and willing to act as Agent for the Operating Companies;
 
NOW, THEREFORE , the Parties hereto mutually agree as follows:
 
 
5

 
ARTICLE I
DEFINITIONS
 
For the purposes of this Agreement and of Service Schedules A through D which are attached hereto and made a part hereof, the following definitions shall apply:
 
1.1   Agreement means this Restated and Amended Operating Agreement, including all Service Schedules and attachments hereto.
 
1.2   Capacity Commitment means generating capacity committed by an Operating Company to provide capability to enable another Operating Company to attain its reserve requirement.
 
1.3   Capacity Commitment Charge means the charge made by an Operating Company supplying a Capacity Commitment to the Operating Company receiving the Capacity Commitment.
 
1.4   Generating Unit means an electric generator, together with its prime mover and all auxiliary and appurtenant devices and equipment designed to be operated as a unit for the production of energy, capacity and any other wholesale products or services capable of being produced there from.  The above is to include equipment necessary for connection to the transmission system.
 
1.5   Industry Standards means all applicable regional and national electric reliability council and regional transmission organization principles, guides, criteria, standards and practices.
 
1.6   Load means the energy required by an Operating Company’s retail or wholesale power customer on whose behalf the Operating Company, by statute, franchise, regulatory requirement, or firm power supply contract, has undertaken an obligation to supply electricity to reliably meet the electric needs of such customer.
 
1.7   Operating Committee means the administrative body established pursuant to Article VI for the purposes specified within this Agreement.
 
 
6

 
1.8   Party or Parties means one or more of the following, individually or collectively, as the context warrants: PSO, SWEPCO, and Agent.
 
1.9   Pool Energy means the energy supplied and sold by one Operating Company to another Operating Company to enable the purchasing Operating Company to meet a portion of its Load that such other Operating Company cannot or does not plan to serve with its resources.
 
1.10   Service Schedules means the Service Schedules attached to this Agreement and those that later may be agreed to by the Parties and accepted for filing by the Commission, as they may be amended from time to time.
 
1.11   Seller's Incremental Energy Cost means the Variable Cost that a selling Operating Company incurs in order to supply energy.
 
1.12   System Emergency means a condition which, if not promptly corrected, threatens to cause imminent harm to persons or property, including the equipment of a Party or a third party, or threatens the reliability of electric service provided by an Operating Company to its customers.
 
1.13   System means the coordinated Generating Units and Load of the Operating Companies.
 
1.14   Variable Cost means a cost or expense incurred that would not have otherwise been incurred to provide energy.
 
ARTICLE II
TERM OF AGREEMENT
 
2.1 Te rm
 
 
Subject to Commission approval or acceptance for filing, this Agreement shall take effect on March 1, 2014 or the date of the start of the Southwest Power Pool Integrated Marketplace, as reasonably determined by the Agent, or such other date permitted by the Commission, and shall
 
 
7

 
 
continue in full force and effect until terminated: (a) by mutual agreement; or (b) upon twelve (12) months' written notice by one Party to each of the other Parties.
 
ARTICLE III
OBJECTIVES
 
3.1  Purpose
 
 
The purpose of this Agreement is to provide a contractual basis for coordinating the planning, operation, and maintenance of the power supply resources of the Operating Companies to achieve economies and efficiencies consistent with the provision of reliable electric service and an equitable sharing of the benefits and costs of such coordinated arrangements. This Agreement is based on the premise that each Operating Company will maintain sufficient long-term power supply resources to meet its Load requirements.
 
ARTICLE IV
SCOPE AND RELATIONSHIP TO
OTHER  AGREEMENTS AND SERVICES
 
4.1  Scope
 
 
The transactions governed by this Agreement are subject to, and may be limited from time to time by, applicable state and federal laws, and the regulations, rules, and orders of applicable regulatory agencies regarding the purchase and sale of energy and/or capacity among affiliates. This Agreement is not intended to preclude the Parties from entering into other arrangements between or among themselves or with third parties.  This Agreement is intended to operate in addition to, not in lieu of, power market transactions and settlements that occur between each Operating Company or the Operating Companies collectively and any applicable regional transmission organizations.
 
 
8

 
4.2 T ransmission
 
 
This Agreement is intended to apply to the coordination of the power supply resources of, and loads served by, the Operating Companies. It is not intended to apply to the coordination of transmission facilities owned or operated by the Operating Companies.
 
ARTICLE V
AGENT
 
5.1 Agent's Functions
 
 
Subject to the direction of the Operating Committee, Agent agrees to:
 
(a)  
evaluate and make recommendations concerning the adequacy of power supply resources to meet the load requirements of the Operating Companies or to make off-System sales, including generation additions, retirements, acquisitions and dispositions;
 
(b)  
coordinate the operation and maintenance of the Operating Companies' respective power supply resources;
 
(c)  
administer the participation of each Operating Company in the power markets of the applicable regional transmission organization, including the settlement and dispatch of each Operating Company’s power supply resources in accordance with the rules of the applicable regional transmission organization;
 
(d)  
conduct off-System purchases and sales on behalf of the Operating Companies;
 
(e)  
prepare and deliver to the Parties a monthly settlement statement relating to transactions pursuant to this Agreement and make available as requested supporting details for any Party to inspect for a period of time not to exceed three (3) years from the date expenses were incurred or revenues received;
 
 
 
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(f)
acquire and coordinate transmission and ancillary services from affiliated and non-affiliated transmission providers for use with respect to transactions between or among Operating Companies under this Agreement, off-System purchases and off-System sales;
 
(g)
reassign transmission services obtained for wholesale merchant purposes on behalf of any Operating Company;  and
 
(h) p erform such other activities and duties as may be assigned from time to time by the Operating Committee.
 
5.2 Appointment of Agent
 
 
As of the effective date of this Agreement as specified in Section 2.1, the Operating Companies delegate to AEPSC as the Agent, and AEPSC, as the Agent, hereby accepts responsibility and authority for the duties listed in Section 5.1 and elsewhere in this Agreement, and shall perform each of those duties under the direction of the Operating Committee.
 
5.3  Delegation of Duties
 
 
With the prior written consent of the other Parties, AEPSC may assign all or a part of its responsibilities under this Agreement to another entity.
 
ARTICLE VI
COMPOSITION AND DUTIES OF THE OPERATING COMMITTEE
 
6.1  Operating Committee
 
 
By written notice to the other Parties, each Party shall name one representative (“Representative”) to act for it in matters pertaining to this Agreement and its implementation.  A Party may change its Representative at any time by written notice to the other Parties.  The Representatives of the respective Parties shall comprise the Operating Committee.  The Agent’s
 
 
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Representative shall act as the chairman of the Operating Committee (“Chairman”).  All decisions of the Operating Committee shall be by a simple majority vote of the Representatives.   With respect to all duties and decisions, the Operating Committee will take such action as reasonably necessary to permit each of the Operating Companies to fulfill its reliability obligations.
 
6.2  Meeting Dates
 
 
The Operating Committee shall hold meetings at such times, means, and places as the Representatives shall determine from time to time.  Minutes of each Operating Committee meeting shall be prepared and maintained.
 
6.3  Duties
 
 
The Operating Committee shall have the following duties, unless such duties are otherwise assigned by a vote of the Operating Committee to the Agent, in which case the Agent shall perform such duties:
 
(a)  
reviewing and determining the proportional sharing of costs and benefits under this Agreement among the Operating Companies;
 
(b)  
administering and interpreting this Agreement and making any amendments hereto, subject to any necessary regulatory approvals, including such amendments that are proposed in response to a change in regulatory requirements applicable to one or more of the Operating Companies or changes concerning an applicable regional transmission organization;
 
(c)  
reviewing and, if necessary, amending the duties and responsibilities of the Agent; and
 
 
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     (d) ensuring coordination for other matters not specifically provided for herein that the Operating Committee considers necessary to the reliable and economic use of each Operating Company’s power supply resources.
 
In the event that an action of the Operating Committee results in a change to the settlement process(es) among the Operating Companies, such modified settlement will normally occur on a prospective basis only, however, this may include past billing periods back to the beginning of the first full billing month preceding the date of action of the Operating Committee.  Such modifications will be subject to the terms of Article IX as applicable.
 
ARTICLE VII
COORDINATED PLANNING AND OPERATIONS
 
7.1  Coordinated System Planning
 
 
Each Operating Company, with support from the Agent, will be individually responsible for its own capacity planning.  Each Operating Company will be responsible for maintaining an adequate level of generation resources to meet its own Load requirements for capacity and energy, including any required reserve margins, and shall bear all of the resulting costs.
 
The Agent, under the direction of the Operating Committee will, on an annual basis, or more frequently if circumstances dictate, assess the adequacy of the power supply resources of the Operating Companies from the perspective of each Operating Company and the Operating Companies collectively, taking into account reserve requirements, capacity requirements of the applicable regional transmission organization, state integrated resource plans, as applicable, each Operating Company's load forecast, changing regulatory structures and requirements and all other criteria applicable by law, regulation or agreement to each Operating Company.  The Agent will subsequently make recommendations to the Operating Committee regarding the need for additional power supply resources.  Based on Agent's recommendations, the Operating
 
 
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Committee will decide whether or not to construct, purchase or otherwise acquire power supply resources for the benefit of one or more Operating Company.  If the Operating Committee decides to add such resources, the costs associated with such power supply resources will be allocated to the Operating Companies in proportion to their need for such power supply resources.
 
Similarly, the Agent, under the direction of the Operating Committee, will, on an annual basis, or more frequently if circumstances dictate, assess whether an Operating Company has power supply resources above its own capacity requirements (short-term or long-term) that could be made available to the other Operating Company. Notwithstanding any of the foregoing, the actual addition or disposition of power supply resources will be conditioned on compliance with all applicable state and other regulatory requirements; in no event will the Operating Committee or Agent acquire, assign, reassign, or dispose of power supply resources for an Operating Company in contravention of such requirements.
 
7.2  Coordinated System Dispatch
 
 
It is the intent of the Operating Companies to dispatch their power supply resources on a coordinated basis and in accordance with the rules of the applicable regional transmission organization.  The revenues and costs of off-System transactions and of serving an Operating Company’s Load will be shared by the Operating Companies pursuant to Schedule B.
 
7.3  Capacity Sales
 
 
Whenever any Operating Company has surplus capacity and the other Operating Company has insufficient capacity, the Agent shall evaluate the feasibility of a capacity transaction between the Operating Companies. Such evaluation shall take into account the
 
 
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availability of transmission capacity, state resource procurement policies, and alternative opportunities for sales and purchases. Where feasible, the Agent may recommend and the Operating Committee may direct an Operating Company with surplus capacity to make a Capacity Commitment to an Operating Company with insufficient capacity.  The Operating Company with insufficient capacity shall make payments to the Operating Company with surplus capacity for each such month that a Capacity Commitment applies in the amount of the Capacity Commitment Charge in accordance with Schedule C.  Capacity sales may also be set out in separate agreements or Service Schedules, which shall be subject to any necessary Commission acceptance or approval.
 
7.4  Energy Sales
 
 
An Operating Company will make energy available from its power supply resources to the other Operating Company for the purposes and to the extent provided by this Agreement.  The Agent shall coordinate and direct off-System sales of energy by the Operating Companies.
 
7.5  Emergency Response
 
 
In the event of a System Emergency, no adverse distinction shall be made between the customers of either Operating Company.  Each Operating Company shall make its power supply resources available in response to a System Emergency. Notwithstanding the foregoing, it is understood that transmission constraints or other factors may limit the ability of one Operating Company to respond to a System Emergency.
 
 
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ARTICLE VIII
ASSIGNMENT OF COSTS AND BENEFITS
OF COORDINATED OPERATIONS
 
8.1 Service Schedules
 
 
The costs and revenues associated with coordinated operations as described in Article VII shall be distributed in the manner provided in the Service Schedules utilizing the billing procedures described in Article IX.  It is understood and agreed that all such Service Schedules are intended to establish an equitable sharing of costs and/or benefits among the Parties, and that circumstances may, from time to time, require a reassessment of the relative benefits and burdens of this Agreement, or the methods used to apportion costs and benefits under the Service Schedules.  Upon a recommendation of the Operating Committee, any of the Service Schedules may be amended as of any date agreed to by the Operating Committee by majority vote, subject to receipt of any necessary regulatory authorizations.
 
ARTICLE IX
BILLING PROCEDURES
 
9.1  Records
 
 

The Agent shall maintain such records as may be necessary to determine the assignment of costs and benefits of coordinated operations pursuant to this Agreement. Such records shall be made available to the Parties upon request for a period not to exceed three (3) years.
 
9.2  Monthly Statements
 
 
As promptly as practicable after the end of each calendar month, the Agent shall prepare a statement setting forth the monthly summary of costs and revenues allocated or assigned to the Parties in sufficient detail as may be needed for settlements under the provisions of this
 
 
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Agreement. As required, the Agent may provide such statements on an estimated basis and then adjust those statements for actual results.
 
9.3  Billings and Payments
 
 
The Agent shall be responsible for all billing between the Operating Companies and other entities with which they engage in off-System purchases and off-System sales pursuant to this Agreement.  Payments among the Operating Companies, if any, shall be made by remittance of the net amount billed or by making appropriate accounting entries on the books of the Parties.  The entire amount shall be paid when due.
 
9.4  Taxes
 
 
Should any federal, state, or local tax, surcharge or similar assessment, in addition to those that may now exist, be levied upon the electric capacity, energy, or services to be provided in connection with this Agreement, or upon the provider of service as measured by the electric capacity, energy, or services, or the revenue therefrom, such additional amount shall be included in the net billing described in Section 9.3.
 
9.5  Billing Errors
 
 
If a Party discovers a billing error pertaining to a prior billing for reasons including, but not limited to, missing or erroneous data or calculations, including those caused by meter, computer or human error, a correction adjustment will be calculated.  The correction adjustment shall not be applied to any period earlier than the beginning of the second full billing month preceding the discovery of the error, nor will interest accrue on such adjustment. The correction adjustment will be applied as soon as practicable to the next subsequent regular monthly bill.
 
 
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Any overpaid amount attributed to such billing errors shall be returned by the owing Party upon determination of the correct amount with no interest.
 
9.6  Billing Omissions
 
 
Within one (1) year from the date on which a bill should have been delivered, if a Party’s records reveal that the bill was not delivered, then the Agent shall deliver to the appropriate Party a bill within one (1) month of this determination.  Any amounts collected or reimbursed due to such omissions shall exclude interest.  The right to receive payment is waived with respect to any amounts not billed within this period.
 
9.7  Billing Disputes
 
 
The Parties shall have the right to dispute the accuracy of any bill or payment for a period not to exceed two months from the date on which the bill was initially delivered.  Following this one-month period, the right to dispute a bill is permanently waived for any and all reasons including but not limited to, (a) errors, (b) omissions, (c) Agent’s actions, and (d) the Operating Committee’s decisions, Agreement interpretations and direction in the administration of the Agreement.  Any amounts collected or reimbursed due to such disputes shall exclude interest.
 
ARTICLE X
FORCE MAJEURE
 
10.1 Events Excusing Performance
 
 
No Party shall be liable to another Party for or on account of any loss, damage, injury, or expense resulting from or arising out of a delay or failure to perform, either in whole or in part, any of the agreements, covenants, or obligations made by or imposed upon the Parties by this Agreement, by reason of or through strike, work stoppage of labor, failure of contractors or
 
 
17

 
suppliers of materials (including fuel, consumables or other goods and services), failure of equipment, environmental restrictions, riot, fire, flood, ice, invasion, civil war, commotion, insurrection, military or usurped power, order of any court or regulatory agency granted in any bona fide legal proceedings or action, or of any civil or military authority either de facto or de jure, explosion, Act of God or the public enemies, or any other cause reasonably beyond its control and not attributable to its neglect.  A Party experiencing such a delay or failure to perform shall use due diligence to remove the cause or causes thereof; however, no Party shall be required to add to, modify or upgrade any facilities, or to settle a strike or labor dispute except when, according to its own best judgment, such action is advisable.
 
ARTICLE XI
DELIVERY POINTS
 
11.1  Delivery Points
 
 
All electric energy delivered under this Agreement shall be of the character commonly known as three-phase sixty-cycle energy, and shall be delivered at the interconnection points of the applicable Generating Units, at the nominal unregulated voltage designated for such points, and at such other points and voltages as may be determined and agreed upon by the Operating Companies.
 
ARTICLE XII
GENERAL
 
12.1  Adherence to Reliability Criteria
 
 
The Parties agree to conform to all applicable Industry Standards as they affect the implementation of this Agreement.
 
 
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12.2  No Third Party Beneficiaries
 
 
This Agreement does not create rights of any character whatsoever in favor of any person, corporation, association, entity or power supplier, other than the Parties, and the obligations herein assumed by the Parties are solely for the use and benefit of the Parties. Nothing in this Agreement shall be construed as permitting or vesting, or attempting to permit or vest, in any person, corporation, association, entity or power supplier, other than the Parties, any rights hereunder or in any of the resources or facilities owned or controlled by the Parties or the use thereof.
 
12.3  Waivers
 
 
Any waiver at any time by a Party of its rights with respect to a default under this Agreement, or with respect to any other matter arising in connection with this Agreement, shall not be deemed a waiver with respect to any subsequent default or matter. Any delay, short of the statutory period of limitation, in asserting or enforcing any right under this Agreement, shall not be deemed a waiver of such right.
 
12.4  Successors and Assigns
 
 
This Agreement shall inure to the benefit of and be binding upon the Parties only, and their respective successors and assigns, and shall not be assignable by any Party without the written consent of the other Parties except to a successor in the operation of its properties by reason of a reorganization to comply with state or federal restructuring requirements, or a merger, consolidation, sale or foreclosure whereby substantially all such properties are acquired by or merged with those of such a successor.
 
 
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12.5  Liability and Indemnification
 
 
SUBJECT TO ANY APPLICABLE STATE OR FEDERAL LAW THAT MAY SPECIFICALLY RESTRICT LIMITATIONS ON LIABILITY, EACH PARTY SHALL RELEASE, INDEMNIFY, AND HOLD HARMLESS THE OTHER PARTIES, THEIR DIRECTORS, OFFICERS AND EMPLOYEES FROM AND AGAINST ANY AND ALL LIABILITY FOR LOSS, DAMAGE OR EXPENSE ALLEGED TO ARISE FROM, OR BE INCIDENTAL TO, INJURY TO PERSONS AND/OR DAMAGE TO PROPERTY IN CONNECTION WITH ITS FACILITIES OR THE PRODUCTION OR TRANSMISSION OF ELECTRIC ENERGY BY OR THROUGH SUCH FACILITIES, OR RELATED TO PERFORMANCE OR NON-PERFORMANCE OF THIS AGREEMENT, INCLUDING ANY NEGLIGENCE ARISING HEREUNDER. IN NO EVENT SHALL ANY PARTY BE LIABLE TO ANOTHER PARTY FOR ANY INDIRECT, SPECIAL, INCIDENTAL, OR CONSEQUENTIAL DAMAGES WITH RESPECT TO ANY CLAIM ARISING OUT OF THIS AGREEMENT.
 
12.6  Headings
 
 
The descriptive headings of the Articles, Sections and Service Schedules of this Agreement are used for convenience only, and shall not modify or restrict any of the terms and provisions thereof.
 
12.7  Notice
 
 
Any notice or demand for performance required or permitted under any of the provisions of this Agreement shall be deemed to have been given on the date such notice, in writing, is deposited in the U.S. mail, postage prepaid, certified or registered mail, addressed to t he Parties
 
 
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at their principal place of business at 1 Riverside Plaza, Columbus, Ohio 43215, or in such other form or to such other address as the Parties may stipulate.
 
12.8  Effect on Other Agreements
 
 
This Agreement supersedes and replaces the Restated and Amended Operating Agreement among PSO, SWEPCO and AEPSC issued on February 2, 2009, effective as of the date this Agreement becomes effective as set out in Section 2.1.
 
12.9  Interpretation
 
 
In this Agreement: (a) unless otherwise specified, references to any Article, Section or Service Schedule are references to such Article, Section or Service Schedule of this Agreement; (b) the singular includes the plural and the plural includes the singular; (c) unless otherwise specified, each reference to a requirement of any governmental entity or regional transmission organization includes all provisions amending, modifying, supplementing or replacing such governmental entity or regional transmission organization from time to time; (d) the words “including,” “includes” and “include” shall be deemed to be followed by the words “without limitation”; (e) unless otherwise specified, each reference to any agreement includes all amendments, modifications, supplements, and restatements made to such agreement from time to time which are not prohibited by this Agreement; (f)  the descriptive headings of the various Articles, Sections and Service Schedules of this Agreement have been inserted for convenience of reference only and shall in no way modify or restrict the terms and provisions thereof; and (g) “herein,” “hereof,” “hereto” and “hereunder” and similar terms refer to this Agreement as a whole.
 
 
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ARTICLE XIII
REGULATORY APPROVAL
 
13.1  Regulatory Authorization
 
 
This Agreement is subject to and conditioned upon its approval or acceptance for filing without material condition or modification by the Commission. In the event that this Agreement is not so approved or accepted for filing in its entirety or without conditions or modifications unacceptable to any Party, or the Commission subsequently modifies this Agreement upon complaint or upon its own initiative (as provided for in Section 13.2), any Party may, irrespective of the notice provisions in Section 2.1, withdraw from this Agreement by giving thirty (30) days’ advance written notice to the other Parties.
 
13.2  Changes
 
 
It is contemplated by the Parties that it may be appropriate from time to time to change, amend, modify, or supplement this Agreement, including the Service Schedules and any other attachments that may be made a part of this Agreement, to reflect changes in operating practices or costs of operations or for other reasons. Any such changes to this Agreement shall be in writing executed by the Parties and subject to approval or acceptance for filing by the Commission.
 
IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed and attested by their duly authorized officers on the day and year first above written.

PUBLIC SERVICE COMPANY OF OKLAHOMA
 
By    /s/ J. Stuart Solomon
Name:  J. Stuart Solomon
 Title:   President

 
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SOUTHWESTERN ELECTRIC POWER COMPANY
 
By   /s/ Venita McCellon-Allen
Name:  Venita McCellon-Allen
      Title:    President

 
AMERICAN ELECTRIC POWER SERVICE CORPORATION
 
By   /s/ Richard E. Munczinski
Name:  Richard E. Munczinski
     Title:   Senior Vice President
 
 
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SCHEDULE A
POOL ENERGY
 
14.1 Duration
 
 
       This Service Schedule A shall become effective and binding when the Agreement o f which it is a part becomes effective, and shall continue in full force and effect throughout the duration of the Agreement unless terminated or suspended.
 
14.2 P urpose
 
 
       This Schedule provides the basis for determining payments and receipts among the Operating Companies for Pool Energy exchanges.
 
14.3 Receipts and Payments
 
 
       A selling Operating Company shall receive from a purchasing Operating Company one hundred and ten percent (110%) of the Seller's Incremental Energy Cost for Pool Energy sold.
 
A purchasing Operating Company shall pay for Pool Energy received one hundred and ten percent (110%) of the Seller's Incremental Cost for Pool Energy.

 
 
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SCHEDULE B
DISTRIBUTION OF BENEFITS AND COSTS OF OFF-SYSTEM SALES AND PURCHASES
 
15.1 Duration
 
 
This Service Schedule B shall become effective and binding when the Agreement of which it is a part becomes effective, and shall continue in full force and effect throughout the duration of the Agreement unless terminated or suspended.
 
15.2 Purpose
 
 
This schedule establishes the basis for distributing among the Operating Companies (i) the revenues and costs associated with off-System purchases and sales of energy, capacity and other wholesale products and services and (ii) other benefits and costs not otherwise assigned or allocated by this Agreement, including amounts allocated to the Operating Companies pursuant to the SIA, if any.  “SIA” means the System Integration Agreement entered into among the operating companies of American Electric Power Company, Inc. in connection with the merger approved by the Commission in American Electric Power Company and Central and South West Corporation, Opinion No. 442, 90 FERC  ¶ 61,242, Order on Rehearing , Opinion No. 442-A, 91 FERC ¶ 61,129 (2000).
 
15.3 Direct Assignment
 
 
The revenues and costs associated with off-System purchases and sales of energy, capacity and other wholesale products and services initiated at the direction of an Operating Company will be directly assigned to that Operating Company whenever reasonably possible.  The revenues and costs associated with serving an Operating Company’s Load, including the purchase of any energy deficits or sales of any energy surpluses in the markets
 
 
25

 
of the applicable regional transmission organization, will be directly assigned to that Operating Company.
 
15.4 System Participation
 
 
The revenues and costs of off-System purchases and sales of energy, capacity and other wholesale products and services not directly assigned to an Operating Company pursuant to Section 15.3 shall be allocated among the Operating Companies in proportion to the relative magnitude of each Operating Company of the energy generated (net exports) or not generated (net imports) by such Operating Company.
 
15.5 Other Distributions
 
 
Revenues and costs incurred during any month other than those allocated to the Operating Companies pursuant to Sections 15.3 and 15.4, including benefits and costs allocated pursuant to Schedule D of the SIA, if any, shall be allocated among the Operating Companies ratably in proportion to the ratio of an Operating Company’s maximum demand in effect for the relevant month to the sum of both Operating Companies’ maximum demands in effect for that month.  The maximum demand in effect for any month for a particular Operating Company is the maximum demand experienced by said Operating Company during the twelve consecutive months next preceding that month.
 
 
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SCHEDULE C
CAPACITY COMMITMENT CHARGE
 
16.1 Duration
 
 
This Service Schedule C shall become effective and binding when the Agreement of which it is a part becomes effective, and shall continue in full force and effect throughout the duration of the Agreement unless terminated or suspended.
 
16.2 Purpose
 
 
   This Schedule establishes the basis for Capacity Commitments between the Operating Companies and the rates for the Capacity Commitment Charge and associated energy.
 
16.3 Basis for Capacity Commitment
 
 
Either Operating Company may make available the other Operating Company unit capacity consisting of a portion of the output of one or more specific Generating Units owned or controlled by the committing Operating Company.  The receiving Operating Company shall be entitled to receive energy from the specified Generating Unit(s) up to an amount equal to the actual availability of that Generating Unit or such other amount as is mutually agreeable.  The capacity commitment shall be for a twelve month period or as otherwise mutually agreed.
 
16.4 Provisions for Capacity Commitment Charge
 
 
             The monthly Capacity Commitment Charge for each specific Generating Unit(s) from which capacity is committed shall be determined pursuant to the following formula:

      A =       (1/12) (B) (C/D) (E)

Where:

 
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A =
Monthly Capacity Commitment Charge for the specified unit to be due each month regardless of the availability of the specific unit.

 
B =
0.1772 (fixed charge rate for the committing Operating Company).

 
C =
Committing Operating Company's total dollar investment, at original cost, in the specific Generating Unit as of December 31 of the year prior to the year of the Capacity Commitment.

 
D =
Rated net dependable capability of the specific Generating Unit in megawatts.

 
E =
Megawatts of capacity committed from the specified unit.

 
16.5 Provision for Energy Charge
 
 
The rate for energy received by a receiving Operating Company from the specified Generating Unit(s) shall be the Variable Cost of energy produced for the specified Generating Unit(s) plus ten (10) percent of those costs or three (3) mills per kilowatt hour, whichever is less.

 
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SCHEDULE D
CAPACITY COMMITMENT UNITS
 
17.1 Duration
 
This Service Schedule D shall become effective and binding when the Agreement of which it is a part becomes effective, and shall continue in full force and effect throughout the duration of the Agreement unless terminated or suspended.
 
17.2 Purpose
 
This Schedule identifies the Generating Units of the Operating Companies from which Capacity Commitments shall be made pursuant to Section 7.3 and with reference to which the Capacity Commitment Charge shall be determined in accordance with Schedule C.
 
17.3 Commitment Units
 
Listed below are the Generating Units from which each of the Operating Companies shall commit Capacity to other Operating Companies pursuant to Section 7.3.  Capacity Commitments shall be made from the first listed unit of the committing Operating Company unless or to the extent that the Generating Unit is not expected to be available during the commitment period.  In that event, Capacity Commitments shall be made from the second listed unit of the committing Operating Company.

 
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OPERATING COMPANY/
UNIT NAME
 
RATING
(MW)
YEAR
INSTALLED
PSO
   
   Riverside #2
465
1976
   Riverside #1
457
1974
SWEPCO
   
   Knox Lee #5
344
1974
   Wilkes #3
351
1971


 
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Exhibit 10(c)
 
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
       
  American Electric Power Service  )  Docket No. ER09-1279-000
  Corporation  )  
 
SETTLEMENT AGREEMENT

Pursuant to Rule 602 of the Rules of Practice and Procedure of the Federal Energy Regulatory Commission (“Commission”), 18 C.F.R. §385.602 (2008), American Electric Power Service Corporation (“AEPSC”),   on behalf of Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Kingsport Power Company, Ohio Power Company, and Wheeling Power Company (collectively “AEP” or the “AEP East Companies”) and certain entities that have intervened in this proceeding as indicated below (individually, a “Settling Party” and together, “Settling Parties”) hereby submit this Settlement Agreement to resolve all issues between and among them in this docket. In addition, this Settlement is supported or not opposed by all parties who have intervened in this proceeding, except Steeel Dynamics, Inc. and Kentucky Public Service Commission who take no position with respect to the Settlement 1 .



 
______________________________
1 In addition to the Settling Parties, the non-opposing parties are Consumer Advocate Division of the Public Service Commission of West Virginia, Virginia State Corporation Commission, Old Dominion Committee for Fair Utility Rates, Public Service Commission of West Virginia, Indiana Utility Regulatory Commission, Indiana Office of Utility Consumer Counsel and the West Virginia Energy Users Group.
 
 

 
ARTICLE I

INTRODUCTION

AEP is a multi-state electric utility holding company system, whose operating companies provide electric service to approximately five million customers in parts of eleven states.  Prior to 2000, when AEP merged with the former Central and South West System, AEP consisted of seven electric utility operating companies.  The five largest companies operate generation, transmission and distribution facilities and are parties to the Transmission Agreement.  The two smaller companies – Kingsport Power Company (“Kingsport”) and Wheeling Power Company (“Wheeling”) operate only transmission and distribution facilities.  These seven AEP operating companies provide electric service to customers in parts of seven states – Indiana, Kentucky, Michigan, Ohio, Tennessee, Virginia and West Virginia.  AEPSC provides management and professional services at cost to these companies and others in the AEP System.
 
AEP represented in its filing in this case that the AEP System is planned and operated on an integrated basis pursuant to various agreements under which the AEP operating companies pool or combine their power supply and delivery facilities to achieve the benefits of integrated operation.  This proceeding involves proposed amendments to one such agreement -- the Transmission Agreement entered into in 1984 among five of the AEP East Companies- Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company and Ohio Power Company, and administered by AEPSC, as Agent .   As
 
 
 

 
approved by the Commission, 2 the Agreement shares the costs of the Members’ investments in Extra-High-Voltage (EHV) and high-voltage facilities operated at 138 kilovolts (138 kV) and  above.
 
On June 5, 2009 AEP filed with the Commission proposed amendments to the Transmission Agreement.  The proposed amendments to the Transmission Agreement would effect a comprehensive reallocation of transmission-related costs and revenues among the AEP East Companies including two new Members, Kingsport Power Company and Wheeling Power Company.  The proposed amendments recognized that, pursuant to the PJM Open Access Transmission Tariff (“PJM OATT”), the AEP East Companies, including Kingsport and Wheeling, and other load serving entities in the AEP zone of PJM now share the cost of all the AEP East Companies transmission facilities, including those operated at voltages below 138 kV.  The proposed amendments also change the cost allocation methodology from the Member Load Ratio (“MLR”) method currently used to a 12-month coincident peak (12-CP) method.  The proposed amendments also address the allocation of OATT-based transmission and related costs and revenues among all seven of the AEP East Companies.  Motions to intervene in this proceedings were filed by the following entities: Public Utilities Commission of Ohio, Public Utilities Commission of West Virginia, West Virginia Energy Users Group 3 ,  Virginia State Corporation Commission, Old Dominion Committee for Fair Utility Rates, East Tennessee Energy Consumers, Indiana Utility Regulatory Commission (“IURC”), Steel Dynamics, Inc. (“Steel Dynamics”), Consumer Advocate Division of the Public Service Commission of West Virginia (W.Va. Consumer Advocate”), Hoosier Energy
 
 
__________________________________
2 American Electric Power Service Corp .,   Opinion No. 311, 44 FERC ¶ 61,206 (1987), reh. denied , Opinion No. 311-A, 45 FERC ¶ 61,382 (1988)  
3 West Virginia Energy Users Group consists of the following entities: [list]
 
 

 
Rural Electric Cooperative, Indiana Office of Utility Consumer Counsel (“IOUCC”), Ohio Consumers’ Counsel, and the Kentucky Public Service Commission.
 
IURC, Steel Dynamics, W. Va Consumer Advocate and IOUCC protested AEP’s filing, and AEP answered their protests. On August 3, 2009 the Commission issued an order accepting AEP’s proposed amendments to the Transmission Agreement for filing, subject to hearing and settlement judge procedures.  The Commission suspended the proposed amendments for a nominal period, making them effective (subject to refund), on the first day of the month after a final Commission order in this proceeding, as requested by AEP. Order Accepting and Suspending Proposed Transmission Agreement and Establishing Hearing and Settlement Judge Procedures , 128 FERC ¶ 61,123 (2009).
 
On August 7, 2009, pursuant to an order of Chief Judge Wagner, The Honorable David Coffman was appointed Settlement Judge.  The Chief Judge’s August 7, 2009 order also scheduled a settlement conference to convene on August 20, 2009.  Settlement negotiations (including informal information gathering and numerous conferences, meetings and telephone conversations) continued since then.  The Commission’s Trial Staff participated actively in the discussions.  Judge Coffman submitted periodic reports to the Commission on the progress of the settlement discussions.  Ultimately, the settlement discussions produced this Settlement Agreement.
 
ARTICLE II
SCOPE OF SETTLEMENT AGREEMENT

The Settling Parties hereby settle and resolve all issues between them arising from AEP’s submittals in Docket No. ER09-1279-000, on the terms set forth in the following Article III and Attachments A, B-1 and B-2.  Attachments A, B-1 and B-2 are incorporated by reference in and made a part of this Settlement Agreement, and all
 
 
 

 
references herein to the Settlement Agreement shall be deemed to encompass the listed Attachments.
 
ARTICLE III
TERMS OF THE SETTLEMENT AGREEMENT

3.1         The Settlement Terms and Conditions set forth in Attachment A describe the agreement of the Settling Parties regarding the implementation of the Revised Transmission Agreement.
 
3.2         Revised tariff provisions for the Transmission Agreement are set forth in  Attachment B-1 (Blacklined) and B-2 (Clean) to this Settlement Agreement.  The provisions submitted herewith shall be substituted for the tariff pages accepted for filing, subject to refund, in the Commission’s August 3, 2009 in this Docket.  The Settling Parties request that the Commission accept the tariff pages set forth in Attachment B for filing without suspension, investigation, change or condition.
 
ARTICLE IV
IMPLEMENTATION
 
4.1         This Settlement Agreement shall be binding as among the Settling Parties upon the execution hereof.  The revised tariff sheets and other provisions set forth in the Attachments hereto shall become effective on the date the Commission specifies as the effective date for the agreed-upon rates and charges in its order approving or accepting the Settlement Agreement.  The Settling Parties shall request that the Commission permit the agreed-upon rates and charges become on the first day of the month after a final Commission order in this proceeding.
 
4.2         This Settlement Agreement shall be null and void and shall not become effective unless: (i) the Commission approves it without condition or modification as a
 
 
 

 
complete settlement of the issues described herein, or (ii) the Settling Parties are willing to accept all such conditions and modifications as the Commission may require.  Any Settling Party that does not notify the other Settling Parties, within 15 days of a Commission order imposing any condition or modification to the Settlement Agreement, that it may or will seek rehearing or reconsideration of the order shall be deemed to have waived all objections thereto.

ARTICLE V
NON-SEVERABILITY
 
This Settlement Agreement and its Attachments establish rights and obligations that are interrelated and interdependent.  No Settling Party shall be deemed to have agreed to any term of the Settlement Agreement in isolation from any other term.  For these reasons, the provisions of this Settlement Agreement are not severable.
 
ARTICLE VI
RESERVATIONS

6.1         The provisions of this Settlement Agreement are intended to govern only  the specific matters addressed herein.  No Settling Party waives any claim or right that it may have with respect to matters not addressed in this Settlement Agreement.
 
6.2         No Settling Party shall be bound or prejudiced by this Settlement Agreement unless it is approved and made effective pursuant to its terms.
 
6.3         Nothing in this Settlement Agreement shall constitute an admission by any Settling Party of the correctness or applicability of any claim, defense, rule, or interpretation of law, allegation of fact, principle, or method of ratemaking or cost-of-service determination.  The Settlement Agreement is made upon the explicit understanding that it constitutes a negotiated agreement with respect to the rates, terms,
 
 
 

 
and conditions at issue in these proceedings.  The Settling Parties shall not be deemed to have conceded the applicability of any principle, or any method of ratemaking or cost-of-service determination, rate design or rate schedule, or terms and conditions of service; or the application of any rule or interpretation of law that may underlie, or be thought to underlie, this Settlement Agreement.  The Cost of Service and Formula Rate Settlement Principles contained in Attachment A are principles that the Settling Parties shall be deemed to have accepted solely for purposes of resolving the issues in this docket, and their inclusion as part of this Settlement Agreement shall not (i) constitute an admission by any Settling Party of the correctness of any principle therein, or (ii) establish any precedent binding on a Settling Party in any other proceeding.  In any further negotiation or proceedings whatsoever (other than a proceeding involving the honoring, enforcement or construction hereof, as applicable as set forth herein), the Settling Parties shall not be bound or prejudiced by this Settlement Agreement.
 
6.4         The Commission’s approval of this Settlement Agreement shall not constitute approval of, or precedent regarding, any principle or issue in this proceeding.  Nothing herein shall be deemed to constitute or establish a “settled practice” as the Court interpreted that term in Public Service Comm’n of New York v. FERC , 642 F.2d 1335 (D.C. Cir. 1980).
 
6.5         This Settlement Agreement is expressly contingent upon the following further conditions: (i) all Settling Parties shall provide reasonable cooperation in seeking the Commission’s acceptance and approval hereof; (ii) no Settling Party shall seek or request additional terms or conditions of settlement beyond those contained herein; and (iii) the Commission approves or accepts this Settlement Agreement without
 
 
 

 
modification.  If the Commission requires any modification(s) of this Settlement Agreement and if such modification(s) is (are) not fulfilled, then:  (i) this Settlement Agreement shall not be binding on any Settling Party; (ii) the Settling Parties shall not be obligated to negotiate further, other than to discuss in good faith whether the modification(s) required by the Commission is (are) acceptable to them; (iii) all Settling Parties shall be deemed to have reserved all of their respective rights and remedies with respect to the issues in this proceeding; and (iv) this Settlement Agreement shall not be part of the record in any subsequent proceedings, and all discussions and negotiations related hereto shall be privileged.
 
6.6         The titles and headings of the various articles of this Settlement Agreement: (i) are for reference and convenience purposes only; (ii)  are not to be construed or taken into account in interpreting the Settlement Agreement; and (iii) do not qualify, modify, or explain the effects of the Settlement Agreement.
 
6.7         This Settlement Agreement may be amended only by a written instrument duly executed by all Settling Parties.  The standard of review for any modification to this Settlement Agreement sought by a Settling Party that is not agreed to by all other Settling Parties shall be the “just and reasonable” standard.   [DISCUSS] A Settling Party or Settling Parties seeking to modify the Formula Rate in any respect shall bear the applicable burden under the FPA.
 
6.8         The standard of review for any modifications to this Settlement Agreement requested by an intervenor or other interested entity that is not a Settling Party or that is sought in a proceeding initiated by the Commission acting sua sponte will be the most stringent standard permissible under applicable law. For purposes of the application of
 
 
 

 
sections 6.7 and 6.8, all parties who have formally represented in writing, by their respective authorized representative, that they did not object to the Agreement shall be treated as “Settling Parties.”
 
6.9         This Settlement Agreement is submitted pursuant to Rule 602 of the Commission’s Rules of Practice and Procedure, 18 C.F.R. §385.602 (2008).  Unless and until the Settlement Agreement becomes effective pursuant to its terms, the Settlement Agreement shall be privileged and of no effect and shall not be admissible in evidence or in any way described or discussed in any proceeding before any court or regulatory body (except in comments on the Settlement Agreement in this proceeding).
 
 
 

 

American Electric Power Service
Corporation as agent for
Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Kingsport Power Company, Ohio Power Company, and Wheeling Power Company

 By : /s/  Monique Rowtham-Kennedy
Monique Rowtham-Kennedy
American Electric Power Service Corporation
801 Pennsylvania Avenue, N.W.
Suite 320
Washington, D.C. 20004-2684
Telephone: 202-383-3436
            Fax: 202-383-3459

Counsel for American Electric Power Service Corporation


By:   /s/ Jody Kyler
Jody Kyler
Assistant Consumers’ Counsel
Office of the Ohio Consumers’ Counsel
10 W. Broad St.  Suite 1800
Columbus, Ohio 43215
Phone:  (614) 466-9601

Counsel for the Office of the Ohio Consumers’ Counsel


 
By:   /s/ Stephen Reilly
Stephan Reilly
Thomas G. Lindgren
Assistant Attorney General
Public Utilities Section
Ohio Attorney General’s Office
180 East Broad St.
Columbus, Ohio 43215

By:   /s/ Edward L. Petrini
Christian & Barton LLP
Attorneys at Law
909 East Main Street, Suite 1200
Richmond, Virginia  23219
804.697.4135 tel

Counsel for East Tennessee Energy Consumers

 
 

 
By:   /s/ Barry Cohen
Barry Cohen
Miller, Balis & O’Neil, P.C.
1015 15 th St., NW, 12 th Floor
Washington, D.C.  20005
(202) 296-2960

Counsel for Hoosier Energy Rural Electric Cooperative

The following undersigned entities are not parties to the Settlement Agreement, however the undersigned indicate by their signature below that they do not object to this  Settlement Agreement:


Public Service Commission of West Virginia,

By:   /s/ Richard E. Hitt
Richard E. Hitt, General Counsel
Public Service Commission of West Virginia
Post Office Box 812
Charleston, West Virginia 25323
Phone: (304) 340-0450

West Virginia Energy Users Group,

By:   /s/ Robert A. Weishaar, Jr.
Robert A. Weishaar, Jr.
McNeews Wallace & Nurick LLC
777 North Capitol Street, NE
Washington, DC 20002-4293
Office: 202.409.4170

Indiana Office of Utility Consumer Counsel,

By:   /s/ Robert G. Mork
Robert G. Mork
Deputy Consumer Counselor for Federal Affairs
Indiana Attorney No. 19146-49
INDIANA OFFICE OF UTILITY CONSUMER COUNSELOR
115 West Washington Street, Suite 1500 South
Indianapolis, Indiana  46204
Phone (317) 233-3234

 
 

 
 
ATTACHMENT A

American Electric Power Service Corporation
Docket No. ER09-1279-000

Transmission Agreement Settlement
For
Appalachian Power Company, Columbus Southern Power Company, Indiana
Michigan Power Company, Kentucky Power Company, Kingsport Power Company,
Ohio Power Company, and Wheeling Power Company
(collectively “AEP” or “the AEP East Companies”)


Settlement Terms and Conditions


The following terms and conditions are a part of the Settlement Agreement being filed August 4, 2010 in Docket No. ER09-1279 (“the Settlement”):


1.  
AEP’s proposal as originally filed in the captioned docket and accepted and suspended subject to hearing and settlement judge procedures pursuant to American Elec. Power Serv. Corp , 128 FERC ¶ 61,123 ( 2009) (hereinafter referred to as the “Revised Transmission Agreement”) will be implemented upon approval of the Settlement, subject to the terms and conditions contained herein.

2.  
Impacts of the Revised Transmission Agreement will for retail rate making purposes be moderated as described in paragraphs 3 and 4, below, for a three (3) year period commencing on the of the Commission order approving the Settlement and ending no later than July 31, 2013 for all of the AEP East Companies except Indiana Michigan Power Company.

3.  
Credits will be applied to Ohio Power Company, Columbus Southern Power Company and Appalachian Power Company -West Virginia to reduce impacts of the Revised Transmission Agreement by 75% in year 1, by 50% in year 2 and by 25% in year 3.

4.  
Charges will be applied to Kentucky Power Company, Kingsport Power Company and Wheeling Power Company to reduce the decrease in transmission cost allocation under the Revised Transmission Agreement by 75% in year 1, by 50% in year 2 and by 25% in year 3.

 
 

 
5.  
Impacts of the Revised Transmission Agreement on Indiana Michigan Power Company will be phased in over a four year period commencing on the effective date of the Settlement and ending no later than July 1, 2014.

6.  
Credits to Indiana Michigan will reduce impacts of the Revised Transmission Agreement by 80% in year 1, 60% in year 2, 40% in year 3 and 20% in year 4.

7.  
All parties to the Settlement reserve their respective rights under sections 205, 206 and 306 of the Federal Power act, however, the Settlement will be voided if a filing is made under 206 challenging the Revised Transmission Agreement or this Settlement.  In addition while the Settelment is in effect, AEP will not modify Appendix 1 of the Revised Transmission Agreement unless such 206 filing is made by a non-AEP settling party.

8.  
AEP shall not seek recovery of any shortfall of revenues resulting from the application of the terms and conditions of this Settlement Agreement in any Ohio state regulatory proceeding, except as provided for in the Settlement.

9.  
The Transmission Agreement will be modified as provided in Attachment B.

10.  
The credits and charges pursuant to paragraphs 3, 4 and 6 above shall be as follows:


 
Year 1
Year 2
Year 3
Year 4
   
(Dollars  
  in Millions)
 
APCo WV
(6.9)
(4.6)
(2.3)
0
CSP
(2.4)
(1.6
(0.8)
0
I&M
(24.1)
(18.1)
(12.1)
(6.0)
KPCo
3.1
2.1
1.1
0
KgPCo
3.0
2.0
1.0
0
OPCo
(10.9)
(7.3)
(3.6)
0
WPCo
1.9
1.2
0.6
0
Exhibit 10(s)
 
AMERICAN ELECTRIC POWER SERVICE CORPORATION

CHANGE IN CONTROL AGREEMENT

As Revised Effective January 1, 2014

Whereas, American Electric Power Service Corporation, a New York corporation, including any of its subsidiary companies, divisions, organizations, or affiliated entities (collectively referred to as “AEPSC”) considers it essential to its best interests and the best interests of the shareholders of the American Electric Power Company, Inc., a New York corporation, (hereinafter referred to as “Corporation”) to foster the continued employment of key management personnel; and

Whereas, the uncertainty attendant to a Change In Control of the Corporation may result in the departure or distraction of management personnel to the detriment of AEPSC and the shareholders of the Corporation; and

Whereas, the Board of the Corporation has determined that steps should be taken to reinforce and encourage the continued attention and dedication of members of AEPSC’s management to their assigned duties in the event of a Change In Control of the Corporation; and

Whereas, AEPSC therefore previously established the American Electric Power Service Corporation Change In Control Agreement (the “Agreement”), the most recent version of which was set forth in a document dated effective January 1, 2013; and

Whereas, the Human Resources Committee of the Board of the Corporation has directed that the tax gross-up provisions be be left out of the Agreement;

Now, Therefore, AEPSC hereby amends the Agreement in its entirety.


ARTICLE I
DEFINITIONS

As used herein the following words and phrases shall have the following respective meanings unless the context clearly indicates otherwise.

(a)  “Anniversary Date” means January 1 of each Calendar Year.

(b)  “Annual Compensation” means the sum of the Executive’s Annual Salary and the Executive’s Target Annual Incentive.

(c)  “Annual Salary” means the Executive’s regular annual base salary immediately prior to the Executive’s Termination of employment, including compensation converted to other benefits under a flexible pay arrangement maintained by
 
 
 

 
AEPSC or deferred pursuant to a written plan or agreement with AEPSC, but excluding sign-on bonuses, allowances and compensation paid or payable under any of AEPSC’s long-term or short-term incentive plans or any similar payments, and any salary lump sum amount paid in lieu of or in addition to a base wage or salary increase.

(d)  “Board” means the Board of Directors of American Electric Power Company, Inc.

(e)  “Calendar Year” means the twelve (12) month period commencing each January 1 and ending each December 31.

(f)  “Cause” shall mean

(i) the willful and continued failure of the Executive to perform substantially the Executive’s duties with AEPSC (other than any such failure as reasonably and consistently determined by the Board to have resulted from incapacity due to physical or mental illness), after a written demand for substantial performance is delivered to the Executive by the Board or an elected officer of AEPSC which specifically identifies the manner in which the Board or the elected officer believes that the Executive has not substantially performed the Executive’s duties, or

(ii) the willful conduct or omission by the Executive, which the Board determines to be illegal or gross misconduct that is demonstrably injurious to AEPSC or the Corporation; or a breach of the Executive’s fiduciary duty to AEPSC or the Corporation, as determined by the Board.

For purposes of this provision, no act or failure to act, on the part of the Executive, shall be considered “willful” unless it is done, or omitted to be done, by the Executive in bad faith or without reasonable belief that the Executive’s action or omission was in the best interests of AEPSC or the Corporation.  Any act, or failure to act, based upon authority given pursuant to a resolution duly adopted by the Board or upon the advice of counsel for AEPSC or the Corporation, shall be conclusively presumed to be done, or omitted to be done, by the Executive in good faith and in the best interests of AEPSC or the Corporation

(g)  “Change In Control” of the Corporation shall be deemed to have occurred if and as of such date that (i) any “person” or “group” (as such terms are used in Section 13(d) and 14(d) of the Securities Exchange Act of 1934 (“Exchange Act”)), other than AEPSC, any company owned, directly or indirectly, by the shareholders of the Corporation in substantially the same proportions as their ownership of stock of the Corporation or a trustee or other fiduciary holding securities under an employee benefit plan of the Corporation, becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than one third of the then outstanding voting stock of the Corporation; or (ii) the consummation of a merger or consolidation of the Corporation with any other entity, other than a merger or consolidation which would
 
 
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result in the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least two-thirds of the total voting power represented by the voting securities of the Corporation or such surviving entity outstanding immediately after such merger or consolidation; or (iii) the consummation of the complete liquidation of the Corporation or the sale or disposition by the Corporation (in one transaction or a series of transactions) of all or substantially all of the Corporation’s assets.

(h)  “CIC Multiple” means a factor of (i) two and ninety-nine one-hundredths (2.99) with respect to the Chief Executive Officer of American Electric Power Service Corporation and such other Executives who are nominated for such factor by the Chief Executive Officer of American Electric Power Service Corporation and approved by the Human Resources Committee of the Board of the Corporation; or (ii) two (2.00) with respect to all other Executives.

(i)  “Code” means the Internal Revenue Code of 1986, as amended from time to time.

(j)  “Commencement Date” means January 1, 2012, which shall be the beginning date of the term of this Agreement.

(k)  “Disability” means the Executive’s total and permanent disability as defined in AEPSC’s long-term disability plan covering the Executive immediately prior to the Change In Control.

(l)  “Executive” means an employee of AEPSC or the Corporation who is designated by AEPSC and approved by the Human Resources Committee of the Board of the Corporation as an employee entitled to benefits, if any, under the terms of this Agreement.

(m)  “Good Reason” means

(1) an adverse change in the Executive’s status, duties or responsibilities as an executive of AEPSC as in effect immediately prior to the Change In Control;

(2) failure of AEPSC to pay or provide the Executive in a timely fashion the salary or benefits to which the Executive is entitled under any employment agreement between AEPSC and the Executive in effect on the date of the Change In Control, or under any benefit plans or policies in which the Executive was participating at the time of the Change In Control;

(3) the reduction of the Executive’s base salary as in effect on the date of the Change In Control;

 
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(4) the taking of any action by AEPSC (including the elimination of a plan without providing substitutes therefor, the reduction of the Executive’s awards thereunder or failure to continue the Executive’s participation therein) that would substantially diminish the aggregate projected value of the Executive’s awards or benefits under AEPSC’s benefit plans or policies in which the Executive was participating at the time of the Change In Control; provided, however, that the diminishment of such awards or benefits that apply to other groups of employees of AEPSC in addition to Executives covered by this or a similar agreement shall be disregarded;

(5) a failure by AEPSC or the Corporation to obtain from any successor the assent to this Agreement contemplated by Article IV hereof; or

(6) the relocation, without the Executive’s prior approval, of the office at which the Executive is to perform services on behalf of AEPSC to a location more than fifty (50) miles from its location immediately prior to the Change In Control.

Any circumstance described in this Article I(m) shall constitute Good Reason even if such circumstance would not constitute a breach by AEPSC of the terms of an employment agreement between AEPSC and the Executive in effect on the date of the Change In Control.  However, such circumstance shall not constitute Good Reason unless (i) within ninety (90) days of the initial existence of such circumstance, the Executive shall have given AEPSC written notice of such circumstance, and (ii) AEPSC shall have failed to remedy such circumstance within thirty (30) days after its receipt of such notice.  Such written notice to be provided by the Executive to AEPSC shall specify (A) the effective date for the Executive’s proposed Termination of employment (provided that such effective date may not precede the expiration of the period for AEPSC’s opportunity to remedy), (B) reasonable detail of the facts and circumstances claimed to provide the basis for Termination, and (C) the Executive’s belief that such facts and circumstance would constitute Good Reason for purposes of this Agreement.  The Executive’s continued employment shall not constitute consent to, or a waiver of rights with respect to, any circumstances constituting Good Reason hereunder.

 
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(n)  “Qualifying Termination” shall mean following a Change In Control and during the term of this Agreement the Executive’s employment is Terminated for any reason excluding (i) the Executive’s death, (ii) the Executive’s Disability, (iii) the exhaustion of the Executive’s benefits under the terms of an applicable AEPSC sick pay plan or long-term disability plan (other than by reason of the amendment or termination of such a plan), (iv) the Executive’s Retirement, (v) by AEPSC for Cause or (vi) by the Executive without Good Reason.  In addition, a Qualifying Termination shall be deemed to have occurred if, prior to a Change In Control, the Executive’s employment was Terminated during the term of this Agreement (A) by AEPSC without Cause, or (B) by the Executive based on events or circumstances that would constitute Good Reason if a Change in Control had occurred, in either case, (x) at the request of a person who has entered into an agreement with AEPSC or the Corporation, the consummation of which would constitute a Change In Control or (y) otherwise in connection with, as a result of or in anticipation of a Change In Control.  For purposes of this Article I(o), (1) the mere act of approving a Change In Control agreement shall not in and of itself be deemed to constitute an event or circumstance in anticipation of a Change In Control, and (2) if an Executive’s level of services decreases to 50% or less of the average level of service performed during the previous 36-month period but does not completely end, such decrease shall not, of itself, be considered a Qualifying Termination, but may, under appropriate circumstance be taken into account in determining whether the Executive has Good Reason for Terminating employment, provided that if the Executive fails to establish that such decrease constitutes Good Reason for purposes of this Agreement, any subsequent termination of the Executive’s employment shall not be considered a Qualifying Termination.

(o)  “Retirement” shall mean an Executive’s voluntary Termination of employment after attainment of age 55 with five or more years of service with AEPSC without Good Reason.

(p)  “Target Annual Incentive” shall mean the award that the Executive would have received under the annual incentive compensation plan applicable to such Executive for the year in which the Executive’s Termination occurs, if one hundred percent (100%) of the annual target award has been earned.  Executives not participating in an annual incentive compensation plan that has predefined target levels will be treated as though they were participants in an annual incentive plan with such targets and will be assigned the same annual target percent as their participating peers in a comparable salary grade.

(q)  “Taxable Year” shall mean the taxable year of the Executive for federal income tax purposes, unless the context clearly indicates that the taxable year of a different taxpayer was intended.

(r)  “Termination” means those circumstances considered to be a separation from service, determined in a manner consistent with the written policies adopted by the HR
 
 
5

 
Committee of the Corporation from time to time to the extent such policies are consistent with the requirements imposed under Code Section 409A(a)(2)(A)(i).
 
(s)  “Triggering Event” shall mean the event that triggered the Qualifying Termination (i.e., the Termination of the Executive’s employment or, if the Qualifying Termination is specified in Article I(o)(A) or (B), the Change in Control).


ARTICLE II
TERM OF AGREEMENT

2.1           The initial term of this Agreement shall be for the period beginning on the Commencement Date and ending on the December 31 immediately following the Commencement Date.  The term of this Agreement shall automatically be extended for an additional Calendar Year on the first Anniversary Date immediately following the initial term of this Agreement without further action by AEPSC, and shall be automatically extended for an additional Calendar Year on each succeeding Anniversary Date, unless AEPSC shall have served notice upon the Executive at least thirty (30) days prior to such Anniversary Date of AEPSC’s intention that this Agreement shall not be extended, provided, however, that if a Change In Control of the Corporation shall occur during the term of this Agreement, this Agreement shall terminate two years after the date the Change In Control is completed.

2.2           If an employee is designated as an Executive after the Commencement Date or after an Anniversary Date, the initial term of this Agreement shall be for the period beginning on the date the employee is designated as an Executive and ending on the December 31 immediately following.

2.3           Notwithstanding Section 2.1, the term of this Agreement shall end upon any Termination of the Executive’s employment that is other than a Qualifying Termination in connection with a Change In Control of the Corporation.  For example, this Agreement shall terminate if the Executive’s position is eliminated and the Executive’s employment is Terminated, other than in connection with a Change In Control of the Corporation, (i) due to a downsizing, consolidation or restructuring of AEPSC or of any other subsidiary of the Corporation   or (ii) due to the sale, disposition or divestiture of all or a portion of AEPSC or of any other subsidiary of the Corporation.


ARTICLE III
COMPENSATION UPON A QUALIFYING TERMINATION IN CONNECTION WITH A CHANGE IN CONTROL

3.1           Except as otherwise provided in Section 3.3, upon a Qualifying Termination, the Executive shall be under no further obligation to perform services for AEPSC and shall be entitled to receive the following payments and benefits:

 
6

 
 
(a)
As soon as practicable following the Executive’s date of Termination, AEPSC shall make a lump sum cash payment to the Executive in an amount equal to the sum of (1) the Executive’s Annual Salary through the date of Termination to the extent not theretofore paid, (2) the product of (x) the current plan year’s Target Annual Incentive and (y) a fraction, the numerator of which is the number of days in such calendar year through the date of Termination, and the denominator of which is 365, except that annual incentive plans which do not have predetermined annual target awards for participants shall have their pro-rated incentive compensation award for the current plan year paid as soon as practicable, and (3) any accrued vacation pay that otherwise would be available upon the Executive’s Termination of employment with AEPSC, in each case to the extent not theretofore paid and in full satisfaction of the rights of the Executive thereto; provided, however, in the case of a Qualifying Termination in the circumstances specified in Article I(o)(B), payment of the amount described in subsection (2) of this Section 3.1(a) shall not be made until immediately after the Change in Control event or circumstance; and

 
(b)
If the Executive timely satisfies the conditions set forth in Section 3.3, AEPSC shall make a lump sum cash payment to the Executive in an amount equal to the CIC Multiple times the Executive’s Annual Compensation. If the Qualifying Termination is specified in Article I(o) (A) or (B), no such lump sum payment shall be made unless and until the Change in Control related to the Qualifying Termination shall have occurred.  If any of the periods specified for timely satisfaction of the conditions set forth in Section 3.3 shall end in a Taxable Year that is different from the Taxable Year of the Triggering Event, the lump sum payment specified in this paragraph (b) shall not be made until the Taxable Year in which such period ends, provided that such payment shall be made no later than the 15 th day of the third month of that later Taxable Year.

3.2       The Executive shall be entitled to such outplacement services and other non-cash severance or separation benefits as may then be available under the terms of a plan or agreement to groups of employees of AEPSC in addition to Executives who are covered under the terms of this or a similar agreement.  See also section 3.3(b).  To the extent any benefits described in this Article III, Section 3.2 cannot be provided pursuant to the appropriate plan or program maintained by AEPSC, AEPSC shall provide such benefits outside such plan or program at no additional cost to the Executive.

3.3       Notwithstanding the foregoing,

 
(a)
The severance payments and benefits provided under Sections 3.1(a)(2), 3.1(b), and 3.2 hereof shall be conditioned upon the Executive executing a release within the period specified therein, but in no event later than sixty (60) days after the Triggering Event, in the form established by the
 
 
7

 
 
  Corporation or by AEPSC, releasing the Corporation, AEPSC and their shareholders, partners, officers, directors, employees and agents from any and all claims and from any and all causes of action of kind or character, including but not limited to all claims or causes of action arising out of Executive’s employment with the Corporation or AEPSC or the termination of such employment.
 
 
(b)
The severance payments and benefits provided under Sections 3.1(a)(2), 3.1(b), and 3.2 hereof shall be subject to, and conditioned upon, the timely waiver of any other cash severance payment or other benefits provided by AEPSC pursuant to any other severance agreement between AEPSC and the Executive.  Such waiver shall not be considered timely unless received by AEPSC within sixty (60) days after the Triggering Event. No amount shall be payable under this Agreement to, or on behalf of the Executive, if the Executive elects benefits under any other cash severance plan or program, or any other special pay arrangement with respect to the termination of the Executive’s employment.

 
(c)
The Executive agrees that at all times following Termination, the Executive will not, without the prior written consent of AEPSC or the Corporation, disclose to any person, firm or corporation any “confidential information,” of AEPSC or the Corporation which is now known to the Executive or which hereafter may become known to the Executive as a result of the Executive’s employment or association with AEPSC or the Corporation, unless such disclosure is required under the terms of a valid and effective subpoena or order issued by a court or governmental body; provided, however, that the foregoing shall not apply to confidential information which becomes publicly disseminated by means other than a breach of this provision.  It is recognized that damages in the event of breach of this Section 3.3(c) by the Executive would be difficult, if not impossible, to ascertain, and it is therefore agreed that AEPSC and the Corporation, in addition to and without limiting any other remedy or right that AEPSC or the Corporation may have, shall have the right to an injunction or other equitable relief in any court of competent jurisdiction, enjoining any such breach, and the Executive hereby waives any and all defenses the Executive may have on the ground of lack of jurisdiction or competence of the court to grant such an injunction or other equitable relief.  The existence of this right shall not preclude AEPSC or the Corporation from pursuing any other rights or remedies at law or in equity which AEPSC or the Corporation may have.

 
“Confidential information” shall mean any confidential, propriety and or trade secret information, including, but not limited to, concepts, ideas, information and materials relating to AEPSC or the Corporation, client records, client lists, economic and financial analysis, financial data, customer contracts, marketing plans, notes, memoranda, lists, books,
 
 
8

 
 
   correspondence, manuals, reports or research, whether developed by AEPSC or the Corporation or developed by the Executive acting alone or jointly with AEPSC or the Corporation while the Executive was employed by AEPSC.
 
3.4           The obligations of AEPSC to pay the benefits described in Sections 3.1, and 3.2 shall, subject to Section 3.3, be absolute and unconditional and shall not be affected by any circumstances, including, without limitation, any set-off, counterclaim, recoupment, defense or other right which AEPSC may have against the Executive; provided, however, AEPSC shall comply with and enforce obligations of AEPSC or the Executive under law determined by AEPSC to be applicable, including any withholding in order to comply with a court order.  In no event shall the Executive be obligated to seek other employment or take any other action by way of mitigation of the amounts payable to the Executive under any of the provisions of this Agreement, nor shall the amount of any payment hereunder be reduced by any compensation earned by the Executive as a result of employment by another employer.

3.5           Executive alone shall be liable for the payment of any and all tax cost, incremental or otherwise, incurred by the Executive in connection with the provision of any benefits described in this Agreement.  No provision of this Agreement shall be interpreted to provide for the gross-up or other mitigation of any amount payable or benefit provided to the Executive under the terms of this Agreement as a result of such taxes.

3.6           Notwithstanding any provision of this Agreement to the contrary, if the Executive is a “specified employee” (as determined with respect AEPSC for purposes of Code Section 409A), the Executive shall not be entitled to any payments of amounts determined to be nonqualified deferred compensation within the meaning of Code Section 409A upon separation of service prior to the earliest of (1) the date that is six months after the date of separation from service for any reason other than death,  (2) the date of the Executive’s death, or (3) such earlier time that would not cause the Executive to incur any excise tax under Code Section 409A.


ARTICLE IV
SUCCESSOR TO CORPORATION

4.1           This Agreement shall bind any successor of AEPSC or the Corporation, its assets or its businesses (whether direct or indirect, by purchase, merger, consolidation or otherwise) in the same manner and to the same extent that AEPSC or the Corporation would be obligated under this Agreement if no succession had taken place.

4.2           In the case of any transaction in which a successor would not by the foregoing provision or by operation of law be bound by this Agreement, AEPSC and the Corporation shall require such successor expressly and unconditionally to assume and agree to perform AEPSC’s and the Corporation’s obligations under this Agreement, in
 
 
9

 
the same manner and to the same extent that AEPSC and the Corporation would be required to perform if no such succession had taken place.  The term “Corporation,” as used in this Agreement, shall mean the Corporation as hereinbefore defined and any successor or assignee to its business or assets which by reason hereof becomes bound by this Agreement.


ARTICLE V
MISCELLANEOUS

5.1           Any notices and all other communications provided for herein shall be in writing and shall be deemed to have been duly given when delivered or mailed, by certified or registered mail, return receipt requested, postage prepaid addressed to AEPSC at its principal office and to the Executive at the Executive’s residence or at such other addresses as AEPSC or the Executive shall designate in writing.

5.2           Except to the extent otherwise provided in Article II (Term of Agreement), no provision of this Agreement may be modified, waived or discharged except in writing specifically referring to such provision and signed by either AEPSC or the Executive against whom enforcement of such modification, waiver or discharge is sought.  No waiver by either AEPSC or the Executive of the breach of any condition or provision of this Agreement shall be deemed a waiver of any other condition or provision at the same or any other time.

5.3           The validity, interpretation, construction and performance of this Agreement shall be governed by the laws of the State of Ohio.

5.4           The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect.

5.5           This Agreement does not constitute a contract of employment or impose on the Executive, AEPSC or the Corporation any obligation to retain the Executive as an employee, to change the status of the Executive’s employment, or to change AEPSC’s policies regarding the termination of employment.

5.6           If the Executive institutes any legal action in seeking to obtain or enforce or is required to defend in any legal action the validity or enforceability of, any right or benefit provided by this Agreement, AEPSC will pay for all actual and reasonable legal fees and expenses incurred (as incurred) by the Executive, regardless of the outcome of such action; provided, however, that if such action instituted by the Executive is found by a court of competent jurisdiction to be frivolous, the Executive shall not be entitled to legal fees and expenses and shall be liable to AEPSC for amounts already paid for this purpose.

 
10

 
5.7           If the Executive makes a written request alleging a right to receive benefits under this Agreement or alleging a right to receive an adjustment in benefits being paid under the Agreement, AEPSC shall treat it as a claim for benefit.  All claims for benefit under the Agreement shall be sent to the Human Resources Department of AEPSC and must be received within 30 days after the Executive’s Termination of employment (or, if the Qualifying Termination is specified in Article I(o)(A) or (B), within 30 days after the Change in Control).  If AEPSC determines that the Executive who has claimed a right to receive benefits, or different benefits, under the Agreement is not entitled to receive all or any part of the benefits claimed, it will inform the Executive in writing of its determination and the reasons therefor in terms calculated to be understood by the Executive.  The notice will be sent within 90 days of the claim unless AEPSC determines additional time, not exceeding 90 days, is needed.  The notice shall make specific reference to the pertinent Agreement provisions on which the denial is based, and describe any additional material or information, if any, necessary for the Executive to perfect the claim and the reason any such additional material or information is necessary.  Such notice shall, in addition, inform the Executive what procedure the Executive should follow to take advantage of the review procedures set forth below in the event the Executive desires to contest the denial of the claim.  The Executive may within 90 days thereafter submit in writing to AEPSC a notice that the Executive contests the denial of the claim by AEPSC and desires a further review.  AEPSC shall within 60 days thereafter review the claim and authorize the Executive to appear personally and review pertinent documents and submit issues and comments relating to the claim to the persons responsible for making the determination on behalf of AEPSC.  AEPSC will render its final decision with specific reasons therefor in writing and will transmit it to the Executive within 60 days of the written request for review, unless AEPSC determines additional time, not exceeding 60 days, is needed, and so notifies the Executive.  If AEPSC fails to respond to a claim filed in accordance with the foregoing within 60 days or any such extended period, AEPSC shall be deemed to have denied the claim.

5.8           AEPSC intends that the design and administration of this Agreement are intended to comply with the requirements of Code Section 409A to the extent such section is effective and applicable to amounts that may become available hereunder. However, no Executive, beneficiary or any other person shall have any recourse against AEPSC, the Corporation, or any of their affiliates, employees, agents, successors, assigns or other representatives if this condition is determined not to be satisfied.

AEPSC has caused this Change In Control Agreement to be signed on behalf of all participating employers as of the 17th day of January, 2014.


 
American Electric Power Service Corporation
   
   
 
By   /s/ Nicholas K. Akins
 
Nicholas K. Akins
 
President & CEO


 
11

 

Exhibit 10(x)
 
November 26, 2012

Lana Hillebrand
202 Matthew Way
Murphy, TX 75094-3758

Dear Lana,

I am excited to be able to offer you the opportunity to join AEP as SVP & Chief Administrative Officer.  This offer letter provides a written summary of the job, compensation and benefits for this position, which will report directly to me.  This offer is subject to the approval of the Human Resources Committee of the Board at its November 20, 2012 meeting.  It is also contingent upon a satisfactory pre-placement health evaluation, a satisfactory background check and production of appropriate identification and employment eligibility documents.

Your salary for this position will be $470,000 and will be reviewed annually and your start date will be Monday December 17, 2012 or such other date to which we might mutually agree.  As we discussed, generally you will be expected to work three days a week in Columbus and from your home the rest of the week, although you will be expected to work more days in Columbus on some weeks and less on others, depending on the needs of the business.

In order to offset the loss of near-term compensation from your current employer that you will forfeit if you come to work for AEP, AEP will pay $464,000 to you in 2012 following the start of your employment.  This amount consists of $204,000 to offset the loss of your eligibility for a 2012 bonus and $260,000 to offset the loss of performance units that would otherwise vest in the next few months.

AEP’s incentive programs are reviewed periodically and modified from time to time at the discretion of senior AEP management and the HR Committee of the Board.  The current annual incentive target opportunity for this position will be 60% of base earnings for the year, with a two times target maximum.  Since your employment starting date is in the last month of the year, your first year of participation in an annual incentive plan will be 2013.

Your current long-term incentive opportunity, as reflected in the February 2013 award cycle, will have an annual target grant date fair value of $832,000.  This long-term incentive opportunity comes with a 29,900 share stock ownership requirement.  You will have 5 years from February 2013 to meet this requirement.  All performance units earned
 
 
 

 
will be mandatorily deferred into AEP career shares to the extent needed to satisfy this stock ownership requirement.

AEP currently expects to award 70% of the grant date value of its long-term incentive awards in the form of performance units with three-year goals tied to AEP’s earning per share relative to a board approved target and total shareholder return relative to other large electric and diversified utilities.  AEP currently expects to award the remaining 30% of this value in the form of restricted stock units (RSUs), which vest in approximately equal thirds, subject to continuous AEP employment, on the May 1 st following the first, second and third anniversary of the grant date.  The number of long-term incentive awards granted to you and the ultimate value of these awards, if any, are based on many factors, including your individual performance, AEP’s performance and AEP’s share price.

In addition, you will be granted $310,000 in additional RSUs as part of the first quarter 2013 award cycle to offset the loss of a similar value of stock units from your current employer that you would forfeit by accepting this offer.  These RSUs will also vest, subject to your continuous AEP employment, in approximately equal thirds on the May 1 st following the first, second and third anniversary of the grant date.

In the event that (A) your employment with AEP is Terminated 1 either (i) within the first year of your employment by AEP without Cause 2 or (ii) by you because your duties are changed to require you to work in Columbus, Ohio more than three days a week on a regular basis without your consent 3 and (B) such termination is not a Qualifying Termination as defined in Restricted Stock Unit Award Agreement provided to you pursuant to this offer letter, then AEP would provide a lump-sum severance benefit to you equal to your then current annual salary and target annual incentive opportunity.  Such payment would be conditioned upon your agreement to release AEP from any and all claims involving your employment with or termination from AEP, including claims of any other severance payments and benefits to which you might otherwise be entitled, and to do so within the period specified therein, but in no event later than sixty (60) days after the Termination, in the form established by AEP.  If applicable, the severance payment would be made no later than the 15th day of the third month of the Taxable Year following the Taxable Year of your Termination. 4

You will be provided with the Change In Control Agreement that will be used for other senior AEP executives for 2013.  This agreement will provide a multiple of 2.0 times your then current salary and target bonus, as well as other benefits, in the event of a Change In Control as defined therein.  As a new participant you will not be considered to be a Grandfathered Executive entitled to the tax-gross-up provisions under this agreement.

Beginning January 2 nd , you will be eligible for up to six months of temporary living expenses, including reimbursement for reasonable housing accommodations, airfare, rental car and other travel expenses.  After this period you will be responsible for all commuting and living expenses.

 
2

 
Beginning in 2013 you will receive five weeks of paid time-off in addition to company holidays.  This will consist of 22 days of paid vacation and three personal days.  As we discussed, you will be provided with sufficient vacation and other paid time-off in 2012 to allow you to be away from work from Monday December 24 through year-end.

In addition you will be eligible to participate in AEP’s comprehensive health and welfare benefit program, qualified and non-qualified retirement savings plans, qualified and non-qualified cash balance pension plans, executive financial counseling and tax preparation services and other AEP benefit programs, as amended from time to time.  Under the terms of the plans as currently in effect, your age and years of service would provide the maximum 8.5% cash balance crediting rate under the terms of AEP’s current qualified and non-qualified pension plans for 2013; and you would become eligible for retiree medical benefits if you would remain employed with AEP through your age 55, since you have already met the 10 year service requirement.  Please contact Andy Carlin at (614) 716-3417 if you have any questions regarding your compensation or executive benefits.

The Immigration Reform and Control Act of 1986, requires employers to verify the identity and employment eligibility of all prospective employees.  Failure to produce employment eligibility documents as required will result in the withdrawal of the employment offer.  Therefore, if this offer is acceptable to you, please fax copies (each on a separate sheet) of your Driver’s License or Passport, Birth Certificate, Social Security Card, and Marriage Certificate (if applicable) to Andy Carlin’s confidential fax number at (614) 716-2406.

Lana, I look forward to your joining American Electric Power’s executive team and working with you again in the coming months.

Sincerely,


/s/ Nicholas K. Akins
Nicholas K. Akins
President & CEO

cc:           Andy Carlin
 
 
3

 
 
Definitions and Other Conditions
 
 
   
1 “Termination” means termination of employment with AEP for any reason; provided that determinations as to the circumstances that will be considered a Termination shall be made in a manner consistent with written policies adopted by the Human Resources Committee of American Electric Power Company, Inc., from time to time to the extent such policies are consistent with the requirements imposed under Code 409A(a)(2)(A)(i).
 
2 “Cause” means any one or more of the following grounds: (a) failure or refusal to perform your assigned duties and responsibilities in a competent or satisfactory manner as determined in good faith by AEP; (b) commission of an act of dishonesty, including, but not limited to, misappropriation of funds or any property of AEP; (c) engagement in activities or conduct injurious to the best interest or reputation of AEP as determined in good faith by AEP; (d) insubordination; (e) a violation of any of the terms and conditions of any written agreement or agreements you may from time to time have with AEP; (f) a violation of any of AEP’s rules of conduct of behavior, such as may be provided in AEP’s Principles of Business Conduct or any employee handbook or as AEP may promulgate from time to time; (g) commission of a crime which is a felony, a misdemeanor involving an act or moral turpitude, or a misdemeanor committed in connection with your employment with AEP which is injurious to the best interest or reputation of AEP as determined in good faith by AEP; or (h) disclosure, dissemination, or misappropriation of confidential, proprietary, and/or trade secret information.
 
3 Your eligibility for a severance payment pursuant to clause (A)(ii) in the eighth paragraph of the offer letter, is conditioned upon (1) within ninety (90) days of the initial existence of that circumstance, you must give AEP written notice of that circumstance and (2) AEP must fail to remedy that circumstance within thirty (30) days after its receipt of your notice.  Your written notice to AEP must specify (I) the effective date for your proposed termination of employment (provided that such effective date may not precede the expiration of the period for AEP’s opportunity to remedy), (II) reasonable detail of the facts and circumstances claimed to provide the basis for termination, and (III) your belief that such facts and circumstance would establish your eligibility for a severance payment pursuant to clause (A)(ii) in the eighth paragraph of the offer letter.
 
4 For purposes of the offer letter, “Taxable Year” means your taxable year for federal income tax purposes.  If any period specified for timely satisfaction of conditions for you to become entitled to the severance payment ends in a Taxable Year that is different from the Taxable Year of your Termination, the payment will not be made to you until the Taxable Year in which that period ends.  In any event, as stated in the offer letter, the payment, if applicable, will be made no later than the 15th day of the third month of that later Taxable Year.
 
 
4

 
EXHIBIT 12
 
 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIAIRIES
Computation of Consolidated Ratios of Earnings to Fixed Charges
(in millions except ratio data)
 
   
Years Ended December 31,
 
   
2009
 
2010
   2011       2012      2013  
EARNINGS
                              
Income Before Income Tax Expense and Equity Earnings
 
$
1,938
 
$
1,849
 
$
2,367
 
1,822
  2,110   
Fixed Charges (as below)
   
1,237
   
1,254
   
1,209
   
1,257
    1,136   
Preferred Security Dividend Requirements of
   Consolidated Subsidiaries
     (4     (4   (8  
-
     
Total Earnings
 
$
3,171
  $
3,099
 
$
3,568
 
3,079
  3,246   
                                 
FIXED CHARGES
                               
Interest Expense
 
$
973
  $ 999  
$
933   988   906   
Credit for Allowance for Borrowed Funds Used
   During Construction
   
67
    53     63     69     40   
Estimated Interest Element in Lease Rentals     193     198     205     200     190   
Preferred Security Dividend Requirements of
   Consolidated Subsidiaries
     4      4     8     -      
Total Fixed Charges
 
$
1,237
  $
1,254
 
$
1,209
  1,257   1,136   
                                 
Ratio of Earnings to Fixed Charges
   
2.56
   
2.47
   
2.95
    2.44     2.85   
 

EXHIBIT 12
 
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Computation of Consolidated Ratios of Earnings to Fixed Charges
(in thousands except ratio data)
 
    Years Ended December 31,  
     
 2009
 
2010
  2011       2012   2013  
EARNINGS
                               
Income Before Income Taxes
  $ 201,263   $ 210,898   $ 252,618   423,030   326,146  
Fixed Charges (as below)     215,640     217,500     217,280     210,421     201,704  
Total Earnings
  $ 416,903   $ 428,398   $ 469,898   633,451   527,850  
                                 
FIXED CHARGES
                               
Interest Expense
  $ 202,426   $ 207,649   $ 204,623   202,074   192,982  
Credit for Allowance for Borrowed Funds Used
   During Construction
    6,014     2,251     6,257     1,347     1,522  
Estimated Interest Element in Lease Rentals    
7,200
    7,600     6,400     7,000     7,200  
Total Fixed Charges
  $ 215,640   $ 217,500   $ 217,280   210,421   201,704  
                                 
Ratio of Earnings to Fixed Charges
    1.93     1.96     2.16     3.01     2.61  
 

EXHIBIT 12
 
 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Computation of Consolidated Ratios of Earnings to Fixed Charges
(in thousands except ratio data)
 
    Years Ended December 31,  
     
2009
    2010   2011       2012   2013  
EARNINGS
                               
Income Before Income Taxes
 
$
297,347   $ 189,517   $ 201,434   157,801   252,615   
Fixed Charges (as below)
    173,293     174,965     168,003     168,656     167,362   
Total Earnings
  $ 470,640   $ 364,482   $ 369,437   326,457   419,977   
                                 
FIXED CHARGES
                               
Interest Expense
  $ 101,145   $ 104,465   $ 97,665   102,739   97,710   
Credit for Allowance for Borrowed Funds Used
   During Construction
    8,348     8,500     7,838     4,717     9,752   
Estimated Interest Element in Lease Rentals     63,800     62,000     62,500     61,200     59,900   
Total Fixed Charges
  $ 173,293   $ 174,965   $ 168,003   168,656   167,362   
                                 
Ratio of Earnings to Fixed Charges
    2.71     2.08     2.19     1.93     2.50   
                                 
 

 
EXHIBIT 12
 
 
OHIO POWER COMPANY AND SUBSIDIARY
Computation of Consolidated Ratios of Earnings to Fixed Charges
(in thousands except ratio data)
 
      Years Ended December 31,  
   
2009
  2010      2011    2012      2013  
EARNINGS
                              
Income Before Income Taxes
 
$
890,471   $ 842,922   $ 678,690   $ 487,817   $ 635,650  
Fixed Charges (as below)
    283,540     269,886     248,026      245,446     215,548  
Total Earnings
 
$
1,174,011   $ 1,112,808   $  926,716   $ 733,263   $ 851,198  
                                 
FIXED CHARGES
                               
Interest Expense
 
$
241,134   $ 242,000   $  221,976   $ 213,100   $ 182,046  
Credit for Allowance for Borrowed Funds
   Used During Construction
    16,506     3,786      2,350     9,046     10,102  
Estimated Interest Element in Lease Rentals     25,900     24,100      23,700      23,300     23,400  
Total Fixed Charges
 
$
283,540   $ 269,886   $  248,026   $  245,446   $ 215,548  
                                 
Ratio of Earnings to Fixed Charges
    4.14     4.12     3.73      2.98     3.94  

 

EXHIBIT 12
 
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
Computation of Ratios of Earnings to Fixed Charges
(in thousands except ratio data)

 
    Years Ended December 31,  
   
2009
 
2010
    2011       2012     2013  
EARNINGS
                               
Income Before Income Taxes
 
$
119,523   $
122,887
 
$
192,257
    $
180 ,835
    $ 163,681   
Fixed Charges (as below)
    62,235    
65,834
   
58,822
   
58,984
    57,647   
Total Earnings
 
$
181,758   $
188,721
  $
251,079
   $
239,819
   $ 221,328   
                                 
FIXED CHARGES
                               
Interest Expense
 
$
59,093   $
63,362
  $
54,700
   $
55,286
   $ 53,175   
Credit for Allowance for Borrowed Funds Used
   During Construction
    1,142    
572
    822    
 
1,098
    2,272   
Estimated Interest Element in Lease Rentals
    2,000    
1,900
   
3,300
   
2,600
    2,200   
Total Fixed Charges
 
$
62,235   $
65,834
  $
58,822
   $
58,984
   $ 57,647   
                                 
Ratio of Earnings to Fixed Charges
    2.92    
2.86
   
4.26
   
4.06
    3.83   
 
 

 
 
 
 
 
 
 
 


EXHIBIT 12
 
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED 
Computation of Consolidated Ratios of Earnings to Fixed Charges
(in thousands except ratio data)
 
 
 
Years Ended December 31,
 
   
2009
   
2010
   2011      2012      2013  
 EARNINGS
                              
Income Before Income Taxes and Equity Earnings 
 
$
140,035  
$
208,484
  $
219,283
  $  245,862   $ 220,957   
Fixed Charges (as below)     109,146    
132,106
   
134,285
     147,817     144,844   
Total Earnings
 
$
249,181  
340,590
  $
353,568
  $  393,679   $ 365,801   
                                 
FIXED CHARGES
                               
Interest Expense
  $ 70,500  
86,538
  $
81,781
  $  88,318   $ 130,282   
Credit for Allowance for Borrowed Funds
   Used During Construction
    29,546    
33,668
   
40,904
    48,499     4,262   
Estimated Interest Element in Lease Rentals     9,100    
11,900
   
11,600
     11,000     10,300   
Total Fixed Charges
 
$
109,146  
132,106
  $
134,285
  $  147,817   $ 144,844   
                                 
Ratio of Earnings to Fixed Charges
    2.28    
2.57
   
2.63
     2 .66     2.52   

 
2013 Annual Reports

American Electric Power Company, Inc. and Subsidiary Companies
Appalachian Power Company and Subsidiaries
Indiana Michigan Power Company and Subsidiaries
Ohio Power Company and Subsidiaries
Public Service Company of Oklahoma
Southwestern Electric Power Company Consolidated









Audited Financial Statements and
Management’s Discussion and Analysis of Financial Condition and Results of Operations












AEP LOGO

 
 

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF ANNUAL REPORTS

   
Page
Number
Glossary of Terms
 
i
     
Forward-Looking Information
 
v
     
AEP Common Stock and Dividend Information
 
vii
       
American Electric Power Company, Inc. and Subsidiary Companies:
   
 
Selected Consolidated Financial Data
 
1
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
2
 
Reports of Independent Registered Public Accounting Firm
 
51
 
Management's Report on Internal Control Over Financial Reporting
 
53
 
Consolidated Financial Statements
 
54
 
Index of Notes to Consolidated Financial Statements
 
60
       
Appalachian Power Company and Subsidiaries:
   
 
Management’s Narrative Discussion and Analysis of Results of Operations
    152
 
Report of Independent Registered Public Accounting Firm
    158
 
Management's Report on Internal Control Over Financial Reporting
    159
 
Consolidated Financial Statements
    160
 
Index of Notes to Financial Statements of Registrant Subsidiaries
    166
       
Indiana Michigan Power Company and Subsidiaries:
   
 
Management’s Narrative Discussion and Analysis of Results of Operations
    168
 
Report of Independent Registered Public Accounting Firm
    174
 
Management's Report on Internal Control Over Financial Reporting
    175
 
Consolidated Financial Statements
    176
 
Index of Notes to Financial Statements of Registrant Subsidiaries
    182
       
Ohio Power Company and Subsidiaries:
   
 
Management’s Narrative Discussion and Analysis of Results of Operations
    184
 
Report of Independent Registered Public Accounting Firm
    190
 
Management's Report on Internal Control Over Financial Reporting
    191
 
Consolidated Financial Statements
    192
 
Index of Notes to Financial Statements of Registrant Subsidiaries
    198
       
Public Service Company of Oklahoma:
   
 
Management’s Narrative Discussion and Analysis of Results of Operations
    200
 
Report of Independent Registered Public Accounting Firm
    203
 
Management's Report on Internal Control Over Financial Reporting
    204
 
Financial Statements
    205
 
Index of Notes to Financial Statements of Registrant Subsidiaries
    211
       
Southwestern Electric Power Company Consolidated:
   
 
Management’s Narrative Discussion and Analysis of Results of Operations
    213
 
Report of Independent Registered Public Accounting Firm
    218
 
Management's Report on Internal Control Over Financial Reporting
    219
 
Consolidated Financial Statements
    220
 
Index of Notes to Financial Statements of Registrant Subsidiaries
    226
       
Index of Notes to Financial Statements of Registrant Subsidiaries
    227
       
Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries
    376

 
 

 

GLOSSARY OF TERMS
 
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

Term
 
Meaning
     
AEGCo
 
AEP Generating Company, an AEP electric utility subsidiary.
AEP or Parent
 
American Electric Power Company, Inc., an electric utility holding company.
AEP Consolidated
 
AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit
 
AEP Credit, Inc., a consolidated variable interest entity of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East Companies
 
APCo, I&M, KPCo and OPCo.
AEP Energy
 
AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.  BlueStar began doing business as AEP Energy, Inc. in June 2012.
AEP System
 
American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP Transmission Holdco
 
AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.
AEP West Companies
 
PSO, SWEPCo, TCC and TNC.
AEPEP
 
AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, asset management and commercial and industrial sales in the deregulated Texas market.
AEPES
 
AEP Energy Services, Inc., a subsidiary of AEP Resources, Inc.
AEPSC
 
American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC
 
Allowance for Funds Used During Construction.
AGR
 
AEP Generation Resources Inc., a nonregulated AEP subsidiary that acquired the generation assets and liabilities of OPCo.
AOCI
 
Accumulated Other Comprehensive Income.
APCo
 
Appalachian Power Company, an AEP electric utility subsidiary.
APSC
 
Arkansas Public Service Commission.
Appalachian Consumer Rate Relief Funding
 
Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance.
BlueStar
 
BlueStar Energy Holdings, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.  BlueStar began doing business as AEP Energy, Inc. in June 2012.
BOA
 
Bank of America Corporation.
CAA
 
Clean Air Act.
CLECO
 
Central Louisiana Electric Company, a nonaffiliated utility company.
CO 2
 
Carbon dioxide and other greenhouse gases.
Cook Plant
 
Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M.
CRES provider
 
Competitive Retail Electric Service providers under Ohio law that target retail customers by offering alternative generation service.
CSPCo
 
Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.
CWIP
 
Construction Work in Progress.
 
 
i

 
Term   Meaning
     
DCC Fuel
 
DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC, DCC Fuel V LLC and DCC Fuel VI LLC, consolidated variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DHLC
 
Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
E&R
 
Environmental compliance and transmission and distribution system reliability.
EIS
 
Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated variable interest entity of AEP.
ENEC
 
Expanded Net Energy Charge.
ERCOT
 
Electric Reliability Council of Texas regional transmission organization.
ESP
 
Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
ETT
 
Electric Transmission Texas, LLC, an equity interest joint venture between AEP and MidAmerican Energy Holdings Company Texas Transco, LLC formed to own and operate electric transmission facilities in ERCOT.
FAC
 
Fuel Adjustment Clause.
FASB
 
Financial Accounting Standards Board.
Federal EPA
 
United States Environmental Protection Agency.
FERC
 
Federal Energy Regulatory Commission.
FGD
 
Flue Gas Desulfurization or scrubbers.
FTR
 
Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP
 
Accounting Principles Generally Accepted in the United States of America.
I&M
 
Indiana Michigan Power Company, an AEP electric utility subsidiary.
IEU
 
Industrial Energy Users-Ohio.
IGCC
 
Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
Interconnection Agreement
 
An agreement by and among APCo, I&M, KPCo and OPCo which defined the sharing of costs and benefits associated with their respective generation plants.  This agreement was terminated January 1, 2014.
IRS
 
Internal Revenue Service.
IURC
 
Indiana Utility Regulatory Commission.
KGPCo
 
Kingsport Power Company, an AEP electric utility subsidiary.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
KPSC
 
Kentucky Public Service Commission.
kV
 
Kilovolt.
KWh
 
Kilowatthour.
LPSC
 
Louisiana Public Service Commission.
MISO
 
Midwest Independent Transmission System Operator.
MLR
 
Member load ratio, the method used to allocate transactions among members of the Interconnection Agreement.
MMBtu
 
Million British Thermal Units.
MPSC
 
Michigan Public Service Commission.
MTM
 
Mark-to-Market.
MW
 
Megawatt.
MWh
 
Megawatthour.
NO x
 
Nitrogen oxide.
Nonutility Money Pool
 
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
 
 
ii

 
Term   Meaning
     
NSR
 
New Source Review.
OATT
 
Open Access Transmission Tariff.
OCC
 
Corporation Commission of the State of Oklahoma.
Ohio Phase-in-Recovery Funding
 
Ohio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property.
OPCo
 
Ohio Power Company, an AEP electric utility subsidiary.
OPEB
 
Other Postretirement Benefit Plans.
Operating Agreement
 
Agreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third party sales.  AEPSC acts as the agent.
OTC
 
Over the counter.
OVEC
 
Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PCA
 
Power Coordination Agreement among APCo, I&M and KPCo.
PJM
 
Pennsylvania – New Jersey – Maryland regional transmission organization.
PM
 
Particulate Matter.
POLR
 
Provider of Last Resort revenues.
PSO
 
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO
 
Public Utilities Commission of Ohio.
PUCT
 
Public Utility Commission of Texas.
Registrant Subsidiaries
 
AEP subsidiaries which are SEC registrants; APCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts
 
Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
 
A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana.  AEGCo and I&M jointly-own Unit 1.  In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
RTO
 
Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine
 
Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo.
SEC
 
U.S. Securities and Exchange Commission.
SEET
 
Significantly Excessive Earnings Test.
SIA
 
System Integration Agreement, effective June 15, 2000, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SNF
 
Spent Nuclear Fuel.
SO 2
 
Sulfur dioxide.
SPP
 
Southwest Power Pool regional transmission organization.
SSO
 
Standard service offer.
Stall Unit
 
J. Lamar Stall Unit at Arsenal Hill Plant, a 534 MW natural gas unit owned by SWEPCo.
SWEPCo
 
Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC
 
AEP Texas Central Company, an AEP electric utility subsidiary.
Texas Restructuring Legislation
 
Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC
 
AEP Texas North Company, an AEP electric utility subsidiary.
 
 
iii

 
Term   Meaning
     
Transition Funding
 
AEP Texas Central Transition Funding I LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas restructuring law.
True-up Proceeding
 
A filing made under the Texas Restructuring Legislation to finalize the amount of stranded costs and other true-up items and the recovery of such amounts.
Turk Plant
 
John W. Turk, Jr. Plant, a 600 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
Utility Money Pool
 
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIE
 
Variable Interest Entity.
Virginia SCC
 
Virginia State Corporation Commission.
WPCo
 
Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC
 
Public Service Commission of West Virginia.

 
iv

 

FORWARD-LOOKING INFORMATION

This report made by AEP and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations,” but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, we undertake no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

·
The economic climate, growth or contraction within and changes in market demand and demographic patterns in our service territory.
·
Inflationary or deflationary interest rate trends.
·
Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.
·
The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
·
Electric load, customer growth and the impact of retail competition, particularly in Ohio.
·
Weather conditions, including storms and drought conditions, and our ability to recover significant storm restoration costs through applicable rate mechanisms.
·
Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·
Availability of necessary generation capacity and the performance of our generation plants.
·
Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·
Our ability to build or acquire generation capacity and transmission lines and facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are cancelled) through applicable rate cases or competitive rates.
·
New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation, cost recovery and/or profitability of our generation plants and related assets.
·
Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
·
A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers.
·
Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
·
Resolution of litigation.
·
Our ability to constrain operation and maintenance costs.
·
Our ability to develop and execute a strategy based on a view regarding prices of electricity and other energy-related commodities.
·
Prices and demand for power that we generate and sell at wholesale.
·
Changes in technology, particularly with respect to new, developing or alternative sources of generation.
·
Our ability to recover through rates or market prices any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.
·
Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas.
 
 
v

 
·
Changes in utility regulation and the allocation of costs within regional transmission organizations, including PJM and SPP.
·
The transition to market generation in Ohio, including the implementation of ESPs.
·
Our ability to successfully and profitably manage our Ohio generation assets in a startup, nonregulated merchant business.
·
Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
·
Actions of rating agencies, including changes in the ratings of our debt.
·
The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact on future funding requirements.
·
Accounting pronouncements periodically issued by accounting standard-setting bodies.
·
Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.
 
The forward looking statements of AEP and its Registrant Subsidiaries speak only as of the date of this report or as of the date they are made.  AEP and its Registrant Subsidiaries expressly disclaim any obligation to update any forward-looking information.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of this report.

 
vi

 
AEP COMMON STOCK AND DIVIDEND INFORMATION

The AEP common stock quarterly high and low sales prices, quarter-end closing price and the cash dividends paid per share are shown in the following table:

 
 
 
 
 
 
 
 
Quarter-End
 
 
 
Quarter Ended
 
High
 
Low
 
Closing Price
 
Dividend
December 31, 2013
 
$
 48.40 
 
$
 43.01 
 
$
 46.74 
 
$
 0.50 
September 30, 2013
 
 
 47.59 
 
 
 41.83 
 
 
 43.35 
 
 
 0.49 
June 30, 2013
 
 
 51.60 
 
 
 42.83 
 
 
 44.78 
 
 
 0.49 
March 31, 2013
 
 
 48.68 
 
 
 42.92 
 
 
 48.63 
 
 
 0.47 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2012
 
$
 45.41 
 
$
 40.56 
 
$
 42.68 
 
$
 0.47 
September 30, 2012
 
 
 44.84 
 
 
 39.62 
 
 
 43.94 
 
 
 0.47 
June 30, 2012
 
 
 40.46 
 
 
 36.97 
 
 
 39.90 
 
 
 0.47 
March 31, 2012
 
 
 41.98 
 
 
 37.46 
 
 
 38.58 
 
 
 0.47 

AEP common stock is traded principally on the New York Stock Exchange.  As of December 31, 2013, AEP had approximately 78,000 registered shareholders.
 
5 YEAR CUMULATIVE TOTAL RETURN
 
 
vii

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2013 
 
2012 
 
2011 
 
2010 
 
2009 
 
 
 
(dollars in millions, except per share amounts)
STATEMENTS OF INCOME DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 15,357 
 
$
 14,945 
 
$
 15,116 
 
$
 14,427 
 
$
 13,489 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating Income
$
 2,855 
 
$
 2,656 
 
$
 2,782 
 
$
 2,663 
 
$
 2,771 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Before Extraordinary Items
$
 1,484 
 
$
 1,262 
 
$
 1,576 
 
$
 1,218 
 
$
 1,370 
Extraordinary Items, Net of Tax
 
 - 
 
 
 - 
 
 
 373 
 
 
 - 
 
 
 (5)
Net Income
 
 1,484 
 
 
 1,262 
 
 
 1,949 
 
 
 1,218 
 
 
 1,365 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income Attributable to Noncontrolling Interests
 
 4 
 
 
 3 
 
 
 3 
 
 
 4 
 
 
 5 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS
 
 1,480 
 
 
 1,259 
 
 
 1,946 
 
 
 1,214 
 
 
 1,360 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred Stock Dividend Requirements of Subsidiaries Including
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital Stock Expense
 
 - 
 
 
 - 
 
 
 5 
 
 
 3 
 
 
 3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
$
 1,480 
 
$
 1,259 
 
$
 1,941 
 
$
 1,211 
 
$
 1,357 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
BALANCE SHEETS DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and Equipment
$
 60,285 
 
$
 57,454 
 
$
 55,670 
 
$
 53,740 
 
$
 51,684 
Accumulated Depreciation and Amortization
 
 19,288 
 
 
 18,691 
 
 
 18,699 
 
 
 18,066 
 
 
 17,340 
Total Property, Plant and Equipment – Net
$
 40,997 
 
$
 38,763 
 
$
 36,971 
 
$
 35,674 
 
$
 34,344 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 56,414 
 
$
 54,367 
 
$
 52,223 
 
$
 50,455 
 
$
 48,348 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total AEP Common Shareholders’ Equity
$
 16,085 
 
$
 15,237 
 
$
 14,664 
 
$
 13,622 
 
$
 13,140 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling Interests
$
 1 
 
$
 - 
 
$
 1 
 
$
 - 
 
$
 - 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
$
 - 
 
$
 - 
 
$
 - 
 
$
 60 
 
$
 61 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt (a)
$
 18,377 
 
$
 17,757 
 
$
 16,516 
 
$
 16,811 
 
$
 17,498 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Obligations Under Capital Leases (a)
$
 538 
 
$
 449 
 
$
 458 
 
$
 474 
(b)
$
 317 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
AEP COMMON STOCK DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Before Extraordinary Items
$
 3.04 
 
$
 2.60 
 
$
 3.25 
 
$
 2.53 
 
$
 2.97 
Extraordinary Items, Net of Tax
 
 - 
 
 
 - 
 
 
 0.77 
 
 
 - 
 
 
 (0.01) 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Basic Earnings per Share Attributable to AEP Common Shareholders
$
 3.04 
 
$
 2.60 
 
$
 4.02 
 
$
 2.53 
 
$
 2.96 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted Average Number of Basic Shares Outstanding (in millions)
 
 487 
 
 
 485 
 
 
 482 
 
 
 479 
 
 
 459 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Market Price Range:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
High
$
 51.60 
 
$
 45.41 
 
$
 41.71 
 
$
 37.94 
 
$
 36.51 
 
 
Low
$
 41.83 
 
$
 36.97 
 
$
 33.09 
 
$
 28.17 
 
$
 24.00 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year-end Market Price
$
 46.74 
 
$
 42.68 
 
$
 41.31 
 
$
 35.98 
 
$
 34.79 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Dividends Declared per AEP Common Share
$
 1.95 
 
$
 1.88 
 
$
 1.85 
 
$
 1.71 
 
$
 1.64 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dividend Payout Ratio
 
64.14%
 
 
72.31%
 
 
46.02%
 
 
67.59%
 
 
55.41%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Book Value per AEP Common Share
$
 32.98 
 
$
 31.35 
 
$
 30.36 
 
$
 28.32 
 
$
 27.49 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Includes portion due within one year.
(b)
Obligations Under Capital Leases increased primarily due to capital leases under new master lease agreements for property that was previously leased
 
 
under operating leases.
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
1

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

American Electric Power Company, Inc. (AEP) is one of the largest investor-owned electric public utility holding companies in the United States.  Our electric utility operating companies provide generation, transmission and distribution services to more than five million retail customers in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia.

Our subsidiaries operate an extensive portfolio of assets including:

·
Approximately 37,600 megawatts of generating capacity, one of the largest complements of generation in the United States.
·
More than 40,000 miles of transmission lines, including 2,110   miles of 765kV lines, the backbone of the electric interconnection grid in the Eastern United States.
·
Approximately 222,000   miles of distribution lines that deliver electricity to 5.3 million customers.
·
Substantial commodity transportation assets (more than 5,700   railcars, approximately 3,000 barges, 60 towboats, 25 harbor boats and a coal handling terminal with approximately 18 million tons of annual capacity).  Our commercial barging operations annually transport approximately 37 million tons of coal and dry bulk commodities.  Approximately 39% of the barging is for transportation of agricultural products, 26% for coal, 20% for steel and 15% for other commodities.

Corporate Separation

Background

On December 31, 2013, based on FERC and PUCO orders which approved corporate separation of generation assets and associated liabilities, OPCo transferred its generation assets and related generation liabilities at net book value to AGR.  In accordance with Ohio law, OPCo remains responsible to provide power and capacity to OPCo customers who have not switched electric providers.  Effective January 1, 2014, OPCo will purchase power from both affiliated and nonaffiliated entities, subject to PUCO approval, to meet the energy and capacity needs of customers.

On December 31, 2013, subsequent to the transfer of OPCo’s generation assets and associated liabilities to AGR, AGR transferred at net book value its ownership (867 MW) in Amos Plant, Unit 3 to APCo.  The transfer of these generation assets and associated liabilities was approved by the FERC, the Virginia SCC and the WVPSC.

On December 31, 2013, subsequent to the transfer of OPCo’s generation assets and associated liabilities to AGR, AGR transferred at net book value a one-half interest (780 MW) in the Mitchell Plant to KPCo.  The transfer of these generation assets and associated liabilities was approved by the FERC and the KPSC.

Other Impacts of Corporate Separation

In accordance with our December 2010 announcement and our October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014.  The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated.

Effective January 1, 2014, the FERC approved the following:

·  
Power Coordination Agreement among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.
·  
Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent to address open commitments related to the termination of the Interconnection Agreement and responsibilities to PJM.
·  
Power Supply Agreement between AGR and OPCo for AGR to supply capacity for OPCo’s switched and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that is not acquired through auctions from January 1, 2014 through December 31, 2014.

 
2

 
For a further discussion of corporate separation, see the “Corporate Separation” section of Note 1 and the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters in Note 4.

Ohio Electric Security Plan Filings

2009 – 2011 ESP

In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover OPCo’s deferred fuel costs in rates beginning September 2012.  As of December 31, 2013, OPCo’s net deferred fuel balance was $445 million, excluding unrecognized equity carrying costs.  Decisions from the Supreme Court of Ohio are pending related to various appeals which, if ordered, could reduce OPCo’s net deferred fuel costs balance.
 
June 2012 – May 2015 Ohio ESP Including Capacity Charge
 
In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015.  This ruling was generally upheld in PUCO rehearing orders in January and March 2013.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The RPM price is approximately $33/MW day through May 2014 and $148/MW day from June 2014 through May 2015.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.

As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012.  The RSR is being collected from customers at $3.50/MWh through May 2014 and will be collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs.  In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR.  As of December 31, 2013, OPCo’s incurred deferred capacity costs balance was $288 million, including debt carrying costs.

In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications.  The modifications include the delay of the energy auctions that were originally ordered in the ESP order.  OPCo must conduct an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015.  The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning November 2014 through May 2015 and for the remaining 40% of the SSO load for delivery from January 2015 through May 2015.  OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015.  The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned.  Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings.  Management believes that these intervenor concerns are without merit.  In December 2013, the PUCO granted applications for rehearing for further consideration filed by OPCo and intervenors.  In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012-2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC.

Proposed June 2015 – May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders effective June 2015 through May 2018.  This filing is consistent with the PUCO’s objective for a full transition from FAC and base generation rates to market.  The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo.  Additionally, the application identifies OPCo’s intention to submit a separate application to continue the RSR established in the June 2012 – May 2015 ESP in which the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected.  Management intends to file this application in the first quarter of 2014.
 
 
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If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its deferred capacity costs, it could reduce future net income and cash flows and impact financial condition.  See “Ohio Electric Security Plan Filing” section of Note 4.

Ohio Customer Choice

In our Ohio service territory, various CRES providers are targeting retail customers by offering alternative generation service.  The reduction in gross margin as a result of customer switching in Ohio is partially offset by (a) collection of capacity revenues from CRES providers, (b) off-system sales, (c) deferral of unrecovered capacity costs, (d) RSR collections and (e) revenues from AEP Energy.  AEP Energy is our CRES provider and part of our Generation & Marketing segment which targets retail customers, both within and outside of our retail service territory.

Customer Demand

In comparison to 2012, our weather-normalized retail sales decreased 1.6% for the year ended December 31, 2013.  Our industrial sales declined 4.5% partially due to lower production levels at Ormet, a large aluminum company.  Ormet had a contract to purchase power from OPCo through 2018.  In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down its operations effective immediately.  The loss of Ormet's load will not have a material impact on future gross margin.  Power previously sold to Ormet will be available to be sold into wholesale markets.

In 2014, we anticipate weather-normalized retail sales will decline by 1.1%.  Excluding Ormet, total weather-normalized retail sales are projected to increase by 0.1% in 2014.  The largest decline is projected to occur in the industrial class, principally due to Ormet’s decision to shut down.  Excluding Ormet, the industrial class is projected to grow by 1.2% in 2014, primarily related to a number of new oil and natural gas expansions, especially around the major shale gas areas within AEP's footprint.  Weather-normalized residential sales are projected to decline by 0.9% in 2014, continuing the recent trend of declining use per customer related to higher saturations of energy efficient appliances and the promotion of utility sponsored energy efficiency programs.  The commercial class energy sales are projected to remain flat compared to 2013.

PJM Capacity Auction

AGR is required to offer all of its available generation in the PJM Reliability Pricing Model (RPM) auction, which is conducted three years in advance of the actual delivery year.  Therefore, the majority of AGR generation assets are subject to PJM capacity prices for periods after May 2015.  Through May 2015, AGR will provide generation capacity to OPCo for both switched and non-switched OPCo generation customers.  For switched customers, OPCo pays AGR $188.88/MW day.  For non-switched OPCo generation customers, OPCo pays AGR for capacity.  AGR’s non-OPCo load is subject to the PJM RPM auction.  Shown below are the current auction prices for capacity, as announced/settled by PJM:

 
 
PJM Base
PJM Auction Period
 
Auction Price
 
 
(per MW day) 
June 2013 through May 2014
 
$
 27.73 
June 2014 through May 2015
 
 
 125.99 
June 2015 through May 2016
 
 
 136.00 
June 2016 through May 2017
 
 
 59.37 

We formed a coalition with other utility companies to address mutual concerns related to the PJM capacity auction process, including: (a) import limits for power without firm transmission, (b) placing bidding caps on available demand response resources in comparison to base generation capacity, (c) modification and enforcement of the timing of demand response requirements to better reflect real-time capacity requirements and (d) tightened rules for incremental auctions in which speculative bidders sell resources in the base auction and buy back that capacity in an incremental auction, resulting in no additional capacity and lower market prices.  PJM has made three FERC filings related to the first three issues.  We anticipate that another filing will be made by PJM later in the first quarter of
 
 
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2014 to address the fourth issue.  In January 2014, FERC accepted without modification PJM's filed recommendations on placing bidding caps on certain demand response products that are available only during the summer period.  We expect to receive FERC decisions on the other filings prior to the next RPM auction in May 2014.

Turk Plant

SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.  As of December 31, 2013, SWEPCo’s share of incurred construction expenditures for the Turk Plant was approximately $1.758 billion.  As of December 31, 2013, a pretax provision of $59 million has been recorded for costs incurred in excess of a Texas cost cap, resulting in total net capitalized expenditures of $1.699 billion.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant.  In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN.  This Turk Plant output that is currently not subject to cost-based rate recovery and is being sold into the wholesale market.  If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant or transmission lines, it could reduce future net income and cash flows and impact financial condition.  See the “Turk Plant” section of Note 4.

2012 Texas Base Rate Case

In December 2013, the PUCT issued an order granting rehearing and reversed its decision on consolidated tax savings increasing SWEPCo’s annual revenues by $5 million.  In January 2014, the PUCT determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap.  As a result of these rulings, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances.  These rulings also increased SWEPCo’s previously approved annual base rates by a total of $13 million.  The resulting annual base rate increase is approximately $52 million.  See the “Turk Plant” and the “2012 Texas Base Rate Case” sections of Note 4.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant.  In February 2013, a settlement was approved by the LPSC that increased Louisiana total rates by approximately $2 million annually, effective March 2013.  The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund.  The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013.  In May 2013, SWEPCo filed testimony in the prudency review of the Turk Plant.  If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudency review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.  See the “2012 Louisiana Formula Rate Filing” section of Note 4.

Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC.  Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC.  As of December 31, 2013, SWEPCo has incurred $32 million in costs related to these projects.  SWEPCo will seek recovery of costs it incurs from these projects from its state commissions and FERC customers.
 
 
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2011 Indiana Base Rate Case

In 2013, the IURC issued an order that granted a $92 million annual increase in base rates based upon a return on common equity of 10.2%.  In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal of the orders with the Indiana Court of Appeals.  In September 2013, the OUCC filed a brief on appeal that included objections to certain aspects of the rate case.  If any part of the IURC order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.  See the “2011 Indiana Base Rate Case” section of Note 4.

2014 Oklahoma Base Rate Case

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity.  This revenue increase includes a proposed increase in depreciation rates of $29 million.  In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three.  The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional types of transmission costs that are expected to increase over the next several years.

Rockport Plant Clean Coal Technology Project (CCT Project)

In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both units of the Rockport Plant with a dry sorbent injection system.  The estimated cost in the application was $285 million, excluding AFUDC to be shared equally between I&M and AEGCo.  In November 2013, the IURC approved a settlement agreement that included the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M’s ownership share.  As of December 31, 2013, we have incurred costs of $109 million related to the CCT Project, including AFUDC.  See the “Rockport Plant Clean Coal Technology Project (CCT Project)” section of Note 4.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its licensed life (2034 for Unit 1 and 2037 for Unit 2).  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of December 31, 2013, I&M has incurred costs of $380 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items which the IURC stated I&M could seek recovery of in a subsequent base rate case.  I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings.  The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates.  In October 2013, I&M filed an application with the IURC for LCM rider rates effective January 2014.  In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC.

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to the approved projects effective January 2013 until these costs are included in rates.  In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON.

If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.  See “Cook Plant Life Cycle Management Project (LCM Project)” section of Note 4.
 
 
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Repositioning Efforts

In April 2012, we initiated a process to identify strategic repositioning opportunities and efficiencies that resulted in sustainable cost savings.  This process included evaluations of our employee and retiree benefit programs as well as evaluations of the functional effectiveness and staffing levels of our finance and accounting, information technology, generation and supply chain and procurement organizations.  While we have completed certain aspects of this program, our continuous improvement initiatives in generation, distribution, transmission, supply chain, procurement and the corporate center continues to yield cost savings for many of our subsidiaries, allowing us to direct many of these savings into infrastructure and other areas of our business.

LITIGATION

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, we cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  We assess the probability of loss for each contingency and accrue a liability for cases that have a probable likelihood of loss if the loss can be estimated.  For details on our regulatory proceedings and pending litigation see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

Rockport Plant Litigation

In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit.  The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement.  The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff.  The New York court has granted our motion to transfer this case to the U.S. District Court for the Southern District of Ohio.  Our motion to dismiss the case, filed in October 2013, is pending.  We will continue to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

ENVIRONMENTAL ISSUES

We are implementing a substantial capital investment program and incurring additional operational costs to comply with environmental control requirements.  We will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO 2 , NO x , PM and hazardous air pollutants (HAPs) from fossil fuel-fired power plants, proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.
 
We are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of our nuclear units.  We, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court.  We are also engaged in the development of possible future requirements including the items discussed below and reductions of CO 2 emissions to address concerns about global climate change.  We believe that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If we are unable to recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.
 
 
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Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  We continue to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of December 31, 2013, the AEP System had a total generating capacity of nearly 37,600 MWs, of which over 23,700 MWs are coal-fired.  We continue to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on our coal-fired generating facilities.  Based upon our estimates, investment to meet these proposed requirements ranges from approximately $3 billion to $3.5 billion between 2013 and 2020.  These amounts include investments to convert some of our coal generation to natural gas.  If natural gas conversion is not completed, these units could be retired sooner than planned.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules.  The cost estimates will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans or federal implementation plans that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on our units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.  In addition, we are continuing to evaluate the economic feasibility of environmental investments on nonregulated plants.

Subject to the factors listed above and based upon our continuing evaluation, we intend to retire the following plants or units of plants before or during 2016:

 
 
 
 
Generating
Company
 
Plant Name and Unit
 
Capacity
 
 
 
 
(in MWs) 
APCo
 
Clinch River Plant, Unit 3
 
 
 235 
APCo
 
Glen Lyn Plant
 
 
 335 
APCo
 
Kanawha River Plant
 
 
 400 
APCo/AGR
 
Sporn Plant, Units 1-4
 
 
 600 
I&M
 
Tanners Creek Plant, Units 1-4
 
 
 995 
KPCo
 
Big Sandy Plant, Unit 2
 
 
 800 
AGR
 
Kammer Plant
 
 
 630 
AGR
 
Muskingum River Plant, Units 1-5
 
 
 1,440 
AGR
 
Picway Plant
 
 
 100 
PSO
 
Northeastern Station, Unit 4
 
 
 470 
SWEPCo
 
Welsh Plant, Unit 2
 
 
 528 
Total
 
 
 
 
 6,533 

As of December 31, 2013, the net book value of the AGR units listed above was zero.  The net book value, before cost of removal, including related material and supplies inventory and CWIP balances of the other plants in the table above was $1 billion.  See Note 5 for further discussion.

In 2013, we re-evaluated potential courses of action with respect to the planned operation of Muskingum River Plant, Unit 5 and concluded that completion of a refueling project which would extend the unit’s useful life is remote.  As a result, in 2013, we completed an impairment analysis and recorded a $154 million pretax ($99 million, net of tax) impairment charge for AGR’s net book value of Muskingum River Plant, Unit 5.  We expect to retire the plant no later than 2015.  See “Muskingum River Plant, Unit 5” section of Note 7.
 
 
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In addition, we are in the process of obtaining permits and other necessary regulatory approvals for either the conversion of some of our coal units to natural gas or installing emission control equipment on certain units.  The following table lists the plants or units that are either awaiting regulatory approval or are still being evaluated by management based on changes in emission requirements and demand for power:

 
 
 
 
Generating
Company
 
Plant Name and Unit
 
Capacity
 
 
 
 
(in MWs) 
KPCo
 
Big Sandy Plant, Unit 1
 
 
 278 
PSO
 
Northeastern Station, Unit 3
 
 
 470 
Total
 
 
 
 
 748 

As of December 31, 2013, the net book value before cost of removal, including related material and supplies inventory and CWIP balances, of the plants in the table above was $295 million.

Volatility in natural gas prices, pending environmental rules and other market factors could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of coal-fired units.  For regulated plants that we may close early, we are seeking regulatory recovery of remaining net book values.  To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows.

Modification of the NSR Litigation Consent Decree

In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between the AEP subsidiaries in the eastern area of the AEP System and the Department of Justice, the Federal EPA, eight northeastern states and other interested parties to settle claims that the AEP subsidiaries violated the NSR provisions of the CAA when it undertook various equipment repair and replacement projects over a period of nearly 20 years.  The consent decree’s terms include installation of environmental control equipment on certain generating units, a declining cap on SO 2 and NO x emissions from the AEP System and various mitigation projects.

The original consent decree required certain types of control equipment to be installed at Muskingum River Plant, Unit 5, Big Sandy Plant, Unit 2 and the two units of the Rockport Plant in 2015, 2017 and 2019, respectively.  In January 2013, an agreement to modify the consent decree was reached and filed with the court.  The terms of the agreement include more options for the affected units (including alternative control technologies, re-fueling and/or retirement), more stringent SO 2 emission caps for the AEP System and additional mitigation measures.  The modified consent decree was approved by the court in May 2013.  For the units of the Rockport Plant, the modified decree requires installation of dry sorbent injection technology for SO 2 control on both units in 2015.  In addition, the consent decree imposes a declining plant-wide cap on SO 2 emissions beginning in 2016.

Oklahoma Environmental Compliance Plan

In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES), Unit 4 in 2016 and additional environmental controls on NES, Unit 3 to continue operations through 2026.  As of December 31, 2013, the net book values of NES, Units 3 and 4 were $208 million and $106 million, respectively, before cost of removal, including materials and supplies inventory and CWIP.  In August 2013, the OCC dismissed PSO’s environmental compliance plan case without prejudice but will permit PSO to seek recovery in a future proceeding.  PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan.  If PSO is ultimately not permitted to fully recover its net book value of NES, Units 3 and 4 and other environmental compliance costs, it could reduce future net income and cash flows and impact financial condition.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions.  The states implement and administer many of these programs and could impose additional or more stringent requirements.
 
 
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The Federal EPA issued the Clean Air Interstate Rule (CAIR) in 2005 requiring specific reductions in SO 2 and NO x emissions from power plants.  In 2008, the District of Columbia Circuit Court of Appeals issued a decision remanding CAIR to the Federal EPA.  The Federal EPA issued the Cross-State Air Pollution Rule (CSAPR) (discussed in detail below) in August 2011 to replace CAIR.  The CSAPR was challenged in the courts.  The U.S. Court of Appeals for the District of Columbia Circuit issued an order in December 2011 staying the effective date of the rule pending judicial review.  In 2012, a panel of the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing CAIR until a replacement rule is finalized.  That decision has been appealed to the U.S. Supreme Court.  Nearly all of the states in which our power plants are located are covered by CAIR.

The Federal EPA issued the final maximum achievable control technology (MACT) standards for coal and oil-fired power plants (discussed in detail below) in 2012.

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) to address regional haze in federal parks and other protected areas.  BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.  CAVR will be implemented through individual state implementation plans (SIPs) or, if SIPs are not adequate or are not developed on schedule, through federal implementation plans (FIPs).  The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas.  The Arkansas SIP was disapproved and the state is developing a revised submittal.  In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the CSAPR trading programs to use those programs in place of source-specific BART for SO 2 and NO x emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states.  This rule is being challenged in the U.S. Court of Appeals for the District of Columbia Circuit and its fate is uncertain given developments in the CSAPR litigation.

In 2009, the Federal EPA issued a final mandatory reporting rule for CO 2 and other greenhouse gases covering a broad range of facilities emitting in excess of 25,000 tons of CO 2 emissions per year.   The Federal EPA issued a final endangerment finding for greenhouse gas emissions from new motor vehicles in 2009.  The Federal EPA determined that greenhouse gas   emissions from stationary sources will be subject to regulation under the CAA beginning January 2011 and finalized its proposed scheme to streamline and phase-in regulation of stationary source CO 2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs through the issuance of final federal rules, SIP calls and FIPs.  The Federal EPA has proposed to include CO 2 emissions in standards that apply to new electric utility units and will consider whether such standards are appropriate for other source categories in the future.

The Federal EPA has also issued new, more stringent national ambient air quality standards (NAAQS) for PM, SO 2 , NO x and lead, and is currently reviewing the NAAQS for ozone.  States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for our facilities as a result of those evaluations.  We cannot currently predict the nature, stringency or timing of those requirements.

Notable developments in significant CAA regulatory requirements affecting our operations are discussed in the following sections.

Cross-State Air Pollution Rule (CSAPR)

In 2011, the Federal EPA issued CSAPR.  Certain revisions to the rule were finalized in 2012.  CSAPR relies on newly-created SO 2 and NO x allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states.  Interstate trading of allowances is allowed on a restricted sub-regional basis.  Arkansas and Louisiana are subject only to the seasonal NO x program in the rule.  Texas is subject to the annual programs for SO 2 and NO x in addition to the seasonal NO x program.  The annual SO 2 allowance budgets in Indiana, Ohio and West Virginia were reduced significantly in the rule.  A supplemental rule includes Oklahoma in the seasonal NO x program.  The supplemental rule was finalized in December 2011 with an increased NO x emission budget for the 2012 compliance year.  The Federal EPA issued a final Error Corrections Rule and further CSAPR revisions in 2012 to make corrections to state budgets and unit allocations and to remove the restrictions on interstate trading in the first phase of CSAPR.
 
 
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Numerous affected entities, states and other parties filed petitions to review the CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit.  Several of the petitioners filed motions to stay the implementation of the rule pending judicial review.  In 2011, the court granted the motions for stay.  In 2012, the panel issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing the Clean Air Interstate Rule until a replacement rule is finalized.  The majority determined that the CAA does not allow the Federal EPA to “overcontrol” emissions in an upwind state and that the Federal EPA exceeded its statutory authority by failing to allow states an opportunity to develop their own implementation plans before issuing a FIP.  The Federal EPA and other respondents filed petitions for rehearing but in January 2013, the U.S. Court of Appeals for the District of Columbia Circuit denied all petitions for rehearing.  The petition for further review filed by the Federal EPA and other parties in the U.S. Supreme Court was granted in June 2013.  Separate appeals of the supplemental rule, the Error Corrections Rule and the further revisions have been filed, but are being held in abeyance.

The time frames and stringency of the required emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and our electric utility customers.  We cannot predict the outcome of the pending litigation.

Mercury and Other Hazardous Air Pollutants Regulation

In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal on a site-wide 30-day rolling average basis.  In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  The effective date of the final rule was April 16, 2012 and compliance is required within three years.  We are participating through various organizations in the petitions for administrative reconsideration and judicial review that have been filed.  In 2012, the Federal EPA published a notice announcing that it would accept comments on its reconsideration of certain issues related to the new source standards, including clarification of the requirements that apply during periods of start-up and shut down, measurement issues and the application of variability factors that may have an impact on the level of the standards.  The Federal EPA issued revisions to the new source standards consistent with the proposed rule, except the start-up and shut down provisions in March 2013.  The Federal EPA is still considering additional changes to the start-up and shut down provisions.

The final rule contains a slightly less stringent PM limit for existing sources than the original proposal and allows operators to exclude periods of start-up and shut down from the emissions averaging periods.  The compliance time frame remains a serious concern.  A one-year administrative extension may be available if the extension is necessary for the installation of controls or to avoid a serious reliability problem.  In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades.  We are concerned about the availability of compliance extensions and the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines.  We are participating in petitions for review filed in the U.S. Court of Appeals for the District of Columbia Circuit by several organizations of which we are members.  Certain issues related to the standards for new coal-fired units have been severed from the main case and are being held in abeyance pending completion of the Federal EPA’s reconsideration proceeding.  The case is briefed and argued, and remains pending before the court.

Regional Haze

In 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze SIP submitted by the State of Oklahoma through the Department of Environmental Quality.  The Federal EPA proposed to approve all of the NO x control measures in the SIP and disapprove the SO 2 control measures for six electric generating units, including two units owned by PSO.  The Federal EPA finalized a FIP that would require these units to install technology capable of reducing SO 2 emissions to 0.06 pounds per million British thermal units within five years of the effective date of the FIP.  PSO filed a petition for review of the FIP in the Tenth Circuit Court of Appeals and engaged in settlement discussions with the Federal EPA, the State of Oklahoma and other parties.  In November 2012, we notified the court that the parties had reached agreement on a settlement that would provide for submission of a revised Regional Haze SIP requiring the retirement of one coal-fired unit of PSO’s Northeastern Station no later
 
 
11

 
than 2016, installation of emission controls on the second coal-fired Northeastern unit in 2016 and retirement of the second unit no later than 2026.  The Tenth Circuit Court of Appeals is holding the appeal in abeyance pending implementation of the settlement.  A revised regional haze SIP was adopted by the State of Oklahoma and the Federal EPA approved the revised SIP in February 2014.  Upon publication of the final approval and withdrawal of the FIP, the Tenth Circuit proceeding will be dismissed.

CO 2 Regulation

In March 2012, the Federal EPA issued a proposal to regulate CO 2 emissions from new fossil fuel-fired electricity generating units.  The proposed rule establishes a new source performance standard of 1,000 pounds of CO 2 per megawatt hour of electricity generated, a rate that most natural gas combined cycle units can meet, but that is substantially below the emission rate of a new pulverized coal generator or an integrated gas combined cycle unit that uses coal for fuel.  As proposed, the rule does not apply to new gas-fired stationary combustion turbines used as peaking units, does not apply to existing, modified or reconstructed sources and does not apply to units whose CO 2 emission rate increases as a result of the addition of pollution control equipment to control criteria pollutant emissions or HAPs.  The rule is not anticipated to have a significant immediate impact on the AEP System since it does not apply to existing units or units that have already commenced construction.  New source performance standards affect units that have not yet received permits.  The proposed standards were challenged in the U.S. Court of Appeals for the District of Columbia Circuit.  That case was dismissed because the court determined that no final agency action had yet been taken.

In June 2013, President Obama issued a memorandum to the Administrator of the Federal EPA directing the agency to develop and issue a new proposal regulating carbon emissions from new electric generating units in September 2013.  The new proposal was issued in September 2013 and requires new large natural gas units to meet 1,000 pounds of CO 2 per MWh of electricity generated and small natural gas units to meet 1,100 pounds of CO 2 per MWh.  New coal-fired units are required to meet the 1,100 pounds of CO 2 per MWh limit, with the option to meet the tighter limits if they choose to average emissions over multiple years.  This proposal was published in the Federal Register in January 2014 and the March 2012 proposal has been withdrawn.

The Federal EPA was also directed to develop and issue a separate proposal regulating carbon emissions from existing, modified and reconstructed electric generating units before June 2014, to finalize those standards by June 2015 and to require states to submit revisions to their implementation plans including such standards no later than June 2016.  The President directed the Federal EPA, in developing this proposal, to directly engage states, leaders in the power sector, labor leaders and other stakeholders, to tailor the regulations to reduce costs, to develop market-based instruments and allow regulatory flexibilities and “assure that the standards are developed and implemented in a manner consistent with the continued provision of reliable and affordable electric power.”  We cannot currently predict the impact these programs may have on future resource plans or our existing generating fleet, but the costs may be substantial.

In June 2012, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision upholding, in all material respects, the Federal EPA’s endangerment finding, its regulatory program for CO 2 emissions from new motor vehicles and its plan to phase in regulation of CO 2 emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs.  A petition for rehearing was filed which the court denied in December 2012.  The U.S. Supreme Court granted several petitions for review and will determine whether the Federal EPA made a reasonable determination that adoption of the motor vehicle standards trigger PSD and Title V permitting obligations for stationary sources.  A decision is expected by June 2014.

The Federal EPA also finalized a rule in June 2012 that retains the current thresholds for permitting stationary sources under the PSD and Title V operating permit programs at 100,000 tons per year for new sources and 75,000 tons per year for modified sources.  The Federal EPA also confirmed that it will re-evaluate these thresholds during its five-year review in 2016.  Our generating units are large sources of CO 2 emissions and we will continue to evaluate the permitting obligations in light of these thresholds.
 
 
12

 

Coal Combustion Residual Rule

In 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units.  The rule contains two alternative proposals.  One proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management.  Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and initiate closure within five years of the issuance of a final rule.  In 2011, the Federal EPA issued a notice of data availability requesting comments on a number of technical reports and other data received during the comment period for the original proposal and requesting comments on potential modeling analyses to update its risk assessment.  In 2013, the Federal EPA also issued a notice of data availability requesting comments on a narrow set of items.

Various environmental organizations and industry groups filed a petition seeking to establish deadlines for a final rule.  The Federal EPA opposed the petition and sought additional time to coordinate the issuance of a final rule with the issuance of new effluent limitations under the Clean Water Act for utility facilities.  In October 2013, the U.S. District Court for the District of Columbia issued a final order partially ruling in favor of the Federal EPA for dismissal of two counts, ruling in favor of the environmental organizations on one count and directing the Federal EPA to provide the court with a proposed schedule for completion of the rulemaking.  In January 2014, the parties filed a motion with the court to establish December 2014 as the Federal EPA’s deadline for publication of the rule.  The court will establish a deadline for the final rule following a comment period for interested parties.

In February 2014, the Federal EPA completed an evaluation of the beneficial uses of coal fly ash in concrete and wallboard and concluded that the Federal EPA supports these beneficial uses.   Currently, approximately 40% of the coal ash and other residual products from our generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses.  Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes.  In addition, we currently use surface impoundments and landfills to manage these materials at our generating facilities and will incur significant costs to upgrade or close and replace these existing facilities under the proposed solid waste management alternative.  Regulation of these materials as hazardous wastes would significantly increase these costs.  As the rule is not final, we are unable to determine a range of potential costs that are reasonably possible of occurring but expect the costs to be significant.

Clean Water Act Regulations

In 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement.  Compliance with this standard is required within eight years of the effective date of the final rule.  The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment.  The proposed entrainment standard for new units at existing facilities requires either intake flows commensurate with closed cycle cooling or achieving entrainment reductions equivalent to 90% or greater of the reductions that could be achieved with closed cycle cooling.  Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority.  We are evaluating the proposal and engaged in the collection of additional information regarding the feasibility of implementing this proposal at our facilities.  In June 2012, the Federal EPA issued additional Notices of Data Availability and requested public comments.  We submitted comments in July 2012.  Issuance of a final rule is expected in 2014.  We are preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.
 
 
13

 

In addition, the Federal EPA issued an information collection request and is developing revised effluent limitation guidelines for electricity generating facilities.  A proposed rule was signed in April 2013 with a final rule expected in 2014.  The Federal EPA proposed eight options of increasing stringency and cost for fly ash and bottom ash transport water, scrubber wastewater, leachate from coal combustion byproduct landfills and impoundments and other wastewaters associated with coal-fired generating units, with four labeled preferred options.  Certain of the Federal EPA's preferred options have already been implemented or are part of our long-term plans.  We continue to review the proposal in detail to evaluate whether our plants are currently meeting the proposed limitations, what technologies have been incorporated into our long-range plans and what additional costs might be incurred if the Federal EPA's most stringent options were adopted.  We submitted detailed comments to the Federal EPA in September 2013 and participated in comments filed by various organizations of which we are members.

Climate Change

National public policy makers and regulators in the 11 states we serve have diverse views on climate change.  We are currently focused on responding to these emerging views with prudent actions, such as improving energy efficiency, investing in developing cost-effective and less carbon-intensive technologies and evaluating our assets across a range of plausible scenarios and outcomes.  We are also active participants in a variety of public policy discussions at state and federal levels to assure that proposed new requirements are feasible and the economies of the states we serve are not placed at a competitive disadvantage.

While comprehensive economy-wide regulation of CO 2 emissions might be achieved through future legislation, Congress has yet to enact such legislation.  The Federal EPA continues to take action to regulate CO 2 emissions under the existing requirements of the CAA.

Several states have adopted programs that directly regulate CO 2 emissions from power plants.  The majority of the states where we have generating facilities have passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements.  We are taking steps to comply with these requirements.  In order to meet these requirements and as a key part of our corporate sustainability effort, we pledged to increase our wind power.

We have taken measurable, voluntary actions to reduce and offset our CO 2 emissions.  We estimate that our 2013 emissions were approximately 115 million metric tons.  This represents a reduction of 21% compared to our 2005 CO 2  emissions of approximately 145 million metric tons.

Future federal and state legislation or regulations that mandate limits on the emission of CO 2 could result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs.  Excessive costs to comply with future legislation or regulations might force our utility subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets.  Public perception may ultimately have a significant impact on future legislation and regulation that could adversely affect our ability to recover our investments in coal-fired plants.

Climate change and its resultant impact on weather patterns could modify our customers’ power usage.  Our customers’ energy needs currently vary with weather conditions and the economy.  Increased or decreased energy usage could require the acquisition or construction of more generation and transmission assets or cause early retirement of such assets.  The timing and duration of extreme weather conditions may require more system backup and contribute to increased system stresses, including service interruptions and increased storm restoration costs.  Extreme weather conditions that create high energy demand could raise electricity prices, which could increase the cost of energy we provide to our customers and could provide opportunity for increased wholesale sales and higher margins.

To the extent climate change affects a region’s economic health, it could also affect our revenues.  Our financial performance is tied to the health of the regional economies we serve.  The price of energy, as a factor in a region's cost of living as well as an important input into the cost of goods, has an impact on the economic health of our communities.  The cost of additional regulatory requirements would normally be borne by consumers through higher prices for energy and purchased goods.


 
14

 


RESULTS OF OPERATIONS

SEGMENTS

Our primary business is the generation, transmission and distribution of electricity.  Within our Vertically Integrated Utilities segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

During the fourth quarter of 2013, we realigned our business segments as a result of corporate separation and plant transfers.  We retrospectively adjusted 2012 and 2011 segment information to reflect our new business segments.  See the “Corporate Separation” section of Executive Overview.

Our reportable segments and their related business activities are outlined below:

Vertically Integrated Utilities

·
Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

·
Transmission and distribution   of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC.
·
OPCo purchases energy and capacity to serve remaining generation service customers.

Generation & Marketing

·
Nonregulated generation in ERCOT and PJM.
·
Marketing, risk management and retail activities in ERCOT, PJM and MISO.

AEP Transmission Holdco

·
Development, construction and operation of transmission facilities through investments in our wholly-owned transmission only subsidiaries and transmission only joint ventures.  These investments have PUCT-approved or FERC-approved returns on equity.

AEP River Operations

·
Commercial barging operations that transports liquids, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.

The table below presents Income Before Extraordinary Item by segment for the years ended December 31, 2013, 2012 and 2011.

 
 
 Years Ended December 31,
 
 
2013 
 
2012 
 
2011 
 
 
(in millions)
Vertically Integrated Utilities
$
 681 
 
$
 803 
 
$
 710 
Transmission and Distribution Utilities
 
 358 
 
 
 389 
 
 
 404 
Generation & Marketing
 
 228 
 
 
 100 
 
 
 439 
AEP Transmission Holdco
 
 80 
 
 
 43 
 
 
 30 
AEP River Operations
 
 12 
 
 
 15 
 
 
 45 
Corporate and Other (a)
 
 125 
 
 
 (88)
 
 
 (52)
Income Before Extraordinary Item
$
 1,484 
 
$
 1,262 
 
$
 1,576 

(a)
While not considered a reportable segment, Corporate and Other primarily includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries.  This segment also includes parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
 
 
15

 

 
AEP CONSOLIDATED

2013 Compared to 2012

Income Before Extraordinary Item increased from $1,262 million in 2012 to $1,484 million in 2013 primarily due to:

·
Successful rate proceedings in our various jurisdictions.
·
2012 impairments of certain Ohio generation plants.
·
A decrease in Ohio depreciation expense due to impairments of certain Ohio generation plants.
·
A favorable U.K. Windfall Tax decision by the U.S. Supreme Court in 2013.

These increases were partially offset by:

·
Impairments during 2013 for the following:
 
·
Muskingum River Plant, Unit 5.
 
·
A write-off from a disallowance of a portion of Amos Plant, Unit 3 pursuant to a Virginia SCC order.
 
·
A decision from the KPSC disallowing scrubber costs on KPCo's Big Sandy Plant.
·
The loss of retail generation customers in Ohio to various CRES providers.
·
2012 reversal of a 2011 recorded obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of OPCo's modified stipulation.

2012 Compared to 2011

Income Before Extraordinary Item decreased from $1,576 million in 2011 to $1,262 million in 2012 primarily due to:

·
A decrease in carrying costs income due to the recognition in 2011 of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005 and a related favorable 2011 resolution of contested tax items related to the TCC stranded cost settlement.
·
2012 impairments of certain Ohio generation plants.
·
The loss of retail generation customers in Ohio to various CRES providers.
·
A decrease in weather-related usage.
·
The elimination of POLR charges, effective June 2011, partially offset by the 2011 provision for refund of POLR charges.  The refund provision was recorded as a result of the October 2011 PUCO remand order.
·
Expenses associated with the early retirement of Parent debt in 2012.
·
Expenses related to the 2012 sustainable cost reductions.
·
The 2012 adjustment of a U.K. Windfall Tax provision as a result of a related Supreme Court case.

These decreases were partially offset by:

·
Successful rate proceedings in our various jurisdictions.
·
Lower spending in 2012 as a result of our cost containment efforts.
·
A 2011 recording and subsequent 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of OPCo's modified stipulation.
·
The 2011 plant impairments for Sporn Plant, Unit 5 and for the FGD project at Muskingum River Plant, Unit 5.
·
The 2011 write-off related to SWEPCo's expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap as a result of the November 2011 Texas Court of Appeals decision.
·
A loss incurred in 2011 related to a settlement of litigation with BOA and Enron.

Our results of operations are discussed below by operating segment.


 
16

 


VERTICALLY INTEGRATED UTILITIES

 
 
 
Years Ended December 31,
Vertically Integrated Utilities
 
2013 
 
2012 
 
2011 
 
 
 
(in millions)
Revenues
 
$
 9,992 
 
$
 9,418 
 
$
 9,702 
Fuel and Purchased Electricity
 
 
 4,770 
 
 
 4,408 
 
 
 4,870 
Gross Margin
 
 
 5,222 
 
 
 5,010 
 
 
 4,832 
Other Operation and Maintenance
 
 
 2,276 
 
 
 2,219 
 
 
 2,237 
Asset Impairments and Other Related Charges
 
 
 72 
 
 
 13 
 
 
 49 
Depreciation and Amortization
 
 
 941 
 
 
 873 
 
 
 785 
Taxes Other Than Income Taxes
 
 
 372 
 
 
 344 
 
 
 339 
Operating Income
 
 
 1,561 
 
 
 1,561 
 
 
 1,422 
Interest and Investment Income
 
 
 7 
 
 
 5 
 
 
 13 
Carrying Costs Income
 
 
 14 
 
 
 28 
 
 
 17 
Allowance for Equity Funds Used During Construction
 
 
 35 
 
 
 72 
 
 
 82 
Interest Expense
 
 
 (540)
 
 
 (520)
 
 
 (514)
Income Before Income Tax Expense and Equity Earnings
 
 
 1,077 
 
 
 1,146 
 
 
 1,020 
Income Tax Expense
 
 
 398 
 
 
 345 
 
 
 312 
Equity Earnings of Unconsolidated Subsidiaries
 
 
 2 
 
 
 2 
 
 
 2 
Income Before Extraordinary Item
 
$
 681 
 
$
 803 
 
$
 710 

Summary of KWh Energy Sales for Vertically Integrated Utilities
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
 
(in millions of KWhs)
Retail:
 
 
 
 
 
 
 
 
 
Residential
 
 33,851 
 
 
 33,199 
 
 
 35,135 
 
Commercial
 
 25,037 
 
 
 25,278 
 
 
 25,651 
 
Industrial
 
 34,216 
 
 
 34,692 
 
 
 34,333 
 
Miscellaneous
 
 2,284 
 
 
 2,356 
 
 
 2,349 
Total Retail
 
 95,388 
 
 
 95,525 
 
 
 97,468 
 
 
 
 
 
 
 
 
 
Wholesale
 
 31,919 
 
 
 28,671 
 
 
 28,290 
 
 
 
 
 
 
 
 
 
Total KWhs
 
 127,307 
 
 
 124,196 
 
 
 125,758 
 
 
 
 
 
 
 
 
 
 


 
17

 


Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.  In general, degree day changes in our eastern region have a larger effect on net income than changes in our western region due to the relative size of the two regions and the number of customers within each region.

Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
2013 
 
2012 
 
2011 
 
 
(in degree days)
Eastern Region
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 2,949 
 
 
 2,216 
 
 
 2,566 
Normal - Heating (b)
 
 2,734 
 
 
 2,774 
 
 
 2,772 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 1,040 
 
 
 1,253 
 
 
 1,280 
Normal - Cooling (b)
 
 1,080 
 
 
 1,079 
 
 
 1,066 
 
 
 
 
 
 
 
 
 
 
Western Region
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 1,772 
 
 
 1,070 
 
 
 1,582 
Normal - Heating (b)
 
 1,501 
 
 
 1,537 
 
 
 1,534 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 2,163 
 
 
 2,635 
 
 
 2,830 
Normal - Cooling (b)
 
 2,202 
 
 
 2,186 
 
 
 2,165 
 
 
 
 
 
 
 
 
 
 
(a)
Eastern Region and Western Region heating degree days are calculated on a 55 degree temperature base.
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
(c)
Eastern Region and Western Region cooling degree days are calculated on a 65 degree temperature base.

 
18

 

2013 Compared to 2012
 
Reconciliation of Year Ended December 31, 2012 to Year Ended December 31, 2013
Income from Vertically Integrated Utilities Before Extraordinary Item
(in millions)
Year Ended December 31, 2012
 
 
 
 
$
 803 
 
 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
 
 
Retail Margins
 
 
 
 
 
 196 
Off-system Sales
 
 
 
 
 
 (26)
Transmission Revenues
 
 
 
 
 
 41 
Other Revenues
 
 
 
 
 
 1 
Total Change in Gross Margin
 
 
 
 
 
 212 
 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
 
 
Other Operation and Maintenance
 
 
 
 
 
 (57)
Asset Impairments and Other Related Charges
 
 
 
 
 
 (59)
Depreciation and Amortization
 
 
 
 
 
 (68)
Taxes Other Than Income Taxes
 
 
 
 
 
 (28)
Interest and Investment Income
 
 
 
 
 
 2 
Carrying Costs Income
 
 
 
 
 
 (14)
Allowance for Equity Funds Used During Construction
 
 
 
 
 
 (37)
Interest Expense
 
 
 
 
 
 (20)
Total Change in Expenses and Other
 
 
 
 
 
 (281)
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 
 
 
 (53)
 
 
 
 
 
 
 
 
Year Ended December 31, 2013
 
 
 
 
$
 681 

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:

·
Retail Margins increased $196 million primarily due to the following:
 
·
Successful rate proceedings in our service territories, which include:
   
·
A $153 million rate increase for SWEPCo.
   
·
A $112 million rate increase for I&M.
   
·
A $9 million rate increase for APCo.
     
For the rate increases described above, $42 million relates to riders/trackers which have corresponding increases in other expense items below.
 
·
A $29 million increase in weather-related usage in our eastern and western regions primarily due to increases of 33% and 66%, respectively, in heating degree days partially offset by decreases in our eastern and western regions of 17% and 18%, respectively, in cooling degree days.
 
These increases were partially offset by:
 
·
A $15 million decrease in SWEPCo's municipal and cooperative revenues primarily due to lower realizations from changes in sales volume mix.
 
·
A $23 million decrease due to lower weather normalized retail sales.
 
·
A $12 million increase in other variable electric generation expenses.
 
·
A $9 million deferral of APCo's additional wind purchase costs in 2012 as a result of the June 2012 Virginia SCC fuel factor order.
 
·
A $9 million decrease due to adjustments for previously disallowed environmental costs by the November 2011 Virginia SCC order subsequently determined in 2012 to be appropriate for recovery by the Supreme Court of Virginia.
·
Margins from Off-system Sales decreased $26 million primarily due to lower PJM capacity revenue, reduced trading and marketing margins, partially offset by higher prices and volumes.
·
Transmission Revenues increased $41 million primarily due to increased investment in the PJM and SPP regions.  These increased revenues are offset-in-part in Other Operation and Maintenance expenses below.

 
19

 
Expenses and Other and Income Tax Expense changed between years as follows:

·
Other Operation and Maintenance expenses increased $57 million primarily due to the following:
 
·
A $33 million increase in recoverable PJM and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers.
 
·
A $30 million write-off in 2013 of previously deferred 2012 Virginia storm costs resulting from the 2013 enactment of a Virginia law.
 
·
A $22 million increase in storm-related expenses primarily in APCo's service territory.
 
·
A $21 million increase in plant outage expenses.
 
These increases were partially offset by:
 
·
A $26 million decrease due to expenses related to the 2012 sustainable cost reductions.
 
·
A $25 million decrease due to an agreement reached to settle an insurance claim in 2013.
·
Asset Impairments and Other Related Charges increased $59 million primarily due to the following:
 
·
A $39 million increase due to APCo's 2013 write-off from a regulatory disallowance of a portion of Amos Plant, Unit 3 pursuant to a Virginia SCC order approving the transfer of Amos Plant, Unit 3.
 
·
A $33 million increase due to KPCo's 2013 write-off of scrubber costs on the Big Sandy Plant and other generation costs in accordance with a KPSC's October 2013 order.
 
These increases were partially offset by:
 
·
A 2012 write-off of an additional $13 million related to SWEPCo's expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap.
·
Depreciation and Amortization expenses increased $68 million primarily due to the following:
 
·
A $40 million increase due to the Turk Plant being placed in service in December 2012.
 
·
A $26 million increase due to higher depreciable base and higher depreciation rates reflecting a change in Tanners Creek Plant's estimated life approved by the MPSC effective April 2012 and by the IURC effective March 2013.  The majority of the increase in depreciation for Tanners Creek Plant's life is offset within Gross Margin.
 
·
Overall higher depreciable property balances.
 
These increases were partially offset by:
 
·
A $13 million decrease in amortization as a result of the cessation of the Virginia Environmental and Reliability surcharge and the Virginia Environmental Rate Adjustment Clause in January 2013 and March 2013, respectively.
·
Taxes Other Than Income Taxes increased $28 million primarily due to increased property taxes as a result of increased capital investments.
·
Carrying Costs Income decreased $14 million primarily due to an increased recovery of Virginia environmental costs in new base rates as approved by the Virginia SCC in late January 2012 and decreased carrying charges related to the Dresden Plant.
·
Allowance for Equity Funds Used During Construction decreased $37 million primarily due to completed construction of the Turk Plant in December 2012.
·
Interest Expense increased $20 million primarily due to a decrease in the debt component of AFUDC due to completed construction of the Turk Plant in December 2012 partially offset by lower average outstanding long-term debt balances and an increase in the debt component of AFUDC related to projects at the Cook Plant.
·
Income Tax Expense increased $53 million primarily due to the recording of federal and state income tax adjustments and other book/tax differences which are accounted for on a flow-through basis, offset-in-part by a decrease in pretax book income.

 
20

 

2012 Compared to 2011
 
Reconciliation of Year Ended December 31, 2011 to Year Ended December 31, 2012
Income from Vertically Integrated Utilities Before Extraordinary Item
(in millions)

Year Ended December 31, 2011
 
 
 
 
$
 710 
 
 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
 
 
Retail Margins
 
 
 
 
 
 181 
Off-system Sales
 
 
 
 
 
 (13)
Transmission Revenues
 
 
 
 
 
 19 
Other Revenues
 
 
 
 
 
 (9)
Total Change in Gross Margin
 
 
 
 
 
 178 
 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
 
 
Other Operation and Maintenance
 
 
 
 
 
 18 
Asset Impairments and Other Related Charges
 
 
 
 
 
 36 
Depreciation and Amortization
 
 
 
 
 
 (88)
Taxes Other Than Income Taxes
 
 
 
 
 
 (5)
Interest and Investment Income
 
 
 
 
 
 (8)
Carrying Costs Income
 
 
 
 
 
 11 
Allowance for Equity Funds Used During Construction
 
 
 
 
 
 (10)
Interest Expense
 
 
 
 
 
 (6)
Total Change in Expenses and Other
 
 
 
 
 
 (52)
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 
 
 
 (33)
 
 
 
 
 
 
 
 
Year Ended December 31, 2012
 
 
 
 
$
 803 

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:

·
Retail Margins increased $181 million primarily due to the following:
 
·
A $130 million increase due to lower capacity settlement expenses under the Interconnection Agreement, net of recovery in West Virginia and environmental deferrals in Virginia.  This increase was primarily a result of a mild winter in 2012 and its impact on APCo's winter peak, APCo's completion of the Dresden Plant in January 2012 and the removal of Sport Plant, Unit 5 from the Interconnection Agreement in September 2011.
 
·
Successful rate proceedings in our service territories which include:
   
·
An $87 million rate increase for APCo.
   
·
A $17 million rate increase for I&M.
   
·
A $13 million rate increase for PSO.
   
·
An $11 million rate increase for WPCo.
     
For the rate increases described above, $99 million relates to riders/trackers which have corresponding increases in other expense items below.
 
·
A $24 million write-off in 2011 related to APCo's disallowance of certain Virginia environmental costs incurred in 2009 and 2010 as a result of a November 2011 Virginia SCC order.
 
·
A $9 million deferral of APCo's additional wind purchase costs in 2012 as a result of a June 2012 Virginia SCC fuel factor order.
 
·
A $9 million increase due to adjustments for previously disallowed environmental costs by the November 2011 Virginia SCC order subsequently determined in 2012 to be appropriate for recovery by the Supreme Court of Virginia.
 
These increases were partially offset by:
 
·
A $71 million decrease in weather-related usage in our eastern and western regions primarily due to decreases of 14% and 32%, respectively, in heating degree days and a 7% decrease in cooling degree days in our western region.
 
 
21

 
·
Margins from Off-system Sales decreased $13 million primarily due to lower PJM capacity revenue, reduced trading and marketing margins and lower power prices.
·
Transmission Revenues increased $19 million primarily due to increased investment in the PJM region.   These increased revenues are offset-in-part in Other Operation and Maintenance expenses below.
·
Other Revenues decreased $9 million primarily due to a decrease in miscellaneous sales partially offset by a 2011 unfavorable provision for refund of outage insurance proceeds.

Expenses and Other and Income Tax Expense changed between years as follows:

·
Other Operation and Maintenance expenses decreased $18 million primarily due to the following:
 
·
A $46 million decrease in plant outage and other plant operating and maintenance expenses.
 
·
A $41 million decrease due to the 2011 write-off of a portion of the West Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC.
 
·
A $13 million decrease due to APCo's deferral of transmission costs for the Virginia Transmission Rate Adjustment Clause as allowed by the Virginia SCC recovered dollar-for-dollar within Gross Margin.
 
These decreases were partially offset by:
 
·
A $33 million increase due to the 2011 deferral of 2009 storm costs and the 2010 cost reduction initiatives as allowed by the WVPSC.
 
·
A $27 million increase due to the favorable 2011 asset retirement obligation adjustment for APCo related to the early closure and previous write-off of the Mountaineer Carbon Capture and Storage Product Validation Facility.
 
·
A $26 million increase due to expenses related to the 2012 sustainable cost reductions.
·
Asset Impairments and Other Related Charges decreased $36 million due to the 2011 write-off of $49 million related to SWEPCo's expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap as a result of a November 2011 Texas Court of Appeals decision.  This was partially offset by the 2012 write-off of an additional $13 million related to SWEPCo's Texas capital cost cap.
·
Depreciation and Amortization expenses increased $88 million primarily due to the following:
 
·
A $48 million combined increase in depreciation for APCo and I&M primarily due to increases in depreciation rates effective February 2012 (Virginia) and April 2012 (Michigan), respectively.  The majority of this increase in depreciation is offset within Gross Margin.
 
·
An $18 million increase in amortization primarily as a result of the Virginia Environmental Rate Adjustment Clause and the Virginia E&R surcharge, both effective February 2012.  This increase in amortization is offset within Gross Margin.
 
·
Overall higher depreciable property balances.
·
Carrying Costs Income increased $11 million due to adjustments for disallowed environmental costs as approved in a November 2011 Virginia SCC order and 2012 adjustments for certain costs subsequently determined by the Supreme Court of Virginia to be appropriate for recovery.
·
Allowance for Equity Funds Used During Construction decreased $10 million primarily due to the completion of APCo's Dresden Plant in January 2012 and I&M's nuclear fuel preparation for usage, partially offset by increases related to SWEPCo's construction of the Turk Plant.
·
Income Tax Expense increased $33 million primarily due to an increase in pretax book income offset-in-part by the recording of federal and state income tax adjustments.


 
22

 


TRANSMISSION AND DISTRIBUTION UTILITIES

 
 
 
Years Ended December 31,
 
Transmission and Distribution Utilities
 
2013 
 
2012 
 
2011 
 
 
 
 
(in millions)
 
Revenues
 
$
 4,478 
 
$
 4,819 
 
$
 5,156 
 
Purchased Electricity
 
 
 1,627 
 
 
 2,072 
 
 
 2,711 
 
Gross Margin
 
 
 2,851 
 
 
 2,747 
 
 
 2,445 
 
Other Operation and Maintenance
 
 
 1,003 
 
 
 911 
 
 
 954 
 
Depreciation and Amortization
 
 
 591 
 
 
 561 
 
 
 549 
 
Taxes Other Than Income Taxes
 
 
 435 
 
 
 428 
 
 
 417 
 
Operating Income
 
 
 822 
 
 
 847 
 
 
 525 
 
Interest and Investment Income
 
 
 2 
 
 
 4 
 
 
 7 
 
Carrying Costs Income
 
 
 16 
 
 
 24 
 
 
 375 
 
Allowance for Equity Funds Used During Construction
 
 
 8 
 
 
 6 
 
 
 9 
 
Interest Expense
 
 
 (292)
 
 
 (291)
 
 
 (293)
 
Income Before Income Tax Expense
 
 
 556 
 
 
 590 
 
 
 623 
 
Income Tax Expense
 
 
 198 
 
 
 201 
 
 
 219 
 
Income Before Extraordinary Item
 
$
 358 
 
$
 389 
 
$
 404 
 

Summary of KWh Energy Sales for Transmission and Distribution Utilities
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
 
(in millions of KWhs)
Retail:
 
 
 
 
 
 
 
 
 
Residential
 
 25,531 
 
 
 25,581 
 
 
 26,520 
 
Commercial
 
 24,631 
 
 
 24,746 
 
 
 25,116 
 
Industrial
 
 22,668 
 
 
 24,902 
 
 
 25,334 
 
Miscellaneous
 
 710 
 
 
 716 
 
 
 751 
Total Retail (a)
 
 73,540 
 
 
 75,945 
 
 
 77,721 
 
 
 
 
 
 
 
 
 
Wholesale
 
 8 
 
 
 8 
 
 
 8 
 
 
 
 
 
 
 
 
 
Total KWhs
 
 73,548 
 
 
 75,953 
 
 
 77,729 
 
 
 
 
 
 
 
 
 
 
(a)  Represents energy delivered to distribution customers.


 
23

 


Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.  In general, degree day changes in our eastern region have a larger effect on net income than changes in our western region due to the relative size of the two regions and the number of customers within each region.

Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
2013 
 
2012 
 
2011 
 
 
(in degree days)
Eastern Region
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 3,383 
 
 
 2,610 
 
 
 3,107 
Normal - Heating (b)
 
 3,229 
 
 
 3,276 
 
 
 3,266 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 1,029 
 
 
 1,248 
 
 
 1,112 
Normal - Cooling (b)
 
 954 
 
 
 948 
 
 
 936 
 
 
 
 
 
 
 
 
 
 
Western Region
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 368 
 
 
 177 
 
 
 394 
Normal - Heating (b)
 
 337 
 
 
 352 
 
 
 351 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (d)
 
 2,737 
 
 
 3,100 
 
 
 3,242 
Normal - Cooling (b)
 
 2,608 
 
 
 2,584 
 
 
 2,557 
 
 
 
 
 
 
 
 
 
 
(a)
Heating degree days are calculated on a 55 degree temperature base.
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
(c)
Eastern Region cooling degree days are calculated on a 65 degree temperature base.
(d)
Western Region cooling degree days are calculated on a 70 degree temperature base.

 
24

 

2013 Compared to 2012
 
Reconciliation of Year Ended December 31, 2012 to Year Ended December 31, 2013
Income from Transmission and Distribution Utilities Before Extraordinary Item
(in millions)

Year Ended December 31, 2012
 
 
 
 
$
 389 
 
 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
 
 
Retail Margins
 
 
 
 
 
 55 
Off-System Sales
 
 
 
 
 
 1 
Transmission Revenues
 
 
 
 
 
 46 
Other Revenues
 
 
 
 
 
 2 
Total Change in Gross Margin
 
 
 
 
 
 104 
 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
 
 
Other Operation and Maintenance
 
 
 
 
 
 (92)
Depreciation and Amortization
 
 
 
 
 
 (30)
Taxes Other Than Income Taxes
 
 
 
 
 
 (7)
Interest and Investment Income
 
 
 
 
 
 (2)
Carrying Costs Income
 
 
 
 
 
 (8)
Allowance for Equity Funds Used During Construction
 
 
 
 
 
 2 
Interest Expense
 
 
 
 
 
 (1)
Total Change in Expenses and Other
 
 
 
 
 
 (138)
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 
 
 
 3 
 
 
 
 
 
 
 
 
Year Ended December 31, 2013
 
 
 
 
$
 358 

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity were as follows:

·
Retail Margins increased $55 million primarily due to the following:
 
·
A $123 million increase in revenues associated with OPCo's Universal Service Fund (USF) surcharge and Distribution Investment Recovery Rider.  A portion of these increases have corresponding increases in other expense items below.
 
·
A $17 million increase related to favorable regulatory proceedings for OPCo.
 
These increases were partially offset by:
 
·
A $40 million decrease related to Ohio customers switching to alternative CRES providers.  This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
 
·
A $35 million decrease due to OPCo's partial reversal in 2012 of a 2011 fuel provision related to CRES providers.
·
Transmission Revenues increased $46 million primarily due to increased transmission revenues from Ohio customers who switched to alternative CRES providers.

Expenses and Other and Income Tax Expense changed between years as follows:

·
Other Operation and Maintenance expenses increased $92 million primarily due to the following:
 
·
An $86 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.  This increase was offset by a corresponding increase in retail margins above.
 
·
A $30 million net increase related to the reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of the Ohio modified stipulation and the PUCO's August 2012 approval of the June 2012-May 2015 ESP.
 
These increases were partially offset by:
 
·
A $14 million decrease in expenses related to the 2012 sustainable cost reductions.
 
·
A $13 million decrease in Ohio's gridSMART ® expenses primarily due to a reduction in the operation
 
 
25

 
    and maintenance component of the gridSMART ® rider for prior years' over collections.  This decrease was partially offset by a corresponding increase in Depreciation and Amortization.
·
Depreciation and Amortization expenses increased $30 million primarily due to the following:
 
·
An $8 million increase due to OPCo's and TCC's issuance of securitization bonds in August 2013 and March 2012, respectively.  This increase in OPCo's and TCC's securitization related amortizations are offset within Gross Margin.
 
·
A $7 million increase due to increased investment in distribution and transmission plant.
 
·
A $4 million increase in Ohio's gridSMART ® expenses primarily due to an increase in the depreciation component of the gridSMART ® rider to recover prior years' under collections.  This increase was offset by a corresponding decrease in operation and maintenance expense above.
·
Taxes Other Than Income Taxes increased $7 million primarily due to increased property taxes.
·
Carrying Costs Income decreased $8 million primarily due to the first quarter 2012 recording of debt carrying costs prior to TCC's issuance of securitization bonds in March 2012.
·
Income Tax Expense decreased $3 million primarily due to a decrease in pretax book income offset-in-part by the recording of state income tax adjustments.

 
26

 

2012 Compared to 2011
 
Reconciliation of Year Ended December 31, 2011 to Year Ended December 31, 2012
Income from Transmission and Distribution Utilities Before Extraordinary Item
(in millions)

Year Ended December 31, 2011
 
 
 
 
$
 404 
 
 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
 
 
Retail Margins
 
 
 
 
 
 192 
Transmission Revenues
 
 
 
 
 
 59 
Other Revenues
 
 
 
 
 
 51 
Total Change in Gross Margin
 
 
 
 
 
 302 
 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
 
 
Other Operation and Maintenance
 
 
 
 
 
 43 
Depreciation and Amortization
 
 
 
 
 
 (12)
Taxes Other Than Income Taxes
 
 
 
 
 
 (11)
Interest and Investment Income
 
 
 
 
 
 (3)
Carrying Costs Income
 
 
 
 
 
 (351)
Allowance for Equity Funds Used During Construction
 
 
 
 
 
 (3)
Interest Expense
 
 
 
 
 
 2 
Total Change in Expenses and Other
 
 
 
 
 
 (335)
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 
 
 
 18 
 
 
 
 
 
 
 
 
Year Ended December 31, 2012
 
 
 
 
$
 389 

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity were as follows:

·
Retail Margins increased $192 million primarily due to the following:
 
·
A $156 million increase in revenues primarily associated with OPCo's Retail Stability Rider, Deferred Asset Recovery Rider and Distribution Investment Recovery Rider.  A portion of these increases have corresponding increases in other expense items below.
 
·
A $35 million increase due to OPCo's partial reversal in 2012 of a 2011 fuel provision related to CRES providers.
 
These increases were partially offset by:
 
·
A $46 million decrease related to Ohio customers switching to alternative CRES providers.  This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
·
Transmission Revenues increased $59 million primarily due to increased transmission revenues from Ohio customers who switched to alternative CRES providers.
·
Other Revenues increased $51 million primarily due to an increase in revenues related to TCC's issuance of securitization bonds in March 2012.  This increase in revenues from securitization bonds is partially offset by an increase in Depreciation and Amortization expense.

Expenses and Other and Income Tax Expense changed between years as follows:

·
Other Operation and Maintenance expenses decreased $43 million primarily due to the following:
 
·
A $70 million decrease related to the 2011 recording and subsequent 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of the Ohio modified stipulation.
 
These decreases were partially offset by:
 
·
A $13 million increase in storm-related expenses primarily in Ohio.
 
·
A $13 million increase due to expenses related to the 2012 sustainable cost reductions.
·
Depreciation and Amortization expenses increased $12 million primarily due to the following :
 
·
A $51 million increase due to TCC's issuance of securitization bonds in March 2012.  The increase in TCC's securitization related amortization is offset within Gross Margin.
 
 
27

 
 
·
An $11 million increase in amortization of Deferred Asset Recovery Rider assets as approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.  This increase in amortization is offset within Gross Margin.
 
·
A $9 million increase due to higher depreciable property balances primarily related to the Texas Automated Meter Infrastructure project.
 
These increases were partially offset by:
 
·
A $39 million decrease due to amortization adjustment approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.
 
·
A $23 million decrease due to amortization of carrying costs on deferred fuel as a result of the October 2011 PUCO remand order which allowed the POLR refund to be applied against any deferred fuel balances.  The equity amortization was offset by amounts recognized in Carrying Costs Income.
·
Taxes Other Than Income Taxes increased $11 million primarily due to increased property taxes.
·
Carrying Costs Income decreased $351 million primarily due to the recognition in 2011 of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005 and a related favorable 2011 resolution of contested tax items related to the TCC stranded cost settlement.
·
Income Tax Expense decreased $18 million primarily due to a decrease in pretax book income and by the recording of state income tax adjustments.

GENERATION & MARKETING

 
 
 
Years Ended December 31,
 
Generation & Marketing
 
2013 
 
2012 
 
2011 
 
 
 
 
(in millions)
 
Revenues
 
$
 3,665 
 
$
 3,467 
 
$
 3,894 
 
Fuel, Purchased Electricity and Other
 
 
 2,305 
 
 
 2,065 
 
 
 2,215 
 
Gross Margin
 
 
 1,360 
 
 
 1,402 
 
 
 1,679 
 
Other Operation and Maintenance
 
 
 523 
 
 
 507 
 
 
 537 
 
Asset Impairments and Other Related Charges
 
 
 154 
 
 
 287 
 
 
 90 
 
Depreciation and Amortization
 
 
 236 
 
 
 349 
 
 
 304 
 
Taxes Other Than Income Taxes
 
 
 54 
 
 
 62 
 
 
 60 
 
Operating Income
 
 
 393 
 
 
 197 
 
 
 688 
 
Interest and Investment Income
 
 
 2 
 
 
 1 
 
 
 4 
 
Interest Expense
 
 
 (55)
 
 
 (83)
 
 
 (87)
 
Income Before Income Tax Expense
 
 
 340 
 
 
 115 
 
 
 605 
 
Income Tax Expense
 
 
 112 
 
 
 15 
 
 
 166 
 
Income Before Extraordinary Item
 
$
 228 
 
$
 100 
 
$
 439 
 

Summary of MWhs Generated for Generation & Marketing
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
 
(in millions of MWhs)
Fuel Type:
 
 
 
 
 
 
 
 
 
Coal
 
 38 
 
 
 37 
 
 
 45 
 
Natural Gas
 
 6 
 
 
 11 
 
 
 7 
 
Wind
 
 1 
 
 
 1 
 
 
 1 
Total MWhs
 
 45 
 
 
 49 
 
 
 53 

 
28

 

2013 Compared to 2012
 
Reconciliation of Year Ended December 31, 2012 to Year Ended December 31, 2013
Income from Generation & Marketing Before Extraordinary Item
(in millions)

Year Ended December 31, 2012
 
 
 
 
$
 100 
 
 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
 
 
Generation
 
 
 
 
 
 (44)
Retail, Trading and Marketing
 
 
 
 
 
 4 
Other
 
 
 
 
 
 (2)
Total Change in Gross Margin
 
 
 
 
 
 (42)
 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
 
 
Other Operation and Maintenance
 
 
 
 
 
 (16)
Asset Impairments and Other Related Charges
 
 
 
 
 
 133 
Depreciation and Amortization
 
 
 
 
 
 113 
Taxes Other Than Income Taxes
 
 
 
 
 
 8 
Interest and Investment Income
 
 
 
 
 
 1 
Interest Expense
 
 
 
 
 
 28 
Total Change in Expenses and Other
 
 
 
 
 
 267 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 
 
 
 (97)
 
 
 
 
 
 
 
 
Year Ended December 31, 2013
 
 
 
 
$
 228 

The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, purchased electricity and certain costs of service for retail operations were as follows:

·
Generation decreased $44 million primarily due to the following:
 
·
A $336 million decrease in affiliated sales to OPCo primarily due to customers switching to alternative CRES providers as well as a reduction in industrial usage.
 
This decrease was partially offset by the following:
 
·
A $221 million net increase in sales to AEP affiliates under the Interconnection Agreement.
 
·
A $63 million decrease in fuel expenses due to a reduction in generation at the Lawrenceburg Plant.

Expenses and Other and Income Tax Expense changed between years as follows:

·
Other Operation and Maintenance expenses increased $16 million primarily due to a 2013 adjustment of $14 million to impaired plant investment as a result of changes to asset retirement obligations for asbestos removal and retirement of ash disposal facilities at impaired plants.
·
Asset Impairments and Other Related Charges decreased $133 million due to the following:
 
·
A 2012 impairment of $287 million for certain Ohio generation plants, which includes $13 million of related materials and supplies inventory.
 
This decrease was partially offset by:
 
·
A 2013 impairment of $154 million for Muskingum River Plant, Unit 5.
·
Depreciation and Amortization expenses decreased $113 million primarily due to depreciation ceasing on certain Ohio generation plants that were impaired in November 2012 and June 2013.
·
Interest Expense decreased $28 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
·
Income Tax Expense increased $97 million primarily due to an increase in pretax book income and by the recording of state income tax adjustments.

 
29

 

2012 Compared to 2011
 
Reconciliation of Year Ended December 31, 2011 to Year Ended December 31, 2012
Income from Generation & Marketing Before Extraordinary Item
(in millions)

Year Ended December 31, 2011
 
 
 
 
$
 439 
 
 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
 
 
Generation
 
 
 
 
 
 (363)
Retail, Trading and Marketing
 
 
 
 
 
 86 
Total Change in Gross Margin
 
 
 
 
 
 (277)
 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
 
 
Other Operation and Maintenance
 
 
 
 
 
 30 
Asset Impairments and Other Related Charges
 
 
 
 
 
 (197)
Depreciation and Amortization
 
 
 
 
 
 (45)
Taxes Other Than Income Taxes
 
 
 
 
 
 (2)
Interest and Investment Income
 
 
 
 
 
 (3)
Interest Expense
 
 
 
 
 
 4 
Total Change in Expenses and Other
 
 
 
 
 
 (213)
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 
 
 
 151 
 
 
 
 
 
 
 
 
Year Ended December 31, 2012
 
 
 
 
$
 100 

The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, purchased electricity and certain costs of service for retail operations were as follows:

·
Generation decreased $363 million primarily due to the following:
 
·
A $396 million decrease in affiliated sales to OPCo primarily due to customer switching to alternative CRES providers.
 
This decrease was partially offset by:
 
·
A $29 million increase in non-affiliated sales due to increased sales to Buckeye Power, Inc. for back-up energy under the Cardinal Station Agreement.
· Retail, Trading and Marketing increased $86 million primarily due to the March 2012 acquisition of BlueStar.
     
Expenses and Other and Income Tax Expense changed between years as follows:
     
· Other Operation and Maintenance expenses decreased $30 million primarily due to the following:
 
·
A $78 million decrease in plant outage and other plant operating and maintenance expenses.
  This decrease was partially offset by:
  · A $47 million increase in AEP Energy labor and sales expenses due to the acquisition of BlueStar in March 2012.
· Asset Impairments and Other Related Charges increased $197 million due to the following:
  · A 2012 impairment of $287 million for certain Ohio generation plants, which includes $13 million of related materials and supplies inventory.
  This increase was partially offset by:
  · A 2011 plant impairment of $48 million for Sporn Plant, Unit 5.
  · A 2011 plant impairment of $42 million for FGD project at Muskingum River Plant, Unit 5.
· Depreciation and Amortization expenses increased $45 million primarily due to the following:
  · A $58 million increase due to shortened depreciable lives for certain AGR generation plants effective December 2011.  The book value of these plants was fully impaired in November 2012.
  · Overall higher depreciable property balances.
 
These increases were partially offset by:
 
·
A $13 million decrease in depreciation due to the 2011 plant impairment of Sporn Plant, Unit 5.
·
Income Tax Expense decreased $151 million primarily due to a decrease in pretax book income.

 
30

 
AEP TRANSMISSION HOLDCO

2013 Compared to 2012

Income Before Extraordinary Item from our AEP Transmission Holdco segment increased from $43 million in 2012 to $80 million in 2013 primarily due to an increase in investments by our wholly-owned transmission subsidiaries and ETT.

2012 Compared to 2011

Income Before Extraordinary Item from our AEP Transmission Holdco segment increased from $30 million in 2011 to $43 million in 2012 primarily due to an increase in investments by ETT and our wholly-owned transmission subsidiaries.

AEP RIVER OPERATIONS

2013 Compared to 2012

Income Before Extraordinary Item from our AEP River Operations segment decreased from $15 million in 2012 to $12 million in 2013 primarily due to significant reductions in export grain and coal demand.  In addition, low water levels in the first and fourth quarters of 2013 limited barge loads and tow sizes.

2012 Compared to 2011

Income Before Extraordinary Item from our AEP River Operations segment decreased from $45 million in 2011 to $15 million in 2012 primarily due to the 2012 drought, which had significant impacts on river conditions and crop yields, resulting in reduced grain exports.

CORPORATE AND OTHER

2013 Compared to 2012

Income Before Extraordinary Item from Corporate and Other increased from a loss of $88 million in 2012 to income of $125 million in 2013 primarily due to a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in 2013 as well as a reduction in interest expense associated with the early retirement of debt in 2012.

2012 Compared to 2011

Income Before Extraordinary Item from Corporate and Other decreased from a loss of $52 million in 2011 to a loss of $88 million in 2012 primarily due to costs associated with the early retirement of debt in 2012 and the 2012 adjustment of a U.K. Windfall Tax provision as a result of a related Supreme Court case, partially offset by a loss incurred in 2011 related to the settlement of litigation with BOA and Enron.

AEP SYSTEM INCOME TAXES

2013 Compared to 2012

Income Tax Expense increased $80 million primarily due to an increase in pretax book income and the recording of state income tax adjustments partially offset by a favorable U.K. Windfall Tax decision by the U.S. Supreme Court in the second quarter of 2013.

2012 Compared to 2011

Income Tax Expense decreased $214 million primarily due to a decrease in pretax book income and the unrealized capital loss valuation allowance related to a deferred tax asset associated with the settlement of litigation with BOA and Enron recorded in 2011, partially offset by the recording of federal and state income tax adjustments.
 
 
31

 

FINANCIAL CONDITION

We measure our financial condition by the strength of our balance sheet and the liquidity provided by our cash flows.

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

 
 
December 31,
 
 
2013 
 
2012 
 
 
(dollars in millions)
Long-term Debt, including amounts due within one year
$
 18,377 
 
 52.2 
%
 
$
 17,757 
 
 52.3 
%
Short-term Debt
 
 757 
 
 2.1 
 
 
 
 981 
 
 2.9 
 
Total Debt
 
 19,134 
 
 54.3 
 
 
 
 18,738 
 
 55.2 
 
AEP Common Equity
 
 16,085 
 
 45.7 
 
 
 
 15,237 
 
 44.8 
 
Noncontrolling Interests
 
 1 
 
 - 
 
 
 
 - 
 
 - 
 
Total Debt and Equity Capitalization
$
 35,220 
 
 100.0 
%
 
$
 33,975 
 
 100.0 
%

Our ratio of debt-to-total capital decreased from 55.2% as of December 31, 2012 to 54.3% as of December 31, 2013 primarily due to an increase in common equity, partially offset by a net increase in debt issuances, including the issuance of $647 million of securitization bonds.

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability.  We believe we have adequate liquidity under our existing credit facilities.  As of December 31, 2013, we had $3.5 billion in aggregate credit facility commitments to support our operations.  Additional liquidity is available from cash from operations and a receivables securitization agreement.  We are committed to maintaining adequate liquidity.  We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, sale-leaseback or leasing agreements or common stock.

Commercial Paper Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  As of December 31, 2013, our available liquidity was approximately $3.4 billion as illustrated in the table below:

 
 
 
Amount
 
 
Maturity
 
 
 
(in millions)
 
 
 
 
 
 
 
 
 
 
 
Commercial Paper Backup:
 
 
 
 
 
 
 
Revolving Credit Facility
 
$
 1,750 
 
 
June 2016
 
Revolving Credit Facility
 
 
 1,750 
 
 
July 2017
Total
 
 
 3,500 
 
 
 
Cash and Cash Equivalents
 
 
 118 
 
 
 
Total Liquidity Sources
 
 
 3,618 
 
 
 
Less:
AEP Commercial Paper Outstanding
 
 
 57 
 
 
 
 
Letters of Credit Issued
 
 
 170 
 
 
 
 
 
 
 
 
 
 
 
Net Available Liquidity
 
$
 3,391 
 
 
 

We have credit facilities totaling $3.5 billion to support our commercial paper program.  The credit facilities allow us to issue letters of credit in an amount up to $1.2 billion.
 
 
32

 

We use our commercial paper program to meet the short-term borrowing needs of our subsidiaries.  The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries.  In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  The maximum amount of commercial paper outstanding during 2013 was $904 million.  The weighted-average interest rate for our commercial paper during 2013 was 0.32%.

Other Credit Facilities

In July 2013, AGR, APCo, KPCo and OPCo entered into a $1 billion term credit facility due in May 2015 to fund certain OPCo maturities on an interim basis and to facilitate OPCo’s corporate separation of generation assets from transmission and distribution.  As of December 31, 2013, the $1 billion term credit facility was entirely drawn.  Repayments prior to maturity are permitted.  However, any amount that is repaid may not be re-borrowed and is a permanent reduction of the term credit facility.

In January 2014, we issued letters of credit utilizing the entire amount available under an $85 million uncommitted facility signed in October 2013.  An uncommitted facility gives the issuer of the facility the right to accept or decline each request we make under the facility.

Financing Plan

As of December 31, 2013, we have $1.5 billion of long-term debt due within one year which includes $879 million of Pollution Control Bonds with mandatory tender dates and credit support for variable interest rates that requires the debt be classified as current.  Also included in our long-term debt due within one year is $413 million of securitization bonds and DCC Fuel notes payable which will be repaid.  We plan to refinance the majority of our other maturities due within one year.

Securitized Accounts Receivables

In 2013, we amended our receivables securitization agreement to extend through June 2014.  The agreement provides a commitment of $700 million from bank conduits to purchase receivables.  A commitment of $385 million expires in June 2014 and the remaining commitment of $315 million expires in June 2015.  We intend to extend or replace the agreement expiring in June 2014 on or before its maturity.

West Virginia Securitization of Regulatory Assets

In September 2013, the WVPSC approved a settlement agreement filed by APCo, WPCo and intervenors which authorized APCo to securitize $376 million, plus upfront financing costs, related primarily to the December 2011 under-recovered Expanded Net Energy Charge (ENEC) deferral balance.  In November 2013, APCo issued $380 million of Securitization Bonds to securitize the under-recovered ENEC deferral balance, including $4 million of upfront financing costs, with a final maturity date of August 2031.  APCo implemented a new securitization rider which was offset by an equal reduction in ENEC revenues, with no overall change in total revenues.

Ohio Securitization of Regulatory Assets

In March 2013, the PUCO approved OPCo’s request to securitize the Deferred Asset Recovery Rider (DARR) balance.  In August 2013, OPCo issued $267 million of Securitization Bonds, with a final maturity date of July 2020, to securitize the DARR balance.  As a result of the securitization, recovery through the DARR has ceased and has been replaced by the Deferred Asset Phase-in Rider which will recover the securitized assets.
 
Debt Covenants and Borrowing Limitations

Our credit agreements contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%.  The method for calculating outstanding debt and capitalization is contractually defined in our credit agreements.  Debt as defined in the credit agreements excludes securitization bonds and debt of AEP Credit.  As of December 31, 2013, this contractually-defined percentage was 50.4%.  Nonperformance under these covenants could result in an event of default under these credit agreements.  As of
 
 
33

 
December 31, 2013, we complied with all of the covenants contained in these credit agreements.  In addition, the acceleration of our payment obligations, or the obligations of certain of our major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements.  This condition also applies in a majority of our non-exchange traded commodity contracts and would similarly allow lenders and counterparties to declare the outstanding amounts payable.  However, a default under our non-exchange traded commodity contracts does not cause an event of default under our credit agreements.

The revolving credit facilities do not permit the lenders to refuse a draw on any facility if a material adverse change occurs.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders.  As of December 31, 2013, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.50 per share in January 2014.  Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time.  Our income derives from our common stock equity in the earnings of our utility subsidiaries.  Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.  However, we do not believe these restrictions will have any significant impact on Parent’s ability to access cash to meet the payment of dividends on its common stock.

Credit Ratings

We do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but our access to the commercial paper market may depend on our credit ratings.  In addition, downgrades in our credit ratings by one of the rating agencies could increase our borrowing costs.  Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject us to additional collateral demands under adequate assurance clauses under our derivative and non-derivative energy contracts.

CASH FLOW

Managing our cash flows is a major factor in maintaining our liquidity strength.

 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
 
 
 
(in millions)
Cash and Cash Equivalents at Beginning of Period
 
$
 279 
 
$
 221 
 
$
 294 
Net Cash Flows from Operating Activities
 
 
 4,106 
 
 
 3,804 
 
 
 3,788 
Net Cash Flows Used for Investing Activities
 
 
 (3,818)
 
 
 (3,391)
 
 
 (2,890)
Net Cash Flows Used for Financing Activities
 
 
 (449)
 
 
 (355)
 
 
 (971)
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 (161)
 
 
 58 
 
 
 (73)
Cash and Cash Equivalents at End of Period
 
$
 118 
 
$
 279 
 
$
 221 

Cash from operations and short-term borrowings provides working capital and allows us to meet other short-term cash needs.


 
34

 

Operating Activities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
 
 
 
(in millions)
Net Income
 
$
 1,484 
 
$
 1,262 
 
$
 1,949 
Depreciation and Amortization
 
 
 1,743 
 
 
 1,782 
 
 
 1,655 
Other
 
 
 879 
 
 
 760 
 
 
 184 
Net Cash Flows from Operating Activities
 
$
 4,106 
 
$
 3,804 
 
$
 3,788 

Net Cash Flows from Operating Activities were $4.1 billion in 2013 consisting primarily of Net Income of $1.5 billion, $1.7 billion of noncash Depreciation and Amortization and $226 million of Asset Impairments related to Muskingum River Plant, Unit 5, Big Sandy and Amos Plants, partially offset by $214 million of Ohio capacity deferrals as a result of a 2012 PUCO order.  Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Deferred Income Taxes increased primarily due to provisions in the Taxpayer Relief Act of 2012 and an increase in tax versus book temporary differences from operations.  Significant changes in other items include the favorable impact of a decrease in fuel inventory and net cash flows for Accrued Taxes as a result of the recognition of the tax benefit related to the U.K. Windfall Tax.

Net Cash Flows from Operating Activities were $3.8 billion in 2012 consisting primarily of Net Income of $1.3 billion, $1.8 billion of noncash Depreciation and Amortization and $287 million in Asset Impairments related to certain Ohio generation assets.  Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  A significant change in other items includes the unfavorable impact of an increase in fuel inventory due to the mild winter weather.  Deferred Income Taxes increased primarily due to provisions in the Small Business Jobs Act and the Tax Relief, Unemployment Insurance Reauthorization and Jobs Creation Act and an increase in tax versus book temporary differences from operations.  During 2012, we also contributed $200 million to our qualified pension trust.

Net Cash Flows from Operating Activities were $3.8 billion in 2011 consisting primarily of Net Income of $1.9 billion and $1.7 billion of noncash Depreciation and Amortization.  Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Following a Supreme Court of Texas reversal of the PUCT’s capacity auction true-up disallowance and the PUCT’s approval of a stipulation agreement, we recorded an Extraordinary Item, Net of Tax of $373 million for the 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts and the reversal of tax related regulatory credits.  We also recorded $393 million in Carrying Costs Income primarily related to the Texas restructuring appeals.  A significant change in other items includes the favorable impact of a decrease in fuel inventory.  Deferred Income Taxes increased primarily due to bonus depreciation provisions in the Small Business Jobs Act and the Tax Relief, Unemployment Insurance Reauthorization and Jobs Creation Act, the settlement with BOA and Enron and an increase in tax versus book temporary differences from operations.  In February 2011, we paid $425 million to BOA of which $211 million was used to settle litigation with BOA and Enron. The remaining $214 million was used to acquire cushion gas as discussed in Investing Activities below.  During 2011, we also contributed $450 million to our qualified pension trust.
 
Investing Activities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
 
 
 
(in millions)
Construction Expenditures
 
$
 (3,624)
 
$
 (3,025)
 
$
 (2,669)
Acquisitions of Nuclear Fuel
 
 
 (154)
 
 
 (107)
 
 
 (106)
Acquisitions of Assets/Businesses
 
 
 (32)
 
 
 (94)
 
 
 (19)
Acquisitions of Cushion Gas from BOA
 
 
 - 
 
 
 - 
 
 
 (214)
Proceeds from Sales of Assets
 
 
 21 
 
 
 18 
 
 
 123 
Other
 
 
 (29)
 
 
 (183)
 
 
 (5)
Net Cash Flows Used for Investing Activities
 
$
 (3,818)
 
$
 (3,391)
 
$
 (2,890)

 
 
35

 
Net Cash Flows Used for Investing Activities were $3.8 billion in 2013 primarily due to Construction Expenditures for environmental, distribution and transmission investments.

Net Cash Flows Used for Investing Activities were $3.4 billion in 2012 primarily due to Construction Expenditures for new generation, environmental, distribution and transmission investments.  Acquisitions of Assets/Businesses include our March 2012 purchase of BlueStar for $70 million.

Net Cash Flows Used for Investing Activities were $2.9 billion in 2011 primarily due to Construction Expenditures for new generation, environmental, distribution and transmission investments.  We paid $214 million to BOA for cushion gas as part of a litigation settlement.
 
Financing Activities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
 
 
 
(in millions)
Issuance of Common Stock, Net
 
$
 84 
 
$
 83 
 
$
 92 
Issuance/Retirement of Debt, Net
 
 
 385 
 
 
 544 
 
 
 (33)
Proceeds from Nuclear Fuel Sale/Leaseback
 
 
 110 
 
 
 - 
 
 
 - 
Retirement of Cumulative Preferred Stock
 
 
 - 
 
 
 - 
 
 
 (64)
Dividends Paid on Common Stock
 
 
 (954)
 
 
 (916)
 
 
 (898)
Other
 
 
 (74)
 
 
 (66)
 
 
 (68)
Net Cash Flows Used for Financing Activities
 
$
 (449)
 
$
 (355)
 
$
 (971)

Net Cash Flows Used for Financing Activities in 2013 were $449 million.  Our net debt issuances were $385 million.  The net issuances included issuances of $745 million of senior unsecured notes, $1 billion draws on a $1 billion term credit facility, $647 million of securitization bonds, $328 million of notes payable and other debt and $305 million of pollution control bonds offset by retirements of $1.8 billion of senior unsecured and other debt notes, $331 million of pollution control bonds, $243 million of securitization bonds and a decrease in short-term borrowing of $224 million.  We paid common stock dividends of $954 million.  See Note 14  – Financing Activities.

Net Cash Flows Used for Financing Activities in 2012 were $355 million.  Our net debt issuances were $544 million. The net issuances included issuances of $1.7 billion of senior unsecured notes, $800 million of securitization bonds, $287 million of notes payable and other debt and $65 million of pollution control bonds offset by retirements of $902 million of senior unsecured and other debt notes, $315 million of junior subordinate debentures, $220 million of pollution control bonds, $206 million of securitization bonds and a decrease in short-term borrowing of $669 million.  We paid common stock dividends of $916 million.

Net Cash Flows Used for Financing Activities in 2011 were $971 million.  Our net debt retirements were $33 million. The net retirements included retirements of $727 million of senior unsecured and other debt notes, $778 million of pollution control bonds and $159 million of securitization bonds offset by issuances of $710 million of notes, $627 million of pollution control bonds and an increase in short-term borrowing of $304 million.  We paid common stock dividends of $898 million and $64 million to retire all of our subsidiaries’ preferred stocks.


 
36

 


The following financing activities occurred during 2013:

AEP Common Stock:

·  
During 2013, we issued 2.1 million shares of common stock under our incentive compensation, employee savings and dividend reinvestment plans and received net proceeds of $84 million.

Debt:

·  
During 2013, we issued approximately $3 billion of long-term debt, including $1 billion drawn on a term credit facility, $745 million of senior notes at interest rates ranging from 2.73% to 5.32% and $647 million of securitization bonds at interest rates ranging from 0.96% to 3.77%.  We also issued $190 million of pollution control revenue bonds at interest rates ranging from 3.25% to 4%, $115 million of pollution control revenue bonds at variable interest rates and $328 million of other debt at variable interest rates.  The proceeds from these issuances were used to fund long-term debt maturities and our construction programs.
·  
During 2013, we entered no interest rate derivatives and settled $379 million of such transactions.  The settlements resulted in net cash payments of $26 million.  As of December 31, 2013, we had in place $820 million of notional interest rate derivatives designated as cash flow and fair value hedges.

In 2014:

·  
In January 2014, TCC retired $112 million of Securitization Bonds.
·  
In January and February 2014, I&M retired $24 million of Notes Payable related to DCC Fuel.
·  
In January 2014, OPCo retired $225 million of 4.85% Senior Unsecured Notes due in 2014.

BUDGETED CONSTRUCTION EXPENDITURES

We forecast approximately $3.8 billion of construction expenditures excluding equity AFUDC for 2014.  For 2015 and 2016, we forecast construction expenditures of $3.8 billion each year.  The expenditures are generally for transmission, distribution and  required environmental investment to comply with Federal EPA rules.  Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  We expect to fund these construction expenditures through cash flows from operations and financing activities.  Generally, the subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged.  The 2014 estimated construction expenditures include generation, transmission and distribution related investments, as well as expenditures for compliance with environmental regulations as follows:

 
 
 
2014 Budgeted Construction Expenditures
Segment
 
Environmental
 
Generation
 
Transmission
 
Distribution
 
Other
 
Total
 
 
 
(in millions)
Vertically Integrated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Utilities
 
$
 467 
 
$
 410 
 
$
 465 
 
$
 564 
 
$
 67 
 
$
 1,973 
Transmission and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Utilities
 
 
 7 
 
 
 5 
 
 
 340 
 
 
 494 
 
 
 36 
 
 
 882 
Generation & Marketing
 
 
 114 
 
 
 63 
 
 
 - 
 
 
 - 
 
 
 14 
 
 
 191 
AEP Transmission Holdco
 
 
 - 
 
 
 - 
 
 
 786 
 
 
 - 
 
 
 1 
 
 
 787 
AEP River Operations
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 9 
 
 
 9 
Corporate and Other
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 3 
 
 
 3 
Total
 
$
 588 
 
$
 478 
 
$
 1,591 
 
$
 1,058 
 
$
 130 
 
$
 3,845 


 
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OFF-BALANCE SHEET ARRANGEMENTS

Our current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements that we enter in the normal course of business.  The following identifies significant off-balance sheet arrangements.

Rockport Plant, Unit 2

AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated unconsolidated trustee for Rockport Plant, Unit 2 (the Plant).  The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and certain institutional investors.  The future minimum lease payments for AEGCo and I&M are $665 million and $665 million, respectively, as of December 31, 2013.

The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022.  The Owner Trustee owns the Plant and leases it to AEGCo and I&M.  Our subsidiaries account for the lease as an operating lease with the future payment obligations included in Note 13.  The lease term is for 33 years with potential renewal options.  At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant.  We, as well as our subsidiaries, have no ownership interest in the Owner Trustee and do not guarantee its debt.

Railcars

In June 2003, we entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  We intend to maintain the lease for the full lease term of twenty years via the renewal options.  The lease is accounted for as an operating lease.  The future minimum lease obligation is $28 million for the remaining railcars as of December 31, 2013.  Under a return-and-sale option, the lessor is guaranteed that the sale proceeds will equal at least a specified lessee obligation amount which declines with each five-year renewal.  As of December 31, 2013, the maximum potential loss was approximately $19 million assuming the fair value of the equipment is zero at the end of the current five-year lease term.  However, we believe that the fair value would produce a sufficient sales price to avoid any loss.  We have other railcar lease arrangements that do not utilize this type of financing structure.


 
38

 


CONTRACTUAL OBLIGATION INFORMATION

Our contractual cash obligations include amounts reported on the balance sheets and other obligations disclosed in our footnotes.  The following table summarizes our contractual cash obligations as of December 31, 2013:

Payments Due by Period
 
 
 
 
Less Than
 
 
 
 
 
After
 
 
Contractual Cash Obligations
 
1 Year
 
2-3 Years
 
4-5 Years
 
5 Years
 
Total
 
 
(in millions)
Short-term Debt (a)
 
$
 757 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 757 
Interest on Fixed Rate Portion of Long-term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt (b)
 
 
 784 
 
 
 1,442 
 
 
 1,250 
 
 
 6,283 
 
 
 9,759 
Fixed Rate Portion of Long-term Debt (c)
 
 
 988 
 
 
 2,284 
 
 
 2,853 
 
 
 10,328 
 
 
 16,453 
Variable Rate Portion of Long-term Debt (d)
 
 
 561 
 
 
 1,382 
 
 
 6 
 
 
 - 
 
 
 1,949 
Capital Lease Obligations (e)
 
 
 135 
 
 
 208 
 
 
 123 
 
 
 215 
 
 
 681 
Noncancelable Operating Leases (e)
 
 
 288 
 
 
 514 
 
 
 445 
 
 
 862 
 
 
 2,109 
Fuel Purchase Contracts (f)
 
 
 2,362 
 
 
 3,391 
 
 
 2,235 
 
 
 2,649 
 
 
 10,637 
Energy and Capacity Purchase Contracts
 
 
 195 
 
 
 410 
 
 
 457 
 
 
 2,634 
 
 
 3,696 
Construction Contracts for Capital Assets (g)
 
 
 807 
 
 
 1,123 
 
 
 931 
 
 
 1,797 
 
 
 4,658 
Total
 
$
 6,877 
 
$
 10,754 
 
$
 8,300 
 
$
 24,768 
 
$
 50,699 

(a)
Represents principal only excluding interest.
(b)
Interest payments are estimated based on final maturity dates of debt securities outstanding as of December 31, 2013 and do not reflect anticipated future refinancing, early redemptions or debt issuances.
(c)
See “Long-term Debt” section of Note 14.  Represents principal only excluding interest.
(d)
See “Long-term Debt” section of Note 14.  Represents principal only excluding interest.  Variable rate debt had interest rates that ranged between 0.02% and 1.91% as of December 31, 2013.
(e)
See Note 13.
(f)
Represents contractual obligations to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel.
(g)
Represents only capital assets for which we have signed contracts.  Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs.

Our $51 million liability related to uncertainty in Income Taxes is not included above because we cannot reasonably estimate the cash flows by period.

Our pension funding requirements are not included in the above table.  As of December 31, 2013, we expect to make contributions to our pension plans totaling $80 million in 2014.  Estimated contributions of $78 million in 2015 and $84 million in 2016 may vary significantly based on market returns, changes in actuarial assumptions and other factors.  Based upon the accumulated benefit obligation and fair value of assets available to pay pension benefits, our pension plans were 99.9% funded as of December 31, 2013.


 
39

 


In addition to the amounts disclosed in the contractual cash obligations table above, we make additional commitments in the normal course of business.  These commitments include standby letters of credit, guarantees for the payment of obligation performance bonds and other commitments.  As of December 31, 2013, our commitments outstanding under these agreements are summarized in the table below:

Amount of Commitment Expiration Per Period
 
 
 
Less Than
 
 
 
 
 
After
 
 
Other Commercial Commitments
 
1 Year
 
2-3 Years
 
4-5 Years
 
5 Years
 
Total
 
 
(in millions)
Standby Letters of Credit (a)
 
$
 170 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 170 
Guarantees of the Performance of Outside Parties (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 115 
 
 
 115 
Guarantees of Our Performance (c)
 
 
 592 
 
 
 - 
 
 
 10 
 
 
 58 
 
 
 660 
Total Commercial Commitments
 
$
 762 
 
$
 - 
 
$
 10 
 
$
 173 
 
$
 945 

(a)
We enter into standby letters of credit (LOCs) with third parties.  These LOCs cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.  AEP, on behalf of our subsidiaries, and/or the subsidiaries issued all of these LOCs in the ordinary course of business.  There is no collateral held in relation to any guarantees in excess of our ownership percentages.  In the event any LOC is drawn, there is no recourse to third parties.  The maximum future payments of these LOCs are $170 million with maturities ranging from February 2014 to April 2015.  See “Letters of Credit” section of Note 6.
(b)
See “Guarantees of Third-Party Obligations” section of Note 6.
(c)
We issued performance guarantees and indemnifications for energy trading and various sale agreements.

SIGNIFICANT TAX LEGISLATION

The Small Business Jobs Act extended the time for claiming bonus depreciation and increased the deduction to 100% for 2011 and decreased the deduction to 50% for 2012.  The American Taxpayer Relief Act of 2012 provided for the extension of several business and energy industry tax deductions and credits, including the one-year extension of the 50% bonus depreciation to 2013.  The enacted provisions had no material impact on net income or financial condition but did have a favorable impact on cash flows in 2013.

CYBER SECURITY

Cyber security presents a heightened risk for electric utility systems because a cyber-attack could affect critical energy infrastructure.  Breaches to the cyber security of the grid or to our system are potentially disruptive to people, property and commerce and create risk for our business, investors and customers.  In February 2013, President Obama signed an executive order that addresses how government agencies will operate and support the functions in cyber security as well as redefine how the government interfaces with critical infrastructure, such as the electric grid.  We already operate under regulatory cyber security standards to protect critical infrastructure.  The cyber security framework that is being developed through this executive order will be reviewed by the FERC and the U.S. Department of Energy.  We are participating in the process by submitting feedback through our industry trade group and sharing best practices already in place.  We protect our critical cyber assets, such as our data centers, power plants, transmission operations centers and business network, using multiple layers of cyber security and authentication.  We constantly scan the system for risks or threats.

Cyber hackers have been able to breach a number of very secure facilities, from federal agencies, banks and retailers to social media sites.  As these events become known and develop, we continually assess our own cyber security tools and processes to determine where we might need to strengthen our defenses.

In recent years, we have taken additional steps to enhance our capabilities for identifying risks or threats and have shared those threats with our utility peers, industry and federal agencies.  We operate our own Cyber Security Operations Center.  Funding for this included a grant from the American Recovery and Reinvestment Act – U.S. Department of Energy Smart Grid Demonstration Program.  This facility was initially designed as a pilot cyber threat and information-sharing center specifically for the electric sector and today is fully operational.
 
 
40

 

In 2013, as part of our industry’s continuing program to advance threat sharing and coordination, we participated in the North American Electric Reliability Corporation (NERC) GridEx II exercise.  This effort, led by NERC, tested and developed the coordination and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid.

In 2012, we signed a cooperative research and development agreement with the Department of Homeland Security’s Office of Cyber Security and Communications, further enhancing our ability to directly exchange information about cyber threats.  In addition, we continue to partner with a number of federal and industry groups to advance the national capabilities of cyber security.  We are working with the U.S. Department of Energy on several projects covering advanced cyber security and assessment tools.

We have partnered with a major defense contractor who has significant cyber security experience and technical capabilities developed through their work with the U.S. Department of Defense.  We work with a consortium of other utilities across the country, learning how best to share information about potential threats and collaborating with each other.  We continue to work with a nonaffiliated entity to conduct several seminars each year about recognizing and investigating cyber vulnerabilities.  Through these types of efforts, we are working to protect ourselves while helping our industry advance its cyber security capabilities.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING PRONOUNCEMENTS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions that affect reported amounts and related disclosures, including amounts related to legal matters and contingencies.  We consider an accounting estimate to be critical if:

·  
It requires assumptions to be made that were uncertain at the time the estimate was made; and
·  
Changes in the estimate or different estimates that could have been selected could have a material effect on net income or financial condition.

We discuss the development and selection of critical accounting estimates as presented below with the Audit Committee of AEP’s Board of Directors and the Audit Committee reviews the disclosures relating to them.

We believe that the current assumptions and other considerations used to estimate amounts reflected in our financial statements are appropriate.  However, actual results can differ significantly from those estimates.

The sections that follow present information about our critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop each estimate.

Regulatory Accounting

Nature of Estimates Required

Our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.

We recognize regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) for the economic effects of regulation.  Specifically, we match the timing of expense and income recognition with regulated revenues.  We also record liabilities for refunds, or probable refunds, to customers that have not been made.

Assumptions and Approach Used

When incurred costs are probable of recovery through regulated rates, we record them as regulatory assets on the balance sheet.  We review the probability of recovery at each balance sheet date and whenever new events occur.  Similarly, we record regulatory liabilities when a determination is made that a refund is probable or when ordered by a commission.  Examples of new events that affect probability include changes in the regulatory environment,
 
 
41

 
issuance of a regulatory commission order or passage of new legislation.  The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs as well as the return of revenues, rate of return earned on invested capital and timing and amount of assets to be recovered through regulated rates.  If recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against earnings.  A write-off of regulatory assets or establishment of a regulatory liability may also reduce future cash flows since there will be no recovery through regulated rates.

Effect if Different Assumptions Used

A change in the above assumptions may result in a material impact on our net income.  Refer to Note 5 for further detail related to regulatory assets and regulatory liabilities.

Revenue Recognition – Unbilled Revenues

Nature of Estimates Required

We record revenues when energy is delivered to the customer.  The determination of sales to individual customers is based on the reading of their meters, which we perform on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue accrual is recorded.  This estimate is reversed in the following month and actual revenue is recorded based on meter readings.  In accordance with the applicable state commission regulatory treatment in Arkansas, Louisiana, Oklahoma and Texas, PSO and SWEPCo do not record the fuel portion of unbilled revenue.

The changes in unbilled electric utility revenues for our Vertically Integrated Utilities segment were $(9) million, $13 million and $(57) million for the years ended December 31, 2013, 2012 and 2011, respectively.  The changes in unbilled electric revenues are primarily due to changes in weather and rate increases.  Accrued unbilled revenues for the Vertically Integrated Utilities segment were $283 million and $292 million as of December 31, 2013 and 2012, respectively.

The changes in unbilled electric utility revenues for our Transmission and Distribution Utilities segment were $(22) million, $(12) million and $(24) million for the years ended December 31, 2013, 2012 and 2011, respectively.  The changes in unbilled electric revenues are primarily due to changes in weather and rate increases.  Accrued unbilled revenues for the Transmission and Distribution Utilities segment were $165 million and $187 million as of December 31, 2013 and 2012, respectively.

In March 2012, our Generation & Marketing segment acquired an independent retail electric supplier.  The change in unbilled electric utility revenues for our Generation & Marketing segment was $10 million and $34 million for the years ended December 31, 2013 and 2012, respectively.  Accrued unbilled revenues for the Generation & Marketing segment were $41 million and $31 million as of December 31, 2013 and 2012, respectively.

Assumptions and Approach Used

For each operating company, we compute the monthly estimate for unbilled revenues as net generation (generation plus purchases less sales) less the current month’s billed KWh plus the prior month’s unbilled KWh.  However, due to meter reading issues, meter drift and other anomalies, a separate monthly calculation limits the unbilled estimate within a range of values.  This limiter calculation is derived from an allocation of billed KWh to the current month and previous month, on a cycle-by-cycle basis, and by dividing the current month aggregated result by the billed KWh.  The limits are statistically set at one standard deviation from this percentage to determine the upper and lower limits of the range.  The unbilled estimate is compared to the limiter calculation and adjusted for variances exceeding the upper and lower limits.

For certain contracts, we calculate unbilled revenues by contract using the most recent historic daily activity adjusted for significant known changes in usage.


 
42

 


Effect if Different Assumptions Used

Significant fluctuations in energy demand for the unbilled period, weather, line losses or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate.  A 1% change in the limiter calculation when it is outside the range would increase or decrease unbilled revenues by 1% of the accrued unbilled revenues.

Accounting for Derivative Instruments

Nature of Estimates Required

We consider fair value techniques, valuation adjustments related to credit and liquidity and judgments related to the probability of forecasted transactions occurring within the specified time period to be critical accounting estimates.  These estimates are considered significant because they are highly susceptible to change from period to period and are dependent on many subjective factors.

Assumptions and Approach Used

We measure the fair values of derivative instruments and hedge instruments accounted for using MTM accounting based primarily on exchange prices and broker quotes.  If a quoted market price is not available, we estimate the fair value based on the best market information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and other assumptions.  Fair value estimates, based upon the best market information available, involve uncertainties and matters of significant judgment.  These uncertainties include projections of macroeconomic trends and future commodity prices, including supply and demand levels and future price volatility.

We reduce fair values by estimated valuation adjustments for items such as discounting, liquidity and credit quality.  We calculate liquidity adjustments by utilizing bid/ask spreads to estimate the potential fair value impact of liquidating open positions over a reasonable period of time.  We calculate credit adjustments on our risk management contracts using estimated default probabilities and recovery rates relative to our counterparties or counterparties with similar credit profiles and contractual netting agreements.

With respect to hedge accounting, we assess hedge effectiveness and evaluate a forecasted transaction’s probability of occurrence within the specified time period as provided in the original hedge documentation.

Effect if Different Assumptions Used

There is inherent risk in valuation modeling given the complexity and volatility of energy markets.  Therefore, it is possible that results in future periods may be materially different as contracts settle.

The probability that hedged forecasted transactions will not occur by the end of the specified time period could change operating results by requiring amounts currently classified in Accumulated Other Comprehensive Income (Loss) to be classified into operating income.

For additional information regarding derivatives, hedging and fair value measurements, see Notes 10 and 11.  See “Fair Value Measurements of Assets and Liabilities” section of Note 1 for fair value calculation policy.

Long-Lived Assets

Nature of Estimates Required

In accordance with the requirements of “Property, Plant and Equipment” accounting guidance, we evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable including planned abandonments and a probable disallowance for rate-making on a plant under construction or the assets meet the held-for-sale criteria.  We utilize a group composite method of depreciation to estimate the useful lives of long-lived assets.  The evaluations of long-lived, held-and-used assets may result from abandonments, significant decreases in the market price of an asset, a significant adverse change in
 
 
43

 
the extent or manner in which an asset is being used or in its physical condition, a significant adverse change in legal factors or in the business climate that could affect the value of an asset, as well as other economic or operations analyses.  If the carrying amount is not recoverable, we record an impairment to the extent that the fair value of the asset is less than its book value.  Performing an impairment evaluation involves a significant degree of estimation and judgment in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping affected assets and developing the undiscounted and discounted future cash flows (used to estimate fair value in the absence of market-based value, in some instances) associated with the asset.  For assets held for sale, an impairment is recognized if the expected net sales price is less than its book value.  For regulated assets, the earnings impact of an impairment charge could be offset by the establishment of a regulatory asset if rate recovery is probable.  For nonregulated assets, any impairment charge is recorded against earnings.

Assumptions and Approach Used

The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties other than in a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets in active markets, we estimate fair value using various internal and external valuation methods including cash flow projections or other market indicators of fair value such as bids received, comparable sales or independent appraisals.  Cash flow estimates are based on relevant information available at the time the estimates are made.  Estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.  Also, when measuring fair value, management evaluates the characteristics of the asset or liability to determine if market participants would take those characteristics into account when pricing the asset or liability at the measurement date.  Such characteristics include, for example, the condition and location of the asset or restrictions of the use of the asset.  We perform depreciation studies that include a review of any external factors that may affect the useful life to determine composite depreciation rates and related lives which are subject to periodic review by state regulatory commissions for cost-based regulated assets.  The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.

Effect if Different Assumptions Used

In connection with the evaluation of long-lived assets in accordance with the requirements of “Property, Plant and Equipment” accounting guidance, the fair value of an asset can vary if different estimates and assumptions would have been used in our applied valuation techniques.  The estimate for depreciation rates takes into account the history of interim capital replacements and the amount of salvage expected.  In cases of impairment, we made our best estimate of fair value using valuation methods based on the most current information at that time.  Fluctuations in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including, but not limited to, differences in subsequent market conditions, the level of bidder interest, timing and terms of the transactions and our analysis of the benefits of the transaction.

Pension and Other Postretirement Benefits

We maintain a qualified, defined benefit pension plan (Qualified Plan), which covers substantially all nonunion and certain union employees, and unfunded, nonqualified supplemental plans (Nonqualified Plans) to provide benefits in excess of amounts permitted under the provisions of the tax law for participants in the Qualified Plan (collectively the Pension Plans).  Additionally, we entered into individual employment contracts with certain current and retired executives that provide additional retirement benefits as a part of the Nonqualified Plans.  We also sponsor other postretirement benefit plans to provide health and life insurance benefits for retired employees (Postretirement Plans).  The Pension Plans and Postretirement Plans are collectively referred to as the Plans.

For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Investments Held in Trust for Future Liabilities” and “Fair Value Measurements of Assets and Liabilities” sections of Note 1.  See Note 8 for information regarding costs and assumptions for employee retirement and postretirement benefits.


 
44

 


The following table shows the net periodic cost (credit) of the Plans:

 
 
 
Years Ended December 31,
Net Periodic Benefit Cost (Credit)
 
2013 
 
2012 
 
2011 
 
 
(in millions)
Pension Plans
 
$
180 
 
$
 134 
 
$
 118 
Postretirement Plans
 
 
(17)
 
 
 89 
 
 
 73 

The net periodic benefit cost is calculated based upon a number of actuarial assumptions, including expected long-term rates of return on the Plans’ assets.  In developing the expected long-term rate of return assumption for 2014, we evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions.  We also considered historical returns of the investment markets and changes in tax rates which affect a portion of the Postretirement Plans’ assets.  We anticipate that the investment managers we employ for the Plans will invest the assets to generate future returns averaging 6% for the Qualified Plan and 6.75% for the Postretirement Plans.

The expected long-term rate of return on the Plans’ assets is based on our targeted asset allocation and our expected investment returns for each investment category.  Our assumptions are summarized in the following table:

 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
 
 
Assumed/
 
 
 
Assumed/
 
2014 
 
Expected
 
2014 
 
Expected
 
Target
 
Long-Term
 
Target
 
Long-Term
 
Asset
 
Rate of
 
Asset
 
Rate of
 
Allocation
 
Return
 
Allocation
 
Return
Equity
 30 
%
 
 8.00 
%
 
 66 
%
 
 7.80 
%
Fixed Income
 55 
%
 
 4.60 
%
 
 33 
%
 
 4.40 
%
Other Investments
 15 
%
 
 7.00 
%
 
%
 
 - 
%
Cash and Cash Equivalents
%
 
%
 
 1 
%
 
 3.00 
%
Total
 100 
%
 
 
 
 
 100 
%
 
 
 

We regularly review the actual asset allocation and periodically rebalance the investments to our targeted allocation.  We believe that 6% and 6.75% are reasonable estimates of the long-term rate of return on the Plans’ assets.  The Pension Plans’ assets had an actual gain of 8.1% and 13.8% for the years ended December 31, 2013 and 2012, respectively.  The Postretirement Plans’ assets had an actual gain of 14.3% and 15.4% for the years ended December 31, 2013 and 2012, respectively.  We will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the assumptions as necessary.

We base our determination of pension expense or income on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets.  Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.  As of December 31, 2013, we had cumulative gains of approximately $207 million that remain to be recognized in the calculation of the market-related value of assets.  These unrecognized net actuarial gains may result in decreases in the future pension costs depending on several factors, including whether such gains at each measurement date exceed the corridor in accordance with “Compensation – Retirement Benefits” accounting guidance.

The method used to determine the discount rate that we utilize for determining future obligations is a duration-based method in which a hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability.  The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.  The discount rate as of December 31, 2013 under this method was 4.7% for the Qualified Plan, 4.55% for the Nonqualified Plans and 4.7% for the Postretirement Plans.  Due to the effect of the unrecognized actuarial gains and based on an expected rate of return on the Pension Plans’ assets of 6%, discount rates of 4.7% and 4.55% and various other assumptions, we estimate that the pension costs for the Pension Plans will approximate $161 million,
 
 
45

 
$113 million and $109 million in 2014, 2015 and 2016, respectively.  Based on an expected rate of return on the Postretirement Plans’ assets of 6.75%, a discount rate of 4.7% and various other assumptions, we estimate credits will approximate $77 million, $82 million and $82 million in 2014, 2015 and 2016, respectively.  Future actual costs will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Plans.  The actuarial assumptions used may differ materially from actual results.  The effects of a 50 basis point change to selective actuarial assumptions are included in the “Effect if Different Assumptions Used” section below.

In November 2012, we announced changes to our retiree medical coverage.  Effective for retirements after December 2012, our contribution to retiree medical costs was capped reducing our future exposure to medical cost inflation.  Effective for employees hired after December 2013, we will not provide retiree medical coverage.  This change reduced costs of the plan beginning in 2013 as shown by the estimated credits for Postretirement Plans in the previous paragraph.

The value of the Pension Plans’ assets remained unchanged at $4.7 billion as of December 31, 2013 and December 31, 2012 primarily due to investment returns offsetting benefit payments.  During 2013, the Qualified Plan paid $324 million and the Nonqualified Plans paid $7 million in benefits to plan participants.  The value of the Postretirement Plans’ assets increased to $1.7 billion as of December 31, 2013 from $1.6 billion as of December 31, 2012 primarily due to investment returns and contributions by the company and the participants in excess of benefit payments.  The Postretirement Plans paid $140 million in benefits to plan participants during 2013.

Nature of Estimates Required

We sponsor pension and other retirement and postretirement benefit plans in various forms covering all employees who meet eligibility requirements.  We account for these benefits under “Compensation” and “Plan Accounting” accounting guidance.  The measurement of our pension and postretirement benefit obligations, costs and liabilities is dependent on a variety of assumptions.

Assumptions and Approach Used

The critical assumptions used in developing the required estimates include the following key factors:

·  
Discount rate
·  
Compensation increase rate
·  
Cash balance crediting rate
·  
Health care cost trend rate
·  
Expected return on plan assets

Other assumptions, such as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience.


 
46

 


Effect if Different Assumptions Used

The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, longer or shorter life spans of participants or higher or lower lump sum versus annuity payout elections by plan participants.  These differences may result in a significant impact to the amount of pension and postretirement benefit expense recorded.  If a 50 basis point change were to occur for the following assumptions, the approximate effect on the financial statements would be as follows:

 
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
+0.5%
 
-0.5%
 
+0.5%
 
-0.5%
 
 
(in millions)
Effect on December 31, 2013 Benefit Obligations
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
$
 (233)
 
$
 254 
 
$
 (71)
 
$
 78 
Compensation Increase Rate
 
 
 13 
 
 
 (12)
 
 
NA 
 
 
NA 
Cash Balance Crediting Rate
 
 
 43 
 
 
 (39)
 
 
NA 
 
 
NA 
Health Care Cost Trend Rate
 
 
NA 
 
 
NA 
 
 
 25 
 
 
 (28)
 
 
 
 
 
 
 
 
 
 
 
 
 
Effect on 2013 Periodic Cost
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
 
 (12)
 
 
 13 
 
 
 (4)
 
 
 4 
Compensation Increase Rate
 
 
 4 
 
 
 (4)
 
 
NA 
 
 
NA 
Cash Balance Crediting Rate
 
 
 11 
 
 
 (11)
 
 
NA 
 
 
NA 
Health Care Cost Trend Rate
 
 
NA 
 
 
NA 
 
 
 4 
 
 
 (4)
Expected Return on Plan Assets
 
 
 (21)
 
 
 21 
 
 
 (8)
 
 
 8 
 
 
 
 
 
 
 
 
 
 
 
 
 
NA   Not applicable.
 
 
 
 
 
 
 
 
 
 
 
 

ACCOUNTING PRONOUNCEMENTS

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, we cannot determine the impact on the reporting of our operations and financial position that may result from any such future changes.  The FASB is currently working on several projects including revenue recognition, financial instruments, leases, insurance, hedge accounting and consolidation policy.  The ultimate pronouncements resulting from these and future projects could have an impact on our future net income and financial position.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

Our Vertically Integrated Utilities segment is exposed to certain market risks as a major power producer and through its transactions in power, coal, natural gas and marketing contracts.  These risks include commodity price risk, interest rate risk and credit risk.  In addition, we are exposed to foreign currency exchange risk as we occasionally procure various services and materials used in our energy business from foreign suppliers.  These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

Our Transmission and Distribution Utilities segment is exposed to FTR price risk as it relates to congestion during the June 2012 – May 2015 Ohio ESP period.  Additional risk includes interest rate risk.

Our Generation & Marketing segment conducts marketing, risk management and retail activities in ERCOT, PJM and MISO.  This segment is exposed to certain market risks as a marketer of wholesale and retail electricity.  These risks include commodity price risk, interest rate risk and credit risk.  These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.  In addition, our Generation & Marketing segment is also exposed to certain market risks as a major power producer and through its transactions in wholesale electricity, natural gas and coal trading and marketing contracts.
 
 
47

 

We employ risk management contracts including physical forward purchase-and-sale contracts and financial forward purchase-and-sale contracts.  We engage in risk management of power, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with our energy business.  As a result, we are subject to price risk.  The amount of risk taken is determined by the Commercial Operations, Energy Supply, and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors.  Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures.  The Regulated Risk Committee consists of our Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.  The Competitive Risk Committee consists of our Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer.  When commercial activities exceed predetermined limits, we modify the positions to reduce the risk to be within the limits unless specifically approved by the respective committee.

The following table summarizes the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2012:

 
MTM Risk Management Contract Net Assets (Liabilities)
 
Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Transmission
 
 
 
 
 
 
Vertically
 
and
 
Generation
 
 
 
 
Integrated
 
Distribution
 
and
 
 
 
 
Utilities
 
Utilities
 
Marketing
 
Total
 
 
 
(in millions)
Total MTM Risk Management Contract Net Assets
 
 
 
 
 
 
 
 
 
 
 
 
as of December 31, 2012
$
 39 
 
$
 (1)
 
$
 158 
 
$
 196 
(Gain) Loss from Contracts Realized/Settled During the
 
 
 
 
 
 
 
 
 
 
 
 
Period and Entered in a Prior Period
 
 (16)
 
 
 1 
 
 
 (32)
 
 
 (47)
Fair Value of New Contracts at Inception When Entered
 
 
 
 
 
 
 
 
 
 
 
 
During the Period (a)
 
 - 
 
 
 - 
 
 
 16 
 
 
 16 
Changes in Fair Value Due to Market Fluctuations
 
 
 
 
 
 
 
 
 
 
 
 
During the Period (b)
 
 - 
 
 
 - 
 
 
 15 
 
 
 15 
Changes in Fair Value Allocated to Regulated
 
 
 
 
 
 
 
 
 
 
 
 
Jurisdictions (c)
 
 9 
 
 
 3 
 
 
 - 
 
 
 12 
Total MTM Risk Management Contract Net Assets
 
 
 
 
 
 
 
 
 
 
 
 
as of December 31, 2013
$
 32 
 
$
 3 
 
$
 157 
 
 
 192 
Commodity Cash Flow Hedge Contracts
 
 
 
 
 
 
 
 
 
 
 1 
Interest Rate and Foreign Currency Cash Flow Hedge
 
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
 
 
 
 
 
 
 
 
 
 (2)
Fair Value Hedge Contracts
 
 
 
 
 
 
 
 
 
 
 (10)
Collateral Deposits
 
 
 
 
 
 
 
 
 
 
 9 
Total MTM Derivative Contract Net Assets as of
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
 
 
 
 
 
 
 
 
 
$
 190 

(a)
Reflects fair value on primarily long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  The contract prices are valued against market curves associated with the delivery location and delivery term.  A significant portion of the total volumetric position has been economically hedged.
(b)
Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)
Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These net gains (losses) are recorded as regulatory liabilities/assets.

See Note 10 – Derivatives and Hedging and Note 11 – Fair Value Measurements for additional information related to our risk management contracts.  The following tables and discussion provide information on our credit risk and market volatility risk.


 
48

 


Credit Risk

We limit credit risk in our wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.  We use Moody’s Investors Service, Standard & Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

We have risk management contracts with numerous counterparties.  Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily.  As of December 31, 2013, our credit exposure net of collateral to sub investment grade counterparties was approximately 8.7%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).  As of December 31, 2013, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

 
 
 
Exposure
 
 
 
 
 
Number of
 
Net Exposure
 
 
Before
 
 
Counterparties
of
 
 
Credit
Credit
Net
>10% of
Counterparties
Counterparty Credit Quality
Collateral
Collateral
Exposure
Net Exposure
>10%
 
 
 
(in millions, except number of counterparties)
Investment Grade
 
$
 630 
 
$
 7 
 
$
 623 
 
 
 2 
 
$
 290 
Split Rating
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Noninvestment Grade
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
No External Ratings:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Internal Investment Grade
 
 
 79 
 
 
 - 
 
 
 79 
 
 
 4 
 
 
 45 
 
Internal Noninvestment Grade
 
 
 78 
 
 
 11 
 
 
 67 
 
 
 3 
 
 
 46 
Total as of December 31, 2013
 
$
 787 
 
$
 18 
 
$
 769 
 
 
 9 
 
$
 381 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total as of December 31, 2012
 
$
 807 
 
$
 13 
 
$
 794 
 
 
 7 
 
$
 338 
 
In addition, we are exposed to credit risk related to our participation in RTOs.  For each of the RTOs in which we participate, this risk is generally determined based on our proportionate share of member gross activity over a specified period of time.
 
Value at Risk (VaR) Associated with Risk Management Contracts

We use a risk measurement model, which calculates VaR, to measure our commodity price risk in the risk management portfolio.  The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, as of December 31, 2013, a near term typical change in commodity prices is not expected to materially impact net income, cash flows or financial condition.

The following table shows the end, high, average and low market risk as measured by VaR for the trading portfolio for the periods indicated:

VaR Model

Twelve Months Ended
 
Twelve Months Ended
December 31, 2013
 
December 31, 2012
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
(in millions)
 
(in millions)
$
 
$
 
$
 
$
 
$
 
$
 
$
 
$

We back-test our VaR results against performance due to actual price movements.  Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.
 
 
49

 

As our VaR calculation captures recent price movements, we also perform regular stress testing of the portfolio to understand our exposure to extreme price movements.  We employ a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last several years in order to ascertain which historical price movements translated into the largest potential MTM loss.  We then research the underlying positions, price movements and market events that created the most significant exposure and report the findings to the Risk Executive Committee, Regulated Risk Committee, or Competitive Risk Committee as appropriate.

Interest Rate Risk

We utilize an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which our interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on debt outstanding as of December 31, 2013 and 2012, the estimated EaR on our debt portfolio for the following twelve months was $32 million and $42 million, respectively.

 
50

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
American Electric Power Company, Inc.:

We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and subsidiary companies (the "Company") as of December 31, 2013 and 2012,and the related consolidated statements of income, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of American Electric Power Company, Inc. and subsidiary companies as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2014 expressed an unqualified opinion on the Company's internal control over financial reporting.

/s/  Deloitte & Touche LLP

Columbus, Ohio
February 25, 2014

 
51

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
American Electric Power Company, Inc.:

We have audited the internal control over financial reporting of American Electric Power Company, Inc. and subsidiary companies (the "Company") as of December 31, 2013, based on criteria established in Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting.  Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2013 of the Company and our report dated February 25, 2014 expressed an unqualified opinion on those financial statements.

/s/  Deloitte & Touche LLP

Columbus, Ohio
February 25, 2014

 
52

 

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of American Electric Power Company, Inc. and subsidiary companies (AEP) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a- 15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  AEP’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of AEP’s internal control over financial reporting as of December 31, 2013.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 1992) in Internal Control – Integrated Framework.  Based on management’s assessment, AEP’s internal control over financial reporting was effective as of December 31, 2013.

AEP’s independent registered public accounting firm has issued an attestation report on AEP’s internal control over financial reporting.  The Report of Independent Registered Public Accounting Firm appears on the previous page.

 
53

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2013, 2012 and 2011
 (in millions, except per-share and share amounts)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
REVENUES
 
 
 
 
 
 
 
 
 
Vertically Integrated Utilities
 
$
 9,347 
 
$
 8,785 
 
$
 8,942 
Transmission and Distribution Utilities
 
 
 4,279 
 
 
 4,659 
 
 
 4,982 
Generation & Marketing
 
 
 1,208 
 
 
 882 
 
 
 563 
Other Revenues
 
 
 523 
 
 
 619 
 
 
 629 
TOTAL REVENUES
 
 
 15,357 
 
 
 14,945 
 
 
 15,116 
EXPENSES
 
 
 
 
 
 
 
 
 
Fuel and Other Consumables Used for Electric Generation
 
 
 4,068 
 
 
 4,111 
 
 
 4,421 
Purchased Electricity for Resale
 
 
 1,491 
 
 
 1,169 
 
 
 1,191 
Other Operation
 
 
 2,904 
 
 
 2,962 
 
 
 2,868 
Maintenance
 
 
 1,179 
 
 
 1,115 
 
 
 1,236 
Asset Impairments and Other Related Charges
 
 
 226 
 
 
 300 
 
 
 139 
Depreciation and Amortization
 
 
 1,743 
 
 
 1,782 
 
 
 1,655 
Taxes Other Than Income Taxes
 
 
 891 
 
 
 850 
 
 
 824 
TOTAL EXPENSES
 
 
 12,502 
 
 
 12,289 
 
 
 12,334 
 
 
 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
 
 2,855 
 
 
 2,656 
 
 
 2,782 
 
 
 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 
 
 
 
 
 
 
 
Interest and Investment Income
 
 
 58 
 
 
 8 
 
 
 27 
Carrying Costs Income
 
 
 30 
 
 
 53 
 
 
 393 
Allowance for Equity Funds Used During Construction
 
 
 73 
 
 
 93 
 
 
 98 
Interest Expense
 
 
 (906)
 
 
 (988)
 
 
 (933)
 
 
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
 
 
 2,110 
 
 
 1,822 
 
 
 2,367 
 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 684 
 
 
 604 
 
 
 818 
Equity Earnings of Unconsolidated Subsidiaries
 
 
 58 
 
 
 44 
 
 
 27 
 
 
 
 
 
 
 
 
 
 
 
INCOME BEFORE EXTRAORDINARY ITEM
 
 
 1,484 
 
 
 1,262 
 
 
 1,576 
 
 
 
 
 
 
 
 
 
 
 
EXTRAORDINARY ITEM, NET OF TAX
 
 
 - 
 
 
 - 
 
 
 373 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME
 
 
 1,484 
 
 
 1,262 
 
 
 1,949 
 
 
 
 
 
 
 
 
 
 
 
Net Income Attributable to Noncontrolling Interests
 
 
 4 
 
 
 3 
 
 
 3 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS
 
 
 1,480 
 
 
 1,259 
 
 
 1,946 
 
 
 
 
 
 
 
 
 
 
 
Preferred Stock Dividend Requirements of Subsidiaries Including Capital Stock Expense
 
 
 - 
 
 
 - 
 
 
 5 
 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
 1,480 
 
$
 1,259 
 
$
 1,941 
 
 
 
 
 
 
 
 
 
 
 
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
 
 
486,619,555 
 
 
484,682,469 
 
 
482,169,282 
 
 
 
 
 
 
 
 
 
 
 
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
 
 
 
 
 
 
 
 
Income Before Extraordinary Item
 
$
 3.04 
 
$
 2.60 
 
$
 3.25 
Extraordinary Item, Net of Tax
 
 
 - 
 
 
 - 
 
 
 0.77 
 
 
 
 
 
 
 
 
 
 
 
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
 3.04 
 
$
 2.60 
 
$
 4.02 
 
 
 
 
 
 
 
 
 
 
 
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING
 
 
487,040,956 
 
 
485,084,694 
 
 
482,460,328 
 
 
 
 
 
 
 
 
 
 
 
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
 
 
 
 
 
 
 
 
Income Before Extraordinary Item
 
$
 3.04 
 
$
 2.60 
 
$
 3.25 
Extraordinary Item, Net of Tax
 
 
 - 
 
 
 - 
 
 
 0.77 
 
 
 
 
 
 
 
 
 
 
 
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
 
 
 
 
 
 
 
 
 
 
SHAREHOLDERS
 
$
 3.04 
 
$
 2.60 
 
$
 4.02 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements beginning on page 60.
 
 
 
 
 
 
 
 
 

 
54

 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2013, 2012 and 2011
 (in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
Net Income
 
$
 1,484 
 
$
 1,262 
 
$
 1,949 
 
 
 
 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $8, $8 and $18 in 2013, 2012 and 2011,
 
 
 
 
 
 
 
 
 
 
Respectively
 
 
 15 
 
 
 (15)
 
 
 (34)
Securities Available for Sale, Net of Tax of $1, $1 and $1 in 2013, 2012 and
 
 
 
 
 
 
 
 
 
 
2011, Respectively
 
 
 3 
 
 
 2 
 
 
 (2)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $12, $16
 
 
 
 
 
 
 
 
 
 
and $13 in 2013, 2012 and 2011, Respectively
 
 
 22 
 
 
 31 
 
 
 24 
Pension and OPEB Funded Status, Net of Tax of $95, $62 and $41 in 2013,
 
 
 
 
 
 
 
 
 
 
2012 and 2011, Respectively
 
 
 177 
 
 
 115 
 
 
 (77)
 
 
 
 
 
 
 
 
 
 
 
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
 
 
 217 
 
 
 133 
 
 
 (89)
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
 
 
 1,701 
 
 
 1,395 
 
 
 1,860 
 
 
 
 
 
 
 
 
 
 
 
Total Comprehensive Income Attributable to Noncontrolling Interests
 
 
 4 
 
 
 3 
 
 
 3 
 
 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
 
 
 
 
 
 
 
 
 
 
SHAREHOLDERS
 
 
 1,697 
 
 
 1,392 
 
 
 1,857 
 
 
 
 
 
 
 
 
 
 
 
Preferred Stock Dividend Requirements of Subsidiaries Including
 
 
 
 
 
 
 
 
 
 
Capital Stock Expense
 
 
 - 
 
 
 - 
 
 
 5 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
 
 
 
 
 
 
 
 
 
 
COMMON SHAREHOLDERS
 
$
 1,697 
 
$
 1,392 
 
$
 1,852 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements beginning on page 60.
 
 
 
 
 
 
 
 
 

 
55

 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2013, 2012 and 2011
(in millions)
 
 
AEP Common Shareholders
 
 
 
 
 
Common Stock
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
 
 
 
 
 
Paid-in
 
Retained
 
Comprehensive
 
Noncontrolling
 
 
 
 
 
 
Shares
 
Amount
 
Capital
 
Earnings
 
Income (Loss)
 
Interests
 
Total
TOTAL EQUITY – DECEMBER 31, 2010
 
 501 
 
 3,257 
 
 5,904 
 
 4,842 
 
 (381)
 
 - 
 
 13,622 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of Common Stock
 
 3 
 
 
 17 
 
 
 75 
 
 
 
 
 
 
 
 
 
 
 
 92 
Common Stock Dividends ($1.85/share)
 
 
 
 
 
 
 
 
 
 
 (894)
 
 
 
 
 
 (4)
 
 
 (898)
Preferred Stock Dividend Requirements of Subsidiaries
 
 
 
 
 
 
 
 
 
 
 (2)
 
 
 
 
 
 
 
 
 (2)
Loss on Reacquired Preferred Stock
 
 
 
 
 
 
 
 (4)
 
 
 
 
 
 
 
 
 
 
 
 (4)
Capital Stock Expense
 
 
 
 
 
 
 
 (16)
 
 
 
 
 
 
 
 
 
 
 
 (16)
Other Changes in Equity
 
 
 
 
 
 
 
 11 
 
 
 (2)
 
 
 
 
 
 2 
 
 
 11 
Net Income
 
 
 
 
 
 
 
 
 
 
 1,946 
 
 
 
 
 
 3 
 
 
 1,949 
Other Comprehensive Loss
 
 
 
 
 
 
 
 
 
 
 
 
 
 (89)
 
 
 
 
 
 (89)
TOTAL EQUITY – DECEMBER 31, 2011
 
 504 
 
 
 3,274 
 
 
 5,970 
 
 
 5,890 
 
 
 (470)
 
 
 1 
 
 
 14,665 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of Common Stock
 
 2 
 
 
 15 
 
 
 68 
 
 
 
 
 
 
 
 
 
 
 
 83 
Common Stock Dividends ($1.88/share)
 
 
 
 
 
 
 
 
 
 
 (913)
 
 
 
 
 
 (3)
 
 
 (916)
Other Changes in Equity
 
 
 
 
 
 
 
 11 
 
 
 
 
 
 
 
 
 (1)
 
 
 10 
Net Income
 
 
 
 
 
 
 
 
 
 
 1,259 
 
 
 
 
 
 3 
 
 
 1,262 
Other Comprehensive Income
 
 
 
 
 
 
 
 
 
 
 
 
 
 133 
 
 
 
 
 
 133 
TOTAL EQUITY – DECEMBER 31, 2012
 
 506 
 
 
 3,289 
 
 
 6,049 
 
 
 6,236 
 
 
 (337)
 
 
 - 
 
 
 15,237 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of Common Stock
 
 2 
 
 
 14 
 
 
 70 
 
 
 
 
 
 
 
 
 
 
 
 84 
Common Stock Dividends ($1.95/share)
 
 
 
 
 
 
 
 
 
 
 (950)
 
 
 
 
 
 (4)
 
 
 (954)
Other Changes in Equity
 
 
 
 
 
 
 
 12 
 
 
 
 
 
 
 
 
 1 
 
 
 13 
Net Income
 
 
 
 
 
 
 
 
 
 
 1,480 
 
 
 
 
 
 4 
 
 
 1,484 
Other Comprehensive Income
 
 
 
 
 
 
 
 
 
 
 
 
 
 217 
 
 
 
 
 
 217 
Pension and OPEB Adjustment Related to Mitchell Plant
 
 
 
 
 
 
 
 
 
 
 
 
 
 5 
 
 
 
 
 
 5 
TOTAL EQUITY – DECEMBER 31, 2013
 
 508 
 
 3,303 
 
 6,131 
 
 6,766 
 
 (115)
 
 1 
 
 16,086 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements beginning on page 60.

 
56

 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2013 and 2012
(in millions)
 
 
 
 
 
 
 
 
 
December 31,
 
 
2013 
 
2012 
CURRENT ASSETS
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 118 
 
$
 279 
Other Temporary Investments
 
 
 
 
 
 
 
(December 31, 2013 and 2012 Amounts Include $335 and $311, Respectively, Related to Transition Funding, Phase-in-Recovery Funding, Consumer Rate Relief Funding and EIS)
 
 
 353 
 
 
 324 
Accounts Receivable:
 
 
 
 
 
 
 
Customers
 
 
 746 
 
 
 685 
 
Accrued Unbilled Revenues
 
 
 157 
 
 
 195 
 
Pledged Accounts Receivable - AEP Credit
 
 
 945 
 
 
 856 
 
Miscellaneous
 
 
 72 
 
 
 171 
 
Allowance for Uncollectible Accounts
 
 
 (60)
 
 
 (36)
 
 
Total Accounts Receivable
 
 
 1,860 
 
 
 1,871 
Fuel
 
 
 701 
 
 
 844 
Materials and Supplies
 
 
 722 
 
 
 675 
Risk Management Assets
 
 
 160 
 
 
 191 
Regulatory Asset for Under-Recovered Fuel Costs
 
 
 80 
 
 
 88 
Margin Deposits
 
 
 70 
 
 
 76 
Prepayments and Other Current Assets
 
 
 246 
 
 
 241 
TOTAL CURRENT ASSETS
 
 
 4,310 
 
 
 4,589 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
Generation
 
 
 25,074 
 
 
 26,279 
 
Transmission
 
 
 10,893 
 
 
 9,846 
 
Distribution
 
 
 16,377 
 
 
 15,565 
Other Property, Plant and Equipment (Including Plant to be Retired, Coal Mining
 
 
 
 
 
 
 
and Nuclear Fuel)
 
 
 5,470 
 
 
 3,945 
Construction Work in Progress
 
 
 2,471 
 
 
 1,819 
Total Property, Plant and Equipment
 
 
 60,285 
 
 
 57,454 
Accumulated Depreciation and Amortization
 
 
 19,288 
 
 
 18,691 
TOTAL PROPERTY, PLANT AND EQUIPMENT NET
 
 
 40,997 
 
 
 38,763 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
Regulatory Assets
 
 
 4,376 
 
 
 5,106 
Securitized Assets
 
 
 2,373 
 
 
 2,117 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 1,932 
 
 
 1,706 
Goodwill
 
 
 91 
 
 
 91 
Long-term Risk Management Assets
 
 
 297 
 
 
 368 
Deferred Charges and Other Noncurrent Assets
 
 
 2,038 
 
 
 1,627 
TOTAL OTHER NONCURRENT ASSETS
 
 
 11,107 
 
 
 11,015 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 56,414 
 
$
 54,367 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements beginning on page 60.
 
 
 
 
 
 

 
57

 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31, 2013 and 2012
(dollars in millions)
 
 
 
 
 
 
 
 
 
December 31,
 
 
2013 
 
2012 
CURRENT LIABILITIES
 
 
Accounts Payable
 
$
 1,266 
 
$
 1,169 
Short-term Debt:
 
 
 
 
 
 
 
Securitized Debt for Receivables - AEP Credit
 
 
 700 
 
 
 657 
 
Other Short-term Debt
 
 
 57 
 
 
 324 
 
 
Total Short-term Debt
 
 
 757 
 
 
 981 
Long-term Debt Due Within One Year
 
 
 
 
 
 
 
(December 31, 2013 and 2012 Amounts Include $416 and $367, Respectively, Related to Transition Funding, DCC Fuel, Phase-in-Recovery Funding, Consumer Rate Relief Funding and Sabine)
 
 
 1,549 
 
 
 2,171 
Risk Management Liabilities
 
 
 90 
 
 
 155 
Customer Deposits
 
 
 299 
 
 
 316 
Accrued Taxes
 
 
 822 
 
 
 747 
Accrued Interest
 
 
 245 
 
 
 269 
Regulatory Liability for Over-Recovered Fuel Costs
 
 
 119 
 
 
 47 
Other Current Liabilities
 
 
 965 
 
 
 968 
TOTAL CURRENT LIABILITIES
 
 
 6,112 
 
 
 6,823 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
Long-term Debt
 
 
 
 
 
 
 
(December 31, 2013 and 2012 Amounts Include $2,532 and $2,227, Respectively, Related to Transition Funding, DCC Fuel, Phase-in-Recovery Funding, Consumer Rate Relief Funding and Sabine)
 
 
 16,828 
 
 
 15,586 
Long-term Risk Management Liabilities
 
 
 177 
 
 
 214 
Deferred Income Taxes
 
 
 10,300 
 
 
 9,252 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 3,694 
 
 
 3,544 
Asset Retirement Obligations
 
 
 1,835 
 
 
 1,696 
Employee Benefits and Pension Obligations
 
 
 415 
 
 
 1,075 
Deferred Credits and Other Noncurrent Liabilities
 
 
 967 
 
 
 940 
TOTAL NONCURRENT LIABILITIES
 
 
 34,216 
 
 
 32,307 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 40,328 
 
 
 39,130 
 
 
 
 
 
 
 
Rate Matters (Note 4)
 
 
 
 
 
 
Commitments and Contingencies (Note 6)
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY
 
 
 
 
 
 
Common Stock – Par Value – $6.50 Per Share:
 
 
 
 
 
 
 
 
 
2013 
 
2012 
 
 
 
 
 
 
 
 
Shares Authorized
600,000,000 
 
600,000,000 
 
 
 
 
 
 
 
 
Shares Issued
508,113,964 
 
506,004,962 
 
 
 
 
 
 
 
(20,336,592 Shares were Held in Treasury as of December 31, 2013 and 2012)
 
 
 3,303 
 
 
 3,289 
Paid-in Capital
 
 
 6,131 
 
 
 6,049 
Retained Earnings
 
 
 6,766 
 
 
 6,236 
Accumulated Other Comprehensive Income (Loss)
 
 
 (115)
 
 
 (337)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY
 
 
 16,085 
 
 
 15,237 
 
 
 
 
 
 
 
Noncontrolling Interests
 
 
 1 
 
 
 - 
 
 
 
 
 
 
 
TOTAL EQUITY
 
 
 16,086 
 
 
 15,237 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 
$
 56,414 
 
$
 54,367 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements beginning on page 60.
 
 
 
 
 
 

 
58

 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2013, 2012 and 2011
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
2013 
 
2012 
 
2011 
OPERATING ACTIVITIES
 
 
 
 
 
 
 
 
 
Net Income
 
 1,484 
 
 1,262 
 
 1,949 
Adjustments to Reconcile Net Income to Net Cash Flows
 
 
 
 
 
 
 
 
 
 
from Operating Activities:
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 1,743 
 
 
 1,782 
 
 
 1,655 
 
 
Deferred Income Taxes
 
 
 709 
 
 
 636 
 
 
 794 
 
 
Gain on Settlement with BOA and Enron
 
 
 - 
 
 
 - 
 
 
 (51)
 
 
Settlement of Litigation with BOA and Enron
 
 
 - 
 
 
 - 
 
 
 (211)
 
 
Extraordinary Item, Net of Tax
 
 
 - 
 
 
 - 
 
 
 (373)
 
 
Asset Impairments and Other Related Charges
 
 
 226 
 
 
 300 
 
 
 139 
 
 
Carrying Costs Income
 
 
 (30)
 
 
 (53)
 
 
 (393)
 
 
Allowance for Equity Funds Used During Construction
 
 
 (73)
 
 
 (93)
 
 
 (98)
 
 
Mark-to-Market of Risk Management Contracts
 
 
 38 
 
 
 57 
 
 
 37 
 
 
Amortization of Nuclear Fuel
 
 
 131 
 
 
 136 
 
 
 137 
 
 
Pension Contributions to Qualified Plan Trust
 
 
 - 
 
 
 (200)
 
 
 (450)
 
 
Property Taxes
 
 
 (35)
 
 
 (19)
 
 
 (15)
 
 
Fuel Over/Under-Recovery, Net
 
 
 62 
 
 
 157 
 
 
 (25)
 
 
Deferral of Ohio Capacity Costs, Net
 
 
 (214)
 
 
 (65)
 
 
 - 
 
 
Change in Other Noncurrent Assets
 
 
 (184)
 
 
 (171)
 
 
 (112)
 
 
Change in Other Noncurrent Liabilities
 
 
 3 
 
 
 127 
 
 
 307 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 5 
 
 
 (16)
 
 
 107 
 
 
 
Fuel, Materials and Supplies
 
 
 122 
 
 
 (224)
 
 
 176 
 
 
 
Accounts Payable
 
 
 95 
 
 
 (60)
 
 
 (44)
 
 
 
Accrued Taxes, Net
 
 
 85 
 
 
 174 
 
 
 193 
 
 
 
Other Current Assets
 
 
 5 
 
 
 (3)
 
 
 37 
 
 
 
Other Current Liabilities
 
 
 (66)
 
 
 77 
 
 
 29 
Net Cash Flows from Operating Activities
 
 
 4,106 
 
 
 3,804 
 
 
 3,788 
 
 
 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
 
 
 
Construction Expenditures
 
 
 (3,624)
 
 
 (3,025)
 
 
 (2,669)
Change in Other Temporary Investments, Net
 
 
 (11)
 
 
 (27)
 
 
 8 
Purchases of Investment Securities
 
 
 (927)
 
 
 (1,047)
 
 
 (1,321)
Sales of Investment Securities
 
 
 858 
 
 
 988 
 
 
 1,379 
Acquisitions of Nuclear Fuel
 
 
 (154)
 
 
 (107)
 
 
 (106)
Acquisitions of Assets/Businesses
 
 
 (32)
 
 
 (94)
 
 
 (19)
Acquisition of Cushion Gas from BOA
 
 
 - 
 
 
 - 
 
 
 (214)
Insurance Proceeds Related to Cook Plant Fire
 
 
 72 
 
 
 - 
 
 
 - 
Proceeds from Sales of Assets
 
 
 21 
 
 
 18 
 
 
 123 
Other Investing Activities
 
 
 (21)
 
 
 (97)
 
 
 (71)
Net Cash Flows Used for Investing Activities
 
 
 (3,818)
 
 
 (3,391)
 
 
 (2,890)
 
 
 
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
 
 
 
Issuance of Common Stock, Net
 
 
 84 
 
 
 83 
 
 
 92 
Issuance of Long-term Debt
 
 
 3,207 
 
 
 2,856 
 
 
 1,328 
Commercial Paper and Credit Facility Borrowings
 
 
 17 
 
 
 25 
 
 
 488 
Change in Short-term Debt, Net
 
 
 (221)
 
 
 (654)
 
 
 744 
Retirement of Long-term Debt
 
 
 (2,598)
 
 
 (1,643)
 
 
 (1,665)
Retirement of Cumulative Preferred Stock
 
 
 - 
 
 
 - 
 
 
 (64)
Proceeds from Nuclear Fuel Sale/Leaseback
 
 
 110 
 
 
 - 
 
 
 - 
Commercial Paper and Credit Facility Repayments
 
 
 (20)
 
 
 (40)
 
 
 (928)
Principal Payments for Capital Lease Obligations
 
 
 (82)
 
 
 (71)
 
 
 (71)
Dividends Paid on Common Stock
 
 
 (954)
 
 
 (916)
 
 
 (898)
Dividends Paid on Cumulative Preferred Stock
 
 
 - 
 
 
 - 
 
 
 (2)
Other Financing Activities
 
 
 8 
 
 
 5 
 
 
 5 
Net Cash Flows Used for Financing Activities
 
 
 (449)
 
 
 (355)
 
 
 (971)
 
 
 
 
 
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 (161)
 
 
 58 
 
 
 (73)
Cash and Cash Equivalents at Beginning of Period
 
 
 279 
 
 
 221 
 
 
 294 
Cash and Cash Equivalents at End of Period
 
 118 
 
 279 
 
 221 
 
 
 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements beginning on page 60.
 
 
 
 
 
 
 
 
 

 
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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 
Page
Number
   
Organization and Summary of Significant Accounting Policies
  61
Extraordinary Item
  76
Comprehensive Income
  76
Rate Matters
  79
Effects of Regulation
  90
Commitments, Guarantees and Contingencies
  93
Acquisitions and Impairments
  98
Benefit Plans
  100
Business Segments
  110
Derivatives and Hedging
  113
Fair Value Measurements
  119
Income Taxes
  125
Leases
  130
Financing Activities
  132
Stock-Based Compensation
  136
Variable Interest Entities
  141
Property, Plant and Equipment
  145
Sustainable Cost Reductions
  148
Unaudited Quarterly Financial Information
  149
Goodwill and Other Intangible Assets
  150

 
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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
1.   ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

Our principal business is the generation, transmission and distribution of electric power.  The subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines.  Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions.

We provide competitive electric supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provide energy management solutions throughout the United States, including energy efficiency services through our independent retail electric supplier.

We also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services.  In addition, our operations include nonregulated wind farms and barging operations.

Corporate Separation

Background

On December 31, 2013, based on FERC and PUCO orders which approved corporate separation of generation assets and associated liabilities, OPCo transferred its generation assets and related generation liabilities at net book value to AGR.  In accordance with Ohio law, OPCo remains responsible to provide power and capacity to OPCo customers who have not switched electric providers.  Effective January 1, 2014, OPCo will purchase power from both affiliated and nonaffiliated entities, subject to PUCO approval, to meet the energy and capacity needs of customers.

On December 31, 2013, subsequent to the transfer of OPCo’s generation assets and associated liabilities to AGR, AGR transferred at net book value its ownership (867 MW) in Amos Plant, Unit 3 to APCo.  The transfer of these generation assets and associated liabilities was approved by the FERC, the Virginia SCC and the WVPSC.

On December 31, 2013, subsequent to the transfer of OPCo’s generation assets and associated liabilities to AGR, AGR transferred at net book value a one-half interest (780 MW) in the Mitchell Plant to KPCo.  The transfer of these generation assets and associated liabilities was approved by the FERC and the KPSC.

Other Impacts of Corporate Separation

In accordance with our December 2010 announcement and our October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014.  The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated.

Effective January 1, 2014, the FERC approved:

·  
PCA among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.  Under the PCA, APCo, I&M and KPCo will be individually responsible for planning their respective capacity obligations and there will be no capacity equalization charges/credits on deficit/surplus companies.   Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities.
·  
Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent.  The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies will fulfill their existing obligations under the PJM Reliability Assurance
 
 
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Agreement through the 2014/2015 PJM planning year.  Under the Bridge Agreement, AGR is committed to meet capacity obligations of member companies through May 31, 2015.
·  
Power Supply Agreement (PSA) between AGR and OPCo for AGR to supply capacity for OPCo’s switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that is not acquired through auctions from January 1, 2014 through December 31, 2014.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

Our public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in our eleven state operating territories.  The FERC also regulates our affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act.  The FERC also has jurisdiction over the issuances and acquisitions of securities of our public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company.  For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate.  The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes.  Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system.

The FERC regulates wholesale power markets and wholesale power transactions.  Our wholesale power transactions are generally market-based.  Wholesale power transactions are cost-based regulated when we negotiate and file a cost-based contract with the FERC or the FERC determines that we have “market power” in the region where the transaction occurs.  We have entered into wholesale power supply contracts with various municipalities and cooperatives that are FERC-regulated, cost-based contracts.  These contracts are generally formula rate mechanisms, which are trued up to actual costs annually.  Our wholesale power transactions in the SPP region are currently cost-based within our balancing authority due to the FERC’s finding that PSO and SWEPCo have market power in the SPP region.

The state regulatory commissions regulate all of the distribution operations and rates of our retail public utilities on a cost basis.  The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas.  The ESP rates in Ohio continue the process of transitioning generation/power supply rates over time to market rates.  In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing and is conducted by Texas Retail Electric Providers (REPs).  Through our nonregulated subsidiaries, we enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market.  In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT.  We have no active REPs in ERCOT.

The FERC also regulates our wholesale transmission operations and rates.  The FERC claims jurisdiction over retail transmission rates when retail rates are unbundled in connection with restructuring.  OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia, I&M’s retail transmission rates in Michigan and TCC’s and TNC’s retail transmission rates in Texas are unbundled.  OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia and I&M’s retail transmission rates in Michigan are based on formula rates included in the PJM OATT that are cost-based.  Although TCC’s and TNC’s retail transmission rates in Texas are unbundled, retail transmission rates are regulated, on a cost basis, by the PUCT.  Bundled retail transmission rates are regulated, on a cost basis, by the state commissions.  Transmission rates for our seven wholly-owned transmission subsidiaries within our AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based.

In addition, the FERC regulates the SIA, the Operating Agreement, the System Transmission Integration Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which are still active and allocate shared system costs and revenues to the utility subsidiaries that are parties to each agreement.  In accordance with management’s December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014.  The AEP System Interim Allowance
 
 
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Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated.  In December 2013, the FERC issued orders approving the creation of a PCA, effective January 1, 2014.  Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent.

Principles of Consolidation

Our consolidated financial statements include our wholly-owned and majority-owned subsidiaries and VIEs of which we are the primary beneficiary.  Intercompany items are eliminated in consolidation.  We use the equity method of accounting for equity investments where we exercise significant influence but do not hold a controlling financial interest.  Such investments are recorded as Deferred Charges and Other Noncurrent Assets on the balance sheets; equity earnings are included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income.  We have ownership interests in generating units that are jointly-owned with nonaffiliated companies.  Our proportionate share of the operating costs associated with such facilities is included on the statements of income and our proportionate share of the assets and liabilities are reflected on the balance sheets.

Accounting for the Effects of Cost-Based Regulation

As the owner of rate-regulated electric public utility companies, our financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated.  In accordance with accounting guidance for “Regulated Operations,” we record regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.

Use of Estimates

The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes.  These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits.  The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements.  Actual results could ultimately differ from those estimates.

Cash and Cash Equivalents

Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.

Other Temporary Investments

Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and Securities Available for Sale, including marketable securities that we intend to hold for less than one year and investments by our protected cell of EIS.

We classify our investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance.  We do not have any investments classified as trading.

Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI.  Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost.  The cost of securities sold is based on the specific identification or weighted average cost method.


 
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In evaluating potential impairment of securities with unrealized losses, we considered, among other criteria, the current fair value compared to cost, the length of time the security's fair value has been below cost, our intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions.  See “Fair Value Measurements of Other Temporary Investments” in Note 11.

Inventory

Fossil fuel inventories are generally carried at average cost with the exception of AGR and TNC which are carried at the lower of average cost or market.  Materials and supplies inventories are carried at average cost.

Accounts Receivable

Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to our risk management activities and customer receivables primarily related to other revenue-generating activities.

We recognize revenue from electric power sales when we deliver power to our customers.  To the extent that deliveries have occurred but a bill has not been issued, we accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing.

AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, for I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo.  Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit.  AEP Credit has a receivables securitization agreement with bank conduits.  Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries.

Allowance for Uncollectible Accounts

Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries.  For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable.  For customer accounts receivables related to our risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis.  For the wires business of TCC and TNC, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful.  For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified.  Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.

Emission Allowances

In regulated jurisdictions, we record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA.  For our nonregulated business, we record allowances at the lower of cost or market.  We follow the inventory model for these allowances.  We record allowances expected to be consumed within one year in Materials and Supplies and allowances with expected consumption beyond one year in Deferred Charges and Other Noncurrent Assets on the balance sheets.  We record the consumption of allowances in the production of energy in Fuel and Other Consumables Used for Electric Generation on the statements of income at an average cost.  We report the purchases and sales of allowances in the Operating Activities section of the statements of cash flows.  We record the net margin on sales of emission allowances in Vertically Integrated Utilities Revenue on the statements of income because of its integral nature to the production process of energy and our revenue optimization strategy for our utility operations.  The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions.


 
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Property, Plant and Equipment and Equity Investments

Regulated

Electric utility property, plant and equipment for our rate-regulated operations are stated at original cost.  Additions, major replacements and betterments are added to the plant accounts.  Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation.  The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss.  The equipment in each primary electric plant account is identified as a separate group.  The depreciation rates that are established take into account the past history of interim capital replacements and the amount of salvage received.  These rates and the related lives are subject to periodic review.  Removal costs are charged to regulatory liabilities.  The costs of labor, materials and overhead incurred to operate and maintain our plants are included in operating expenses.

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.”  When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense.  Equity investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value.

The fair value of an asset or investment is the amount at which that asset or investment could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets or investments in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.

Nonregulated

Our nonregulated operations generally follow the policies of our rate-regulated operations listed above but with the following exceptions.  Property, plant and equipment of nonregulated operations and equity investments (included in Deferred Charges and Other Noncurrent Assets) are stated at fair value at acquisition (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals.  Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation.  For nonregulated plant assets, a gain or loss would be recorded if the retirement is not considered an interim routine replacement.  Removal costs are charged to expense.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization

For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant.  We record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense.  For nonregulated operations, including  certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”

Valuation of Nonderivative Financial Instruments

The book values of Cash and Cash Equivalents, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments.  The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value.


 
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Fair Value Measurements of Assets and Liabilities

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors.  Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures.  The Regulated Risk Committee consists of our Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.  The Competitive Risk Committee consists of our Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer.

For our commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1.  We verify our price curves using these broker quotes and classify these fair values within Level 2 when substantially all of the fair value can be corroborated.  We typically obtain multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace.  When multiple broker quotes are obtained, we average the quoted bid and ask prices.  In certain circumstances, we may discard a broker quote if it is a clear outlier.  We use a historical correlation analysis between the broker quoted location and the illiquid locations.  If the points are highly correlated we include these locations within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs.  Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.  The main driver of our contracts being classified as Level 3 is the inability to substantiate our energy price curves in the market.  A significant portion of our Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.

We utilize our trustee’s external pricing service in our estimate of the fair value of the underlying investments held in the benefit plan and nuclear trusts.  Our investment managers review and validate the prices utilized by the trustee to determine fair value.  We perform our own valuation testing to verify the fair values of the securities.  We receive audit reports of our trustee’s operating controls and valuation processes.  The trustee uses multiple pricing vendors for the assets held in the trusts.

Assets in the benefits and nuclear trusts, Cash and Cash Equivalents and Other Temporary Investments are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities.  They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.  Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds.  Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  
 
 
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Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.  Benefit plan assets included in Level 3 are primarily real estate and private equity investments that are valued using methods requiring judgment including appraisals.

Deferred Fuel Costs

The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized.  The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method.  In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel revenues billed to customers over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel revenues billed to customers) are generally deferred as current regulatory assets.  Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended.  These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval.  The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions.  On a routine basis, state regulatory commissions review and/or audit our fuel procurement policies and practices, the fuel cost calculations and FAC deferrals.  When a FAC under-recovery is no longer probable of recovery, we adjust our FAC deferrals and record provisions for estimated refunds to recognize these probable outcomes.

Changes in fuel costs, including purchased power in Kentucky for KPCo, in Indiana and Michigan for I&M, in Ohio (beginning in 2012 through the ESP related to non-auction standard service offer load served) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO and in Virginia and West Virginia (upon securitization in November 2013) for APCo are reflected in rates in a timely manner generally through the FAC.  Changes in fuel costs, including purchased power in Ohio (beginning in 2009 through 2011) for OPCo and in West Virginia (prior to securitization in November 2013) for APCo are reflected in rates through FAC phase-in plans.  The FAC generally includes some sharing of off-system sales.  In West Virginia for APCo, all of the profits from off-system sales are given to customers through the FAC.  None of the profits from off-system sales are given to customers through the FAC in Ohio for OPCo.  A portion of profits from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M.  Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.

Revenue Recognition

Regulatory Accounting

Our financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.  Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.

When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheets.  We test for probability of recovery at each balance sheet date or whenever new events occur.  Examples of new events include the issuance of a regulatory commission order or passage of new legislation.  If it is determined that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against income.


 
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Electricity Supply and Delivery Activities

Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services.  For regulated and nonregulated operations, we recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts.  In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue.

Most of the power produced at the generation plants in the east service territory is sold to PJM.  We purchase power from PJM to supply our customers.  Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income.  However, purchases of power in excess of sales to PJM, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income.  Other RTOs in which we participate do not function in the same manner as PJM.  They function as balancing organizations and not as exchanges.

Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income.  Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s economic substance.  Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income.  All other non-trading derivative purchases are recorded net in revenues.

In general, we record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated.  In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

Energy Marketing and Risk Management Activities

We engage in wholesale power, coal and natural gas marketing and risk management activities focused on wholesale markets where we own assets and adjacent markets.  Our activities include the purchase and sale of energy under forward contracts at fixed and variable prices.  These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options.  We engage in certain energy marketing and risk management transactions with RTOs.

We recognize revenues and expenses from wholesale marketing and risk management transactions that are not derivatives upon delivery of the commodity.  We use MTM accounting for wholesale marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or a normal purchase or sale.  We include unrealized and realized gains and losses on wholesale marketing and risk management transactions that are accounted for using MTM in Revenues on the statements of income on a net basis.  In jurisdictions subject to cost-based regulation, we defer unrealized MTM amounts and some realized gains and losses as regulatory assets (for losses) and regulatory liabilities (for gains).  We include unrealized MTM gains and losses resulting from derivative contracts on the balance sheets as Risk Management Assets or Liabilities as appropriate.

Certain qualifying wholesale marketing and risk management derivative transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge).  We initially record the effective portion of the cash flow hedge’s gain or loss as a component of AOCI.  When the forecasted transaction is realized and affects net income, we subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on the statements of income.  Excluding those jurisdictions subject to cost-based regulation, we recognize the ineffective portion of the gain or loss in revenues or expense immediately on the statements of income, depending on the specific nature of the associated hedged risk.  In regulated jurisdictions, we defer the ineffective portion as regulatory assets (for losses) and regulatory liabilities (for gains).  See “Accounting for Cash Flow Hedging Strategies” section of Note 10.


 
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Barging Activities

AEP River Operations’ revenue is recognized based on percentage of voyage completion.  The proportion of freight transportation revenue to be recognized is determined by applying a percentage to the contractual charges for such services.  The percentage is determined by dividing the number of miles from the loading point to the position of the barge as of the end of the accounting period by the total miles to the destination specified in the customer’s freight contract.  The position of the barge at accounting period end is determined by our computerized barge tracking system.

Levelization of Nuclear Refueling Outage Costs

In accordance with regulatory orders, I&M defers incremental operation and maintenance costs associated with periodic refueling outages at its Cook Plant and amortizes the costs over the period beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins.  I&M adjusts the amortization amount as necessary to ensure full amortization of all deferred costs by the end of the refueling cycle.

Maintenance

We expense maintenance costs as incurred.  If it becomes probable that we will recover specifically-incurred costs through future rates, we establish a regulatory asset to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues.  In certain regulatory jurisdictions, we defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.

Income Taxes and Investment Tax Credits

We use the liability method of accounting for income taxes.  Under the liability method, we provide deferred income taxes for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence.

When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), we record deferred income taxes and establish related regulatory assets and liabilities to match the regulated revenues and tax expense.

We account for investment tax credits under the flow-through method except where regulatory commissions reflect investment tax credits in the rate-making process on a deferral basis.  We amortize deferred investment tax credits over the life of the plant investment.

We account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.”  We classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense.

Excise Taxes

We act as an agent for some state and local governments and collect from customers certain excise taxes levied by those state or local governments on our customers.  We do not recognize these taxes as revenue or expense.

Debt

We defer gains and losses from the reacquisition of debt used to finance regulated electric utility plants and amortize the deferral over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced.  If we refinance the reacquired debt associated with the regulated business, the reacquisition costs attributable to the portions of the business subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates.  Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition.
 
 
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We defer debt discount or premium and debt issuance expenses and amortize generally utilizing the straight-line method over the term of the related debt.  The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations.  We include the net amortization expense in Interest Expense on the statements of income.

Goodwill and Intangible Assets

When we acquire businesses, we record the fair value of all assets and liabilities, including intangible assets.  To the extent that consideration exceeds the fair value of identified assets, we record goodwill.  We do not amortize goodwill and intangible assets with indefinite lives.  We test acquired goodwill and other intangible assets with indefinite lives for impairment at least annually at their estimated fair value.  We test goodwill at the reporting unit level and other intangibles at the asset level.  Fair value is the amount at which an asset or liability could be bought or sold in a current transaction between willing parties, that is, other than in a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets in active markets, we estimate fair value using various internal and external valuation methods.  We amortize intangible assets with finite lives over their respective estimated lives to their estimated residual values.  We also review the lives of the amortizable intangibles with finite lives on an annual basis.

Investments Held in Trust for Future Liabilities

We have several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and spent nuclear fuel disposal.  All of our trust funds’ investments are diversified and managed in compliance with all laws and regulations.  Our investment strategy for trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the interest rate sensitivity of the assets relative to the associated liabilities.  To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers.  We regularly review the actual asset allocations and periodically rebalance the investments to targeted allocations when appropriate.  Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities.  The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance.

Benefit Plans

All benefit plan assets are invested in accordance with each plan’s investment policy.  The investment policy outlines the investment objectives, strategies and target asset allocations by plan.

The investment philosophies for our benefit plans support the allocation of assets to minimize risks and optimize net returns.  Strategies used include:

·  
Maintaining a long-term investment horizon.
·  
Diversifying assets to help control volatility of returns at acceptable levels.
·  
Managing fees, transaction costs and tax liabilities to maximize investment earnings.
·  
Using active management of investments where appropriate risk/return opportunities exist.
·  
Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks.
·  
Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification.


 
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The investment policy for the pension fund allocates assets based on the funded status of the pension plan.  The objective of the asset allocation policy is to reduce the investment volatility of the plan over time.  Generally, more of the investment mix will be allocated to fixed income investments as the plan becomes better funded.  Assets will be transferred away from equity investments into fixed income investments based on the market value of plan assets compared to the plan’s projected benefit obligation.  The current target asset allocations are as follows:

Pension Plan Assets
 
Target
Equity
 
 30.0 
%
Fixed Income
 
 55.0 
%
Other Investments
 
 15.0 
%
 
 
 
OPEB Plans Assets
 
Target
Equity
 
 66.0 
%
Fixed Income
 
 33.0 
%
Cash
 
 1.0 
%

The investment policy for each benefit plan contains various investment limitations.  The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies).  However, our investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law.  Each investment manager's portfolio is compared to a diversified benchmark index.

For equity investments, the limits are as follows:

·  
No security in excess of 5% of all equities.
·  
Cash equivalents must be less than 10% of an investment manager's equity portfolio.
·  
No individual stock may be more than 10% of each manager's equity portfolio.
·  
No investment in excess of 5% of an outstanding class of any company.
·  
No securities may be bought or sold on margin or other use of leverage.

For fixed income investments, the concentration limits must not exceed:

·  
3% in any single issuer
·  
5% for private placements
·  
5% for convertible securities
·  
60% for bonds rated AA+ or lower
·  
50% for bonds rated A+ or lower
·  
10% for bonds rated BBB- or lower

For obligations of non-government issuers, the following limitations apply:

·  
AAA rated debt: a single issuer should account for no more than 5% of the portfolio.
·  
AA+, AA, AA- rated debt: a single issuer should account for no more than 3% of the portfolio.
·  
Debt rated A+ or lower:  a single issuer should account for no more than 2% of the portfolio.
·  
No more than 10% of the portfolio may be invested in high yield and emerging market debt combined at any time.

A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation.  Real estate properties are illiquid, difficult to value and not actively traded.  The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties.  To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification.  Real estate holdings include core, value-added and development risk classifications and some investments in Real Estate Investment Trusts (REITs), which are publicly traded real estate securities.


 
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A portion of the pension assets is invested in private equity.  Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance.  Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded.  The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum.   Our private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise.  The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investment instruments.  Commingled private equity funds are used to enhance the holdings’ diversity.

We participate in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses.  We lend securities to borrowers approved by BNY Mellon in exchange for cash collateral.  All loans are collateralized by at least 102% of the loaned asset’s market value and the cash collateral is invested.  The difference between the rebate owed to the borrower and the cash collateral rate of return determines the earnings on the loaned security.  The securities lending program’s objective is providing modest incremental income with a limited increase in risk.

We hold trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company in the OPEB plan trusts.  The strategy for holding life insurance contracts in the taxable Voluntary Employees' Beneficiary Association (VEBA) trust is to minimize taxes paid on the asset growth in the trust.  Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid.  Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities.  With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds.  A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges.  The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities.

Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal.  The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities.  The cash funds are valued each business day and provide daily liquidity.

Nuclear Trust Funds

Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow us to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities.  By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines.  In general, limitations include:

·  
Acceptable investments (rated investment grade or above when purchased).
·  
Maximum percentage invested in a specific type of investment.
·  
Prohibition of investment in obligations of AEP or its affiliates.
·  
Withdrawals permitted only for payment of decommissioning costs and trust expenses.

We maintain trust records for each regulatory jurisdiction. The trust assets may not be used for another jurisdiction’s liabilities.  Regulatory approval is required to withdraw decommissioning funds.  These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities.  The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

We record securities held in these trust funds as Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.  We record these securities at fair value.  We classify securities in the trust funds as available-for-sale due to their long-term purpose.  Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment.  We record unrealized gains and other-than-
 
 
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temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  Consequently, changes in fair value of trust assets do not affect earnings or AOCI.  See the “Nuclear Contingencies” section of Note 6 for additional discussion of nuclear matters.  See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts.

Comprehensive Income (Loss)

Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources.  It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners.  Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).

Stock-Based Compensation Plans

As of December 31, 2013, we had performance units and restricted stock units outstanding under the Amended and Restated American Electric Power System Long-Term Incentive Plan (LTIP).  This plan was last approved by shareholders in April 2010.  Upon vesting, performance units are paid in cash and restricted stock units are settled in AEP Common Shares, except for restricted stock units granted after January 1, 2013 and vesting to executive officers, which are paid in cash.

We maintain a variety of tax qualified and nonqualified deferred compensation plans for employees and non-employee directors that include, among other options, an investment in or an investment return equivalent to that of AEP common stock.  This includes career share accounts maintained under the American Electric Power System Stock Ownership Requirement Plan, which facilitates executives in meeting minimum stock ownership requirements assigned to them by the Human Resources Committee of the Board of Directors.  Career shares are derived from vested performance units granted to employees under the LTIP.  Career shares are equal in value to shares of AEP common stock and become payable to executives in cash after their service ends.  Dividends paid on career shares are reinvested as additional career shares.

We compensate our non-employee directors, in part, with stock units under the American Electric Power Company, Inc. Stock Unit Accumulation Plan for Non-Employee Directors.  These stock units become payable in cash to directors after their service ends.

In January 2006, we adopted accounting guidance for “Compensation - Stock Compensation” which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including stock options, based on estimated fair values.

We recognize compensation expense for all share-based awards with service only vesting conditions granted on or after January 2006 using the straight-line single-option method.  Stock-based compensation expense recognized on the statements of income for the years ended December 31, 2013, 2012 and 2011 is based on awards ultimately expected to vest.  Therefore, stock-based compensation expense has been reduced to reflect estimated forfeitures.  Accounting guidance for “Compensation - Stock Compensation” requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates.

For the years ended December 31, 2013, 2012 and 2011, compensation expense is included in Net Income for the performance units, career shares, restricted shares, restricted stock units and the non-employee director’s stock units.  See Note 15 for additional discussion.


 
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Earnings Per Share (EPS)

Shown below are income statement amounts attributable to AEP common shareholders:

 
 
 
Years Ended December 31,
Amounts Attributable to AEP Common Shareholders
 
2013 
 
2012 
 
2011 
 
 
 
(in millions)
Income Before Extraordinary Item
 
$
 1,480 
 
$
 1,259 
 
$
 1,568 
Extraordinary Item, Net of Tax
 
 
 - 
 
 
 - 
 
 
 373 
Earnings Attributable to AEP Common Shareholders
 
$
 1,480 
 
$
 1,259 
 
$
 1,941 

Basic earnings per common share is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period.  Diluted earnings per common share is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.

The following table presents our basic and diluted EPS calculations included on the statements of income:

 
 
 
 
Years Ended December 31,
 
 
 
 
2013 
 
2012 
 
2011 
 
 
 
 
(in millions, except per share data)
 
 
 
 
 
 
 
$/share
 
 
 
 
$/share
 
 
 
 
$/share
Earnings Attributable to AEP Common
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Shareholders
 
$
 1,480 
 
 
 
 
$
 1,259 
 
 
 
 
$
 1,941 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted Average Number of Basic Shares
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding
 
 
 486.6 
 
$
 3.04 
 
 
 484.7 
 
$
 2.60 
 
 
 482.2 
 
$
 4.02 
Weighted Average Dilutive Effect of:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Stock Options
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 0.1 
 
 
 - 
 
 
Restricted Stock Units
 
 
 0.4 
 
 
 - 
 
 
 0.4 
 
 
 - 
 
 
 0.2 
 
 
 - 
Weighted Average Number of Diluted Shares
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding
 
 
 487.0 
 
$
 3.04 
 
 
 485.1 
 
$
 2.60 
 
 
 482.5 
 
$
 4.02 

There were no antidilutive shares outstanding as of December 31, 2013, 2012 and 2011.

OPCo Revised Depreciation Rates

Effective December 1, 2011, we revised book depreciation rates for certain of OPCo’s generation plants consistent with shortened depreciable lives for the generating units.  This change in depreciable lives resulted in a $52 million increase in depreciation expense in 2012.

In the fourth quarter of 2012, we impaired certain Ohio generating units (see Note 7).  As a result of this impairment of the full book value of these assets, we ceased depreciation on these generating units effective December 1, 2012.

In the second quarter of 2013, we impaired Muskingum River Plant, Unit 5 (MR5).  As a result of this impairment of the full book value of this generating unit, we ceased depreciation on MR5 effective July 1, 2013.

Supplementary Related Party Information

AEP and several nonaffiliated utility companies jointly own OVEC.  As of December 31, 2013, AEP’s ownership and investment in OVEC were 43.47% and $4.4 million, respectively.

OVEC’s owners are members to an intercompany power agreement.  Participants of this agreement are entitled to receive and obligated to pay for all OVEC generating capacity, approximately 2,200 MWs, in proportion to their respective power participation ratios.  The aggregate power participation ratio of certain AEP utility subsidiaries is 43.47%.  The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and provide a return on capital.  In 2011, the intercompany power agreement was extended until June 2040.
 
 
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AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests and OVEC’s Board of Directors authorized capital expenditures totaling $1.4 billion in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at OVEC’s two generation plants.  These environmental projects were funded through debt issuances.  As of December 31, 2013, both generation plants were operating with new environmental controls.

The following details related party transactions for the years ended December 31, 2013, 2012 and 2011:

 
 
 
 
 Years Ended December 31,
 
Related Party Transactions
 
2013 
 
2012 
 
2011 
 
 
 
(in millions)
 
AEP Consolidated Revenues – Other Revenues
 
 
 
 
 
 
 
 
 
 
 
OVEC – Barging and Other Transportation Services
 
$
 21 
 
$
 30 
 
$
 37 
 
AEP Consolidated Expenses – Purchased Electricity
 
 
 
 
 
 
 
 
 
 
  for Resale:
 
 
 
 
 
 
 
 
 
 
 
OVEC
 
 
 289 
 
 
 273 
 
 
 383 
(a)

 
(a)
The parties to the Interconnection Agreement purchased power from OVEC to serve retail sales in 2011.  The total amount reported in 2011 includes $66 million related to this agreement.
 
Supplementary Cash Flow Information
 
 
 
 
 
Years Ended December 31,
Cash Flow Information
 
2013 
 
2012 
 
2011 
 
 
 
 
(in millions)
Cash Paid (Received) for:
 
 
 
 
 
 
 
 
 
 
Interest, Net of Capitalized Amounts
 
$
 882 
 
$
 931 
 
$
 900 
 
Income Taxes
 
 
 (55)
 
 
 (82)
 
 
 (118)
Noncash Investing and Financing Activities:
 
 
 
 
 
 
 
 
 
 
Acquisitions Under Capital Leases
 
 
 182 
 
 
 63 
 
 
 54 
 
Construction Expenditures Included in Current Liabilities as of December 31,
 
 
 492 
 
 
 439 
 
 
 380 
 
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,
 
 
 - 
 
 
 35 
 
 
 1 
 
Assumption of Liabilities Related to Acquisitions
 
 
 - 
 
 
 56 
 
 
 - 
 
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage
 
 
 4 
 
 
 30 
 
 
 - 


 
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2.   EXTRAORDINARY ITEM

TCC Texas Restructuring

In February 2006, the PUCT issued an order that denied recovery of capacity auction true-up amounts.  Based on the February 2006 PUCT order, TCC recorded the disallowance as a $421 million ($273 million, net of tax) extraordinary loss in the December 31, 2005 financial statements.  In July 2011, the Supreme Court of Texas reversed the PUCT’s February 2006 disallowance of capacity auction true-up amounts and remanded for reconsideration the treatment of certain tax balances under normalization rules.  Based upon the Supreme Court of Texas reversal of the PUCT’s capacity auction true-up disallowance, TCC recorded a pretax gain of $421 million ($273 million, net of tax) in Extraordinary Item, Net of Tax on the statements of income in 2011.

Following a remand proceeding, the PUCT allowed TCC to retain contested tax balances in full satisfaction of its true-up proceeding, including carrying charges.  Based upon the PUCT order, TCC recorded the reversal of regulatory credits of $65 million ($42 million, net of tax) and the reversal of $89 million of accumulated deferred investment tax credits ($58 million, net of tax) in Extraordinary Item, Net of Tax on the statements of income in 2011.

3.   COMPREHENSIVE INCOME

Presentation of Comprehensive Income

The following table provides the components of changes in AOCI for the year ended December 31, 2013.  All amounts in the following table are presented net of related income taxes.

Changes in Accumulated Other Comprehensive Income (Loss) by Component
For the Year Ended December 31, 2013
 
 
 
 
Cash Flow Hedges
 
 
 
 
Pension and OPEB
 
 
 
            Interest Rate   Securities   Amortization   Changes      
 
 
 
 
 
 
and Foreign
 
Available
 
of Deferred
 
in Funded
 
 
 
 
 
 
Commodity
 
Currency
 
for Sale
 
Costs
 
Status
 
Total
 
 
 
(in millions)
Balance in AOCI as of December 31, 2012
$
 (8)
 
$
 (30)
 
$
 4 
 
$
 112 
 
$
 (415)
 
$
 (337)
Change in Fair Value Recognized in AOCI
 
 10 
 
 
 2 
 
 
 3 
 
 
 - 
 
 
 177 
 
 
 192 
Amounts Reclassified from AOCI
 
 (2)
 
 
 5 
 
 
 - 
 
 
 22 
 
 
 - 
 
 
 25 
Net Current Period Other
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Comprehensive Income
 
 8 
 
 
 7 
 
 
 3 
 
 
 22 
 
 
 177 
 
 
 217 
Pension and OPEB Adjustment Related to
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mitchell Plant
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 5 
 
 
 5 
Balance in AOCI as of December 31, 2013
$
 - 
 
$
 (23)
 
$
 7 
 
$
 134 
 
$
 (233)
 
$
 (115)


 
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Reclassifications from Accumulated Other Comprehensive Income

The following table provides details of reclassifications from AOCI for the year ended December 31, 2013.  The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs.  See Note 8 for additional details.

Reclassifications from Accumulated Other Comprehensive Income (Loss)
For the Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
Amount of
 
 
 
 
(Gain) Loss
 
 
 
 
Reclassified
 
 
 
 
from AOCI
Gains and Losses on Cash Flow Hedges
 
(in millions)
Commodity:
 
 
 
 
 
Vertically Integrated Utilities Revenues
 
$
 (1)
 
 
Generation & Marketing Revenues
 
 
 (10)
 
 
Purchased Electricity for Resale
 
 
 8 
 
 
Property, Plant and Equipment
 
 
 - 
 
 
Regulatory Assets/(Liabilities), Net (a)
 
 
 - 
Subtotal - Commodity
 
 
 (3)
 
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
 
Interest Expense
 
 
 7 
Subtotal - Interest Rate and Foreign Currency
 
 
 7 
 
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 4 
Income Tax (Expense) Credit
 
 
 1 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 3 
 
 
 
 
Gains and Losses on Securities Available for Sale
 
 
 
Interest Income
 
 
 - 
Interest Expense
 
 
 - 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 - 
Income Tax (Expense) Credit
 
 
 - 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 - 
 
 
 
 
 
Pension and OPEB
 
 
 
Amortization of Prior Service Cost (Credit)
 
 
 (21)
Amortization of Actuarial (Gains)/Losses
 
 
 55 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 34 
Income Tax (Expense) Credit
 
 
 12 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 22 
 
 
 
 
 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
 25 
 
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. 
 
 
 
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The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges for the years ended December 31, 2012 and 2011.  All amounts in the following tables are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
Year Ended December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
 
 
 
Commodity
 
Currency
 
Total
 
 
 
 
(in millions)
Balance in AOCI as of December 31, 2011
 
$
 (3)
 
$
 (20)
 
$
 (23)
Changes in Fair Value Recognized in AOCI
 
 
 (15)
 
 
 (14)
 
 
 (29)
Amount of (Gain) or Loss Reclassified from AOCI
 
 
 
 
 
 
 
 
 
 
to Statement of Income/within Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
Vertically Integrated Utilities Revenues
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Generation & Marketing Revenues
 
 
 (5)
 
 
 - 
 
 
 (5)
 
 
Purchased Electricity for Resale
 
 
 13 
 
 
 - 
 
 
 13 
 
 
Other Operation Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Maintenance Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Interest Expense
 
 
 - 
 
 
 4 
 
 
 4 
 
 
Property, Plant and Equipment
 
 
 - 
 
 
 - 
 
 
 - 
 
 
Regulatory Assets (a)
 
 
 2 
 
 
 - 
 
 
 2 
Balance in AOCI as of December 31, 2012
 
$
 (8)
 
$
 (30)
 
$
 (38)
 
 
 
 
 
 
 
 
 
 
 
 
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
Year Ended December 31, 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
 
 
 
Commodity
 
Currency
 
Total
 
 
 
 
(in millions)
Balance in AOCI as of December 31, 2010
 
$
 7 
 
$
 4 
 
$
 11 
Changes in Fair Value Recognized in AOCI
 
 
 (5)
 
 
 (28)
 
 
 (33)
Amount of (Gain) or Loss Reclassified from AOCI
 
 
 
 
 
 
 
 
 
 
to Statement of Income/within Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
Vertically Integrated Utilities Revenues
 
 
 1 
 
 
 - 
 
 
 1 
 
 
Generation & Marketing Revenues
 
 
 (3)
 
 
 - 
 
 
 (3)
 
 
Purchased Electricity for Resale
 
 
 (2)
 
 
 - 
 
 
 (2)
 
 
Other Operation Expense
 
 
 (1)
 
 
 - 
 
 
 (1)
 
 
Maintenance Expense
 
 
 (1)
 
 
 - 
 
 
 (1)
 
 
Interest Expense
 
 
 - 
 
 
 4 
 
 
 4 
 
 
Property, Plant and Equipment
 
 
 (1)
 
 
 - 
 
 
 (1)
 
 
Regulatory Assets (a)
 
 
 2 
 
 
 - 
 
 
 2 
Balance in AOCI as of December 31, 2011
 
$
 (3)
 
$
 (20)
 
$
 (23)
 
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
 
 
 
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The following table provides details of changes in unrealized gains and losses related to Securities Available for Sale and the reasons for changes for the year ended December 31, 2012.  All amounts in the following table are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Securities Available for Sale
Year Ended December 31, 2012
 
 
 
 
 
 
 
 
 
 
(in millions)
Balance in AOCI as of December 31, 2011
 
$
 2 
Changes in Fair Value Recognized in AOCI
 
 
 2 
Amount of (Gain) or Loss Reclassified from AOCI to Statement of Income:
 
 
 
 
 
Interest Income
 
 
 - 
Balance in AOCI as of December 31, 2012
 
$
 4 

4.   RATE MATTERS

Our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  Rate matters can have a material impact on net income, cash flows and possibly financial condition.  Our recent significant rate orders and pending rate filings are addressed in this note.

OPCo Rate Matters

Ohio Electric Security Plan Filings

2009 – 2011 ESP

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011.  OPCo collected the 2009 annualized revenue increase over the last nine months of 2009.  The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018.  The PUCO’s March 2009 order was appealed to the Supreme Court of Ohio, which issued an opinion and remanded certain issues back to the PUCO.

In October 2011, the PUCO issued an order in the remand proceeding.  As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011.  In February 2012, the Ohio Consumers’ Counsel (OCC) and the IEU filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO’s refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which, if ordered, could reduce OPCo’s net deferred fuel costs up to the total balance.  As of December 31, 2013, OPCo’s net deferred fuel balance was $445 million, excluding unrecognized equity carrying costs.  In February 2014, the Supreme Court of Ohio affirmed the PUCO’s decision and rejected all appeals filed by the OCC and the IEU.  In February 2014, the IEU filed for reconsideration of the Supreme Court of Ohio decision.

In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover deferred fuel costs in rates beginning September 2012.  The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin.  In November 2012, OPCo filed an appeal at the Supreme Court of Ohio related to the PUCO decision in the PIRR proceeding claiming a long-term debt rate modified the previously adjudicated 2009 – 2011 ESP order, which granted a weighted average cost of capital rate.  In November 2012, the IEU and the OCC filed appeals regarding the PUCO decision in the PIRR proceeding.  These appeals principally argued that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues which could reduce OPCo’s net deferred fuel balance up to the total balance.  These intervenors’ appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of December 31, 2013, could reduce carrying costs by $31 million including $16 million of unrecognized equity carrying costs.  A decision from the Supreme Court of Ohio is pending.


 
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In January 2011, the PUCO issued an order on the 2009 SEET filing.  The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm.  In January 2013, the PUCO found there was not a need for the large solar farm.  The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project.  In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive.  A decision from the PUCO is pending.

In July 2011, OPCo filed its 2010 SEET filing with the PUCO.  In October 2013, the PUCO issued an order on the 2010 SEET filing that determined there were excessive earnings of $7 million, which were primarily offset against deferred fuel, as ordered.  OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis.  In November 2013, OPCo filed its 2011 and 2012 SEET filings with the PUCO.  In February 2014, the PUCO staff filed testimony asserting that no significantly excessive earnings had occurred in 2011 for CSPCo or OPCo and that no significantly excessive earnings had occurred in 2012 for OPCo.   In February 2014, OPCo entered into a stipulation agreement with the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2011 for CSPCo or OPCo.  A hearing at the PUCO related to the 2011 SEET filing is scheduled for February 2014.  Management does not believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo or in either 2012 or 2013 for OPCo.

Management is unable to predict the outcome of the unresolved litigation discussed above.  Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition.

June 2012 – May 2015 ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015.  This ruling was generally upheld in rehearing orders in January and March 2013.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The RPM price is approximately $33/MW day through May 2014 and $148/MW day from June 2014 through May 2015.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.

As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012.  The RSR is being collected from customers at $3.50/MWh through May 2014 and will be collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs.  As of December 31, 2013, OPCo’s incurred deferred capacity costs balance of $288 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet.

In January and March 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order including the implementation of the RSR.  The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel.  In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP).  In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR.

In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications.  The modifications include the delay of the energy auctions that were originally ordered in the ESP order.  OPCo must conduct an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015.  The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning November 2014 through May 2015 and for the remaining 40% of the SSO load for delivery from January 2015 through May 2015.  OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015.  The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned.  Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC
 
 
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proceedings.  Management believes that these intervenor concerns are without merit.  In December 2013, the PUCO granted applications for rehearing for further consideration filed by OPCo and intervenors.  In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012-2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC.
 
If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its fixed fuel and deferred capacity costs, it could reduce future net income and cash flows and impact financial condition.

Proposed June 2015 – May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018.  This filing is consistent with the PUCO’s objective for a full transition from FAC and base generation rates to market.  The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo.  Additionally, the application identifies OPCo’s intention to submit a separate application to continue the RSR established in the June 2012 – May 2015 ESP in which the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected.  Management intends to file this application in the first quarter of 2014.

Corporate Separation

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR.  In April 2013, the FERC issued orders approving the transfer of OPCo’s generation assets to AGR.  In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful.  A decision from the Supreme Court of Ohio is pending.  In December 2013, the PUCO approved OPCo’s application to amend the corporate separation plan by permitting OPCo to retain certain rights to purchase power from OVEC.  The approval is subject to the condition that energy from the OVEC entitlements are sold into the day-ahead or real-time PJM energy markets, or on a forward basis through a bilateral arrangement.  In December 2013, corporate separation of OPCo’s generation assets was completed.  See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.

Storm Damage Recovery Rider (SDRR)

In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates.  The SDRR seeks recovery of 2012 incremental storm distribution expenses over twelve months starting with the effective date of the SDRR as approved by the PUCO.  In December 2013, a stipulation agreement was reached between OPCo, the PUCO staff and all intervenors except the OCC.  The stipulation included a $6 million reduction in the amount of 2012 storm expenses to be recovered and for recovery of those expenses to take place over a 12-month period.  The agreement also states that carrying charges using a long-term debt rate will be assessed from April 2013 until recovery begins, but no additional carrying charges will accrue during the actual recovery period.   In December 2013, the OCC filed testimony opposing the stipulation.  The testimony recommended the disallowance of approximately $18 million of the 2012 storm expenses and that the remaining 2012 storm expenses be offset by an additional $20 million that OPCo was ordered to spend on a solar project in OPCo’s 2009 SEET filing.  See the “2009-2011 ESP” section above.  Hearings were held at the PUCO in January 2014 related to the settlement agreement and to address issues presented in the OCC’s testimony.  As of December 31, 2013, OPCo has deferred $56 million in Regulatory Assets on the balance sheet related to 2012 storm damage.  If OPCo is not ultimately permitted to recover these storm costs, it could reduce future net income and cash flows and impact financial condition.
 
 
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2009 Fuel Adjustment Clause Audit

In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance.  In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges.  As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012.  The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers.  Management is unable to predict the outcome of any future consultant recommendation regarding valuation of the coal reserve.  If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.

In August 2012, intervenors filed an appeal with the Supreme Court of Ohio claiming the settlement credit ordered by the PUCO should have reflected the remaining gain not already flowed through the FAC with carrying charges, which, if ordered, would be $35 million plus carrying charges.  If the Supreme Court of Ohio   ultimately determines that additional amounts should benefit ratepayers, it could reduce future net income and cash flows and impact financial condition.

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes with the use of a weighted average cost of capital (WACC).  The PUCO subsequently ruled in the PIRR proceeding that the fuel clause for these years was approved with a WACC carrying cost and that the carrying costs on the balance should not be net of accumulated income taxes.  Hearings at the PUCO were held in November 2013.  If the PUCO orders result in a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition.  See the 2009-2011 ESP section of the “Ohio Electric Security Plan Filing” related to the PUCO order in the PIRR proceeding.

Ormet

Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018.  In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware.  In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down operations effective immediately.  Based upon previous PUCO rulings providing rate assistance to Ormet, the PUCO is expected to permit OPCo to recover unpaid Ormet amounts through the Economic Development Rider, except where recovery from ratepayers is limited to $20 million related to previously deferred payments from Ormet’s October and November 2012 power bills.  OPCo expects that any additional unpaid generation usage by Ormet will be recoverable as a regulatory asset through the Economic Development Rider (EDR).  In February 2014, a stipulation agreement between OPCo and Ormet was filed with the PUCO.  The stipulation recommends approval of OPCo’s right to fully recover approximately $49 million of foregone revenues through the EDR which, as of December 31, 2013, is recorded in regulatory assets on the balance sheet.  Also in February 2014, intervenor comments were filed objecting to full recovery of these forgone revenues.

In addition, in the 2009 – 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future.  Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs.  The PUCO did not take any action on this request.  The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement.

To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition.
 
 
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Ohio IGCC Plant

In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant.  As of December 31, 2013, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order.  Intervenors have filed motions with the PUCO requesting that OPCo refund all collected pre-construction costs to Ohio ratepayers with interest.

Management cannot predict the outcome of this proceeding concerning the Ohio IGCC plant or what effect, if any, this proceeding could have on future net income and cash flows.  However, if OPCo is required to refund pre-construction costs collected, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters

Turk Plant

SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.  As of December 31, 2013, SWEPCo’s share of incurred construction expenditures for the Turk Plant was approximately $1.758 billion.  As of December 31, 2013, a pretax provision of $59 million has been recorded for costs incurred in excess of a Texas cost cap, resulting in total net capitalized expenditures of $1.699 billion.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%).  Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN.  In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN.  This Turk Plant output that is currently not subject to cost-based rate recovery and is being sold into the wholesale market.

The PUCT approved a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected cash construction cost, excluding related transmission costs, (b) a cap on recovery of annual CO 2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers.  The PUCT decision was upheld on appeal.   See the “2012 Texas Base Rate Case” disclosure below for a discussion of a PUCT order on the Texas capital cost cap.

If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant or transmission lines, it could reduce future net income and cash flows and impact financial condition.
 
2012 Texas Base Rate Case
 
In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million, primarily due to the Turk Plant, based upon an 11.25% return on common equity to be effective January 2013.  The requested base rate increase included a return on and of the Texas jurisdictional share (approximately 33%) of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operation and maintenance costs.  The filing also (a) increased depreciation expense due to the decrease in the average remaining life of the Welsh Plant to account for the change in the retirement date of the Welsh Plant, Unit 2 from 2040 to 2016 and (b) included a return on and of the Stall Unit as of December 2011 and associated operation and maintenance costs.

In October 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determining that the Turk Plant Texas capital cost cap established in the Certificate of Convenience and Necessity (CCN) case discussed above (the Texas capital cost cap) also limited SWEPCo’s recovery of AFUDC in addition to its recovery of cash construction costs.  As a result of the determination that AFUDC was to be included in the cap, in the third quarter of 2013, SWEPCo recorded an additional pretax regulatory disallowance of $111 million.  The order approved an annual rate increase of approximately $39 million based upon a return on common equity of 9.65%, including an
 
 
83

 
unfavorable consolidated income tax adjustment of $5 million.  As a result of this approval, SWEPCo retroactively applied the rate increase to the end of January 2013.  The order also provided that there would be no disallowance to the existing book investment in the Stall Unit and that the Turk Plant related transmission line investment that was not in service at the end of the test year would be excluded from rate base.  SWEPCo has since sought approval to recover this transmission investment through a Transmission Cost Recovery Rider in a filing made in December 2013.  Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2.  As of December 31, 2013, the net book value of Welsh Plant, Unit 2 was $87 million, before cost of removal, including materials and supplies inventory and CWIP.

In October 2013, SWEPCo filed a motion for rehearing with the PUCT.  In December 2013, the PUCT issued an order granting rehearing and reversed its decision on consolidated tax savings increasing SWEPCo’s annual revenues by $5 million.  In January 2014, the PUCT determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap.  As a result of these rulings, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances.  These rulings also increased SWEPCo’s previously approved annual base rates by a total of $13 million, which was also retroactively applied to the end of January 2013.  The resulting annual base rate increase is approximately $52 million. 

If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Welsh Plant, Unit 2 and its retirement-related costs, it could reduce future net income and cash flows and impact financial condition.
 
2013 Texas Transmission Costs Recovery Factor Filing
 
In December 2013, SWEPCo filed an application to implement its initial transmission cost recovery factor (TCRF) requesting additional annual revenue of $10 million.  The TCRF is designed to recover increases from the amounts included in SWEPCo’s Texas retail base rates for transmission infrastructure improvement costs and wholesale transmission charges under a tariff approved by the FERC.  SWEPCo’s application included Turk Plant transmission-related costs.  In January and February 2014, intervenors filed motions with the PUCT opposing SWEPCo’s filing.  In February 2014, an Administrative Law Judge issued an order requesting additional information from SWEPCo related to this filing.  If the PUCT were to disallow any portion of the TCRF, it could reduce future net income and cash flows.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant.  In February 2013, a settlement was filed and approved by the LPSC.  The settlement increased Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually.  The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund based on the staff review of the cost of service and the prudency review of the Turk Plant.  The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013.  In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant.  If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudency review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.

Flint Creek Plant Environmental Controls

In February 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA.  The estimated cost of the project is $408 million, excluding AFUDC and company overheads.  As a joint owner of the Flint Creek Plant, SWEPCo’s portion of those costs is estimated at $204 million.  In July 2013, the APSC approved the request to install environmental controls at the Flint Creek Plant.
 
 
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APCo and WPCo Rate Matters

Plant Transfers

In October 2012, the AEP East Companies submitted several filings with the FERC regarding the transfer of certain generation plants within the AEP System.  See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.  In December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant, comprising 1,647 MW of generating capacity.  In July 2013, the Virginia SCC approved the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo, but directed that an amount equal to $83 million pretax be removed from the proposed transfer price.  The Virginia jurisdictional share of the disallowance was approximately $39 million.  The Virginia SCC also denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo.

In December 2013, the WVPSC approved the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo but deferred a final decision related to the recovery of West Virginia’s jurisdictional share of the $83 million pretax Virginia SCC disallowance until APCo’s next West Virginia base rate case which APCo has agreed to file no later than June 2014.  The West Virginia and FERC jurisdictional share of the potential disallowance is approximately $44 million pretax.  Additionally, the WVPSC order also approved a rate surcharge for Amos Plant, Unit 3 effective January 2014 and deferred ruling on the transfer of the one-half interest in the Mitchell Plant to APCo.  The surcharge was offset by an equal reduction in ENEC revenue with no overall change in total revenue.

In December 2013, the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo was completed.  As a result of the Virginia order, in the fourth quarter of 2013, APCo recorded a pretax regulatory disallowance of $39 million in Asset Impairments and Other Related Charges on the statement of income.  Management continues to review its options related to the remaining one-half interest in the Mitchell Plant currently owned by AGR.  If APCo and WPCo are not ultimately permitted to recover their Amos Plant, Unit 3 incurred costs in West Virginia and FERC, it could reduce future net income and cash flows and impact financial condition.

APCo IGCC Plant

As of December 31, 2013, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $10 million applicable to its Virginia jurisdiction.  If the costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing

In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $39 million related to 2012 and 2011 environmental compliance costs, including carrying costs.  In March 2013, the environmental RAC surcharge expired related to the collection of 2009 and 2010 environmental compliance costs.  In November 2013, the Virginia SCC approved a settlement agreement which recommended approval of an environmental RAC to recover $38 million of the 2012 and 2011 environmental compliance costs, effective January 2014 for a one-year period.  The order also states that APCo must file its next environmental RAC petition on or before May 1, 2015.  As of December 31, 2013, APCo has deferred $28 million for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $10 million of unrecognized equity carrying costs.

2013 Virginia Generation Rate Adjustment Clause (Generation RAC)Filing

In March 2013, APCo filed with the Virginia SCC to increase its generation RAC revenues by $12 million for a total of $38 million to collect costs related to the Dresden Plant.  In December 2013, the Virginia SCC approved a settlement agreement that included an increase in the generation RAC to $39 million.  Per the approved settlement agreement, the generation RAC increase was effective in February 2014 for a period of one year at which time the component to collect an under-recovery of approximately $10 million will cease and the remaining annual $29 million revenue to recover on-going Dresden Plant costs will continue.  As of December 31, 2013, APCo has deferred $6 million for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $5 million of unrecognized equity carrying costs.
 
 
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2013 Virginia Transmission Rate Adjustment Clause (Transmission RAC)

In December 2013, APCo filed with the Virginia SCC to increase its transmission RAC revenues by $50 million annually.  The increase in the transmission RAC is expected to be effective May 2014.   In February 2014, a hearing was held at the Virginia SCC in which a stipulation agreement between APCo and the Virginia SCC staff was submitted to the Virginia SCC that recommended approval to increase the transmission RAC revenues by $ 49 million annually, subject to true-up. The stipulation included the Virginia SCC staff’s commitment to fully audit APCo’s transmission RAC under-recoveries and report its findings and recommendations in testimony in APCo’s next transmission RAC filing in 2015.  As of December 31, 2013, APCo has deferred $47 million for the Virginia portion of unrecovered transmission RAC costs.  If the Virginia SCC were to disallow any portion of the transmission RAC, it could reduce future net income and cash flows.
 
2013 West Virginia Expanded Net Energy Charge (ENEC) Filing

In March 2012, West Virginia passed securitization legislation which allowed the WVPSC to establish a regulatory framework for electric utilities to securitize certain deferred ENEC balances and other ENEC-related assets.  In August 2013, the WVPSC approved a settlement that included (a) a $56 million reduction in ENEC revenues, offset by a $6 million annual increase in construction surcharges, effective September 2013 and subject to true-up, (b) an agreement to file a base case no later than June 2014 and (c) the deferral of $21 million from the ENEC recovery balance with the ability to include that amount in the ENEC recovery balance upon reaching certain coal inventory levels at the Amos Plant.  In September 2013, the WVPSC approved a settlement agreement filed by APCo, WPCo and intervenors which authorized APCo to securitize $376 million, plus upfront financing costs, primarily related to the December 2011 under-recovered ENEC deferral balance.  In November 2013, APCo issued $380 million of Securitization Bonds to securitize the under-recovered ENEC deferral balance, including $4 million of upfront financing costs, with a final maturity date of August 2031.  APCo implemented a new securitization rider which was offset by an equal reduction in ENEC revenues, with no overall change in total revenues.

As of December 31, 2013, APCo’s ENEC net over-recovery balance was $86 million, of which $107 million was recorded in Regulatory Liabilities and $21 million was recorded in Regulatory Assets on the balance sheet.

Virginia Storm Costs

In March 2013, due to the 2013 enactment of a Virginia law, APCo wrote off $30 million of previously deferred 2012 Virginia storm costs.  The change in law affected the test years to be included in APCo's next biennial Virginia base rate filing in March 2014 and the determination of how these costs are treated in the Virginia jurisdictional biennial earnings test for 2012 and 2013.  As of December 31, 2013, APCo has not deferred any Virginia storm costs incurred in 2012 or 2013 based on actual 2012 and estimated 2013 Virginia jurisdictional earnings.  The 2012 and 2013 earnings test will be filed in the first quarter of 2014 as part of APCo’s biennial Virginia base rate filing.

PSO Rate Matters

2014 Oklahoma Base Rate Case

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity.  This revenue increase includes a proposed increase in depreciation rates of $29 million.  In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three.  The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional types of transmission costs that are expected to increase over the next several years.

Oklahoma Environmental Compliance Plan

In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES), Unit 4 in 2016 and additional environmental controls on NES, Unit 3 to continue operations through 2026.  As of December 31, 2013, the net book values of NES, Units 3 and 4 were $208 million and $106 million, respectively, before cost of removal, including materials and supplies inventory and CWIP.  In August 2013, the OCC dismissed PSO’s environmental compliance plan case without prejudice but will permit PSO
 
 
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to seek recovery in a future proceeding.  PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan.  If PSO is ultimately not permitted to fully recover its net book value of NES, Units 3 and 4 and other environmental compliance costs, it could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters
 
2011 Indiana Base Rate Case
 
In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%.  In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates from $85 million to $92 million.  In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed a request for reconsideration with the IURC, which was denied.  Also in March 2013, the OUCC filed an appeal of the order with the Indiana Court of Appeals.  In September 2013, the OUCC filed a brief on appeal that included objections to the inclusion of a prepaid pension asset in rate base, the use of an end-of-test-year amount for materials and supplies instead of a thirteen-month average and the application of an “outdated” capital structure.  If any part of the IURC order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its licensed life (2034 for Unit 1 and 2037 for Unit 2).  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of December 31, 2013, I&M has incurred costs of $380 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items that might accommodate a future potential power uprate which the IURC stated I&M could seek recovery of in a subsequent base rate case.  I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings.  The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates.  In October 2013, I&M filed an application with the IURC for LCM rider rates effective January 2014.  In November 2013, the OUCC filed testimony identifying concerns related to the LCM rider that included the use of forecasted capital expenditures and the method used to calculate carrying charges.  In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC.

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to the approved projects effective January 2013 until these costs are included in rates.  In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project.

If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.

Rockport Plant Clean Coal Technology Project (CCT Project)

In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both units of the Rockport Plant with a dry sorbent injection system.  The estimated cost in the application was $285 million, excluding AFUDC, to be shared equally between I&M and AEGCo.  The application requested deferral treatment of any unrecovered carrying costs incurred during construction and incremental post in-service depreciation expense and operation and maintenance expenses until such costs are recognized and recovered in a rider.  I&M also requested cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism.
 
 
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In November 2013, the IURC approved a settlement agreement that included the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M’s ownership share.  The settlement agreement specifies that 80% of the recoverable I&M direct ownership share of CCT Project costs will be recovered through a Federal Mandate Rider with the remaining 20% deferred until rates are established in a subsequent rate case.  I&M’s Indiana jurisdictional allocated share of the CCT Project costs received in the form of purchased power from AEGCo will be recovered in subsequent I&M rate cases.  As of December 31, 2013, we have incurred costs of $109 million related to the CCT Project, including AFUDC.

Tanners Creek Plant, Units 1 - 4

In 2011, I&M announced that it would retire Tanners Creek Plant, Units 1-3 by June 2015 to comply with proposed environmental regulations.  In September 2013, I&M announced that Tanners Creek Plant, Unit 4 would also be retired in mid-2015 rather than being converted from coal to natural gas.   I&M is currently recovering depreciation and a return on the net book value of the Tanners Creek Plant in base rates and plans to seek recovery of all of the plant’s retirement related costs in its next Indiana and Michigan base rate cases.

In December 2013, I&M filed an application with the MPSC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and Tanners Creek Plant due to the retirement of the Tanners Creek Plant in 2015.  Upon the retirement of the Tanners Creek Plant, I&M proposes that the net book value of the Tanners Creek Plant will be recovered over the remaining life of the Rockport Plant.  I&M requested to have the impact of these new depreciation rates incorporated into the rates set in its next rate case.  The new depreciation rates result in a decrease in I&M’s Michigan jurisdictional electric depreciation expense which I&M proposes to implement in the month following a MPSC order in the revised depreciation case.

As of December 31, 2013, the net book value of the Tanners Creek Plant was $341 million, before cost of removal, including materials and supplies inventory and CWIP.  If I&M is ultimately not permitted to fully recover its net book value of the Tanners Creek Plant and its retirement-related costs, it could reduce future net income and cash flows and impact financial condition.

KPCo Rate Matters

Plant Transfer

In October 2012, the AEP East Companies submitted several filings with the FERC.  See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.  In December 2012, KPCo filed a request with the KPSC for approval to transfer at net book value to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity.  KPCo also requested that costs related to the Big Sandy Plant, Unit 2 FGD project be established as a regulatory asset.  As of December 31, 2013, the net book value of Big Sandy Plant, Unit 2 was $249 million, before cost of removal, including materials and supplies inventory and CWIP.  In March 2013, KPCo issued a Request for Proposal (RFP) to purchase up to 250 MW of long-term capacity and energy to replace a portion of the capacity from Big Sandy Plant, Unit 1.  In June 2013, KPCo filed the results of its RFP with the KPSC.

In October 2013, the KPSC issued an order approving a modified settlement agreement between KPCo, Kentucky Industrial Utility Customers, Inc. and the Sierra Club.  The modified settlement approved the transfer of a one-half interest in the Mitchell Plant to KPCo at net book value on December 31, 2013 with the limitation that the net book value of the Mitchell Plant transfer not exceed the amount to be determined by a WVPSC order.  The WVPSC order was subsequently issued in December 2013, but the WVPSC deferred a decision on the transfer of the one-half interest in the Mitchell Plant to APCo.  The settlement also included the implementation of an Asset Transfer Rider to collect $44 million annually effective January 2014, subject to true-up, and allowed KPCo to retain any off-system sales margins above the $15.3 million annual level in base rates.  Additionally, the settlement allows for KPCo to file a Certificate of Public Convenience and Necessity to convert Big Sandy Plant, Unit 1 to natural gas, provided the cost is approximately $60 million, and addressed potential greenhouse gas initiatives on the Mitchell Plant.  The settlement also approved recovery, including a return, of coal-related retirement costs related to Big Sandy Plant over 25 years when base rates are set in the next base rate case (no earlier than June 2015), but rejected KPCo’s request to defer FGD project costs for Big Sandy Plant, Unit 2.  As a result of this order, in 2013, KPCo
 
 
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recorded a pretax regulatory disallowance of $33 million in Asset Impairments and Other Related Charges on the statement of income.  In November 2013, the KPSC denied the Attorney General’s petition for rehearing.  In December 2013, the Attorney General filed an appeal with the Franklin County Circuit Court.  In December 2013, KPCo filed motions with the Franklin County Circuit Court to dismiss the appeal.  A hearing on the motions to dismiss was held in January 2014.  In December 2013, the transfer of a one-half interest in the Mitchell Plant to KPCo was completed.

2013 Kentucky Base Rate Case

In June 2013, KPCo filed a request with the KPSC for an annual increase in base rates of $114 million based upon a return on common equity of 10.65% to be effective January 2014.  The proposed revenue increase included cost recovery of the proposed transfer of the one-half interest in the Mitchell Plant (780 MW).  In October 2013, the KPSC issued an order in the plant transfer case which modified and approved a settlement agreement that included the approval of the proposed transfer of the one-half interest in the Mitchell Plant to KPCo.  The modified and approved settlement agreement also included KPCo’s agreement to withdraw this base rate case request and file a base case proceeding no later than December 2014 with its current base rates to remain in effect until at least May 2015.  In November 2013, KPCo withdrew this base rate request and the withdrawal was approved by the KPSC.

FERC Rate Matters

Corporate Separation and Termination of Interconnection Agreement

In October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations.  The filings requested approval to transfer at net book value (NBV) approximately 9,200 MW of OPCo-owned generation assets and associated liabilities to AGR.  The AEP East Companies also requested FERC approval to transfer at NBV two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer the Mitchell Plant at NBV to APCo and KPCo in equal one-half interests (780 MW each) to be effective December 31, 2013.  In April 2013, the FERC issued orders approving the transfer of OPCo’s generation assets to AGR, the transfers of the Amos Plant and Mitchell Plant to APCo and KPCo, respectively, and the merger of APCo and WPCo.  In January 2014, the FERC dismissed an IEU petition for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AGR.  Similar asset transfer filings were made at the KPSC, the Virginia SCC and the WVPSC.  In December 2013, corporate separation of OPCo’s generation assets was completed.  See the “Plant Transfers” section of APCo and WPCo Rate Matters and the “Plant Transfer” section of KPCo Rate Matters.

In accordance with our December 2010 announcement and our October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014.  The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated.

In December 2013, the FERC issued orders approving the creation of the PCA, effective January 1, 2014, conditioned upon certain compliance filings which were filed with the FERC in January 2014.  The PCA was established among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.  Under the PCA, APCo, I&M and KPCo would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies.  Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities.  

Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent.  The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies will fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year.  Under the Bridge Agreement, AGR is committed to meet capacity obligations of member companies through May 31, 2015.
 
 
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Additionally, FERC approval was sought for a Power Supply Agreement (PSA) between AGR and OPCo.  This agreement provides for AGR to supply capacity for OPCo’s switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that is not acquired through an auction from January 1, 2014 through December 31, 2014.  In December 2013, the FERC issued an order approving the PSA.  The order conditioned the acceptance of the PSA on the revision of the agreement to reflect the PUCO’s current and future underlying rates and rate structure.  In January 2014, initial revisions to reflect current underlying rates and rate structure were filed at the FERC.

In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation.  In December 2013, the FERC issued an order approving these additional filings.  See the “Plant Transfers” section of APCo and WPCo Rate Matters and the “Plant Transfer” section of KPCo Rate Matters for a discussion of those orders.

If incurred costs are not ultimately recovered, it could reduce future net income and cash flows and impact financial condition.

5.   EFFECTS OF REGULATION

Regulated Generating Units to be Retired Before or During 2016

The following regulated generating units are probable of abandonment.  Accordingly, CWIP and Plant in Service has been reclassified as Other Property, Plant and Equipment on the balance sheet as of December 31, 2013.  The following table summarizes the plant investment and cost of removal, currently being recovered, for each generating unit as of December 31, 2013.

Plant Name and Unit
 
Company
 
Gross
Investment
 
Accumulated
Depreciation
 
Net
Investment
 
Cost of
Removal
Regulatory
Liability
 
Expected
Retirement
Date
 
Remaining
Recovery
Period
 
 
 
 
(in millions)
 
 
 
 
Tanners Creek Plant,
 
I&M
 
$
 681 
 
$
 354 
 
$
 327 
 
$
 87 
 
2015 
 
17 years
   Units 1-4
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Big Sandy Plant, Unit 2
 
KPCo
 
 
 424 
 
 
 180 
 
 
 244 
 
 
 47 
 
2015 
 
27 years
Northeastern Station,
 
PSO
 
 
 182 
 
 
 89 
 
 
 93 
 
 
 11 
 
2016 
 
27 years
   Unit 4
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Welsh Plant, Unit 2
 
SWEPCo
 
 
 175 
 
 
 93 
 
 
 82 
 
 
 19 
 
2016 
 
27 years
Total
 
 
 
$
 1,462 
 
$
 716 
 
$
 746 
 
$
 164 
 
 
 
 

In accordance with accounting guidance for “Regulated Operations”, APCo regulated generating units expected to be retired before or during 2016 are not considered probable of abandonment.


 
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Regulatory Assets

Regulatory assets are comprised of the following items:

 
 
 
 
 
December 31,
 
Remaining
 
 
 
 
 
2013 
 
2012 
 
Recovery Period
Current Regulatory Assets
 
(in millions)
 
 
Under-recovered Fuel Costs - earns a return
 
$
 61 
 
$
 86 
 
1 year
Under-recovered Fuel Costs - does not earn a return
 
 
 19 
 
 
 2 
 
1 year
Total Current Regulatory Assets
 
$
 80 
 
$
 88 
 
 
 
 
 
 
 
 
 
 
 
Noncurrent Regulatory Assets
 
 
 
 
 
 
 
 
Regulatory assets not yet being recovered pending future
 
 
 
 
 
 
 
 
 
proceedings to determine the recovery method and timing:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
 
 
 
 
 
 
Storm Related Costs
 
$
 22 
 
$
 23 
 
 
 
 
Ohio Economic Development Rider
 
 
 14 
 
 
 13 
 
 
 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 4 
 
 
 1 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
 
 
 
Storm Related Costs
 
 
 161 
 
 
 172 
 
 
 
 
Ormet Special Rate Recovery Mechanism
 
 
 36 
 
 
 5 
 
 
 
 
Indiana Under-Recovered Capacity Costs
 
 
 22 
 
 
 - 
 
 
 
 
Expanded Net Energy Charge - Coal Inventory
 
 
 21 
 
 
 - 
 
 
 
 
Mountaineer Carbon Capture and Storage Product Validation Facility
 
 
 13 
 
 
 14 
 
 
 
 
Virginia Environmental Rate Adjustment Clause
 
 
 2 
 
 
 29 
 
 
 
 
Litigation Settlement
 
 
 - 
 
 
 11 
 
 
 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 35 
 
 
 36 
 
 
Total Regulatory Assets Not Yet Being Recovered
 
 
 330 
 
 
 304 
 
 
 
 
 
 
 
 
 
 
 
Regulatory assets being recovered:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
 
 
 
 
 
 
Ohio Fuel Adjustment Clause
 
 
 445 
 
 
 519 
 
5 years
 
 
Ohio Capacity Deferral
 
 
 288 
 
 
 66 
 
5 years
 
 
Ohio Transmission Cost Recovery Rider
 
 
 87 
 
 
 49 
 
2 years
 
 
Unamortized Loss on Reacquired Debt
 
 
 81 
 
 
 82 
 
30 years
 
 
Texas Meter Replacement Costs
 
 
 77 
 
 
 47 
 
15 years
 
 
Ohio Distribution Decoupling
 
 
 31 
 
 
 - 
 
2 years
 
 
Storm Related Costs
 
 
 17 
 
 
 36 
 
5 years
 
 
RTO Formation/Integration Costs
 
 
 12 
 
 
 15 
 
6 years
 
 
Red Rock Generating Facility
 
 
 10 
 
 
 10 
 
43 years
 
 
West Virginia Expanded Net Energy Charge
 
 
 - 
 
 
 273 
 
 
 
 
Ohio Deferred Asset Recovery Rider
 
 
 - 
 
 
 152 
 
 
 
 
Other Regulatory Assets Being Recovered
 
 
 18 
 
 
 15 
 
various
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
 
 
 
Income Taxes, Net
 
 
 1,390 
 
 
 1,353 
 
55 years
 
 
Pension and OPEB Funded Status
 
 
 1,157 
 
 
 1,896 
 
11 years
 
 
Cook Nuclear Plant Refueling Outage Levelization
 
 
 58 
 
 
 27 
 
3 years
 
 
Medicare Subsidy
 
 
 51 
 
 
 - 
 
11 years
 
 
Virginia Transmission Rate Adjustment Clause
 
 
 47 
 
 
 33 
 
2 years
 
 
Peak Demand Reduction/Energy Efficiency
 
 
 44 
 
 
 12 
 
2 years
 
 
Postemployment Benefits
 
 
 40 
 
 
 45 
 
5 years
 
 
United Mine Workers of America Pension Withdrawal
 
 
 27 
 
 
 - 
 
12 years
 
 
Virginia Environmental Rate Adjustment Clause
 
 
 27 
 
 
 8 
 
1 year
 
 
Under-Recovery of Transmission Cost Recovery Factor
 
 
 20 
 
 
 6 
 
1 year
 
 
Storm Related Costs
 
 
 18 
 
 
 27 
 
5 years
 
 
Vegetation Management
 
 
 14 
 
 
 13 
 
1 year
 
 
Deferred Restructuring Costs
 
 
 11 
 
 
 15 
 
5 years
 
 
Litigation Settlement
 
 
 10 
 
 
 - 
 
12 years
 
 
Under-Recovered Distribution Investment Rider
 
 
 9 
 
 
 1 
 
1 year
 
 
Asset Retirement Obligation
 
 
 8 
 
 
 9 
 
33 years
 
 
West Virginia Expanded Net Energy Charge
 
 
 - 
 
 
 26 
 
 
 
 
Ohio Distribution Decoupling
 
 
 - 
 
 
 16 
 
 
 
 
Deferred PJM Fees
 
 
 - 
 
 
 14 
 
 
 
 
Unrealized Loss on Forward Commitments
 
 
 - 
 
 
 8 
 
 
 
 
Other Regulatory Assets Being Recovered
 
 
 49 
 
 
 29 
 
various
Total Regulatory Assets Being Recovered
 
 
 4,046 
 
 
 4,802 
 
 
 
 
 
 
 
 
 
 
 
Total Noncurrent Regulatory Assets
 
$
 4,376 
 
$
 5,106 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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Regulatory Liabilities

Regulatory liabilities are comprised of the following items:

 
 
 
 
 
December 31,
 
Remaining
 
 
 
 
 
2013 
 
2012 
 
Refund Period
Current Regulatory Liabilities
 
(in millions)
 
 
Over-recovered Fuel Costs - pays a return
 
$
 9 
 
$
 25 
 
1 year
Over-recovered Fuel Costs - does not pay a return
 
 
 110 
 
 
 22 
 
1 year
Total Current Regulatory Liabilities
 
$
 119 
 
$
 47 
 
 
 
 
 
 
 
 
 
 
 
Noncurrent Regulatory Liabilities and
 
 
 
 
 
 
 
 
Deferred Investment Tax Credits
 
 
 
 
 
 
 
 
Regulatory liabilities not yet being paid:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Liabilities Currently Paying a Return
 
 
 
 
 
 
 
 
 
 
Louisiana Refundable Construction Financing Costs
 
$
 - 
 
$
 96 
 
 
 
 
Other Regulatory Liabilities Not Yet Being Paid
 
 
 5 
 
 
 4 
 
 
 
Regulatory Liabilities Currently Not Paying a Return
 
 
 
 
 
 
 
 
 
 
Other Regulatory Liabilities Not Yet Being Paid
 
 
 3 
 
 
 9 
 
 
Total Regulatory Liabilities Not Yet Being Paid
 
 
 8 
 
 
 109 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory liabilities being paid:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Liabilities Currently Paying a Return
 
 
 
 
 
 
 
 
 
 
Asset Removal Costs
 
 
 2,589 
 
 
 2,511 
 
(a)
 
 
Louisiana Refundable Construction Financing Costs
 
 
 78 
 
 
 - 
 
5 years
 
 
Advanced Metering Infrastructure Surcharge
 
 
 68 
 
 
 83 
 
7 years
 
 
Deferred Investment Tax Credits
 
 
 29 
 
 
 23 
 
47 years
 
 
Excess Earnings
 
 
 12 
 
 
 12 
 
40 years
 
 
Other Regulatory Liabilities Being Paid
 
 
 1 
 
 
 1 
 
various
 
Regulatory Liabilities Currently Not Paying a Return
 
 
 
 
 
 
 
 
 
 
Excess Asset Retirement Obligations for
 
 
 
 
 
 
 
 
 
 
 
Nuclear Decommissioning Liability
 
 
 597 
 
 
 436 
 
(b)
 
 
Deferred Investment Tax Credits
 
 
 121 
 
 
 136 
 
49 years
 
 
Spent Nuclear Fuel Liability
 
 
 43 
 
 
 43 
 
(b)
 
 
Over-Recovery of Transition Charges
 
 
 40 
 
 
 57 
 
14 years
 
 
Unrealized Gain on Forward Commitments
 
 
 35 
 
 
 46 
 
4 years
 
 
Deferred State Income Tax Coal Credits
 
 
 28 
 
 
 29 
 
10 years
 
 
Peak Demand Reduction/Energy Efficiency
 
 
 18 
 
 
 31 
 
1 year
 
 
Over-Recovery of PJM Expense
 
 
 14 
 
 
 - 
 
2 years
 
 
Other Regulatory Liabilities Being Paid
 
 
 13 
 
 
 27 
 
various
Total Regulatory Liabilities Being Paid
 
 
 3,686 
 
 
 3,435 
 
 
 
 
 
 
 
 
 
 
 
Total Noncurrent Regulatory Liabilities and
 
 
 
 
 
 
 
 
 
Deferred Investment Tax Credits
 
$
 3,694 
 
$
 3,544 
 
 
 
 
 
 
 
 
 
 
 
(a)
Relieved as removal costs are incurred.
(b)
Relieved when plant is decommissioned.

 
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6.   COMMITMENTS, GUARANTEES AND CONTINGENCIES

We are subject to certain claims and legal actions arising in our ordinary course of business.  In addition, our business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation against us cannot be predicted.  For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on our financial statements.

COMMITMENTS

Construction and Commitments

The AEP System has substantial construction commitments to support its operations and environmental investments.  In managing the overall construction program and in the normal course of business, we contractually commit to third-party construction vendors for certain material purchases and other construction services.  The subsidiaries purchase fuel, materials, supplies, services and property, plant and equipment under contract as part of their normal course of business.  Certain supply contracts contain penalty provisions for early termination.

The following table summarizes our actual contractual commitments as of December 31, 2013:

 
 
Less Than 1
 
 
 
 
 
After
 
 
Contractual Commitments
 
Year
 
2-3 Years
 
4-5 Years
 
5 Years
 
Total
 
 
(in millions)
Fuel Purchase Contracts (a)
 
$
 2,387 
 
$
 3,358 
 
$
 2,189 
 
$
 2,480 
 
$
 10,414 
Energy and Capacity Purchase Contracts
 
 
 195 
 
 
 410 
 
 
 457 
 
 
 2,634 
 
 
 3,696 
Construction Contracts for Capital Assets (b)
 
 
 146 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 146 
Total
 
$
 2,728 
 
$
 3,768 
 
$
 2,646 
 
$
 5,114 
 
$
 14,256 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel.
(b)
Represents only capital assets for which we have signed contracts.  Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs.

GUARANTEES

We record liabilities for guarantees in accordance with the accounting guidance for “Guarantees.”  There is no collateral held in relation to any guarantees.  In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letters of Credit

We enter into standby letters of credit with third parties.  As Parent, we issue all of these letters of credit in our ordinary course of business on behalf of our subsidiaries.  These letters of credit cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

We have two revolving credit facilities totaling $3.5 billion, under which we may issue up to $1.2 billion as letters of credit.  As of December 31, 2013, the maximum future payments for letters of credit issued under the revolving credit facilities were $170 million with maturities ranging from February 2014 to April 2015.

In January 2014, we issued letters of credit utilizing the entire amount available under an $85 million uncommitted facility signed in October 2013.  An uncommitted facility gives the issuer of the facility the right to accept or decline each request we make under the facility.

We have $352 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $356 million.  The letters of credit have maturities ranging from March 2014 to March 2015.  In February 2014, $106 million of bilateral letters of credit maturing in March 2014 were extended to March 2017.
 
 
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Guarantees of Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study completed in 2010, we estimate the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation.  As of December 31, 2013, SWEPCo has collected approximately $62 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $46 million is recorded in Asset Retirement Obligations on the balance sheets.

Sabine charges SWEPCo, its only customer, all of its costs.  SWEPCo passes these costs to customers through its fuel clause.

Indemnifications and Other Guarantees

Contracts

We enter into several types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, our exposure generally does not exceed the sale price.  As of December 31, 2013, there were no material liabilities recorded for any indemnifications.

Lease Obligations

We lease certain equipment under master lease agreements.  See “Master Lease Agreements” and “Railcar Lease” sections of Note 13 for disclosure of lease residual value guarantees.

ENVIRONMENTAL CONTINGENCIES

Carbon Dioxide Public Nuisance Claims

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO 2 emissions exacerbated the effects of Hurricane Katrina.  The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims.  The court granted petitions for rehearing.  An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place.  Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision.  The petition was denied in January 2011.  Plaintiffs refiled their complaint in federal district court.  The court ordered all defendants to respond to the refiled complaints in October 2011.  In March 2012, the court granted the defendants’ motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations.  In May 2013, the U.S. Court of Appeals for the Fifth Circuit affirmed the district court’s dismissal of the complaint.  The plaintiffs did not appeal to the U.S. Supreme Court.


 
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Alaskan Villages’ Claims

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies.  The complaint alleges that the defendants' emissions of CO 2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together.  The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance.  The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million.  In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim.  The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court.  In September 2012, the Ninth Circuit Court of Appeals affirmed the trial court’s decision, holding that the CAA displaced Kivalina’s claims for damages.  Plaintiffs filed seeking further review in the U.S. Supreme Court.  In May 2013, the U.S. Supreme Court denied the plaintiffs’ request for review.
 
The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation
 
By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF.  Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized.  In addition, our generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials.  We currently incur costs to dispose of these substances safely.

Superfund addresses clean-up of hazardous substances that have been released to the environment.  The Federal EPA administers the clean-up programs.  Several states have enacted similar laws.  As of December 31, 2013, our subsidiaries are named by the Federal EPA as a Potentially Responsible Party (PRP) for five sites for which alleged liability is unresolved.  There are eight additional sites for which our subsidiaries have received information requests which could lead to PRP designation.  Our subsidiaries have also been named potentially liable at three sites under state law including the I&M site discussed in the next paragraph.  In those instances where we have been named a PRP or defendant, our disposal or recycling activities were in accordance with the then-applicable laws and regulations.  Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories.  Liability has been resolved for a number of sites with no significant effect on net income.

In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm.  I&M started remediation work in accordance with a plan approved by MDEQ.  I&M’s reserve is approximately $8 million.  As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ.  We cannot predict the amount of additional cost, if any.

We evaluate the potential liability for each Superfund site separately, but several general statements can be made about our potential future liability.  Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often nonhazardous.  Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises.  At present, our estimates do not anticipate material cleanup costs for any of our identified Superfund sites, except the I&M site discussed above.

NUCLEAR CONTINGENCIES

I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC).  We have a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant.  The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037.  The operation of a nuclear facility also involves special risks, potential liabilities and specific
 
 
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regulatory and safety requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S.  Should a nuclear incident occur at any nuclear power plant in the U.S., the liability could be substantial.

Decommissioning and Low Level Waste Accumulation Disposal

The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program.  Decommissioning costs are accrued over the service life of the Cook Plant.  The most recent decommissioning cost study was performed in 2012.  According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste ranges from $1.3 billion to $1.7 billion in 2012 nondiscounted dollars.  The wide range in estimated costs is caused by variables in assumptions.  I&M recovers estimated decommissioning costs for the Cook Plant in its rates.  The amounts recovered in rates were $10 million, $14 million and $14 million for the years ended December 31, 2013, 2012 and 2011, respectively.  Decommissioning costs recovered from customers are deposited in external trusts.

As of December 31, 2013 and 2012, the total decommissioning trust fund balance was $1.6 billion and $1.4 billion, respectively.  Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers.  The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability.

I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant.  However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered.

SNF Disposal

The Federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal.  A fee of one mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant is being collected from customers and remitted to the U.S. Treasury.  As of December 31, 2013 and 2012, fees and related interest of $265 million and $265 million, respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $309 million and $308 million, respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts.  I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program.

In 2011, I&M signed a settlement agreement with the Federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delays in accepting SNF for permanent storage.  Under the settlement agreement, I&M received $31 million, $20 million and $14 million in 2013, 2012 and 2011, respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2016.  The proceeds reduced costs for dry cask storage.  As of December 31, 2013, I&M has deferred $22 million in Prepayments and Other Current Assets and $7 million in Deferred Charges and Other Noncurrent Assets on the balance sheet of dry cask storage and related operation and maintenance costs for recovery under this agreement.

See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts.

Nuclear Incident Liability

I&M carries insurance coverage for a nuclear incident at the Cook Plant for property damage, decommissioning and decontamination in the amount of $2.8 billion.  Insurance coverage for a nonnuclear incident at the Cook Plant is $1.7 billion.  Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage.  I&M utilizes industry mutual insurers for the placement of this insurance coverage.  Participation in this mutual insurance requires a contingent financial obligation of up to $39 million for I&M which is assessable if the insurer’s financial resources would be inadequate to pay for losses.


 
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The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public liability arising from a nuclear incident at $13.6 billion and covers any incident at a licensed reactor in the U.S.  Commercially available insurance, which must be carried for each licensed reactor, provides $375 million of coverage.  In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $121 million on each licensed reactor in the U.S. payable in annual installments of $19 million.  As a result, I&M could be assessed $242 million per nuclear incident payable in annual installments of $38 million.  The number of incidents for which payments could be required is not limited.

In the event of an incident of a catastrophic nature, I&M is initially covered for the first $375 million through commercially available insurance.  The next level of liability coverage of up to $13.2 billion would be covered by claims made under the Price-Anderson Act.  If the liability were in excess of amounts recoverable from insurance and retrospective claim payments made under the Price-Anderson Act, I&M would seek to recover those amounts from customers through rate increases.  In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition.

OPERATIONAL CONTINGENCIES

Insurance and Potential Losses

We maintain insurance coverage normal and customary for an integrated electric utility, subject to various deductibles.  Our insurance includes coverage for all risks of physical loss or damage to our nonnuclear assets, subject to insurance policy conditions and exclusions.  Covered property generally includes power plants, substations, facilities and inventories.  Excluded property generally includes transmission and distribution lines, poles and towers.  Our insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by us.  Coverage is generally provided by a combination of our protected cell of EIS and/or various industry mutual and/or commercial insurance carriers.

See “Nuclear Contingencies” section of this footnote for a discussion of nuclear exposures and related insurance.

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant.  Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition.

Rockport Plant Litigation

In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit.  The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement.  The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff.  The New York court has granted our motion to transfer this case to the U.S. District Court for the Southern District of Ohio.  Our motion to dismiss, filed in October 2013, is pending.  We will continue to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

Natural Gas Markets Lawsuits

In 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity.  AEP was dismissed from the case.  A number of similar cases were also filed in California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies.  AEP (or a subsidiary) is among the companies named as defendants in some of these cases.  
 
 
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We settled, received summary judgment or were dismissed from all of these cases.  The plaintiffs appealed the Nevada federal district court's dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit.  In April 2013, the appellate court reversed in part, and affirmed in part, the district court's orders in these cases.  The appellate court reversed the district court's holding that the state antitrust claims were preempted by the Natural Gas Act and the order dismissing AEP from two of the cases on personal jurisdiction grounds and affirmed the decision denying leave to the plaintiffs to amend their complaints in two of the cases.  AEP filed a motion with the appellate court for rehearing on the issue of whether the district court had personal jurisdiction of AEP in the two referenced cases.  No decision has been rendered on that motion.  Defendants in these cases, including AEP, filed a petition seeking further review with the U.S. Supreme Court on the preemption issue, which is pending.  We will continue to defend the cases.  We believe the provision we have is adequate.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

7.   ACQUISITIONS AND IMPAIRMENTS

ACQUISITIONS

2012

BlueStar Energy (Generation & Marketing segment)

In March 2012, we completed the acquisition of BlueStar Energy Holdings, Inc. (BlueStar) and its independent retail electric supplier BlueStar Energy Solutions for $70 million.  This transaction also included goodwill of $15 million, intangible assets associated with sales contracts and customer accounts of $58 million and liabilities associated with supply contracts of $25 million.  BlueStar has been in operation since 2002.  Beginning in June 2012, BlueStar began doing business as AEP Energy.  AEP Energy provides electric supply for retail customers in Ohio, Illinois and other deregulated electricity markets and also provides energy solutions throughout the United States, including demand response and energy efficiency services.

Other Matters

Enron Bankruptcy (Corporate and Other)

In February 2011, we reached a $425 million settlement covering all claims with BOA and Enron related to our purchase of Houston Pipeline Company (HPL) from Enron in 2001.  As part of the settlement, we received title to the 55 billion cubic feet of natural gas in the Bammel storage facility and recorded this asset at fair value.  Under the HPL sales agreement, we have a service obligation to the buyer for the right to use the cushion gas through May 2031.  We recognized the obligation as a liability and will amortize it over the life of the agreement.

The settlement resulted in a pretax gain of $51 million and a net loss after tax of $22 million primarily due to an unrealized capital loss valuation allowance of $56 million.

IMPAIRMENTS

2013

Amos Plant, Unit 3 (Vertically Integrated Utilities segment)

In July 2013, the Virginia SCC approved the transfer of a two-thirds interest in the Amos Plant, Unit 3 to APCo but, for rate purposes, reduced the proposed transfer price by $83 million pretax.  The Virginia jurisdictional share of the reduced price is approximately $39 million.  In December 2013, the WVPSC issued an order that approved the transfer of a two-thirds interest in the Amos Plant, Unit 3 to APCo but deferred a final decision related to the $83 million pretax reduction in transfer price until APCo’s next base rate case.  The West Virginia and FERC jurisdictional share of the potential reduced transfer price is approximately $44 million.  Upon evaluation, management believes the West Virginia jurisdictional share is probable of recovery.  As a result of the Virginia order, in the fourth quarter of 2013, we recorded a pretax impairment of $39 million in Asset Impairments and Other Related Charges on the statement of income.  See the “Plant Transfer” section of Note 4.
 
 
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Big Sandy Plant, Unit 2 FGD Project (Vertically Integrated Utilities segment)

In the third quarter of 2013, KPCo recorded a pretax write-off of $33 million in Asset Impairments and Other Related Charges on the statement of income primarily related to the Big Sandy Plant, Unit 2 FGD project.  See the “Plant Transfer” section of Note 4.

Muskingum River Plant, Unit 5 (Generation & Marketing segment)

In May 2013, the U.S. District Court for the Southern District of Ohio approved a modification to the consent decree, which was initially entered into in 2007, requiring certain types of pollution control equipment to be installed at certain AEP plants, including the 600 MW Muskingum River Plant, Unit 5 (MR5) coal-fired generation plant.  Under the modification to the consent decree, we have the option to cease burning coal and retire MR5 in 2015 or to cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017.  In the second quarter of 2013, based on the approval of the modified consent decree and changes in other market factors, we re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project, which would have extended the useful life of MR5, is remote.  As a result, management completed an impairment analysis and concluded that MR5 was impaired.  Under a market-based value approach, using level 3 unobservable inputs, management determined that the fair value of this generating unit was zero based on the lack of installed environmental control equipment and the nature and condition of this generating unit.  In the second quarter of 2013, we recorded a pretax impairment of $154 million in Asset Impairments and Other Related Charges on the statement of income which includes a $6 million pretax impairment of related material and supplies inventory.  Management expects to retire the plant in 2015.

2012

Beckjord Plant, Unit 6, Conesville Plant, Unit 3, Kammer Plant, Units 1-3, Muskingum River Plant, Units 1-4, Sporn Plant, Units 2 and 4 and Picway Plant, Unit 5 (Generation & Marketing segment)

In October 2012, we filed applications with the FERC proposing to terminate the Interconnection Agreement and seeking to complete the corporate separation of OPCo's generation assets.  Based on the intention to terminate the Interconnection Agreement and the FERC filing, we performed an evaluation of the recoverability of generation assets.  As a result, in November 2012, we, using generating unit specific estimated future cash flows, concluded that we had a material impairment of certain Ohio generation assets.  Under a market-based value approach, using level 3 unobservable inputs, we determined that the fair value of these generating units was zero based on the lack of installed environmental control equipment and the nature and condition of these generating units.  In the fourth quarter of 2012, we recorded a pretax impairment of $287 million in Asset Impairments and Other Related Charges on the statement of income related to Beckjord Plant, Unit 6, Conesville Plant, Unit 3, Kammer Plant, Units 1-3, Muskingum River Plant, Units 1-4, Sporn Plant, Units 2 and 4 and Picway Plant, Unit 5 generating units which includes $13 million of related material and supplies inventory.

Turk Plant (Vertically Integrated Utilities segment)

In 2012, SWEPCo recorded a pretax write-off of $13 million in Asset Impairments and Other Related Charges on the statement of income related to unrecoverable construction costs subject to the Texas capital costs cap portion of the Turk Plant.

2011

Turk Plant (Vertically Integrated Utilities segment)

In the fourth quarter of 2011, SWEPCo recorded a pretax write-off of $49 million in Asset Impairments and Other Related Charges on the statement of income related to the Texas jurisdictional portion of the Turk Plant as a result of the November 2011 Texas Court of Appeals decision upholding the Texas capital cost cap.


 
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Muskingum River Plant, Unit 5 FGD Project (MR5) (Generation & Marketing segment)

In September 2011, subsequent to the stipulation agreement filed with the PUCO, we determined that we were not likely to complete the previously suspended MR5 project and that the project’s preliminary engineering costs were no longer probable of being recovered.  As a result, in the third quarter of 2011, we recorded a pretax write-off of $42 million in Asset Impairments and Other Related Charges on the statement of income.

Sporn Plant, Unit 5 (Generation & Marketing segment)

In the third quarter of 2011, we decided to no longer offer the output of Sporn Plant, Unit 5 into the PJM Reliability Pricing Model auction.  Sporn Plant, Unit 5 is not expected to operate in the future, resulting in the removal of Sporn Plant, Unit 5 from the Interconnection Agreement.  As a result, in the third quarter of 2011, we recorded a pretax write-off of $48 million in Asset Impairments and Other Related Charges on the statement of income.

8.   BENEFIT PLANS

For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Investments Held in Trust for Future Liabilities” and “Fair Value Measurements of Assets and Liabilities” sections of Note 1.

We sponsor a qualified pension plan and two unfunded nonqualified pension plans.  Substantially all of our employees are covered by the qualified plan or both the qualified and a nonqualified pension plan.  We sponsor OPEB plans to provide health and life insurance benefits for retired employees.

We recognize the funded status associated with our defined benefit pension and OPEB plans in the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance.  We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost.  We record a regulatory asset instead of other comprehensive income for qualifying benefit costs of our regulated operations that for ratemaking purposes are deferred for future recovery.  The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.

Actuarial Assumptions for Benefit Obligations

The weighted-average assumptions as of December 31 of each year used in the measurement of our benefit obligations are shown in the following table:

 
 
 
 
 
Other Postretirement
 
 
Pension Plans
 
 
Benefit Plans
Assumptions
 
2013 
 
 
2012 
 
 
2013 
 
2012 
Discount Rate
 
 4.70 
%
 
 
 3.95 
%
 
 
 4.70 
%
 
 3.95 
%
Rate of Compensation Increase
 
 4.85 
%
(a)
 
 4.95 
%
(a)
 
NA
 
NA

(a)
Rates are for base pay only.  In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees .
NA
Not applicable.

We use a duration-based method to determine the discount rate for our plans.  A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability.  The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.

For 2013, the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 11.5% per year, with an average increase of 4.85%.
 
 
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Actuarial Assumptions for Net Periodic Benefit Costs

The weighted-average assumptions as of January 1 of each year used in the measurement of our benefit costs are shown in the following table:

 
 
 
 
 
Other Postretirement
 
 
 
Pension Plans
 
Benefit Plans
 
 
2013 
 
2012 
 
2011 
 
2013 
 
2012 
 
2011 
Discount Rate
 
 3.95 
%
 
 4.55 
%
 
 5.05 
%
 
 3.95 
%
 
 4.75 
%
 
 5.25 
%
Expected Return on Plan Assets
 
 6.50 
%
 
 7.25 
%
 
 7.75 
%
 
 7.00 
%
 
 7.25 
%
 
 7.50 
%
Rate of Compensation Increase
 
 4.95 
%
 
 4.85 
%
 
 4.85 
%
 
NA
 
NA
 
NA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NA   Not applicable.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation and current prospects for economic growth.

The health care trend rate assumptions as of January 1 of each year used for OPEB plans measurement purposes are shown below:

Health Care Trend Rates
 
2013 
 
2012 
Initial
 
 6.75 
%
 
 7.00 
%
Ultimate
 
 5.00 
%
 
 5.00 
%
Year Ultimate Reached
 
2020 
 
 
2020 
 

Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans.  A 1% change in assumed health care cost trend rates would have the following effects:

 
1% Increase
 
1% Decrease
 
(in millions)
Effect on Total Service and Interest Cost
 
 
 
 
 
 
Components of Net Periodic Postretirement Health
 
 
 
 
 
 
Care Benefit Cost
$
 6 
 
$
 (4)
 
 
 
 
 
 
Effect on the Health Care Component of the
 
 
 
 
 
 
Accumulated Postretirement Benefit Obligation
 
 74 
 
 
 (59)

Significant Concentrations of Risk within Plan Assets

In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets.  The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits.  The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment.  We monitor the plans to control security diversification and ensure compliance with our investment policy.  As of December 31, 2013, the assets were invested in compliance with all investment limits.  See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details.


 
101

 


Benefit Plan Obligations, Plan Assets and Funded Status as of December 31, 2013 and 2012

The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status as of December 31.  The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively.

 
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
2013 
 
2012 
 
2013 
 
2012 
Change in Benefit Obligation
 
(in millions)
Benefit Obligation as of January 1,
 
$
 5,205 
 
$
 4,991 
 
$
 1,849 
 
$
 2,227 
Service Cost
 
 
 69 
 
 
 76 
 
 
 23 
 
 
 47 
Interest Cost
 
 
 203 
 
 
 223 
 
 
 71 
 
 
 103 
Actuarial (Gain) Loss
 
 
 (305)
 
 
 299 
 
 
 (395)
 
 
 148 
Plan Amendment Prior Service Credit
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (570)
Curtailment and Settlements
 
 
 - 
 
 
 (1)
 
 
 - 
 
 
 - 
Benefit Payments
 
 
 (331)
 
 
 (383)
 
 
 (140)
 
 
 (151)
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 39 
 
 
 35 
Medicare Subsidy
 
 
 - 
 
 
 - 
 
 
 9 
 
 
 10 
Benefit Obligation as of December 31,
 
$
 4,841 
 
$
 5,205 
 
$
 1,456 
 
$
 1,849 
 
 
 
 
 
 
 
 
 
 
 
 
 
Change in Fair Value of Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Plan Assets as of January 1,
 
$
 4,696 
 
$
 4,303 
 
$
 1,568 
 
$
 1,410 
Actual Gain on Plan Assets
 
 
 340 
 
 
 560 
 
 
 208 
 
 
 178 
Company Contributions
 
 
 6 
 
 
 216 
 
 
 24 
 
 
 96 
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 39 
 
 
 35 
Benefit Payments
 
 
 (331)
 
 
 (383)
 
 
 (140)
 
 
 (151)
Fair Value of Plan Assets as of December 31,
 
$
 4,711 
 
$
 4,696 
 
$
 1,699 
 
$
 1,568 
 
 
 
 
 
 
 
 
 
 
 
 
 
Funded (Underfunded) Status as of December 31,
 
$
 (130)
 
$
 (509)
 
$
 243 
 
$
 (281)
 
Amounts Recognized on the Balance Sheets as of December 31, 2013 and 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement
 
 
 
Pension Plans
 
Benefit Plans
 
 
 
December 31,
 
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
(in millions)
Deferred Charges and Other Noncurrent Assets -
 
 
 
 
 
 
 
 
 
 
 
 
 
Prepaid Benefit Costs
 
$
 - 
 
$
 - 
 
$
 264 
 
$
 - 
Other Current Liabilities - Accrued Short-term
 
 
 
 
 
 
 
 
 
 
 
 
 
Benefit Liability
 
 
 (7)
 
 
 (7)
 
 
 (4)
 
 
 (4)
Employee Benefits and Pension Obligations -
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Long-term Benefit Liability
 
 
 (123)
 
 
 (502)
 
 
 (17)
 
 
 (277)
Funded (Underfunded) Status
 
$
 (130)
 
$
 (509)
 
$
 243 
 
$
 (281)


 
102

 


Amounts Included in AOCI and Regulatory Assets as of December 31, 2013 and 2012
 
 
 
 
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
 
December 31,
 
 
 
2013 
 
2012 
 
2013 
 
2012 
 
Components
 
(in millions)
Net Actuarial Loss
 
$
 1,561 
 
$
 2,111 
 
$
 428 
 
$
 989 
 
Prior Service Cost (Credit)
 
 
 8 
 
 
 11 
 
 
 (693)
 
 
 (762)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recorded as
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets
 
$
 1,343 
 
$
 1,774 
 
$
 (191)
 
$
 108 
 
Deferred Income Taxes
 
 
 79 
 
 
 122 
 
 
 (26)
 
 
 42 
 
Net of Tax AOCI
 
 
 147 
 
 
 226 
 
 
 (48)
 
 
 77 
 

Components of the change in amounts included in AOCI and Regulatory Assets during the years ended December 31, 2013 and 2012 are as follows:

 
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
Years Ended December 31,
 
 
2013 
 
2012 
 
2013 
 
2012 
Components
 
(in millions)
Actuarial (Gain) Loss During the Year
 
$
 (367)
 
$
 58 
 
$
 (496)
 
$
 67 
Prior Service Credit
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (570)
Amortization of Actuarial Loss
 
 
 (183)
 
 
 (155)
 
 
 (65)
 
 
 (57)
Amortization of Prior Service Credit (Cost)
 
 
 (3)
 
 
 1 
 
 
 69 
 
 
 18 
Amortization of Transition Obligation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (1)
Change for the Year
 
$
 (553)
 
$
 (96)
 
$
 (492)
 
$
 (543)


 
103

 


Pension and Other Postretirement Plans’ Assets

The following table presents the classification of pension plan assets within the fair value hierarchy as of December 31, 2013:

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
(in millions)
 
 
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 1,092 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 1,092 
 
 23.2 
%
 
International
 
 
 514 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 514 
 
 10.9 
%
 
Real Estate Investment Trusts
 
 
 58 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 58 
 
 1.2 
%
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 10 
 
 
 - 
 
 
 - 
 
 
 10 
 
 0.2 
%
Subtotal - Equities
 
 
 1,664 
 
 
 10 
 
 
 - 
 
 
 - 
 
 
 1,674 
 
 35.5 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 26 
 
 
 - 
 
 
 - 
 
 
 26 
 
 0.5 
%
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 387 
 
 
 - 
 
 
 - 
 
 
 387 
 
 8.2 
%
 
Corporate Debt
 
 
 - 
 
 
 1,600 
 
 
 - 
 
 
 - 
 
 
 1,600 
 
 34.0 
%
 
Foreign Debt
 
 
 - 
 
 
 344 
 
 
 - 
 
 
 - 
 
 
 344 
 
 7.3 
%
 
State and Local Government
 
 
 - 
 
 
 28 
 
 
 - 
 
 
 - 
 
 
 28 
 
 0.6 
%
 
Other - Asset Backed
 
 
 - 
 
 
 33 
 
 
 - 
 
 
 - 
 
 
 33 
 
 0.7 
%
Subtotal - Fixed Income
 
 
 - 
 
 
 2,418 
 
 
 - 
 
 
 - 
 
 
 2,418 
 
 51.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 238 
 
 
 - 
 
 
 238 
 
 5.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 330 
 
 
 - 
 
 
 330 
 
 7.0 
%
Securities Lending
 
 
 - 
 
 
 35 
 
 
 - 
 
 
 - 
 
 
 35 
 
 0.8 
%
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (45)
 
 
 (45)
 
 (0.9)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 - 
 
 
 48 
 
 
 - 
 
 
 - 
 
 
 48 
 
 1.0 
%
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 13 
 
 
 13 
 
 0.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 1,664 
 
$
 2,511 
 
$
 568 
 
$
 (32)
 
$
 4,711 
 
 100.0 
%

(a)
Amounts in "Other" column primarily represent an obligation to repay cash collateral received as part of the Securities Lending Program.
(b)
Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.

The following table sets forth a reconciliation of changes in the fair value of assets classified as Level 3 in the fair value hierarchy for the pension assets:

 
 
 
Real
 
Alternative
 
Total
 
 
 
Estate
 
Investments
 
Level 3
 
 
 
 
Balance as of January 1, 2013
 
$
 220 
 
$
 195 
 
$
 415 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 26 
 
 
 15 
 
 
 41 
 
Relating to Assets Sold During the Period
 
 
 - 
 
 
 15 
 
 
 15 
Purchases and Sales
 
 
 (8)
 
 
 105 
 
 
 97 
Transfers into Level 3
 
 
 - 
 
 
 - 
 
 
 - 
Transfers out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
Balance as of December 31, 2013
 
$
 238 
 
$
 330 
 
$
 568 


 
104

 


The following table presents the classification of OPEB plan assets within the fair value hierarchy as of December 31, 2013:

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
(in millions)
 
 
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 473 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 473 
 
 27.9 
%
 
International
 
 
 616 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 616 
 
 36.2 
%
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Global
 
 
 - 
 
 
 15 
 
 
 - 
 
 
 - 
 
 
 15 
 
 0.9 
%
Subtotal - Equities
 
 
 1,089 
 
 
 15 
 
 
 - 
 
 
 - 
 
 
 1,104 
 
 65.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 88 
 
 
 - 
 
 
 - 
 
 
 88 
 
 5.2 
%
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 56 
 
 
 - 
 
 
 - 
 
 
 56 
 
 3.3 
%
 
Corporate Debt
 
 
 - 
 
 
 110 
 
 
 - 
 
 
 - 
 
 
 110 
 
 6.5 
%
 
Foreign Debt
 
 
 - 
 
 
 22 
 
 
 - 
 
 
 - 
 
 
 22 
 
 1.2 
%
 
State and Local Government
 
 
 - 
 
 
 5 
 
 
 - 
 
 
 - 
 
 
 5 
 
 0.3 
%
 
Other - Asset Backed
 
 
 - 
 
 
 8 
 
 
 - 
 
 
 - 
 
 
 8 
 
 0.5 
%
Subtotal - Fixed Income
 
 
 - 
 
 
 289 
 
 
 - 
 
 
 - 
 
 
 289 
 
 17.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 13 
 
 
 - 
 
 
 - 
 
 
 13 
 
 0.8 
%
 
United States Bonds
 
 
 - 
 
 
 211 
 
 
 - 
 
 
 - 
 
 
 211 
 
 12.4 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 68 
 
 
 9 
 
 
 - 
 
 
 - 
 
 
 77 
 
 4.5 
%
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 5 
 
 
 5 
 
 0.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 1,157 
 
$
 537 
 
$
 - 
 
$
 5 
 
$
 1,699 
 
 100.0 
%

(a)
Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.


 
105

 


The following table presents the classification of pension plan assets within the fair value hierarchy as of December 31, 2012:

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
(in millions)
 
 
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 1,308 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 1,308 
 
 27.9 
%
 
International
 
 
 497 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 497 
 
 10.5 
%
 
Real Estate Investment Trusts
 
 
 91 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 91 
 
 1.9 
%
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 4 
 
 
 - 
 
 
 - 
 
 
 4 
 
 0.1 
%
Subtotal - Equities
 
 
 1,896 
 
 
 4 
 
 
 - 
 
 
 - 
 
 
 1,900 
 
 40.4 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 32 
 
 
 - 
 
 
 - 
 
 
 32 
 
 0.7 
%
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 715 
 
 
 - 
 
 
 - 
 
 
 715 
 
 15.2 
%
 
Corporate Debt
 
 
 - 
 
 
 1,235 
 
 
 - 
 
 
 - 
 
 
 1,235 
 
 26.3 
%
 
Foreign Debt
 
 
 - 
 
 
 199 
 
 
 - 
 
 
 - 
 
 
 199 
 
 4.2 
%
 
State and Local Government
 
 
 - 
 
 
 44 
 
 
 - 
 
 
 - 
 
 
 44 
 
 0.9 
%
 
Other - Asset Backed
 
 
 - 
 
 
 36 
 
 
 - 
 
 
 - 
 
 
 36 
 
 0.8 
%
Subtotal - Fixed Income
 
 
 - 
 
 
 2,261 
 
 
 - 
 
 
 - 
 
 
 2,261 
 
 48.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 220 
 
 
 - 
 
 
 220 
 
 4.7 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 195 
 
 
 - 
 
 
 195 
 
 4.2 
%
Securities Lending
 
 
 - 
 
 
 80 
 
 
 - 
 
 
 - 
 
 
 80 
 
 1.7 
%
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (91)
 
 
 (91)
 
 (1.9)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 - 
 
 
 126 
 
 
 - 
 
 
 - 
 
 
 126 
 
 2.7 
%
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 5 
 
 
 5 
 
 0.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 1,896 
 
$
 2,471 
 
$
 415 
 
$
 (86)
 
$
 4,696 
 
 100.0 
%

(a)
Amounts in "Other" column primarily represent an obligation to repay cash collateral received as part of the Securities Lending Program.
(b)
Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.

The following table sets forth a reconciliation of changes in the fair value of assets classified as Level 3 in the fair value hierarchy for the pension assets:

 
 
 
Corporate
 
Real
 
Alternative
 
Total
 
 
 
Debt
 
Estate
 
Investments
 
Level 3
 
 
 
 
(in millions)
Balance as of January 1, 2012
 
$
 6 
 
$
 163 
 
$
 161 
 
$
 330 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 - 
 
 
 30 
 
 
 10 
 
 
 40 
 
Relating to Assets Sold During the Period
 
 
 (2)
 
 
 - 
 
 
 4 
 
 
 2 
Purchases and Sales
 
 
 (4)
 
 
 27 
 
 
 20 
 
 
 43 
Transfers into Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Transfers out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Balance as of December 31, 2012
 
$
 - 
 
$
 220 
 
$
 195 
 
$
 415 


 
106

 


The following table presents the classification of OPEB plan assets within the fair value hierarchy as of December 31, 2012:

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
(in millions)
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 422 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 422 
 
 26.9 
%
 
International
 
 
 505 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 505 
 
 32.2 
%
Subtotal - Equities
 
 
 927 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 927 
 
 59.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 72 
 
 
 - 
 
 
 - 
 
 
 72 
 
 4.6 
%
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 82 
 
 
 - 
 
 
 - 
 
 
 82 
 
 5.2 
%
 
Corporate Debt
 
 
 - 
 
 
 155 
 
 
 - 
 
 
 - 
 
 
 155 
 
 9.9 
%
 
Foreign Debt
 
 
 - 
 
 
 26 
 
 
 - 
 
 
 - 
 
 
 26 
 
 1.7 
%
 
State and Local Government
 
 
 - 
 
 
 7 
 
 
 - 
 
 
 - 
 
 
 7 
 
 0.5 
%
 
Other - Asset Backed
 
 
 - 
 
 
 10 
 
 
 - 
 
 
 - 
 
 
 10 
 
 0.6 
%
Subtotal - Fixed Income
 
 
 - 
 
 
 352 
 
 
 - 
 
 
 - 
 
 
 352 
 
 22.5 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 52 
 
 
 - 
 
 
 - 
 
 
 52 
 
 3.3 
%
 
United States Bonds
 
 
 - 
 
 
 163 
 
 
 - 
 
 
 - 
 
 
 163 
 
 10.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 62 
 
 
 11 
 
 
 - 
 
 
 - 
 
 
 73 
 
 4.7 
%
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1 
 
 
 1 
 
 0.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 989 
 
$
 578 
 
$
 - 
 
$
 1 
 
$
 1,568 
 
 100.0 
%

(a)    Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.

Determination of Pension Expense

We base our determination of pension expense or income on a market-related valuation of assets which reduces year-to-year volatility.  This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return.

The accumulated benefit obligation for the pension plans is as follows:

 
 
December 31,
Accumulated Benefit Obligation
 
2013 
 
2012 
 
 
(in millions)
Qualified Pension Plan
 
$
 4,638 
 
$
 5,001 
Nonqualified Pension Plans
 
 
 77 
 
 
 82 
Total
 
$
 4,715 
 
$
 5,083 


 
107

 


For our underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans as of December 31, 2013 and 2012 were as follows:

 
 
Underfunded Pension Plans
 
 
December 31,
 
 
2013 
 
2012 
 
 
(in millions)
Projected Benefit Obligation
 
$
 4,841 
 
$
 5,205 
 
 
 
 
 
 
 
Accumulated Benefit Obligation
 
$
 4,715 
 
$
 5,083 
Fair Value of Plan Assets
 
 
 4,711 
 
 
 4,696 
Underfunded Accumulated Benefit Obligation
 
$
 (4)
 
$
 (387)

Estimated Future Benefit Payments and Contributions

We expect contributions and payments for the pension plans of $80 million and the OPEB plans of $6 million during 2014.  For the pension plans, this amount includes the payment of unfunded nonqualified benefits plus contributions to the qualified trust fund of at least the minimum amount required by the Employee Retirement Income Security Act.  For the qualified pension plan, we may also make additional discretionary contributions to maintain the funded status of the plan.  For the OPEB plans, expected payments include the payment of unfunded benefits.

The table below reflects the total benefits expected to be paid from the plan or from our assets.  The payments include the participants’ contributions to the plan for their share of the cost.  In November 2012, we announced changes to our retiree medical coverage.  Effective for retirements after December 2012, our contribution to retiree medical coverage was capped reducing our exposure to future medical cost inflation.  Effective for employees hired after December 2013, we will not provide retiree medical coverage.  The impact of the changes is reflected in the Benefit Plan Obligation table as plan amendments.  Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results.  The estimated payments for pension benefits and OPEB are as follows:

 
 
Pension Plans
 
Other Postretirement Benefit Plans
 
 
Pension
 
Benefit
 
Medicare Subsidy
 
 
Payments
 
Payments
 
Receipts
 
 
(in millions)
2014 
 
$
 355 
 
$
 140 
 
$
 - 
2015 
 
 
 363 
 
 
 145 
 
 
 - 
2016 
 
 
 368 
 
 
 149 
 
 
 - 
2017 
 
 
 372 
 
 
 152 
 
 
 - 
2018 
 
 
 377 
 
 
 156 
 
 
 - 
Years 2019 to 2023, in Total
 
 
 1,857 
 
 
 809 
 
 
 2 


 
108

 


Components of Net Periodic Benefit Cost

The following table provides the components of our net periodic benefit cost (credit) for the plans for the years ended December 31, 2013, 2012 and 2011:

 
 
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
 
2013 
 
2012 
 
2011 
 
 
 
(in millions)
Service Cost
 
$
 69 
 
$
 76 
 
$
 72 
 
$
 23 
 
$
 47 
 
$
 42 
Interest Cost
 
 
 203 
 
 
 223 
 
 
 237 
 
 
 71 
 
 
 103 
 
 
 109 
Expected Return on Plan Assets
 
 
 (278)
 
 
 (319)
 
 
 (314)
 
 
 (107)
 
 
 (101)
 
 
 (109)
Curtailment
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1 
Amortization of Transition Obligation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1 
 
 
 2 
Amortization of Prior Service Cost (Credit)
 
 
 3 
 
 
 (1)
 
 
 1 
 
 
 (69)
 
 
 (18)
 
 
 (1)
Amortization of Net Actuarial Loss
 
 
 183 
 
 
 155 
 
 
 122 
 
 
 65 
 
 
 57 
 
 
 29 
Net Periodic Benefit Cost (Credit)
 
 
 180 
 
 
 134 
 
 
 118 
 
 
 (17)
 
 
 89 
 
 
 73 
Capitalized Portion
 
 
 (56)
 
 
 (42)
 
 
 (37)
 
 
 5 
 
 
 (28)
 
 
 (22)
Net Periodic Benefit Cost (Credit)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recognized in Expense
 
$
 124 
 
$
 92 
 
$
 81 
 
$
 (12)
 
$
 61 
 
$
 51 

Estimated amounts expected to be amortized to net periodic benefit costs (credits) and the impact on the balance sheet during 2014 are shown in the following table:

 
 
 
 
Other
 
 
 
 
 
Postretirement
 
 
 
Pension Plans
 
Benefit Plans
Components
 
(in millions)
Net Actuarial Loss
 
$
 125 
 
$
 21 
Prior Service Cost (Credit)
 
 
 2 
 
 
 (69)
Total Estimated 2014 Amortization
 
$
 127 
 
$
 (48)
 
 
 
 
 
 
 
Expected to be Recorded as
 
 
 
 
 
 
Regulatory Asset
 
$
 107 
 
$
 (34)
Deferred Income Taxes
 
 
 7 
 
 
 (5)
Net of Tax AOCI
 
 
 13 
 
 
 (9)
Total
 
$
 127 
 
$
 (48)

American Electric Power System Retirement Savings Plan

We sponsor the American Electric Power System Retirement Savings Plan, a defined contribution retirement savings plan for substantially all employees who are not members of the United Mine Workers of America (UMWA).  It is a qualified plan offering participants an opportunity to contribute a portion of their pay with features under Section 401(k) of the Internal Revenue Code.  The matching contributions to the plan are 100% of the first 1% of eligible employee contributions and 70% of the next 5% of contributions.  The cost for matching contributions totaled $67 million in 2013, $66 million in 2012 and $64 million in 2011.

UMWA Benefits

We provide UMWA pension, health and welfare benefits for certain unionized mining employees, retirees and their survivors who meet eligibility requirements.  UMWA trustees make final interpretive determinations with regard to all benefits.  The pension benefits are administered by UMWA trustees and contributions are made to their trust funds.  The health and welfare benefits are administered by us and benefits are paid from our general assets.

The UMWA pension benefits are administered through a multiemployer plan that is different from single-employer plans as an employer’s contributions may be used to provide benefits to employees of other participating employers.  Required contributions not made by any employer may result in other employers bearing the unfunded plan obligations, while a withdrawing employer may be subject to a withdrawal liability.  UMWA pension benefits are provided through the United Mine Workers of America 1974 Pension Plan (Employer Identification Number: 52-
 
 
109

 
1050282, Plan Number 002), which under the Pension Protection Act of 2006 (PPA) was in Seriously Endangered Status for the plan years ending June 30, 2013 and 2012, without utilization of extended amortization provisions.  The Plan adopted a funding improvement plan in May 2012, as required under the PPA.

Contributions to the UMWA pension plan in 2013, 2012 and 2011 were made under a collective bargaining agreement that is scheduled to expire December 31, 2017.  We contributed immaterial amounts in 2013, 2012 and 2011 that represent less than 5% of the total contributions in the plan’s latest annual report for the years ended June 30, 2013, 2012 and 2011.  The contributions we made did not include a surcharge.  There are no minimum contributions for future years.

Based upon the plan to retrofit the Rockport Plant with dry sorbent injection technology to meet environmental emission control requirements, the timing of the closure of Cook Coal Terminal is expected to be in or after 2025.  Due to the estimated closure date and the ability to estimate the amount of the withdrawal liability, we recorded a liability of $39 million during 2013 and a related regulatory asset of $30 million.  The regulatory asset should be recovered in future billings for transloading services before the planned closure.

9.   BUSINESS SEGMENTS

Our primary business is the generation, transmission and distribution of electricity.  Within our Vertically Integrated Utilities segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

During the fourth quarter of 2013, we changed the structure of our internal organization which resulted in a change in the composition of our reportable segments.  In accordance with authoritative accounting guidance for segment reporting, prior period financial information has been recast in the financial statements and footnotes to be comparable to the current year presentation of reportable segments.  See the “Corporate Separation” section of Executive Overview.

Our reportable segments and their related business activities are outlined below:

Vertically Integrated Utilities

·  
Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

·  
Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC.
·  
OPCo purchases energy and capacity to serve remaining generation service customers.

Generation & Marketing

·  
Nonregulated generation in ERCOT and PJM.
·  
Marketing, risk management and retail activities in ERCOT, PJM and MISO.

AEP Transmission Holdco

·  
Development, construction and operation of transmission facilities through investments in our wholly-owned transmission only subsidiaries and transmission only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.

AEP River Operations

·  
Commercial barging operations that transports liquids, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.


 
110

 


The remainder of our activities is presented as Corporate and Other.  While not considered a reportable segment, Corporate and Other primarily includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries.  This segment also includes parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

The tables below present our reportable segment information for the years ended December 31, 2013, 2012 and 2011   and balance sheet information as of December 31, 2013 and 2012.  These amounts include certain estimates and allocations where necessary.

 
 
 
 
 
 
 
Transmission
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Vertically
 
and
 
AEP
 
 
 
 
Generation
 
Corporate
 
 
 
 
 
 
 
 
 
 
Integrated
 
Distribution
Transmission
AEP River
 
and
and Other
Reconciling
 
 
 
 
 
 
Utilities
 
Utilities
Holdco
Operations
 
Marketing
(a)
Adjustments
 
Consolidated
 
 
 
 
(in millions)
Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
External Customers
 
$
 9,347 
 
$
 4,279 
 
$
 27 
 
$
 544 
 
$
 1,208 
 
$
 32 
 
$
 (80)
(b)
 
$
 15,357 
 
 
Other Operating Segments
 
 
 645 
 
 
 199 
 
 
 51 
 
 
 19 
 
 
 2,457 
 
 
 57 
 
 
 (3,428)
 
 
 
 - 
Total Revenues
 
$
 9,992 
 
$
 4,478 
 
$
 78 
 
$
 563 
 
$
 3,665 
 
$
 89 
 
$
 (3,508)
 
 
$
 15,357 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Asset Impairments and Other
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Related Charges
 
$
 72 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 154 
 
$
 - 
 
$
 - 
 
 
$
 226 
Depreciation and Amortization
 
 
 941 
 
 
 591 
 
 
 10 
 
 
 31 
 
 
 236 
 
 
 - 
 
 
 (66)
(c)
 
 
 1,743 
Interest Income
 
 
 7 
 
 
 2 
 
 
 - 
 
 
 - 
 
 
 2 
 
 
 69 
 
 
 (22)
 
 
 
 58 
Carrying Costs Income
 
 
 14 
 
 
 16 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
 30 
Interest Expense
 
 
 540 
 
 
 292 
 
 
 10 
 
 
 17 
 
 
 55 
 
 
 27 
 
 
 (35)
(c)
 
 
 906 
Income Tax Expense
 
 
 398 
 
 
 198 
 
 
 29 
 
 
 7 
 
 
 112 
 
 
 (60)
 
 
 - 
 
 
 
 684 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income
 
 
 681 
 
 
 358 
 
 
 80 
 
 
 12 
 
 
 228 
 
 
 125 
 
 
 - 
 
 
 
 1,484 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gross Property Additions
 
 
 1,822 
 
 
 871 
 
 
 843 
 
 
 7 
 
 
 185 
 
 
 9 
 
 
 (81)
 
 
 
 3,656 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Transmission
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Vertically
 
and
 
AEP
 
 
 
 
Generation
 
Corporate
 
 
 
 
 
 
 
 
 
 
Integrated
 
Distribution
Transmission
AEP River
 
and
and Other
Reconciling
 
 
 
 
 
 
Utilities
 
Utilities
Holdco
Operations
 
Marketing
(a)
 Adjustments
 
Consolidated
 
 
 
 
(in millions)
 Year Ended December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
External Customers
 
$
 8,785 
 
$
 4,659 
 
$
 7 
 
$
 647 
 
$
 882 
 
$
 25 
 
$
 (60)
(b)
 
$
 14,945 
 
 
Other Operating Segments
 
 
 633 
 
 
 159 
 
 
 17 
 
 
 20 
 
 
 2,585 
 
 
 58 
 
 
 (3,472)
 
 
 
 - 
Total Revenues
 
$
 9,418 
 
$
 4,818 
 
$
 24 
 
$
 667 
 
$
 3,467 
 
$
 83 
 
$
 (3,532)
 
 
$
 14,945 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Asset Impairments and Other
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Related Charges
 
$
 13 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 287 
 
$
 - 
 
$
 - 
 
 
$
 300 
Depreciation and Amortization
 
 
 873 
 
 
 561 
 
 
 3 
 
 
 29 
 
 
 349 
 
 
 - 
 
 
 (33)
(c)
 
 
 1,782 
Interest Income
 
 
 5 
 
 
 4 
 
 
 - 
 
 
 - 
 
 
 1 
 
 
 22 
 
 
 (24)
 
 
 
 8 
Carrying Costs Income
 
 
 28 
 
 
 24 
 
 
 1 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
 53 
Interest Expense
 
 
 520 
 
 
 291 
 
 
 3 
 
 
 17 
 
 
 83 
 
 
 112 
 
 
 (38)
(c)
 
 
 988 
Income Tax Expense
 
 
 345 
 
 
 201 
 
 
 17 
 
 
 7 
 
 
 15 
 
 
 19 
 
 
 - 
 
 
 
 604 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss)
 
 
 803 
 
 
 389 
 
 
 43 
 
 
 15 
 
 
 100 
 
 
 (88)
 
 
 - 
 
 
 
 1,262 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gross Property Additions
 
 
 1,801 
 
 
 664 
 
 
 392 
 
 
 31 
 
 
 249 
 
 
 2 
 
 
 (20)
 
 
 
 3,119 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


 
111

 



 
 
 
 
 
 
 
Transmission
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Vertically
 
and
 
AEP
 
 
 
 
Generation
 
Corporate
 
 
 
 
 
 
 
 
 
 
Integrated
 
Distribution
Transmission
AEP River
 
and
and Other
Reconciling
 
 
 
 
 
 
Utilities
 
Utilities
Holdco
Operations
 
Marketing
(a)
 Adjustments
 
Consolidated
 
 
 
 
(in millions)
 Year Ended December 31, 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
External Customers
 
$
 8,942 
 
$
 4,982 
 
$
 3 
 
$
 697 
 
$
 563 
 
$
 24 
 
$
 (95)
(b)
 
$
 15,116 
 
 
Other Operating Segments
 
 
 760 
 
 
 174 
 
 
 5 
 
 
 19 
 
 
 3,331 
 
 
 59 
 
 
 (4,348)
 
 
 
 - 
Total Revenues
 
$
 9,702 
 
$
 5,156 
 
$
 8 
 
$
 716 
 
$
 3,894 
 
$
 83 
 
$
 (4,443)
 
 
$
 15,116 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Asset Impairments and Other
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Related Charges
 
$
 49 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 90 
 
$
 - 
 
$
 - 
 
 
$
 139 
Depreciation and Amortization
 
 
 785 
 
 
 549 
 
 
 - 
 
 
 28 
 
 
 304 
 
 
 2 
 
 
 (13)
(c)
 
 
 1,655 
Interest Income
 
 
 13 
 
 
 7 
 
 
 - 
 
 
 - 
 
 
 4 
 
 
 22 
 
 
 (19)
 
 
 
 27 
Carrying Costs Income
 
 
 17 
 
 
 376 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
 393 
Interest Expense
 
 
 514 
 
 
 293 
 
 
 1 
 
 
 17 
 
 
 87 
 
 
 56 
 
 
 (35)
(c)
 
 
 933 
Income Tax Expense
 
 
 312 
 
 
 220 
 
 
 2 
 
 
 24 
 
 
 166 
 
 
 94 
 
 
 - 
 
 
 
 818 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income (Loss) Before
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Extraordinary Item
 
$
 710 
 
$
 404 
 
$
 30 
 
$
 45 
 
$
 439 
 
$
 (52)
 
$
 - 
 
 
$
 1,576 
Extraordinary Item, Net of Tax
 
 
 - 
 
 
 373 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
 373 
Net Income (Loss)
 
$
 710 
 
$
 777 
 
$
 30 
 
$
 45 
 
$
 439 
 
$
 (52)
 
$
 - 
 
 
$
 1,949 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gross Property Additions
 
$
 1,733 
 
$
 544 
 
$
 263 
 
$
 18 
 
$
 156 
 
$
 219 
 
$
 (31)
 
 
$
 2,902 
 
 
 
 
 
 
 
 
Transmission
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Vertically
 
and
 
AEP
 
 
 
 
Generation
 
Corporate
 
Reconciling
 
 
 
 
 
 
 
 
Integrated
 
Distribution
 
Transmission
 
AEP River
 
and
 
and Other
 
 Adjustments
 
 
 
 
 
 
 
 
Utilities
 
Utilities
 
Holdco
 
Operations
 
Marketing
 
(a)
 
(c)
 
 
Consolidated
 
 
 
 
 
(in millions)
 
December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equipment
 
$
 37,545 
 
 12,143 
 
$
 1,636 
 
$
 638 
 
$
 8,277 
 
$
 315 
 
$
 (269)
 
 
$
 60,285 
 
Accumulated Depreciation and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amortization
 
 
 12,250 
 
 
 3,342 
 
 
 10 
 
 
 189 
 
 
 3,409 
 
 
 173 
 
 
 (85)
 
 
 
 19,288 
 
Total Property, Plant and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equipment - Net
 
$
 25,295 
 
 8,801 
 
$
 1,626 
 
$
 449 
 
$
 4,868 
 
$
 142 
 
$
 (184)
 
 
$
 40,997 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
 32,791 
 
 14,165 
 
$
 2,245 
 
$
 673 
 
$
 6,426 
 
$
 19,645 
 
$
 (19,531)
(d) 
 
$
 56,414 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Investments in Equity Method
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Investees
 
 
 24 
 
 
 - 
 
 
 480 
 
 
 54 
 
 
 - 
 
 
 11 
 
 
 - 
 
 
 
 569 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Transmission
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Vertically
 
and
 
AEP
 
 
 
Generation
 
Corporate
 
Reconciling
 
 
 
 
 
 
 
 
 
Integrated
 
Distribution
 
Transmission
 
AEP River
 
and
 
and Other
 
 Adjustments
 
 
 
 
 
 
 
 
Utilities
 
Utilities
 
Holdco
 
Operations
 
Marketing
 
(a)
 
(c)
 
 
Consolidated
 
 
 
 
 
(in millions)
 
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equipment
 
$
 36,066 
 
 11,461 
 
$
 748 
 
$
 636 
 
$
 8,529 
 
$
 280 
 
$
 (266)
 
 
$
 57,454 
 
Accumulated Depreciation and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amortization
 
 
 11,733 
 
 
 3,232 
 
 
 4 
 
 
 161 
 
 
 3,465 
 
 
 168 
 
 
 (72)
 
 
 
 18,691 
 
Total Property, Plant and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equipment - Net
 
$
 24,333 
 
 8,229 
 
$
 744 
 
$
 475 
 
$
 5,064 
 
$
 112 
 
$
 (194)
 
 
$
 38,763 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
 32,008 
 
 13,516 
 
$
 1,216 
 
$
 670 
 
$
 6,664 
 
$
 19,179 
 
$
 (18,886)
(d) 
 
$
 54,367 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Investments in Equity Method
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Investees
 
 
 24 
 
 
 - 
 
 
 393 
 
 
 43 
 
 
 - 
 
 
 5 
 
 
 - 
 
 
 
 465 
 

(a)
Corporate and Other includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
(b)
Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation.
(c)
Includes eliminations due to an intercompany capital lease.
(d)
Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP's investments in subsidiary companies.

 
112

 


10.   DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

We are exposed to certain market risks as a major power producer and marketer of wholesale electricity, natural gas, coal and emission allowances.  These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk.  These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.  We manage these risks using derivative instruments.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

Our strategy surrounding the use of derivative instruments primarily focuses on managing our risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies.  Our risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which we transact.  To accomplish our objectives, we primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options.  Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.”  Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

We enter into power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with our energy business.  We enter into interest rate derivative contracts in order to manage the interest rate exposure associated with our commodity portfolio.  For disclosure purposes, such risks are grouped as “Commodity,” as they are related to energy risk management activities.  We also engage in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies.  For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.”  The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors.

The following table represents the gross notional volume of our outstanding derivative contracts as of December 31, 2013 and 2012:

Notional Volume of Derivative Instruments
 
 
 
 
 
 
 
 
 
 
 
 
 
Volume
 
 
 
 
 
 
December 31,
 
Unit of
Primary Risk Exposure
 
 
2013 
 
 
2012 
 
Measure
 
 
 
(in millions)
 
Commodity:
 
 
 
 
 
 
 
 
 
Power
 
 
 406 
 
 
 498 
 
MWhs
 
Coal
 
 
 4 
 
 
 10 
 
Tons
 
Natural Gas
 
 
 127 
 
 
 147 
 
MMBtus
 
Heating Oil and Gasoline
 
 
 6 
 
 
 6 
 
Gallons
 
Interest Rate
 
$
 191 
 
$
 235 
 
USD
 
 
 
 
 
 
 
 
 
 
Interest Rate and Foreign Currency
 
$
 820 
 
$
 1,199 
 
USD

Fair Value Hedging Strategies

We enter into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt.  Certain interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our fixed-rate debt to a floating rate.  Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.
 
 
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Cash Flow Hedging Strategies

We enter into and designate as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities.  We monitor the potential impacts of commodity price changes and, where appropriate, enter into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases.  We do not hedge all commodity price risk.

Our vehicle fleet and barge operations are exposed to gasoline and diesel fuel price volatility.  We enter into financial heating oil and gasoline derivative contracts in order to mitigate price risk of our future fuel purchases.  For disclosure purposes, these contracts are included with other hedging activities as “Commodity.”  We do not hedge all fuel price risk.

We enter into a variety of interest rate derivative transactions in order to manage interest rate risk exposure.  Some interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our floating-rate debt to a fixed rate.  We also enter into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt.  Our forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures.  We do not hedge all interest rate exposure.

At times, we are exposed to foreign currency exchange rate risks primarily when we purchase certain fixed assets from foreign suppliers.  In accordance with our risk management policy, we may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar.  We do not hedge all foreign currency exposure.
 
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS
 
The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value.  The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes.  If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions.  In order to determine the relevant fair values of our derivative instruments, we also apply valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due.  Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions.  Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts.  Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles.  Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with our estimates of current market consensus for forward prices in the current period.  This is particularly true for longer term contracts.  Cash flows may vary based on market conditions, margin requirements and the timing of settlement of our risk management contracts.

According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral.  For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the December 31, 2013 and 2012 balance sheets, we netted $4 million and $7 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $13 million and $50 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.


 
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The following tables represent the gross fair value impact of our derivative activity on the balance sheets as of December 31, 2013 and 2012:

Fair Value of Derivative Instruments
December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Risk Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in millions)
Current Risk Management Assets
 
$
 347 
 
$
 12 
 
$
 4 
 
$
 363 
 
$
 (203)
 
$
 160 
Long-term Risk Management Assets
 
 
 368 
 
 
 3 
 
 
 - 
 
 
 371 
 
 
 (74)
 
 
 297 
Total Assets
 
 
 715 
 
 
 15 
 
 
 4 
 
 
 734 
 
 
 (277)
 
 
 457 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
 292 
 
 
 11 
 
 
 1 
 
 
 304 
 
 
 (214)
 
 
 90 
Long-term Risk Management Liabilities
 
 
 237 
 
 
 3 
 
 
 15 
 
 
 255 
 
 
 (78)
 
 
 177 
Total Liabilities
 
 
 529 
 
 
 14 
 
 
 16 
 
 
 559 
 
 
 (292)
 
 
 267 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
 186 
 
$
 1 
 
$
 (12)
 
$
 175 
 
$
 15 
 
$
 190 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Risk Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in millions)
Current Risk Management Assets
 
$
 589 
 
$
 32 
 
$
 3 
 
$
 624 
 
$
 (433)
 
$
 191 
Long-term Risk Management Assets
 
 
 528 
 
 
 5 
 
 
 1 
 
 
 534 
 
 
 (166)
 
 
 368 
Total Assets
 
 
 1,117 
 
 
 37 
 
 
 4 
 
 
 1,158 
 
 
 (599)
 
 
 559 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
 546 
 
 
 43 
 
 
 35 
 
 
 624 
 
 
 (469)
 
 
 155 
Long-term Risk Management Liabilities
 
 
 383 
 
 
 6 
 
 
 6 
 
 
 395 
 
 
 (181)
 
 
 214 
Total Liabilities
 
 
 929 
 
 
 49 
 
 
 41 
 
 
 1,019 
 
 
 (650)
 
 
 369 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
 188 
 
$
 (12)
 
$
 (37)
 
$
 139 
 
$
 51 
 
$
 190 

(a)
Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."
(b)
Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging."  Amounts also include de-designated risk management contracts.
(c)
There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.


 
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The table below presents our activity of derivative risk management contracts for the years ended December 31, 2013, 2012 and 2011:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
Location of Gain (Loss)
 
2013 
 
2012 
 
2011 
 
 
(in millions)
Vertically Integrated Utilities Revenues
 
$
 15 
 
$
 10 
 
$
 18 
Generation & Marketing Revenues
 
 
 49 
 
 
 50 
 
 
 48 
Regulatory Assets (a)
 
 
 (2)
 
 
 (43)
 
 
 (22)
Regulatory Liabilities (a)
 
 
 (5)
 
 
 8 
 
 
 (3)
Total Gain (Loss) on Risk Management Contracts
 
$
 57 
 
$
 25 
 
$
 41 
 
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

       
Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.”  Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis.

Our accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship.  Depending on the exposure, we designate a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes.  Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income.  Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances.  However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

Accounting for Fair Value Hedging Strategies

For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change.

We record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income.  During 2013, we recognized a loss of $10 million on our hedging instruments and an offsetting gain of $10 million on our long-term debt.  During 2012, the fair value changes for both our hedging instruments and hedged long-term debt were immaterial.  During 2011, we recognized a gain of $3 million on our hedging instruments and an offsetting loss of $6 million on our long-term debt.  For 2013, 2012 and 2011, hedge ineffectiveness was immaterial.

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income.  We recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).
 
 
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Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the statements of income, or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged.  During 2013, 2012 and 2011, we designated power, coal and natural gas derivatives as cash flow hedges.

We reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the statements of income.  During 2013, 2012 and 2011, we designated heating oil and gasoline derivatives as cash flow hedges.

We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur.  During 2013, 2012 and 2011, we designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.  During 2013, we did not designate any foreign currency derivatives as cash flow hedges.  During 2012 and 2011, we designated foreign currency derivatives as cash flow hedges.

During 2013, 2012 and 2011, hedge ineffectiveness was immaterial or nonexistent for all cash flow hedge strategies disclosed above.

For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges for the years ended December 31, 2013, 2012 and 2011, see Note 3.

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets as of December 31, 2013 and 2012 were:

Impact of Cash Flow Hedges on the Balance Sheet
December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
 
 
 
Commodity
 
Currency
 
Total
 
 
 
 
(in millions)
Hedging Assets (a)
 
$
 7 
 
$
 - 
 
$
 7 
Hedging Liabilities (a)
 
 
 6 
 
 
 2 
 
 
 8 
AOCI Gain (Loss) Net of Tax
 
 
 - 
 
 
 (23)
 
 
 (23)
Portion Expected to be Reclassified to Net
 
 
 
 
 
 
 
 
 
 
Income During the Next Twelve Months
 
 
 - 
 
 
 (4)
 
 
 (4)
 
 
 
 
 
 
 
 
 
 
 
 
Impact of Cash Flow Hedges on the Balance Sheet
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
 
 
 
Commodity
 
Currency
 
Total
 
 
 
 
(in millions)
Hedging Assets (a)
 
$
 24 
 
$
 - 
 
$
 24 
Hedging Liabilities (a)
 
 
 36 
 
 
 37 
 
 
 73 
AOCI Gain (Loss) Net of Tax
 
 
 (8)
 
 
 (30)
 
 
 (38)
Portion Expected to be Reclassified to Net
 
 
 
 
 
 
 
 
 
 
Income During the Next Twelve Months
 
 
 (8)
 
 
 (4)
 
 
 (12)

(a)
Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.
 
 
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The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.  As of December 31, 2013, the maximum length of time that we are hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) our exposure to variability in future cash flows related to forecasted transactions was 44 months.

Credit Risk

We limit credit risk in our wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.  We use Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

When we use standardized master agreements, these agreements may include collateral requirements.  These master agreements facilitate the netting of cash flows associated with a single counterparty.  Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk.  The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds our established threshold.  The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with our credit policy.  In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.

Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, we are obligated to post an additional amount of collateral if our credit ratings decline below investment grade.  The amount of collateral required fluctuates based on market prices and our total exposure.  On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts.  AEP and its subsidiaries have not experienced a downgrade below investment grade.  The following table represents: (a) our fair value of such derivative contracts, (b) the amount of collateral we would have been required to post for all derivative and non-derivative contracts if our credit ratings had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of December 31, 2013 and 2012:

 
 
 
December 31,
 
 
 
2013 
 
2012 
 
 
 
(in millions)
Liabilities for Derivative Contracts with Credit Downgrade Triggers
 
$
 3 
 
$
 7 
Amount of Collateral AEP Subsidiaries Would Have Been
 
 
 
 
 
 
 
Required to Post
 
 
 33 
 
 
 32 
Amount Attributable to RTO and ISO Activities
 
 
 28 
 
 
 31 

In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable.  These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million.  On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts.  The following table represents: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral we have posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering our contractual netting arrangements as of December 31, 2013 and 2012:

 
 
December 31,
 
 
2013 
 
2012 
 
 
(in millions)
Liabilities for Contracts with Cross Default Provisions Prior to Contractual
 
 
 
 
 
 
   Netting Arrangements
 
$
 293 
 
$
 469 
Amount of Cash Collateral Posted
 
 
 1 
 
 
 8 
Additional Settlement Liability if Cross Default Provision is Triggered
 
 
 235 
 
 
 328 

 
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11.   FAIR VALUE MEASUREMENTS

Fair Value Measurements of Long-term Debt

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs.  These instruments are not marked-to-market.  The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange.

The book values and fair values of Long-term Debt as of December 31, 2013 and 2012 are summarized in the following table:

 
 
December 31,
 
 
2013 
 
2012 
 
 
Book Value
 
Fair Value
 
Book Value
 
Fair Value
 
 
(in millions)
Long-term Debt
 
$
 18,377 
 
$
 19,672 
 
$
 17,757 
 
$
 20,907 

Fair Value Measurements of Other Temporary Investments

Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and Securities Available for Sale, including marketable securities that we intend to hold for less than one year and investments by our protected cell of EIS.  See “Other Temporary Investments” section of Note 1.

The following is a summary of Other Temporary Investments:

 
 
 
 
December 31, 2013
 
 
 
 
 
 
Gross
 
Gross
 
Estimated
 
 
 
 
 
 
 Unrealized
 
Unrealized
 
 Fair
Other Temporary Investments
 
Cost
 
Gains
 
Losses
 
Value
 
 
 
 
(in millions)
Restricted Cash (a)
 
$
 250 
 
$
 - 
 
$
 - 
 
$
 250 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
Mutual Funds
 
 
 80 
 
 
 - 
 
 
 - 
 
 
 80 
Equity Securities - Mutual Funds
 
 
 12 
 
 
 11 
 
 
 - 
 
 
 23 
Total Other Temporary Investments
 
$
 342 
 
$
 11 
 
$
 - 
 
$
 353 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2012
 
 
 
 
 
 
Gross
 
Gross
 
Estimated
 
 
 
 
 
 
 Unrealized
 
Unrealized
 
 Fair
Other Temporary Investments
 
Cost
 
Gains
 
Losses
 
Value
 
 
 
 
(in millions)
Restricted Cash (a)
 
$
 241 
 
$
 - 
 
$
 - 
 
$
 241 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
Mutual Funds
 
 
 65 
 
 
 2 
 
 
 - 
 
 
 67 
Equity Securities - Mutual Funds
 
 
 10 
 
 
 6 
 
 
 - 
 
 
 16 
Total Other Temporary Investments
 
$
 316 
 
$
 8 
 
$
 - 
 
$
 324 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Primarily represents amounts held for the repayment of debt.


 
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The following table provides the activity for our fixed income and equity securities within Other Temporary Investments for the years ended December 31, 2013, 2012 and 2011:

 
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
(in millions)
Proceeds from Investment Sales
$
 - 
 
$
 - 
 
$
 268 
Purchases of Investments
 
 17 
 
 
 2 
 
 
 154 
Gross Realized Gains on Investment Sales
 
 - 
 
 
 - 
 
 
 4 
Gross Realized Losses on Investment Sales
 
 - 
 
 
 - 
 
 
 - 

As of December 31, 2013 and 2012, we had no Other Temporary Investments with an unrealized loss position.  As of December 31, 2013, fixed income securities were primarily debt based mutual funds with short and intermediate maturities.  Mutual funds may be sold and do not contain maturity dates.

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value.  See “Nuclear Trust Funds” section of Note 1.

The following is a summary of nuclear trust fund investments as of December 31, 2013 and December 31, 2012:

 
 
 
 
December 31,
 
 
 
 
2013 
 
2012 
 
 
 
 
Estimated
 
Gross
 
Other-Than-
 
Estimated
 
Gross
 
Other-Than-
 
 
 
Fair
Unrealized
Temporary
Fair
Unrealized
Temporary
 
 
 
Value
Gains
Impairments
Value
Gains
Impairments
 
 
 
 
(in millions)
Cash and Cash Equivalents
 
$
 19 
 
$
 - 
 
$
 - 
 
$
 17 
 
$
 - 
 
$
 - 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 
 609 
 
 
 26 
 
 
 (4)
 
 
 648 
 
 
 58 
 
 
 (1)
 
Corporate Debt
 
 
 37 
 
 
 2 
 
 
 (1)
 
 
 35 
 
 
 5 
 
 
 (1)
 
State and Local Government
 
 
 255 
 
 
 1 
 
 
 - 
 
 
 270 
 
 
 1 
 
 
 (1)
 
 
Subtotal Fixed Income Securities
 
 
 901 
 
 
 29 
 
 
 (5)
 
 
 953 
 
 
 64 
 
 
 (3)
Equity Securities - Domestic
 
 
 1,012 
 
 
 506 
 
 
 (82)
 
 
 736 
 
 
 285 
 
 
 (77)
Spent Nuclear Fuel and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decommissioning Trusts
 
$
 1,932 
 
$
 535 
 
$
 (87)
 
$
 1,706 
 
$
 349 
 
$
 (80)

The following table provides the securities activity within the decommissioning and SNF trusts for the years ended December 31, 2013, 2012 and 2011:

 
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
(in millions)
Proceeds from Investment Sales
$
 858 
 
$
 988 
 
$
 1,111 
Purchases of Investments
 
 910 
 
 
 1,045 
 
 
 1,167 
Gross Realized Gains on Investment Sales
 
 18 
 
 
 25 
 
 
 33 
Gross Realized Losses on Investment Sales
 
 8 
 
 
 9 
 
 
 22 

The adjusted cost of fixed income securities was $872 million and $889 million as of December 31, 2013 and 2012, respectively.  The adjusted cost of equity securities was $506 million and $451 million as of December 31, 2013 and 2012, respectively.


 
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The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2013 was as follows:

 
Fair Value of
 
Fixed Income
 
Securities
 
(in millions)
Within 1 year
$
 79 
1 year – 5 years
 
 384 
5 years – 10 years
 
 188 
After 10 years
 
 250 
Total
$
 901 


 
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Fair Value Measurements of Financial Assets and Liabilities

For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1.

The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 and 2012.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in our valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
$
 16 
 
$
 1 
 
$
 - 
 
$
 101 
 
$
 118 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Temporary Investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Restricted Cash (a)
 
 231 
 
 
 8 
 
 
 - 
 
 
 11 
 
 
 250 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mutual Funds
 
 80 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 80 
Equity Securities - Mutual Funds (b)
 
 23 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 23 
Total Other Temporary Investments
 
 334 
 
 
 8 
 
 
 - 
 
 
 11 
 
 
 353 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (c) (d)
 
 22 
 
 
 549 
 
 
 142 
 
 
 (273)
 
 
 440 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (c)
 
 - 
 
 
 15 
 
 
 - 
 
 
 (8)
 
 
 7 
Fair Value Hedges
 
 - 
 
 
 1 
 
 
 - 
 
 
 3 
 
 
 4 
De-designated Risk Management Contracts (e)
 
 - 
 
 
 - 
 
 
 - 
 
 
 6 
 
 
 6 
Total Risk Management Assets
 
 22 
 
 
 565 
 
 
 142 
 
 
 (272)
 
 
 457 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (f)
 
 8 
 
 
 - 
 
 
 - 
 
 
 11 
 
 
 19 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 - 
 
 
 609 
 
 
 - 
 
 
 - 
 
 
 609 
 
Corporate Debt
 
 - 
 
 
 37 
 
 
 - 
 
 
 - 
 
 
 37 
 
State and Local Government
 
 - 
 
 
 255 
 
 
 - 
 
 
 - 
 
 
 255 
 
 
Subtotal Fixed Income Securities
 
 - 
 
 
 901 
 
 
 - 
 
 
 - 
 
 
 901 
Equity Securities - Domestic (b)
 
 1,012 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,012 
Total Spent Nuclear Fuel and Decommissioning Trusts
 
 1,020 
 
 
 901 
 
 
 - 
 
 
 11 
 
 
 1,932 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 1,392 
 
$
 1,475 
 
$
 142 
 
$
 (149)
 
$
 2,860 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (c) (d)
$
 30 
 
$
 475 
 
$
 22 
 
$
 (282)
 
$
 245 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (c)
 
 - 
 
 
 11 
 
 
 3 
 
 
 (8)
 
 
 6 
 
Interest Rate/Foreign Currency Hedges
 
 - 
 
 
 2 
 
 
 - 
 
 
 - 
 
 
 2 
Fair Value Hedges
 
 - 
 
 
 11 
 
 
 - 
 
 
 3 
 
 
 14 
Total Risk Management Liabilities
$
 30 
 
$
 499 
 
$
 25 
 
$
 (287)
 
$
 267 

 
122

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
$
 6 
 
$
 1 
 
$
 - 
 
$
 272 
 
$
 279 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Temporary Investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Restricted Cash (a)
 
 227 
 
 
 5 
 
 
 - 
 
 
 9 
 
 
 241 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mutual Funds
 
 67 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 67 
Equity Securities - Mutual Funds (b)
 
 16 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 16 
Total Other Temporary Investments
 
 310 
 
 
 5 
 
 
 - 
 
 
 9 
 
 
 324 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (c) (g)
 
 47 
 
 
 938 
 
 
 131 
 
 
 (599)
 
 
 517 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (c)
 
 8 
 
 
 28 
 
 
 - 
 
 
 (12)
 
 
 24 
Fair Value Hedges
 
 - 
 
 
 2 
 
 
 - 
 
 
 2 
 
 
 4 
De-designated Risk Management Contracts (e)
 
 - 
 
 
 - 
 
 
 - 
 
 
 14 
 
 
 14 
Total Risk Management Assets
 
 55 
 
 
 968 
 
 
 131 
 
 
 (595)
 
 
 559 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (f)
 
 7 
 
 
 - 
 
 
 - 
 
 
 10 
 
 
 17 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 - 
 
 
 648 
 
 
 - 
 
 
 - 
 
 
 648 
 
Corporate Debt
 
 - 
 
 
 35 
 
 
 - 
 
 
 - 
 
 
 35 
 
State and Local Government
 
 - 
 
 
 270 
 
 
 - 
 
 
 - 
 
 
 270 
 
 
Subtotal Fixed Income Securities
 
 - 
 
 
 953 
 
 
 - 
 
 
 - 
 
 
 953 
Equity Securities - Domestic (b)
 
 736 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 736 
Total Spent Nuclear Fuel and Decommissioning Trusts
 
 743 
 
 
 953 
 
 
 - 
 
 
 10 
 
 
 1,706 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 1,114 
 
$
 1,927 
 
$
 131 
 
$
 (304)
 
$
 2,868 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (c) (g)
$
 45 
 
$
 838 
 
$
 45 
 
$
 (636)
 
$
 292 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (c)
 
 - 
 
 
 48 
 
 
 - 
 
 
 (12)
 
 
 36 
 
Interest Rate/Foreign Currency Hedges
 
 - 
 
 
 37 
 
 
 - 
 
 
 - 
 
 
 37 
Fair Value Hedges
 
 - 
 
 
 2 
 
 
 - 
 
 
 2 
 
 
 4 
Total Risk Management Liabilities
$
 45 
 
$
 925 
 
$
 45 
 
$
 (646)
 
$
 369 

(a)
Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties.  Level 1 and Level 2 amounts primarily represent investments in money market funds.
(b)
Amounts represent publicly traded equity securities and equity-based mutual funds.
(c)
Amounts in "Other" column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for "Derivatives and Hedging."
(d)
The December 31, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $4 million in 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019;  Level 2 matures $25 million in 2014, $37 million in periods 2015-2017, $7 million in periods 2018-2019 and $5 million in periods 2020-2030;  Level 3 matures $27 million in 2014, $60 million in periods 2015-2017, $14 million in periods 2018-2019 and $19 million in periods 2020-2030.  Risk management commodity contracts are substantially comprised of power contracts.
(e)
Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for "Derivatives and Hedging."  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This MTM value will be amortized into revenues over the remaining life of the contracts.
(f)
Amounts in "Other" column primarily represent accrued interest receivables from financial institutions.  Level 2 amounts primarily represent investments in money market funds.
(g)
The December 31, 2012 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $9 million in 2013, $(3) million in periods 2014-2016 and $(4) million in periods 2017-2018;  Level 2 matures $16 million in 2013, $61 million in periods 2014-2016, $16 million in periods 2017-2018 and $7 million in periods 2019-2030;  Level 3 matures $18 million in 2013, $31 million in periods 2014-2016, $13 million in periods 2017-2018 and $24 million in periods 2019-2030.  Risk management commodity contracts are substantially comprised of power contracts.
 
 
123

 
There have been no transfers between Level 1 and Level 2 during the years ended December 31, 2013, 2012 and 2011.
 
The following tables set forth a reconciliation of changes in the fair value of net trading derivatives and other investments classified as Level 3 in the fair value hierarchy:

 
 
 
Net Risk Management
Year Ended December 31, 2013
 
Assets (Liabilities)
 
 
 
(in millions)
Balance as of December 31, 2012
 
$
 86 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
 
 (9)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
 
 
 
 
Relating to Assets Still Held at the Reporting Date (a)
 
 
 37 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
 
 
 (3)
Purchases, Issuances and Settlements (c)
 
 
 (16)
Transfers into Level 3 (d) (e)
 
 
 19 
Transfers out of Level 3 (e) (f)
 
 
 (4)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
 
 7 
Balance as of December 31, 2013
 
$
 117 
 
 
 
 
 
 
 
 
Net Risk Management
Year Ended December 31, 2012
 
Assets (Liabilities)
 
 
 
(in millions)
Balance as of December 31, 2011
 
$
 69 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
 
 (15)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
 
 
 
 
Relating to Assets Still Held at the Reporting Date (a)
 
 
 29 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
 
 
 - 
Purchases, Issuances and Settlements (c)
 
 
 32 
Transfers into Level 3 (d) (e)
 
 
 1 
Transfers out of Level 3 (e) (f)
 
 
 (35)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
 
 5 
Balance as of December 31, 2012
 
$
 86 
 
 
 
 
 
 
 
 
Net Risk Management
Year Ended December 31, 2011
 
Assets (Liabilities)
 
 
 
(in millions)
Balance as of December 31, 2010
 
$
 85 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
 
 (10)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
 
 
 
 
Relating to Assets Still Held at the Reporting Date (a)
 
 
 9 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
 
 
 - 
Purchases, Issuances and Settlements (c)
 
 
 (3)
Transfers into Level 3 (d) (e)
 
 
 13 
Transfers out of Level 3 (e) (f)
 
 
 (12)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
 
 (13)
Balance as of December 31, 2011
 
$
 69 

(a)
Included in revenues on the statements of income.
(b)
Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)
Represents the settlement of risk management commodity contracts for the reporting period.
(d)
Represents existing assets or liabilities that were previously categorized as Level 2.
(e)
Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
(f)
Represents existing assets or liabilities that were previously categorized as Level 3.
(g)
Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These net gains (losses) are recorded as regulatory liabilities/assets.

 
124

 
The following tables quantify the significant unobservable inputs used in developing the fair value of our Level 3 positions as of December 31, 2013 and 2012:
 
 
Significant Unobservable Inputs
December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value
 
Valuation
 
Significant
 
Input/Range
 
 
Assets
 
Liabilities
 
Technique
 
Unobservable Input
 
Low
 
High
 
 
(in millions)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
 
$
 132 
 
$
 22 
 
Discounted Cash Flow
 
Forward Market Price (a) 
 
 11.42 
 
 120.72 
 
 
 
 
 
 
 
 
 
 
Counterparty Credit Risk (b) 
 
 
316 
FTRs
 
 
 10 
 
 
 3 
 
Discounted Cash Flow
 
Forward Market Price (a) 
 
 
 (5.10)
 
 
 10.44 
Total
 
$
142 
 
$
25 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Significant Unobservable Inputs
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value
 
Valuation
 
Significant
 
Input/Range
 
 
Assets
 
Liabilities
 
Technique
 
Unobservable Input
 
Low
 
High
 
 
(in millions)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
 
$
 124 
 
$
 38 
 
Discounted Cash Flow
 
Forward Market Price (a) 
 
 9.40 
 
 111.97 
 
 
 
 
 
 
 
 
 
 
Counterparty Credit Risk (b) 
 
 
397 
FTRs
 
 
 7 
 
 
 7 
 
Discounted Cash Flow
 
Forward Market Price (a) 
 
 
 (3.21)
 
 
 14.79 
Total
 
$
131 
 
$
45 
 
 
 
 
 
 
 
 
 
 

(a)   Represents market prices in dollars per MWh.
(b)   Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points.

12.   INCOME TAXES

The details of our consolidated income taxes before extraordinary item as reported are as follows:

 
 
 
 
Years Ended December 31,
 
 
 
 
2013 
 
2012 
 
2011 
 
 
 
 
(in millions)
Federal:
 
 
 
 
 
 
 
 
 
 
 
Current
 
$
 (45)
 
$
 (52)
 
$
 20 
 
 
Deferred
 
 
 676 
 
 
 698 
 
 
 786 
Total Federal
 
 
 631 
 
 
 646 
 
 
 806 
 
 
 
 
 
 
 
 
 
 
State and Local:
 
 
 
 
 
 
 
 
 
 
 
Current
 
 
 29 
 
 
 35 
 
 
 37 
 
 
Deferred
 
 
 24 
 
 
 (77)
 
 
 (25)
Total State and Local
 
 
 53 
 
 
 (42)
 
 
 12 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
$
 684 
 
$
 604 
 
$
 818 


 
125

 


The following is a reconciliation of our consolidated difference between the amount of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported:

 
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
(in millions)
Net Income
$
 1,484 
 
$
 1,262 
 
$
 1,949 
Extraordinary Item, Net of Tax of $112 million in 2011
 
 - 
 
 
 - 
 
 
 (373)
Income Before Extraordinary Item
 
 1,484 
 
 
 1,262 
 
 
 1,576 
Income Tax Expense
 
 684 
 
 
 604 
 
 
 818 
Pretax Income
$
 2,168 
 
$
 1,866 
 
$
 2,394 
 
 
 
 
 
 
 
 
 
Income Taxes on Pretax Income at Statutory Rate (35%)
$
 759 
 
$
 653 
 
$
 838 
Increase (Decrease) in Income Taxes resulting from the following items:
 
 
 
 
 
 
 
 
 
 
Depreciation
 
 47 
 
 
 39 
 
 
 41 
 
 
Investment Tax Credits, Net
 
 (14)
 
 
 (14)
 
 
 (15)
 
 
Energy Production Credits
 
 - 
 
 
 - 
 
 
 (18)
 
 
State and Local Income Taxes, Net
 
 29 
 
 
 (33)
 
 
 (22)
 
 
Removal Costs
 
 (21)
 
 
 (18)
 
 
 (20)
 
 
AFUDC
 
 (31)
 
 
 (39)
 
 
 (42)
 
 
Valuation Allowance
 
 5 
 
 
 6 
 
 
 86 
 
 
U.K. Windfall Tax
 
 (80)
 
 
 15 
 
 
 - 
 
 
Other
 
 (10)
 
 
 (5)
 
 
 (30)
Income Tax Expense
$
 684 
 
$
 604 
 
$
 818 
 
 
 
 
 
 
 
 
 
Effective Income Tax Rate
 
 31.5 
%
 
 
 32.4 
%
 
 
 34.2 
%

The following table shows elements of the net deferred tax liability and significant temporary differences:

 
 
December 31,
 
 
2013 
 
2012 
 
 
(in millions)
Deferred Tax Assets
 
$
 2,900 
 
$
 2,900 
Deferred Tax Liabilities
 
 
 (13,088)
 
 
 (12,098)
Net Deferred Tax Liabilities
 
$
 (10,188)
 
$
 (9,198)
 
 
 
 
 
 
 
Property Related Temporary Differences
 
$
 (7,508)
 
$
 (6,752)
Amounts Due from Customers for Future Federal Income Taxes
 
 
 (273)
 
 
 (289)
Deferred State Income Taxes
 
 
 (765)
 
 
 (683)
Securitized Assets
 
 
 (870)
 
 
 (780)
Regulatory Assets
 
 
 (609)
 
 
 (781)
Deferred Income Taxes on Other Comprehensive Loss
 
 
 66 
 
 
 184 
Accrued Nuclear Decommissioning
 
 
 (554)
 
 
 (475)
Net Operating Loss Carryforward
 
 
 233 
 
 
 194 
Tax Credit Carryforward
 
 
 109 
 
 
 104 
Valuation Allowance
 
 
 (97)
 
 
 (92)
All Other, Net
 
 
 80 
 
 
 172 
Net Deferred Tax Liabilities
 
$
 (10,188)
 
$
 (9,198)

AEP System Tax Allocation Agreement

We, along with our subsidiaries, file a consolidated federal income tax return.  The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense.  The tax benefit of the Parent is allocated to our subsidiaries with taxable income.  With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
 
 
126

 

Federal and State Income Tax Audit Status

We are no longer subject to U.S. federal examination for years before 2011.  We completed the examination of the years 2007 and 2008 in April 2011 and settled all outstanding issues on appeal for the years 2001 through 2006 in October 2011.  The settlements did not materially impact net income, cash flows or financial condition.  The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013.  Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters.  In addition, we accrue interest on these uncertain tax positions.  We are not aware of any issues for open tax years that upon final resolution are expected to materially impact net income.

We, along with our subsidiaries, file income tax returns in various state, local and foreign jurisdictions.  These taxing authorities routinely examine our tax returns and we are currently under examination in several state and local jurisdictions.  However, it is possible that we have filed tax returns with positions that may be challenged by these tax authorities.  We believe that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and the ultimate resolution of these audits will not materially impact net income.  We are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009.

Net Income Tax Operating Loss Carryforward

In 2012 and 2011, we recognized federal net income tax operating losses of $366 million and $226 million, respectively, driven primarily by bonus depreciation, pension plan contributions and other book-versus-tax temporary differences.  We also had state net income tax operating loss carryforwards as indicated in the table below.

 
 
State Net Income
 
 
 
 
Tax Operating
 
 
 
 
Loss
 
Year of
State
 
Carryforward
 
Expiration
 
 
(in millions)
 
 
Indiana
 
$
 50 
 
2033 
Louisiana
 
 
 428 
 
2028 
Oklahoma
 
 
 241 
 
2033 
Tennessee
 
 
 9 
 
2026 
Virginia
 
 
 301 
 
2031 
West Virginia
 
 
 725 
 
2032 

As a result, we recognized deferred federal, state and local income tax benefits in 2012 and 2011.  As of December 31, 2013, we have $156 million of unrealized federal net operating loss carryforward tax benefits.  We anticipate future taxable income will be sufficient to realize the remaining net income tax operating loss tax benefits before the federal carryforward expires after 2032.  We also anticipate future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the state carryforward expires for each state.

At the end of 2013 and 2012, we had $121 million of uncertain tax positions netted against the federal net operating loss carryforward tax benefits.

Tax Credit Carryforward

Federal and state net income tax operating losses sustained in 2012, 2011 and 2009, along with lower federal and state taxable income in 2010, resulted in unused federal and state income tax credits.  As of December 31, 2013, we have total federal tax credit carryforwards of $108 million and total state tax credit carryforwards of $98 million, not all of which are subject to an expiration date.  If these credits are not utilized, the federal general business tax credits of $74 million will expire in the years 2028 through 2032 and the state coal tax credits of $29 million will expire in the years 2014 through 2022.

 
127

 

We anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused.  We do not anticipate state taxable income will be sufficient in future periods to realize the tax benefits of all state income tax credits before they expire and we have provided a valuation allowance accordingly.

Valuation Allowance

We assess past results and future operations to estimate and evaluate available positive and negative evidence to determine whether sufficient future taxable income will be generated to use existing deferred tax assets.  A significant piece of objective negative information evaluated was the net income tax operating losses sustained in 2012, 2011 and 2009.  The positive evidence we considered is the history of positive pretax income and the fact that the tax losses resulted from temporary differences that will reverse in future periods.  On the basis of the evaluation of all available positive and negative evidence, as of December 31, 2013, a valuation allowance of $41 million for state tax credits, net of federal tax, and $56 million for an unrealized capital loss has been recorded in order to recognize only the portion of the deferred tax assets that, more likely than not, will be realized.  The amount of the deferred tax assets realizable, however, could be adjusted if estimates of future taxable income during the carryforward period are materially impacted.

For a discussion of the tax implications of the unrealized capital loss resulting from our settlement with BOA and Enron, see “Enron Bankruptcy” section of Note 7.

Uncertain Tax Positions

In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes.  We filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case.  As a result of the favorable U.S. Supreme Court decision, we recognized a tax benefit of $80 million, plus $43 million of pretax interest income in the second quarter of 2013.  The tax benefit and interest income resulted in an increase in net income of $108 million, but did not result in the receipt of cash in 2013.

We recognize interest accruals related to uncertain tax positions in interest income or expense, as applicable, and penalties in Other Operation expense in accordance with the accounting guidance for “Income Taxes.”

The following table shows amounts reported for interest expense, interest income and reversal of prior period interest expense:
 
 

 
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
(in millions)
Interest Expense
$
 1 
 
$
 11 
 
$
Interest Income
 
 51 
 
 
 - 
 
 
22 
Reversal of Prior Period Interest Expense
 
 - 
 
 
 1 
 
 
13 

The following table shows balances for amounts accrued for the receipt of interest and the payment of interest and penalties:

 
December 31,
 
2013 
 
2012 
 
(in millions)
Accrual for Receipt of Interest
$
 43 
 
$
 - 
Accrual for Payment of Interest and Penalties
 
 5 
 
 
 7 


 
128

 


The reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

 
 
2013 
 
2012 
 
2011 
 
 
(in millions)
Balance as of January 1,
 
$
 267 
 
$
 168 
 
$
 219 
Increase - Tax Positions Taken During a Prior Period
 
 
 - 
 
 
 23 
 
 
 51 
Decrease - Tax Positions Taken During a Prior Period
 
 
 (94)
 
 
 (16)
 
 
 (43)
Increase - Tax Positions Taken During the Current Year
 
 
 2 
 
 
 121 
 
 
 10 
Decrease - Tax Positions Taken During the Current Year
 
 
 - 
 
 
 - 
 
 
 - 
Decrease - Settlements with Taxing Authorities
 
 
 - 
 
 
 (25)
 
 
 (31)
Decrease - Lapse of the Applicable Statute of Limitations
 
 
 - 
 
 
 (4)
 
 
 (38)
Balance as of December 31,
 
$
 175 
 
$
 267 
 
$
 168 

The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $87 million, $149 million and $111 million for 2013, 2012 and 2011, respectively.  We believe there will be no significant net increase or decrease in unrecognized tax benefits within 12 months of the reporting date.

Federal Tax Legislation

The American Taxpayer Relief Act of 2012 (the 2012 Act) was enacted in January 2013.  Included in the 2012 Act was a one-year extension of 50% bonus depreciation.  The 2012 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2011.  The enacted provisions will not materially impact net income or financial condition but did have a favorable impact on cash flows in 2013.

Federal Tax Regulations

In 2013, the U.S. Treasury Department issued final and re-proposed regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014.  In addition, the IRS issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry.  The impact of these final regulations is not material to net income, cash flows or financial condition.

State Tax Legislation

Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rate from 8.5% to 6.5%.  The 8.5% Indiana corporate income tax rate will be reduced 0.5% each year beginning after June 30, 2012 with the final reduction occurring in years beginning after June 30, 2015.

In May 2011, Michigan repealed its Business Tax regime and replaced it with a traditional corporate net income tax rate of 6%, effective January 1, 2012.

During the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds.  As a result, the West Virginia corporate income tax rate will be reduced from 7.0% to 6.5% in 2014.  The enacted provisions will not materially impact net income, cash flows or financial condition.


 
129

 


13.   LEASES

Leases of property, plant and equipment are for remaining periods up to 36 years and require payments of related property taxes, maintenance and operating costs.  The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.

Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations.  Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period.  Capital leases for nonregulated property are accounted for as if the assets were owned and financed.  The components of rental costs are as follows:

 
 
Years Ended December 31,
Lease Rental Costs
 
2013 
 
2012 
 
2011 
 
 
(in millions)
Net Lease Expense on Operating Leases
 
$
 327 
 
$
 346 
 
$
 343 
Amortization of Capital Leases
 
 
 74 
 
 
 73 
 
 
 72 
Interest on Capital Leases
 
 
 28 
 
 
 29 
 
 
 32 
Total Lease Rental Costs
 
$
 429 
 
$
 448 
 
$
 447 

The following table shows the property, plant and equipment under capital leases and related obligations recorded on the balance sheets.  Capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on the balance sheets.

 
 
December 31,
Property, Plant and Equipment Under Capital Leases
 
2013 
 
2012 
 
 
(in millions)
Generation
 
$
 103 
 
$
 117 
Other Property, Plant and Equipment
 
 
 627 
 
 
 495 
Total Property, Plant and Equipment Under Capital Leases
 
 
 730 
 
 
 612 
Accumulated Amortization
 
 
 197 
 
 
 173 
Net Property, Plant and Equipment Under Capital Leases
 
$
 533 
 
$
 439 
 
 
 
 
 
 
 
 
Obligations Under Capital Leases
 
 
 
 
 
 
Noncurrent Liability
 
$
 428 
 
$
 375 
Liability Due Within One Year
 
 
 110 
 
 
 74 
Total Obligations Under Capital Leases
 
$
 538 
 
$
 449 

Future minimum lease payments consisted of the following as of December 31, 2013:

 
 
 
 
Noncancelable
Future Minimum Lease Payments
 
Capital Leases
 
Operating Leases
 
 
 
(in millions)
2014 
 
$
 135 
 
$
 288 
2015 
 
 
 111 
 
 
 268 
2016 
 
 
 97 
 
 
 246 
2017 
 
 
 79 
 
 
 230 
2018 
 
 
 44 
 
 
 215 
Later Years
 
 
 215 
 
 
 862 
Total Future Minimum Lease Payments
 
 
 681 
 
$
 2,109 
Less Estimated Interest Element
 
 
 143 
 
 
 
Estimated Present Value of Future Minimum
 
 
 
 
 
 
 
Lease Payments
 
$
 538 
 
 
 


 
130

 


Master Lease Agreements

We lease certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, we are committed to pay the difference between the actual fair value and the residual value guarantee.  Historically, at the end of the lease term, the fair value has been in excess of the unamortized balance.  As of December 31, 2013, the maximum potential loss for these lease agreements was approximately $20 million assuming the fair value of the equipment is zero at the end of the lease term.

Rockport Lease

AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant).  The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors.

The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022.  The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M.  The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note.  The lease term is for 33 years with potential renewal options.  At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant.  AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt.  The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2013 are as follows:

Future Minimum Lease Payments
 
AEGCo
 
I&M
 
 
 
(in millions)
2014 
 
$
 74 
 
$
 74 
2015 
 
 
 74 
 
 
 74 
2016 
 
 
 74 
 
 
 74 
2017 
 
 
 74 
 
 
 74 
2018 
 
 
 74 
 
 
 74 
Later Years
 
 
 295 
 
 
 295 
Total Future Minimum Lease Payments
 
$
 665 
 
$
 665 

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease is accounted for as an operating lease.  In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignment is accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $13 million and $15 million for I&M and SWEPCo, respectively, for the remaining railcars as of December 31, 2013.  These obligations are included in the future minimum lease payments schedule earlier in this note.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 83% of the projected fair value of the equipment under the current five-year lease term to 77% at the end of the 20-year term.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  The maximum potential losses related to the guarantee are approximately $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term.  However, we believe that the fair value would produce a sufficient sales price to avoid any loss.


 
131

 


Sabine Dragline Lease

During 2009, Sabine entered into capital lease arrangements with a nonaffiliated company to finance the purchase of two electric draglines to be used for Sabine’s mining operations totaling $47 million.  The amounts included in the lease represented the aggregate fair value of the existing equipment and a sale-and-leaseback transaction for additional dragline rebuild costs required to keep the dragline operational.  These capital lease assets are included in Other Property, Plant and Equipment on our December 31, 2013 and 2012 balance sheets.  The short-term and long-term capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on our December 31, 2013 and 2012 balance sheets.  The future payment obligations are included in our future minimum lease payments schedule earlier in this note.

I&M Nuclear Fuel Lease

In November 2013, I&M entered into a sale-and-leaseback transaction with IMP 11-2013, a nonaffiliated Ohio Trust, to lease nuclear fuel for I&M’s Cook Plant.  In November 2013, I&M sold a portion of its unamortized nuclear fuel inventory to the trust for $110 million.  The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 54 months. The future payment obligations of $110 million are included in our future minimum lease payments schedule earlier in this note.  The net capital lease asset is included in Other Property, Plant and Equipment and the short-term and long-term capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities, respectively, on our December 31, 2013 balance sheet.  The future minimum lease payments for the sale-and-leaseback transaction as of December 31, 2013 are as follows, based on estimated fuel burn:

Future Minimum Lease Payments
 
I&M
 
 
 
(in millions)
2014 
 
$
 43 
2015 
 
 
 32 
2016 
 
 
 27 
2017 
 
 
 6 
2018 
 
 
 2 
Total Future Minimum Lease Payments
 
$
 110 

14.   FINANCING ACTIVITIES

AEP Common Stock

Listed below is a reconciliation of common stock share activity for the years ended December 31, 2013, 2012 and 2011:

 
 
 
 
 
Held in
Shares of AEP Common Stock
 
Issued
 
Treasury
Balance, December 31, 2010
 
 501,114,881 
 
 20,307,725 
Issued
 
 2,644,579 
 
 - 
Treasury Stock Acquired
 
 - 
 
 28,867 
Balance, December 31, 2011
 
 503,759,460 
 
 20,336,592 
Issued
 
 2,245,502 
 
 - 
Balance, December 31, 2012
 
 506,004,962 
 
 20,336,592 
Issued
 
 2,109,002 
 
 - 
Balance, December 31, 2013
 
 508,113,964 
 
 20,336,592 

Preferred Stock

In December 2011, AEP subsidiaries redeemed all of their outstanding preferred stock with a par value of $60 million at a premium, resulting in a $2.8 million loss, which is included in Preferred Stock Dividend Requirements of Subsidiaries Including Capital Stock Expense on the statement of income.
 
 
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Long-term Debt

The following details long-term debt outstanding as of December 31, 2013 and 2012:

 
 
Weighted
 
 
 
 
 
 
Average
 
 
 
 
 
 
 
 
 
Interest
 
 
 
 
 
 
 
 
 
 
 
 
Rate as of
 
Interest Rate Ranges as of
 
Outstanding as of
 
 
December 31,
 
December 31,
 
December 31,
Type of Debt and Maturity
 
2013 
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
 
 
 
 
 
(in millions)
Senior Unsecured Notes (a)
 
 
 
 
 
 
 
 
 
 
 
 
 
2013-2043
 
5.45%
 
1.65%-8.13%
 
0.685%-8.13%
 
$
 11,799 
 
$
 12,712 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pollution Control Bonds (b)
 
 
 
 
 
 
 
 
 
 
 
 
 
2013-2038 (c)
 
3.29%
 
0.02%-6.30%
 
0.11%-6.30%
 
 
 1,932 
 
 
 1,958 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes Payable (d)
 
 
 
 
 
 
 
 
 
 
 
 
 
2013-2032
 
4.17%
 
1.164%-8.03%
 
1.913%-8.03%
 
 
 369 
 
 
 427 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Securitization Bonds (e)
 
 
 
 
 
 
 
 
 
 
 
 
 
2013-2031
 
3.72%
 
0.88%-6.25%
 
0.88%-6.25%
 
 
 2,686 
 
 
 2,281 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel Obligation (f)
 
 
 
 
 
 
 
 
 265 
 
 
 265 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Long-term Debt (a) (g)
 
 
 
 
 
 
 
 
 
 
 
 
 
2015-2059
 
1.41%
 
1.15%-13.718%
 
1.72%-13.718%
 
 
 1,360 
 
 
 140 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Interest Rate Hedges
 
 
 
 
 
 
 
 
 (9)
 
 
 3 
Unamortized Discount, Net
 
 
 
 
 
 
 
 
 (25)
 
 
 (29)
Total Long-term Debt Outstanding
 
 
 
 
 
 
 
 
 18,377 
 
 
 17,757 
Long-term Debt Due Within One Year
 
 
 
 
 
 
 
 
 1,549 
 
 
 2,171 
Long-term Debt
 
 
 
 
 
 
 
$
 16,828 
 
$
 15,586 

(a)
In July 2013, AGR, APCo, KPCo and OPCo entered into a $1 billion term credit facility due in May 2015 to provide liquidity during the corporate separation process.  In 2013, OPCo borrowed $1 billion under the credit facility and retired other certain debt.  On December 31, 2013, OPCo assigned the $1 billion in credit facility borrowings to AGR upon the transfer of OPCo’s generation assets to AGR.  Also on December 31, 2013, AGR subsequently assigned a portion of the borrowings to APCo and KPCo in the amounts of $300 million and $200 million, respectively, upon AGR’s transfer of certain of those generation assets.
(b)
For certain series of pollution control bonds, interest rates are subject to periodic adjustment.  Certain series may be purchased on demand at periodic interest adjustment dates.  Letters of credit from banks and insurance policies support certain series.
(c)
Certain pollution control bonds are subject to redemption earlier than the maturity date.  Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year on the balance sheets.
(d)
Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions.  At expiration, all notes then issued and outstanding are due and payable.  Interest rates are both fixed and variable.  Variable rates generally relate to specified short-term interest rates.
(e)
In 2013, APCo and OPCo issued $380 million and $267 million, respectively, of Securitization Bonds (see Note 16).
(f)
Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see "SNF Disposal" section of Note 6).
(g)
In 2013, PSO, TCC and TNC issued $50 million, $100 million and $75 million three-year credit facilities, respectively, to be used for general corporate purposes.

Long-term debt outstanding as of December 31, 2013 is payable as follows:

 
 
 
 
 
 
 
 
 
 
 
After
 
 
 
2014 
 
2015 
 
2016 
 
2017 
 
2018 
 
2018 
 
Total
 
(in millions)
Principal Amount
$
 1,549 
 
$
 2,519 
 
$
 1,147 
 
$
 1,724 
 
$
 1,135 
 
$
 10,328 
 
$
 18,402 
Unamortized Discount, Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (25)
Total Long-term Debt Outstanding
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$
 18,377 


 
133

 


In January 2014 and February 2014, I&M retired $5 million and $19 million, respectively, of Notes Payable related to DCC Fuel.

In January 2014, TCC retired $112 million of its outstanding Securitization Bonds.

In January 2014, OPCo retired $225 million of 4.85% Senior Unsecured Notes due in 2014.

As of December 31, 2013, trustees held, on our behalf, $500 million of our reacquired Pollution Control Bonds.

Dividend Restrictions

Parent Restrictions

The holders of our common stock are entitled to receive the dividends declared by our Board of Directors provided funds are legally available for such dividends.  Our income derives from our common stock equity in the earnings of our utility subsidiaries.

Pursuant to the leverage restrictions in our credit agreements, we must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%.  The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend.  The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements.  None of AEP’s retained earnings were restricted for the purpose of the payment of dividends.

Utility Subsidiaries’ Restrictions

Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.  Specifically, several of our public utility subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%.  As of December 31, 2013, the amount of restricted net assets of AEP’s subsidiaries that may not be distributed to Parent in the form of a loan, advance or dividend was approximately $6 billion.

The Federal Power Act prohibits the utility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.”  The term “capital account” is not defined in the Federal Power Act or its regulations.  Management understands “capital account” to mean the book value of the common stock.  This restriction does not limit the ability of the utility subsidiaries to pay dividends out of retained earnings.


 
134

 


Lines of Credit and Short-term Debt

We use our commercial paper program to meet the short-term borrowing needs of our subsidiaries.  The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries.  In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  As of December 31, 2013, we had credit facilities totaling $3.5 billion to support our commercial paper program.  The maximum amount of commercial paper outstanding during 2013 was $904 million and the weighted average interest rate of commercial paper outstanding during 2013 was 0.32%.  Our outstanding short-term debt was as follows:

 
 
 
December 31,
 
 
 
2013 
 
2012 
 
 
 
Outstanding
 
Interest
 
Outstanding
 
Interest
Type of Debt
Amount
Rate (a)
 
Amount
Rate (a)
 
 
(in millions)
 
 
 
 
(in millions)
 
 
 
Securitized Debt for Receivables (b)
 
$
 700 
 
 0.23 
%
 
$
 657 
 
 0.26 
%
Commercial Paper
 
 
 57 
 
 0.29 
%
 
 
 321 
 
 0.42 
%
Line of Credit – Sabine (c)
 
 
 - 
 
 - 
%
 
 
 3 
 
 1.82 
%
Total Short-term Debt
 
$
 757 
 
 
 
 
$
 981 
 
 
 

(a)
Weighted average rate.
(b)
Amount of securitized debt for receivables as accounted for under the "Transfers and Servicing" accounting guidance.
(c)
This line of credit does not reduce available liquidity under AEP's credit facilities.

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 6.

Securitized Accounts Receivable – AEP Credit

AEP Credit has a receivables securitization agreement with bank conduits.  Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries.  AEP Credit continues to service the receivables.  These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase our operating companies’ receivables and accelerate AEP Credit’s cash collections.

In June 2013, we amended our receivables securitization agreement to extend through June 2014.  The agreement provides a commitment of $700 million from bank conduits to purchase receivables.  We amended a commitment of $385 million to now expire in June 2014.  The remaining commitment of $315 million expires in June 2015.  We intend to extend or replace the agreement expiring in June 2014 on or before its maturity.


 
135

 


Accounts receivable information for AEP Credit is as follows:

 
 
 
Years Ended December 31,
 
 
 
 
2013 
 
2012 
 
2011 
 
 
 
(dollars in millions)
 
Effective Interest Rates on Securitization of
 
 
 
 
 
 
 
 
 
 
 
Accounts Receivable
 
 
 0.23 
 
 0.26 
 
 0.27 
%
Net Uncollectible Accounts Receivable Written Off
 
$
 35 
 
$
 29 
 
$
 37 
 

 
 
 
December 31,
 
 
 
2013 
 
 
2012 
 
 
 
(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral
 
 
 
 
 
 
 
Less Uncollectible Accounts
 
$
 929 
 
$
 835 
Total Principal Outstanding
 
 
 700 
 
 
 657 
Delinquent Securitized Accounts Receivable
 
 
 45 
 
 
 37 
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable
 
 
 16 
 
 
 21 
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable
 
 
 331 
 
 
 316 

Customer accounts receivable retained and securitized for our operating companies are managed by AEP Credit.  AEP Credit’s delinquent customer accounts receivable represents accounts greater than 30 days past due.

15.   STOCK-BASED COMPENSATION

As approved by shareholder vote, the Amended and Restated American Electric Power System Long-Term Incentive Plan (LTIP) authorizes the use of 20,000,000 shares of AEP common stock for various types of stock-based compensation awards to employees.  A maximum of 10,000,000 shares may be used under this plan for full value share awards, which includes performance units, restricted shares and restricted stock units.  As of December 31, 2013, 15,973,699 shares remained available for issuance under the LTIP plan.  The AEP Board of Directors and shareholders last approved the LTIP in 2010.  The following sections provide further information regarding each type of stock-based compensation award granted by the Human Resources Committee of the Board of Directors (HR Committee).

Stock Options

We did not grant stock options in 2013, 2012 or 2011 but we did have outstanding stock options from grants in earlier periods that were exercised in these years.  As of December 31, 2013 we have no outstanding stock options.  The exercise price of all outstanding stock options equaled or exceeded the market price of AEP’s common stock on the date of grant.  All outstanding stock options were granted with a ten-year term and generally vested, subject to the participant’s continued employment, in approximately equal 1/3 increments on January 1 of the year following the first, second and third anniversary of the grant date.  We record compensation cost for stock options over the vesting period based on the fair value on the grant date.  The LTIP does not specify a maximum contractual term for stock options.

The total intrinsic value of options exercised is as follows:

 
 
Years Ended December 31,
Stock Options
 
2013 
 
2012 
 
2011 
 
 
(in thousands)
Intrinsic Value of Options Exercised (a)
 
$
 3,105 
 
$
 1,699 
 
$
 1,202 
 
 
 
 
 
 
 
 
 
 
(a)
Intrinsic value is calculated as market price at exercise dates less the option exercise price.


 
136

 


A summary of AEP stock option transactions during the years ended December 31, 2013, 2012 and 2011 is as follows:

 
 
 
2013 
 
2012 
 
2011 
 
 
 
 
 
Weighted
 
 
 
Weighted
 
 
 
Weighted
 
 
 
 
 
Average
 
 
 
Average
 
 
 
Average
 
 
 
 
 
Exercise
 
 
 
Exercise
 
 
 
Exercise
 
 
 
Options
 
Price
 
Options
 
Price
 
Options
 
Price
 
 
 
(in thousands)
 
 
 
 
(in thousands)
 
 
 
 
(in thousands)
 
 
 
Outstanding as of January 1,
 188 
 
$
 30.17 
 
 321 
 
$
 29.35 
 
 551 
 
$
 32.88 
 
 
Granted
 - 
 
 
NA 
 
 - 
 
 
NA 
 
 - 
 
 
NA 
 
 
Exercised/Converted
 (187)
 
 
 30.18 
 
 (128)
 
 
 28.21 
 
 (104)
 
 
 27.39 
 
 
Forfeited/Expired
 (1)
 
 
 27.95 
 
 (5)
 
 
 27.26 
 
 (126)
 
 
 46.40 
Outstanding as of December 31,
 - 
 
 
NA 
 
 188 
 
 
 30.17 
 
 321 
 
 
 29.35 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Options Exercisable as of December 31,
 - 
 
$
NA 
 
 188 
 
$
 30.17 
 
 321 
 
$
 29.35 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NA   Not applicable.
 
 
 
 
 
 
 
 
 
 
 
 
 
 

We include the proceeds received from exercised stock options in common stock and paid-in capital.

Performance Units

Our performance units have a fair value upon vesting equal to the average closing market price of AEP common stock for the last 20 trading days of the performance period.  The number of performance units held is multiplied by the performance score to determine the actual number of performance units realized.  The performance score can range from 0% to 200% and is determined at the end of the performance period based on performance measures, which include both performance and market conditions, established for each grant at the beginning of the performance period by the HR Committee.  Performance units are paid in cash, unless they are needed to satisfy a participant’s stock ownership requirement.  In that case, the number of units needed to satisfy the participant’s largest stock ownership requirement is mandatorily deferred as AEP Career Shares until after the end of the participant’s AEP career.  AEP Career Shares are a form of non-qualified deferred compensation that has a value equivalent to shares of AEP common stock.  AEP Career Shares are paid in cash after the participant’s termination of employment.  Amounts equivalent to cash dividends on both performance units and AEP Career Shares accrue as additional units.  We record compensation cost for performance units over the three-year vesting period.  The liability for both the performance units and AEP Career Shares, recorded in Employee Benefits and Pension Obligations on the balance sheets, is adjusted for changes in value.  The fair value of performance unit awards is based on the estimated performance score and the current 20-day average closing price of AEP common stock at the date of valuation.

The HR Committee awarded performance units and reinvested dividends on outstanding performance units and AEP Career Shares for the years ended December 31, 2013, 2012 and 2011 as follows:

 
 
Years Ended December 31,
Performance Units
 
2013 
 
2012 
 
2011 
Awarded Units (in thousands)
 
 
 1,284 
 
 
 546 
 
 
 7 
Weighted Average Unit Fair Value at Grant Date
 
$
 46.23 
 
$
 41.38 
 
$
 38.39 
Vesting Period (in years)
 
 
 3 
 
 
 3 
 
 
 3 
 
 
 
 
 
 
 
 
 
 
 
Performance Units and AEP Career Shares
 
Years Ended December 31,
(Reinvested Dividends Portion)
 
2013 
 
2012 
 
2011 
Awarded Units (in thousands)
 
 
 101 
 
 
 138 
 
 
 198 
Weighted Average Grant Date Fair Value
 
$
 45.42 
 
$
 40.97 
 
$
 37.31 
Vesting Period (in years)
 
 
(a) 
 
 
(a) 
 
 
(a) 

(a)
The vesting period for the reinvested dividends on performance units is equal to the remaining life of the related performance units.  Dividends on AEP Career Shares vest immediately upon grant but are not paid in cash until after the participant’s termination of employment.

 
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Performance scores and final awards are determined and certified by the HR Committee in accordance with the pre-established performance measures within approximately a month after the end of the performance period.  The HR Committee has discretion to reduce or eliminate the number of performance units earned but may not increase the number earned.  The performance scores for all open performance periods prior to those granted in 2012 are dependent on two equally-weighted performance measures: (a) three-year total shareholder return measured relative to the electric utility and multi utility sub-industry segments of the Standard and Poor’s 500 Index and (b) three-year cumulative earnings per share measured relative to an AEP Board of Directors approved target.  Starting with the performance units granted in 2012, the three-year total shareholder return peer group was changed to the S&P 500 Electric Utility Index.

The certified performance scores and units earned for the three-year periods ended December 31, 2013, 2012 and 2011 were as follows:

 
 
Years Ended December 31,
Performance Units
 
2013 
 
2012 
 
2011 
Certified Performance Score
 
 118.8  %
 
 99.7  %
 
 89.8 %
Performance Units Earned
 
 749,219 
 
 1,096,572 
 
 1,216,926 
Performance Units Mandatorily Deferred as AEP Career Shares
 
 72,883 
 
 51,056 
 
 52,639 
Performance Units Voluntarily Deferred into the Incentive
 
 
 
 
 
 
 
Compensation Deferral Program
 
 39,691 
 
 26,337 
 
 42,502 
Performance Units to be Paid in Cash
 
 636,645 
 
 1,019,179 
 
 1,121,785 

The cash payouts for the years ended December 31, 2013, 2012 and 2011 were as follows:

 
 
 
Years Ended December 31,
Performance Units and AEP Career Shares
 
2013 
 
2012 
 
2011 
 
 
 
(in thousands)
Cash Payouts for Performance Units
 
$
 43,925 
 
$
 44,968 
 
$
 15,985 
Cash Payouts for AEP Career Share Distributions
 
 
 3,675 
 
 
 11,027 
 
 
 2,777 

Restricted Shares and Restricted Stock Units

In 2004, the independent members of the AEP Board of Directors granted restricted shares to the then Chairman, President and CEO upon the commencement of his AEP employment.  The final 66,667 shares vested on November 30, 2011.  Compensation cost for restricted shares is measured at fair value on the grant date and recorded over the vesting period.  Fair value is determined by multiplying the number of shares granted by the grant date market closing price, which was $30.76.  The maximum contractual term for these restricted shares was eight years and dividends on these restricted shares were paid in cash.  AEP has not granted other restricted shares.

The HR Committee also grants restricted stock units (RSUs), which generally vest, subject to the participant’s continued employment, over at least three years in approximately equal annual increments.  Additional RSUs granted as dividends vest on the same date as the underlying RSUs on which the dividends were awarded.  Upon vesting, RSUs are converted into a share of AEP common stock, with the exception of participants subject to the disclosure requirements set forth in Section 16 of the Securities Exchange Act of 1934, who are paid in cash.  For awards that are settled with shares, compensation cost is measured at fair value on the grant date and recorded over the vesting period.  Fair value is determined by multiplying the number of units granted by the grant date market closing price.  For awards that are paid in cash, compensation cost is recorded over the vesting period and adjusted for changes in value until vested.  The fair value at vesting is determined by multiplying the number of units vested by the 20-day average closing price of AEP common stock.  The maximum contractual term of outstanding RSUs is six years from the grant date.

In 2010, the HR Committee granted a total of 165,520 RSUs to four CEO succession candidates as a retention incentive for these candidates.  These grants vest, subject to the candidates’ continuous employment, in three approximately equal installments on August 3, 2013, August 3, 2014 and August 3, 2015.  Of these RSUs, 55,172 vested on August 3, 2013 and 110,348 remain outstanding, excluding dividends.

 
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The HR Committee awarded RSUs, including units awarded for dividends, for the years ended December 31, 2013, 2012 and 2011 as follows:

 
 
 
Years Ended December 31,
Restricted Stock Units
 
2013 
 
2012 
 
2011 
Awarded Units (in thousands)
 
 
 644 
 
 
 497 
 
 
 121 
Weighted Average Grant Date Fair Value
 
$
 46.24 
 
$
 40.69 
 
$
 37.07 

The total fair value and total intrinsic value of restricted shares and restricted stock units vested during the years ended December 31, 2013, 2012 and 2011 were as follows:

 
 
 
Years Ended December 31,
Restricted Shares and Restricted Stock Units
 
2013 
 
2012 
 
2011 
 
 
(in thousands)
Fair Value of Restricted Shares and Restricted Stock Units Vested
 
$
 15,325 
 
$
 10,608 
 
$
 7,164 
Intrinsic Value of Restricted Shares and Restricted Stock Units Vested (a)
 
 
 20,378 
 
 
 12,157 
 
 
 8,017 
 
 
 
 
 
 
 
 
 
 
(a)
Intrinsic value is calculated as market price at exercise date.

A summary of the status of our nonvested RSUs as of December 31, 2013 and changes during the year ended December 31, 2013 are as follows:

 
 
 
 
Weighted
 
 
 
 
 
Average
 
 
 
 
Grant Date
Nonvested Restricted Stock Units
 
Shares/Units
 
Fair Value
 
 
(in thousands)
 
 
 
Nonvested as of January 1, 2013
 
 1,000 
 
$
 38.22 
Granted
 
 644 
 
 
 46.24 
Vested
 
 (408)
 
 
 37.57 
Forfeited
 
 (31)
 
 
 39.97 
Nonvested as of December 31, 2013
 
 1,205 
 
 
 42.64 

The total aggregate intrinsic value of nonvested RSUs as of December 31, 2013 was $56 million and the weighted average remaining contractual life was 2.09 years.

Other Stock-Based Plans

We also have a Stock Unit Accumulation Plan for Non-employee Directors providing each non-employee director with AEP stock units as a substantial portion of their quarterly compensation for their services as a director.  The number of stock units provided is based on the closing price of AEP common stock on the last trading day of the quarter for which the stock units were earned.  Amounts equivalent to cash dividends on the stock units accrue as additional AEP stock units.  The stock units granted to Non-employee Directors are fully vested upon grant date.  Stock units are paid in cash upon termination of board service or up to 10 years later if the participant so elects.  Cash payments for stock units are calculated based on the average closing price of AEP common stock for the last 20 trading days prior to the distribution date.

We record compensation cost for stock units when the units are awarded and adjust the liability for changes in value based on the current 20-day average closing price of AEP common stock on the valuation date.

We had no material cash payouts for stock unit distributions for the years ended December 31, 2013, 2012 and 2011.


 
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The Board of Directors awarded stock units, including units awarded for dividends, for the years ended December 31, 2013, 2012 and 2011 as follows:

 
 
 
Years Ended December 31,
Stock Unit Accumulation Plan for Non-Employee Directors
 
2013 
 
2012 
 
2011 
Awarded Units (in thousands)
 
 
 33 
 
 
 52 
 
 
 52 
Weighted Average Grant Date Fair Value
 
$
 45.81 
 
$
 41.20 
 
$
 37.72 

Share-based Compensation Plans

Compensation cost and the actual tax benefit realized for the tax deductions from compensation cost for share-based payment arrangements recognized in income and total compensation cost capitalized in relation to the cost of an asset for the years ended December 31, 2013, 2012 and 2011 were as follows:

 
 
 
Years Ended December 31,
 
Share-based Compensation Plans
 
2013 
 
2012 
 
2011 
 
 
 
(in thousands)
 
Compensation Cost for Share-based Payment Arrangements (a)
 
$
 56,352 
 
$
 51,767 
 
$
 61,807 
 
Actual Tax Benefit Realized
 
 
 19,723 
 
 
 18,119 
 
 
 12,632 
 
Total Compensation Cost Capitalized
 
 
 13,165 
 
 
 10,707 
 
 
 11,608 
 

(a)
Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income.

During the years ended December 31, 2013, 2012 and 2011, there were no significant modifications affecting any of our share-based payment arrangements.

As of December 31, 2013, there was $105 million of total unrecognized compensation cost related to unvested share-based compensation arrangements granted under the LTIP.  Unrecognized compensation cost related to the performance units and AEP Career Shares will change as the fair value is adjusted each period and forfeitures for all award types are realized.  Our unrecognized compensation cost will be recognized over a weighted-average period of 1.66 years.

Cash received from stock options exercised and actual tax benefit realized for the tax deductions from stock options exercised during the years ended December 31, 2013, 2012 and 2011 were as follows:

 
 
Years Ended December 31,
Share-based Compensation Plans
 
2013 
 
2012 
 
2011 
 
 
(in thousands)
Cash Received from Stock Options Exercised
 
$
 5,659 
 
$
 3,598 
 
$
 2,855 
Actual Tax Benefit Realized for the Tax Deductions from Stock Options
 
 
 
 
 
 
 
 
 
 
Exercised
 
 
 1,040 
 
 
 618 
 
 
 411 

Our practice is to use authorized but unissued shares to fulfill share commitments for stock option exercises and RSU vesting.  Although we do not currently anticipate any changes to this practice, we are permitted to use treasury shares, shares acquired in the open market specifically for distribution under the LTIP or any combination thereof for this purpose.  The number of new shares issued to fulfill vesting RSUs is generally reduced to offset our tax withholding obligation.


 
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16.   VARIABLE INTEREST ENTITIES

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE.  A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.  Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.”  In determining whether we are the primary beneficiary of a VIE, we consider factors such as equity at risk, the amount of the VIE’s variability we absorb, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors.  We believe that significant assumptions and judgments were applied consistently.

We are the primary beneficiary of Sabine, DCC Fuel, AEP Credit, Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and a protected cell of EIS.  In addition, we have not provided material financial or other support to Sabine, DCC Fuel, AEP Credit, Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding and our protected cell of EIS that was not previously contractually required.  We hold a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series).

Sabine is a mining operator providing mining services to SWEPCo.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee.  In addition, SWEPCo determines how much coal will be mined each year.  Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine.  SWEPCo’s total billings from Sabine for the years ended December 31, 2013, 2012 and 2011 were $155 million, $147 million and $128 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on the balance sheets.

I&M has nuclear fuel lease agreements with DCC Fuel II LLC, DCC Fuel IV LLC, DCC Fuel V LLC and DCC Fuel VI LLC (collectively DCC Fuel).  DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions.  Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on the leases for the years ended December 31, 2013, 2012 and 2011 were $153 million, $127 million and $85 million, respectively.  The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months.  Based on our control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The capital leases are eliminated upon consolidation.  In October 2013, the lease agreements ended for DCC Fuel LLC and DCC Fuel III LLC.  See the tables below for the classification of DCC Fuel’s assets and liabilities on the balance sheets.

AEP Credit is a wholly-owned subsidiary of AEP.  AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements.  AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings.  Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing.  Based on our control of AEP Credit, management concluded that we are the primary beneficiary and are required to consolidate AEP Credit.  See the tables below for the classification of AEP Credit’s assets and liabilities on the balance sheets.  See “Securitized Accounts Receivables – AEP Credit” section of Note 14.

Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation.  Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant.  Therefore, TCC is required to consolidate Transition Funding.  The securitized bonds totaled $2 billion and $2.3 billion as of December 31, 2013 and 2012, respectively.  Transition Funding has
 
 
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securitized transition assets of $1.9 billion and $2.1 billion as of December 31, 2013 and 2012, respectively.  The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT.  The securitization bonds are payable only from and secured by the securitized transition assets.  The bondholders have no recourse to TCC or any other AEP entity.  TCC acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs.  See the tables below for the classification of Transition Funding’s assets and liabilities on the balance sheets.

Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property.  Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant.  Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding.  The securitized bonds totaled $267 million as of December 31, 2013.  Ohio Phase-in-Recovery Funding has securitized assets of $132 million as of December 31, 2013.  The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO.  In August 2013, securitization bonds were issued.  The securitization bonds are payable only from and secured by the securitized assets.  The bondholders have no recourse to OPCo or any other AEP entity.  OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs.  See the table below for the classification of Ohio Phase-in-Recovery Funding's assets and liabilities on the balance sheet.

Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo's under-recovered ENEC deferral balance.  Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo's equity interest could potentially be significant.  Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding.  The securitized bonds totaled $380 million as of December 31, 2013.   Appalachian Consumer Rate Relief Funding has securitized assets of $369 million as of December 31, 2013.  The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC.  In November 2013, securitization bonds were issued.  The securitization bonds are payable only from and secured by the securitized assets.  The bondholders have no recourse to APCo or any other AEP entity.  APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs.  See the table below for the classification of Appalachian Consumer Rate Relief Funding's assets and liabilities on the balance sheet.

The securitized bonds of Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding are included in current and long-term debt on the balance sheets.  The securitized assets of Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding are included in securitized assets on the balance sheets.

Our subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance.  EIS has multiple protected cells.  Neither AEP nor its subsidiaries have an equity investment in EIS.  The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance.  Our subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims.  Based on our control and the structure of the protected cell and EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate EIS.  Our insurance premium expense to the protected cell for the years ended December 31, 2013, 2012 and 2011 were $31 million, $32 million and $48 million, respectively.  See the tables below for the classification of the protected cell’s assets and liabilities on the balance sheets.  The amount reported as equity is the protected cell’s policy holders’ surplus.


 
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The balances below represent the assets and liabilities of the VIEs that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2013
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPCo
 
Appalachian
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ohio
 
Consumer
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TCC
 
Phase-in-
 
Rate
 
Protected
 
 
SWEPCo
 
I&M
 
AEP
 
Transition
 
Recovery
 
Relief
 
Cell
 
 
Sabine
DCC Fuel
Credit
Funding
 
Funding
 
Funding
 
of EIS
ASSETS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Assets
 
$
 67 
 
$
 118 
 
$
 935 
 
$
 232 
 
$
 23 
 
$
 6 
 
$
 143 
Net Property, Plant and Equipment
 
 
 157 
 
 
 157 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Other Noncurrent Assets
 
 
 51 
 
 
 60 
 
 
 1 
 
 
 1,918 
(a) 
 
 252 
(b) 
 
 378 
(c) 
 
 3 
Total Assets
 
$
 275 
 
$
 335 
 
$
 936 
 
$
 2,150 
 
$
 275 
 
$
 384 
 
$
 146 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Liabilities
 
$
 33 
 
$
 108 
 
$
 827 
 
$
 312 
 
$
 37 
 
$
 14 
 
$
 39 
Noncurrent Liabilities
 
 
 242 
 
 
 227 
 
 
 1 
 
 
 1,820 
 
 
 237 
 
 
 368 
 
 
 66 
Equity
 
 
 - 
 
 
 - 
 
 
 108 
 
 
 18 
 
 
 1 
 
 
 2 
 
 
 41 
Total Liabilities and Equity
 
$
 275 
 
$
 335 
 
$
 936 
 
$
 2,150 
 
$
 275 
 
$
 384 
 
$
 146 
 
(a)  Includes an intercompany item eliminated in consolidation of $82 million.
(b)  Includes an intercompany item eliminated in consolidation of $116 million.
(c)  Includes an intercompany item eliminated in consolidation of $4 million.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2012
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TCC
 
 
 
 
SWEPCo
 
I&M
 
 
 
Transition
 
Protected Cell
 
 
Sabine
DCC Fuel
AEP Credit
Funding
 
of EIS
ASSETS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Assets
 
$
 57 
 
$
 133 
 
$
 843 
 
$
 250 
 
$
 130 
Net Property, Plant and Equipment
 
 
 170 
 
 
 176 
 
 
 - 
 
 
 - 
 
 
 - 
Other Noncurrent Assets
 
 
 55 
 
 
 92 
 
 
 1 
 
 
 2,167 
(a) 
 
 4 
Total Assets
 
$
 282 
 
$
 401 
 
$
 844 
 
$
 2,417 
 
$
 134 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Liabilities
 
$
 32 
 
$
 121 
 
$
 800 
 
$
 304 
 
$
 43 
Noncurrent Liabilities
 
 
 250 
 
 
 280 
 
 
 1 
 
 
 2,095 
 
 
 66 
Equity
 
 
 - 
 
 
 - 
 
 
 43 
 
 
 18 
 
 
 25 
Total Liabilities and Equity
 
$
 282 
 
$
 401 
 
$
 844 
 
$
 2,417 
 
$
 134 
 
(a)  Includes an intercompany item eliminated in consolidation of $89 million.

DHLC is a mining operator that sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  SWEPCo and CLECO share the executive board seats and voting rights equally.  Each entity guarantees 50% of DHLC’s debt.  SWEPCo and CLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee.  SWEPCo’s total billings from DHLC for the years ended December 31, 2013, 2012 and 2011 were $60 million, $77 million and $62 million, respectively.  We are not required to consolidate DHLC as we are not the primary beneficiary, although we hold a significant variable interest in DHLC.  Our equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on the balance sheets.


 
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Our investment in DHLC was:

 
December 31,
 
2013 
 
2012 
 
As Reported on
 
Maximum
 
As Reported on
 
Maximum
 
the Balance Sheet
 
Exposure
 
the Balance Sheet
 
Exposure
 
(in millions)
Capital Contribution from SWEPCo
$
 8 
 
$
 8 
 
$
 8 
 
$
 8 
Retained Earnings
 
 1 
 
 
 1 
 
 
 1 
 
 
 1 
SWEPCo's Guarantee of Debt
 
 - 
 
 
 61 
 
 
 - 
 
 
 49 
 
 
 
 
 
 
 
 
 
 
 
 
Total Investment in DHLC
$
 9 
 
$
 70 
 
$
 9 
 
$
 58 

We and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH).  PATH is a series limited liability company and was created to construct, through its operating companies, a high-voltage transmission line project in the PJM region.  PATH consists of the “West Virginia Series (PATH-WV),” owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is 100% owned by a subsidiary of FirstEnergy.  Provisions exist within the PATH-WV agreement that make it a VIE.  The “Allegheny Series” is not considered a VIE.  We are not required to consolidate PATH-WV as we are not the primary beneficiary, although we hold a significant variable interest in PATH-WV.  Our equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the balance sheets.  We and FirstEnergy share the returns and losses equally in PATH-WV.  Our subsidiaries and FirstEnergy’s subsidiaries provide services to the PATH companies through service agreements.  The entities recover costs through regulated rates.

In August 2012, the PJM board cancelled the PATH Project, our transmission joint venture with FirstEnergy, and removed it from the 2012 Regional Transmission Expansion Plan.  In September 2012, the PATH Project companies submitted an application to the FERC requesting authority to recover prudently-incurred costs associated with the PATH Project.  In November 2012, the FERC issued an order accepting the PATH Project’s abandonment cost recovery application, subject to settlement procedures and hearing.  The settlement proceedings are ongoing.

Our investment in PATH-WV was:

 
December 31,
 
2013 
 
2012 
 
As Reported on
 
Maximum
 
As Reported on
 
Maximum
 
the Balance Sheet
 
Exposure
 
the Balance Sheet
 
Exposure
 
 
 
(in millions)
 
 
 
Capital Contribution from AEP
$
 19 
 
$
 19 
 
$
 19 
 
$
 19 
Retained Earnings
 
 6 
 
 
 6 
 
 
 12 
 
 
 12 
 
 
 
 
 
 
 
 
 
 
 
 
Total Investment in PATH-WV
$
 25 
 
$
 25 
 
$
 31 
 
$
 31 

As of December 31, 2013, our $25 million investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the balance sheet.  If we cannot ultimately recover our investment related to PATH-WV, it could reduce future net income and cash flows.


 
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17.   PROPERTY, PLANT AND EQUIPMENT

Depreciation, Depletion and Amortization

We provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class.  The following tables provide the annual property information:

2013 
 
Regulated
 
Nonregulated
 
 
 
 
 
 
 
Annual
 
 
 
 
 
 
 
 
 
Annual
 
 
 
 
Functional
 
Property,
 
 
 
 
Composite
 
 
 
 
 
Property,
 
 
 
Composite
 
 
 
 
Class of
 
Plant and
 
Accumulated
 
 
Depreciation
 
Depreciable
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
Property
 
Equipment
 
Depreciation
 
 
Rate Ranges
 
Life Ranges
 
Equipment
 
Depreciation
 
Rate Ranges
 
Life Ranges
 
 
(in millions)
 
 
 
 
 
 
 
(in years)
 
(in millions)
 
 
 
 
 
 
 
(in years)
Generation
 
$
 17,873 
 
$
 7,168 
 
 
 1.7 
-
 3.7 
%
 
 31 
 132 
 
$
 7,201 
 
$
 2,969 
 
 
 2.6 
-
 3.3 
%
 
 35 
-
 66 
Transmission
 
 
 10,854 
 
 
 2,805 
 
 
 1.1 
-
 2.7 
%
 
 25 
 87 
 
 
 39 
 
 
 16 
 
 
 2.5 
%
 
 
 43 
-
 55 
Distribution
 
 
 16,377 
 
 
 3,988 
 
 
 2.3 
-
 3.8 
%
 
 11 
 75 
 
 
 - 
 
 
 - 
 
 
NA 
 
 
NA 
CWIP
 
 
 2,326 
 
 
 (121)
 
 
NM
 
 
NM
 
 
 145 
 
 
 1 
 
 
NM 
 
 
NM
Other
 
 
 4,116 
 
 
 1,931 
 
 
 2.0 
-
 7.9 
%
 
 5 
 75 
 
 
 1,354 
 
 
 531 
 
 
NM 
 
 
NM
Total
 
$
 51,546 
 
$
 15,771 
 
 
 
 
 
 
 
 
 
 
 
$
 8,739 
 
$
 3,517 
 
 
 
 
 
 
 
 
 
 

2012 
 
Regulated
 
Nonregulated
 
 
 
 
 
 
 
Annual
 
 
 
 
 
 
 
 
 
Annual
 
 
 
 
Functional
 
Property,
 
 
 
 
Composite
 
 
 
 
 
Property,
 
 
 
Composite
 
 
 
 
Class of
 
Plant and
 
Accumulated
 
 
Depreciation
 
Depreciable
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
Property
 
Equipment
 
Depreciation
 
 
Rate Ranges
 
Life Ranges
 
Equipment
 
Depreciation
 
Rate Ranges
 
Life Ranges
 
 
(in millions)
 
 
 
 
 
 
 
(in years)
 
(in millions)
 
 
 
 
 
 
 
(in years)
Generation
 
$
 16,973 
 
$
 6,962 
 
 
 1.7 
 3.8 
%
 
 31 
 132 
 
$
 9,306 
 
$
 3,526 
 
 
 2.6 
 3.3 
%
 
 35 
-
 66 
Transmission
 
 
 9,846 
 
 
 2,720 
 
 
 1.2 
 2.8 
%
 
 25 
 87 
 
 
 - 
 
 
 - 
 
 
NA 
 
 
NA 
Distribution
 
 
 15,565 
 
 
 3,837 
 
 
 2.4 
 3.9 
%
 
 11 
 75 
 
 
 - 
 
 
 - 
 
 
NA 
 
 
NA 
CWIP
 
 
 1,600 
 
 
 (27)
 
 
NM 
 
 
NM
 
 
 219 
 
 
 1 
 
 
NM 
 
 
NM
Other
 
 
 2,644 
 
 
 1,238 
 
 
 1.8 
 9.6 
%
 
 5 
 75 
 
 
 1,301 
 
 
 434 
 
 
NM 
 
 
NM
Total
 
$
 46,628 
 
$
 14,730 
 
 
 
 
 
 
 
 
 
 
 
$
 10,826 
 
$
 3,961 
 
 
 
 
 
 
 
 
 
 

2011 
 
Regulated
 
Nonregulated
 
 
 
 
Annual
 
 
 
 
 
Annual
 
 
 
 
 
 
 
 
Composite
 
 
 
 
 
Composite
 
 
 
 
 
 
 
 
Depreciation
 
Depreciable
 
Depreciation
 
Depreciable
Functional Class of Property
 
Rate Ranges
 
Life Ranges
 
Rate Ranges
 
Life Ranges
 
 
 
 
 
 
 
 
 
 
(in years)
 
 
 
 
 
 
 
(in years)
Generation
 
 
 1.6 
 3.8 
%
 
 9 
 132 
 
 
 2.6 
 3.5 
%
 
 20 
 66 
Transmission
 
 
 1.3 
 2.7 
%
 
 25 
 87 
 
 
NA 
 
 
NA 
Distribution
 
 
 2.4 
 4.0 
%
 
 11 
 75 
 
 
NA 
 
 
NA 
CWIP
 
 
NM
 
 
NM
 
 
NM
 
 
NM
Other
 
 
 1.7 
 9.3 
%
 
 5 
 55 
 
 
NM
 
 
NM
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NA
 
Not applicable.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NM
 
Not meaningful.

We provide for depreciation, depletion and amortization of coal-mining assets over each asset's estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment.  We use either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages.  We include these costs in the cost of coal charged to fuel expense.
 
 
145

 

For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization.  Actual removal costs incurred are charged to Accumulated Depreciation and Amortization.  Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability.  For nonregulated operations, non-ARO removal costs are expensed as incurred.

Asset Retirement Obligations (ARO)

We record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for our legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities, as well as for nuclear decommissioning of our Cook Plant.  We have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which we have assets.  Generally, such easements are perpetual and require only the retirement and removal of our assets upon the cessation of the property’s use.  We do not estimate the retirement for such easements because we plan to use our facilities indefinitely.  The retirement obligation would only be recognized if and when we abandon or cease the use of specific easements, which is not expected.

The following is a reconciliation of the 2013 and 2012 aggregate carrying amounts of ARO:

 
 
 
Carrying
 
 
 
 
Amount
 
 
 
 
of ARO
 
 
 
 
(in millions)
 
ARO as of December 31, 2011 (a)
 
$
 1,474 
 
Accretion Expense
 
 
 85 
 
Liabilities Incurred
 
 
 17 
 
Liabilities Settled
 
 
 (24)
 
Revisions in Cash Flow Estimates
 
 
 144 
 
ARO as of December 31, 2012
 
 
 1,696 
 
Accretion Expense
 
 
 103 
 
Liabilities Incurred
 
 
 4 
 
Liabilities Settled
 
 
 (22)
 
Revisions in Cash Flow Estimates
 
 
 54 
 
ARO as of December 31, 2013
 
$
 1,835 
 

(a)
A current portion of ARO, totaling $2 million, is included in Other Current Liabilities on our 2011 balance sheet.

As of December 31, 2013 and 2012, our ARO liability included $1.2 billion and $1.2 billion, respectively, for nuclear decommissioning of the Cook Plant.  As of December 31, 2013 and 2012, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $1.6 billion and $1.4 billion, respectively, and are recorded in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization

Our amounts of allowance for borrowed, including interest capitalized, and equity funds used during construction is summarized in the following table:

 
Years Ended December 31,
 
 
2013 
 
2012 
 
2011 
 
 
(in millions)
 
Allowance for Equity Funds Used During Construction
$
 73 
 
$
 93 
 
$
 98 
 
Allowance for Borrowed Funds Used During Construction
 
 40 
 
 
 69 
 
 
 63 
 


 
146

 


Jointly-owned Electric Facilities

We have electric facilities that are jointly-owned with nonaffiliated companies.  Using our own financing, we are obligated to pay a share of the costs of these jointly-owned facilities in the same proportion as our ownership interest.  Our proportionate share of the operating costs associated with such facilities is included on the statements of income and the investments and accumulated depreciation are reflected on the balance sheets under Property, Plant and Equipment as follows:

 
 
 
 
 
 
Company’s Share as of December 31, 2013
 
 
 
 
 
 
 
 
Construction
 
 
 
Fuel
Percent of
Utility Plant
Work in
Accumulated
 
Type
Ownership
 in Service
Progress
Depreciation
 
 
 
 
 
 
(in millions)
W.C. Beckjord Generating Station, Unit 6 (a)
Coal
 
 12.5 
%
 
$
 - 
 
$
 - 
 
$
 - 
Conesville Generating Station, Unit 4 (b)
Coal
 
 43.5 
%
 
 
 335 
 
 
 2 
 
 
 55 
J.M. Stuart Generating Station (c)
Coal
 
 26.0 
%
 
 
 544 
 
 
 11 
 
 
 190 
Wm. H. Zimmer Generating Station (a)
Coal
 
 25.4 
%
 
 
 809 
 
 
 2 
 
 
 399 
Dolet Hills Generating Station, Unit 1 (d)
Lignite
 
 40.2 
%
 
 
 262 
 
 
 47 
 
 
 198 
Flint Creek Generating Station, Unit 1 (e)
Coal
 
 50.0 
%
 
 
 123 
 
 
 54 
 
 
 66 
Pirkey Generating Station, Unit 1 (e)
Lignite
 
 85.9 
%
 
 
 519 
 
 
 29 
 
 
 376 
Oklaunion Generating Station, Unit 1 (f)
Coal
 
 70.3 
%
 
 
 404 
 
 
 7 
 
 
 223 
Turk Generating Plant (e)
Coal
 
 73.33 
%
 
 
 1,638 
 
 
 13 
 
 
 35 
Transmission
NA
 
(g)
 
 
 
 78 
 
 
 - 
 
 
 50 
Total
 
 
 
 
 
$
 4,712 
 
$
 165 
 
$
 1,592 

 
 
 
 
 
 
Company’s Share as of December 31, 2012
 
 
 
 
 
 
 
 
Construction
 
 
 
Fuel
Percent of
Utility Plant
Work in
Accumulated
 
Type
Ownership
 in Service
Progress
Depreciation
 
 
 
 
 
 
(in millions)
W.C. Beckjord Generating Station, Unit 6 (a)
Coal
 
 12.5 
%
 
$
 - 
 
$
 - 
 
$
 - 
Conesville Generating Station, Unit 4 (b)
Coal
 
 43.5 
%
 
 
 310 
 
 
 26 
 
 
 59 
J.M. Stuart Generating Station (c)
Coal
 
 26.0 
%
 
 
 542 
 
 
 11 
 
 
 181 
Wm. H. Zimmer Generating Station (a)
Coal
 
 25.4 
%
 
 
 807 
 
 
 2 
 
 
 387 
Dolet Hills Generating Station, Unit 1 (d)
Lignite
 
 40.2 
%
 
 
 263 
 
 
 8 
 
 
 195 
Flint Creek Generating Station, Unit 1 (e)
Coal
 
 50.0 
%
 
 
 121 
 
 
 14 
 
 
 64 
Pirkey Generating Station, Unit 1 (e)
Lignite
 
 85.9 
%
 
 
 514 
 
 
 16 
 
 
 371 
Oklaunion Generating Station, Unit 1 (f)
Coal
 
 70.3 
%
 
 
 403 
 
 
 4 
 
 
 216 
Turk Generating Plant (e)
Coal
 
 73.33 
%
 
 
 1,613 
 
 
 (3)
 
 
 - 
Transmission
NA
 
(g) 
 
 
 
 69 
 
 
 4 
 
 
 50 
Total
 
 
 
 
 
$
 4,642 
 
$
 82 
 
$
 1,523 
 
(a ) Operated by Duke Energy Corporation, a nonaffiliated company.  AEP's portion of Beckjord Plant, U nit 6 was impaired in the fourth quarter of 2012.  See "Impairments" section of Note 7.
(b) Operated by AGR.
(c) Operated by The Dayton Power & Light Company, a nonaffiliated company.
(d) Operated by CLECO, a nonaffiliated company.
(e) Operated by SWEPCo.
(f) Operated by PSO and also jointly-owned (54.7%) by TNC.
(g) Varying percentages of ownership.
NA Not applicable.
 
 
 
147

 


18.   SUSTAINABLE COST REDUCTIONS

In April 2012, we initiated a process to identify strategic repositioning opportunities and efficiencies that will result in sustainable cost savings.  We selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate our current employee benefit programs.  The process resulted in involuntary severances and was completed by the end of the first quarter of 2013.  The severance program provides two weeks of base pay for every year of service along with other severance benefits.

We recorded a charge of $47 million to Other Operation expense in 2012 primarily related to severance benefits as a result of the sustainable cost reductions initiative.  In addition, the sustainable cost reduction activity for the year ended December 31, 2013 is described in the following table:

 
 
Sustainable Cost
 
 
Reduction Activity
 
 
(in millions)
Balance as of December 31, 2012
 
$
 25 
Incurred
 
 
 16 
Settled
 
 
 (31)
Adjustments
 
 
 (9)
Balance as of December 31, 2013
 
$
 1 

These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the statements of income.  Of the current period expense, approximately 43% was within the Generation & Marketing segment, 36% was within the Transmission and Distribution Utilities segment and 18% was within the Vertically Integrated Utilities segment.   Of the total cumulative expense, approximately 51% was within the Vertically Integrated Utilities segment, 27% was within the Transmission and Distribution Utilities segment and 19% was within the Generation & Marketing segment.  The remaining liability is included in Other Current Liabilities on the balance sheets.  We do not expect additional costs to be incurred related to this initiative.


 
148

 


19.   UNAUDITED QUARTERLY FINANCIAL INFORMATION

In our opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of our results of operations for interim periods.  Quarterly results are not necessarily indicative of a full year’s operations because of various factors.  Our unaudited quarterly financial information is as follows:

 
 
 
 
2013 Quarterly Periods Ended
 
 
 
 
March 31
 
June 30
 
September 30
 
December 31
 
 
 
 
 
(in millions - except per share amounts)
 
Total Revenues
$
 3,826 
 
$
 3,582 
 
$
 4,176 
 
$
 3,773 
 
Operating Income
 
 755 
 
 
 547 
(a)
 
 875 
(c)
 
 678 
(d)(e)
Net Income
 
 364 
 
 
 339 
(a)(b)
 
 434 
(c)
 
 347 
(d)(e)
 
 
 
 
 
 
 
 
 
 
 
 
 
Amounts Attributable to AEP Common Shareholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income
 
 363 
 
 
 338 
(a)(b)
 
 433 
(c)
 
 346 
(d)(e)
 
 
 
 
 
 
 
 
 
 
 
 
 
Basic Earnings per Share Attributable to AEP
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Shareholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Earnings per Share (f)
 
 0.75 
 
 
 0.69 
 
 
 0.89 
 
 
 0.71 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Diluted Earnings per Share Attributable to AEP
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Shareholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Earnings per Share (f)
 
 0.75 
 
 
 0.69 
 
 
 0.89 
 
 
 0.71 
 

 
 
 
 
2012 Quarterly Periods Ended
 
 
 
 
March 31
 
June 30
 
September 30
 
December 31
 
 
 
 
 
(in millions - except per share amounts)
 
Total Revenues
$
 3,625 
 
$
 3,551 
 
$
 4,156 
 
$
 3,613 
 
Operating Income
 
 754 
 
 
 741 
 
 
 912 
 
 
 249 
(g)(h)
Net Income
 
 390 
 
 
 363 
 
 
 488 
 
 
 21 
(g)(h)
 
 
 
 
 
 
 
 
 
 
 
 
 
Amounts Attributable to AEP Common Shareholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income
 
 389 
 
 
 362 
 
 
 487 
 
 
 21 
(g)(h)
 
 
 
 
 
 
 
 
 
 
 
 
 
Basic Earnings per Share Attributable to AEP
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Shareholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Earnings per Share (f)
 
 0.80 
 
 
 0.75 
 
 
 1.00 
 
 
 0.05 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Diluted Earnings per Share Attributable to AEP
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Shareholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Earnings per Share (f)
 
 0.80 
 
 
 0.75 
 
 
 1.00 
 
 
 0.05 
 

(a)
Includes an impairment for Muskingum River Plant, Unit 5 (see Note 7).
(b)
Includes U.K. Windfall Tax benefit (see Note 12).
(c)
Includes regulatory disallowances for the Turk Plant (see Note 4) and for Big Sandy Plant, Unit 2 (see Note 7).
(d)
Includes a regulatory disallowance for Amos Plant, Unit 3 (see Note 7).
(e)
Includes the reversal of regulatory disallowance for the Turk Plant (see Note 4).
(f)
Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding.
(g)
Includes impairments for certain Ohio generation plants (see Note 7).
(h)
See Note 18 for discussion of cost reduction programs in 2012.


 
149

 


20.   GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

The changes in our carrying amount of goodwill for the years ended December 31, 2013 and 2012 by operating segment are as follows:

 
Vertically
 
 
 
Generation
 
 
 
Integrated
 
AEP River
 
 
and
 
AEP
 
Utilities
 
Operations
 
Marketing
 
Consolidated
 
(in millions)
Balance as of December 31, 2011
$
 37 
 
$
 39 
 
$
 - 
 
$
 76 
Acquired Goodwill
 
 - 
 
 
 - 
 
 
 15 
 
 
 15 
Impairment Losses
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Balance as of December 31, 2012
 
 37 
 
 
 39 
 
 
 15 
 
 
 91 
Impairment Losses
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Balance as of December 31, 2013
$
 37 
 
$
 39 
 
$
 15 
 
$
 91 

In the fourth quarters of 2013 and 2012, we performed our annual impairment tests.  The fair values of the operations with goodwill were estimated using cash flow projections and other market value indicators.  There were no goodwill impairment losses.  We do not have any accumulated impairment on existing goodwill.

During 2012, the increase in goodwill of $15 million was due to the acquisition of BlueStar.

Other Intangible Assets

Acquired intangible assets subject to amortization were $10 million as of December 31, 2013, net of accumulated amortization and are included in Deferred Charges and Other Noncurrent Assets on the balance sheets.  During 2012, as a result of the acquisition of BlueStar, we acquired intangible assets associated with sales contracts and customer accounts of $58 million.  The amortization life, gross carrying amount and accumulated amortization by major asset class are as follows:

 
 
 
December 31,
 
 
 
2013 
 
2012 
 
 
 
Gross
 
 
 
Gross
 
 
 
Amortization
 
Carrying
 
Accumulated
 
Carrying
 
Accumulated
 
Life
 
Amount
 
Amortization
 
Amount
 
Amortization
 
(in years)
 
(in millions)
Acquired Customer Contracts
 
$
 58 
 
$
 48 
 
$
 58 
 
$
 34 

Amortization of intangible assets was $14 million, $34 million and $1 million for the years ended December 31, 2013, 2012 and 2011, respectively.  Our estimated total amortization is $6 million, $3 million and $1 million for 2014, 2015 and 2016, respectively.


 
150

 










APPALACHIAN POWER COMPANY
AND SUBSIDIARIES

 
151

 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

As a public utility, APCo engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 960,000 retail customers in its service territory in southwestern Virginia and southern West Virginia.  APCo consolidates Cedar Coal Company, Central Appalachian Coal Company, Southern Appalachian Coal Company and Appalachian Consumer Rate Relief Funding LLC, its wholly-owned subsidiaries.  APCo sells power at wholesale to municipalities.

In accordance with management’s December 2010 announcement and an October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014.  The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated.

Effective January 1, 2014, the FERC approved a PCA among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.  Under the PCA, APCo, I&M and KPCo will be individually responsible for planning their respective capacity obligations and there will be no capacity equalization charges/credits on deficit/surplus companies.   Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities.

Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent.  The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies will fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year.  Under the Bridge Agreement, AGR is committed to meet capacity obligations of member companies.

Effective January 1, 2014, AEPSC conducts power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M and KPCo.  Power and natural gas risk management activities are allocated based on the three member companies’ respective equity positions and the SIA.  APCo shares in coal risk management activities based on its proportion of fossil fuels burned by the AEP System.  Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and, to a lesser extent, the purchase and sale of natural gas and coal.  The power, natural gas and coal contracts include physical transactions, OTC options and financially-settled swaps and exchange-traded futures and options.  AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts.  For contracts entered and settled prior to January 1, 2014, power and natural gas risk management activities were allocated based on the Interconnection Agreement and the SIA.  For contracts entered prior to January 1, 2014 and settled after January 1, 2014, power and natural gas risk management activities are allocated based on frozen MLR ratios as of December 31, 2013.  APCo shared in the revenues and expenses associated with these risk management activities with the other AEP East Companies, PSO and SWEPCo.

Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East Companies and trading and marketing activities originating in SPP generally accruing to the benefit of PSO and SWEPCo.  Margins resulting from other transactions are allocated among the AEP East Companies, PSO and SWEPCo in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months.

Prior to January 1, 2014, the Interconnection Agreement permitted the AEP East Companies to pool their generation assets on a cost basis.  It established an allocation method for generating capacity among its members based on relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity revenues.  Members of the Interconnection Agreement were compensated for their costs of energy delivered and
 
 
152

 
charged for energy received.  The capacity reserve relationship of the Interconnection Agreement members changed as generating assets were added, retired or sold and relative peak demand changed.  The Interconnection Agreement calculated each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs.  The result of this calculation was the MLR, which determined each member’s percentage share of revenues and costs.

To minimize the credit requirements and operating constraints when operating within PJM, participating AEP companies, including APCo, agreed to a netting of all payment obligations incurred by any of the AEP companies against all balances due to the AEP companies and to hold PJM harmless from actions that any one or more AEP companies may take with respect to PJM.

APCo is jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity pursuant to the SIA.

Regulatory Activity

Plant Transfers and Termination of Interconnection Agreement

Based upon the PUCO’s approval of OPCo’s corporate separation plan in October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations, transfer these generation assets and associated liabilities to AGR and subsequently transfer, at net book value (NBV), the two-thirds ownership in Amos Plant, Unit 3 to APCo and transfer at NBV the Mitchell Plant to APCo and KPCo in equal one-half interests.  In December 2012, APCo filed requests with the Virginia SCC and WVPSC for the approval of these plant transfers.

In April 2013, the FERC issued orders approving the transfers of the Amos Plant and Mitchell Plant to APCo and KPCo, respectively, to be effective December 31, 2013.  In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful.  A decision from the Supreme Court of Ohio is pending.  In July 2013, the Virginia SCC approved the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo but directed that an amount equal to $83 million pretax, on a total APCo basis, be removed from the proposed transfer price.  Additionally, the Virginia SCC denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo.  In December 2013, the WVPSC approved the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo but deferred a final decision related to the recovery of the West Virginia jurisdictional share of the $83 million pretax Virginia SCC disallowance until APCo’s next West Virginia base rate case which APCo has agreed to file no later than June 2014.  Additionally, the WVPSC order also approved a rate surcharge for Amos Plant, Unit 3 effective January 2014 and deferred ruling on the transfer of the one-half interest in the Mitchell Plant to APCo.  As a result of the Virginia SCC order, in the fourth quarter of 2013, APCo recorded a pretax regulatory disallowance of $39 million in Asset Impairments and Other Related Charges on the statement of income.  See the “Plant Transfers” section of APCo Rate Matters  and the “Corporate Separation and Termination of the Interconnection Agreement” section of FERC Rate Matters in Note 3.
 
If APCo experiences decreases in revenues or is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows and impact financial condition.

2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing

In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $39 million related to 2012 and 2011 environmental compliance costs, including carrying costs.  In November 2013, the Virginia SCC approved a settlement agreement which recommended approval of an environmental RAC to recover $38 million of the 2012 and 2011 environmental compliance costs, effective January 2014 for a one-year period.   As of December 31, 2013, APCo has deferred $28 million for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $10 million of unrecognized equity carrying costs.  See “2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing” section of Note 3.
 
2013 Virginia Generation Rate Adjustment Clause (Generation RAC) Filing

In March 2013, APCo filed with the Virginia SCC to increase its generation RAC revenues by $12 million for a total of $38 million to collect costs related to the Dresden Plant.  In December 2013, the Virginia SCC approved a settlement agreement that included an increase in the generation RAC to $39 million.  Per the approved settlement
 
 
153

 
agreement, the generation RAC increase was effective February 2014 for a period of one year at which time the component to collect an under-recovery will cease and the remaining component to recover on-going Dresden Plant costs will continue.  As of December 31, 2013, APCo has deferred $6 million for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $5 million of unrecognized equity carrying costs.  See “2013 Virginia Generation Rate Adjustment Clause (Generation RAC) Filing” section of Note 3.

2013 Virginia Transmission Rate Adjustment Clause (Transmission RAC) Filing

In December 2013, APCo filed with the Virginia SCC to increase its transmission RAC revenues by $50 million annually.  The increase in the transmission RAC is expected to be effective May 2014.  In February 2014, a hearing was held at the Virginia SCC in which a stipulation agreement between APCo and the Virginia SCC staff was submitted to the Virginia SCC that recommended approval to increase the transmission RAC revenues by $ 49 million annually, subject to true-up.  As of December 31, 2013, APCo has deferred $47 million for the Virginia portion of unrecovered transmission RAC costs.  If the Virginia SCC were to disallow any portion of the transmission RAC, it could reduce future net income and cash flows.  See “2013 Virginia Transmission Rate Adjustment Clause (Transmission RAC) Filing” section of Note 3.

Securitization of Regulatory Assets

In September 2013, the WVPSC approved a settlement agreement filed by APCo, WPCo and intervenors which authorized APCo to securitize $376 million, plus upfront financing costs, related primarily to the December 2011 under-recovered Expanded Net Energy Charge (ENEC) deferral balance.  In November 2013, APCo issued $380 million of Securitization Bonds to securitize the under-recovered ENEC deferral balance, including $4 million of upfront financing costs, with a final maturity date of August 2031.  APCo implemented a new securitization rider which was offset by an equal reduction in ENEC revenues, with no overall change in total revenues.  See the “2013 West Virginia Expanded Net Energy Charge (ENEC) Filing” section of Note 3.

WPCo Merger with APCo

In December 2011, APCo and WPCo filed an application with the WVPSC requesting authority to merge WPCo into APCo.  In December 2012, APCo and WPCo filed merger applications with the Virginia SCC and the FERC and in April 2013, the FERC approved the merger.  Also in December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval of the transfers at NBV to APCo of OPCo’s two-thirds interest in Amos Plant, Unit 3 and one-half of OPCo’s interest in the Mitchell Plant.  In June 2013, the WVPSC issued an order consolidating the merger case with APCo’s plant asset transfer case.  In July 2013, the Virginia SCC approved the merger of WPCo into APCo and the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo but denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo.  Although the Virginia SCC authorized the merger of WPCo into APCo, denial of the Mitchell Plant ownership transfer will result in insufficient generation to serve the merged company.  In December 2013, the WVPSC issued an order that deferred ruling on the merger of WPCo into APCo.  Management continues to review its options and the feasibility related to the merger, the respective companies’ needs for generation and the remaining one-half interest in the Mitchell Plant currently owned by AGR.  See the “Plant Transfers” and “WPCo Merger with APCo” sections of APCo Rate Matters in Note 3.

Litigation and Environmental Issues

In the ordinary course of business, APCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 376 for additional discussion of relevant factors.

 
154

 
 
RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
 
(in millions of KWhs)
Retail:
 
 
 
 
 
 
 
 
 
Residential
 
 11,914 
 
 
 11,395 
 
 
 12,011 
 
Commercial
 
 6,828 
 
 
 6,794 
 
 
 6,915 
 
Industrial
 
 10,393 
 
 
 10,778 
 
 
 10,811 
 
Miscellaneous
 
 835 
 
 
 820 
 
 
 828 
Total Retail
 
 29,970 
 
 
 29,787 
 
 
 30,565 
 
 
 
 
 
 
 
 
 
Wholesale
 
 9,527 
 
 
 8,153 
 
 
 8,376 
 
 
 
 
 
 
 
 
 
Total KWhs
 
 39,497 
 
 
 37,940 
 
 
 38,941 

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.

 
Summary of Heating and Cooling Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
 
 
 
(in degree days)
 
Actual - Heating (a)
 
 2,377 
 
 
 1,783 
 
 
 1,996 
 
Normal - Heating (b)
 
 2,225 
 
 
 2,265 
 
 
 2,267 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 1,150 
 
 
 1,354 
 
 
 1,432 
 
Normal - Cooling (b)
 
 1,206 
 
 
 1,201 
 
 
 1,186 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Eastern Region heating degree days are calculated on a 55 degree temperature base.
 
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
 
(c)
Eastern Region cooling degree days are calculated on a 65 degree temperature base.

 
155

 
 
2013 Compared to 2012
 
 
 
 
 
 
 
 
 
 
Reconciliation of Year Ended December 31, 2012 to Year Ended December 31, 2013
 
Net Income
 
(in millions)
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2012
 
 
 
 
$
 258 
 
 
 
 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
 
 
 
Retail Margins
 
 
 
 
 
 (7)
 
Off-system Sales
 
 
 
 
 
 (2)
 
Transmission Revenues
 
 
 
 
 
 12 
 
Other Revenues
 
 
 
 
 
 (8)
 
Total Change in Gross Margin
 
 
 
 
 
 (5)
 
 
 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
 
 
 
Other Operation and Maintenance
 
 
 
 
 
 (41)
 
Asset Impairments and Other Related Charges
 
 
 
 
 
 (39)
 
Depreciation and Amortization
 
 
 
 
 
 2 
 
Taxes Other Than Income Taxes
 
 
 
 
 
 (8)
 
Carrying Costs Income
 
 
 
 
 
 (17)
 
Other Income
 
 
 
 
 
 2 
 
Interest Expense
 
 
 
 
 
 9 
 
Total Change in Expenses and Other
 
 
 
 
 
 (92)
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 
 
 
 32 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2013
 
 
 
 
$
 193 

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:

 
·
Retail Margins decreased $7 million primarily due to the following:
   
·
A $12 million increase in other variable electric generation expenses.
   
·
An $11 million decrease in industrial usage.
   
·
A $9 million deferral of additional wind purchase costs in 2012 as a result of the June 2012 Virginia SCC fuel factor order.
   
·
A $9 million decrease due to adjustments for previously disallowed environmental costs by the November 2011 Virginia SCC order subsequently determined in 2012 to be appropriate for recovery by the Supreme Court of Virginia.
   
·
A $2 million increase in PJM expenses.
   
These decreases were partially offset by:
   
·
A $33 million increase in weather-related usage primarily due to a 33% increase in heating degree days.
   
·
A $9 million increase due to higher rates in Virginia and West Virginia.  For this increase, $8 million have a corresponding increase in Depreciation and Amortization expenses below.
 
·
Transmission Revenues increased $12 million primarily due to increased investments in the PJM region.  These increased revenues are offset in Other Operation and Maintenance expenses below.
 
·
Other Revenues decreased $8 million primarily due to resolution of contingencies related to pole attachments in 2013.  This decrease in Other Revenues is offset by a decrease in Other Operation and Maintenance expense detailed below.
 
 
156

 
 
Expenses and Other and Income Tax Expense changed between years as follows:
 
 
·
Other Operation and Maintenance expenses increased $41 million primarily due to the following:
   
·
A $34 million increase in distribution maintenance expense primarily due to storms in January and June 2013.
   
·
A $30 million write-off in 2013 of previously deferred 2012 Virginia storm costs resulting from the 2013 enactment of a Virginia law.
   
·
A $19 million increase in transmission expenses due to increased investment in the PJM region.  These expenses are offset in Transmission Revenues.
   
These increases were partially offset by:
   
·
A $14 million decrease in employee benefit expenses.
   
·
An $11 million decrease in uncollectible accounts expense as a result of:
      ·
An $8 million resolution of contingencies related to pole attachments in 2013.  This decrease in Other Operation and Maintenance expense is offset by a decrease in Other Revenues detailed above.
      ·
A $5 million provision for customer bankruptcy recorded in 2012.
   
·
A $10 million decrease in transmission maintenance due to major storms in 2012.
    ·
An $8 million decrease due to expenses related to the 2012 sustainable cost reductions.
  · Asset Impairments and Other Related Charges increased $39 million due to the 2013 write-off from a regulatory disallowance of a portion of Amos Plant, Unit 3 pursuant to a Virginia SCC order approving the transfer of Amos Plant, Unit 3.
  ·
Depreciation and Amortization expenses decreased $2 million primarily due to the following:
    · A $13 million decrease in amortization as a result of the cessation of the Virginia Environmental and Reliability surcharge and the Virginia Environmental Rate Adjustment Clause in January 2013 and March 2013, respectively.
   
This decrease was partially offset by:
    · A $10 million increase due to an increase in depreciable base.
 
·
Taxes Other Than Income Taxes expenses increased $8 million primarily due to a $5 million increase in the Virginia Minimum Tax and a $4 million increase in real and personal property taxes amortization.
  ·
Carrying Costs Income decreased $17 million primarily due to an increased recovery of Virginia environmental costs in new base rates as approved by the Virginia SCC in late January 2012 and decreased carrying charges related to the Dresden Plant.
  · Int erest Expense decreased $9 million primarily due to lower average outstanding long-term debt balances.
  · Income Tax Expense decreased $32 million primarily due to a decrease in pretax book income. 
 
CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 376 for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 376 for a discussion of accounting pronouncements.

 
157

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of
Appalachian Power Company:

We have audited the accompanying consolidated balance sheets of Appalachian Power Company and subsidiaries (the "Company") as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income (loss), changes in common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Appalachian Power Company and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

/s/  Deloitte & Touche LLP

Columbus, Ohio
February 25, 2014

 
158

 

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Appalachian Power Company and subsidiaries (APCo) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  APCo’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of APCo’s internal control over financial reporting as of December 31, 2013.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 1992) in Internal Control – Integrated Framework.  Based on management’s assessment, APCo’s internal control over financial reporting was effective as of December 31, 2013.

This annual report does not include an attestation report of APCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit APCo to provide only management’s report in this annual report.

 
159

 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2013, 2012 and 2011
(in thousands)
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
 
REVENUES
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission and Distribution
 
$
 3,059,577 
 
$
 2,948,762 
 
$
 2,835,481 
 
Sales to AEP Affiliates
 
 
 347,484 
 
 
 318,199 
 
 
 359,802 
 
Other Revenues
 
 
 10,345 
 
 
 9,970 
 
 
 9,942 
 
TOTAL REVENUES
 
 
 3,417,406 
 
 
 3,276,931 
 
 
 3,205,225 
 
 
 
 
 
 
 
 
 
 
 
 
EXPENSES
 
 
 
 
 
 
 
 
 
 
Fuel and Other Consumables Used for Electric Generation
 
 
 769,853 
 
 
 815,979 
 
 
 759,684 
 
Purchased Electricity for Resale
 
 
 232,702 
 
 
 211,133 
 
 
 305,647 
 
Purchased Electricity from AEP Affiliates
 
 
 830,959 
 
 
 661,238 
 
 
 819,182 
 
Other Operation
 
 
 311,975 
 
 
 332,936 
 
 
 316,995 
 
Maintenance
 
 
 273,164 
 
 
 211,702 
 
 
 197,002 
 
Asset Impairments and Other Related Charges
 
 
 39,283 
 
 
 - 
 
 
 - 
 
Depreciation and Amortization
 
 
 342,643 
 
 
 344,293 
 
 
 270,529 
 
Taxes Other Than Income Taxes
 
 
 110,549 
 
 
 102,190 
 
 
 106,606 
 
TOTAL EXPENSES
 
 
 2,911,128 
 
 
 2,679,471 
 
 
 2,775,645 
 
 
 
 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
 
 506,278 
 
 
 597,460 
 
 
 429,580 
 
 
 
 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 2,411 
 
 
 1,358 
 
 
 5,016 
 
Carrying Costs Income
 
 
 8,086 
 
 
 24,602 
 
 
 13,433 
 
Allowance for Equity Funds Used During Construction
 
 
 2,353 
 
 
 1,684 
 
 
 9,212 
 
Interest Expense
 
 
 (192,982)
 
 
 (202,074)
 
 
 (204,623)
 
 
 
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE
 
 
 326,146 
 
 
 423,030 
 
 
 252,618 
 
 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 132,935 
 
 
 165,527 
 
 
 89,860 
 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME
 
 
 193,211 
 
 
 257,503 
 
 
 162,758 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred Stock Dividend Requirements Including Capital
 
 
 
 
 
 
 
 
 
 
 
Stock   Expense
 
 
 - 
 
 
 - 
 
 
 1,745 
 
 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO COMMON STOCK
 
$
 193,211 
 
$
 257,503 
 
$
 161,013 
 
 
 
The common stock of APCo is wholly-owned by AEP.
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
160

 
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2013, 2012 and 2011
 (in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
Net Income
 
$
 193,211 
 
$
 257,503 
 
$
 162,758 
 
 
 
 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $943, $925 and $123 in 2013, 2012 and 2011,
 
 
 
 
 
 
 
 
 
 
Respectively
 
 
 1,751 
 
 
 1,718 
 
 
 (229)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $772, $1,937
 
 
 
 
 
 
 
 
 
 
and $1,674 in 2013, 2012 and 2011, Respectively
 
 
 1,433 
 
 
 3,597 
 
 
 3,109 
Pension and OPEB Funded Status, Net of Tax of $15,974, $12,562 and $7,215 in 2013,
 
 
 
 
 
 
 
 
 
 
2012 and 2011, Respectively
 
 
 29,665 
 
 
 23,330 
 
 
 (13,400)
 
 
 
 
 
 
 
 
 
 
 
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
 
 
 32,849 
 
 
 28,645 
 
 
 (10,520)
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
 
$
 226,060 
 
$
 286,148 
 
$
 152,238 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
161

 
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY
For the Years Ended December 31, 2013, 2012 and 2011
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
 
 
 
Stock
 
Capital
 
Earnings
 
Income (Loss)
 
Total
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2010
 
 260,458 
 
 1,475,496 
 
 1,133,748 
 
 (48,023)
 
 2,821,679 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital Contribution from Parent
 
 
 
 
 
 100,000 
 
 
 
 
 
 
 
 
 100,000 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (135,000)
 
 
 
 
 
 (135,000)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (732)
 
 
 
 
 
 (732)
Loss on Reacquired Preferred Stock
 
 
 
 
 
 (1,770)
 
 
 
 
 
 
 
 
 (1,770)
Capital Stock Expense
 
 
 
 
 
 26 
 
 
 (27)
 
 
 
 
 
 (1)
Net Income
 
 
 
 
 
 
 
 
 162,758 
 
 
 
 
 
 162,758 
Other Comprehensive Loss
 
 
 
 
 
 
 
 
 
 
 
 (10,520)
 
 
 (10,520)
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2011
 
 
 260,458 
 
 
 1,573,752 
 
 
 1,160,747 
 
 
 (58,543)
 
 
 2,936,414 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (170,000)
 
 
 
 
 
 (170,000)
Net Income
 
 
 
 
 
 
 
 
 257,503 
 
 
 
 
 
 257,503 
Other Comprehensive Income
 
 
 
 
 
 
 
 
 
 
 
 28,645 
 
 
 28,645 
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2012
 
 
 260,458 
 
 
 1,573,752 
 
 
 1,248,250 
 
 
 (29,898)
 
 
 3,052,562 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (285,000)
 
 
 
 
 
 (285,000)
Net Income
 
 
 
 
 
 
 
 
 193,211 
 
 
 
 
 
 193,211 
Other Comprehensive Income
 
 
 
 
 
 
 
 
 
 
 
 32,849 
 
 
 32,849 
Contribution of Amos Plant from Parent
 
 
 
 
 
 235,810 
 
 
 
 
 
 
 
 
 235,810 
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2013
 
 260,458 
 
 1,809,562 
 
 1,156,461 
 
 2,951 
 
 3,229,432 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
162

 
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2013 and 2012
(in thousands)
 
 
 
 
 
 
 
December 31,
 
 
 
2013 
 
2012 
 
CURRENT ASSETS
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 2,745 
 
$
 3,576 
 
Advances to Affiliates
 
 
 92,485 
 
 
 23,024 
 
Accounts Receivable:
 
 
 
 
 
 
 
 
Customers
 
 
 142,010 
 
 
 158,380 
 
 
Affiliated Companies
 
 
 113,793 
 
 
 96,213 
 
 
Accrued Unbilled Revenues
 
 
 55,930 
 
 
 70,825 
 
 
Miscellaneous
 
 
 412 
 
 
 1,344 
 
 
Allowance for Uncollectible Accounts
 
 
 (2,443)
 
 
 (6,087)
 
 
 
Total Accounts Receivable
 
 
 309,702 
 
 
 320,675 
 
Fuel
 
 
 191,811 
 
 
 185,813 
 
Materials and Supplies
 
 
 128,843 
 
 
 105,208 
 
Risk Management Assets
 
 
 21,171 
 
 
 30,960 
 
Accrued Tax Benefits
 
 
 97 
 
 
 50,032 
 
Regulatory Asset for Under-Recovered Fuel Costs
 
 
 39,811 
 
 
 74,906 
 
Prepayments and Other Current Assets
 
 
 16,375 
 
 
 18,690 
 
TOTAL CURRENT ASSETS
 
 
 803,040 
 
 
 812,884 
 
 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
 
Generation
 
 
 6,745,172 
 
 
 5,632,665 
 
 
Transmission
 
 
 2,160,660 
 
 
 2,042,144 
 
 
Distribution
 
 
 3,139,150 
 
 
 2,991,898 
 
Other Property, Plant and Equipment
 
 
 357,517 
 
 
 373,327 
 
Construction Work in Progress
 
 
 184,701 
 
 
 266,247 
 
Total Property, Plant and Equipment
 
 
 12,587,200 
 
 
 11,306,281 
 
Accumulated Depreciation and Amortization
 
 
 3,617,990 
 
 
 3,196,639 
 
TOTAL PROPERTY, PLANT AND EQUIPMENT NET
 
 
 8,969,210 
 
 
 8,109,642 
 
 
 
 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
 
Regulatory Assets
 
 
 1,003,890 
 
 
 1,435,704 
 
Securitized Assets
 
 
 369,355 
 
 
 - 
 
Long-term Risk Management Assets
 
 
 16,948 
 
 
 34,360 
 
Deferred Charges and Other Noncurrent Assets
 
 
 148,205 
 
 
 115,078 
 
TOTAL OTHER NONCURRENT ASSETS
 
 
 1,538,398 
 
 
 1,585,142 
 
 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 11,310,648 
 
$
 10,507,668 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
163

 
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
December 31, 2013 and 2012
 
 
 
 
 
 
 
December 31,
 
 
 
2013 
 
2012 
 
 
 
 
(in thousands)
 
CURRENT LIABILITIES
 
 
 
 
 
 
 
Advances from Affiliates
 
$
 - 
 
$
 173,965 
 
Accounts Payable:
 
 
 
 
 
 
 
 
General
 
 
 169,184 
 
 
 195,203 
 
 
Affiliated Companies
 
 
 120,789 
 
 
 137,088 
 
Long-term Debt Due Within One Year – Nonaffiliated
 
 
 342,360 
 
 
 574,679 
 
Risk Management Liabilities
 
 
 8,892 
 
 
 16,698 
 
Customer Deposits
 
 
 66,040 
 
 
 67,339 
 
Deferred Income Taxes
 
 
 6,899 
 
 
 11,715 
 
Accrued Taxes
 
 
 114,699 
 
 
 74,967 
 
Accrued Interest
 
 
 51,899 
 
 
 51,442 
 
Regulatory Liability for Over-Recovered Fuel Costs
 
 
 107,048 
 
 
 - 
 
Other Current Liabilities
 
 
 97,566 
 
 
 110,657 
 
TOTAL CURRENT LIABILITIES
 
 
 1,085,376 
 
 
 1,413,753 
 
 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
 
Long-term Debt – Nonaffiliated
 
 
 3,765,997 
 
 
 3,127,763 
 
Long-term Debt – Affiliated
 
 
 86,000 
 
 
 - 
 
Long-term Risk Management Liabilities
 
 
 10,241 
 
 
 18,476 
 
Deferred Income Taxes
 
 
 2,232,441 
 
 
 1,928,683 
 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 631,225 
 
 
 607,680 
 
Employee Benefits and Pension Obligations
 
 
 82,264 
 
 
 204,207 
 
Deferred Credits and Other Noncurrent Liabilities
 
 
 187,672 
 
 
 154,544 
 
TOTAL NONCURRENT LIABILITIES
 
 
 6,995,840 
 
 
 6,041,353 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 8,081,216 
 
 
 7,455,106 
 
 
 
 
 
 
 
 
 
Rate Matters (Note 3)
 
 
 
 
 
 
 
Commitments and Contingencies (Note 5)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMMON SHAREHOLDER’S EQUITY
 
 
 
 
 
 
 
Common Stock – No Par Value:
 
 
 
 
 
 
 
 
Authorized – 30,000,000 Shares
 
 
 
 
 
 
 
 
Outstanding  – 13,499,500 Shares
 
 
 260,458 
 
 
 260,458 
 
Paid-in Capital
 
 
 1,809,562 
 
 
 1,573,752 
 
Retained Earnings
 
 
 1,156,461 
 
 
 1,248,250 
 
Accumulated Other Comprehensive Income (Loss)
 
 
 2,951 
 
 
 (29,898)
 
TOTAL COMMON SHAREHOLDER’S EQUITY
 
 
 3,229,432 
 
 
 3,052,562 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER’S EQUITY
 
$
 11,310,648 
 
$
 10,507,668 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
164

 
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2013, 2012 and 2011
(in thousands)
 
 
 
 
 
 
Years Ended December 31,
 
 
2013 
 
2012 
 
2011 
OPERATING ACTIVITIES
 
 
 
 
 
 
 
 
 
Net Income
 
$
 193,211 
 
$
 257,503 
 
$
 162,758 
Adjustments to Reconcile Net Income to Net Cash Flows from
 
 
 
 
 
 
 
 
 
 
Operating Activities:
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 342,643 
 
 
 344,293 
 
 
 270,529 
 
 
Deferred Income Taxes
 
 
 75,714 
 
 
 138,460 
 
 
 107,565 
 
 
Asset Impairments and Other Related Charges
 
 
 39,283 
 
 
 - 
 
 
 - 
 
 
Carrying Costs Income
 
 
 (8,086)
 
 
 (24,602)
 
 
 (13,433)
 
 
Deferral of Storm Costs
 
 
 36,068 
 
 
 (87,992)
 
 
 (16,324)
 
 
Allowance for Equity Funds Used During Construction
 
 
 (2,353)
 
 
 (1,684)
 
 
 (9,212)
 
 
Mark-to-Market of Risk Management Contracts
 
 
 12,288 
 
 
 10,130 
 
 
 (26)
 
 
Pension Contributions to Qualified Plan Trust
 
 
 - 
 
 
 (25,199)
 
 
 (60,312)
 
 
Fuel Over/Under-Recovery, Net
 
 
 59,174 
 
 
 96,774 
 
 
 (9,589)
 
 
Change in Regulatory Assets
 
 
 (10,108)
 
 
 (31,104)
 
 
 (3,031)
 
 
Change in Other Noncurrent Assets
 
 
 (22,894)
 
 
 (21,724)
 
 
 (2,402)
 
 
Change in Other Noncurrent Liabilities
 
 
 15,707 
 
 
 24,206 
 
 
 10,392 
 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 12,470 
 
 
 42,161 
 
 
 59,352 
 
 
 
Fuel, Materials and Supplies
 
 
 28,042 
 
 
 (40,268)
 
 
 80,191 
 
 
 
Accounts Payable
 
 
 (31,951)
 
 
 12,547 
 
 
 (60,843)
 
 
 
Accrued Taxes, Net
 
 
 81,228 
 
 
 (14,396)
 
 
 71,610 
 
 
 
Other Current Assets
 
 
 5,626 
 
 
 3,706 
 
 
 15,570 
 
 
 
Other Current Liabilities
 
 
 (11,667)
 
 
 7,234 
 
 
 3,933 
Net Cash Flows from Operating Activities
 
 
 814,395 
 
 
 690,045 
 
 
 606,728 
 
 
 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
 
 
 
Construction Expenditures
 
 
 (380,974)
 
 
 (469,052)
 
 
 (463,077)
Change in Advances to Affiliates, Net
 
 
 (69,461)
 
 
 (1,016)
 
 
 (22,008)
Acquisitions of Assets
 
 
 (1,744)
 
 
 (1,183)
 
 
 (302,512)
Other Investing Activities
 
 
 513 
 
 
 8,392 
 
 
 15,096 
Net Cash Flows Used for Investing Activities
 
 
 (451,666)
 
 
 (462,859)
 
 
 (772,501)
 
 
 
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
 
 
 
Capital Contribution from Parent
 
 
 - 
 
 
 - 
 
 
 100,000 
Issuance of Long-term Debt – Nonaffiliated
 
 
 444,437 
 
 
 339,374 
 
 
 739,393 
Change in Advances from Affiliates, Net
 
 
 (173,965)
 
 
 (24,283)
 
 
 69,917 
Retirement of Long-term Debt – Nonaffiliated
 
 
 (345,029)
 
 
 (364,875)
 
 
 (579,672)
Retirement of Cumulative Preferred Stock
 
 
 - 
 
 
 - 
 
 
 (19,517)
Principal Payments for Capital Lease Obligations
 
 
 (5,550)
 
 
 (6,496)
 
 
 (7,447)
Dividends Paid on Common Stock
 
 
 (285,000)
 
 
 (170,000)
 
 
 (135,000)
Dividends Paid on Cumulative Preferred Stock
 
 
 - 
 
 
 - 
 
 
 (732)
Other Financing Activities
 
 
 1,547 
 
 
 353 
 
 
 197 
Net Cash Flows from (Used for) Financing Activities
 
 
 (363,560)
 
 
 (225,927)
 
 
 167,139 
 
 
 
 
 
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 (831)
 
 
 1,259 
 
 
 1,366 
Cash and Cash Equivalents at Beginning of Period
 
 
 3,576 
 
 
 2,317 
 
 
 951 
Cash and Cash Equivalents at End of Period
 
$
 2,745 
 
$
 3,576 
 
$
 2,317 
 
 
 
 
 
 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
 
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 184,584 
 
$
 200,383 
 
$
 198,465 
Net Cash Paid (Received) for Income Taxes
 
 
 (27,759)
 
 
 31,418 
 
 
 (66,520)
Noncash Acquisitions Under Capital Leases
 
 
 4,351 
 
 
 3,366 
 
 
 2,692 
Government Grants Included in Accounts Receivable as of December 31,
 
 
 - 
 
 
 - 
 
 
 1,048 
Construction Expenditures Included in Current Liabilities as of December 31,
 
 
 50,829 
 
 
 62,177 
 
 
 65,308 
Noncash Contribution of Amos Plant from Parent
 
 
 235,810 
 
 
 - 
 
 
 - 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.
 
 
 

 
165

 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to APCo’s financial statements are combined with the notes to financial statements for other registrant subsidiaries.  Listed below are the notes that apply to APCo.  The footnotes begin on page 227.

 
Page
Number
   
Organization and Summary of Significant Accounting Policies
  228
Comprehensive Income
  240
Rate Matters
  249
Effects of Regulation
  259
Commitments, Guarantees and Contingencies
  265
Acquisition, Disposition and Impairments
  271
Benefit Plans
  273
Business Segments
  308
Derivatives and Hedging
  308
Fair Value Measurements
  323
Income Taxes
  334
Leases
  342
Financing Activities
  346
Related Party Transactions
  352
Variable Interest Entities
  360
Property, Plant and Equipment
  366
Sustainable Cost Reductions
  374
Unaudited Quarterly Financial Information
  375

 
166

 










INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES


 
167

 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

As a public utility, I&M engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 587,000 retail customers in its service territory in northern and eastern Indiana and a portion of southwestern Michigan.  I&M consolidates Blackhawk Coal Company and Price River Coal Company, its wholly-owned subsidiaries.  I&M also consolidates DCC Fuel.  I&M sells power at wholesale to municipalities and electric cooperatives.  I&M’s River Transportation Division provides barging services to affiliates and nonaffiliated companies.  The revenues from barging represent the majority of other revenues.

In accordance with management’s December 2010 announcement and an October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014.  The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated.

Effective January 1, 2014, the FERC approved a PCA among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.  Under the PCA, APCo, I&M and KPCo will be individually responsible for planning their respective capacity obligations and there will be no capacity equalization charges/credits on deficit/surplus companies.   Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities.

Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent.  The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies will fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year.  Under the Bridge Agreement, AGR is committed to meet capacity obligations of member companies.

Effective January 1, 2014, AEPSC conducts power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M and KPCo.  Power and natural gas risk management activities are allocated based on the three member companies’ respective equity positions and the SIA.  I&M shared in coal risk management activities based on its proportion of fossil fuels burned by the AEP System.  Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and, to a lesser extent, the purchase and sale of natural gas and coal.  The power, natural gas and coal contracts include physical transactions, OTC options and financially-settled swaps and exchange-traded futures and options.  AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts.  For contracts entered and settled prior to January 1, 2014, power and natural gas risk management activities were allocated based on the Interconnection Agreement and the SIA.  For contracts entered prior to January 1, 2014 and settled after January 1, 2014, power and natural gas risk management activities are allocated based on frozen MLR ratios as of December 31, 2013.  I&M shared in the revenues and expenses associated with these risk management activities with the other AEP East Companies, PSO and SWEPCo.

Under a unit power agreement, I&M purchases AEGCo’s 50% share of the 2,620 MW Rockport Plant capacity unless it is sold to other utilities.  Another unit power agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo’s Rockport Plant capacity to KPCo through 2022.  Under these agreements, I&M purchases 910 MW of AEGCo’s 50% share of Rockport Plant capacity.

Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East Companies and trading and marketing activities originating in SPP generally accruing to the benefit of PSO and SWEPCo.  Margins resulting from other transactions are allocated among the AEP East Companies, PSO and SWEPCo in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months.

 
168

 
 
Prior to January 1, 2014, the Interconnection Agreement permitted the AEP East Companies to pool their generation assets on a cost basis.  It established an allocation method for generating capacity among its members based on relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity revenues.  Members of the Interconnection Agreement were compensated for their costs of energy delivered and charged for energy received.  The capacity reserve relationship of the Interconnection Agreement members changed as generating assets were added, retired or sold and relative peak demand changed.  The Interconnection Agreement calculated each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs.  The result of this calculation was the MLR, which determined each member’s percentage share of revenues and costs.

To minimize the credit requirements and operating constraints when operating within PJM, participating AEP companies, including I&M, agreed to a netting of all payment obligations incurred by any of the AEP companies against all balances due to the AEP companies and to hold PJM harmless from actions that any one or more AEP companies may take with respect to PJM.

I&M is jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity pursuant to the SIA.

Regulatory Activity

2011 Indiana Base Rate Case

In 2013, the IURC issued an order that granted a $92 million annual increase in base rates based upon a return on common equity of 10.2%.  In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal of the orders with the Indiana Court of Appeals.  In September 2013, the OUCC filed a brief on appeal that included objections to certain aspects of the rate case.  If any part of the IURC order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.  See the “2011 Indiana Base Rate Case” section of Note 3.

Rockport Plant Clean Coal Technology Project (CCT Project)

In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both units of the Rockport Plant with a dry sorbent injection system.  The estimated cost in the application was $285 million, excluding AFUDC to be shared equally between I&M and AEGCo.  In November 2013, the IURC approved a settlement agreement that included the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M’s ownership share.  As of December 31, 2013, I&M has incurred costs of $56 million related to the CCT Project, including AFUDC.  See the “Rockport Plant Clean Coal Technology Project (CCT Project)” section of Note 3.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its licensed life (2034 for Unit 1 and 2037 for Unit 2).  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of December 31, 2013, I&M has incurred costs of $380 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items which the IURC stated I&M could seek recovery of in a subsequent base rate case.  I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings.  The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates.  In October 2013, I&M filed an application with the IURC for LCM rider rates to be effective January 2014.  In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC.

 
169

 
 
In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to certain projects effective January 2013 until these costs are included in rates.  In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON.  If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.  See “Cook Plant Life Cycle Management Project (LCM Project)” section of Note 3.

Litigation and Environmental Issues

In the ordinary course of business, I&M is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

Rockport Plant Litigation

In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit.  The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement.  The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff.  The New York court has granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio.  A motion to dismiss the case, filed in October 2013, is pending.  Management will continue to defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 376 for additional discussion of relevant factors.

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
 
(in millions of KWhs)
Retail:
 
 
 
 
 
 
 
 
 
Residential
 
 5,778 
 
 
 5,771 
 
 
 5,997 
 
Commercial
 
 4,943 
 
 
 5,001 
 
 
 5,045 
 
Industrial
 
 7,522 
 
 
 7,556 
 
 
 7,523 
 
Miscellaneous
 
 72 
 
 
 75 
 
 
 73 
Total Retail
 
 18,315 
 
 
 18,403 
 
 
 18,638 
 
 
 
 
 
 
 
 
 
Wholesale
 
 10,499 
 
 
 9,782 
 
 
 9,249 
 
 
 
 
 
 
 
 
 
Total KWhs
 
 28,814 
 
 
 28,185 
 
 
 27,887 


 
170

 
 
Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.

Summary of Heating and Cooling Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
 
 
 
(in degree days)
 
Actual - Heating (a)
 
 4,076 
 
 
 3,042 
 
 
 3,659 
 
Normal - Heating (b)
 
 3,730 
 
 
 3,772 
 
 
 3,766 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 826 
 
 
 1,098 
 
 
 1,075 
 
Normal - Cooling (b)
 
 855 
 
 
 861 
 
 
 848 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Eastern Region heating degree days are calculated on a 55 degree temperature base.
 
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
 
(c)
Eastern Region cooling degree days are calculated on a 65 degree temperature base.

 
171

 
 
2013 Compared to 2012
 
 
 
 
 
 
 
 
 
 
 
 
Reconciliation of Year Ended December 31, 2012 to Year Ended December 31, 2013
 
Net Income
 
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2012
 
 
 
 
$
 118 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
 
 
 
 
 
Retail Margins
 
 
 
 
 
 84 
 
 
 
FERC Municipals and Cooperatives
 
 
 
 
 
 36 
 
 
 
Off-system Sales
 
 
 
 
 
 (9)
 
 
 
Transmission Revenues
 
 
 
 
 
 3 
 
 
 
Other Revenues
 
 
 
 
 
 3 
 
 
 
Total Change in Gross Margin
 
 
 
 
 
 117 
 
 
 
 
 
 
 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
 
 
 
 
 
Other Operation and Maintenance
 
 
 
 
 
 (3)
 
 
 
Depreciation and Amortization
 
 
 
 
 
 (31)
 
 
 
Taxes Other Than Income Taxes
 
 
 
 
 
 (8)
 
 
 
Other Income
 
 
 
 
 
 16 
 
 
 
Interest Expense
 
 
 
 
 
 5 
 
 
 
Total Change in Expenses and Other
 
 
 
 
 
 (21)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 
 
 
 (36)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2013
 
 
 
 
$
 178 
 

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:

 
·
Retail Margins increased $84 million primarily due to an increase of $56 million from a rate increase in Indiana effective March 2013, higher PJM revenue and higher Indiana Demand Side Management (DSM) revenue.  The PJM and DSM increases were partially offset in expense items below.
 
·
Margins from FERC Municipals and Cooperatives increased $36 million primarily due to the annual true-up adjustment of formula rates to actual costs and higher formula rates for 2013.
 
·
Margins from Off-system Sales decreased $9 million primarily due to lower PJM capacity revenues, reduced trading and marketing margins and true-up of prior period PJM expenses.
 
Expenses and Other and Income Tax Expense changed between years as follows:
 
 
·
Other Operation and Maintenance expenses increased $3 million primarily due to the following:
    · A $15 million increase in transmission expenses primarily due to increased PJM expenses.  The increase in PJM expenses are partially offset by a corresponding increase in Retail Margins discussed above.
    · An $8 million increase in customer service expenses primarily due to higher DSM expenses.  The increase in DSM expenses was offset by a corresponding increase in Retail Margins discussed above.
    These increases were partially offset by:
    · A $12 million decrease in administrative and general operation expenses primarily related to employee benefit expenses.
    · A $9 million decrease in accretion expense due to lower recovery from Indiana customers of decommissioning Asset Retirement Obligation (ARO) accretion and depreciation and an increase in deferral of decommissioning ARO costs.  The lower recovery is offset in revenues and the increase in deferral is offset in Depreciation and Amortization expense.
  · Depreciation and Amortization increased $31 million primarily due to the following:
    · A $26 million increase primarily due to higher depreciable base and higher depreciation rates reflecting a change in Tanners Creek Plant’s estimated life as approved in the Michigan base case settlement effective April 2012 and by the IURC effective March 2013.  The majority of the increase in depreciation for Tanners Creek Plant’s life is offset within Gross Margin.
 
 
172

 
 
    · A $5 million increase in ARO depreciation expense due to higher depreciation rates specified in the Indiana rate order in March 2013.  This increase is offset by an increased deferral in accretion expense within Other Operation and Maintenance.
 
·
Other Income increased $16 million primarily due to an increase in the equity component of AFUDC.
 
·
Interest Expense decreased $5 million primarily due to an increase in the debt component of AFUDC related to projects at the Cook Plant.
  · Income Tax Expense increased $36 million primarily due to an increase in pretax book income. 
 
CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 376 for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 376 for a discussion of accounting pronouncements.

 
173

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of
Indiana Michigan Power Company:

We have audited the accompanying consolidated balance sheets of Indiana Michigan Power Company and subsidiaries (the "Company") as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income (loss), changes in common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

/s/  Deloitte & Touche LLP

Columbus, Ohio
February 25, 2014

 
174

 

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Indiana Michigan Power Company and subsidiaries (I&M) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  I&M’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of I&M’s internal control over financial reporting as of December 31, 2013.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 1992) in Internal Control – Integrated Framework.  Based on management’s assessment, I&M’s internal control over financial reporting was effective as of December 31, 2013.

This annual report does not include an attestation report of I&M’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit I&M to provide only management’s report in this annual report.

 
175

 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2013, 2012 and 2011
(in thousands)
 
 
 
 
 
 
Years Ended December 31,
 
 
 
 
2013 
 
2012 
 
2011 
 
 
REVENUES
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission and Distribution
 
$
 2,022,257 
 
$
 1,810,069 
 
$
 1,770,447 
 
 
Sales to AEP Affiliates
 
 
 219,399 
 
 
 268,408 
 
 
 320,184 
 
 
Other Revenues - Affiliated
 
 
 122,287 
 
 
 117,052 
 
 
 109,053 
 
 
Other Revenues - Nonaffiliated
 
 
 2,916 
 
 
 4,582 
 
 
 15,086 
 
 
TOTAL REVENUES
 
 
 2,366,859 
 
 
 2,200,111 
 
 
 2,214,770 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EXPENSES
 
 
 
 
 
 
 
 
 
 
 
Fuel and Other Consumables Used for Electric Generation
 
 
 434,078 
 
 
 464,420 
 
 
 472,080 
 
 
Purchased Electricity for Resale
 
 
 151,404 
 
 
 117,860 
 
 
 121,375 
 
 
Purchased Electricity from AEP Affiliates
 
 
 433,209 
 
 
 386,404 
 
 
 353,484 
 
 
Other Operation
 
 
 564,012 
 
 
 583,865 
 
 
 540,595 
 
 
Maintenance
 
 
 195,892 
 
 
 172,562 
 
 
 229,883 
 
 
Depreciation and Amortization
 
 
 177,727 
 
 
 146,619 
 
 
 133,394 
 
 
Taxes Other Than Income Taxes
 
 
 88,676 
 
 
 80,687 
 
 
 82,303 
 
 
TOTAL EXPENSES
 
 
 2,044,998 
 
 
 1,952,417 
 
 
 1,933,114 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
 
 321,861 
 
 
 247,694 
 
 
 281,656 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 8,521 
 
 
 3,122 
 
 
 2,048 
 
 
Allowance for Equity Funds Used During Construction
 
 
 19,943 
 
 
 9,724 
 
 
 15,395 
 
 
Interest Expense
 
 
 (97,710)
 
 
 (102,739)
 
 
 (97,665)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE
 
 
 252,615 
 
 
 157,801 
 
 
 201,434 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 75,111 
 
 
 39,344 
 
 
 51,760 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME
 
 
 177,504 
 
 
 118,457 
 
 
 149,674 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred Stock Dividend Requirements Including Capital Stock Expense
 
 
 - 
 
 
 - 
 
 
 626 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO COMMON STOCK
 
$
 177,504 
 
$
 118,457 
 
$
 149,048 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
The common stock of I&M is wholly-owned by AEP.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
176

 
 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2013, 2012 and 2011
 (in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
Net Income
 
$
 177,504 
 
$
 118,457 
 
$
 149,674 
 
 
 
 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $2,242, $2,590 and $3,553 in 2013, 2012 and
 
 
 
 
 
 
 
 
 
 
2011, Respectively
 
 
 4,163 
 
 
 (4,809)
 
 
 (6,599)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $377, $598 and
 
 
 
 
 
 
 
 
 
 
$510 in 2013, 2012 and 2011, Respectively
 
 
 700 
 
 
 1,113 
 
 
 948 
Pension and OPEB Funded Status, Net of Tax of $4,583, $1,634 and $906 in 2013,
 
 
 
 
 
 
 
 
 
 
2012 and 2011, Respectively
 
 
 8,511 
 
 
 3,034 
 
 
 (1,681)
 
 
 
 
 
 
 
 
 
 
 
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
 
 
 13,374 
 
 
 (662)
 
 
 (7,332)
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
 
$
 190,878 
 
$
 117,795 
 
$
 142,342 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
177

 
 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY
For the Years Ended December 31, 2013, 2012 and 2011
(in thousands)
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
 
 
 
 
Stock
 
Capital
 
Earnings
 
Income (Loss)
 
 
Total
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2010
 
 56,584 
 
 981,294 
 
 677,360 
 
 (20,889)
 
 1,694,349 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (75,000)
 
 
 
 
 
 (75,000)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (313)
 
 
 
 
 
 (313)
Loss on Reacquired Preferred Stock
 
 
 
 
 
 (398)
 
 
 
 
 
 
 
 
 (398)
Net Income
 
 
 
 
 
 
 
 
 149,674 
 
 
 
 
 
 149,674 
Other Comprehensive Loss
 
 
 
 
 
 
 
 
 
 
 
 (7,332)
 
 
 (7,332)
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2011
 
 
 56,584 
 
 
 980,896 
 
 
 751,721 
 
 
 (28,221)
 
 
 1,760,980 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (75,000)
 
 
 
 
 
 (75,000)
Net Income
 
 
 
 
 
 
 
 
 118,457 
 
 
 
 
 
 118,457 
Other Comprehensive Loss
 
 
 
 
 
 
 
 
 
 
 
 (662)
 
 
 (662)
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2012
 
 
 56,584 
 
 
 980,896 
 
 
 795,178 
 
 
 (28,883)
 
 
 1,803,775 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (72,500)
 
 
 
 
 
 (72,500)
Net Income
 
 
 
 
 
 
 
 
 177,504 
 
 
 
 
 
 177,504 
Other Comprehensive Income
 
 
 
 
 
 
 
 
 
 
 
 13,374 
 
 
 13,374 
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2013
 
 56,584 
 
 980,896 
 
 900,182 
 
 (15,509)
 
 1,922,153 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
178

 
 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2013 and 2012
(in thousands)
 
 
 
 
 
 
 
December 31,
 
 
 
2013 
 
2012 
 
CURRENT ASSETS
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 1,317 
 
$
 1,562 
 
Advances to Affiliates
 
 
 55,863 
 
 
 116,977 
 
Accounts Receivable:
 
 
 
 
 
 
 
 
Customers
 
 
 63,011 
 
 
 61,776 
 
 
Affiliated Companies
 
 
 78,282 
 
 
 79,886 
 
 
Accrued Unbilled Revenues
 
 
 17,293 
 
 
 11,218 
 
 
Miscellaneous
 
 
 5,064 
 
 
 12,260 
 
 
Allowance for Uncollectible Accounts
 
 
 (184)
 
 
 (229)
 
 
 
Total Accounts Receivable
 
 
 163,466 
 
 
 164,911 
 
Fuel
 
 
 53,807 
 
 
 53,406 
 
Materials and Supplies
 
 
 209,718 
 
 
 195,147 
 
Risk Management Assets
 
 
 15,388 
 
 
 26,974 
 
Accrued Tax Benefits
 
 
 48,832 
 
 
 20,547 
 
Deferred Cook Plant Fire Costs
 
 
 - 
 
 
 80,000 
 
Prepayments and Other Current Assets
 
 
 38,103 
 
 
 62,723 
 
TOTAL CURRENT ASSETS
 
 
 586,494 
 
 
 722,247 
 
 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
 
Generation
 
 
 3,577,906 
 
 
 4,062,733 
 
 
Transmission
 
 
 1,304,225 
 
 
 1,278,236 
 
 
Distribution
 
 
 1,625,057 
 
 
 1,553,358 
 
Other Property, Plant and Equipment (Including Plant to be Retired, Coal Mining
 
 
 
 
 
 
 
 
and Nuclear Fuel)
 
 
 1,421,361 
 
 
 725,313 
 
Construction Work in Progress
 
 
 427,164 
 
 
 341,063 
 
Total Property, Plant and Equipment
 
 
 8,355,713 
 
 
 7,960,703 
 
Accumulated Depreciation, Depletion and Amortization
 
 
 3,299,349 
 
 
 3,232,135 
 
TOTAL PROPERTY, PLANT AND EQUIPMENT NET
 
 
 5,056,364 
 
 
 4,728,568 
 
 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
 
Regulatory Assets
 
 
 524,114 
 
 
 540,019 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 1,931,610 
 
 
 1,705,772 
 
Long-term Risk Management Assets
 
 
 11,495 
 
 
 23,569 
 
Deferred Charges and Other Noncurrent Assets
 
 
 143,657 
 
 
 111,364 
 
TOTAL OTHER NONCURRENT ASSETS
 
 
 2,610,876 
 
 
 2,380,724 
 
 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 8,253,734 
 
$
 7,831,539 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
179

 
 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
December 31, 2013 and 2012
(dollars in thousands)
 
 
 
 
 
 
 
December 31,
 
 
 
2013 
 
2012 
 
CURRENT LIABILITIES
 
 
 
 
Accounts Payable:
 
 
 
 
 
 
 
 
General
 
$
 142,219 
 
$
 208,701 
 
 
Affiliated Companies
 
 
 93,773 
 
 
 104,631 
 
Long-term Debt Due Within One Year – Nonaffiliated
 
 
 
 
 
 
 
 
(December 31, 2013 and 2012 Amounts Include $107,143 and $119,890
 
 
 
 
 
 
 
 
Respectively, Related to DCC Fuel)
 
 
 294,845 
 
 
 203,953 
 
Risk Management Liabilities
 
 
 7,029 
 
 
 31,517 
 
Customer Deposits
 
 
 31,103 
 
 
 31,142 
 
Accrued Taxes
 
 
 73,292 
 
 
 67,675 
 
Accrued Interest
 
 
 27,686 
 
 
 26,859 
 
Obligations Under Capital Leases
 
 
 46,210 
 
 
 5,803 
 
Other Current Liabilities
 
 
 139,088 
 
 
 116,250 
 
TOTAL CURRENT LIABILITIES
 
 
 855,245 
 
 
 796,531 
 
 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
 
Long-term Debt – Nonaffiliated
 
 
 1,744,171 
 
 
 1,853,713 
 
Long-term Risk Management Liabilities
 
 
 6,946 
 
 
 13,898 
 
Deferred Income Taxes
 
 
 1,183,350 
 
 
 1,019,160 
 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 1,112,645 
 
 
 948,292 
 
Asset Retirement Obligations
 
 
 1,255,184 
 
 
 1,192,313 
 
Deferred Credits and Other Noncurrent Liabilities
 
 
 174,040 
 
 
 203,857 
 
TOTAL NONCURRENT LIABILITIES
 
 
 5,476,336 
 
 
 5,231,233 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 6,331,581 
 
 
 6,027,764 
 
 
 
 
 
 
 
 
 
Rate Matters (Note 3)
 
 
 
 
 
 
 
Commitments and Contingencies (Note 5)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMMON SHAREHOLDER’S EQUITY
 
 
 
 
 
 
 
Common Stock – No Par Value:
 
 
 
 
 
 
 
 
Authorized – 2,500,000 Shares
 
 
 
 
 
 
 
 
Outstanding  – 1,400,000 Shares
 
 
 56,584 
 
 
 56,584 
 
Paid-in Capital
 
 
 980,896 
 
 
 980,896 
 
Retained Earnings
 
 
 900,182 
 
 
 795,178 
 
Accumulated Other Comprehensive Income (Loss)
 
 
 (15,509)
 
 
 (28,883)
 
TOTAL COMMON SHAREHOLDER’S EQUITY
 
 
 1,922,153 
 
 
 1,803,775 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
 8,253,734 
 
$
 7,831,539 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
180

 
 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2013, 2012 and 2011
(in thousands)
 
 
 
 
 
 
Years Ended December 31,
 
 
2013 
 
2012 
 
2011 
OPERATING ACTIVITIES
 
 
 
 
 
 
 
 
 
Net Income
 
$
 177,504 
 
$
 118,457 
 
$
 149,674 
Adjustments to Reconcile Net Income to Net Cash Flows from
 
 
 
 
 
 
 
 
 
 
Operating Activities:
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 177,727 
 
 
 146,619 
 
 
 133,394 
 
 
Accretion of Asset Retirement Obligations
 
 
 2,815 
 
 
 11,712 
 
 
 11,668 
 
 
Deferred Income Taxes
 
 
 129,109 
 
 
 53,067 
 
 
 141,015 
 
 
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net
 
 
 (31,328)
 
 
 13,899 
 
 
 13,244 
 
 
Allowance for Equity Funds Used During Construction
 
 
 (19,943)
 
 
 (9,724)
 
 
 (15,395)
 
 
Mark-to-Market of Risk Management Contracts
 
 
 12,496 
 
 
 12,164 
 
 
 (1,590)
 
 
Amortization of Nuclear Fuel
 
 
 130,629 
 
 
 135,905 
 
 
 136,707 
 
 
Pension Contributions to Qualified Plan Trust
 
 
 - 
 
 
 (22,285)
 
 
 (52,588)
 
 
Fuel Over/Under-Recovery, Net
 
 
 3,254 
 
 
 4,175 
 
 
 (13,885)
 
 
Change in Other Noncurrent Assets
 
 
 (57,106)
 
 
 (2,347)
 
 
 (22,977)
 
 
Change in Other Noncurrent Liabilities
 
 
 34,495 
 
 
 47,097 
 
 
 50,371 
 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 1,445 
 
 
 34,431 
 
 
 57,661 
 
 
 
Fuel, Materials and Supplies
 
 
 (8,848)
 
 
 (19,321)
 
 
 40,239 
 
 
 
Accounts Payable
 
 
 (11,151)
 
 
 15,959 
 
 
 (52,175)
 
 
 
Accrued Taxes, Net
 
 
 (23,887)
 
 
 16,897 
 
 
 15,508 
 
 
 
Cook Plant Fire Costs, Net
 
 
 - 
 
 
 (8,465)
 
 
 18,282 
 
 
 
Other Current Assets
 
 
 21,287 
 
 
 (2,039)
 
 
 6,409 
 
 
 
Other Current Liabilities
 
 
 575 
 
 
 11,717 
 
 
 6,167 
Net Cash Flows from Operating Activities
 
 
 539,073 
 
 
 557,918 
 
 
 621,729 
 
 
 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
 
 
 
Construction Expenditures
 
 
 (508,857)
 
 
 (317,284)
 
 
 (301,242)
Change in Advances to Affiliates, Net
 
 
 61,114 
 
 
 (21,263)
 
 
 (95,714)
Purchases of Investment Securities
 
 
 (909,998)
 
 
 (1,045,422)
 
 
 (1,166,690)
Sales of Investment Securities
 
 
 858,406 
 
 
 987,550 
 
 
 1,110,909 
Acquisitions of Nuclear Fuel
 
 
 (153,730)
 
 
 (106,714)
 
 
 (105,703)
Insurance Proceeds Related to Cook Plant Fire
 
 
 72,000 
 
 
 - 
 
 
 - 
Other Investing Activities
 
 
 32,635 
 
 
 29,324 
 
 
 47,169 
Net Cash Flows Used for Investing Activities
 
 
 (548,430)
 
 
 (473,809)
 
 
 (511,271)
 
 
 
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
 
 
 
Issuance of Long-term Debt - Nonaffiliated
 
 
 348,874 
 
 
 217,900 
 
 
 185,972 
Change in Advances from Affiliates, Net
 
 
 - 
 
 
 - 
 
 
 (42,769)
Retirement of Long-term Debt - Nonaffiliated
 
 
 (370,338)
 
 
 (220,212)
 
 
 (160,645)
Retirement of Cumulative Preferred Stock
 
 
 - 
 
 
 - 
 
 
 (8,470)
Proceeds from Nuclear Fuel Sale/Leaseback
 
 
 110,200 
 
 
 - 
 
 
 - 
Principal Payments for Capital Lease Obligations
 
 
 (8,030)
 
 
 (6,536)
 
 
 (8,652)
Dividends Paid on Common Stock
 
 
 (72,500)
 
 
 (75,000)
 
 
 (75,000)
Dividends Paid on Cumulative Preferred Stock
 
 
 - 
 
 
 - 
 
 
 (313)
Other Financing Activities
 
 
 906 
 
 
 281 
 
 
 78 
Net Cash Flows from (Used for) Financing Activities
 
 
 9,112 
 
 
 (83,567)
 
 
 (109,799)
 
 
 
 
 
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 (245)
 
 
 542 
 
 
 659 
Cash and Cash Equivalents at Beginning of Period
 
 
 1,562 
 
 
 1,020 
 
 
 361 
Cash and Cash Equivalents at End of Period
 
$
 1,317 
 
$
 1,562 
 
$
 1,020 
 
 
 
 
 
 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
 
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 90,079 
 
$
 98,130 
 
$
 95,124 
Net Cash Paid (Received) for Income Taxes
 
 
 (31,271)
 
 
 (21,196)
 
 
 (96,452)
Noncash Acquisitions Under Capital Leases
 
 
 114,077 
 
 
 6,243 
 
 
 3,454 
Construction Expenditures Included in Current Liabilities as of December 31,
 
 
 85,423 
 
 
 112,622 
 
 
 42,992 
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,
 
 
 35 
 
 
 35,493 
 
 
 715 
Noncash Increase in Long-term Debt Through the Fort Wayne Lease Settlement
 
 
 - 
 
 
 - 
 
 
 26,802 
Expected Reimbursement for Capital Cost of Spent Nuclear Fuel Dry Cask Storage
 
 
 4,352 
 
 
 30,332 
 
 
 - 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
181

 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to I&M’s financial statements are combined with the notes to financial statements for other registrant subsidiaries.  Listed below are the notes that apply to I&M.  The footnotes begin on page 227.

 
Page
Number
   
Organization and Summary of Significant Accounting Policies
  228
Comprehensive Income
  240
Rate Matters
  249
Effects of Regulation
  259
Commitments, Guarantees and Contingencies
  265
Benefit Plans
  273
Business Segments
  308
Derivatives and Hedging
  308
Fair Value Measurements
  323
Income Taxes
  334
Leases
  342
Financing Activities
  346
Related Party Transactions
  352
Variable Interest Entities
  360
Property, Plant and Equipment
  366
Sustainable Cost Reductions
  374
Unaudited Quarterly Financial Information
  375

 
182

 










OHIO POWER COMPANY AND SUBSIDIARIES


 
183

 

OHIO POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

As a public utility, OPCo engages in the transmission and distribution of power to 1,464,000 retail customers in the northwestern, central, eastern and southern sections of Ohio.  OPCo purchases energy and capacity to serve its remaining generation service customers.  Prior to January 1, 2014, OPCo also engaged in the generation of electric power and the subsequent sale of that power to customers.  On December 31, 2013, based on FERC and PUCO orders which approved corporate separation of generation assets and associated liabilities, OPCo transferred its generation assets and related generation liabilities at net book value to AGR.  In accordance with the PUCO’s corporate separation order, OPCo remains responsible to provide power and capacity to OPCo customers who have not switched electric providers.  Effective January 1, 2014, OPCo will purchase power from both affiliated and nonaffiliated entities, subject to auction requirements and PUCO approval, to meet the energy and capacity needs of customers.  In April 2013 and in connection with corporate separation of OPCo’s generation assets, OPCo sold the majority of its assets related to its wholly-owned subsidiary, Conesville Coal Preparation Company (CCPC).  Also in connection with corporate separation, OPCo transferred its ownership of Cook Coal Terminal to AEGCo in August 2013.  OPCo consolidates Ohio Phase-in Recovery Funding LLC, its wholly-owned subsidiary.

In accordance with management’s December 2010 announcement and an October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014.  The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated.

Effective January 1, 2014, the FERC approved a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent.  The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies will fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year.  Under the Bridge Agreement, AGR is committed to meet capacity obligations of member companies.

Additionally, effective January 1, 2014, AGR and OPCo received approval for a Power Supply Agreement (PSA).  The PSA provides for AGR to supply capacity for OPCo’s switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that is not acquired through auctions from January 1, 2014 through December 31, 2014.

In 2007, OPCo and AEGCo entered into a 10-year unit power agreement for the entire output from the Lawrenceburg Plant with an option for an additional 2-year period.  OPCo paid AEGCo for the capacity, depreciation, fuel, operation, maintenance and tax expenses.  These payments were due regardless of whether the plant operated.  Effective January 1, 2014, OPCo assigned the unit power agreement to AGR.

Effective January 1, 2014, AEPSC conducts only gasoline, diesel fuel and FTR price risk management activities on OPCo’s behalf.  With the transfer of OPCo’s generation assets to AGR, OPCo will no longer participate in natural gas and coal risk management activities.  Prior to January 1, 2014, AEPSC also conducted power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on OPCo’s behalf.  OPCo shared in the revenues and expenses associated with these risk management activities, with the other AEP East Companies, PSO and SWEPCo.  Power and natural gas risk management activities were allocated based on the Interconnection Agreement and the SIA.  OPCo shared in coal risk management activities based on its proportion of fossil fuels burned by the AEP System.  Risk management activities primarily involved the purchase and sale of electricity under physical forward contracts at fixed and variable prices and, to a lesser extent, the purchase and sale of natural gas and coal.  The power, natural gas and coal contracts included physical transactions, OTC options and financially-settled swaps and exchange-traded futures and options.  AEPSC settled the majority of the physical forward contracts by entering into offsetting contracts.

 
184

 
 
Under the SIA, AEPSC allocated physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East Companies and trading and marketing activities originating in SPP generally accruing to the benefit of PSO and SWEPCo.  Margins resulting from other transactions are allocated among the AEP East Companies, PSO and SWEPCo in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months.

Prior to January 1, 2014, the Interconnection Agreement permitted the AEP East Companies to pool their generation assets on a cost basis.  It established an allocation method for generating capacity among its members based on relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity revenues.  Members of the Interconnection Agreement were compensated for their costs of energy delivered and charged for energy received.  The capacity reserve relationship of the Interconnection Agreement members changed as generating assets were added, retired or sold and relative peak demand changed.  The Interconnection Agreement calculates each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs.  The result of this calculation is the MLR, which determined each member’s percentage share of revenues and costs.

To minimize the credit requirements and operating constraints of operating within PJM, participating AEP companies, including OPCo, agreed to a netting of all payment obligations incurred by any of the AEP companies against all balances due to the AEP companies and to hold PJM harmless from actions that any one or more AEP companies may take with respect to PJM.

OPCo is jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity pursuant to the SIA.

Ohio Customer Choice

In OPCo’s service territory, various CRES providers are targeting retail customers by offering alternative generation service.  Prior to January 1, 2014, the reduction in gross margin as a result of customer switching in Ohio is partially offset by (a) collection of capacity revenues from CRES providers, (b) off-system sales, (c) deferral of unrecovered capacity costs and (d) Retail Stability Rider (RSR) collections.

Ormet

Ormet had a contract to purchase power from OPCo through 2018.  In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down operations effective immediately.  The loss of Ormet's load will not have a material impact on future gross margin.

Regulatory Activity

Ohio Electric Security Plan Filings

2009 – 2011 ESP

In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover OPCo’s deferred fuel costs in rates beginning September 2012.  As of December 31, 2013, OPCo’s net deferred fuel balance was $445 million, excluding unrecognized equity carrying costs.  Decisions from the Supreme Court of Ohio are pending related to various appeals which, if ordered, could reduce OPCo’s net deferred fuel costs balance.

June 2012 – May 2015 Ohio ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015, which was generally upheld in rehearing orders in January and March 2013.

 
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In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The RPM price is approximately $33/MW day through May 2014 and $148/MW day from June 2014 through May 2015.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.

As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012.  The RSR is being collected from customers at $3.50/MWh through May 2014 and will be collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs.  In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR.  As of December 31, 2013, OPCo’s incurred deferred capacity costs balance was $288 million, including debt carrying costs.

In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications.  The modifications include the delay of the energy auctions that were originally ordered in the ESP order.  OPCo must conduct an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015.  The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning November 2014 through May 2015 and for the remaining 40% of the SSO load for delivery from January 2015 through May 2015.  OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015.  The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned.  Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings.  Management believes that these intervenor concerns are without merit.  In December 2013, the PUCO granted applications for rehearing for further consideration filed by OPCo and intervenors.  In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012-2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC.

Proposed June 2015 – May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders effective June 2015 through May 2018.  This filing is consistent with the PUCO’s objective for a full transition from FAC and base generation rates to market.  The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo.  Additionally, the application identifies OPCo’s intention to submit a separate application to continue the RSR established in the June 2012 – May 2015 ESP in which the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected.  Management intends to file this application in the first quarter of 2014.

If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its deferred capacity costs, it could reduce future net income and cash flows and impact financial condition.  See “Ohio Electric Security Plan Filing” section of Note 3.

Corporate Separation, Plant Transfers and Termination of Interconnection Agreement

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets and associated generation liabilities at net book value (NBV) to AGR.  In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful.  A decision from the Supreme Court of Ohio is pending.  In December 2013, the PUCO approved OPCo’s application to amend the corporate separation plan by permitting OPCo to retain certain rights to purchase power from OVEC.  The approval is subject to the condition that energy from the OVEC entitlements are sold into the day-ahead or real-time PJM energy markets, or on a forward basis through a bilateral arrangement.  In December 2013, corporate separation of OPCo’s generation assets was completed.  See the “Corporate Separation” section of OPCo Rate Matters and the “Corporate Separation and Termination of Interconnection Agreement” section FERC Rate Matters in Note 3.
 
 
186

 
 
Securitization of Regulatory Assets

In March 2013, the PUCO approved OPCo’s request to securitize the Deferred Asset Recovery Rider (DARR) balance.  In August 2013, OPCo issued $267 million of Securitization Bonds, with a final maturity date of July 2020, to securitize the DARR balance.  As a result of the securitization, recovery through the DARR has ceased and has been replaced by the Deferred Asset Phase-in Rider which will recover the securitized assets.

Litigation and Environmental Issues

In the ordinary course of business, OPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 376 for additional discussion of relevant factors.

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
 
(in millions of KWhs)
Retail:
 
 
 
 
 
 
 
 
 
Residential
 
 14,486 
 
 
 14,485 
 
 
 15,082 
 
Commercial
 
 14,188 
 
 
 14,176 
 
 
 14,269 
 
Industrial
 
 15,915 
 
 
 18,122 
 
 
 18,946 
 
Miscellaneous
 
 125 
 
 
 120 
 
 
 123 
Total Retail
 
 44,714 
 
 
 46,903 
 
 
 48,420 
 
 
 
 
 
 
 
 
 
Wholesale
 
 12,828 
 
 
 13,221 
 
 
 12,229 
 
 
 
 
 
 
 
 
 
Total KWhs
 
 57,542 
 
 
 60,124 
 
 
 60,649 

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.

Summary of Heating and Cooling Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
 
 
 
(in degree days)
 
Actual - Heating (a)
 
 3,383 
 
 
 2,610 
 
 
 3,107 
 
Normal - Heating (b)
 
 3,229 
 
 
 3,276 
 
 
 3,266 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 1,029 
 
 
 1,248 
 
 
 1,112 
 
Normal - Cooling (b)
 
 954 
 
 
 948 
 
 
 936 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Eastern Region heating degree days are calculated on a 55 degree temperature base.
 
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
 
(c)
Eastern Region cooling degree days are calculated on a 65 degree temperature base.

 
187

 
 
2013 Compared to 2012
 
 
 
 
 
 
 
 
 
 
Reconciliation of Year Ended December 31, 2012 to Year Ended December 31, 2013
 
Net Income
 
(in millions)
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2012
 
 
 
 
$
 344 
 
 
 
 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
 
 
 
Retail Margins
 
 
 
 
 
 (40)
 
Off-system Sales
 
 
 
 
 
 (85)
 
Transmission Revenues
 
 
 
 
 
 39 
 
Other Revenues
 
 
 
 
 
 (20)
 
Total Change in Gross Margin
 
 
 
 
 
 (106)
 
 
 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
 
 
 
Other Operation and Maintenance
 
 
 
 
 
 (39)
 
Asset Impairments and Other Related Charges
 
 
 
 
 
 133 
 
Depreciation and Amortization
 
 
 
 
 
 128 
 
Interest Expense
 
 
 
 
 
 31 
 
Total Change in Expenses and Other
 
 
 
 
 
 253 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 
 
 
 (81)
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2013
 
 
 
 
$
 410 

The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:

 
·
Retail Margins decreased $40 million primarily due to the following:
   
·
A $275 million decrease attributable to customers switching to alternative CRES providers.  This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
   
·
A $35 million decrease due to the second quarter 2012 partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
   
·
A $29 million decrease due to a reduction in industrial usage.
   
·
A $19 million decrease due to lower sales to Buckeye Power, Inc. to provide backup energy under the Cardinal Station Agreement.
   
These decreases were partially offset by:
   
·
A $228 million increase in revenues associated with the Universal Service Fund (USF) surcharge, Retail Stability Rider, Deferred Asset Recovery Rider and Distribution Investment Recovery Rider.  Of these increases, $134 million relate to riders/trackers which have corresponding increases in other expense items below.
   
·
A $78 million increase due to the deferral of consumables and purchased power as a result of the PUCO’s July 2012 approval of the capacity deferral mechanism.
 
·
Margins from Off-system Sales decreased $85 million primarily due to lower CRES capacity revenues as a result of Reliability Pricing Model pricing effective August 2012, lower PJM capacity revenues, reduced trading and marketing margins and true-up of prior period PJM expenses.  The decrease in CRES capacity revenues is partially offset in other expense items below.
 
·
Transmission Revenues increased $39 million primarily due to increased transmission revenues from customers who have switched to alternative CRES providers.  The increase in transmission revenues related to CRES providers offsets lost revenues included in Retail Margins above.
 
·
Other Revenues decreased $20 million due to:
   
·
A $25 million decrease in revenues related to the Cook Coal Terminal which was transferred to AEGCo in August 2013.  This decrease in Other Revenues has a corresponding decrease in Other Operation and Maintenance expense below.
   
This decrease was partially offset by:
   
·
A $5 million increase associated with billings to affiliated companies.

 
188

 
 
Expenses and Other and Income Tax Expense changed between years as follows:

 
·
Other Operation and Maintenance expenses increased $39 million primarily due to the following:
   
·
An $86 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.  This increase was offset by a corresponding increase in retail margins above.
   
·
A $30 million net increase related to the reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO’s February 2012 rejection of the Ohio modified stipulation and the PUCO’s August 2012 approval of the June 2012-May 2015 ESP.
   
·
A $14 million increase due to 2013 asset retirement obligation adjustments related to the OPCo impaired and closed facilities.
   
·
A $12 million increase due to a December 2013 settlement agreement with Buckeye Power, Inc. extinguishing future NO x allowance purchase commitments.
   
These increases were partially offset by:
   
·
A $29 million decrease due to the deferral of capacity-related costs as a result of the PUCO’s July 2012 approval of the capacity deferral mechanism.
   
·
A $26 million decrease in expenses related to Cook Coal Terminal which was transferred to AEGCo in August 2013.  This decrease in other operation and maintenance has a corresponding decrease in Other Revenues above.
   
·
A $14 million decrease in recoverable PJM expenses.
   
·
A $13 million decrease in gridSMART ® expenses due primarily to a reduction in the operation and maintenance component of the gridSMART ® rider for prior years’ over collections.  This decrease was partially offset by a corresponding increase in Depreciation and Amortization.
   
·
A $9 million decrease in expenses relating to the 2012 cost reductions.
   
·
An $8 million decrease in advertising expenses.
   
·
A $7 million decrease in plant maintenance expenses at various plants.
 
·
Asset Impairments and Other Related Charges decreased $133 million due to the following:
   
·
A 2012 impairment of $287 million for certain Ohio generation plants, which includes $13 million of related materials and supplies inventory.
   
This decrease was partially offset by:
   
·
A $154 million increase due to the second quarter 2013 impairment of Muskingum River Plant, Unit 5.
 
·
Depreciation and Amortization expenses   decreased $128 million primarily due to the following:
   
·
A $116 million decrease as a result of depreciation ceasing on certain generation plants that were impaired in November 2012 and June 2013.
   
·
A $42 million decrease due to the deferral of capacity-related depreciation costs as a result of the PUCO’s July 2012 approval of the capacity deferral mechanism.
   
These decreases were partially offset by:
   
·
A $10 million increase due to an increase in depreciable base.
   
·
A $4 million increase in gridSMART ®   expenses due primarily to an increase in the depreciation component of the gridSMART ®   rider to recover prior years’ over collections.  This increase was offset by a corresponding decrease in Other Operation and Maintenance expense above.
 
·
Interest Expense decreased $31 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
 
·
Income Tax Expense increased $81 million primarily due to an increase in pretax book income and the recording of state income tax adjustments.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 376 for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 376 for a discussion of accounting pronouncements.

 
189

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of
Ohio Power Company:

We have audited the accompanying consolidated balance sheets of Ohio Power Company and subsidiaries (the "Company") as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income (loss), changes in common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Ohio Power Company and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

/s/  Deloitte & Touche LLP

Columbus, Ohio
February 25, 2014

 
190

 

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Ohio Power Company and Subsidiaries (OPCo) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  OPCo’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of OPCo’s internal control over financial reporting as of December 31, 2013.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 1992) in Internal Control – Integrated Framework.  Based on management’s assessment, OPCo’s internal control over financial reporting was effective as of December 31, 2013.

This annual report does not include an attestation report of OPCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit OPCo to provide only management’s report in this annual report.

 
191

 

OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2013, 2012 and 2011
(in thousands)
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
 
REVENUES
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission and Distribution
 
$
 3,562,224 
 
$
 4,022,116 
 
$
 4,406,814 
 
Sales to AEP Affiliates
 
 
 1,166,854 
 
 
 847,294 
 
 
 977,999 
 
Other Revenues – Affiliated
 
 
 18,140 
 
 
 39,401 
 
 
 27,903 
 
Other Revenues – Nonaffiliated
 
 
 15,397 
 
 
 19,385 
 
 
 18,395 
 
TOTAL REVENUES
 
 
 4,762,615 
 
 
 4,928,196 
 
 
 5,431,111 
 
 
 
 
 
 
 
 
 
 
 
 
EXPENSES
 
 
 
 
 
 
 
 
 
 
Fuel and Other Consumables Used for Electric Generation
 
 
 1,496,856 
 
 
 1,471,316 
 
 
 1,597,410 
 
Purchased Electricity for Resale
 
 
 151,561 
 
 
 205,845 
 
 
 300,653 
 
Purchased Electricity from AEP Affiliates
 
 
 349,732 
 
 
 380,706 
 
 
 515,613 
 
Other Operation
 
 
 707,953 
 
 
 669,981 
 
 
 754,109 
 
Maintenance
 
 
 319,625 
 
 
 319,324 
 
 
 393,943 
 
Asset Impairments and Other Related Charges
 
 
 154,304 
 
 
 287,031 
 
 
 89,824 
 
Depreciation and Amortization
 
 
 382,570 
 
 
 511,070 
 
 
 545,376 
 
Taxes Other Than Income Taxes
 
 
 406,916 
 
 
 405,976 
 
 
 399,479 
 
TOTAL EXPENSES
 
 
 3,969,517 
 
 
 4,251,249 
 
 
 4,596,407 
 
 
 
 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
 
 793,098 
 
 
 676,947 
 
 
 834,704 
 
 
 
 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 3,325 
 
 
 3,536 
 
 
 7,069 
 
Carrying Costs Income
 
 
 16,312 
 
 
 16,942 
 
 
 53,345 
 
Allowance for Equity Funds Used During Construction
 
 
 4,961 
 
 
 3,492 
 
 
 5,549 
 
Interest Expense
 
 
 (182,046)
 
 
 (213,100)
 
 
 (221,977)
 
 
 
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE
 
 
 635,650 
 
 
 487,817 
 
 
 678,690 
 
 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 225,670 
 
 
 144,283 
 
 
 213,697 
 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME
 
 
 409,980 
 
 
 343,534 
 
 
 464,993 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred Stock Dividend Requirements Including
 
 
 
 
 
 
 
 
 
 
 
Capital Stock Expense
 
 
 - 
 
 
 - 
 
 
 1,259 
 
 
 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO COMMON STOCK
 
$
 409,980 
 
$
 343,534 
 
$
 463,734 
 
 
 
 
 
 
 
 
 
 
 
 
 
The common stock of OPCo is wholly-owned by AEP.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
192

 
 
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2013, 2012 and 2011
 (in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
Net Income
 
$
 409,980 
 
$
 343,534 
 
$
 464,993 
 
 
 
 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $191, $282 and $1,477 in 2013, 2012
 
 
 
 
 
 
 
 
 
 
 and 2011, Respectively
 
 
 (355)
 
 
 (523)
 
 
 (2,743)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $6,736, $6,979 and
 
 
 
 
 
 
 
 
 
 
 $5,894 in 2013, 2012 and 2011, Respectively
 
 
 12,509 
 
 
 12,961 
 
 
 10,946 
Pension and OPEB Funded Status, Net of Tax of $35,225, $10,533 and
 
 
 
 
 
 
 
 
 
 
$13,876 in 2013, 2012 and 2011, Respectively
 
 
 65,418 
 
 
 19,559 
 
 
 (25,770)
 
 
 
 
 
 
 
 
 
 
 
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
 
 
 77,572 
 
 
 31,997 
 
 
 (17,567)
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
 
$
 487,552 
 
$
 375,531 
 
$
 447,426 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.
 
 
 

 
193

 
 
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY
For the Years Ended December 31, 2013, 2012 and 2011
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
 
 
 
Stock
 
Capital
 
Earnings
 
Income (Loss)
 
Total
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 EQUITY – DECEMBER 31, 2010
 
 321,201 
 
 1,744,991 
 
 2,768,602 
 
 (180,155)
 
 4,654,639 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (650,000)
 
 
 
 
 
 (650,000)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (671)
 
 
 
 
 
 (671)
Loss on Reacquired Preferred Stock
 
 
 
 
 
 (1,216)
 
 
 
 
 
 
 
 
 (1,216)
Capital Stock Expense
 
 
 
 
 
 324 
 
 
 (324)
 
 
 
 
 
 - 
Net Income
 
 
 
 
 
 
 
 
 464,993 
 
 
 
 
 
 464,993 
Other Comprehensive Loss
 
 
 
 
 
 
 
 
 
 
 
 (17,567)
 
 
 (17,567)
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – DECEMBER 31, 2011
 
 
 321,201 
 
 
 1,744,099 
 
 
 2,582,600 
 
 
 (197,722)
 
 
 4,450,178 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (300,000)
 
 
 
 
 
 (300,000)
Net Income
 
 
 
 
 
 
 
 
 343,534 
 
 
 
 
 
 343,534 
Other Comprehensive Income
 
 
 
 
 
 
 
 
 
 
 
 31,997 
 
 
 31,997 
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – DECEMBER 31, 2012
 
 
 321,201 
 
 
 1,744,099 
 
 
 2,626,134 
 
 
 (165,725)
 
 
 4,525,709 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (375,000)
 
 
 
 
 
 (375,000)
Net Income
 
 
 
 
 
 
 
 
 409,980 
 
 
 
 
 
 409,980 
Other Comprehensive Income
 
 
 
 
 
 
 
 
 
 
 
 77,572 
 
 
 77,572 
Deferred State Income Tax Rate Adjustment
 
 
 
 
 
 (4,971)
 
 
 
 
 
 
 
 
 (4,971)
Distribution of Cook Coal Terminal to Parent
 
 
 
 
 
 
 
 
 (22,303)
 
 
 19,652 
 
 
 (2,651)
Distribution of OPCo Generation to Parent
 
 
 
 
 
 (1,075,346)
 
 
 (2,005,608)
 
 
 75,580 
 
 
 (3,005,374)
TOTAL COMMON SHAREHOLDER'S
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY – DECEMBER 31, 2013
 
 321,201 
 
 663,782 
 
 633,203 
 
 7,079 
 
 1,625,265 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
194

 
 
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2013 and 2012
(in thousands)
 
 
 
 
 
 
 
December 31,
 
 
 
2013 
 
2012 
 
CURRENT ASSETS
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 3,004 
 
$
 3,640 
 
Advances to Affiliates
 
 
 339,070 
 
 
 116,422 
 
Accounts Receivable:
 
 
 
 
 
 
 
 
Customers
 
 
 67,054 
 
 
 135,954 
 
 
Affiliated Companies
 
 
 74,771 
 
 
 176,590 
 
 
Accrued Unbilled Revenues
 
 
 36,353 
 
 
 57,887 
 
 
Miscellaneous
 
 
 1,559 
 
 
 9,327 
 
 
Allowance for Uncollectible Accounts
 
 
 (34,984)
 
 
 (129)
 
 
 
Total Accounts Receivable
 
 
 144,753 
 
 
 379,629 
 
Notes Receivable Due Within One Year – Affiliated
 
 
 178,580 
 
 
 - 
 
Fuel
 
 
 - 
 
 
 328,840 
 
Materials and Supplies
 
 
 53,711 
 
 
 186,269 
 
Risk Management Assets
 
 
 3,082 
 
 
 44,313 
 
Accrued Tax Benefits
 
 
 7,109 
 
 
 17,785 
 
Prepayments and Other Current Assets
 
 
 77,804 
 
 
 26,807 
 
TOTAL CURRENT ASSETS
 
 
 807,113 
 
 
 1,103,705 
 
 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
 
Generation
 
 
 - 
 
 
 8,673,296 
 
 
Transmission
 
 
 2,011,289 
 
 
 2,013,737 
 
 
Distribution
 
 
 3,877,532 
 
 
 3,722,745 
 
Other Property, Plant and Equipment
 
 
 364,573 
 
 
 571,154 
 
Construction Work in Progress
 
 
 185,428 
 
 
 354,497 
 
Total Property, Plant and Equipment
 
 
 6,438,822 
 
 
 15,335,429 
 
Accumulated Depreciation and Amortization
 
 
 1,973,042 
 
 
 5,242,805 
 
TOTAL PROPERTY, PLANT AND EQUIPMENT NET
 
 
 4,465,780 
 
 
 10,092,624 
 
 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
 
Notes Receivable - Affiliated
 
 
 118,245 
 
 
 - 
 
Regulatory Assets
 
 
 1,378,697 
 
 
 1,420,966 
 
Securitized Assets
 
 
 131,582 
 
 
 - 
 
Long-term Risk Management Assets
 
 
 - 
 
 
 48,288 
 
Deferred Charges and Other Noncurrent Assets
 
 
 260,141 
 
 
 320,026 
 
TOTAL OTHER NONCURRENT ASSETS
 
 
 1,888,665 
 
 
 1,789,280 
 
 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 7,161,558 
 
$
 12,985,609 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
195

 
 
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
December 31, 2013 and 2012
 
 
 
 
 
 
 
December 31,
 
 
 
2013 
 
2012 
 
 
 
(in thousands)
 
CURRENT LIABILITIES
 
 
 
 
 
 
 
Accounts Payable:
 
 
 
 
 
 
 
 
General
 
$
 146,307 
 
$
 276,220 
 
 
Affiliated Companies
 
 
 222,889 
 
 
 153,222 
 
Long-term Debt Due Within One Year – Nonaffiliated
 
 
 438,595 
 
 
 856,000 
 
Risk Management Liabilities
 
 
 - 
 
 
 24,155 
 
Accrued Taxes
 
 
 429,260 
 
 
 467,309 
 
Accrued Interest
 
 
 40,853 
 
 
 63,560 
 
Other Current Liabilities
 
 
 144,334 
 
 
 263,638 
 
TOTAL CURRENT LIABILITIES
 
 
 1,422,238 
 
 
 2,104,104 
 
 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
 
Long-term Debt – Nonaffiliated
 
 
 2,296,580 
 
 
 2,804,440 
 
Long-term Debt – Affiliated
 
 
 - 
 
 
 200,000 
 
Long-term Risk Management Liabilities
 
 
 - 
 
 
 25,965 
 
Deferred Income Taxes
 
 
 1,330,711 
 
 
 2,345,850 
 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 435,499 
 
 
 451,071 
 
Employee Benefits and Pension Obligations
 
 
 28,329 
 
 
 178,620 
 
Deferred Credits and Other Noncurrent Liabilities
 
 
 22,936 
 
 
 349,850 
 
TOTAL NONCURRENT LIABILITIES
 
 
 4,114,055 
 
 
 6,355,796 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 5,536,293 
 
 
 8,459,900 
 
 
 
 
 
 
 
 
 
Rate Matters (Note 3)
 
 
 
 
 
 
 
Commitments and Contingencies (Note 5)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMMON SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
Common Stock – No Par Value:
 
 
 
 
 
 
 
 
Authorized – 40,000,000 Shares
 
 
 
 
 
 
 
 
Outstanding  – 27,952,473 Shares
 
 
 321,201 
 
 
 321,201 
 
Paid-in Capital
 
 
 663,782 
 
 
 1,744,099 
 
Retained Earnings
 
 
 633,203 
 
 
 2,626,134 
 
Accumulated Other Comprehensive Income (Loss)
 
 
 7,079 
 
 
 (165,725)
 
TOTAL COMMON SHAREHOLDER’S EQUITY
 
 
 1,625,265 
 
 
 4,525,709 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
 7,161,558 
 
$
 12,985,609 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
196

 
 
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2013, 2012 and 2011
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
2013 
 
2012 
 
2011 
OPERATING ACTIVITIES
 
 
 
 
 
 
 
 
 
Net Income
 
$
 409,980 
 
$
 343,534 
 
$
 464,993 
Adjustments to Reconcile Net Income to Net Cash Flows from
 
 
 
 
 
 
 
 
 
 
Operating Activities:
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 382,570 
 
 
 511,070 
 
 
 545,376 
 
 
Deferred Income Taxes
 
 
 134,463 
 
 
 45,685 
 
 
 119,184 
 
 
Asset Impairments and Other Related Charges
 
 
 154,304 
 
 
 287,031 
 
 
 89,824 
 
 
Carrying Costs Income
 
 
 (16,312)
 
 
 (16,942)
 
 
 (53,345)
 
 
Deferral of Storm Costs
 
 
 (1,822)
 
 
 (53,453)
 
 
 (8,375)
 
 
Allowance for Equity Funds Used During Construction
 
 
 (4,961)
 
 
 (3,492)
 
 
 (5,549)
 
 
Mark-to-Market of Risk Management Contracts
 
 
 17,597 
 
 
 12,143 
 
 
 (3,695)
 
 
Pension Contributions to Qualified Plan Trust
 
 
 - 
 
 
 (43,189)
 
 
 (127,884)
 
 
Property Taxes
 
 
 (11,760)
 
 
 (3,849)
 
 
 (5,722)
 
 
Fuel Over/Under-Recovery, Net
 
 
 36,165 
 
 
 10,598 
 
 
 (727)
 
 
Deferral of Ohio Capacity Costs, Net
 
 
 (214,384)
 
 
 (65,274)
 
 
 - 
 
 
Change in Other Noncurrent Assets
 
 
 31,680 
 
 
 (3,650)
 
 
 (64,867)
 
 
Change in Other Noncurrent Liabilities
 
 
 (52,809)
 
 
 (27,039)
 
 
 85,173 
 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 86,640 
 
 
 (37,787)
 
 
 116,197 
 
 
 
Fuel, Materials and Supplies
 
 
 80,250 
 
 
 (54,945)
 
 
 79,787 
 
 
 
Accounts Payable
 
 
 (2,919)
 
 
 (63,450)
 
 
 (17,059)
 
 
 
Accrued Taxes, Net
 
 
 23,839 
 
 
 41,475 
 
 
 36,466 
 
 
 
Other Current Assets
 
 
 7,804 
 
 
 9,977 
 
 
 7,789 
 
 
 
Other Current Liabilities
 
 
 (60,296)
 
 
 17,669 
 
 
 (15,821)
Net Cash Flows from Operating Activities
 
 
 1,000,029 
 
 
 906,112 
 
 
 1,241,745 
 
 
 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
 
 
 
Construction Expenditures
 
 
 (640,050)
 
 
 (517,744)
 
 
 (454,873)
Change in Advances to Affiliates, Net
 
 
 4,330 
 
 
 103,036 
 
 
 (64,756)
Acquisitions of Assets
 
 
 (4,166)
 
 
 (2,915)
 
 
 (2,229)
Proceeds from Sales of Assets
 
 
 62,975 
 
 
 7,320 
 
 
 47,463 
Other Investing Activities
 
 
 (17,017)
 
 
 10,014 
 
 
 29,014 
Net Cash Flows Used for Investing Activities
 
 
 (593,928)
 
 
 (400,289)
 
 
 (445,381)
 
 
 
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
 
 
 
Issuance of Long-term Debt – Nonaffiliated
 
 
 1,378,326 
 
 
 - 
 
 
 49,748 
Issuance of Long-term Debt – Affiliated
 
 
 200,000 
 
 
 - 
 
 
 - 
Change in Advances from Affiliates, Net
 
 
 1,143 
 
 
 - 
 
 
 - 
Retirement of Long-term Debt – Nonaffiliated
 
 
 (1,196,032)
 
 
 (194,500)
 
 
 (165,000)
Retirement of Long-term Debt – Affiliated
 
 
 (400,000)
 
 
 - 
 
 
 - 
Retirement of Cumulative Preferred Stock
 
 
 - 
 
 
 - 
 
 
 (17,831)
Principal Payments for Capital Lease Obligations
 
 
 (17,199)
 
 
 (10,072)
 
 
 (11,854)
Dividends Paid on Common Stock
 
 
 (375,000)
 
 
 (300,000)
 
 
 (650,000)
Dividends Paid on Cumulative Preferred Stock
 
 
 - 
 
 
 - 
 
 
 (671)
Other Financing Activities
 
 
 2,025 
 
 
 294 
 
 
 390 
Net Cash Flows Used for Financing Activities
 
 
 (406,737)
 
 
 (504,278)
 
 
 (795,218)
 
 
 
 
 
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 (636)
 
 
 1,545 
 
 
 1,146 
Cash and Cash Equivalents at Beginning of Period
 
 
 3,640 
 
 
 2,095 
 
 
 949 
Cash and Cash Equivalents at End of Period
 
$
 3,004 
 
$
 3,640 
 
$
 2,095 
 
 
 
 
 
 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
 
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 195,677 
 
$
 212,753 
 
$
 226,711 
Net Cash Paid for Income Taxes
 
 
 93,324 
 
 
 69,771 
 
 
 81,740 
Noncash Acquisitions Under Capital Leases
 
 
 7,655 
 
 
 8,602 
 
 
 5,766 
Government Grants Included in Accounts Receivable as of December 31,
 
 
 300 
 
 
 660 
 
 
 1,383 
Construction Expenditures Included in Current Liabilities as of December 31,
 
 
 92,324 
 
 
 84,321 
 
 
 61,428 
Noncash Distribution of Cook Coal Terminal to Parent
 
 
 (22,303)
 
 
 - 
 
 
 - 
Noncash Distribution of OPCo Generation to Parent
 
 
 (3,080,954)
 
 
 - 
 
 
 - 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
197

 

OHIO POWER COMPANY AND SUBSIDIARIES
INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to OPCo’s financial statements are combined with the notes to financial statements for other registrant subsidiaries.  Listed below are the notes that apply to OPCo.  The footnotes begin on page 227.

 
Page
Number
   
Organization and Summary of Significant Accounting Policies
  228
Comprehensive Income
  240
Rate Matters
  249
Effects of Regulation
  259
Commitments, Guarantees and Contingencies
  265
Acquisition, Disposition and Impairments
  271
Benefit Plans
  273
Business Segments
  308
Derivatives and Hedging
  308
Fair Value Measurements
  323
Income Taxes
  334
Leases
  342
Financing Activities
  346
Related Party Transactions
  352
Variable Interest Entities
  360
Property, Plant and Equipment
  366
Sustainable Cost Reductions
  374
Unaudited Quarterly Financial Information
  375

 
198

 













PUBLIC SERVICE COMPANY OF OKLAHOMA


 
199

 

PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

As a public utility, PSO engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 540,000 retail customers in its service territory in eastern and southwestern Oklahoma.  PSO sells electric power at wholesale to other utilities, municipalities and electric cooperatives.

PSO, as a party to the Operating Agreement, is compensated for energy delivered to the other member based upon the delivering member’s incremental cost plus a portion of the savings realized by the purchasing member that avoids the use of more costly alternatives.  PSO and SWEPCo share the revenues and costs of sales to neighboring utilities and power marketers made by AEPSC on their behalf based upon the relative magnitude of the energy each company provides to make such sales.  PSO shares off-system sales margins, if positive on an annual basis, with its customers.

AEPSC conducts power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on PSO’s behalf.  PSO shares in the revenues and expenses associated with these risk management activities, as described in the preceding paragraph, with the AEP East Companies and SWEPCo.  Power and natural gas risk management activities are allocated based on the Operating Agreement and the SIA.  PSO shares in coal allowance risk management activities based on its proportion of fossil fuels burned by the AEP System.  Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and, to a lesser extent, the purchase and sale of natural gas and coal.  The power, natural gas and coal contracts include physical transactions, OTC options and financially-settled swaps and exchange-traded futures and options.  AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts.

Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East Companies and trading and marketing activities originating in SPP generally accruing to the benefit of PSO and SWEPCo.  Margins resulting from other transactions are allocated among the AEP East Companies, PSO and SWEPCo in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months.

PSO is jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity pursuant to the SIA.

Regulatory Activity

2014 Oklahoma Base Rate Case

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity.  This revenue increase includes a proposed increase in depreciation rates of $29 million.  In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three.  The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional types of transmission costs that are expected to increase over the next several years.

Oklahoma Environmental Compliance Plan

In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES), Unit 4 in 2016 and additional environmental controls on NES, Unit 3 to continue operations through 2026.  As of December 31, 2013, the net book values of NES, Units 3 and 4 were $208 million and $106 million, respectively, before cost of removal, including materials and supplies inventory and CWIP.  In August 2013, the OCC dismissed PSO’s environmental compliance plan case without prejudice but will permit PSO
 
 
200

 
to seek recovery in a future proceeding.  PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan.  If PSO is ultimately not permitted to fully recover its net book value of NES, Units 3 and 4 and other environmental compliance costs, it could reduce future net income and cash flows and impact financial condition.

Litigation and Environmental Issues

In the ordinary course of business, PSO is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 376 for additional discussion of relevant factors.

RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
 
(in millions of KWhs)
Retail:
 
 
 
 
 
 
 
 
 
Residential
 
 6,290 
 
 
 6,393 
 
 
 6,741 
 
Commercial
 
 5,066 
 
 
 5,178 
 
 
 5,190 
 
Industrial
 
 5,083 
 
 
 5,066 
 
 
 4,956 
 
Miscellaneous
 
 1,243 
 
 
 1,326 
 
 
 1,310 
Total Retail
 
 17,682 
 
 
 17,963 
 
 
 18,197 
 
 
 
 
 
 
 
 
 
Wholesale
 
 1,091 
 
 
 1,492 
 
 
 1,113 
 
 
 
 
 
 
 
 
 
Total KWhs
 
 18,773 
 
 
 19,455 
 
 
 19,310 

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.

 
Summary of Heating and Cooling Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
 
 
 
(in degree days)
 
Actual - Heating (a)
 
 2,107 
 
 
 1,271 
 
 
 1,879 
 
Normal - Heating (b)
 
 1,763 
 
 
 1,803 
 
 
 1,796 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 2,082 
 
 
 2,663 
 
 
 2,788 
 
Normal - Cooling (b)
 
 2,133 
 
 
 2,119 
 
 
 2,102 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Western Region heating degree days are calculated on a 55 degree temperature base.
 
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
 
(c)
Western Region cooling degree days are calculated on a 65 degree temperature base.

 
201

 
 
2013 Compared to 2012
 
 
 
 
 
 
 
 
 
 
 
Reconciliation of Year Ended December 31, 2012 to Year Ended December 31, 2013
 
Net Income
 
(in millions)
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2012
 
 
 
 
$
 114 
 
 
 
 
 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
 
 
 
Retail Margins (a)
 
 
 
 
 
 (13)
 
Transmission Revenues
 
 
 
 
 
 6 
 
Other Revenues
 
 
 
 
 
 2 
 
Total Change in Gross Margin
 
 
 
 
 
 (5)
 
 
 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
 
 
 
Other Operation and Maintenance
 
 
 
 
 
 (13)
 
Taxes Other Than Income Taxes
 
 
 
 
 
 (2)
 
Other Income
 
 
 
 
 
 1 
 
Interest Expense
 
 
 
 
 
 2 
 
Total Change in Expenses and Other
 
 
 
 
 
 (12)
 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 
 
 
 1 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2013
 
 
 
 
$
 98 
 
 
 
 
 
 
 
 
 
 
 
(a)
Includes firm wholesale sales to municipals and cooperatives.

The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:

 
·
Retail Margins decreased $13 million primarily due to the following:
   
·
A $13 million net decrease in weather-related usage primarily due to a 22% decrease in cooling degree days, partially offset by an increase in heating degree days.
   
·
A $4 million decrease primarily due to lower weather-normalized retail sales.
   
These decreases were partially offset by:
   
·
A $4 million increase primarily due to revenue increases from rate riders. This increase in retail margins has corresponding increases to riders/trackers recognized in other expense items below.
 
·
Transmission Revenues increased $6 million primarily due to increased investment in the SPP region.

Expenses and Other changed between years as follows:

 
·
Other Operation and Maintenance expenses increased $13 million primarily due to the following:
   
·
A $19 million increase in transmission expenses primarily due to increased SPP transmission services.
   
This increase was partially offset by:
   
·
A $5 million decrease in general and administrative expenses.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 376 for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 376 for a discussion of accounting pronouncements.

 
202

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of
Public Service Company of Oklahoma:

We have audited the accompanying balance sheets of Public Service Company of Oklahoma (the "Company") as of December 31, 2013 and 2012, and the related statements of income, comprehensive income (loss), changes in common shareholder’s equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Public Service Company of Oklahoma as of December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

/s/  Deloitte & Touche LLP

Columbus, Ohio
February 25, 2014

 
203

 

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Public Service Company of Oklahoma (PSO) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  PSO’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of PSO’s internal control over financial reporting as of December 31, 2013.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 1992) in Internal Control – Integrated Framework.  Based on management’s assessment, PSO’s internal control over financial reporting was effective as of December 31, 2013.

This annual report does not include an attestation report of PSO’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit PSO to provide only management’s report in this annual report.

 
204

 

PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF INCOME
For the Years Ended December 31, 2013, 2012 and 2011
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
 
2013 
 
2012 
 
2011 
 
REVENUES
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission and Distribution
 
$
 1,277,711 
 
$
 1,206,583 
 
$
 1,345,551 
 
Sales to AEP Affiliates
 
 
 14,246 
 
 
 22,603 
 
 
 14,192 
 
Other Revenues
 
 
 3,565 
 
 
 3,752 
 
 
 3,645 
 
TOTAL REVENUES
 
 
 1,295,522 
 
 
 1,232,938 
 
 
 1,363,388 
 
 
 
 
 
 
 
 
 
 
 
 
 
EXPENSES
 
 
 
 
 
 
 
 
 
 
Fuel and Other Consumables Used for Electric Generation
 
 
 327,829 
 
 
 310,296 
 
 
 465,546 
 
Purchased Electricity for Resale
 
 
 246,109 
 
 
 208,676 
 
 
 163,550 
 
Purchased Electricity from AEP Affiliates
 
 
 36,891 
 
 
 24,378 
 
 
 50,092 
 
Other Operation
 
 
 225,500 
 
 
 213,195 
 
 
 201,247 
 
Maintenance
 
 
 107,076 
 
 
 106,835 
 
 
 104,732 
 
Depreciation and Amortization
 
 
 95,667 
 
 
 95,180 
 
 
 95,915 
 
Taxes Other Than Income Taxes
 
 
 45,215 
 
 
 43,428 
 
 
 41,295 
 
TOTAL EXPENSES
 
 
 1,084,287 
 
 
 1,001,988 
 
 
 1,122,377 
 
 
 
 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
 
 211,235 
 
 
 230,950 
 
 
 241,011 
 
 
 
 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 1,096 
 
 
 1,308 
 
 
 596 
 
Carrying Costs Income
 
 
 338 
 
 
 1,856 
 
 
 4,033 
 
Allowance for Equity Funds Used During Construction
 
 
 4,187 
 
 
 2,007 
 
 
 1,317 
 
Interest Expense
 
 
 (53,175)
 
 
 (55,286)
 
 
 (54,700)
 
 
 
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE
 
 
 163,681 
 
 
 180,835 
 
 
 192,257 
 
 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 65,885 
 
 
 66,694 
 
 
 67,629 
 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME
 
 
 97,796 
 
 
 114,141 
 
 
 124,628 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred Stock Dividend Requirements Including Capital Stock
 
 
 
 
 
 
 
 
 
 
 
Expense
 
 
 - 
 
 
 - 
 
 
 434 
 
 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO COMMON STOCK
 
$
97,796 
 
$
 114,141 
 
$
 124,194 
 
 
 
 
 
 
 
 
 
 
 
 
The common stock of PSO is wholly-owned by AEP.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
205

 
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2013, 2012 and 2011
 (in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
Net Income
 
$
97,796 
 
$
 114,141 
 
$
 124,628 
 
 
 
 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE LOSS, NET OF TAXES
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $389, $360 and $724 in 2013, 2012 and 2011,
 
 
 
 
 
 
 
 
 
 
Respectively
 
 
 (723)
 
 
 (668)
 
 
 (1,345)
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
 
$
 97,073 
 
$
 113,473 
 
$
 123,283 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
206

 
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY
For the Years Ended December 31, 2013, 2012 and 2011
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
 
 
 
Stock
 
Capital
 
Earnings
 
Income (Loss)
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2010
 
 157,230 
 
 364,307 
 
 312,441 
 
 8,494 
 
 842,472 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (72,500)
 
 
 
 
 
 (72,500)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (180)
 
 
 
 
 
 (180)
Loss on Reacquired Preferred Stock
 
 
 
 
 
 (270)
 
 
 
 
 
 
 
 
 (270)
Net Income
 
 
 
 
 
 
 
 
 124,628 
 
 
 
 
 
 124,628 
Other Comprehensive Loss
 
 
 
 
 
 
 
 
 
 
 
 (1,345)
 
 
 (1,345)
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2011
 
 
 157,230 
 
 
 364,037 
 
 
 364,389 
 
 
 7,149 
 
 
 892,805 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (90,000)
 
 
 
 
 
 (90,000)
Net Income
 
 
 
 
 
 
 
 
 114,141 
 
 
 
 
 
 114,141 
Other Comprehensive Loss
 
 
 
 
 
 
 
 
 
 
 
 (668)
 
 
 (668)
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2012
 
 
 157,230 
 
 
 364,037 
 
 
 388,530 
 
 
 6,481 
 
 
 916,278 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (71,250)
 
 
 
 
 
 (71,250)
Net Income
 
 
 
 
 
 
 
 
 97,796 
 
 
 
 
 
 97,796 
Other Comprehensive Loss
 
 
 
 
 
 
 
 
 
 
 
 (723)
 
 
 (723)
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2013
 
 157,230 
 
 364,037 
 
 415,076 
 
 5,758 
 
 942,101 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
207

 
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
ASSETS
December 31, 2013 and 2012
(in thousands)
 
 
 
 
 
December 31,
 
 
2013 
 
2012 
CURRENT ASSETS
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 1,277 
 
$
 1,367 
Advances to Affiliates
 
 
 - 
 
 
 10,558 
Accounts Receivable:
 
 
 
 
 
 
 
Customers
 
 
 32,314 
 
 
 31,047 
 
Affiliated Companies
 
 
 30,392 
 
 
 24,751 
 
Miscellaneous
 
 
 3,102 
 
 
 6,216 
 
Allowance for Uncollectible Accounts
 
 
 (462)
 
 
 (872)
 
 
Total Accounts Receivable
 
 
 65,346 
 
 
 61,142 
Fuel
 
 
 15,191 
 
 
 22,085 
Materials and Supplies
 
 
 52,707 
 
 
 52,183 
Risk Management Assets
 
 
 1,167 
 
 
 509 
Deferred Income Tax Benefits
 
 
 7,333 
 
 
 7,183 
Accrued Tax Benefits
 
 
 21,665 
 
 
 11,812 
Regulatory Asset for Under-Recovered Fuel Costs
 
 
 3,298 
 
 
 - 
Prepayments and Other Current Assets
 
 
 6,194 
 
 
 7,633 
TOTAL CURRENT ASSETS
 
 
 174,178 
 
 
 174,472 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
Generation
 
 
 1,203,221 
 
 
 1,346,530 
 
Transmission
 
 
 731,312 
 
 
 706,917 
 
Distribution
 
 
 1,986,032 
 
 
 1,859,557 
Other Property, Plant and Equipment (Including Plant to be Retired)
 
 
 393,026 
 
 
 210,549 
Construction Work in Progress
 
 
 175,890 
 
 
 95,170 
Total Property, Plant and Equipment
 
 
 4,489,481 
 
 
 4,218,723 
Accumulated Depreciation and Amortization
 
 
 1,323,522 
 
 
 1,278,941 
TOTAL PROPERTY, PLANT AND EQUIPMENT NET
 
 
 3,165,959 
 
 
 2,939,782 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
Regulatory Assets
 
 
 156,690 
 
 
 202,328 
Long-term Risk Management Assets
 
 
 - 
 
 
 31 
Employee Benefits and Pension Assets
 
 
 22,629 
 
 
 - 
Deferred Charges and Other Noncurrent Assets
 
 
 7,238 
 
 
 8,560 
TOTAL OTHER NONCURRENT ASSETS
 
 
 186,557 
 
 
 210,919 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 3,526,694 
 
$
 3,325,173 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
208

 
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
December 31, 2013 and 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31,
 
 
 
2013 
 
2012 
 
 
 
 
(in thousands)
 
CURRENT LIABILITIES
 
 
 
 
 
 
 
Advances from Affiliates
 
$
 36,772 
 
$
 - 
 
Accounts Payable:
 
 
 
 
 
 
 
 
General
 
 
 150,184 
 
 
 87,050 
 
 
Affiliated Companies
 
 
 45,427 
 
 
 36,189 
 
Long-term Debt Due Within One Year – Nonaffiliated
 
 
 34,115 
 
 
 764 
 
Risk Management Liabilities
 
 
 85 
 
 
 5,848 
 
Customer Deposits
 
 
 45,379 
 
 
 46,533 
 
Accrued Taxes
 
 
 23,442 
 
 
 28,024 
 
Accrued Interest
 
 
 12,646 
 
 
 12,654 
 
Regulatory Liability for Over-Recovered Fuel Costs
 
 
 - 
 
 
 7,945 
 
Other Current Liabilities
 
 
 58,992 
 
 
 50,684 
 
TOTAL CURRENT LIABILITIES
 
 
 407,042 
 
 
 275,691 
 
 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
 
Long-term Debt – Nonaffiliated
 
 
 965,695 
 
 
 949,107 
 
Long-term Risk Management Liabilities
 
 
 - 
 
 
 31 
 
Deferred Income Taxes
 
 
 836,556 
 
 
 740,676 
 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 327,673 
 
 
 344,817 
 
Employee Benefits and Pension Obligations
 
 
 10,561 
 
 
 34,906 
 
Deferred Credits and Other Noncurrent Liabilities
 
 
 37,066 
 
 
 63,667 
 
TOTAL NONCURRENT LIABILITIES
 
 
 2,177,551 
 
 
 2,133,204 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 2,584,593 
 
 
 2,408,895 
 
 
 
 
 
 
 
 
 
Rate Matters (Note 3)
 
 
 
 
 
 
 
Commitments and Contingencies (Note 5)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMMON SHAREHOLDER’S EQUITY
 
 
 
 
 
 
 
Common Stock – Par Value – $15 Per Share:
 
 
 
 
 
 
 
 
Authorized – 11,000,000 Shares
 
 
 
 
 
 
 
 
Issued – 10,482,000 Shares
 
 
 
 
 
 
 
 
Outstanding – 9,013,000 Shares
 
 
 157,230 
 
 
 157,230 
 
Paid-in Capital
 
 
 364,037 
 
 
 364,037 
 
Retained Earnings
 
 
 415,076 
 
 
 388,530 
 
Accumulated Other Comprehensive Income (Loss)
 
 
 5,758 
 
 
 6,481 
 
TOTAL COMMON SHAREHOLDER’S EQUITY
 
 
 942,101 
 
 
 916,278 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
 
$
 3,526,694 
 
$
 3,325,173 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
209

 
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CASH FLOWS
For the Years Ended December 31,  2013, 2012 and 2011
(in thousands)
 
 
 
 
 
 
Years Ended December 31,
 
 
2013 
 
2012 
 
2011 
OPERATING ACTIVITIES
 
 
 
 
 
 
 
 
 
Net Income
 
$
 97,796 
 
$
 114,141 
 
$
 124,628 
Adjustments to Reconcile Net Income to Net Cash Flows from
 
 
 
 
 
 
 
 
 
 
Operating Activities:
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 95,667 
 
 
 95,180 
 
 
 95,915 
 
 
Deferred Income Taxes
 
 
 53,788 
 
 
 48,916 
 
 
 61,581 
 
 
Carrying Costs Income
 
 
 (338)
 
 
 (1,856)
 
 
 (4,033)
 
 
Allowance for Equity Funds Used During Construction
 
 
 (4,187)
 
 
 (2,007)
 
 
 (1,317)
 
 
Mark-to-Market of Risk Management Contracts
 
 
 (6,362)
 
 
 3,740 
 
 
 1,290 
 
 
Pension Contributions to Qualified Plan Trust
 
 
 - 
 
 
 (12,306)
 
 
 (33,189)
 
 
Fuel Over/Under-Recovery, Net
 
 
 (12,643)
 
 
 12,258 
 
 
 32,949 
 
 
Change in Other Noncurrent Assets
 
 
 (16,435)
 
 
 7,436 
 
 
 14,883 
 
 
Change in Other Noncurrent Liabilities
 
 
 (15,271)
 
 
 4,762 
 
 
 32,196 
 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 (4,376)
 
 
 4,422 
 
 
 44,414 
 
 
 
Fuel, Materials and Supplies
 
 
 6,370 
 
 
 (3,067)
 
 
 (4,778)
 
 
 
Accounts Payable
 
 
 37,248 
 
 
 3,158 
 
 
 (20,068)
 
 
 
Accrued Taxes, Net
 
 
 332 
 
 
 5,006 
 
 
 19,535 
 
 
 
Other Current Assets
 
 
 1,450 
 
 
 (970)
 
 
 4,855 
 
 
 
Other Current Liabilities
 
 
 5,877 
 
 
 5,538 
 
 
 10,628 
Net Cash Flows from Operating Activities
 
 
 238,916 
 
 
 284,351 
 
 
 379,489 
 
 
 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
 
 
 
Construction Expenditures
 
 
 (259,449)
 
 
 (224,295)
 
 
 (140,327)
Change in Advances to Affiliates, Net
 
 
 10,558 
 
 
 29,318 
 
 
 (39,876)
Other Investing Activities
 
 
 (2,059)
 
 
 1,723 
 
 
 1,126 
Net Cash Flows Used for Investing Activities
 
 
 (250,950)
 
 
 (193,254)
 
 
 (179,077)
 
 
 
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
 
 
 
Issuance of Long-term Debt – Nonaffiliated
 
 
 49,709 
 
 
 2,395 
 
 
 248,909 
Change in Advances from Affiliates, Net
 
 
 36,772 
 
 
 - 
 
 
 (91,382)
Retirement of Long-term Debt – Nonaffiliated
 
 
 (402)
 
 
 (229)
 
 
 (275,000)
Retirement of Cumulative Preferred Stock
 
 
 - 
 
 
 - 
 
 
 (5,152)
Principal Payments for Capital Lease Obligations
 
 
 (3,498)
 
 
 (3,481)
 
 
 (4,189)
Dividends Paid on Common Stock
 
 
 (71,250)
 
 
 (90,000)
 
 
 (72,500)
Dividends Paid on Cumulative Preferred Stock
 
 
 - 
 
 
 - 
 
 
 (180)
Other Financing Activities
 
 
 613 
 
 
 172 
 
 
 25 
Net Cash Flows from (Used for) Financing Activities
 
 
 11,944 
 
 
 (91,143)
 
 
 (199,469)
 
 
 
 
 
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 (90)
 
 
 (46)
 
 
 943 
Cash and Cash Equivalents at Beginning of Period
 
 
 1,367 
 
 
 1,413 
 
 
 470 
Cash and Cash Equivalents at End of Period
 
$
 1,277 
 
$
 1,367 
 
$
 1,413 
 
 
 
 
 
 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
 
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 51,387 
 
$
 52,403 
 
$
 37,573 
Net Cash Paid (Received) for Income Taxes
 
 
 8,671 
 
 
 27,229 
 
 
 (16,043)
Noncash Acquisitions Under Capital Leases
 
 
 5,795 
 
 
 1,542 
 
 
 1,078 
Construction Expenditures Included in Current Liabilities as of December 31,
 
 
 63,648 
 
 
 27,118 
 
 
 28,427 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
210

 

PUBLIC SERVICE COMPANY OF OKLAHOMA
INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to PSO’s financial statements are combined with the notes to financial statements for other registrant subsidiaries.  Listed below are the notes that apply to PSO.  The footnotes begin on page 227.

 
Page
Number
   
Organization and Summary of Significant Accounting Policies
  228
Comprehensive Income
  240
Rate Matters
  249
Effects of Regulation
  259
Commitments, Guarantees and Contingencies
  265
Benefit Plans
  273
Business Segments
  308
Derivatives and Hedging
  308
Fair Value Measurements
  323
Income Taxes
  334
Leases
  342
Financing Activities
  346
Related Party Transactions
  352
Variable Interest Entities
  360
Property, Plant and Equipment
  366
Sustainable Cost Reductions
  374
Unaudited Quarterly Financial Information
  375

 
211

 









SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

 
212

 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

As a public utility, SWEPCo engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 526,000 retail customers in its service territory in northeastern and panhandle of Texas, northwestern Louisiana and western Arkansas.  SWEPCo consolidates its wholly-owned subsidiary, Southwest Arkansas Utilities Corporation.  SWEPCo also consolidates Sabine Mining Company, a variable interest entity.  SWEPCo sells electric power at wholesale to other utilities, municipalities and electric cooperatives.

SWEPCo, as a party to the Operating Agreement, is compensated for energy delivered to the other member based upon the delivering member’s incremental cost plus a portion of the savings realized by the purchasing member that avoids the use of more costly alternatives.  PSO and SWEPCo share the revenues and costs for sales to neighboring utilities and power marketers made by AEPSC on their behalf based upon the relative magnitude of the energy each company provides to make such sales.  SWEPCo shares these margins with its customers.

AEPSC conducts power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on SWEPCo’s behalf.  SWEPCo shares in the revenues and expenses associated with these risk management activities, as described in the preceding paragraph, with the AEP East Companies and PSO.  Power and natural gas risk management activities are allocated based on the Operating Agreement and the SIA.  SWEPCo shares in coal risk management activities based on its proportion of fossil fuels burned by the AEP System.  Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and, to a lesser extent, the purchase and sale of natural gas and coal.  The power, natural gas and coal contracts include physical transactions, OTC options and financially-settled swaps and exchange-traded futures and options.  AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts.

Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East Companies and trading and marketing activities originating in SPP generally accruing to the benefit of PSO and SWEPCo.  Margins resulting from other transactions are allocated among the AEP East Companies, PSO and SWEPCo in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months.

SWEPCo is jointly and severally liable for activity conducted by AEPSC on the behalf of PSO and SWEPCo related to power purchase and sale activity pursuant to the SIA.

Regulatory Activity

Turk Plant

SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.  As of December 31, 2013, SWEPCo’s share of incurred construction expenditures for the Turk Plant was approximately $1.758 billion.  As of December 31, 2013, a pretax provision of $59 million has been recorded for costs incurred in excess of a Texas cost cap, resulting in total net capitalized expenditures of $1.699 billion.  The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant.  In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN.  This Turk Plant output that is currently not subject to cost-based rate recovery and
 
 
213

 
is being sold into the wholesale market.  If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant or transmission lines, it could reduce future net income and cash flows and impact financial condition.  See “Turk Plant” section of Note 3.

2012 Texas Base Rate Case

In December 2013, the PUCT issued an order granting rehearing and reversed its decision on consolidated tax savings increasing SWEPCo’s annual revenues by $5 million.  In January 2014, the PUCT determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap.  As a result of these rulings, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances.  These rulings also increased SWEPCo’s previously approved annual base rates by a total of $13 million.  The resulting annual base rate increase is approximately $52 million.  See the “Turk Plant” and the “2012 Texas Base Rate Case” sections of Note 3.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant.  In February 2013, a settlement was approved by the LPSC that increased Louisiana total rates by approximately $2 million annually, effective March 2013.  The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund.  The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013.  In May 2013, SWEPCo filed testimony in the prudency review of the Turk Plant.  If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudency review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.  See “2012 Louisiana Formula Rate Filing” section of Note 3.

Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC.  Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC.  As of December 31, 2013, SWEPCo has incurred $32 million in costs related to these projects.  SWEPCo will seek recovery of costs it incurs from these projects from its state commissions and FERC customers.

Litigation and Environmental Issues

In the ordinary course of business, SWEPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 376 for additional discussion of relevant factors.

 
214

 
 
RESULTS OF OPERATIONS

KWh Sales/Degree Days

Summary of KWh Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
 
(in millions of KWhs)
Retail:
 
 
 
 
 
 
 
 
 
Residential
 
 6,431 
 
 
 6,301 
 
 
 6,908 
 
Commercial
 
 6,011 
 
 
 6,103 
 
 
 6,280 
 
Industrial
 
 5,612 
 
 
 5,661 
 
 
 5,408 
 
Miscellaneous
 
 81 
 
 
 81 
 
 
 82 
Total Retail
 
 18,135 
 
 
 18,146 
 
 
 18,678 
 
 
 
 
 
 
 
 
 
Wholesale
 
 9,018 
 
 
 7,762 
 
 
 7,947 
 
 
 
 
 
 
 
 
 
Total KWhs
 
 27,153 
 
 
 25,908 
 
 
 26,625 

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.

Summary of Heating and Cooling Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
 
 
 
(in degree days)
 
Actual - Heating (a)
 
 1,421 
 
 
 860 
 
 
 1,271 
 
Normal - Heating (b)
 
 1,226 
 
 
 1,259 
 
 
 1,260 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 2,248 
 
 
 2,605 
 
 
 2,874 
 
Normal - Cooling (b)
 
 2,275 
 
 
 2,256 
 
 
 2,231 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Western Region heating degree days are calculated on a 55 degree temperature base.
 
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
 
(c)
Western Region cooling degree days are calculated on a 65 degree temperature base.

 
215

 
 
2013 Compared to 2012
 
 
 
 
 
 
 
 
 
 
 
Reconciliation of Year Ended December 31, 2012 to Year Ended December 31, 2013
 
Net Income
 
(in millions)
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2012
 
 
 
 
$
 203 
 
 
 
 
 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
 
 
 
Retail Margins (a)
 
 
 
 
 
 119 
 
Off-system Sales
 
 
 
 
 
 4 
 
Transmission Revenues
 
 
 
 
 
 13 
 
Other Revenues
 
 
 
 
 
 1 
 
Total Change in Gross Margin
 
 
 
 
 
 137 
 
 
 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
 
 
 
Other Operation and Maintenance
 
 
 
 
 
 (33)
 
Asset Impairments and Other Related Charges
 
 
 
 
 
 13 
 
Depreciation and Amortization
 
 
 
 
 
 (40)
 
Taxes Other Than Income Taxes
 
 
 
 
 
 (9)
 
Interest Income
 
 
 
 
 
 (1)
 
Allowance for Equity Funds Used During Construction
 
 
 
 
 
 (50)
 
Interest Expense
 
 
 
 
 
 (42)
 
Total Change in Expenses and Other
 
 
 
 
 
 (162)
 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 
 
 
 (24)
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2013
 
 
 
 
$
 154 
 
 
 
 
 
 
 
 
 
 
 
(a)
Includes firm wholesale sales to municipals and cooperatives.

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:

 
·
Retail Margins increased $119 million primarily due to the following:
   
·
A $153 million increase primarily due to the Louisiana and Texas rate orders related to the Turk Plant.
   
This increase was partially offset by:
   
·
A $15 million decrease in municipal and cooperative revenues primarily due to lower realizations from changes in sales volume mix.
   
·
A $9 million decrease primarily due to lower weather-normalized retail sales.
   
·
A $9 million decrease due to fuel cost adjustments.
 
·
Margins from Off-system Sales increased $4 million primarily due to higher physical sales margins.
 
·
Transmission Revenues increased $13 million primarily due to increased investment in the SPP region.

Expenses and Other and Income Tax Expense changed between years as follows:

 
·
Other Operation and Maintenance expenses increased $33 million primarily due to the following:
   
·
A $21 million increase in transmission expenses primarily due to increased SPP transmission services.
   
·
A $12 million increase in generation plant expenses primarily due to Turk Plant operations, partially offset by reduced planned and unplanned plant outage maintenance expenses.
   
·
A $4 million increase in distribution expenses primarily due to increased storm-related and overhead line maintenance expenses.
   
These increases were partially offset by:
   
·
A $6 million decrease in administrative and general expenses.
 
·
Asset Impairments and Other Related Charges decreased $13 million due to the 2012 write-off of the additional expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap.
 
 
216

 
 
 
·
Depreciation and Amortization expenses increased $40 million primarily due to the Turk Plant being placed in service in December 2012.
 
·
Taxes Other Than Income Taxes increased $9 million primarily due to higher property taxes related to the Turk Plant being placed in service in December 2012.
 
·
Allowance for Equity Funds Used During Construction decreased $50 million primarily due to completed construction of the Turk Plant in December 2012.
 
·
Interest Expense increased $42 million primarily due to a decrease in the debt component of AFUDC due to completed construction of the Turk Plant in December 2012.
 
·
Income Tax Expense increased $24 million primarily due to federal and state book/tax differences related to the Turk Plant which are accounted for on a flow-through basis, partially offset by a decrease in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 376 for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 376 for a discussion of accounting pronouncements.

 
217

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of
Southwestern Electric Power Company:

We have audited the accompanying consolidated balance sheets of Southwestern Electric Power Company Consolidated (the "Company") as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Southwestern Electric Power Company Consolidated as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

/s/  Deloitte & Touche LLP

Columbus, Ohio
February 25, 2014

 
218

 

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Southwestern Electric Power Company Consolidated (SWEPCo) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended.  SWEPCo’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of SWEPCo’s internal control over financial reporting as of December 31, 2013.  In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 1992) in Internal Control – Integrated Framework.  Based on management’s assessment, SWEPCo’s internal control over financial reporting was effective as of December 31, 2013.

This annual report does not include an attestation report of SWEPCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit SWEPCo to provide only management’s report in this annual report.

 
219

 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2013, 2012 and 2011
(in thousands)
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
 
REVENUES
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission and Distribution
 
$
 1,742,575 
 
$
 1,538,533 
 
$
 1,594,192 
 
Sales to AEP Affiliates
 
 
 51,812 
 
 
 37,441 
 
 
 57,615 
 
Other Revenues
 
 
 1,416 
 
 
 1,860 
 
 
 2,019 
 
TOTAL REVENUES
 
 
 1,795,803 
 
 
 1,577,834 
 
 
 1,653,826 
 
 
 
 
 
 
 
 
 
 
 
 
 
EXPENSES
 
 
 
 
 
 
 
 
 
 
Fuel and Other Consumables Used for Electric Generation
 
 
 630,503 
 
 
 579,721 
 
 
 626,599 
 
Purchased Electricity for Resale
 
 
 169,954 
 
 
 131,706 
 
 
 152,645 
 
Purchased Electricity from AEP Affiliates
 
 
 11,172 
 
 
 19,229 
 
 
 11,808 
 
Other Operation
 
 
 250,676 
 
 
 230,078 
 
 
 224,068 
 
Maintenance
 
 
 129,742 
 
 
 117,415 
 
 
 140,981 
 
Asset Impairments and Other Related Charges
 
 
 - 
 
 
 13,000 
 
 
 49,000 
 
Depreciation and Amortization
 
 
 179,251 
 
 
 138,778 
 
 
 133,229 
 
Taxes Other Than Income Taxes
 
 
 80,662 
 
 
 72,011 
 
 
 65,239 
 
TOTAL EXPENSES
 
 
 1,451,960 
 
 
 1,301,938 
 
 
 1,403,569 
 
 
 
 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
 
 343,843 
 
 
 275,896 
 
 
 250,257 
 
 
 
 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 
 
 
 
 
 
 
 
 
Interest Income
 
 
 58 
 
 
 1,230 
 
 
 2,076 
 
Allowance for Equity Funds Used During Construction
 
 
 7,338 
 
 
 57,054 
 
 
 48,731 
 
Interest Expense
 
 
 (130,282)
 
 
 (88,318)
 
 
 (81,781)
 
 
 
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY
 
 
 
 
 
 
 
 
 
 
 
EARNINGS
 
 
 220,957 
 
 
 245,862 
 
 
 219,283 
 
 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 69,461 
 
 
 45,858 
 
 
 56,903 
 
Equity Earnings of Unconsolidated Subsidiary
 
 
 2,323 
 
 
 2,509 
 
 
 2,746 
 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME
 
 
 153,819 
 
 
 202,513 
 
 
 165,126 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income Attributable to Noncontrolling Interest
 
 
 4,008 
 
 
 3,622 
 
 
 3,841 
 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME ATTRIBUTABLE TO SWEPCo SHAREHOLDERS
 
 
 149,811 
 
 
 198,891 
 
 
 161,285 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred Stock Dividend Requirements Including Capital Stock
 
 
 
 
 
 
 
 
 
 
 
Expense
 
 
 - 
 
 
 - 
 
 
 579 
 
 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON
 
 
 
 
 
 
 
 
 
 
 
SHAREHOLDER
 
$
 149,811 
 
$
 198,891 
 
$
 160,706 
 
 
 
 
 
 
 
 
 
 
 
 
The common stock of SWEPCo is wholly-owned by AEP.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
220

 
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2013, 2012 and 2011
 (in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
Net Income
 
$
 153,819 
 
$
 202,513 
 
$
 165,126 
 
 
 
 
 
 
 
 
 
 
 
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $1,244, $13 and $6,103 in 2013, 2012 and 2011,
 
 
 
 
 
 
 
 
 
 
Respectively
 
 
 2,311 
 
 
 (25)
 
 
 (11,334)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $137, $358 and
 
 
 
 
 
 
 
 
 
 
$275 in 2013, 2012 and 2011, Respectively
 
 
 (255)
 
 
 665 
 
 
 511 
Pension and OPEB Funded Status, Net of Tax of $3,963, $4,477 and $1,885 in 2013,
 
 
 
 
 
 
 
 
 
 
2012 and 2011, Respectively
 
 
 7,360 
 
 
 8,315 
 
 
 (3,501)
 
 
 
 
 
 
 
 
 
 
 
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)
 
 
 9,416 
 
 
 8,955 
 
 
 (14,324)
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME
 
 
 163,235 
 
 
 211,468 
 
 
 150,802 
 
 
 
 
 
 
 
 
 
 
 
Total Comprehensive Income Attributable to Noncontrolling Interest
 
 
 4,008 
 
 
 3,622 
 
 
 3,841 
 
 
 
 
 
 
 
 
 
 
TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo
 
 
 
 
 
 
 
 
 
 
SHAREHOLDERS
 
$
 159,227 
 
$
 207,846 
 
$
 146,961 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
221

 
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2013, 2012 and 2011
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SWEPCo Common Shareholder
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
 
 
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
Noncontrolling
 
 
 
 
Stock
 
Capital
 
Earnings
 
Income (Loss)
 
Interest
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY – DECEMBER 31, 2010
 
 135,660 
 
 674,979 
 
 868,840 
 
 (12,491)
 
 361 
 
 1,667,349 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends – Nonaffiliated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (3,811)
 
 
 (3,811)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (210)
 
 
 
 
 
 
 
 
 (210)
Loss on Reacquired Preferred Stock
 
 
 
 
 
 (373)
 
 
 
 
 
 
 
 
 
 
 
 (373)
Net Income
 
 
 
 
 
 
 
 
 161,285 
 
 
 
 
 
 3,841 
 
 
 165,126 
Other Comprehensive Loss
 
 
 
 
 
 
 
 
 
 
 
 (14,324)
 
 
 
 
 
 (14,324)
TOTAL EQUITY – DECEMBER 31, 2011
 
 
 135,660 
 
 
 674,606 
 
 
 1,029,915 
 
 
 (26,815)
 
 
 391 
 
 
 1,813,757 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends – Nonaffiliated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (3,752)
 
 
 (3,752)
Net Income
 
 
 
 
 
 
 
 
 198,891 
 
 
 
 
 
 3,622 
 
 
 202,513 
Other Comprehensive Income
 
 
 
 
 
 
 
 
 
 
 
 8,955 
 
 
 
 
 
 8,955 
TOTAL EQUITY – DECEMBER 31, 2012
 
 
 135,660 
 
 
 674,606 
 
 
 1,228,806 
 
 
 (17,860)
 
 
 261 
 
 
 2,021,473 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (125,000)
 
 
 
 
 
 
 
 
 (125,000)
Common Stock Dividends – Nonaffiliated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (3,791)
 
 
 (3,791)
Net Income
 
 
 
 
 
 
 
 
 149,811 
 
 
 
 
 
 4,008 
 
 
 153,819 
Other Comprehensive Income
 
 
 
 
 
 
 
 
 
 
 
 9,416 
 
 
 
 
 
 9,416 
TOTAL EQUITY – DECEMBER 31, 2013
 
 135,660 
 
 674,606 
 
 1,253,617 
 
 (8,444)
 
 478 
 
 2,055,917 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
222

 
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2013 and 2012
(in thousands)
 
 
 
 
 
 
 
December 31,
 
 
 
2013 
 
2012 
 
CURRENT ASSETS
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 17,241 
 
$
 2,036 
 
 
 
(December 31, 2013 Amount Includes $15,827 Related to Sabine)
 
 
 
 
 
 
 
Advances to Affiliates
 
 
 - 
 
 
 153,829 
 
Accounts Receivable:
 
 
 
 
 
 
 
 
Customers
 
 
 86,263 
 
 
 39,349 
 
 
Affiliated Companies
 
 
 22,389 
 
 
 26,288 
 
 
Miscellaneous
 
 
 27,175 
 
 
 35,514 
 
 
Allowance for Uncollectible Accounts
 
 
 (1,418)
 
 
 (2,041)
 
 
 
Total Accounts Receivable
 
 
 134,409 
 
 
 99,110 
 
Fuel
 
 
 
 
 
 
 
 
(December 31, 2013 and 2012 Amounts Include $37,518 and
 
 
 
 
 
 
 
 
$42,084, Respectively, Related to Sabine)
 
 
 122,026 
 
 
 134,234 
 
Materials and Supplies
 
 
 74,862 
 
 
 69,212 
 
Risk Management Assets
 
 
 1,179 
 
 
 695 
 
Deferred Income Tax Benefits
 
 
 177,297 
 
 
 101,403 
 
Accrued Tax Benefits
 
 
 158 
 
 
 9,616 
 
Regulatory Asset for Under-Recovered Fuel Costs
 
 
 17,949 
 
 
 8,527 
 
Prepayments and Other Current Assets
 
 
 20,931 
 
 
 16,489 
 
TOTAL CURRENT ASSETS
 
 
 566,052 
 
 
 595,151 
 
 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
 
Generation
 
 
 3,764,429 
 
 
 3,888,230 
 
 
Transmission
 
 
 1,165,167 
 
 
 1,115,795 
 
 
Distribution
 
 
 1,843,912 
 
 
 1,758,988 
 
Other Property, Plant and Equipment (Including Plant to be Retired)
 
 
 
 
 
 
 
 
(December 31, 2013 and 2012 Amounts include $291,556 and
 
 
 
 
 
 
 
 
$287,032, Respectively, Related to Sabine)
 
 
 869,230 
 
 
 688,254 
 
Construction Work in Progress
 
 
 281,849 
 
 
 99,783 
 
Total Property, Plant and Equipment
 
 
 7,924,587 
 
 
 7,551,050 
 
Accumulated Depreciation and Amortization
 
 
 
 
 
 
 
 
(December 31, 2013 and 2012 Amounts Include $134,282 and
 
 
 
 
 
 
 
 
$116,597, Respectively, Related to Sabine)
 
 
 2,391,652 
 
 
 2,284,258 
 
TOTAL PROPERTY, PLANT AND EQUIPMENT NET
 
 
 5,532,935 
 
 
 5,266,792 
 
 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
 
Regulatory Assets
 
 
 369,905 
 
 
 403,278 
 
Deferred Charges and Other Noncurrent Assets
 
 
 92,890 
 
 
 76,432 
 
TOTAL OTHER NONCURRENT ASSETS
 
 
 462,795 
 
 
 479,710 
 
 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 6,561,782 
 
$
 6,341,653 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
223

 
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31, 2013 and 2012
 
 
 
 
 
 
 
December 31,
 
 
 
2013 
 
2012 
 
 
 
 
(in thousands)
 
CURRENT LIABILITIES
 
 
 
 
 
 
 
Advances from Affiliates
 
$
 9,180 
 
$
 - 
 
Accounts Payable:
 
 
 
 
 
 
 
 
General
 
 
 152,653 
 
 
 126,768 
 
 
Affiliated Companies
 
 
 56,923 
 
 
 62,835 
 
Short-term Debt – Nonaffiliated
 
 
 - 
 
 
 2,603 
 
Long-term Debt Due Within One Year – Nonaffiliated
 
 
 3,250 
 
 
 3,250 
 
Risk Management Liabilities
 
 
 - 
 
 
 1,128 
 
Customer Deposits
 
 
 56,375 
 
 
 69,393 
 
Accrued Taxes
 
 
 41,508 
 
 
 31,532 
 
Accrued Interest
 
 
 43,996 
 
 
 43,950 
 
Obligations Under Capital Leases
 
 
 17,899 
 
 
 17,599 
 
Regulatory Liability for Over-Recovered Fuel Costs
 
 
 7,275 
 
 
 16,761 
 
Other Current Liabilities
 
 
 79,622 
 
 
 64,997 
 
TOTAL CURRENT LIABILITIES
 
 
 468,681 
 
 
 440,816 
 
 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
 
Long-term Debt – Nonaffiliated
 
 
 2,040,082 
 
 
 2,042,978 
 
Deferred Income Taxes
 
 
 1,271,478 
 
 
 1,075,551 
 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 472,128 
 
 
 476,471 
 
Asset Retirement Obligations
 
 
 87,630 
 
 
 78,017 
 
Employee Benefits and Pension Obligations
 
 
 14,602 
 
 
 38,240 
 
Obligations Under Capital Leases
 
 
 105,086 
 
 
 114,161 
 
Deferred Credits and Other Noncurrent Liabilities
 
 
 46,178 
 
 
 53,946 
 
TOTAL NONCURRENT LIABILITIES
 
 
 4,037,184 
 
 
 3,879,364 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 4,505,865 
 
 
 4,320,180 
 
 
 
 
 
 
 
 
 
Rate Matters (Note 3)
 
 
 
 
 
 
 
Commitments and Contingencies (Note 5)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY
 
 
 
 
 
 
 
Common Stock – Par Value – $18 Per Share:
 
 
 
 
 
 
 
 
Authorized –  7,600,000 Shares
 
 
 
 
 
 
 
 
Outstanding  – 7,536,640 Shares
 
 
 135,660 
 
 
 135,660 
 
Paid-in Capital
 
 
 674,606 
 
 
 674,606 
 
Retained Earnings
 
 
 1,253,617 
 
 
 1,228,806 
 
Accumulated Other Comprehensive Income (Loss)
 
 
 (8,444)
 
 
 (17,860)
 
TOTAL COMMON SHAREHOLDER’S EQUITY
 
 
 2,055,439 
 
 
 2,021,212 
 
 
 
 
 
 
 
 
 
Noncontrolling Interest
 
 
 478 
 
 
 261 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY
 
 
 2,055,917 
 
 
 2,021,473 
 
 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 
$
 6,561,782 
 
$
 6,341,653 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
224

 
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2013, 2012 and 2011
(in thousands)
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
2013 
 
2012 
 
2011 
OPERATING ACTIVITIES
 
 
 
 
 
 
 
 
 
Net Income
 
$
 153,819 
 
$
 202,513 
 
$
 165,126 
Adjustments to Reconcile Net Income to Net Cash Flows from
 
 
 
 
 
 
 
 
 
 
Operating Activities:
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 179,251 
 
 
 138,778 
 
 
 133,229 
 
 
Deferred Income Taxes
 
 
 81,888 
 
 
 260,761 
 
 
 16,726 
 
 
Asset Impairments and Other Related Charges
 
 
 - 
 
 
 13,000 
 
 
 49,000 
 
 
Allowance for Equity Funds Used During Construction
 
 
 (7,338)
 
 
 (57,054)
 
 
 (48,731)
 
 
Mark-to-Market of Risk Management Contracts
 
 
 (1,539)
 
 
 (4,159)
 
 
 1,732 
 
 
Pension Contributions to Qualified Plan Trust
 
 
 - 
 
 
 (13,192)
 
 
 (31,263)
 
 
Fuel Over/Under-Recovery, Net
 
 
 (18,916)
 
 
 14,045 
 
 
 (21,485)
 
 
Change in Regulatory Liabilities
 
 
 (12,806)
 
 
 37,955 
 
 
 28,031 
 
 
Change in Other Noncurrent Assets
 
 
 34,559 
 
 
 21,309 
 
 
 24,519 
 
 
Change in Other Noncurrent Liabilities
 
 
 (634)
 
 
 14,594 
 
 
 20,904 
 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 (35,472)
 
 
 (21,919)
 
 
 20,751 
 
 
 
Fuel, Materials and Supplies
 
 
 6,558 
 
 
 (46,106)
 
 
 (15,168)
 
 
 
Accounts Payable
 
 
 12,816 
 
 
 3,813 
 
 
 1,168 
 
 
 
Accrued Taxes, Net
 
 
 25,341 
 
 
 (16,057)
 
 
 40,189 
 
 
 
Other Current Assets
 
 
 (1,398)
 
 
 (387)
 
 
 2,983 
 
 
 
Other Current Liabilities
 
 
 1,634 
 
 
 (3,611)
 
 
 (570)
Net Cash Flows from Operating Activities
 
 
 417,763 
 
 
 544,283 
 
 
 387,141 
 
 
 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
 
 
 
Construction Expenditures
 
 
 (411,512)
 
 
 (542,427)
 
 
 (551,163)
Change in Advances to Affiliates, Net
 
 
 153,829 
 
 
 (153,829)
 
 
 86,222 
Acquisitions of Assets
 
 
 (975)
 
 
 (1,091)
 
 
 (8,045)
Other Investing Activities
 
 
 (1,099)
 
 
 2,696 
 
 
 2,102 
Net Cash Flows Used for Investing Activities
 
 
 (259,757)
 
 
 (694,651)
 
 
 (470,884)
 
 
 
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
 
 
 
Issuance of Long-term Debt – Nonaffiliated
 
 
 - 
 
 
 336,418 
 
 
 - 
Credit Facility Borrowings
 
 
 17,091 
 
 
 25,123 
 
 
 58,435 
Change in Advances from Affiliates, Net
 
 
 9,180 
 
 
 (132,473)
 
 
 132,473 
Retirement of Long-term Debt – Nonaffiliated
 
 
 (3,250)
 
 
 (21,625)
 
 
 (41,135)
Retirement of Cumulative Preferred Stock
 
 
 - 
 
 
 - 
 
 
 (5,069)
Credit Facility Repayments
 
 
 (19,694)
 
 
 (39,536)
 
 
 (47,636)
Principal Payments for Capital Lease Obligations
 
 
 (18,111)
 
 
 (16,537)
 
 
 (13,675)
Dividends Paid on Common Stock
 
 
 (125,000)
 
 
 - 
 
 
 - 
Dividends Paid on Common Stock – Nonaffiliated
 
 
 (3,791)
 
 
 (3,752)
 
 
 (3,811)
Dividends Paid on Cumulative Preferred Stock
 
 
 - 
 
 
 - 
 
 
 (210)
Other Financing Activities
 
 
 774 
 
 
 3,985 
 
 
 3,658 
Net Cash Flows from (Used for) Financing Activities
 
 
 (142,801)
 
 
 151,603 
 
 
 83,030 
 
 
 
 
 
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 15,205 
 
 
 1,235 
 
 
 (713)
Cash and Cash Equivalents at Beginning of Period
 
 
 2,036 
 
 
 801 
 
 
 1,514 
Cash and Cash Equivalents at End of Period
 
$
 17,241 
 
$
 2,036 
 
$
 801 
 
 
 
 
 
 
 
 
 
 
SUPPLEMENTARY INFORMATION
 
 
 
 
 
 
 
 
 
Cash Paid for Interest, Net of Capitalized Amounts
 
$
 120,427 
 
$
 68,918 
 
$
 71,713 
Net Cash Paid (Received) for Income Taxes
 
 
 (35,363)
 
 
 (191,638)
 
 
 (336)
Noncash Acquisitions Under Capital Leases
 
 
 9,376 
 
 
 20,547 
 
 
 13,334 
Construction Expenditures Included in Current Liabilities as of December 31,
 
 
 63,169 
 
 
 55,767 
 
 
 109,600 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 227.

 
225

 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to SWEPCo’s financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to SWEPCo.  The footnotes begin on page 227.

 
Page
Number
   
Organization and Summary of Significant Accounting Policies
  228
Comprehensive Income
  240
Rate Matters
  249
Effects of Regulation
  259
Commitments, Guarantees and Contingencies
  265
Acquisition, Disposition and Impairments
  271
Benefit Plans
  273
Business Segments
  308
Derivatives and Hedging
  308
Fair Value Measurements
  323
Income Taxes
  334
Leases
  343
Financing Activities
  346
Related Party Transactions
  352
Variable Interest Entities
  360
Property, Plant and Equipment
  366
Sustainable Cost Reductions
  374
Unaudited Quarterly Financial Information
  375


 
226

 


INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to financial statements that follow are a combined presentation for the Registrant Subsidiaries.  The following list indicates the registrants to which the footnotes apply:

   
Page
Number
     
Organization and Summary of Significant Accounting Policies
APCo, I&M, OPCo, PSO, SWEPCo
  228
Comprehensive Income
APCo, I&M, OPCo, PSO, SWEPCo
  240
Rate Matters
APCo, I&M, OPCo, PSO, SWEPCo
  249
Effects of Regulation
APCo, I&M, OPCo, PSO, SWEPCo
  259
Commitments, Guarantees and Contingencies
APCo, I&M, OPCo, PSO, SWEPCo
  265
Acquisition, Disposition and Impairments
APCo, OPCo, SWEPCo
  271
Benefit Plans
APCo, I&M, OPCo, PSO, SWEPCo
  273
Business Segments
APCo, I&M, OPCo, PSO, SWEPCo
  308
Derivatives and Hedging
APCo, I&M, OPCo, PSO, SWEPCo
  308
Fair Value Measurements
APCo, I&M, OPCo, PSO, SWEPCo
  323
Income Taxes
APCo, I&M, OPCo, PSO, SWEPCo
  334
Leases
APCo, I&M, OPCo, PSO, SWEPCo
  342
Financing Activities
APCo, I&M, OPCo, PSO, SWEPCo
  346
Related Party Transactions
APCo, I&M, OPCo, PSO, SWEPCo
  352
Variable Interest Entities
APCo, I&M, OPCo, PSO, SWEPCo
  360
Property, Plant and Equipment
APCo, I&M, OPCo, PSO, SWEPCo
  366
Sustainable Cost Reductions
APCo, I&M, OPCo, PSO, SWEPCo
  374
Unaudited Quarterly Financial Information
APCo, I&M, OPCo, PSO, SWEPCo
  375

 
227

 

1.   ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

The principal business conducted by the Registrant Subsidiaries is the generation, transmission and distribution of electric power.  These companies are subject to regulation by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines.  These companies are subject to further regulation with regard to rates and other matters by state regulatory commissions.

The Registrant Subsidiaries also engage in wholesale electricity marketing and risk management activities in the United States.  I&M provides barging services to both affiliated and nonaffiliated companies.  SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities.

Corporate Separation

Background

On December 31, 2013, based on FERC and PUCO orders which approved corporate separation of generation assets and associated liabilities, OPCo transferred its generation assets and related generation liabilities at net book value to AGR.  In accordance with Ohio law, OPCo remains responsible to provide power and capacity to OPCo customers who have not switched electric providers.  Effective January 1, 2014, OPCo will purchase power from both affiliated and nonaffiliated entities, subject to PUCO approval, to meet the energy and capacity needs of customers.

In April 2013 and in connection with corporate separation of OPCo’s generation assets and liabilities, OPCo sold the majority of its assets related to its wholly-owned subsidiary, Conesville Coal Preparation Company (CCPC).  Also in connection with corporate separation, OPCo transferred its ownership of Cook Coal Terminal to AEGCo in August 2013.

On December 31, 2013, subsequent to the transfer of OPCo’s generation assets and associated liabilities to AGR, AGR transferred at net book value its ownership (867 MW) in Amos Plant, Unit 3 to APCo.  The transfer of these generation assets and associated liabilities was approved by the FERC, the Virginia SCC and the WVPSC.

Significant Accounting Issues

Shown below are the carrying amounts of OPCo generation assets, liabilities and equity that were distributed to AGR on December 31, 2013:

          December 31,   
 
 
 
 
 
2013 
 
 
ASSETS
 
(in thousands)
 
 
Current Assets
 
$
 777,677 
 
 
Net Property, Plant and Equipment
 
 
 5,685,415 
 
 
Other Noncurrent Assets
 
 
 259,801 
 
 
Total Assets
 
$
 6,722,893 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
Long-term Debt
 
$
 1,411,825 
 
 
Other Current Liabilities
 
 
 633,505 
 
 
Other Noncurrent Liabilities
 
 
 1,672,189 
 
 
Equity
 
 
 3,005,374 
 
 
Total Liabilities and Equity
 
$
 6,722,893 
 

 
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As noted above, APCo’s acquisition of the two-thirds ownership in Amos Plant, Unit 3 qualifies as an acquisition of a business under common control, which is typically accounted for as if the transfer had occurred at the beginning of the earliest period presented, pursuant to accounting guidance for “Business Combinations.”  However, management determined the retrospective application of this transfer to be quantitatively and qualitatively immaterial when taken as a whole in relation to APCo’s financial statements.  As a result, APCo’s financial statements were not retrospectively adjusted to reflect the transfer.

All regulatory assets and regulatory liabilities related to OPCo’s generation activities remain on OPCo’s balance sheet subsequent to OPCo’s transfer of generation assets and associated liabilities to AGR.  As previously approved by the PUCO, these regulatory assets and liabilities will be recovered/refunded primarily through OPCo non-bypassable riders.

Substantially all of the current income tax receivables and payables related to OPCo’s generation activities prior to December 31, 2013 will remain on OPCo’s balance sheet.  These current income tax receivables and payables are the responsibility of OPCo.  Deferred tax assets and liabilities related to APCo’s acquired share of Amos Plant, Unit 3 and KPCo’s acquired share of the Mitchell Plant were transferred to APCo and KPCo, respectively, based upon their respective plant-related asset and liability values.  Following these transfers, APCo and KPCo adjusted their deferred tax balances and related regulatory assets to reflect their respective deferred state tax rates.

Long-term Debt

In the fourth quarter of 2013, OPCo:

·  
Drew down an additional $400 million of Long-term Debt – Nonaffiliated on an existing $1 billion term credit facility and subsequently assigned $1 billion of Long-term Debt – Nonaffiliated that was drawn down on this term credit facility to AGR.
·  
Received $297 million of Notes Receivable – Affiliated from AGR with terms and conditions similar to OPCo Pollution Control Bonds.
·  
Retired $200 million of Long-term Debt – Affiliated in the fourth quarter of 2013.
·  
Assigned $115 million of Long-term Debt – Nonaffiliated to AGR related to certain OPCo Pollution Control Bonds.
·  
Retired $50 million of Long-term Debt – Nonaffiliated related to OPCo Pollution Control Bonds.

On December 31, 2013, APCo:

·  
Was assigned $300 million of Long-term Debt – Nonaffiliated from AGR related to a term credit facility.
·  
Issued $86 million in Long-term Debt – Affiliated to AGR.

Other Impacts of Corporate Separation

In accordance with the December 2010 announcement and the October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014.  The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection agreement was also terminated.
 
Effective January 1, 2014, the FERC approved:

·  
PCA among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.  Under the PCA, APCo, I&M and KPCo will be individually responsible for planning their respective capacity obligations and there will be no capacity equalization charges/credits on deficit/surplus companies.   Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities.
·  
Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent.  The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b)

 
229

 
 
  
address how member companies will fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year.  Under the Bridge Agreement, AGR is committed to meet capacity obligations of member companies.
·  
Power Supply Agreement (PSA) between AGR and OPCo for AGR to supply capacity for OPCo’s switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that is not acquired through auctions from January 1, 2014 through December 31, 2014.
 
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rates and Service Regulation

The Registrant Subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the nine state operating territories in which they operate.  The FERC also regulates the Registrant Subsidiaries’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act.  The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company.  For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate.  The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes.  Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system.

The FERC regulates wholesale power markets and wholesale power transactions.  The Registrant Subsidiaries’ wholesale power transactions are generally market-based.  Wholesale power transactions are cost-based regulated when the Registrant Subsidiaries negotiate and file a cost-based contract with the FERC or the FERC determines that the Registrant Subsidiaries have “market power” in the region where the transaction occurs.  The Registrant Subsidiaries have entered into wholesale power supply contracts with various municipalities and cooperatives that are FERC-regulated, cost-based contracts.  These contracts are generally formula rate mechanisms, which are trued up to actual costs annually.  PSO’s and SWEPCo’s wholesale power transactions in the SPP region are currently cost-based within their balancing authority due to the FERC’s finding that PSO and SWEPCo have market power in the SPP region.

The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrant Subsidiaries on a cost basis.  The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio.  The ESP rates in Ohio continue the process of transitioning generation/power supply rates over time to market rates.
 
The FERC also regulates the Registrant Subsidiaries’ wholesale transmission operations and rates.  The FERC claims jurisdiction over retail transmission rates when retail rates are unbundled in connection with restructuring.  OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia and I&M’s retail transmission rates in Michigan are unbundled and are based on formula rates included in the PJM OATT that are cost-based.  Bundled retail transmission rates are regulated, on a cost basis, by the state commissions.

In addition, the FERC regulates the SIA, the Operating Agreement, the System Transmission Integration Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which are still active and allocate shared system costs and revenues to the Registrant Subsidiaries that are parties to each agreement.  In accordance with management’s December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014.  The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated.  In December 2013, the FERC issued orders approving the creation of a PCA, effective January 1, 2014.  Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent.

 
230

 
Principles of Consolidation

The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE).  The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs).  The consolidated financial statements for OPCo include the Registrant Subsidiary, a wholly-owned subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE).  The consolidated financial statements for SWEPCo include the Registrant Subsidiary, a wholly-owned subsidiary and Sabine (a substantially-controlled VIE).  Intercompany items are eliminated in consolidation.  The Registrant Subsidiaries use the equity method of accounting for equity investments where they exercise significant influence but do not hold a controlling financial interest.  Such investments are recorded as Deferred Charges and Other Noncurrent Assets on the balance sheets; equity earnings are included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income.  OPCo, PSO and SWEPCo have ownership interests in generating units that are jointly-owned with nonaffiliated companies.  The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected in the balance sheets.  See Note 15 − Variable Interest Entities.

Accounting for the Effects of Cost-Based Regulation

As rate-regulated electric public utility companies, the Registrant Subsidiaries’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated.  In accordance with accounting guidance for “Regulated Operations,” the Registrant Subsidiaries record regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.

Use of Estimates

The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes.  These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits.  The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements.  Actual results could ultimately differ from those estimates.

Cash and Cash Equivalents

Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.

Inventory

Fossil fuel inventories are carried at average cost.  Materials and supplies inventories are carried at average cost.

Accounts Receivable

Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities.

Revenue is recognized from electric power sales when power is delivered to customers.  To the extent that deliveries have occurred but a bill has not been issued, the Registrant Subsidiaries accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing.

 
231

 
AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, OPCo, PSO, SWEPCo and a portion of APCo.  Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit.  See “Sale of Receivables – AEP Credit” section of Note 13 for additional information.

Allowance for Uncollectible Accounts

Generally, AEP Credit records bad debt expense related to receivables purchased from the Registrant Subsidiaries under a sale of receivables agreement.  For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable.  For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis.  For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified.  Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.

Concentrations of Credit Risk and Significant Customers

The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues as of December 31, 2013.

The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk.  The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs.  Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements.

Emission Allowances

The Registrant Subsidiaries in regulated jurisdictions record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA.  Prior to corporate separation and the distribution of all emission allowances to AGR on December 31, 2013, OPCo recorded allowances at the lower of cost or market.  The Registrant Subsidiaries follow the inventory model for these allowances.  Allowances expected to be consumed within one year are reported in Materials and Supplies.  Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets.  These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost.  The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows.  The net margin on sales of emission allowances is included in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions because of its integral nature to the production process of energy and the Registrant Subsidiaries’ revenue optimization strategy for their operations.  The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions.

Property, Plant and Equipment and Equity Investments

Regulated

Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts.  Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation.  The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss.  The equipment in each primary electric plant account is identified as a separate group.  The depreciation rates that are established take into account the past history of interim capital replacements and the amount of salvage received.  These rates and the related lives are subject to periodic review.  Removal costs are charged to regulatory liabilities.  The costs of labor, materials and overhead incurred to operate and maintain plants are included in operating expenses.

 
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Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.”  When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense.  Equity investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value.

The fair value of an asset or investment is the amount at which that asset or investment could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets or investments in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.

Nonregulated

Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions.  Property, plant and equipment of nonregulated operations and equity investments (included in Deferred Charges and Other Noncurrent Assets) are stated at fair value at acquisition (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals.  Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation.  A gain or loss would be recorded if the retirement is not considered an interim routine replacement.  Removal costs are charged to expense.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization

For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant.  The Registrant Subsidiaries record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense.  For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”

Valuation of Nonderivative Financial Instruments

The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments.  The book value of the pre-April 1983 spent nuclear fuel disposal liability for I&M approximates the best estimate of its fair value.

Fair Value Measurements of Assets and Liabilities

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.  The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors.  The AEP System’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures.  The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.

 
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For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1.  Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated.  Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace.  When multiple broker quotes are obtained, the quoted bid and ask prices are averaged.  In certain circumstances, a broker quote may be discarded if it is a clear outlier.  Management uses a historical correlation analysis between the broker quoted location and the illiquid locations.  If the points are highly correlated, these locations are included within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs.  Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.  The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market.  A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.

AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts.  AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value.  AEP’s management performs its own valuation testing to verify the fair values of the securities.  AEP receives audit reports of the trustee’s operating controls and valuation processes.  The trustee uses multiple pricing vendors for the assets held in the trusts.

Assets in the benefits and nuclear trusts, Other Cash Deposits and Cash and Cash Equivalents are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities.  They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets.  Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds.  Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.  Benefit plan assets included in Level 3 are primarily real estate and private equity investments that are valued using methods requiring judgment including appraisals.

Deferred Fuel Costs

The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized.  The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method.  In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel revenues billed to customers over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel revenues billed to customers) are generally deferred as current regulatory assets.  Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended.  These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval.  The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions.  On a routine basis, state regulatory commissions review and/or audit the Registrant Subsidiaries’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals.  When a FAC under-recovery is no longer probable of recovery, the Registrant Subsidiaries adjust their FAC deferrals and record provisions for estimated refunds to recognize these probable outcomes.

 
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Changes in fuel costs, including purchased power in Indiana and Michigan for I&M, in Ohio (beginning in 2012 through the ESP related to non-auction standard service offer load served) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO and in Virginia and West Virginia (upon securitization in November 2013) for APCo are reflected in rates in a timely manner generally through the FAC.  Changes in fuel costs, including purchased power in Ohio (beginning in 2009 through 2011) for OPCo and in West Virginia (prior to securitization in November 2013) for APCo are reflected in rates through FAC phase-in plans.  The FAC generally includes some sharing of off-system sales.  In West Virginia for APCo, all of the profits from off-system sales are given to customers through the FAC.  None of the profits from off-system sales are given to customers through the FAC in Ohio for OPCo.  A portion of profits from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Virginia for APCo and in Indiana and Michigan for I&M.  Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.

Revenue Recognition

Regulatory Accounting

The financial statements of the Registrant Subsidiaries reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.  Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.

When regulatory assets are probable of recovery through regulated rates, the Registrant Subsidiaries record them as assets on the balance sheets.  The Registrant Subsidiaries test for probability of recovery at each balance sheet date or whenever new events occur.  Examples of new events include the issuance of a regulatory commission order or passage of new legislation.  If it is determined that recovery of a regulatory asset is no longer probable, the Registrant Subsidiaries write off that regulatory asset as a charge against income.

Electricity Supply and Delivery Activities

The Registrant Subsidiaries recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services.  The Registrant Subsidiaries recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts.  In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue.

Most of the power produced at the generation plants of the AEP East Companies is sold to PJM.  The AEP East Companies purchase power from PJM to supply power to their customers.  Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income.  However, purchases of power in excess of sales to PJM, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income.  Other RTOs in which the Registrant Subsidiaries participate do not function in the same manner as PJM.  They function as balancing organizations and not as exchanges.

Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income.  Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s economic substance.  Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income.  All other non-trading derivative purchases are recorded net in revenues.

In general, the Registrant Subsidiaries record expenses when purchased electricity is received and when expenses are incurred.  For certain power purchase contracts that are derivatives and accounted for using MTM accounting, OPCo records these contracts on a net basis in revenues.  In other jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

 
235

 
Energy Marketing and Risk Management Activities

AEPSC, on behalf of the Registrant Subsidiaries, engages in wholesale power, coal and natural gas marketing and risk management activities focused on wholesale markets where the AEP System owns assets and adjacent markets.  These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices.  These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options.  Certain energy marketing and risk management transactions are with RTOs.

The Registrant Subsidiaries recognize revenues and expenses from wholesale marketing and risk management transactions that are not derivatives upon delivery of the commodity.  The Registrant Subsidiaries use MTM accounting for wholesale marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or a normal purchase or sale.  The Registrant Subsidiaries include realized gains and losses on wholesale marketing and risk management transactions in revenues on a net basis.  For OPCo, unrealized gains and losses on wholesale marketing and risk management transactions that are accounted for using MTM are included in revenues on a net basis.  For APCo, I&M, PSO and SWEPCo, who are subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).  Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate.

Certain qualifying wholesale marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge).  The Registrant Subsidiaries initially record the effective portion of the cash flow hedge’s gain or loss as a component of AOCI.  When the forecasted transaction is realized and affects net income, the Registrant Subsidiaries subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income.  For OPCo, the ineffective portion of the gain or loss is recognized in revenues or expense on the income statements immediately.  APCo, I&M, PSO and SWEPCo, who are subject to cost-based regulation, defer the ineffective portion as regulatory assets (for losses) and regulatory liabilities (for gains).  See “Accounting for Cash Flow Hedging Strategies” section of Note 9.

Levelization of Nuclear Refueling Outage Costs

In accordance with regulatory orders, I&M defers incremental operation and maintenance costs associated with periodic refueling outages at its Cook Plant and amortizes the costs over the period beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins.  I&M adjusts the amortization amount as necessary to ensure full amortization of all deferred costs by the end of the refueling cycle.

Maintenance

The Registrant Subsidiaries expense maintenance costs as incurred.  If it becomes probable that the Registrant Subsidiaries will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues.  In certain regulatory jurisdictions, the Registrant Subsidiaries defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.

Income Taxes and Investment Tax Credits

The Registrant Subsidiaries use the liability method of accounting for income taxes.  Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence.

When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense.

 
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Investment tax credits are accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis.  Investment tax credits that have been deferred are amortized over the life of the plant investment.

The Registrant Subsidiaries account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.”  The Registrant Subsidiaries classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense.

Excise Taxes

As agents for some state and local governments, the Registrant Subsidiaries collect from customers certain excise taxes levied by those state or local governments on customers.  The Registrant Subsidiaries do not record these taxes as revenue or expense.

Debt

Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced.  If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates.  Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition.

Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt.  The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations.  The net amortization expense is included in Interest Expense.

Investments Held in Trust for Future Liabilities

AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and spent nuclear fuel disposal.  All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations.  The investment strategy for trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the interest rate sensitivity of the assets relative to the associated liabilities.  To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers.  Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate.  Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities.  The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance.

Benefit Plans

All benefit plan assets are invested in accordance with each plan’s investment policy.  The investment policy outlines the investment objectives, strategies and target asset allocations by plan.

The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns.  Strategies used include:

·  
Maintaining a long-term investment horizon.
·  
Diversifying assets to help control volatility of returns at acceptable levels.
·  
Managing fees, transaction costs and tax liabilities to maximize investment earnings.
·  
Using active management of investments where appropriate risk/return opportunities exist.
·  
Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks.
·  
Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification.

 
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The investment policy for the pension fund allocates assets based on the funded status of the pension plan.  The objective of the asset allocation policy is to reduce the investment volatility of the plan over time.  Generally, more of the investment mix will be allocated to fixed income investments as the plan becomes better funded.  Assets will be transferred away from equity investments into fixed income investments based on the market value of plan assets compared to the plan’s projected benefit obligation.  The current target asset allocations are as follows:

Pension Plan Assets
 
Target
Equity
 
 30.0 
%
Fixed Income
 
 55.0 
%
Other Investments
 
 15.0 
%
 
 
 
OPEB Plans Assets
 
Target
Equity
 
 66.0 
%
Fixed Income
 
 33.0 
%
Cash
 
 1.0 
%

The investment policy for each benefit plan contains various investment limitations.  The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies).  However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law.  Each investment manager's portfolio is compared to a diversified benchmark index.

For equity investments, the limits are as follows:

·  
No security in excess of 5% of all equities.
·  
Cash equivalents must be less than 10% of an investment manager's equity portfolio.
·  
No individual stock may be more than 10% of each manager's equity portfolio.
·  
No investment in excess of 5% of an outstanding class of any company.
·  
No securities may be bought or sold on margin or other use of leverage.

For fixed income investments, the concentration limits must not exceed:

·  
3% in any single issuer
·  
5% for private placements
·  
5% for convertible securities
·  
60% for bonds rated AA+ or lower
·  
50% for bonds rated A+ or lower
·  
10% for bonds rated BBB- or lower

For obligations of non-government issuers, the following limitations apply:

·  
AAA rated debt: a single issuer should account for no more than 5% of the portfolio.
·  
AA+, AA, AA- rated debt: a single issuer should account for no more than 3% of the portfolio.
·  
Debt rated A+ or lower:  a single issuer should account for no more than 2% of the portfolio.
·  
No more than 10% of the portfolio may be invested in high yield and emerging market debt combined at any time.

A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation.  Real estate properties are illiquid, difficult to value and not actively traded.  The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties.  To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification.  Real estate holdings include core, value-added and development risk classifications and some investments in Real Estate Investment Trusts (REITs), which are publicly traded real estate securities.

 
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A portion of the pension assets is invested in private equity.  Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance.  Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded.  The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum.   The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise.  The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investment instruments.  Commingled private equity funds are used to enhance the holdings’ diversity.

AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses.  AEP lends securities to borrowers approved by BNY Mellon in exchange for cash collateral.  All loans are collateralized by at least 102% of the loaned asset’s market value and the cash collateral is invested.  The difference between the rebate owed to the borrower and the cash collateral rate of return determines the earnings on the loaned security.  The securities lending program’s objective is providing modest incremental income with a limited increase in risk.

Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts.  The strategy for holding life insurance contracts in the taxable Voluntary Employees' Beneficiary Association (VEBA) trust is to minimize taxes paid on the asset growth in the trust.  Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid.  Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities.  With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds.  A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges.  The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities.

Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal.  The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities.  The cash funds are valued each business day and provide daily liquidity.

Nuclear Trust Funds

Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities.  By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines.  In general, limitations include:

·  
Acceptable investments (rated investment grade or above when purchased).
·  
Maximum percentage invested in a specific type of investment.
·  
Prohibition of investment in obligations of AEP, I&M or their affiliates.
·  
Withdrawals permitted only for payment of decommissioning costs and trust expenses.

I&M maintains trust funds for each regulatory jurisdiction.  The trust assets may not be used for another jurisdiction’s liabilities.  Regulatory approval is required to withdraw decommissioning funds.  These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets.  I&M records these securities at fair value.  I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose.  Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment.  I&M records unrealized
 
 
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gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  Consequently, changes in fair value of trust assets do not affect earnings or AOCI.  See the “Nuclear Contingencies” section of Note 5 for additional discussion of nuclear matters.  See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 10 for disclosure of the fair value of assets within the trusts.

Comprehensive Income (Loss)

Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources.  It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners.  Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).

Earnings Per Share (EPS)

The Registrant Subsidiaries are wholly-owned subsidiaries of AEP.  Therefore, none are required to report EPS.

OPCo Revised Depreciation Rates

Effective December 1, 2011, OPCo revised book depreciation rates for certain of OPCo’s generation plants consistent with shortened depreciable lives for the generating units.  This change in depreciable lives resulted in a $52 million increase in depreciation expense in 2012.

In the fourth quarter of 2012, OPCo impaired the generating units discussed above (see Note 6).  As a result of this impairment of the full book value of these assets, OPCo ceased depreciation on these generating units effective December 1, 2012.

In the second quarter of 2013, OPCo impaired Muskingum River Plant, Unit 5 (MR5).  As a result of this impairment of the full book value of this generating unit, OPCo ceased depreciation on MR5 effective July 1, 2013.

2.   COMPREHENSIVE INCOME

Presentation of Comprehensive Income

The following tables provide the components of changes in AOCI for the year ended December 31, 2013.  All amounts in the following tables are presented net of related income taxes.

APCo
 
Changes in Accumulated Other Comprehensive Income (Loss) by Component
 
For the Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges
 
Pension and OPEB
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
Amortization
 
Changes
 
 
 
 
 
 
 
 
 
 
and Foreign
 
of Deferred
 
in Funded
 
 
 
 
 
 
 
Commodity
 
Currency
 
Costs
 
Status
 
Total
 
 
 
 
(in thousands)
 
Balance in AOCI as of December 31, 2012
$
 (644)
 
$
 2,077 
 
$
 19,118 
 
$
 (50,449)
 
$
 (29,898)
 
Change in Fair Value Recognized in AOCI
 
 768 
 
 
 - 
 
 
 - 
 
 
 29,665 
 
 
 30,433 
 
Amounts Reclassified from AOCI
 
 (30)
 
 
 1,013 
 
 
 1,433 
 
 
 - 
 
 
 2,416 
 
Net Current Period Other
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Comprehensive Income
 
 738 
 
 
 1,013 
 
 
 1,433 
 
 
 29,665 
 
 
 32,849 
 
Balance in AOCI as of December 31, 2013
$
 94 
 
$
 3,090 
 
$
 20,551 
 
$
 (20,784)
 
$
 2,951 


 
240

 
 
I&M
 
Changes in Accumulated Other Comprehensive Income (Loss) by Component
 
For the Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges
 
Pension and OPEB
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
Amortization
 
Changes
 
 
 
 
 
 
 
 
 
 
and Foreign
 
of Deferred
 
in Funded
 
 
 
 
 
 
 
Commodity
 
Currency
 
Costs
 
Status
 
Total
 
 
 
 
(in thousands)
 
Balance in AOCI as of December 31, 2012
$
 (446)
 
$
 (19,647)
 
$
 4,201 
 
$
 (12,991)
 
$
 (28,883)
 
Change in Fair Value Recognized in AOCI
 
 477 
 
 
 2,249 
 
 
 - 
 
 
 8,511 
 
 
 11,237 
 
Amounts Reclassified from AOCI
 
 15 
 
 
 1,422 
 
 
 700 
 
 
 - 
 
 
 2,137 
 
Net Current Period Other
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Comprehensive Income
 
 492 
 
 
 3,671 
 
 
 700 
 
 
 8,511 
 
 
 13,374 
 
Balance in AOCI as of December 31, 2013
$
 46 
 
$
 (15,976)
 
$
 4,901 
 
$
 (4,480)
 
$
 (15,509)

OPCo
 
Changes in Accumulated Other Comprehensive Income (Loss) by Component
 
For the Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges
 
Pension and OPEB
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
Amortization
 
Changes
 
 
 
 
 
 
 
 
 
 
and Foreign
 
of Deferred
 
in Funded
 
 
 
 
 
 
 
Commodity
 
Currency
 
Costs
 
Status
 
Total
 
 
 
 
(in thousands)
 
Balance in AOCI as of December 31, 2012
$
 (912)
 
$
 8,095 
 
$
 45,938 
 
$
 (218,846)
 
$
 (165,725)
 
Change in Fair Value Recognized in AOCI
 
 982 
 
 
 - 
 
 
 - 
 
 
 65,418 
 
 
 66,400 
 
Amounts Reclassified from AOCI
 
 22 
 
 
 (1,359)
 
 
 12,509 
 
 
 - 
 
 
 11,172 
 
Net Current Period Other
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Comprehensive Income
 
 1,004 
 
 
 (1,359)
 
 
 12,509 
 
 
 65,418 
 
 
 77,572 
 
Distribution of Cook Coal Terminal to Parent
 
 - 
 
 
 - 
 
 
 - 
 
 
 19,652 
 
 
 19,652 
 
Distribution of OPCo Generation to Parent
 
 13 
 
 
 238 
 
 
 - 
 
 
 75,329 
 
 
 75,580 
 
Balance in AOCI as of December 31, 2013
$
 105 
 
$
 6,974 
 
$
 58,447 
 
$
 (58,447)
 
$
 7,079 

PSO
 
 
Changes in Accumulated Other Comprehensive Income (Loss) by Component
 
 
For the Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
 
 
 
 
 
 
 
Commodity
 
Foreign Currency
 
Total
 
 
 
 
 
(in thousands)
 
 
Balance in AOCI as of December 31, 2012
$
 21 
 
$
 6,460 
 
$
 6,481 
 
 
Change in Fair Value Recognized in AOCI
 
 68 
 
 
 - 
 
 
 68 
 
 
Amounts Reclassified from AOCI
 
 (32)
 
 
 (759)
 
 
 (791)
 
 
Net Current Period Other
 
 
 
 
 
 
 
 
 
 
 
 
Comprehensive Income
 
 36 
 
 
 (759)
 
 
 (723)
 
 
Balance in AOCI as of December 31, 2013
$
 57 
 
$
 5,701 
 
$
 5,758 
 


 
241

 
 
SWEPCo
 
Changes in Accumulated Other Comprehensive Income (Loss) by Component
 
For the Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges
 
Pension and OPEB
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
Amortization
 
Changes
 
 
 
 
 
 
 
 
 
 
and Foreign
 
of Deferred
 
in Funded
 
 
 
 
 
 
 
Commodity
 
Currency
 
Costs
 
Status
 
Total
 
 
 
 
(in thousands)
 
Balance in AOCI as of December 31, 2012
$
 22 
 
$
 (15,571)
 
$
 4,778 
 
$
 (7,089)
 
$
 (17,860)
 
Change in Fair Value Recognized in AOCI
 
 83 
 
 
 - 
 
 
 - 
 
 
 7,360 
 
 
 7,443 
 
Amounts Reclassified from AOCI
 
 (39)
 
 
 2,267 
 
 
 (255)
 
 
 - 
 
 
 1,973 
 
Net Current Period Other
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Comprehensive Income
 
 44 
 
 
 2,267 
 
 
 (255)
 
 
 7,360 
 
 
 9,416 
 
Balance in AOCI as of December 31, 2013
$
 66 
 
$
 (13,304)
 
$
 4,523 
 
$
 271 
 
$
 (8,444)

Reclassifications from Accumulated Other Comprehensive Income

The following tables provide details of reclassifications from AOCI for the year ended December 31, 2013.  The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs.  See Note 7 for additional details.

APCo
 
 
 
 
Reclassifications from Accumulated Other Comprehensive Income (Loss)
 
For the Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
Amount of
 
 
 
 
 
(Gain) Loss
 
 
 
 
 
 Reclassified
 
 
 
 
 
from AOCI
 
Gains and Losses on Cash Flow Hedges
 
(in thousands)
 
Commodity:
 
 
 
 
 
 
Electric Generation, Transmission and Distribution Revenues
 
$
 (80)
 
 
 
Purchased Electricity for Resale
 
 
 90 
 
 
 
Other Operation Expense
 
 
 (37)
 
 
 
Maintenance Expense
 
 
 (31)
 
 
 
Property, Plant and Equipment
 
 
 (35)
 
 
 
Regulatory Assets/(Liabilities), Net (a)
 
 
 47 
 
Subtotal - Commodity
 
 
 (46)
 
 
 
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
 
 
Interest Expense
 
 
 1,559 
 
Subtotal - Interest Rate and Foreign Currency
 
 
 1,559 
 
 
 
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 1,513 
 
Income Tax (Expense) Credit
 
 
 530 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 983 
 
 
 
 
 
 
Pension and OPEB
 
 
 
 
Amortization of Prior Service Cost (Credit)
 
 
 (5,129)
 
Amortization of Actuarial (Gains)/Losses
 
 
 7,334 
 
Change in Funded Status
 
 
 - 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 2,205 
 
Income Tax (Expense) Credit
 
 
 772 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 1,433 
 
 
 
 
 
 
 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
 2,416 


 
242

 
 
I&M
 
 
 
 
Reclassifications from Accumulated Other Comprehensive Income (Loss)
 
For the Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
Amount of
 
 
 
 
 
(Gain) Loss
 
 
 
 
 
 Reclassified
 
 
 
 
 
from AOCI
 
Gains and Losses on Cash Flow Hedges
 
(in thousands)
 
Commodity:
 
 
 
 
 
 
Electric Generation, Transmission and Distribution Revenues
 
$
 (155)
 
 
 
Purchased Electricity for Resale
 
 
 219 
 
 
 
Other Operation Expense
 
 
 (23)
 
 
 
Maintenance Expense
 
 
 (14)
 
 
 
Property, Plant and Equipment
 
 
 (20)
 
 
 
Regulatory Assets/(Liabilities), Net (a)
 
 
 16 
 
Subtotal - Commodity
 
 
 23 
 
 
 
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
 
 
Interest Expense
 
 
 2,188 
 
Subtotal - Interest Rate and Foreign Currency
 
 
 2,188 
 
 
 
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 2,211 
 
Income Tax (Expense) Credit
 
 
 774 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 1,437 
 
 
 
 
 
 
Pension and OPEB
 
 
 
 
Amortization of Prior Service Cost (Credit)
 
 
 (794)
 
Amortization of Actuarial (Gains)/Losses
 
 
 1,872 
 
Change in Funded Status
 
 
 - 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 1,078 
 
Income Tax (Expense) Credit
 
 
 378 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 700 
 
 
 
 
 
 
 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
 2,137 


 
243

 
 
OPCo
 
 
 
 
Reclassifications from Accumulated Other Comprehensive Income (Loss)
 
For the Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
Amount of
 
 
 
 
 
(Gain) Loss
 
 
 
 
 
 Reclassified
 
 
 
 
 
from AOCI
 
Gains and Losses on Cash Flow Hedges
 
(in thousands)
 
Commodity:
 
 
 
 
 
 
Electric Generation, Transmission and Distribution Revenues
 
$
 (415)
 
 
 
Purchased Electricity for Resale
 
 
 576 
 
 
 
Other Operation Expense
 
 
 (56)
 
 
 
Maintenance Expense
 
 
 (26)
 
 
 
Property, Plant and Equipment
 
 
 (45)
 
 
 
Regulatory Assets/(Liabilities), Net (a)
 
 
 - 
 
Subtotal - Commodity
 
 
 34 
 
 
 
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
 
 
Depreciation and Amortization Expense
 
 
 7 
 
 
 
Interest Expense
 
 
 (2,098)
 
Subtotal - Interest Rate and Foreign Currency
 
 
 (2,091)
 
 
 
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 (2,057)
 
Income Tax (Expense) Credit
 
 
 (720)
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 (1,337)
 
 
 
 
 
 
Pension and OPEB
 
 
 
 
Amortization of Prior Service Cost (Credit)
 
 
 (5,840)
 
Amortization of Actuarial (Gains)/Losses
 
 
 25,085 
 
Change in Funded Status
 
 
 - 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 19,245 
 
Income Tax (Expense) Credit
 
 
 6,736 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 12,509 
 
 
 
 
 
 
 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
 11,172 


 
244

 
 
PSO
 
 
 
 
Reclassifications from Accumulated Other Comprehensive Income (Loss)
 
For the Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
Amount of
 
 
 
 
 
(Gain) Loss
 
 
 
 
 
 Reclassified
 
 
 
 
 
from AOCI
 
Gains and Losses on Cash Flow Hedges
 
(in thousands)
 
Commodity:
 
 
 
 
 
 
Electric Generation, Transmission and Distribution Revenues
 
$
 - 
 
 
 
Purchased Electricity for Resale
 
 
 - 
 
 
 
Other Operation Expense
 
 
 (25)
 
 
 
Maintenance Expense
 
 
 (10)
 
 
 
Property, Plant and Equipment
 
 
 (15)
 
 
 
Regulatory Assets/(Liabilities), Net (a)
 
 
 - 
 
Subtotal - Commodity
 
 
 (50)
 
 
 
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
 
 
Interest Expense
 
 
 (1,167)
 
Subtotal - Interest Rate and Foreign Currency
 
 
 (1,167)
 
 
 
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 (1,217)
 
Income Tax (Expense) Credit
 
 
 (426)
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 (791)
 

 
 
245

 
SWEPCo
 
 
 
 
Reclassifications from Accumulated Other Comprehensive Income (Loss)
 
For the Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
Amount of
 
 
 
 
 
(Gain) Loss
 
 
 
 
 
 Reclassified
 
 
 
 
 
from AOCI
 
Gains and Losses on Cash Flow Hedges
 
(in thousands)
 
Commodity:
 
 
 
 
 
 
Electric Generation, Transmission and Distribution Revenues
 
$
 - 
 
 
 
Purchased Electricity for Resale
 
 
 - 
 
 
 
Other Operation Expense
 
 
 (29)
 
 
 
Maintenance Expense
 
 
 (15)
 
 
 
Property, Plant and Equipment
 
 
 (17)
 
 
 
Regulatory Assets/(Liabilities), Net (a)
 
 
 - 
 
Subtotal - Commodity
 
 
 (61)
 
 
 
 
 
 
 
 
Interest Rate and Foreign Currency:
 
 
 
 
 
 
Interest Expense
 
 
 3,488 
 
Subtotal - Interest Rate and Foreign Currency
 
 
 3,488 
 
 
 
 
 
 
 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 3,427 
 
Income Tax (Expense) Credit
 
 
 1,199 
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 2,228 
 
 
 
 
 
 
Pension and OPEB
 
 
 
 
Amortization of Prior Service Cost (Credit)
 
 
 (1,785)
 
Amortization of Actuarial (Gains)/Losses
 
 
 1,393 
 
Change in Funded Status
 
 
 - 
 
Reclassifications from AOCI, before Income Tax (Expense) Credit
 
 
 (392)
 
Income Tax (Expense) Credit
 
 
 (137)
 
Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
 
 (255)
 
 
 
 
 
 
 
 
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit
 
$
 1,973 

 
(a)
Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

 
246

 
The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges for the years ended December 31, 2012 and 2011.  All amounts in the following tables are presented net of related income taxes.

 
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
 
 Year Ended December 31, 2012
 
 
 
Commodity
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
 
Balance in AOCI as of December 31, 2011
 
$
 (1,309)
 
$
 (819)
 
$
 (1,748)
 
$
 (69)
 
$
 (62)
 
Changes in Fair Value Recognized in AOCI
 
 
 (1,310)
 
 
 (987)
 
 
 (2,002)
 
 
 104 
 
 
 100 
 
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Statement of Income/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
 
 (16)
 
 
 (43)
 
 
 (109)
 
 
 - 
 
 
 - 
 
 
 
Purchased Electricity for Resale
 
 
 440 
 
 
 1,151 
 
 
 3,002 
 
 
 - 
 
 
 - 
 
 
 
Other Operation Expense
 
 
 (25)
 
 
 (14)
 
 
 (35)
 
 
 (14)
 
 
 (11)
 
 
 
Maintenance Expense
 
 
 - 
 
 
 (2)
 
 
 (5)
 
 
 1 
 
 
 - 
 
 
 
Property, Plant and Equipment
 
 
 (14)
 
 
 (10)
 
 
 (15)
 
 
 (1)
 
 
 (5)
 
 
 
Regulatory Assets (a)
 
 
 1,590 
 
 
 278 
 
 
 - 
 
 
 - 
 
 
 - 
 
Balance in AOCI as of December 31, 2012
 
$
 (644)
 
$
 (446)
 
$
 (912)
 
$
 21 
 
$
 22 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Foreign Currency
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
 
(in thousands)
 
Balance in AOCI as of December 31, 2011
 
$
 1,024 
 
$
 (14,465)
 
$
 9,454 
 
$
 7,218 
 
$
 (15,462)
 
Changes in Fair Value Recognized in AOCI
 
 
 - 
 
 
 (5,777)
 
 
 - 
 
 
 - 
 
 
 (2,778)
 
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Statement of Income/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
 
 - 
 
 
 - 
 
 
 4 
 
 
 - 
 
 
 - 
 
 
 
Interest Expense
 
 
 1,053 
 
 
 595 
 
 
 (1,363)
 
 
 (758)
 
 
 2,669 
 
Balance in AOCI as of December 31, 2012
 
$
 2,077 
 
$
 (19,647)
 
$
 8,095 
 
$
 6,460 
 
$
 (15,571)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total – Cash Flow Hedges
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
 
(in thousands)
 
Balance in AOCI as of December 31, 2011
 
$
 (285)
 
$
 (15,284)
 
$
 7,706 
 
$
 7,149 
 
$
 (15,524)
 
Changes in Fair Value Recognized in AOCI
 
 
 (1,310)
 
 
 (6,764)
 
 
 (2,002)
 
 
 104 
 
 
 (2,678)
 
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Statement of Income/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
 
 (16)
 
 
 (43)
 
 
 (109)
 
 
 - 
 
 
 - 
 
 
 
Purchased Electricity for Resale
 
 
 440 
 
 
 1,151 
 
 
 3,002 
 
 
 - 
 
 
 - 
 
 
 
Other Operation Expense
 
 
 (25)
 
 
 (14)
 
 
 (35)
 
 
 (14)
 
 
 (11)
 
 
 
Maintenance Expense
 
 
 - 
 
 
 (2)
 
 
 (5)
 
 
 1 
 
 
 - 
 
 
 
Depreciation and Amortization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
 
 - 
 
 
 - 
 
 
 4 
 
 
 - 
 
 
 - 
 
 
 
Interest Expense
 
 
 1,053 
 
 
 595 
 
 
 (1,363)
 
 
 (758)
 
 
 2,669 
 
 
 
Property, Plant and Equipment
 
 
 (14)
 
 
 (10)
 
 
 (15)
 
 
 (1)
 
 
 (5)
 
 
 
Regulatory Assets (a)
 
 
 1,590 
 
 
 278 
 
 
 - 
 
 
 - 
 
 
 - 
 
Balance in AOCI as of December 31, 2012
 
$
 1,433 
 
$
 (20,093)
 
$
 7,183 
 
$
 6,481 
 
$
 (15,549)


 
247

 
 
 
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
 
 Year Ended December 31, 2011
 
 
 
Commodity
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
 
Balance in AOCI as of December 31, 2010
 
$
 (273)
 
$
 (178)
 
$
 (364)
 
$
 88 
 
$
 82 
 
Changes in Fair Value Recognized in AOCI
 
 
 (2,077)
 
 
 (1,294)
 
 
 (2,748)
 
 
 108 
 
 
 102 
 
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Statement of Income/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
 
 249 
 
 
 544 
 
 
 1,457 
 
 
 - 
 
 
 - 
 
 
 
Purchased Electricity for Resale
 
 
 62 
 
 
 79 
 
 
 425 
 
 
 - 
 
 
 - 
 
 
 
Other Operation Expense
 
 
 (95)
 
 
 (71)
 
 
 (160)
 
 
 (93)
 
 
 (93)
 
 
 
Maintenance Expense
 
 
 (169)
 
 
 (64)
 
 
 (141)
 
 
 (62)
 
 
 (65)
 
 
 
Property, Plant and Equipment
 
 
 (175)
 
 
 (90)
 
 
 (217)
 
 
 (110)
 
 
 (88)
 
 
 
Regulatory Assets (a)
 
 
 1,169 
 
 
 255 
 
 
 - 
 
 
 - 
 
 
 - 
 
Balance in AOCI as of December 31, 2011
 
$
 (1,309)
 
$
 (819)
 
$
 (1,748)
 
$
 (69)
 
$
 (62)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Foreign Currency
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
 
(in thousands)
 
Balance in AOCI as of December 31, 2010
 
$
 217 
 
$
 (8,507)
 
$
 10,813 
 
$
 8,406 
 
$
 (4,272)
 
Changes in Fair Value Recognized in AOCI
 
 
 (373)
 
 
 (6,913)
 
 
 - 
 
 
 (475)
 
 
 (12,438)
 
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Statement of Income/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
 
 - 
 
 
 - 
 
 
 4 
 
 
 - 
 
 
 - 
 
 
 
Interest Expense
 
 
 1,180 
 
 
 955 
 
 
 (1,363)
 
 
 (713)
 
 
 1,248 
 
Balance in AOCI as of December 31, 2011
 
$
 1,024 
 
$
 (14,465)
 
$
 9,454 
 
$
 7,218 
 
$
 (15,462)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total – Cash Flow Hedges
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
 
(in thousands)
 
Balance in AOCI as of December 31, 2010
 
$
 (56)
 
$
 (8,685)
 
$
 10,449 
 
$
 8,494 
 
$
 (4,190)
 
Changes in Fair Value Recognized in AOCI
 
 
 (2,450)
 
 
 (8,207)
 
 
 (2,748)
 
 
 (367)
 
 
 (12,336)
 
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Statement of Income/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
 
 249 
 
 
 544 
 
 
 1,457 
 
 
 - 
 
 
 - 
 
 
 
Purchased Electricity for Resale
 
 
 62 
 
 
 79 
 
 
 425 
 
 
 - 
 
 
 - 
 
 
 
Other Operation Expense
 
 
 (95)
 
 
 (71)
 
 
 (160)
 
 
 (93)
 
 
 (93)
 
 
 
Maintenance Expense
 
 
 (169)
 
 
 (64)
 
 
 (141)
 
 
 (62)
 
 
 (65)
 
 
 
Depreciation and Amortization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
 
 - 
 
 
 - 
 
 
 4 
 
 
 - 
 
 
 - 
 
 
 
Interest Expense
 
 
 1,180 
 
 
 955 
 
 
 (1,363)
 
 
 (713)
 
 
 1,248 
 
 
 
Property, Plant and Equipment
 
 
 (175)
 
 
 (90)
 
 
 (217)
 
 
 (110)
 
 
 (88)
 
 
 
Regulatory Assets (a)
 
 
 1,169 
 
 
 255 
 
 
 - 
 
 
 - 
 
 
 - 
 
Balance in AOCI as of December 31, 2011
 
$
 (285)
 
$
 (15,284)
 
$
 7,706 
 
$
 7,149 
 
$
 (15,524)

 (a)
Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

 
248

 
3.   RATE MATTERS

The Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  Rate matters can have a material impact on net income, cash flows and possibly financial condition.  The Registrant Subsidiaries’ recent significant rate orders and pending rate filings are addressed in this note.

OPCo Rate Matters

Ohio Electric Security Plan Filings

2009 – 2011 ESP

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011.  OPCo collected the 2009 annualized revenue increase over the last nine months of 2009.  The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018.  The PUCO’s March 2009 order was appealed to the Supreme Court of Ohio, which issued an opinion and remanded certain issues back to the PUCO.

In October 2011, the PUCO issued an order in the remand proceeding.  As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011.  In February 2012, the Ohio Consumers’ Counsel (OCC) and the IEU filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO’s refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which, if ordered, could reduce OPCo’s net deferred fuel costs up to the total balance.  As of December 31, 2013, OPCo’s net deferred fuel balance was $445 million, excluding unrecognized equity carrying costs.  In February 2014, the Supreme Court of Ohio affirmed the PUCO’s decision and rejected all appeals filed by the OCC and the IEU.  In February 2014, the IEU filed for reconsideration of the Supreme Court of Ohio decision.

In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover deferred fuel costs in rates beginning September 2012.  The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin.  In November 2012, OPCo filed an appeal at the Supreme Court of Ohio related to the PUCO decision in the PIRR proceeding claiming a long-term debt rate modified the previously adjudicated 2009 – 2011 ESP order, which granted a weighted average cost of capital rate.  In November 2012, the IEU and the OCC filed appeals regarding the PUCO decision in the PIRR proceeding.  These appeals principally argued that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues which could reduce OPCo’s net deferred fuel balance up to the total balance.  These intervenors’ appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of December 31, 2013, could reduce carrying costs by $31 million including $16 million of unrecognized equity carrying costs.  A decision from the Supreme Court of Ohio is pending.

In January 2011, the PUCO issued an order on the 2009 SEET filing.  The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm.  In January 2013, the PUCO found there was not a need for the large solar farm.  The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project.  In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive.  A decision from the PUCO is pending.

In July 2011, OPCo filed its 2010 SEET filing with the PUCO.  In October 2013, the PUCO issued an order on the 2010 SEET filing that determined there were excessive earnings of $7 million, which were primarily offset against deferred fuel, as ordered.  OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis.  In November 2013, OPCo filed its 2011 and 2012 SEET filings with the PUCO.  In February 2014, the PUCO staff filed testimony asserting that no significantly excessive earnings had occurred in 2011 for CSPCo or OPCo and that no significantly excessive earnings had occurred in 2012 for OPCo.  In February 2014, OPCo entered into a stipulation agreement with the PUCO staff which both parties agree that there were no significantly excessive earnings in 2011 for CSPCo or OPCo.  A hearing at the PUCO related to the 2011 SEET filing is scheduled for February 2014.  Management does not believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo or in either 2012 or 2013 for OPCo.

 
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Management is unable to predict the outcome of the unresolved litigation discussed above.  Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition.

June 2012 – May 2015 ESP Including Capacity Charge

In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015.  This ruling was generally upheld in rehearing orders in January and March 2013.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The RPM price is approximately $33/MW day through May 2014 and $148/MW day from June 2014 through May 2015.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.

As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012.  The RSR is being collected from customers at $3.50/MWh through May 2014 and will be collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs.  As of December 31, 2013, OPCo’s incurred deferred capacity costs balance of $288 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet.

In January and March 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order including the implementation of the RSR.  The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel.  In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP).  In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR.

In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications.  The modifications include the delay of the energy auctions that were originally ordered in the ESP order.  OPCo must conduct an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015.  The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning November 2014 through May 2015 and for the remaining 40% of the SSO load for delivery from January 2015 through May 2015.  OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015.  The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned.  Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings.  Management believes that these intervenor concerns are without merit.  In December 2013, the PUCO granted applications for rehearing for further consideration filed by OPCo and intervenors.  In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012-2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC.

If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its fixed fuel and deferred capacity costs, it could reduce future net income and cash flows and impact financial condition.

Proposed June 2015 – May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018.  This filing is consistent with the PUCO’s objective for a full transition from FAC and base generation rates to market.  The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo.  Additionally, the application identifies OPCo’s intention to submit a separate application to continue the RSR established in the June 2012 – May 2015 ESP in which the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected.  Management intends to file this application in the first quarter of 2014.

 
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Corporate Separation

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo’s generation assets including the transfer of OPCo’s generation assets and associated generation liabilities at net book value to AGR.  In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful.  A decision from the Supreme Court of Ohio is pending.  In December 2013, the PUCO approved OPCo’s application to amend the corporate separation plan by permitting OPCo to retain certain rights to purchase power from OVEC.  The approval is subject to the condition that energy from the OVEC entitlements are sold into the day-ahead or real-time PJM energy markets, or on a forward basis through a bilateral arrangement.  In December 2013, corporate separation of OPCo’s generation assets was completed.

Also in October 2012, filings at the FERC were submitted related to corporate separation.  In April 2013, the FERC issued orders approving the transfer of OPCo’s generation assets to AGR.  See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.

Storm Damage Recovery Rider (SDRR)

In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates.  The SDRR seeks recovery of 2012 incremental storm distribution expenses over twelve months starting with the effective date of the SDRR as approved by the PUCO.  In December 2013, a stipulation agreement was reached between OPCo, the PUCO staff and all intervenors except the OCC.  The stipulation included a $6 million reduction in the amount of 2012 storm expenses to be recovered and for recovery of those expenses to take place over a 12-month period.  The agreement also states that carrying charges using a long-term debt rate will be assessed from April 2013 until recovery begins, but no additional carrying charges will accrue during the actual recovery period.   In December 2013, the OCC filed testimony opposing the stipulation.  The testimony recommended the disallowance of approximately $18 million of the 2012 storm expenses and that the remaining 2012 storm expenses be offset by an additional $20 million that OPCo was ordered to spend on a solar project in OPCo’s 2009 SEET filing.  See the “2009-2011 ESP” section above.  Hearings were held at the PUCO in January 2014 related to the settlement agreement and to address issues presented in the OCC’s testimony.  As of December 31, 2013, OPCo has deferred $56 million in Regulatory Assets on the balance sheet related to 2012 storm damage.  If OPCo is not ultimately permitted to recover these storm costs, it could reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance.  In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges.  As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012.  The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers.  Management is unable to predict the outcome of any future consultant recommendation regarding valuation of the coal reserve.  If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.

In August 2012, intervenors filed an appeal with the Supreme Court of Ohio claiming the settlement credit ordered by the PUCO should have reflected the remaining gain not already flowed through the FAC with carrying charges, which, if ordered, would be $35 million plus carrying charges.  If the Supreme Court of Ohio   ultimately determines that additional amounts should benefit ratepayers, it could reduce future net income and cash flows and impact financial condition.

 
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2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes with the use of a weighted average cost of capital (WACC).  The PUCO subsequently ruled in the PIRR proceeding that the fuel clause for these years was approved with a WACC carrying cost and that the carrying costs on the balance should not be net of accumulated income taxes.  Hearings at the PUCO were held in November 2013.  If the PUCO orders result in a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition.  See the 2009-2011 ESP section of the “Ohio Electric Security Plan Filing” related to the PUCO order in the PIRR proceeding.

Ormet

Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018.  In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware.  In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down operations effective immediately.  Based upon previous PUCO rulings providing rate assistance to Ormet, the PUCO is expected to permit OPCo to recover unpaid Ormet amounts through the Economic Development Rider, except where recovery from ratepayers is limited to $20 million related to previously deferred payments from Ormet’s October and November 2012 power bills.  OPCo expects that any additional unpaid generation usage by Ormet will be recoverable as a regulatory asset through the Economic Development Rider (EDR).  In February 2014, a stipulation agreement between OPCo and Ormet was filed with the PUCO.  The stipulation recommends approval of OPCo’s right to fully recover approximately $49 million of foregone revenues through the EDR which, as of December 31, 2013, is recorded in regulatory assets on the balance sheet.  Also in February 2014, intervenor comments were filed objecting to full recovery of these forgone revenues.

In addition, in the 2009 – 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future.  Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs.  The PUCO did not take any action on this request.  The intervenors raised this issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement.

To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Ohio IGCC Plant

In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant.  As of December 31, 2013, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order.  Intervenors have filed motions with the PUCO requesting that OPCo refund all collected pre-construction costs to Ohio ratepayers with interest.

Management cannot predict the outcome of this proceeding concerning the Ohio IGCC plant or what effect, if any, this proceeding could have on future net income and cash flows.  However, if OPCo is required to refund pre-construction costs collected, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters

Turk Plant

SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.  As of December 31, 2013, SWEPCo’s share of incurred construction expenditures for the Turk Plant was approximately $1.758 billion.  As of December 31, 2013, a pretax provision of $59 million has been recorded for costs incurred in excess of a Texas cost cap, resulting in total net capitalized expenditures of $1.699 billion.

 
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The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%).  Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN.  In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN.  This Turk Plant output that is currently not subject to cost-based rate recovery and is being sold into the wholesale market.

The PUCT approved a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected cash construction cost, excluding related transmission costs, (b) a cap on recovery of annual CO 2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers.  The PUCT decision was upheld on appeal.   See the “2012 Texas Base Rate Case” disclosure below for a discussion of a PUCT order on the Texas capital cost cap.

If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant or transmission lines, it could reduce future net income and cash flows and impact financial condition.
 
2012 Texas Base Rate Case
 
In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million, primarily due to the Turk Plant, based upon an 11.25% return on common equity to be effective January 2013.  The requested base rate increase included a return on and of the Texas jurisdictional share (approximately 33%) of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operation and maintenance costs.  The filing also (a) increased depreciation expense due to the decrease in the average remaining life of the Welsh Plant to account for the change in the retirement date of the Welsh Plant, Unit 2 from 2040 to 2016 and (b) included a return on and of the Stall Unit as of December 2011 and associated operation and maintenance costs.

In October 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determining that the Turk Plant Texas capital cost cap established in the Certificate of Convenience and Necessity (CCN) case discussed above (the Texas capital cost cap) also limited SWEPCo’s recovery of AFUDC in addition to its recovery of cash construction costs.  As a result of the determination that AFUDC was to be included in the cap, in the third quarter of 2013, SWEPCo recorded an additional pretax regulatory disallowance of $111 million.  The order approved an annual rate increase of approximately $39 million based upon a return on common equity of 9.65%, including an unfavorable consolidated income tax adjustment of $5 million.  As a result of this approval, SWEPCo retroactively applied the rate increase to the end of January 2013.  The order also provided that there would be no disallowance to the existing book investment in the Stall Unit and that the Turk Plant related transmission line investment that was not in service at the end of the test year would be excluded from rate base.  SWEPCo has since sought approval to recover this transmission investment through a Transmission Cost Recovery Rider in a filing made in December 2013.  Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2.  As of December 31, 2013, the net book value of Welsh Plant, Unit 2 was $87 million, before cost of removal, including materials and supplies inventory and CWIP.

In October 2013, SWEPCo filed a motion for rehearing with the PUCT.  In December 2013, the PUCT issued an order granting rehearing and reversed its decision on consolidated tax savings increasing SWEPCo’s annual revenues by $5 million.  In January 2014, the PUCT determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap.  As a result of these rulings, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances.  These rulings also increased SWEPCo’s previously approved annual base rates by a total of $13 million, which was also retroactively applied to the end of January 2013.  The resulting annual base rate increase is approximately $52 million. 

If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Welsh Plant, Unit 2 and its retirement-related costs, it could reduce future net income and cash flows and impact financial condition.
 
 
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2013 Texas Transmission Costs Recovery Factor Filing
 
In December 2013, SWEPCo filed an application to implement its initial transmission cost recovery factor (TCRF) requesting additional annual revenue of $10 million.  The TCRF is designed to recover increases from the amounts included in SWEPCo’s Texas retail base rates for transmission infrastructure improvement costs and wholesale transmission charges under a tariff approved by the FERC.  SWEPCo’s application included Turk Plant transmission-related costs.  In January and February 2014, intervenors filed motions with the PUCT opposing SWEPCo’s filing.  In February 2014, an Administrative Law Judge issued an order requesting additional information from SWEPCo related to this filing.  If the PUCT were to disallow any portion of the TCRF, it could reduce future net income and cash flows.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant.  In February 2013, a settlement was filed and approved by the LPSC.  The settlement increased Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually.  The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund based on the staff review of the cost of service and the prudency review of the Turk Plant.  The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013.  In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant.  If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudency review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.

Flint Creek Plant Environmental Controls

In February 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA.  The estimated cost of the project is $408 million, excluding AFUDC and company overheads.  As a joint owner of the Flint Creek Plant, SWEPCo’s portion of those costs is estimated at $204 million.  In July 2013, the APSC approved the request to install environmental controls at the Flint Creek Plant.

APCo Rate Matters

Plant Transfers

In October 2012, the AEP East Companies submitted several filings with the FERC regarding the transfer of certain generation plants within the AEP System.  See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.  In December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant, comprising 1,647 MW of generating capacity.  In July 2013, the Virginia SCC approved the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo, but directed that an amount equal to $83 million pretax be removed from the proposed transfer price.  The Virginia jurisdictional share of the disallowance was approximately $39 million.  The Virginia SCC also denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo.

In December 2013, the WVPSC approved the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo but deferred a final decision related to the recovery of West Virginia’s jurisdictional share of the $83 million pretax Virginia SCC disallowance until APCo’s next West Virginia base rate case which APCo has agreed to file no later than June 2014.  The West Virginia and FERC jurisdictional share of the potential disallowance is approximately $44 million pretax.  Additionally, the WVPSC order also approved a rate surcharge for Amos Plant, Unit 3 effective January 2014 and deferred ruling on the transfer of the one-half interest in the Mitchell Plant to APCo.  The surcharge was offset by an equal reduction in ENEC revenue with no overall change in total revenue.

 
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In December 2013, the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo was completed.  As a result of the Virginia order, in the fourth quarter of 2013, APCo recorded a pretax regulatory disallowance of $39 million in Asset Impairments and Other Related Charges on the statement of income.  Management continues to review its options related to the remaining one-half interest in the Mitchell Plant currently owned by AGR.  If APCo and WPCo are not ultimately permitted to recover their Amos Plant, Unit 3 incurred costs in West Virginia and FERC, it could reduce future net income and cash flows and impact financial condition.

APCo IGCC Plant

As of December 31, 2013, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $10 million applicable to its Virginia jurisdiction.  If the costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing

In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $39 million related to 2012 and 2011 environmental compliance costs, including carrying costs.  In March 2013, the environmental RAC surcharge expired related to the collection of 2009 and 2010 environmental compliance costs.  In November 2013, the Virginia SCC approved a settlement agreement which recommended approval of an environmental RAC to recover $38 million of the 2012 and 2011 environmental compliance costs, effective January 2014 for a one-year period.  The order also states that APCo must file its next environmental RAC petition on or before May 1, 2015.  As of December 31, 2013, APCo has deferred $28 million for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $10 million of unrecognized equity carrying costs.

2013 Virginia Generation Rate Adjustment Clause (Generation RAC)Filing

In March 2013, APCo filed with the Virginia SCC to increase its generation RAC revenues by $12 million for a total of $38 million to collect costs related to the Dresden Plant.  In December 2013, the Virginia SCC approved a settlement agreement that included an increase in the generation RAC to $39 million.  Per the approved settlement agreement, the generation RAC increase was effective in February 2014 for a period of one year at which time the component to collect an under-recovery of approximately $10 million will cease and the remaining annual $29 million revenue to recover on-going Dresden Plant costs will continue.  As of December 31, 2013, APCo has deferred $6 million for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $5 million of unrecognized equity carrying costs.

2013 Virginia Transmission Rate Adjustment Clause (Transmission RAC)

In December 2013, APCo filed with the Virginia SCC to increase its transmission RAC revenues by $50 million annually.  The increase in the transmission RAC is expected to be effective May 2014.  In February 2014, a hearing was held at the Virginia SCC in which a stipulation agreement between APCo and the Virginia SCC staff was submitted to the Virginia SCC that recommended approval to increase the transmission RAC revenues by $49 million annually, subject to true-up.  The stipulation included the Virginia SCC staff's commitment to fully audit APCo's transmission RAC under-recoveries and report its findings and recommendations in testimony in APCo's next transmission RAC filing in 2015.  As of December 31, 2013, APCo has deferred $47 million for the Virginia portion of unrecovered transmission RAC costs.  If the Virginia SCC were to disallow any portion of the transmission RAC, it could reduce future net income and cash flows.
 
2013 West Virginia Expanded Net Energy Charge (ENEC) Filing

In March 2012, West Virginia passed securitization legislation which allowed the WVPSC to establish a regulatory framework for electric utilities to securitize certain deferred ENEC balances and other ENEC-related assets.  In August 2013, the WVPSC approved a settlement that included (a) a $56 million reduction in ENEC revenues, offset by a $6 million annual increase in construction surcharges, effective September 2013 and subject to true-up, (b) an agreement to file a base case no later than June 2014 and (c) the deferral of $21 million from the ENEC recovery balance with the ability to include that amount in the ENEC recovery balance upon reaching certain coal inventory
 
 
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levels at the Amos Plant.  In September 2013, the WVPSC approved a settlement agreement filed by APCo, WPCo and intervenors which authorized APCo to securitize $376 million, plus upfront financing costs, primarily related to the December 2011 under-recovered ENEC deferral balance.  In November 2013, APCo issued $380 million of Securitization Bonds to securitize the under-recovered ENEC deferral balance, including $4 million of upfront financing costs, with a final maturity date of August 2031.  APCo implemented a new securitization rider which was offset by an equal reduction in ENEC revenues, with no overall change in total revenues.

As of December 31, 2013, APCo’s ENEC net over-recovery balance was $86 million, of which $107 million was recorded in Regulatory Liabilities and $21 million was recorded in Regulatory Assets on the balance sheet.

Virginia Storm Costs

In March 2013, due to the 2013 enactment of a Virginia law, APCo wrote off $30 million of previously deferred 2012 Virginia storm costs.  The change in law affected the test years to be included in APCo's next biennial Virginia base rate filing in March 2014 and the determination of how these costs are treated in the Virginia jurisdictional biennial earnings test for 2012 and 2013.  As of December 31, 2013, APCo has not deferred any Virginia storm costs incurred in 2012 or 2013 based on actual 2012 and estimated 2013 Virginia jurisdictional earnings.  The 2012 and 2013 earnings test will be filed in the first quarter of 2014 as part of APCo’s biennial Virginia base rate filing.

WPCo Merger with APCo

In December 2011, APCo and WPCo filed an application with the WVPSC requesting authority to merge WPCo into APCo.  In December 2012, APCo and WPCo filed merger applications with the Virginia SCC and the FERC.  In April 2013, the FERC approved the merger.  Also in December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant.  In June 2013, the WVPSC issued an order consolidating the merger case with APCo’s plant asset transfer case.  In July 2013, the Virginia SCC approved the merger of WPCo into APCo and the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo but denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo.  Although the Virginia SCC authorized the merger of WPCo into APCo, denial of the Mitchell Plant ownership transfer will result in insufficient generation to serve the merged company.  In December 2013, the WVPSC issued an order that deferred ruling on the merger of WPCo into APCo.  Management continues to review its options and the feasibility related to the merger, the respective companies’ needs for generation and the remaining one-half interest in the Mitchell Plant currently owned by AGR.  See the “Plant Transfers” section of APCo Rate Matters and the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters.

PSO Rate Matters

2014 Oklahoma Base Rate Case

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity.  This revenue increase includes a proposed increase in depreciation rates of $29 million.  In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three.  The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional types of transmission costs that are expected to increase over the next several years.

Oklahoma Environmental Compliance Plan

In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES), Unit 4 in 2016 and additional environmental controls on NES, Unit 3 to continue operations through 2026.  As of December 31, 2013, the net book values of NES, Units 3 and 4 were $208 million and $106 million, respectively, before cost of removal, including materials and supplies inventory and CWIP.  In August 2013, the OCC dismissed PSO’s environmental compliance plan case without prejudice but will permit PSO to seek recovery in a future proceeding.  PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan.  If PSO is ultimately not permitted to fully recover its net book value of NES, Units 3 and 4 and other environmental compliance costs, it could reduce future net income and cash flows and impact financial condition.

 
256

 
I&M Rate Matters
 
2011 Indiana Base Rate Case
 
In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%.  In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates from $85 million to $92 million.  In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed a request for reconsideration with the IURC, which was denied.  Also in March 2013, the OUCC filed an appeal of the order with the Indiana Court of Appeals.  In September 2013, the OUCC filed a brief on appeal that included objections to the inclusion of a prepaid pension asset in rate base, the use of an end-of-test-year amount for materials and supplies instead of a thirteen-month average and the application of an “outdated” capital structure.  If any part of the IURC order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its licensed life (2034 for Unit 1 and 2037 for Unit 2).  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of December 31, 2013, I&M has incurred costs of $380 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items that might accommodate a future potential power uprate which the IURC stated I&M could seek recovery of in a subsequent base rate case.  I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings.  The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates.  In October 2013, I&M filed an application with the IURC for LCM rider rates effective January 2014.  In November 2013, the OUCC filed testimony identifying concerns related to the LCM rider that included the use of forecasted capital expenditures and the method used to calculate carrying charges.  In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC.

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to the approved projects effective January 2013 until these costs are included in rates.  In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project.

If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.

Rockport Plant Clean Coal Technology Project (CCT Project)

In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both units of the Rockport Plant with a dry sorbent injection system.  The estimated cost of the CCT Project was $285 million, excluding AFUDC, to be shared equally between I&M and AEGCo.  The application requested deferral treatment of any unrecovered carrying costs incurred during construction and incremental post in-service depreciation expense and operation and maintenance expenses until such costs are recognized and recovered in a rider.  I&M also requested cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism.

In November 2013, the IURC approved a settlement agreement that included the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M’s ownership share of $129 million.  The settlement agreement specifies that 80% of the recoverable I&M direct ownership share of CCT Project costs will be recovered through a Federal Mandate Rider with the remaining 20% deferred until rates are established in a subsequent rate case.  I&M’s Indiana allocated share
 
 
257

 
of the CCT Project costs received in the form of purchased power from AEGCo will be recovered in subsequent I&M rate cases.  As of December 31, 2013, I&M has incurred costs of $56 million related to the CCT Project, including AFUDC.

Tanners Creek Plant, Units 1 - 4

In 2011, I&M announced that it would retire Tanners Creek Plant, Units 1-3 by June 2015 to comply with proposed environmental regulations.  In September 2013, I&M announced that Tanners Creek Plant, Unit 4 would also be retired in mid-2015 rather than being converted from coal to natural gas.   I&M is currently recovering depreciation and a return on the net book value of the Tanners Creek Plant in base rates and plans to seek recovery of all of the plant’s retirement related costs in its next Indiana and Michigan base rate cases.

In December 2013, I&M filed an application with the MPSC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and Tanners Creek Plant due to the retirement of the Tanners Creek Plant in 2015.  Upon the retirement of the Tanners Creek Plant, I&M proposes that the net book value of the Tanners Creek Plant will be recovered over the remaining life of the Rockport Plant.  I&M requested to have the impact of these new depreciation rates incorporated into the rates set in its next rate case.  The new depreciation rates result in a decrease in I&M’s Michigan jurisdictional electric depreciation expense which I&M proposes to implement in the month following a MPSC order in the revised depreciation case.

As of December 31, 2013, the net book value of the Tanners Creek Plant was $341 million, before cost of removal, including materials and supplies inventory and CWIP.  If I&M is ultimately not permitted to fully recover its net book value of the Tanners Creek Plant and its retirement-related costs, it could reduce future net income and cash flows and impact financial condition.

FERC Rate Matters

Corporate Separation and Termination of Interconnection Agreement – Affecting APCo, I&M and OPCo

In October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo’s generation assets from its distribution and transmission operations.  The filings requested approval to transfer at net book value (NBV) approximately 9,200 MW of OPCo-owned generation assets and associated liabilities to AGR.  The AEP East Companies also requested FERC approval to transfer at NBV two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer the Mitchell Plant at NBV to APCo and KPCo in equal one-half interests (780 MW each) to be effective December 31, 2013.  In April 2013, the FERC issued orders approving the transfer of OPCo’s generation assets to AGR, the transfers of the Amos Plant and Mitchell Plant to APCo and KPCo, respectively, and the merger of APCo and WPCo.  In January 2014, the FERC dismissed an IEU petition for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AGR.  Similar asset transfer filings were made at the Virginia SCC and the WVPSC.  In December 2013, corporate separation of OPCo’s generation assets was completed.  See the “Plant Transfers” section of APCo Rate Matters.

In accordance with management’s December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014.  The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated.

In December 2013, the FERC issued orders approving the creation of the PCA, effective January 1, 2014, conditioned upon certain compliance filings which were filed with the FERC in January 2014.  The PCA was established among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.  Under the PCA, APCo and I&M would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies.  Further, the PCA allows, but does not obligate, APCo and I&M to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities.  
 
 
258

 
Also effective January 1, 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent.  The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies will fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year.  Under the Bridge Agreement, AGR is committed to meet capacity obligations of member companies through May 31, 2015.

Additionally, FERC approval was sought for a Power Supply Agreement (PSA) between AGR and OPCo.  This agreement provides for AGR to supply capacity for OPCo’s switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that is not acquired through an auction from January 1, 2014 through December 31, 2014.  In December 2013, the FERC issued an order approving the PSA.  The order conditioned the acceptance of the PSA on the revision of the agreement to reflect the PUCO’s current and future underlying rates and rate structure.  In January 2014, initial revisions to reflect current underlying rates and rate structure were filed at the FERC.

In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation.  In December 2013, the FERC issued an order approving these additional filings.  See the “Plant Transfers” section of APCo Rate Matters for a discussion of the Virginia SCC order.  

If APCo and/or I&M experience decreases in revenues or increases in expenses as a result of changes to their relationship with affiliates and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

4.   EFFECTS OF REGULATION

Regulated Generating Units to be Retired Before or During 2016

The following regulated generating units are probable of abandonment.  Accordingly, CWIP and Plant in Service has been reclassified as Other Property, Plant and Equipment on the balance sheet as of December 31, 2013.  The following table summarizes the plant investment and cost of removal, currently being recovered, for each generating unit as of December 31, 2013.

Plant Name and Unit
 
Company
 
 
Gross Investment
 
 
Accumulated Depreciation
 
 
Net Investment
 
 
Cost of Removal Regulatory Liability
 
Expected Retirement Date
 
Remaining Recovery Period
 
 
 
 
(in thousands)
 
 
 
 
Tanners Creek Plant,
 
I&M
 
$
 681,490 
 
$
 353,800 
 
$
 327,690 
 
$
 87,102 
 
2015 
 
17 years
   Units 1-4
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Northeastern Station,
 
PSO
 
 
 181,652 
 
 
 88,836 
 
 
 92,816 
 
 
 11,142 
 
2016 
 
27 years
   Unit 4
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Welsh Plant, Unit 2
 
SWEPCo
 
 
 174,919 
 
 
 92,973 
 
 
 81,946 
 
 
 19,054 
 
2016 
 
27 years
Total
 
 
 
$
 1,038,061 
 
$
 535,609 
 
$
 502,452 
 
$
 117,298 
 
 
 
 

In accordance with accounting guidance for “Regulated Operations”, APCo regulated generating units expected to be retired before or during 2016 are not considered probable of abandonment.

 
259

 

Regulatory Assets

Regulatory assets and liabilities are comprised of the following items:

 
 
 
 
 
 
 
APCo
 
I&M
 
 
 
 
 
 
 
 
 
Remaining
 
 
 
Remaining
 
 
 
 
 
 
 
December 31,
 
Recovery
 
December 31,
 
Recovery
Regulatory Assets:
 
2013 
 
2012 
 
Period
 
2013 
 
2012 
 
Period
 
 
(in thousands)
 
 
 
(in thousands)
 
 
Current Regulatory Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Under-recovered Fuel Costs - earns a return
 
$
 39,811 
 
$
 74,906 
 
1 year
 
$
 - 
 
$
 3,029 
 
 
Under-recovered Fuel Costs - does not earn a return
 
 
 - 
 
 
 - 
 
 
 
 
 3,397 
 
 
 1,647 
 
1 year
Total Current Regulatory Assets
 
$
 39,811 
 
$
 74,906 
 
 
 
$
 3,397 
 
$
 4,676 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncurrent Regulatory Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory assets not yet being recovered pending
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
future proceedings to determine the recovery
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
method and timing:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Storm Related Costs
 
$
 65,206 
 
$
 94,458 
 
 
 
$
 1,836 
 
$
 - 
 
 
 
 
 
Expanded Net Energy Charge - Coal Inventory
 
 
 20,528 
 
 
 - 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Mountaineer Carbon Capture and Storage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Product Validation Facility
 
 
 13,264 
 
 
 14,155 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Virginia Demand Response Program Costs
 
 
 5,012 
 
 
 1,447 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Transmission Agreement Phase-In
 
 
 3,313 
 
 
 2,992 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Virginia Environmental Rate Adjustment Clause
 
 
 2,440 
 
 
 29,320 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Mountaineer Carbon Capture and Storage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commercial Scale Facility
 
 
 1,287 
 
 
 1,287 
 
 
 
 
 - 
 
 
 1,380 
 
 
 
 
 
Indiana Under-Recovered Capacity Costs
 
 
 - 
 
 
 - 
 
 
 
 
 21,945 
 
 
 - 
 
 
 
 
 
Indiana Deferred Cook Plant Life Cycle
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Management Project Costs
 
 
 - 
 
 
 - 
 
 
 
 
 4,093 
 
 
 - 
 
 
 
 
 
Stranded Costs on Abandoned Plants
 
 
 - 
 
 
 - 
 
 
 
 
 3,896 
 
 
 - 
 
 
 
 
 
Dresden Plant Operating Costs
 
 
 - 
 
 
 8,758 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Deferred Wind Power Costs
 
 
 - 
 
 
 5,143 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Litigation Settlement
 
 
 - 
 
 
 - 
 
 
 
 
 - 
 
 
 11,098 
 
 
 
 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 168 
 
 
 - 
 
 
 
 
 3,616 
 
 
 786 
 
 
Total Regulatory Assets Not Yet Being Recovered
 
 
 111,218 
 
 
 157,560 
 
 
 
 
 35,386 
 
 
 13,264 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory assets being recovered:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Storm Related Costs
 
 
 17,167 
 
 
 21,371 
 
5 years
 
 
 - 
 
 
 - 
 
 
 
 
 
Unamortized Loss on Reacquired Debt
 
 
 11,622 
 
 
 12,969 
 
29 years
 
 
 21,508 
 
 
 15,871 
 
19 years
 
 
 
RTO Formation/Integration Costs
 
 
 3,473 
 
 
 4,370 
 
6 years
 
 
 2,544 
 
 
 3,229 
 
6 years
 
 
 
Cook Plant, Unit 2 Baffle Bolts
 
 
 - 
 
 
 - 
 
 
 
 
 7,248 
 
 
 - 
 
25 years
 
 
 
West Virginia Expanded Net Energy Charge
 
 
 - 
 
 
 272,783 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Customer Choice Implementation Costs
 
 
 - 
 
 
 - 
 
 
 
 
 - 
 
 
 1,493 
 
 
 
 
 
Other Regulatory Assets Being Recovered
 
 
 665 
 
 
 - 
 
various
 
 
 522 
 
 
 - 
 
various
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Taxes, Net
 
 
 531,302 
 
 
 525,549 
 
26 years
 
 
 250,478 
 
 
 222,252 
 
30 years
 
 
 
Pension and OPEB Funded Status
 
 
 192,464 
 
 
 312,645 
 
11 years
 
 
 100,132 
 
 
 220,797 
 
11 years
 
 
 
Virginia Transmission Rate Adjustment Clause
 
 
 47,322 
 
 
 32,992 
 
2 years
 
 
 - 
 
 
 - 
 
 
 
 
 
Virginia Environmental Rate Adjustment Clause
 
 
 27,426 
 
 
 8,347 
 
1 year
 
 
 - 
 
 
 - 
 
 
 
 
 
Postemployment Benefits
 
 
 19,772 
 
 
 22,663 
 
5 years
 
 
 9,096 
 
 
 8,897 
 
5 years
 
 
 
Storm Related Costs
 
 
 11,100 
 
 
 13,712 
 
5 years
 
 
 - 
 
 
 - 
 
 
 
 
 
Deferred Restructuring Costs
 
 
 8,525 
 
 
 10,531 
 
5 years
 
 
 2,423 
 
 
 3,688 
 
2 years
 
 
 
Medicare Subsidy
 
 
 6,477 
 
 
 - 
 
11 years
 
 
 11,221 
 
 
 - 
 
11 years
 
 
 
Litigation Settlement
 
 
 - 
 
 
 - 
 
 
 
 
 10,382 
 
 
 - 
 
12 years
 
 
 
Asset Retirement Obligation
 
 
 6,453 
 
 
 8,489 
 
4 years
 
 
 696 
 
 
 808 
 
7 years
 
 
 
Virginia Generation Rate Adjustment Clause
 
 
 6,491 
 
 
 3,469 
 
2 years
 
 
 - 
 
 
 - 
 
 
 
 
 
West Virginia Expanded Net Energy Charge
 
 
 - 
 
 
 25,932 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Virginia Environmental and Reliability Costs
 
 
 - 
 
 
 560 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Cook Nuclear Plant Refueling Outage Levelization
 
 
 - 
 
 
 - 
 
 
 
 
 57,979 
 
 
 26,652 
 
3 years
 
 
 
Peak Demand Reduction/Energy Efficiency
 
 
 - 
 
 
 - 
 
 
 
 
 4,457 
 
 
 2,608 
 
1 year
 
 
 
Off-system Sales Margin Sharing
 
 
 - 
 
 
 - 
 
 
 
 
 4,409 
 
 
 - 
 
1 year
 
 
 
River Transportation Division Expenses
 
 
 - 
 
 
 - 
 
 
 
 
 4,090 
 
 
 4,576 
 
1 year
 
 
 
Deferred PJM Fees
 
 
 - 
 
 
 - 
 
 
 
 
 - 
 
 
 13,998 
 
 
 
 
 
Other Regulatory Assets Being Recovered
 
 
 2,413 
 
 
 1,762 
 
various
 
 
 1,543 
 
 
 1,886 
 
various
Total Regulatory Assets Being Recovered
 
 
 892,672 
 
 
 1,278,144 
 
 
 
 
 488,728 
 
 
 526,755 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Noncurrent Regulatory Assets
 
$
 1,003,890 
 
$
 1,435,704 
 
 
 
$
 524,114 
 
$
 540,019 
 
 

 
260

 



 
 
 
 
 
 
 
APCo
 
I&M
 
 
 
 
 
 
 
 
 
Remaining
 
 
 
Remaining
 
 
 
 
 
 
 
December 31,
 
Refund
 
December 31,
 
Refund
Regulatory Liabilities:
 
2013 
 
2012 
 
Period
 
2013 
 
2012 
 
Period
 
 
(in thousands)
 
 
 
(in thousands)
 
 
Current Regulatory Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Over-recovered Fuel Costs - does not pay a return
 
$
 107,048 
 
$
 - 
 
1 year
 
$
 - 
 
$
 - 
 
 
Over-recovered Fuel Costs - pays a return
 
 
 - 
 
 
 - 
 
 
 
 
 1,976 
 
 
 - 
 
1 year
Total Current Regulatory Liabilities
 
$
 107,048 
 
$
 - 
 
 
 
$
 1,976 
 
$
 - 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncurrent Regulatory Liabilities and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred Investment Tax Credits
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory liabilities not yet being paid:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Liabilities Currently Not Paying a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Regulatory Liabilities Not Yet Being Paid
 
$
 249 
 
$
 249 
 
 
 
$
 113 
 
$
 124 
 
 
Total Regulatory Liabilities Not Yet Being Paid
 
 
 249 
 
 
 249 
 
 
 
 
 113 
 
 
 124 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory liabilities being paid:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Liabilities Currently Paying a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Asset Removal Costs
 
 
 583,723 
 
 
 552,590 
 
(a)
 
 
 389,025 
 
 
 381,116 
 
(a)
 
 
 
Deferred Investment Tax Credits
 
 
 1,863 
 
 
 2,823 
 
47 years
 
 
 - 
 
 
 - 
 
 
 
Regulatory Liabilities Currently Not Paying a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred State Income Tax Coal Credits
 
 
 28,255 
 
 
 29,296 
 
10 years
 
 
 - 
 
 
 - 
 
 
 
 
 
Unrealized Gain on Forward Commitments
 
 
 15,853 
 
 
 21,433 
 
4 years
 
 
 10,810 
 
 
 19,872 
 
4 years
 
 
 
Deferred Investment Tax Credits
 
 
 122 
 
 
 382 
 
2 years
 
 
 43,200 
 
 
 48,130 
 
23 years
 
 
 
Peak Demand Reduction/Energy Efficiency
 
 
 746 
 
 
 907 
 
1 year
 
 
 15,021 
 
 
 11,080 
 
1 year
 
 
 
Excess Asset Retirement Obligations for Nuclear
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decommissioning Liability
 
 
 - 
 
 
 - 
 
 
 
 
 597,113 
 
 
 435,717 
 
(b)
 
 
 
Spent Nuclear Fuel Liability
 
 
 - 
 
 
 - 
 
 
 
 
 43,416 
 
 
 42,898 
 
(b)
 
 
 
Over-Recovery of PJM Expense
 
 
 - 
 
 
 - 
 
 
 
 
 13,924 
 
 
 - 
 
2 years
 
 
 
Off-system Sales Margin Sharing
 
 
 - 
 
 
 - 
 
 
 
 
 - 
 
 
 7,611 
 
 
 
 
 
Other Regulatory Liabilities Being Paid
 
 
 414 
 
 
 - 
 
various
 
 
 23 
 
 
 1,744 
 
various
Total Regulatory Liabilities Being Paid
 
 
 630,976 
 
 
 607,431 
 
 
 
 
 1,112,532 
 
 
 948,168 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Noncurrent Regulatory Liabilities and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred Investment Tax Credits
 
$
 631,225 
 
$
 607,680 
 
 
 
$
 1,112,645 
 
$
 948,292 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
 
Relieved as removal costs are incurred.
(b)
 
Relieved when plant is decommissioned.


 
261

 
 
 
 
 
 
 
 
 
OPCo
 
 
 
 
 
 
 
 
 
Remaining
 
 
 
 
 
 
 
December 31,
 
Recovery
Regulatory Assets:
 
2013 
 
2012 
 
Period
 
 
(in thousands)
 
 
Current Regulatory Assets
 
 
 
 
 
 
 
 
Under-recovered Fuel Costs - does not earn a return
 
$
 15,829 
 
$
 - 
 
1 year
Total Current Regulatory Assets
 
$
 15,829 
 
$
 - 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncurrent Regulatory Assets
 
 
 
 
 
 
 
 
Regulatory assets not yet being recovered pending future proceedings to
 
 
 
 
 
 
 
 
 
determine the recovery method and timing:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
 
 
 
 
 
 
 
Ohio Economic Development Rider
 
$
 13,854 
 
$
 13,213 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
 
 
 
 
Storm Related Costs
 
 
 57,589 
 
 
 61,828 
 
 
 
 
 
Ormet Special Rate Recovery Mechanism
 
 
 35,631 
 
 
 5,453 
 
 
 
 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 - 
 
 
 30 
 
 
Total Regulatory Assets Not Yet Being Recovered
 
 
 107,074 
 
 
 80,524 
 
 
 
 
 
 
 
 
 
 
 
Regulatory assets being recovered:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
 
 
 
 
 
 
 
Ohio Fuel Adjustment Clause
 
 
 444,959 
 
 
 518,595 
 
5 years
 
 
 
Ohio Capacity Deferral
 
 
 288,060 
 
 
 65,818 
 
5 years
 
 
 
Ohio Transmission Cost Recovery Rider
 
 
 86,621 
 
 
 49,391 
 
2 years
 
 
 
Ohio Distribution Decoupling
 
 
 31,329 
 
 
 - 
 
2 years
 
 
 
Unamortized Loss on Reacquired Debt
 
 
 13,033 
 
 
 13,215 
 
25 years
 
 
 
RTO Formation/Integration Costs
 
 
 5,232 
 
 
 6,594 
 
6 years
 
 
 
Economic Development Rider
 
 
 791 
 
 
 5,488 
 
1 year
 
 
 
Ohio Deferred Asset Recovery Rider
 
 
 - 
 
 
 152,039 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
 
 
 
 
Pension and OPEB Funded Status
 
 
 188,722 
 
 
 309,685 
 
11 years
 
 
 
Income Taxes, Net
 
 
 150,183 
 
 
 190,685 
 
29 years
 
 
 
Peak Demand Reduction/Energy Efficiency
 
 
 18,529 
 
 
 - 
 
2 years
 
 
 
Medicare Subsidy
 
 
 11,354 
 
 
 - 
 
11 years
 
 
 
Under-Recovered Distribution Investment Rider
 
 
 8,677 
 
 
 1,304 
 
1 year
 
 
 
Under-Recovered gridSMART ® Costs
 
 
 8,396 
 
 
 - 
 
2 years
 
 
 
Enhanced Service Reliability Plan
 
 
 6,836 
 
 
 557 
 
2 years
 
 
 
Postemployment Benefits
 
 
 6,198 
 
 
 7,658 
 
5 years
 
 
 
Partnership with Ohio Contribution
 
 
 1,410 
 
 
 2,405 
 
2 years
 
 
 
Ohio Distribution Decoupling
 
 
 - 
 
 
 16,198 
 
 
 
 
 
Other Regulatory Assets Being Recovered
 
 
 1,293 
 
 
 810 
 
various
Total Regulatory Assets Being Recovered
 
 
 1,271,623 
 
 
 1,340,442 
 
 
 
 
 
 
 
 
 
 
 
Total Noncurrent Regulatory Assets
 
$
 1,378,697 
 
$
 1,420,966 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


 
262

 
 
 
 
 
 
 
 
 
OPCo
 
 
 
 
 
 
 
 
 
Remaining
 
 
 
 
 
 
 
December 31,
 
Refund
 
 
2013 
 
2012 
 
Period
Regulatory Liabilities:
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Regulatory Liabilities
 
 
 
 
 
 
 
 
Over-recovered Fuel Costs - does not pay a return
 
$
 - 
 
$
 14,848 
 
 
Total Current Regulatory Liabilities
 
$
 - 
 
$
 14,848 
 
 
 
 
 
 
 
 
 
 
 
Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 
 
 
 
 
 
Regulatory liabilities not yet being paid:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Liabilities Currently Paying a Return
 
 
 
 
 
 
 
 
 
 
 
IGCC Preconstruction Costs
 
$
 4,782 
 
$
 4,411 
 
 
 
Regulatory Liabilities Currently Not Paying a Return
 
 
 
 
 
 
 
 
 
 
 
Other Regulatory Liabilities Not Yet Being Paid
 
 
 216 
 
 
 216 
 
 
Total Regulatory Liabilities Not Yet Being Paid
 
 
 4,998 
 
 
 4,627 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory liabilities being paid:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Liabilities Currently Paying a Return
 
 
 
 
 
 
 
 
 
 
 
Asset Removal Costs
 
 
 421,061 
 
 
 416,461 
 
(a)
 
 
 
Deferred Investment Tax Credits
 
 
 165 
 
 
 322 
 
8 years
 
Reg ul atory Liabilities Currently Not Paying a Return
 
 
 
 
 
 
 
 
 
 
 
Deferred Asset Phase-In Rider
 
 
 4,334 
 
 
 - 
 
7 years
 
 
 
Unrealized Gain on Forward Commitments
 
 
 2,920 
 
 
 - 
 
1 year
 
 
 
Low Income Customers/Economic Recovery
 
 
 1,724 
 
 
 2,243 
 
2 years
 
 
 
Deferred Investment Tax Credits
 
 
 224 
 
 
 11,321 
 
7 years
 
 
 
Over-Recovery of Costs Related to gridSMART ®
 
 
 73 
 
 
 3,501 
 
2 years
 
 
 
Peak Demand Reduction/Energy Efficiency
 
 
 - 
 
 
 12,596 
 
 
Total Regulatory Liabilities Being Paid
 
 
 430,501 
 
 
 446,444 
 
 
 
 
 
 
 
 
 
 
 
Total Noncurrent Regulatory Liabilities and
 
 
 
 
 
 
 
 
 
Deferred Investment Tax Credits
 
$
 435,499 
 
$
 451,071 
 
 
 
 
 
 
 
 
 
 
 
(a)
 
Relieved as removal costs are incurred.


 
263

 
 
 
 
 
 
 
 
 
PSO
 
SWEPCo
 
 
 
 
 
 
 
 
 
Remaining
 
 
 
Remaining
 
 
 
 
 
 
 
December 31,
 
Recovery
 
December 31,
 
Recovery
 
 
 
 
 
 
 
2013 
 
2012 
 
Period
 
2013 
 
2012 
 
Period
Regulatory Assets:
 
(in thousands)
 
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Regulatory Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Under-recovered Fuel Costs - earns a return
 
$
 3,298 
 
$
 - 
 
1 year
 
$
 17,949 
 
$
 8,527 
 
1 year
Total Current Regulatory Assets
 
$
 3,298 
 
$
 - 
 
 
 
$
 17,949 
 
$
 8,527 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncurrent Regulatory Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory assets not yet being recovered pending
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
future proceedings to determine the recovery
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
method and timing:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Storm Related Costs
 
$
 18,743 
 
$
 - 
 
 
 
$
 - 
 
$
 - 
 
 
 
 
 
Rate Case Expense
 
 
 - 
 
 
 - 
 
 
 
 
 7,934 
 
 
 4,517 
 
 
 
 
 
Mountaineer Carbon Capture and Storage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commercial Scale Facility
 
 
 - 
 
 
 - 
 
 
 
 
 1,143 
 
 
 2,295 
 
 
 
 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 845 
 
 
 423 
 
 
 
 
 1,951 
 
 
 2,188 
 
 
Total Regulatory Assets Not Yet Being Recovered
 
 
 19,588 
 
 
 423 
 
 
 
 
 11,028 
 
 
 9,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory assets being recovered:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Red Rock Generating Facility
 
 
 9,728 
 
 
 9,954 
 
43 years
 
 
 - 
 
 
 - 
 
 
 
 
 
Unamortized Loss on Reacquired Debt
 
 
 9,455 
 
 
 10,923 
 
19 years
 
 
 8,165 
 
 
 9,379 
 
30 years
 
 
 
Storm Related Costs
 
 
 - 
 
 
 14,172 
 
 
 
 
 - 
 
 
 337 
 
 
 
 
 
Acquisition of Valley Electric Membership
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Corporation (VEMCO)
 
 
 - 
 
 
 - 
 
 
 
 
 4,100 
 
 
 6,443 
 
2 years
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension and OPEB Funded Status
 
 
 77,171 
 
 
 133,404 
 
11 years
 
 
 89,672 
 
 
 143,226 
 
11 years
 
 
 
Peak Demand Reduction/Energy Efficiency
 
 
 11,333 
 
 
 6,248 
 
1 year
 
 
 2,584 
 
 
 1,467 
 
1 year
 
 
 
Vegetation Management
 
 
 13,963 
 
 
 13,388 
 
1 year
 
 
 - 
 
 
 - 
 
 
 
 
 
Base Load Purchase Power Contract
 
 
 6,400 
 
 
 - 
 
1 year
 
 
 - 
 
 
 - 
 
 
 
 
 
Medicare Subsidy
 
 
 5,389 
 
 
 - 
 
11 years
 
 
 5,866 
 
 
 - 
 
11 years
 
 
 
Deferral of Major Generation Overhauls
 
 
 2,933 
 
 
 4,533 
 
4 years
 
 
 - 
 
 
 - 
 
 
 
 
 
Income Taxes, Net
 
 
 88 
 
 
 3,785 
 
34 years
 
 
 247,827 
 
 
 230,220 
 
31 years
 
 
 
Unrealized Loss on Forward Commitments
 
 
 2 
 
 
 5,347 
 
1 year
 
 
 3 
 
 
 427 
 
1 year
 
 
 
Other Regulatory Assets Being Recovered
 
 
 640 
 
 
 151 
 
various
 
 
 660 
 
 
 2,779 
 
various
Total Regulatory Assets Being Recovered
 
 
 137,102 
 
 
 201,905 
 
 
 
 
 358,877 
 
 
 394,278 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Noncurrent Regulatory Assets (a)
 
$
 156,690 
 
$
 202,328 
 
 
 
$
 369,905 
 
$
 403,278 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
 
Additionally, as of December 31, 2013, SWEPCo has recorded approximately $42 million in Customer Accounts Receivable on the balance sheet to reflect revenues, retroactive to January 2013, resulting from the PUCT decision in the Texas Base Rate Case.  These amounts will be collected from customers through a rider currently being billed to customers.


 
264

 
 
 
 
 
 
 
 
 
PSO
 
SWEPCo
 
 
 
 
 
 
 
 
 
Remaining
 
 
 
Remaining
 
 
 
 
 
 
 
December 31,
 
Refund
 
December 31,
 
Refund
 
 
 
 
 
 
 
2013 
 
2012 
 
Period
 
2013 
 
2012 
 
Period
Regulatory Liabilities:
 
(in thousands)
 
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Regulatory Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Over-recovered Fuel Costs - pays a return
 
$
 - 
 
$
 7,945 
 
 
 
$
 7,275 
 
$
 16,761 
 
1 year
Total Current Regulatory Liabilities
 
$
 - 
 
$
 7,945 
 
 
 
$
 7,275 
 
$
 16,761 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncurrent Regulatory Liabilities and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred Investment Tax Credits
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory liabilities not yet being paid:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Liabilities Currently Paying a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Louisiana Refundable Construction Financing Costs
 
$
 - 
 
$
 - 
 
 
 
$
 - 
 
$
 96,094 
 
 
 
Regulatory Liabilities Currently Not Paying a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Over-recovery of Costs Related to gridSMART ®
 
 
 2,635 
 
 
 3,964 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Storm Related Costs
 
 
 - 
 
 
 3,207 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Other Regulatory Liabilities Not Yet Being Paid
 
 
 248 
 
 
 1,613 
 
 
 
 
 - 
 
 
 - 
 
 
Total Regulatory Liabilities Not Yet Being Paid
 
 
 2,883 
 
 
 8,784 
 
 
 
 
 - 
 
 
 96,094 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory liabilities being paid:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Liabilities Currently Paying a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Asset Removal Costs
 
 
 276,418 
 
 
 280,446 
 
(a)
 
 
 372,381 
 
 
 362,838 
 
(a)
 
 
 
Louisiana Refundable Construction Financing Costs
 
 
 - 
 
 
 - 
 
 
 
 
 77,664 
 
 
 - 
 
5 years
 
 
 
Excess Earnings
 
 
 - 
 
 
 - 
 
 
 
 
 2,903 
 
 
 2,975 
 
40 years
 
 
 
Other Regulatory Liabilities Being Paid
 
 
 - 
 
 
 - 
 
 
 
 
 1,286 
 
 
 838 
 
various
 
Regulatory Liabilities Currently Not Paying a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred Investment Tax Credits
 
 
 46,753 
 
 
 42,345 
 
51 years
 
 
 11,207 
 
 
 12,769 
 
17 years
 
 
 
Vegetation Management
 
 
 - 
 
 
 - 
 
 
 
 
 4,002 
 
 
 130 
 
1 year
 
 
 
Peak Demand Reduction/Energy Efficiency
 
 
 - 
 
 
 2,915 
 
 
 
 
 901 
 
 
 - 
 
1 year
 
 
 
Base Load Purchase Power Contract
 
 
 - 
 
 
 8,484 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Other Regulatory Liabilities Being Paid
 
 
 1,619 
 
 
 1,843 
 
various
 
 
 1,784 
 
 
 827 
 
various
Total Regulatory Liabilities Being Paid
 
 
 324,790 
 
 
 336,033 
 
 
 
 
 472,128 
 
 
 380,377 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Noncurrent Regulatory Liabilities and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred Investment Tax Credits
 
$
 327,673 
 
$
 344,817 
 
 
 
$
 472,128 
 
$
 476,471 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
 
Relieved as removal costs are incurred.
 
5.   COMMITMENTS, GUARANTEES AND CONTINGENCIES

The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business.  In addition, their business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation cannot be predicted.  For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements.

COMMITMENTS

Construction and Commitments – Affecting APCo,  I&M, OPCo, PSO and SWEPCo

The Registrant Subsidiaries have substantial construction commitments to support their operations and environmental investments.  In managing the overall construction program and in the normal course of business, the Registrant Subsidiaries contractually commit to third-party construction vendors for certain material purchases and other construction services.  
 
The Registrant Subsidiaries also purchase fuel, materials, supplies, services and property, plant and equipment under contract as part of their normal course of business.  Certain supply contracts contain penalty provisions for early termination.

 
265

 
 

The following tables summarize the Registrant Subsidiaries’ actual contractual commitments as of December 31, 2013:

 
 
Less Than 1
 
 
 
 
 
After
 
 
Contractual Commitments - APCo
 
Year
 
2-3 Years
 
4-5 Years
 
5 Years
 
Total
 
 
(in thousands)
Fuel Purchase Contracts (a)
 
$
 402,442 
 
$
 569,302 
 
$
 510,386 
 
$
 737,128 
 
$
 2,219,258 
Energy and Capacity Purchase Contracts
 
 
 32,450 
 
 
 66,966 
 
 
 70,658 
 
 
 548,381 
 
 
 718,455 
Construction Contracts for Capital Assets (b)
 
 
 17,604 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 17,604 
Total
 
$
 452,496 
 
$
 636,268 
 
$
 581,044 
 
$
 1,285,509 
 
$
 2,955,317 

 
 
Less Than 1
 
 
 
 
 
After
 
 
Contractual Commitments - I&M
 
Year
 
2-3 Years
 
4-5 Years
 
5 Years
 
Total
 
 
(in thousands)
Fuel Purchase Contracts (a)
 
$
 456,669 
 
$
 477,289 
 
$
 251,669 
 
$
 427,000 
 
$
 1,612,627 
Energy and Capacity Purchase Contracts
 
 
 107,567 
 
 
 216,716 
 
 
 219,249 
 
 
 819,754 
 
 
 1,363,286 
Construction Contracts for Capital Assets (b)
 
 
 7,544 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 7,544 
Total
 
$
 571,780 
 
$
 694,005 
 
$
 470,918 
 
$
 1,246,754 
 
$
 2,983,457 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
 
Less Than 1
 
 
 
 
 
After
 
 
Contractual Commitments - OPCo
 
Year
 
2-3 Years
 
4-5 Years
 
5 Years
 
Total
 
 
(in thousands)
Energy and Capacity Purchase Contracts
 
$
 44,623 
 
$
 92,369 
 
$
 97,847 
 
$
 868,305 
 
$
 1,103,144 
Construction Contracts for Capital Assets (b)
 
 
 19,366 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 19,366 
Total
 
$
 63,989 
 
$
 92,369 
 
$
 97,847 
 
$
 868,305 
 
$
 1,122,510 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
 
Less Than 1
 
 
 
 
 
After
 
 
Contractual Commitments - PSO
 
Year
 
2-3 Years
 
4-5 Years
 
5 Years
 
Total
 
 
(in thousands)
Fuel Purchase Contracts (a)
 
$
 137,715 
 
$
 160,540 
 
$
 113,490 
 
$
 173,880 
 
$
 585,625 
Energy and Capacity Purchase Contracts
 
 
 70,252 
 
 
 149,977 
 
 
 170,418 
 
 
 475,431 
 
 
 866,078 
Construction Contracts for Capital Assets (b)
 
 
 8,082 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 8,082 
Total
 
$
 216,049 
 
$
 310,517 
 
$
 283,908 
 
$
 649,311 
 
$
 1,459,785 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
 
Less Than 1
 
 
 
 
 
After
 
 
Contractual Commitments - SWEPCo
 
Year
 
2-3 Years
 
4-5 Years
 
5 Years
 
Total
 
 
(in thousands)
Fuel Purchase Contracts (a)
 
$
 272,810 
 
$
 470,596 
 
$
 197,337 
 
$
 302,382 
 
$
 1,243,125 
Energy and Capacity Purchase Contracts
 
 
 19,455 
 
 
 45,911 
 
 
 61,833 
 
 
 248,035 
 
 
 375,234 
Construction Contracts for Capital Assets (b)
 
 
 4,911 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 4,911 
Total
 
$
 297,176 
 
$
 516,507 
 
$
 259,170 
 
$
 550,417 
 
$
 1,623,270 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

(a)
Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel.
(b)
Represents only capital assets for which there are signed contracts.  Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs.
 
 
 
266

 
GUARANTEES

Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.”  There is no collateral held in relation to any guarantees.  In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letters of Credit – Affecting APCo, I&M, OPCo and SWEPCo

Certain Registrant Subsidiaries enter into standby letters of credit with third parties.  These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves.

AEP has two revolving credit facilities totaling $3.5 billion, under which up to $1.2 billion may be issued as letters of credit.  As of December 31, 2013, the maximum future payments for letters of credit issued under the revolving credit facilities were as follows:

Company
 
Amount
 
Maturity
(in thousands)
I&M
 
$
 150 
 
March 2014
OPCo
 
 
 3,081 
 
June 2014
SWEPCo
 
 
 4,448 
 
March 2014

The Registrant Subsidiaries have $307 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $310 million as follows:

 
 
 
 
 
 
Bilateral
 
Maturity of
 
 
 
Pollution
 
 
Letters
 
Bilateral Letters
 
Company
 
Control Bonds
 
 
of Credit
 
of Credit
 
 
 
(in thousands)
 
 
 
APCo
 
$
 229,650 
 
$
 232,293 
(a) 
March 2014 to March 2015 
 
I&M
 
 
 77,000 
 
 
 77,886 
 
March 2015
 
                   
(a)  In February 2014, $106 million of bilateral letters of credit maturing in March 2014 were extended to March 2017.  

Guarantees of Third-Party Obligations – Affecting SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation.  As of December 31, 2013, SWEPCo has collected approximately $62 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $46 million is recorded in Asset Retirement Obligations on SWEPCo’s balance sheets.

Sabine charges SWEPCo, its only customer, all of its costs.  SWEPCo passes these costs to customers through its fuel clause.

 
267

 
Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo

Contracts

The Registrant Subsidiaries enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of December 31, 2013, there were no material liabilities recorded for any indemnifications.

APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East Companies related to power purchase and sale activity pursuant to the SIA.  PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity pursuant to the SIA.

Lease Obligations

Certain Registrant Subsidiaries lease certain equipment under master lease agreements.  See “Master Lease Agreements” and “Railcar Lease” sections of Note 12 for disclosure of lease residual value guarantees.

ENVIRONMENTAL CONTINGENCIES

Carbon Dioxide Public Nuisance Claims – Affecting APCo, I&M, OPCo, PSO and SWEPCo

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO 2 emissions exacerbated the effects of Hurricane Katrina.  The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims.  The court granted petitions for rehearing.  An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place.  Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision.  The petition was denied in January 2011.  Plaintiffs refiled their complaint in federal district court.  The court ordered all defendants to respond to the refiled complaints in October 2011.  In March 2012, the court granted the defendants’ motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations.  In May 2013, the U.S. Court of Appeals for the Fifth Circuit affirmed the district court’s dismissal of the complaint.  The plaintiffs did not appeal to the U.S. Supreme Court.

Alaskan Villages’ Claims – Affecting APCo, I&M, OPCo, PSO and SWEPCo

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies.  The complaint alleges that the defendants' emissions of CO 2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together.  The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance.  The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million.  In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim.  The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court.  In September 2012, the Ninth Circuit Court of Appeals affirmed the trial court’s decision, holding that the CAA displaced Kivalina’s claims for damages.  Plaintiffs filed seeking further review in the U.S. Supreme Court.  In May 2013, the U.S. Supreme Court denied the plaintiffs’ request for review.
 
 
268

 
The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation - Affecting APCo, I&M, OPCo, PSO and SWEPCo

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF.  Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized.  In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials.  The Registrant Subsidiaries currently incur costs to dispose of these substances safely.

Superfund addresses clean-up of hazardous substances that have been released to the environment.  The Federal EPA administers the clean-up programs.  Several states have enacted similar laws.  As of December 31, 2013, APCo and OPCo are each named as a Potentially Responsible Party (PRP) for two sites by the Federal EPA.  There are seven additional sites for which APCo, I&M, OPCo and SWEPCo have received information requests which could lead to PRP designation.  I&M has also been named potentially liable at two sites under state law including the I&M site discussed in the next paragraph.  SWEPCo has also been named potentially liable at one site under state law.  In those instances where the Registrant Subsidiaries have been named a PRP or defendant, disposal or recycling activities were in accordance with the then-applicable laws and regulations.  Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories.  Liability has been resolved for a number of sites with no significant effect on net income.

In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm.  I&M started remediation work in accordance with a plan approved by MDEQ.  I&M’s reserve is approximately $8 million.  As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ.  Management cannot predict the amount of additional cost, if any.

Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability.  Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often nonhazardous.  Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises.  At present, management’s estimates do not anticipate material cleanup costs for identified Superfund sites, except the I&M site discussed above.
 
NUCLEAR CONTINGENCIES – AFFECTING I&M

I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC).  I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant.  The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037.  The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S.  Should a nuclear incident occur at any nuclear power plant in the U.S., the liability could be substantial.

Decommissioning and Low Level Waste Accumulation Disposal

The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program.  Decommissioning costs are accrued over the service life of the Cook Plant.  The most recent decommissioning cost study was performed in 2012.  According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste ranges from $1.3 billion to $1.7 billion in 2012 nondiscounted dollars.  The wide range in estimated costs is caused by variables in assumptions.  I&M recovers estimated decommissioning costs for the Cook Plant in its rates.  The amounts recovered in rates were $10 million, $14 million and $14 million for the years ended December 31, 2013, 2012 and 2011, respectively.  Decommissioning costs recovered from customers are deposited in external trusts.

 
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As of December 31, 2013 and 2012, the total decommissioning trust fund balance was $1.6 billion and $1.4 billion, respectively.  Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers.  The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability.

I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant.  However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered.

SNF Disposal

The Federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal.  A fee of one mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant is being collected from customers and remitted to the U.S. Treasury.  As of December 31, 2013 and 2012, fees and related interest of $265 million and $265 million, respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $309 million and $308 million, respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts.  I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program.

In 2011, I&M signed a settlement agreement with the Federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delays in accepting SNF for permanent storage.  Under the settlement agreement, I&M received $31 million, $20 million and $14 million in 2013, 2012 and 2011, respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2016.  The proceeds reduced costs for dry cask storage.  As of December 31, 2013, I&M has deferred $22 million in Prepayments and Other Current Assets and $7 million in Deferred Charges and Other Noncurrent Assets on the balance sheet of dry cask storage and related operation and maintenance costs for recovery under this agreement.

See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 10 for disclosure of the fair value of assets within the trusts.

Nuclear Incident Liability

I&M carries insurance coverage for a nuclear incident at the Cook Plant for property damage, decommissioning and decontamination in the amount of $2.8 billion.  Insurance coverage for a nonnuclear incident at the Cook Plant is $1.7 billion.  Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage.  I&M utilizes industry mutual insurers for the placement of this insurance coverage.  Participation in this mutual insurance requires a contingent financial obligation of up to $39 million for I&M which is assessable if the insurer’s financial resources would be inadequate to pay for losses.

The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public liability arising from a nuclear incident at $13.6 billion and covers any incident at a licensed reactor in the U.S.  Commercially available insurance, which must be carried for each licensed reactor, provides $375 million of coverage.  In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $121 million on each licensed reactor in the U.S. payable in annual installments of $19 million.  As a result, I&M could be assessed $242 million per nuclear incident payable in annual installments of $38 million.  The number of incidents for which payments could be required is not limited.

In the event of an incident of a catastrophic nature, I&M is initially covered for the first $375 million through commercially available insurance.  The next level of liability coverage of up to $13.2 billion would be covered by claims made under the Price-Anderson Act.  If the liability were in excess of amounts recoverable from insurance and retrospective claim payments made under the Price-Anderson Act, I&M would seek to recover those amounts from customers through rate increases.  In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition.

 
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OPERATIONAL CONTINGENCIES

Insurance and Potential Losses – Affecting APCo, I&M, OPCo, PSO and SWEPCo

The Registrant Subsidiaries maintain insurance coverage normal and customary for electric utilities, subject to various deductibles.  Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions.  Covered property generally includes power plants, substations, facilities and inventories.  Excluded property generally includes transmission and distribution lines, poles and towers.  The insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by the Registrant Subsidiaries.  Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers.

See “Nuclear Contingencies” section of this footnote for a discussion of I&M’s nuclear exposures and related insurance.

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant.  Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition.

Rockport Plant Litigation – Affecting I&M

In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit.  The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement.  The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff.  The New York court has granted the motion to transfer this case to the U.S. District Court for the Southern District of Ohio.  The motion to dismiss, filed in October 2013, is pending.  Management will continue to defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.

6.   ACQUISITION, DISPOSITION AND IMPAIRMENTS

ACQUISITION

2011

Dresden Plant – Affecting APCo

In August 2011, APCo purchased the partially completed Dresden Plant from AEGCo, at cost, for $302 million.  The Dresden Plant was completed and placed in service in January 2012.  The Dresden Plant is located near Dresden, Ohio and is a natural gas, combined cycle power plant with a generating capacity of 608 MW.

DISPOSITION

2013

Conesville Coal Preparation Company – Affecting OPCo

In April 2013, OPCo closed on the sale of its Conesville Coal Preparation Company.  This sale did not have a significant impact on OPCo’s financial statements.

 
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IMPAIRMENTS

2013

Amos Plant, Unit 3 – Affecting APCo

In July 2013, the Virginia SCC approved the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo but, for rate purposes, reduced the proposed transfer price by $83 million pretax.  The Virginia jurisdictional share of the reduced price is approximately $39 million.  In December 2013, the WVPSC issued an order that approved the transfer of OPCo’s two-thirds interest in the Amos Plant, Unit 3 to APCo but deferred a final decision related to the $83 million pretax reduction in transfer price until APCo’s next base rate case.  The West Virginia and FERC jurisdictional share of the potential reduced transfer price is approximately $44 million.  Upon evaluation, management believes the West Virginia jurisdictional share is probable of recovery.  As a result of the Virginia order, in the fourth quarter of 2013, management recorded a pretax impairment of $39 million in Asset Impairments and Other Related Charges on the statement of income.  See the “Plant Transfer” section of Note 3.

Muskingum River Plant, Unit 5 – Affecting OPCo

In May 2013, the U.S. District Court for the Southern District of Ohio approved a modification to the consent decree, which was initially entered into in 2007, requiring certain types of pollution control equipment to be installed at certain AEP plants, including OPCo’s 600 MW Muskingum River Plant, Unit 5 (MR5) coal-fired generation plant.  Under the modification to the consent decree, OPCo has the option to cease burning coal and retire MR5 in 2015 or to cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017.  In the second quarter of 2013, based on the approval of the modified consent decree and changes in other market factors, management re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project, which would have extended the useful life of MR5, is remote.  As a result, management completed an impairment analysis and concluded that MR5 was impaired.  Under a market-based value approach, using level 3 unobservable inputs, management determined that the fair value of this generating unit was zero based on the lack of installed environmental control equipment and the nature and condition of this generating unit.  In the second quarter of 2013, OPCo recorded a pretax impairment of $154 million in Asset Impairments and Other Related Charges on the statement of income which includes a $6 million pretax impairment of related material and supplies inventory.  Management expects to retire the plant in 2015.

2012

Beckjord Plant, Unit 6, Conesville Plant, Unit 3, Kammer Plant, Units 1-3, Muskingum River Plant, Units 1-4, Sporn Plant, Units 2 and 4 and Picway Plant, Unit 5 – Affecting OPCo

In October 2012, management filed applications with the FERC proposing to terminate the Interconnection Agreement and seeking to complete the corporate separation of OPCo's generation assets.  Based on the intention to terminate the Interconnection Agreement and the FERC filing, management performed an evaluation of the recoverability of generation assets.  As a result, in November 2012, management, using generating unit specific estimated future cash flows, concluded that OPCo had a material impairment of certain generation assets.  Under a market-based value approach, using level 3 unobservable inputs, management determined that the fair value of these generating units was zero based on the lack of installed environmental control equipment and the nature and condition of these generating units.  In the fourth quarter of 2012, OPCo recorded a pretax impairment of $287 million in Asset Impairments and Other Related Charges on the statement of income related to Beckjord Plant, Unit 6, Conesville Plant, Unit 3, Kammer Plant, Units 1-3, Muskingum River Plant, Units 1-4, Sporn Plant, Units 2 and 4 and Picway Plant, Unit 5 generating units which includes $13 million of related material and supplies inventory.

 
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Turk Plant – Affecting SWEPCo

In 2012, SWEPCo recorded a pretax write-off of $13 million in Asset Impairments and Other Related Charges on the statement of income related to unrecoverable construction costs subject to the Texas capital costs cap portion of the Turk Plant.

2011

Turk Plant – Affecting SWEPCo

In the fourth quarter of 2011, SWEPCo recorded a pretax write-off of $49 million in Asset Impairments and Other Related Charges on the statement of income related to the Texas jurisdictional portion of the Turk Plant as a result of the November 2011 Texas Court of Appeals decision upholding the Texas capital cost cap.

Muskingum River Plant, Unit 5 FGD Project (MR5) – Affecting OPCo

In September 2011, subsequent to the stipulation agreement filed with the PUCO, management determined that OPCo was not likely to complete the previously suspended MR5 project and that the project’s preliminary engineering costs were no longer probable of being recovered.  As a result, in the third quarter of 2011, OPCo recorded a pretax write-off of $42 million in Asset Impairments and Other Related Charges on the statement of income.

Sporn Plant, Unit 5 – Affecting OPCo

In the third quarter of 2011, management decided to no longer offer the output of Sporn Plant, Unit 5 into the PJM Reliability Pricing Model auction.  Sporn Plant, Unit 5 is not expected to operate in the future, resulting in the removal of Sporn Plant, Unit 5 from the Interconnection Agreement.  As a result, in the third quarter of 2011, OPCo recorded a pretax write-off of $48 million in Asset Impairments and Other Related Charges on the statement of income.

7.   BENEFIT PLANS

For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Investments Held in Trust for Future Liabilities” and “Fair Value Measurements of Assets and Liabilities” sections of Note 1.

The Registrant Subsidiaries participate in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans.  Substantially all employees are covered by the qualified plan or both the qualified and a nonqualified pension plan.  The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees.

Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same.  This section details the assumptions that apply to all Registrant Subsidiaries and the rate of compensation increase for each subsidiary.

The Registrant Subsidiaries recognize the funded status associated with defined benefit pension and OPEB plans in their balance sheets.  Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance.  The Registrant Subsidiaries recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost.  The Registrant Subsidiaries record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery.  The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.

 
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Actuarial Assumptions for Benefit Obligations

The weighted-average assumptions as of December 31 of each year used in the measurement of the Registrant Subsidiaries’ benefit obligations are shown in the following tables:

 
 
 
 
 
Other Postretirement
 
 
Pension Plans
 
 
Benefit Plans
Assumption
 
2013 
 
2012 
 
 
2013 
 
2012 
Discount Rate
 
 4.70 
%
 
 3.95 
%
 
 
 4.70 
%
 
 3.95 
%

 
 
Pension Plans
 
Assumption - Rate of Compensation Increase (a)
 
2013 
 
2012 
 
APCo
 
 4.60 
%
 
 4.70 
%
 
I&M
 
 4.90 
%
 
 5.00 
%
 
OPCo
 
 5.00 
%
 
 5.00 
%
 
PSO
 
 4.90 
%
 
 4.90 
%
 
SWEPCo
 
 4.85 
%
 
 4.75 
%
 
               
(a)  Rates are for base pay only.  In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.   

A duration-based method is used to determine the discount rate for the plans.  A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability.  The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.  The discount rate is the same for each Registrant Subsidiary.

For 2013, the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 11.5% per year, with the average increase shown in the table above.  The compensation increase rates reflect variations in each Registrant Subsidiary’s population participating in the pension plan.

Actuarial Assumptions for Net Periodic Benefit Costs

The weighted-average assumptions as of January 1 of each year used in the measurement of each Registrant Subsidiary’s benefit costs are shown in the following tables:

 
 
 
 
 
Other Postretirement
 
 
 
Pension Plans
 
Benefit Plans
Assumptions
 
2013 
 
2012 
 
2011 
 
2013 
 
2012 
 
2011 
Discount Rate
 
 3.95 
%
 
 4.55 
%
 
 5.05 
%
 
 3.95 
%
 
 4.75 
%
 
 5.25 
%
Expected Return on Plan Assets
 
 6.50 
%
 
 7.25 
%
 
 7.75 
%
 
 7.00 
%
 
 7.25 
%
 
 7.50 
%

 
 
Pension Plans
Assumption - Rate of Compensation Increase
 
2013 
 
2012 
 
2011 
APCo
 
 4.70 
%
 
 4.70 
%
 
 4.65 
%
I&M
 
 5.00 
%
 
 5.00 
%
 
 4.90 
%
OPCo
 
 5.00 
%
 
 5.00 
%
 
 4.95 
%
PSO
 
 4.90 
%
 
 4.90 
%
 
 4.85 
%
SWEPCo
 
 4.75 
%
 
 4.75 
%
 
 4.70 
%

The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation and current prospects for economic growth.  The expected return on plan assets is the same for each Registrant Subsidiary.

 
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The health care trend rate assumptions as of January 1 of each year used for OPEB plans measurement purposes are shown below:

Health Care Trend Rates
 
2013 
 
2012 
Initial
 
 6.75 
%
 
 7.00 
%
Ultimate
 
 5.00 
%
 
 5.00 
%
Year Ultimate Reached
 
2020 
 
 
2020 
 

Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans.  A 1% change in assumed health care cost trend rates would have the following effects:

 
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Effect on Total Service and Interest Cost
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Components of Net Periodic Postretirement
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Health Care Benefit Cost:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
   1% Increase
 
$
 1,267 
 
$
 579 
 
$
 1,060 
 
$
 262 
 
$
 304 
 
   1% Decrease
 
 
 (877)
 
 
 (382)
 
 
 (738)
 
 
 (172)
 
 
 (200)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effect on the Health Care Component of the
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated Postretirement Benefit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Obligation:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
   1% Increase
 
$
 18,179 
 
$
 6,884 
 
$
 7,077 
 
$
 3,216 
 
$
 3,597 
 
   1% Decrease
 
 
 (14,552)
 
 
 (5,603)
 
 
 (5,760)
 
 
 (2,617)
 
 
 (2,927)

Significant Concentrations of Risk within Plan Assets

In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets.  The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits.  The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment.  Management monitors the plans to control security diversification and ensure compliance with the investment policy.  As of December 31, 2013, the assets were invested in compliance with all investment limits.  See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details.

 
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Benefit Plan Obligations, Plan Assets and Funded Status as of December 31, 2013 and 2012

The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status as of December 31.  The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively.

APCo
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
2013 
 
2012 
 
2013 
 
2012 
Change in Benefit Obligation
 
(in thousands)
Benefit Obligation as of January 1,
 
$
 718,460 
 
$
 681,450 
 
$
 348,990 
 
$
 395,482 
Service Cost
 
 
 6,171 
 
 
 7,565 
 
 
 2,566 
 
 
 5,387 
Interest Cost
 
 
 27,662 
 
 
 30,211 
 
 
 13,454 
 
 
 18,462 
Actuarial (Gain) Loss
 
 
 (45,619)
 
 
 43,341 
 
 
 (66,056)
 
 
 31,776 
Plan Amendment Prior Service Credit
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (80,528)
Benefit Payments
 
 
 (43,443)
 
 
 (44,107)
 
 
 (27,220)
 
 
 (29,228)
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 6,600 
 
 
 5,826 
Medicare Subsidy
 
 
 - 
 
 
 - 
 
 
 1,550 
 
 
 1,813 
Benefit Obligation as of December 31,
 
$
 663,231 
 
$
 718,460 
 
$
 279,884 
 
$
 348,990 
 
 
 
 
 
 
 
 
 
 
 
 
 
Change in Fair Value of Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Plan Assets as of January 1,
 
$
 621,570 
 
$
 570,756 
 
$
 267,758 
 
$
 229,735 
Actual Gain on Plan Assets
 
 
 49,832 
 
 
 69,686 
 
 
 34,289 
 
 
 44,919 
Company Contributions
 
 
 36 
 
 
 25,235 
 
 
 3,413 
 
 
 16,506 
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 6,600 
 
 
 5,826 
Benefit Payments
 
 
 (43,443)
 
 
 (44,107)
 
 
 (27,220)
 
 
 (29,228)
Fair Value of Plan Assets as of December 31,
 
$
 627,995 
 
$
 621,570 
 
$
 284,840 
 
$
 267,758 
 
 
 
 
 
 
 
 
 
 
 
 
 
Funded (Underfunded) Status as of December 31,
 
$
 (35,236)
 
$
 (96,890)
 
$
 4,956 
 
$
 (81,232)

I&M
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
2013 
 
2012 
 
2013 
 
2012 
Change in Benefit Obligation
 
(in thousands)
Benefit Obligation as of January 1,
 
$
 618,973 
 
$
 581,677 
 
$
 218,553 
 
$
 277,353 
Service Cost
 
 
 8,736 
 
 
 9,908 
 
 
 3,219 
 
 
 6,621 
Interest Cost
 
 
 24,100 
 
 
 26,245 
 
 
 8,221 
 
 
 12,785 
Actuarial (Gain) Loss
 
 
 (41,631)
 
 
 44,475 
 
 
 (52,800)
 
 
 13,638 
Plan Amendment Prior Service Credit
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (78,851)
Benefit Payments
 
 
 (35,479)
 
 
 (43,332)
 
 
 (16,613)
 
 
 (18,394)
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 4,745 
 
 
 4,226 
Medicare Subsidy
 
 
 - 
 
 
 - 
 
 
 1,172 
 
 
 1,175 
Benefit Obligation as of December 31,
 
$
 574,699 
 
$
 618,973 
 
$
 166,497 
 
$
 218,553 
 
 
 
 
 
 
 
 
 
 
 
 
 
Change in Fair Value of Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Plan Assets as of January 1,
 
$
 552,026 
 
$
 503,926 
 
$
 194,128 
 
$
 181,237 
Actual Gain on Plan Assets
 
 
 42,584 
 
 
 69,136 
 
 
 23,844 
 
 
 14,357 
Company Contributions
 
 
 12 
 
 
 22,296 
 
 
 110 
 
 
 12,702 
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 4,745 
 
 
 4,226 
Benefit Payments
 
 
 (35,479)
 
 
 (43,332)
 
 
 (16,613)
 
 
 (18,394)
Fair Value of Plan Assets as of December 31,
 
$
 559,143 
 
$
 552,026 
 
$
 206,214 
 
$
 194,128 
 
 
 
 
 
 
 
 
 
 
 
 
 
Funded (Underfunded) Status as of December 31,
 
$
 (15,556)
 
$
 (66,947)
 
$
 39,717 
 
$
 (24,425)


 
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OPCo
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
2013 
 
2012 
 
2013 
 
2012 
Change in Benefit Obligation
 
(in thousands)
Benefit Obligation as of January 1,
 
$
 1,068,186 
 
$
 1,020,890 
 
$
 466,290 
 
$
 519,892 
Transfer of OPCo Generation Benefit Obligation
 
 
 (499,725)
 
 
 - 
 
 
 (250,843)
 
 
 - 
Service Cost
 
 
 5,285 
 
 
 11,003 
 
 
 2,882 
 
 
 8,748 
Interest Cost
 
 
 21,939 
 
 
 45,194 
 
 
 9,494 
 
 
 24,189 
Actuarial (Gain) Loss
 
 
 (34,373)
 
 
 63,571 
 
 
 (44,149)
 
 
 42,013 
Plan Amendment Prior Service Credit
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (101,384)
Benefit Payments
 
 
 (37,669)
 
 
 (72,472)
 
 
 (18,844)
 
 
 (38,269)
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 5,199 
 
 
 8,545 
Medicare Subsidy
 
 
 - 
 
 
 - 
 
 
 1,135 
 
 
 2,556 
Benefit Obligation as of December 31,
 
$
 523,643 
 
$
 1,068,186 
 
$
 171,164 
 
$
 466,290 
 
 
 
 
 
 
 
 
 
 
 
 
 
Change in Fair Value of Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Plan Assets as of January 1,
 
$
 1,015,115 
 
$
 925,939 
 
$
 366,301 
 
$
 311,836 
Transfer of OPCo Generation Plan Assets
 
 
 (506,076)
 
 
 - 
 
 
 (170,650)
 
 
 - 
Actual Gain on Plan Assets
 
 
 30,264 
 
 
 118,395 
 
 
 29,576 
 
 
 65,125 
Company Contributions
 
 
 - 
 
 
 43,253 
 
 
 412 
 
 
 19,064 
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 5,199 
 
 
 8,545 
Benefit Payments
 
 
 (37,669)
 
 
 (72,472)
 
 
 (18,844)
 
 
 (38,269)
Fair Value of Plan Assets as of December 31,
 
$
 501,634 
 
$
 1,015,115 
 
$
 211,994 
 
$
 366,301 
 
 
 
 
 
 
 
 
 
 
 
 
 
Funded (Underfunded) Status as of December 31,
 
$
 (22,009)
 
$
 (53,071)
 
$
 40,830 
 
$
 (99,989)

PSO
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
2013 
 
2012 
 
2013 
 
2012 
Change in Benefit Obligation
 
(in thousands)
Benefit Obligation as of January 1,
 
$
 279,685 
 
$
 277,448 
 
$
 99,680 
 
$
 125,164 
Service Cost
 
 
 5,562 
 
 
 5,951 
 
 
 1,372 
 
 
 2,836 
Interest Cost
 
 
 10,993 
 
 
 12,301 
 
 
 3,793 
 
 
 5,797 
Actuarial (Gain) Loss
 
 
 (15,381)
 
 
 6,128 
 
 
 (22,070)
 
 
 7,511 
Plan Amendment Prior Service Credit
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (35,971)
Benefit Payments
 
 
 (20,149)
 
 
 (22,143)
 
 
 (7,741)
 
 
 (8,363)
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 2,229 
 
 
 2,024 
Medicare Subsidy
 
 
 - 
 
 
 - 
 
 
 516 
 
 
 682 
Benefit Obligation as of December 31,
 
$
 260,710 
 
$
 279,685 
 
$
 77,779 
 
$
 99,680 
 
 
 
 
 
 
 
 
 
 
 
 
 
Change in Fair Value of Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Plan Assets as of January 1,
 
$
 264,823 
 
$
 245,769 
 
$
 90,521 
 
$
 83,090 
Actual Gain on Plan Assets
 
 
 19,892 
 
 
 28,861 
 
 
 11,324 
 
 
 8,089 
Company Contributions
 
 
 31 
 
 
 12,336 
 
 
 - 
 
 
 5,681 
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 2,229 
 
 
 2,024 
Benefit Payments
 
 
 (20,149)
 
 
 (22,143)
 
 
 (7,741)
 
 
 (8,363)
Fair Value of Plan Assets as of December 31,
 
$
 264,597 
 
$
 264,823 
 
$
 96,333 
 
$
 90,521 
 
 
 
 
 
 
 
 
 
 
 
 
 
Funded (Underfunded) Status as of December 31,
 
$
 3,887 
 
$
 (14,862)
 
$
 18,554 
 
$
 (9,159)


 
277

 
 
SWEPCo
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
2013 
 
2012 
 
2013 
 
2012 
Change in Benefit Obligation
 
(in thousands)
Benefit Obligation as of January 1,
 
$
 285,560 
 
$
 277,594 
 
$
 109,948 
 
$
 145,160 
Service Cost
 
 
 7,011 
 
 
 7,099 
 
 
 1,693 
 
 
 3,324 
Interest Cost
 
 
 11,454 
 
 
 12,537 
 
 
 4,301 
 
 
 6,673 
Actuarial (Gain) Loss
 
 
 (12,818)
 
 
 9,752 
 
 
 (23,852)
 
 
 7,885 
Plan Amendment Prior Service Credit
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (47,309)
Benefit Payments
 
 
 (20,643)
 
 
 (21,422)
 
 
 (8,057)
 
 
 (8,610)
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 2,410 
 
 
 2,189 
Medicare Subsidy
 
 
 - 
 
 
 - 
 
 
 554 
 
 
 636 
Benefit Obligation as of December 31,
 
$
 270,564 
 
$
 285,560 
 
$
 86,997 
 
$
 109,948 
 
 
 
 
 
 
 
 
 
 
 
 
 
Change in Fair Value of Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Plan Assets as of January 1,
 
$
 279,699 
 
$
 255,861 
 
$
 99,846 
 
$
 96,364 
Actual Gain on Plan Assets
 
 
 19,823 
 
 
 31,992 
 
 
 13,551 
 
 
 3,143 
Company Contributions
 
 
 67 
 
 
 13,268 
 
 
 - 
 
 
 6,760 
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 2,410 
 
 
 2,189 
Benefit Payments
 
 
 (20,643)
 
 
 (21,422)
 
 
 (8,057)
 
 
 (8,610)
Fair Value of Plan Assets as of December 31,
 
$
 278,946 
 
$
 279,699 
 
$
 107,750 
 
$
 99,846 
 
 
 
 
 
 
 
 
 
 
 
 
 
Funded (Underfunded) Status as of December 31,
 
$
 8,382 
 
$
 (5,861)
 
$
 20,753 
 
$
 (10,102)

Amounts Recognized on the Registrant Subsidiaries' Balance Sheets as of December 31, 2013 and 2012

 
 
 
 
 
 
Other Postretirement
 
 
 
 
Pension Plans
 
Benefit Plans
 
 
 
 
December 31,
 
APCo
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
 
(in thousands)
 
Deferred Charges and Other Noncurrent Assets -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prepaid Benefit Costs
 
$
 - 
 
$
 - 
 
$
 27,945 
 
$
 - 
 
Other Current Liabilities - Accrued Short-term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Benefit Liability
 
 
 (34)
 
 
 (34)
 
 
 (2,970)
 
 
 (2,836)
 
Employee Benefits and Pension Obligations -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Long-term Benefit Liability
 
 
 (35,202)
 
 
 (96,856)
 
 
 (20,019)
 
 
 (78,396)
 
Funded (Underfunded) Status
 
$
 (35,236)
 
$
 (96,890)
 
$
 4,956 
 
$
 (81,232)

 
 
 
 
 
 
Other Postretirement
 
 
 
 
Pension Plans
 
Benefit Plans
 
 
 
 
December 31,
 
I&M
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
 
(in thousands)
 
Deferred Charges and Other Noncurrent Assets -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prepaid Benefit Costs
 
$
 - 
 
$
 - 
 
$
 39,590 
 
$
 - 
 
Other Current Liabilities - Accrued Short-term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Benefit Liability
 
 
 (43)
 
 
 (15)
 
 
 - 
 
 
 (290)
 
Deferred Credits and Other Noncurrent Liabilities -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Long-term Benefit Liability
 
 
 (15,513)
 
 
 (66,932)
 
 
 127 
 
 
 (24,135)
 
Funded (Underfunded) Status
 
$
 (15,556)
 
$
 (66,947)
 
$
 39,717 
 
$
 (24,425)


 
278

 
 
 
 
 
 
 
 
Other Postretirement
 
 
 
 
Pension Plans
 
Benefit Plans
 
 
 
 
December 31,
 
OPCo
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
 
(in thousands)
 
Deferred Charges and Other Noncurrent Assets -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prepaid Benefit Costs
 
$
 - 
 
$
 - 
 
$
 39,496 
 
$
 - 
 
Other Current Liabilities - Accrued Short-term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Benefit Liability
 
 
 (1)
 
 
 (64)
 
 
 - 
 
 
 (986)
 
Employee Benefits and Pension Obligations -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Long-term Benefit Liability
 
 
 (22,008)
 
 
 (53,007)
 
 
 1,334 
 
 
 (99,003)
 
Funded (Underfunded) Status
 
$
 (22,009)
 
$
 (53,071)
 
$
 40,830 
 
$
 (99,989)

 
 
 
 
 
 
Other Postretirement
 
 
 
 
Pension Plans
 
Benefit Plans
 
 
 
 
December 31,
 
PSO
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
 
(in thousands)
 
Employee Benefits and Pension Assets -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prepaid Benefit Costs
 
$
 5,280 
 
$
 - 
 
$
 17,349 
 
$
 - 
 
Other Current Liabilities - Accrued Short-term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Benefit Liability
 
 
 (107)
 
 
 (89)
 
 
 - 
 
 
 - 
 
Employee Benefits and Pension Obligations -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Long-term Benefit Liability
 
 
 (1,286)
 
 
 (14,773)
 
 
 1,205 
 
 
 (9,159)
 
Funded (Underfunded) Status
 
$
 3,887 
 
$
 (14,862)
 
$
 18,554 
 
$
 (9,159)

 
 
 
 
 
 
Other Postretirement
 
 
 
 
Pension Plans
 
Benefit Plans
 
 
 
 
December 31,
 
SWEPCo
 
2013 
 
2012 
 
2013 
 
2012 
 
 
 
 
(in thousands)
 
Deferred Charges and Other Noncurrent Assets -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prepaid Benefit Costs
 
$
 9,506 
 
$
 - 
 
$
 19,210 
 
$
 - 
 
Other Current Liabilities - Accrued Short-term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Benefit Liability
 
 
 (79)
 
 
 (80)
 
 
 - 
 
 
 - 
 
Employee Benefits and Pension Obligations -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Long-term Benefit Liability
 
 
 (1,045)
 
 
 (5,781)
 
 
 1,543 
 
 
 (10,102)
 
Funded (Underfunded) Status
 
$
 8,382 
 
$
 (5,861)
 
$
 20,753 
 
$
 (10,102)

Amounts Included in AOCI and Regulatory Assets as of December 31, 2013 and 2012

 
 
 
 
 
Other Postretirement
APCo
 
Pension Plans
 
Benefit Plans
 
 
 
December 31,
 
 
 
2013 
 
2012 
 
2013 
 
2012 
Components
 
(in thousands)
Net Actuarial Loss
 
$
 220,047 
 
$
 303,483 
 
$
 72,732 
 
$
 167,173 
Prior Service Cost (Credit)
 
 
 720 
 
 
 918 
 
 
 (100,676)
 
 
 (110,726)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recorded as
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets
 
$
 217,937 
 
$
 299,456 
 
$
 (25,473)
 
$
 13,189 
Deferred Income Taxes
 
 
 991 
 
 
 1,732 
 
 
 (865)
 
 
 15,140 
Net of Tax AOCI
 
 
 1,839 
 
 
 3,213 
 
 
 (1,606)
 
 
 28,118 


 
279

 
 
 
 
 
 
 
Other Postretirement
I&M
 
Pension Plans
 
Benefit Plans
 
 
 
December 31,
 
 
 
2013 
 
2012 
 
2013 
 
2012 
Components
 
(in thousands)
Net Actuarial Loss
 
$
 138,367 
 
$
 211,443 
 
$
 54,949 
 
$
 125,935 
Prior Service Cost (Credit)
 
 
 705 
 
 
 900 
 
 
 (94,538)
 
 
 (103,959)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recorded as
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets
 
$
 134,560 
 
$
 202,821 
 
$
 (34,428)
 
$
 17,976 
Deferred Income Taxes
 
 
 1,579 
 
 
 3,332 
 
 
 (1,807)
 
 
 1,400 
Net of Tax AOCI
 
 
 2,933 
 
 
 6,190 
 
 
 (3,354)
 
 
 2,600 

 
 
 
 
 
Other Postretirement
OPCo
 
Pension Plans
 
Benefit Plans
 
 
 
December 31,
 
 
 
2013 
 
2012 
 
2013 
 
2012 
Components
 
(in thousands)
Net Actuarial Loss
 
$
 227,668 
 
$
 500,318 
 
$
 29,804 
 
$
 216,350 
Prior Service Cost (Credit)
 
 
 550 
 
 
 1,282 
 
 
 (69,300)
 
 
 (142,253)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recorded as
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets
 
$
 228,218 
 
$
 289,931 
 
$
 (39,496)
 
$
 19,754 
Deferred Income Taxes
 
 
 - 
 
 
 74,084 
 
 
 - 
 
 
 19,020 
Net of Tax AOCI
 
 
 - 
 
 
 137,585 
 
 
 - 
 
 
 35,323 

 
 
 
 
 
Other Postretirement
PSO
 
Pension Plans
 
Benefit Plans
 
 
 
December 31,
 
 
 
2013 
 
2012 
 
2013 
 
2012 
Components
 
(in thousands)
Net Actuarial Loss
 
$
 93,688 
 
$
 123,132 
 
$
 25,712 
 
$
 56,493 
Prior Service Cost (Credit)
 
 
 832 
 
 
 1,129 
 
 
 (43,061)
 
 
 (47,350)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recorded as
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets
 
$
 94,520 
 
$
 124,261 
 
$
 (17,349)
 
$
 9,143 

 
 
 
 
 
Other Postretirement
SWEPCo
 
Pension Plans
 
Benefit Plans
 
 
 
December 31,
 
 
 
2013 
 
2012 
 
2013 
 
2012 
Components
 
(in thousands)
Net Actuarial Loss
 
$
 95,492 
 
$
 121,839 
 
$
 32,772 
 
$
 67,223 
Prior Service Cost (Credit)
 
 
 1,004 
 
 
 1,353 
 
 
 (51,982)
 
 
 (57,138)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recorded as
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets
 
$
 96,496 
 
$
 123,192 
 
$
 (11,836)
 
$
 6,528 
Deferred Income Taxes
 
 
 - 
 
 
 - 
 
 
 (2,580)
 
 
 1,246 
Net of Tax AOCI
 
 
 - 
 
 
 - 
 
 
 (4,794)
 
 
 2,311 


 
280

 

Components of the change in amounts included in AOCI and Regulatory Assets by Registrant Subsidiary during the years ended December 31, 2013 and 2012 are as follows:

Pension Plans - Components
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Actuarial Gain During the Year
 
$
 (58,411)
 
$
 (51,388)
 
$
 (253,392)
 
$
 (19,599)
 
$
 (16,133)
Amortization of Actuarial Loss
 
 
 (25,025)
 
 
 (21,688)
 
 
 (19,833)
 
 
 (9,845)
 
 
 (10,214)
Amortization of Prior Service Cost
 
 
 (198)
 
 
 (195)
 
 
 (157)
 
 
 (297)
 
 
 (349)
Change for the Year Ended
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 December 31, 2013
$
 (83,634)
 
$
 (73,271)
 
$
 (273,382)
 
$
 (29,741)
 
$
 (26,696)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension Plans - Components
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Actuarial (Gain) Loss During the Year
 
$
 15,599 
 
$
 12,905 
 
$
 13,577 
 
$
 (4,718)
 
$
 (3,373)
Amortization of Actuarial Loss
 
 
 (20,339)
 
 
 (17,569)
 
 
 (30,439)
 
 
 (8,206)
 
 
 (8,330)
Amortization of Prior Service Credit (Cost)
 
 
 (475)
 
 
 (407)
 
 
 (743)
 
 
 948 
 
 
 793 
Change for the Year Ended
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2012
$
 (5,215)
 
$
 (5,071)
 
$
 (17,605)
 
$
 (11,976)
 
$
 (10,910)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement Benefit Plans - Components
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Actuarial Gain During the Year
 
$
 (82,192)
 
$
 (63,460)
 
$
 (111,922)
 
$
 (27,305)
 
$
 (30,523)
Amortization of Actuarial Loss
 
 
 (12,249)
 
 
 (7,526)
 
 
 (8,633)
 
 
 (3,476)
 
 
 (3,928)
Amortization of Prior Service Credit
 
 
 10,050 
 
 
 9,421 
 
 
 6,962 
 
 
 4,289 
 
 
 5,156 
Change for the Year Ended
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
$
 (84,391)
 
$
 (61,565)
 
$
 (113,593)
 
$
 (26,492)
 
$
 (29,295)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement Benefit Plans - Components
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Actuarial (Gain) Loss During the Year
 
$
 3,084 
 
$
 11,747 
 
$
 (1,170)
 
$
 5,166 
 
$
 11,341 
Amortization of Actuarial Loss
 
 
 (10,526)
 
 
 (7,050)
 
 
 (13,669)
 
 
 (3,189)
 
 
 (3,659)
Prior Service Credit
 
 (80,528)
 
 
 (78,851)
 
 
 (101,384)
 
 
 (35,971)
 
 
 (47,309)
Amortization of Prior Service Credit
 
 
 2,862 
 
 
 2,383 
 
 
 3,873 
 
 
 1,079 
 
 
 933 
Amortization of Transition Obligation
 
 
 (780)
 
 
 (132)
 
 
 (104)
 
 
 - 
 
 
 - 
Change for the Year Ended
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2012
$
 (85,888)
 
$
 (71,903)
 
$
 (112,454)
 
$
 (32,915)
 
$
 (38,694)


 
281

 

Pension and Other Postretirement Plans’ Assets

The following tables present the classification of pension plan assets within the fair value hierarchy by Registrant Subsidiary as of December 31, 2013:

 
APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 145,515 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 145,515 
 
 23.2 
%
 
 
International
 
 
 68,591 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 68,591 
 
 10.9 
%
 
 
Real Estate Investment Trusts
 
 
 7,718 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 7,718 
 
 1.2 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 1,302 
 
 
 - 
 
 
 - 
 
 
 1,302 
 
 0.2 
%
 
Subtotal - Equities
 
 
 221,824 
 
 
 1,302 
 
 
 - 
 
 
 - 
 
 
 223,126 
 
 35.5 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 3,456 
 
 
 - 
 
 
 - 
 
 
 3,456 
 
 0.5 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 51,556 
 
 
 - 
 
 
 - 
 
 
 51,556 
 
 8.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 213,280 
 
 
 - 
 
 
 - 
 
 
 213,280 
 
 34.0 
%
 
 
Foreign Debt
 
 
 - 
 
 
 45,818 
 
 
 - 
 
 
 - 
 
 
 45,818 
 
 7.3 
%
 
 
State and Local Government
 
 
 - 
 
 
 3,730 
 
 
 - 
 
 
 - 
 
 
 3,730 
 
 0.6 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 4,437 
 
 
 - 
 
 
 - 
 
 
 4,437 
 
 0.7 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 322,277 
 
 
 - 
 
 
 - 
 
 
 322,277 
 
 51.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 31,757 
 
 
 - 
 
 
 31,757 
 
 5.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 43,939 
 
 
 - 
 
 
 43,939 
 
 7.0 
%
 
Securities Lending
 
 
 - 
 
 
 4,689 
 
 
 - 
 
 
 - 
 
 
 4,689 
 
 0.8 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (6,024)
 
 
 (6,024)
 
 (0.9)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 - 
 
 
 6,476 
 
 
 - 
 
 
 - 
 
 
 6,476 
 
 1.0 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,755 
 
 
 1,755 
 
 0.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 221,824 
 
$
 334,744 
 
$
 75,696 
 
$
 (4,269)
 
$
 627,995 
 
 100.0 
%


 
282

 
 
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 129,561 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 129,561 
 
 23.2 
%
 
 
International
 
 
 61,071 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 61,071 
 
 10.9 
%
 
 
Real Estate Investment Trusts
 
 
 6,872 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 6,872 
 
 1.2 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 1,159 
 
 
 - 
 
 
 - 
 
 
 1,159 
 
 0.2 
%
 
Subtotal - Equities
 
 
 197,504 
 
 
 1,159 
 
 
 - 
 
 
 - 
 
 
 198,663 
 
 35.5 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 3,077 
 
 
 - 
 
 
 - 
 
 
 3,077 
 
 0.5 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 45,904 
 
 
 - 
 
 
 - 
 
 
 45,904 
 
 8.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 189,896 
 
 
 - 
 
 
 - 
 
 
 189,896 
 
 34.0 
%
 
 
Foreign Debt
 
 
 - 
 
 
 40,794 
 
 
 - 
 
 
 - 
 
 
 40,794 
 
 7.3 
%
 
 
State and Local Government
 
 
 - 
 
 
 3,321 
 
 
 - 
 
 
 - 
 
 
 3,321 
 
 0.6 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 3,951 
 
 
 - 
 
 
 - 
 
 
 3,951 
 
 0.7 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 286,943 
 
 
 - 
 
 
 - 
 
 
 286,943 
 
 51.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 28,275 
 
 
 - 
 
 
 28,275 
 
 5.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 39,121 
 
 
 - 
 
 
 39,121 
 
 7.0 
%
 
Securities Lending
 
 
 - 
 
 
 4,175 
 
 
 - 
 
 
 - 
 
 
 4,175 
 
 0.8 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (5,363)
 
 
 (5,363)
 
 (0.9)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 - 
 
 
 5,766 
 
 
 - 
 
 
 - 
 
 
 5,766 
 
 1.0 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,563 
 
 
 1,563 
 
 0.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 197,504 
 
$
 298,043 
 
$
 67,396 
 
$
 (3,800)
 
$
 559,143 
 
 100.0 
%


 
283

 
 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 116,233 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 116,233 
 
 23.2 
%
 
 
International
 
 
 54,790 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 54,790 
 
 10.9 
%
 
 
Real Estate Investment Trusts
 
 
 6,165 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 6,165 
 
 1.2 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 1,040 
 
 
 - 
 
 
 - 
 
 
 1,040 
 
 0.2 
%
 
Subtotal - Equities
 
 
 177,188 
 
 
 1,040 
 
 
 - 
 
 
 - 
 
 
 178,228 
 
 35.5 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 2,761 
 
 
 - 
 
 
 - 
 
 
 2,761 
 
 0.5 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 41,183 
 
 
 - 
 
 
 - 
 
 
 41,183 
 
 8.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 170,365 
 
 
 - 
 
 
 - 
 
 
 170,365 
 
 34.0 
%
 
 
Foreign Debt
 
 
 - 
 
 
 36,599 
 
 
 - 
 
 
 - 
 
 
 36,599 
 
 7.3 
%
 
 
State and Local Government
 
 
 - 
 
 
 2,980 
 
 
 - 
 
 
 - 
 
 
 2,980 
 
 0.6 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 3,545 
 
 
 - 
 
 
 - 
 
 
 3,545 
 
 0.7 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 257,433 
 
 
 - 
 
 
 - 
 
 
 257,433 
 
 51.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 25,367 
 
 
 - 
 
 
 25,367 
 
 5.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 35,098 
 
 
 - 
 
 
 35,098 
 
 7.0 
%
 
Securities Lending
 
 
 - 
 
 
 3,745 
 
 
 - 
 
 
 - 
 
 
 3,745 
 
 0.8 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (4,812)
 
 
 (4,812)
 
 (0.9)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 - 
 
 
 5,173 
 
 
 - 
 
 
 - 
 
 
 5,173 
 
 1.0 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,402 
 
 
 1,402 
 
 0.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 177,188 
 
$
 267,391 
 
$
 60,465 
 
$
 (3,410)
 
$
 501,634 
 
 100.0 
%


 
284

 
 
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 61,309 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 61,309 
 
 23.2 
%
 
 
International
 
 
 28,900 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 28,900 
 
 10.9 
%
 
 
Real Estate Investment Trusts
 
 
 3,252 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 3,252 
 
 1.2 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 548 
 
 
 - 
 
 
 - 
 
 
 548 
 
 0.2 
%
 
Subtotal - Equities
 
 
 93,461 
 
 
 548 
 
 
 - 
 
 
 - 
 
 
 94,009 
 
 35.5 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 1,456 
 
 
 - 
 
 
 - 
 
 
 1,456 
 
 0.5 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 21,723 
 
 
 - 
 
 
 - 
 
 
 21,723 
 
 8.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 89,863 
 
 
 - 
 
 
 - 
 
 
 89,863 
 
 34.0 
%
 
 
Foreign Debt
 
 
 - 
 
 
 19,305 
 
 
 - 
 
 
 - 
 
 
 19,305 
 
 7.3 
%
 
 
State and Local Government
 
 
 - 
 
 
 1,572 
 
 
 - 
 
 
 - 
 
 
 1,572 
 
 0.6 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 1,870 
 
 
 - 
 
 
 - 
 
 
 1,870 
 
 0.7 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 135,789 
 
 
 - 
 
 
 - 
 
 
 135,789 
 
 51.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 13,380 
 
 
 - 
 
 
 13,380 
 
 5.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 18,513 
 
 
 - 
 
 
 18,513 
 
 7.0 
%
 
Securities Lending
 
 
 - 
 
 
 1,976 
 
 
 - 
 
 
 - 
 
 
 1,976 
 
 0.8 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (2,538)
 
 
 (2,538)
 
 (0.9)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 - 
 
 
 2,729 
 
 
 - 
 
 
 - 
 
 
 2,729 
 
 1.0 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 739 
 
 
 739 
 
 0.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 93,461 
 
$
 141,042 
 
$
 31,893 
 
$
 (1,799)
 
$
 264,597 
 
 100.0 
%


 
285

 
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 64,634 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 64,634 
 
 23.2 
%
 
 
International
 
 
 30,467 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 30,467 
 
 10.9 
%
 
 
Real Estate Investment Trusts
 
 
 3,428 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 3,428 
 
 1.2 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 578 
 
 
 - 
 
 
 - 
 
 
 578 
 
 0.2 
%
 
Subtotal - Equities
 
 
 98,529 
 
 
 578 
 
 
 - 
 
 
 - 
 
 
 99,107 
 
 35.5 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 1,535 
 
 
 - 
 
 
 - 
 
 
 1,535 
 
 0.5 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 22,901 
 
 
 - 
 
 
 - 
 
 
 22,901 
 
 8.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 94,736 
 
 
 - 
 
 
 - 
 
 
 94,736 
 
 34.0 
%
 
 
Foreign Debt
 
 
 - 
 
 
 20,352 
 
 
 - 
 
 
 - 
 
 
 20,352 
 
 7.3 
%
 
 
State and Local Government
 
 
 - 
 
 
 1,657 
 
 
 - 
 
 
 - 
 
 
 1,657 
 
 0.6 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 1,971 
 
 
 - 
 
 
 - 
 
 
 1,971 
 
 0.7 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 143,152 
 
 
 - 
 
 
 - 
 
 
 143,152 
 
 51.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 14,106 
 
 
 - 
 
 
 14,106 
 
 5.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 19,517 
 
 
 - 
 
 
 19,517 
 
 7.0 
%
 
Securities Lending
 
 
 - 
 
 
 2,083 
 
 
 - 
 
 
 - 
 
 
 2,083 
 
 0.8 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (2,676)
 
 
 (2,676)
 
 (0.9)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 - 
 
 
 2,877 
 
 
 - 
 
 
 - 
 
 
 2,877 
 
 1.0 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 780 
 
 
 780 
 
 0.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 98,529 
 
$
 148,690 
 
$
 33,623 
 
$
 (1,896)
 
$
 278,946 
 
 100.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

(a)
Amounts in "Other" column primarily represent an obligation to repay cash collateral received as part of the Securities Lending Program.
(b)
Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.

The following tables set forth a reconciliation of changes in the fair value of assets classified as Level 3 in the fair value hierarchy by Registrant Subsidiary for pension assets:

 
 
 
Real
 
Alternative
 
Total
APCo
 
Estate
 
Investments
 
Level 3
 
 
 
(in thousands)
Balance as of January 1, 2013
 
$
 29,063 
 
$
 25,888 
 
$
 54,951 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 3,861 
 
 
 1,932 
 
 
 5,793 
 
Relating to Assets Sold During the Period
 
 
 - 
 
 
 1,949 
 
 
 1,949 
Purchases and Sales
 
 
 (1,167)
 
 
 14,170 
 
 
 13,003 
Transfers into Level 3
 
 
 - 
 
 
 - 
 
 
 - 
Transfers out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
Balance as of December 31, 2013
 
$
 31,757 
 
$
 43,939 
 
$
 75,696 


 
286

 
 
 
 
 
Real
 
Alternative
 
Total
I&M
 
Estate
 
Investments
 
Level 3
 
 
 
(in thousands)
Balance as of January 1, 2013
 
$
 25,811 
 
$
 22,992 
 
$
 48,803 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 3,531 
 
 
 1,727 
 
 
 5,258 
 
Relating to Assets Sold During the Period
 
 
 - 
 
 
 1,741 
 
 
 1,741 
Purchases and Sales
 
 
 (1,067)
 
 
 12,661 
 
 
 11,594 
Transfers into Level 3
 
 
 - 
 
 
 - 
 
 
 - 
Transfers out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
Balance as of December 31, 2013
 
$
 28,275 
 
$
 39,121 
 
$
 67,396 

 
 
 
Real
 
Alternative
 
Total
OPCo
 
Estate
 
Investments
 
Level 3
 
 
 
(in thousands)
Balance as of January 1, 2013
 
$
 47,464 
 
$
 42,279 
 
$
 89,743 
Transfer of OPCo Generation Plan Assets
 
 
 (26,218)
 
 
 (36,275)
 
 
 (62,493)
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 5,907 
 
 
 3,113 
 
 
 9,020 
 
Relating to Assets Sold During the Period
 
 
 - 
 
 
 3,142 
 
 
 3,142 
Purchases and Sales
 
 
 (1,786)
 
 
 22,839 
 
 
 21,053 
Transfers into Level 3
 
 
 - 
 
 
 - 
 
 
 - 
Transfers out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
Balance as of December 31, 2013
 
$
 25,367 
 
$
 35,098 
 
$
 60,465 

 
 
 
Real
 
Alternative
 
Total
PSO
 
Estate
 
Investments
 
Level 3
 
 
 
(in thousands)
Balance as of January 1, 2013
 
$
 12,382 
 
$
 11,030 
 
$
 23,412 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 1,430 
 
 
 801 
 
 
 2,231 
 
Relating to Assets Sold During the Period
 
 
 - 
 
 
 808 
 
 
 808 
Purchases and Sales
 
 
 (432)
 
 
 5,874 
 
 
 5,442 
Transfers into Level 3
 
 
 - 
 
 
 - 
 
 
 - 
Transfers out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
Balance as of December 31, 2013
 
$
 13,380 
 
$
 18,513 
 
$
 31,893 

 
 
 
Real
 
Alternative
 
Total
SWEPCo
 
Estate
 
Investments
 
Level 3
 
 
 
(in thousands)
Balance as of January 1, 2013
 
$
 13,078 
 
$
 11,649 
 
$
 24,727 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 1,474 
 
 
 841 
 
 
 2,315 
 
Relating to Assets Sold During the Period
 
 
 - 
 
 
 850 
 
 
 850 
Purchases and Sales
 
 
 (446)
 
 
 6,177 
 
 
 5,731 
Transfers into Level 3
 
 
 - 
 
 
 - 
 
 
 - 
Transfers out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
Balance as of December 31, 2013
 
$
 14,106 
 
$
 19,517 
 
$
 33,623 


 
287

 

The following tables present the classification of OPEB plan assets within the fair value hierarchy by Registrant Subsidiary as of December 31, 2013:

 
APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 79,369 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 79,369 
 
 27.9 
%
 
 
International
 
 
 103,188 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 103,188 
 
 36.2 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Global
 
 
 - 
 
 
 2,463 
 
 
 - 
 
 
 - 
 
 
 2,463 
 
 0.9 
%
 
Subtotal - Equities
 
 
 182,557 
 
 
 2,463 
 
 
 - 
 
 
 - 
 
 
 185,020 
 
 65.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 14,737 
 
 
 - 
 
 
 - 
 
 
 14,737 
 
 5.2 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 9,476 
 
 
 - 
 
 
 - 
 
 
 9,476 
 
 3.3 
%
 
 
Corporate Debt
 
 
 - 
 
 
 18,458 
 
 
 - 
 
 
 - 
 
 
 18,458 
 
 6.5 
%
 
 
Foreign Debt
 
 
 - 
 
 
 3,605 
 
 
 - 
 
 
 - 
 
 
 3,605 
 
 1.2 
%
 
 
State and Local Government
 
 
 - 
 
 
 776 
 
 
 - 
 
 
 - 
 
 
 776 
 
 0.3 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 1,362 
 
 
 - 
 
 
 - 
 
 
 1,362 
 
 0.5 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 48,414 
 
 
 - 
 
 
 - 
 
 
 48,414 
 
 17.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 2,219 
 
 
 - 
 
 
 - 
 
 
 2,219 
 
 0.8 
%
 
 
United States Bonds
 
 
 - 
 
 
 35,470 
 
 
 - 
 
 
 - 
 
 
 35,470 
 
 12.4 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 11,441 
 
 
 1,470 
 
 
 - 
 
 
 - 
 
 
 12,911 
 
 4.5 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 806 
 
 
 806 
 
 0.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 193,998 
 
$
 90,036 
 
$
 - 
 
$
 806 
 
$
 284,840 
 
 100.0 
%
 
 
 
288

 
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 57,460 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 57,460 
 
 27.9 
%
 
 
International
 
 
 74,705 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 74,705 
 
 36.2 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Global
 
 
 - 
 
 
 1,783 
 
 
 - 
 
 
 - 
 
 
 1,783 
 
 0.9 
%
 
Subtotal - Equities
 
 
 132,165 
 
 
 1,783 
 
 
 - 
 
 
 - 
 
 
 133,948 
 
 65.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 10,669 
 
 
 - 
 
 
 - 
 
 
 10,669 
 
 5.2 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 6,860 
 
 
 - 
 
 
 - 
 
 
 6,860 
 
 3.3 
%
 
 
Corporate Debt
 
 
 - 
 
 
 13,363 
 
 
 - 
 
 
 - 
 
 
 13,363 
 
 6.5 
%
 
 
Foreign Debt
 
 
 - 
 
 
 2,610 
 
 
 - 
 
 
 - 
 
 
 2,610 
 
 1.2 
%
 
 
State and Local Government
 
 
 - 
 
 
 562 
 
 
 - 
 
 
 - 
 
 
 562 
 
 0.3 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 986 
 
 
 - 
 
 
 - 
 
 
 986 
 
 0.5 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 35,050 
 
 
 - 
 
 
 - 
 
 
 35,050 
 
 17.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 1,607 
 
 
 - 
 
 
 - 
 
 
 1,607 
 
 0.8 
%
 
 
United States Bonds
 
 
 - 
 
 
 25,679 
 
 
 - 
 
 
 - 
 
 
 25,679 
 
 12.4 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 8,283 
 
 
 1,064 
 
 
 - 
 
 
 - 
 
 
 9,347 
 
 4.5 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 583 
 
 
 583 
 
 0.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 140,448 
 
$
 65,183 
 
$
 - 
 
$
 583 
 
$
 206,214 
 
 100.0 
%
 

 
 
289

 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 59,069 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 59,069 
 
 27.9 
%
 
 
International
 
 
 76,799 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 76,799 
 
 36.2 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Global
 
 
 - 
 
 
 1,833 
 
 
 - 
 
 
 - 
 
 
 1,833 
 
 0.9 
%
 
Subtotal - Equities
 
 
 135,868 
 
 
 1,833 
 
 
 - 
 
 
 - 
 
 
 137,701 
 
 65.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 10,968 
 
 
 - 
 
 
 - 
 
 
 10,968 
 
 5.2 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 7,053 
 
 
 - 
 
 
 - 
 
 
 7,053 
 
 3.3 
%
 
 
Corporate Debt
 
 
 - 
 
 
 13,738 
 
 
 - 
 
 
 - 
 
 
 13,738 
 
 6.5 
%
 
 
Foreign Debt
 
 
 - 
 
 
 2,683 
 
 
 - 
 
 
 - 
 
 
 2,683 
 
 1.2 
%
 
 
State and Local Government
 
 
 - 
 
 
 577 
 
 
 - 
 
 
 - 
 
 
 577 
 
 0.3 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 1,014 
 
 
 - 
 
 
 - 
 
 
 1,014 
 
 0.5 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 36,033 
 
 
 - 
 
 
 - 
 
 
 36,033 
 
 17.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 1,652 
 
 
 - 
 
 
 - 
 
 
 1,652 
 
 0.8 
%
 
 
United States Bonds
 
 
 - 
 
 
 26,399 
 
 
 - 
 
 
 - 
 
 
 26,399 
 
 12.4 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 8,515 
 
 
 1,094 
 
 
 - 
 
 
 - 
 
 
 9,609 
 
 4.5 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 600 
 
 
 600 
 
 0.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 144,383 
 
$
 67,011 
 
$
 - 
 
$
 600 
 
$
 211,994 
 
 100.0 
%
 
 
 
290

 

 
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 26,842 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 26,842 
 
 27.9 
%
 
 
International
 
 
 34,898 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 34,898 
 
 36.2 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Global
 
 
 - 
 
 
 833 
 
 
 - 
 
 
 - 
 
 
 833 
 
 0.9 
%
 
Subtotal - Equities
 
 
 61,740 
 
 
 833 
 
 
 - 
 
 
 - 
 
 
 62,573 
 
 65.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 4,984 
 
 
 - 
 
 
 - 
 
 
 4,984 
 
 5.2 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 3,205 
 
 
 - 
 
 
 - 
 
 
 3,205 
 
 3.3 
%
 
 
Corporate Debt
 
 
 - 
 
 
 6,243 
 
 
 - 
 
 
 - 
 
 
 6,243 
 
 6.5 
%
 
 
Foreign Debt
 
 
 - 
 
 
 1,219 
 
 
 - 
 
 
 - 
 
 
 1,219 
 
 1.2 
%
 
 
State and Local Government
 
 
 - 
 
 
 262 
 
 
 - 
 
 
 - 
 
 
 262 
 
 0.3 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 461 
 
 
 - 
 
 
 - 
 
 
 461 
 
 0.5 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 16,374 
 
 
 - 
 
 
 - 
 
 
 16,374 
 
 17.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 751 
 
 
 - 
 
 
 - 
 
 
 751 
 
 0.8 
%
 
 
United States Bonds
 
 
 - 
 
 
 11,996 
 
 
 - 
 
 
 - 
 
 
 11,996 
 
 12.4 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 3,869 
 
 
 497 
 
 
 - 
 
 
 - 
 
 
 4,366 
 
 4.5 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 273 
 
 
 273 
 
 0.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 65,609 
 
$
 30,451 
 
$
 - 
 
$
 273 
 
$
 96,333 
 
 100.0 
%


 
291

 
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 30,022 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 30,022 
 
 27.9 
%
 
 
International
 
 
 39,034 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 39,034 
 
 36.2 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Global
 
 
 - 
 
 
 932 
 
 
 - 
 
 
 - 
 
 
 932 
 
 0.9 
%
 
Subtotal - Equities
 
 
 69,056 
 
 
 932 
 
 
 - 
 
 
 - 
 
 
 69,988 
 
 65.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 5,575 
 
 
 - 
 
 
 - 
 
 
 5,575 
 
 5.2 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 3,585 
 
 
 - 
 
 
 - 
 
 
 3,585 
 
 3.3 
%
 
 
Corporate Debt
 
 
 - 
 
 
 6,982 
 
 
 - 
 
 
 - 
 
 
 6,982 
 
 6.5 
%
 
 
Foreign Debt
 
 
 - 
 
 
 1,364 
 
 
 - 
 
 
 - 
 
 
 1,364 
 
 1.2 
%
 
 
State and Local Government
 
 
 - 
 
 
 294 
 
 
 - 
 
 
 - 
 
 
 294 
 
 0.3 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 515 
 
 
 - 
 
 
 - 
 
 
 515 
 
 0.5 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 18,315 
 
 
 - 
 
 
 - 
 
 
 18,315 
 
 17.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 840 
 
 
 - 
 
 
 - 
 
 
 840 
 
 0.8 
%
 
 
United States Bonds
 
 
 - 
 
 
 13,418 
 
 
 - 
 
 
 - 
 
 
 13,418 
 
 12.4 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 4,328 
 
 
 556 
 
 
 - 
 
 
 - 
 
 
 4,884 
 
 4.5 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 305 
 
 
 305 
 
 0.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 73,384 
 
$
 34,061 
 
$
 - 
 
$
 305 
 
$
 107,750 
 
 100.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

(a)
Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.


 
292

 


The following tables present the classification of pension plan assets within the fair value hierarchy by Registrant Subsidiary as of December 31, 2012:

 
APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 173,149 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 173,149 
 
 27.9 
%
 
 
International
 
 
 65,757 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 65,757 
 
 10.5 
%
 
 
Real Estate Investment Trusts
 
 
 11,986 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 11,986 
 
 1.9 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 574 
 
 
 - 
 
 
 - 
 
 
 574 
 
 0.1 
%
 
Subtotal - Equities
 
 
 250,892 
 
 
 574 
 
 
 - 
 
 
 - 
 
 
 251,466 
 
 40.4 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 4,200 
 
 
 - 
 
 
 - 
 
 
 4,200 
 
 0.7 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 94,682 
 
 
 - 
 
 
 - 
 
 
 94,682 
 
 15.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 163,484 
 
 
 - 
 
 
 - 
 
 
 163,484 
 
 26.3 
%
 
 
Foreign Debt
 
 
 - 
 
 
 26,292 
 
 
 - 
 
 
 - 
 
 
 26,292 
 
 4.2 
%
 
 
State and Local Government
 
 
 - 
 
 
 5,821 
 
 
 - 
 
 
 - 
 
 
 5,821 
 
 0.9 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 4,714 
 
 
 - 
 
 
 - 
 
 
 4,714 
 
 0.8 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 299,193 
 
 
 - 
 
 
 - 
 
 
 299,193 
 
 48.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 29,063 
 
 
 - 
 
 
 29,063 
 
 4.7 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 25,888 
 
 
 - 
 
 
 25,888 
 
 4.2 
%
 
Securities Lending
 
 
 - 
 
 
 10,633 
 
 
 - 
 
 
 - 
 
 
 10,633 
 
 1.7 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (12,025)
 
 
 (12,025)
 
 (1.9)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 - 
 
 
 16,646 
 
 
 - 
 
 
 - 
 
 
 16,646 
 
 2.7 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 706 
 
 
 706 
 
 0.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 250,892 
 
$
 327,046 
 
$
 54,951 
 
$
 (11,319)
 
$
 621,570 
 
 100.0 
%


 
293

 
 
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 153,776 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 153,776 
 
 27.9 
%
 
 
International
 
 
 58,400 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 58,400 
 
 10.5 
%
 
 
Real Estate Investment Trusts
 
 
 10,645 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 10,645 
 
 1.9 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 510 
 
 
 - 
 
 
 - 
 
 
 510 
 
 0.1 
%
 
Subtotal - Equities
 
 
 222,821 
 
 
 510 
 
 
 - 
 
 
 - 
 
 
 223,331 
 
 40.4 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 3,730 
 
 
 - 
 
 
 - 
 
 
 3,730 
 
 0.7 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 84,089 
 
 
 - 
 
 
 - 
 
 
 84,089 
 
 15.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 145,193 
 
 
 - 
 
 
 - 
 
 
 145,193 
 
 26.3 
%
 
 
Foreign Debt
 
 
 - 
 
 
 23,350 
 
 
 - 
 
 
 - 
 
 
 23,350 
 
 4.2 
%
 
 
State and Local Government
 
 
 - 
 
 
 5,170 
 
 
 - 
 
 
 - 
 
 
 5,170 
 
 0.9 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 4,187 
 
 
 - 
 
 
 - 
 
 
 4,187 
 
 0.8 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 265,719 
 
 
 - 
 
 
 - 
 
 
 265,719 
 
 48.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 25,811 
 
 
 - 
 
 
 25,811 
 
 4.7 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 22,992 
 
 
 - 
 
 
 22,992 
 
 4.2 
%
 
Securities Lending
 
 
 - 
 
 
 9,443 
 
 
 - 
 
 
 - 
 
 
 9,443 
 
 1.7 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (10,680)
 
 
 (10,680)
 
 (1.9)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 - 
 
 
 14,783 
 
 
 - 
 
 
 - 
 
 
 14,783 
 
 2.7 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 627 
 
 
 627 
 
 0.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 222,821 
 
$
 290,455 
 
$
 48,803 
 
$
 (10,053)
 
$
 552,026 
 
 100.0 
%


 
294

 
 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 282,777 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 282,777 
 
 27.9 
%
 
 
International
 
 
 107,391 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 107,391 
 
 10.5 
%
 
 
Real Estate Investment Trusts
 
 
 19,576 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 19,576 
 
 1.9 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 938 
 
 
 - 
 
 
 - 
 
 
 938 
 
 0.1 
%
 
Subtotal - Equities
 
 
 409,744 
 
 
 938 
 
 
 - 
 
 
 - 
 
 
 410,682 
 
 40.4 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 6,858 
 
 
 - 
 
 
 - 
 
 
 6,858 
 
 0.7 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 154,630 
 
 
 - 
 
 
 - 
 
 
 154,630 
 
 15.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 266,994 
 
 
 - 
 
 
 - 
 
 
 266,994 
 
 26.3 
%
 
 
Foreign Debt
 
 
 - 
 
 
 42,938 
 
 
 - 
 
 
 - 
 
 
 42,938 
 
 4.2 
%
 
 
State and Local Government
 
 
 - 
 
 
 9,506 
 
 
 - 
 
 
 - 
 
 
 9,506 
 
 0.9 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 7,699 
 
 
 - 
 
 
 - 
 
 
 7,699 
 
 0.8 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 488,625 
 
 
 - 
 
 
 - 
 
 
 488,625 
 
 48.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 47,464 
 
 
 - 
 
 
 47,464 
 
 4.7 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 42,279 
 
 
 - 
 
 
 42,279 
 
 4.2 
%
 
Securities Lending
 
 
 - 
 
 
 17,365 
 
 
 - 
 
 
 - 
 
 
 17,365 
 
 1.7 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (19,639)
 
 
 (19,639)
 
 (1.9)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 - 
 
 
 27,185 
 
 
 - 
 
 
 - 
 
 
 27,185 
 
 2.7 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,154 
 
 
 1,154 
 
 0.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 409,744 
 
$
 534,113 
 
$
 89,743 
 
$
 (18,485)
 
$
 1,015,115 
 
 100.0 
%


 
295

 
 
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 73,770 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 73,770 
 
 27.9 
%
 
 
International
 
 
 28,016 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 28,016 
 
 10.5 
%
 
 
Real Estate Investment Trusts
 
 
 5,107 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 5,107 
 
 1.9 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 245 
 
 
 - 
 
 
 - 
 
 
 245 
 
 0.1 
%
 
Subtotal - Equities
 
 
 106,893 
 
 
 245 
 
 
 - 
 
 
 - 
 
 
 107,138 
 
 40.4 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 1,789 
 
 
 - 
 
 
 - 
 
 
 1,789 
 
 0.7 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 40,340 
 
 
 - 
 
 
 - 
 
 
 40,340 
 
 15.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 69,653 
 
 
 - 
 
 
 - 
 
 
 69,653 
 
 26.3 
%
 
 
Foreign Debt
 
 
 - 
 
 
 11,202 
 
 
 - 
 
 
 - 
 
 
 11,202 
 
 4.2 
%
 
 
State and Local Government
 
 
 - 
 
 
 2,480 
 
 
 - 
 
 
 - 
 
 
 2,480 
 
 0.9 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 2,009 
 
 
 - 
 
 
 - 
 
 
 2,009 
 
 0.8 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 127,473 
 
 
 - 
 
 
 - 
 
 
 127,473 
 
 48.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 12,382 
 
 
 - 
 
 
 12,382 
 
 4.7 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 11,030 
 
 
 - 
 
 
 11,030 
 
 4.2 
%
 
Securities Lending
 
 
 - 
 
 
 4,530 
 
 
 - 
 
 
 - 
 
 
 4,530 
 
 1.7 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (5,123)
 
 
 (5,123)
 
 (1.9)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 - 
 
 
 7,092 
 
 
 - 
 
 
 - 
 
 
 7,092 
 
 2.7 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 301 
 
 
 301 
 
 0.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 106,893 
 
$
 139,340 
 
$
 23,412 
 
$
 (4,822)
 
$
 264,823 
 
 100.0 
%


 
296

 
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 77,915 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 77,915 
 
 27.9 
%
 
 
International
 
 
 29,590 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 29,590 
 
 10.5 
%
 
 
Real Estate Investment Trusts
 
 
 5,394 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 5,394 
 
 1.9 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 258 
 
 
 - 
 
 
 - 
 
 
 258 
 
 0.1 
%
 
Subtotal - Equities
 
 
 112,899 
 
 
 258 
 
 
 - 
 
 
 - 
 
 
 113,157 
 
 40.4 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 1,890 
 
 
 - 
 
 
 - 
 
 
 1,890 
 
 0.7 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 42,606 
 
 
 - 
 
 
 - 
 
 
 42,606 
 
 15.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 73,566 
 
 
 - 
 
 
 - 
 
 
 73,566 
 
 26.3 
%
 
 
Foreign Debt
 
 
 - 
 
 
 11,831 
 
 
 - 
 
 
 - 
 
 
 11,831 
 
 4.2 
%
 
 
State and Local Government
 
 
 - 
 
 
 2,619 
 
 
 - 
 
 
 - 
 
 
 2,619 
 
 0.9 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 2,121 
 
 
 - 
 
 
 - 
 
 
 2,121 
 
 0.8 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 134,633 
 
 
 - 
 
 
 - 
 
 
 134,633 
 
 48.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 13,078 
 
 
 - 
 
 
 13,078 
 
 4.7 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 11,649 
 
 
 - 
 
 
 11,649 
 
 4.2 
%
 
Securities Lending
 
 
 - 
 
 
 4,785 
 
 
 - 
 
 
 - 
 
 
 4,785 
 
 1.7 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (5,411)
 
 
 (5,411)
 
 (1.9)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 - 
 
 
 7,490 
 
 
 - 
 
 
 - 
 
 
 7,490 
 
 2.7 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 318 
 
 
 318 
 
 0.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 112,899 
 
$
 147,166 
 
$
 24,727 
 
$
 (5,093)
 
$
 279,699 
 
 100.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

(a)
Amounts in "Other" column primarily represent an obligation to repay cash collateral received as part of the Securities Lending Program.
(b)
Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.

The following tables set forth a reconciliation of changes in the fair value of assets classified as Level 3 in the fair value hierarchy for pension assets by Registrant Subsidiary:

 
 
 
Corporate
 
Real
 
Alternative
 
Total
APCo
 
Debt
 
Estate
 
Investments
 
Level 3
 
 
 
(in thousands)
Balance as of January 1, 2012
 
$
 846 
 
$
 21,666 
 
$
 21,269 
 
$
 43,781 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 - 
 
 
 3,913 
 
 
 1,319 
 
 
 5,232 
 
Relating to Assets Sold During the Period
 
 
 (298)
 
 
 - 
 
 
 640 
 
 
 342 
Purchases and Sales
 
 
 (548)
 
 
 3,484 
 
 
 2,660 
 
 
 5,596 
Transfers into Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Transfers out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Balance as of December 31, 2012
 
$
 - 
 
$
 29,063 
 
$
 25,888 
 
$
 54,951 


 
297

 
 
 
 
 
Corporate
 
Real
 
Alternative
 
Total
I&M
 
Debt
 
Estate
 
Investments
 
Level 3
 
 
 
(in thousands)
Balance as of January 1, 2012
 
$
 747 
 
$
 19,129 
 
$
 18,779 
 
$
 38,655 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 - 
 
 
 3,535 
 
 
 1,203 
 
 
 4,738 
 
Relating to Assets Sold During the Period
 
 
 (263)
 
 
 - 
 
 
 584 
 
 
 321 
Purchases and Sales
 
 
 (484)
 
 
 3,147 
 
 
 2,426 
 
 
 5,089 
Transfers into Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Transfers out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Balance as of December 31, 2012
 
$
 - 
 
$
 25,811 
 
$
 22,992 
 
$
 48,803 

 
 
 
Corporate
 
Real
 
Alternative
 
Total
OPCo
 
Debt
 
Estate
 
Investments
 
Level 3
 
 
 
(in thousands)
Balance as of January 1, 2012
 
$
 1,372 
 
$
 35,148 
 
$
 34,505 
 
$
 71,025 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 - 
 
 
 6,515 
 
 
 2,220 
 
 
 8,735 
 
Relating to Assets Sold During the Period
 
 
 (483)
 
 
 - 
 
 
 1,077 
 
 
 594 
Purchases and Sales
 
 
 (889)
 
 
 5,801 
 
 
 4,477 
 
 
 9,389 
Transfers into Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Transfers out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Balance as of December 31, 2012
 
$
 - 
 
$
 47,464 
 
$
 42,279 
 
$
 89,743 

 
 
 
Corporate
 
Real
 
Alternative
 
Total
PSO
 
Debt
 
Estate
 
Investments
 
Level 3
 
 
 
(in thousands)
Balance as of January 1, 2012
 
$
 364 
 
$
 9,329 
 
$
 9,159 
 
$
 18,852 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 - 
 
 
 1,615 
 
 
 534 
 
 
 2,149 
 
Relating to Assets Sold During the Period
 
 
 (128)
 
 
 - 
 
 
 259 
 
 
 131 
Purchases and Sales
 
 
 (236)
 
 
 1,438 
 
 
 1,078 
 
 
 2,280 
Transfers into Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Transfers out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Balance as of December 31, 2012
 
$
 - 
 
$
 12,382 
 
$
 11,030 
 
$
 23,412 

 
 
 
Corporate
 
Real
 
Alternative
 
Total
SWEPCo
 
Debt
 
Estate
 
Investments
 
Level 3
 
 
 
(in thousands)
Balance as of January 1, 2012
 
$
 379 
 
$
 9,712 
 
$
 9,535 
 
$
 19,626 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 - 
 
 
 1,780 
 
 
 603 
 
 
 2,383 
 
Relating to Assets Sold During the Period
 
 
 (134)
 
 
 - 
 
 
 293 
 
 
 159 
Purchases and Sales
 
 
 (245)
 
 
 1,586 
 
 
 1,218 
 
 
 2,559 
Transfers into Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Transfers out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Balance as of December 31, 2012
 
$
 - 
 
$
 13,078 
 
$
 11,649 
 
$
 24,727 


 
298

 

The following tables present the classification of OPEB plan assets within the fair value hierarchy by Registrant Subsidiary as of December 31, 2012:

APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
(in thousands)
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 72,063 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 72,063 
 
 26.9 
%
 
International
 
 
 86,158 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 86,158 
 
 32.2 
%
Subtotal - Equities
 
 
 158,221 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 158,221 
 
 59.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 12,388 
 
 
 - 
 
 
 - 
 
 
 12,388 
 
 4.6 
%
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 14,036 
 
 
 - 
 
 
 - 
 
 
 14,036 
 
 5.2 
%
 
Corporate Debt
 
 
 - 
 
 
 26,437 
 
 
 - 
 
 
 - 
 
 
 26,437 
 
 9.9 
%
 
Foreign Debt
 
 
 - 
 
 
 4,469 
 
 
 - 
 
 
 - 
 
 
 4,469 
 
 1.7 
%
 
State and Local Government
 
 
 - 
 
 
 1,242 
 
 
 - 
 
 
 - 
 
 
 1,242 
 
 0.5 
%
 
Other - Asset Backed
 
 
 - 
 
 
 1,678 
 
 
 - 
 
 
 - 
 
 
 1,678 
 
 0.6 
%
Subtotal - Fixed Income
 
 
 - 
 
 
 60,250 
 
 
 - 
 
 
 - 
 
 
 60,250 
 
 22.5 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 8,800 
 
 
 - 
 
 
 - 
 
 
 8,800 
 
 3.3 
%
 
United States Bonds
 
 
 - 
 
 
 27,762 
 
 
 - 
 
 
 - 
 
 
 27,762 
 
 10.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 10,598 
 
 
 1,947 
 
 
 - 
 
 
 - 
 
 
 12,545 
 
 4.7 
%
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 180 
 
 
 180 
 
 0.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 168,819 
 
$
 98,759 
 
$
 - 
 
$
 180 
 
$
 267,758 
 
 100.0 
%
 
 
 
299

 
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 52,245 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 52,245 
 
 26.9 
%
 
 
International
 
 
 62,466 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 62,466 
 
 32.2 
%
 
Subtotal - Equities
 
 
 114,711 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 114,711 
 
 59.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 8,982 
 
 
 - 
 
 
 - 
 
 
 8,982 
 
 4.6 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 10,176 
 
 
 - 
 
 
 - 
 
 
 10,176 
 
 5.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 19,167 
 
 
 - 
 
 
 - 
 
 
 19,167 
 
 9.9 
%
 
 
Foreign Debt
 
 
 - 
 
 
 3,240 
 
 
 - 
 
 
 - 
 
 
 3,240 
 
 1.7 
%
 
 
State and Local Government
 
 
 - 
 
 
 901 
 
 
 - 
 
 
 - 
 
 
 901 
 
 0.5 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 1,217 
 
 
 - 
 
 
 - 
 
 
 1,217 
 
 0.6 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 43,683 
 
 
 - 
 
 
 - 
 
 
 43,683 
 
 22.5 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 6,380 
 
 
 - 
 
 
 - 
 
 
 6,380 
 
 3.3 
%
 
 
United States Bonds
 
 
 - 
 
 
 20,128 
 
 
 - 
 
 
 - 
 
 
 20,128 
 
 10.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 7,684 
 
 
 1,412 
 
 
 - 
 
 
 - 
 
 
 9,096 
 
 4.7 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 130 
 
 
 130 
 
 0.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 122,395 
 
$
 71,603 
 
$
 - 
 
$
 130 
 
$
 194,128 
 
 100.0 
%
 
 
 
300

 

 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 98,583 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 98,583 
 
 26.9 
%
 
 
International
 
 
 117,867 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 117,867 
 
 32.2 
%
 
Subtotal - Equities
 
 
 216,450 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 216,450 
 
 59.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 16,947 
 
 
 - 
 
 
 - 
 
 
 16,947 
 
 4.6 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 19,202 
 
 
 - 
 
 
 - 
 
 
 19,202 
 
 5.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 36,166 
 
 
 - 
 
 
 - 
 
 
 36,166 
 
 9.9 
%
 
 
Foreign Debt
 
 
 - 
 
 
 6,113 
 
 
 - 
 
 
 - 
 
 
 6,113 
 
 1.7 
%
 
 
State and Local Government
 
 
 - 
 
 
 1,700 
 
 
 - 
 
 
 - 
 
 
 1,700 
 
 0.5 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 2,296 
 
 
 - 
 
 
 - 
 
 
 2,296 
 
 0.6 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 82,424 
 
 
 - 
 
 
 - 
 
 
 82,424 
 
 22.5 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 12,038 
 
 
 - 
 
 
 - 
 
 
 12,038 
 
 3.3 
%
 
 
United States Bonds
 
 
 - 
 
 
 37,980 
 
 
 - 
 
 
 - 
 
 
 37,980 
 
 10.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 14,499 
 
 
 2,664 
 
 
 - 
 
 
 - 
 
 
 17,163 
 
 4.7 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 246 
 
 
 246 
 
 0.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 230,949 
 
$
 135,106 
 
$
 - 
 
$
 246 
 
$
 366,301 
 
 100.0 
%

 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 24,362 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 24,362 
 
 26.9 
%
 
 
International
 
 
 29,128 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 29,128 
 
 32.2 
%
 
Subtotal - Equities
 
 
 53,490 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 53,490 
 
 59.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 4,188 
 
 
 - 
 
 
 - 
 
 
 4,188 
 
 4.6 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 4,745 
 
 
 - 
 
 
 - 
 
 
 4,745 
 
 5.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 8,937 
 
 
 - 
 
 
 - 
 
 
 8,937 
 
 9.9 
%
 
 
Foreign Debt
 
 
 - 
 
 
 1,511 
 
 
 - 
 
 
 - 
 
 
 1,511 
 
 1.7 
%
 
 
State and Local Government
 
 
 - 
 
 
 420 
 
 
 - 
 
 
 - 
 
 
 420 
 
 0.5 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 567 
 
 
 - 
 
 
 - 
 
 
 567 
 
 0.6 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 20,368 
 
 
 - 
 
 
 - 
 
 
 20,368 
 
 22.5 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 2,975 
 
 
 - 
 
 
 - 
 
 
 2,975 
 
 3.3 
%
 
 
United States Bonds
 
 
 - 
 
 
 9,386 
 
 
 - 
 
 
 - 
 
 
 9,386 
 
 10.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 3,583 
 
 
 658 
 
 
 - 
 
 
 - 
 
 
 4,241 
 
 4.7 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 61 
 
 
 61 
 
 0.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 57,073 
 
$
 33,387 
 
$
 - 
 
$
 61 
 
$
 90,521 
 
 100.0 
%
 
 
 
301

 

 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 26,874 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 26,874 
 
 26.9 
%
 
 
International
 
 
 32,128 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 32,128 
 
 32.2 
%
 
Subtotal - Equities
 
 
 59,002 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 59,002 
 
 59.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 4,619 
 
 
 - 
 
 
 - 
 
 
 4,619 
 
 4.6 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 5,234 
 
 
 - 
 
 
 - 
 
 
 5,234 
 
 5.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 9,858 
 
 
 - 
 
 
 - 
 
 
 9,858 
 
 9.9 
%
 
 
Foreign Debt
 
 
 - 
 
 
 1,666 
 
 
 - 
 
 
 - 
 
 
 1,666 
 
 1.7 
%
 
 
State and Local Government
 
 
 - 
 
 
 463 
 
 
 - 
 
 
 - 
 
 
 463 
 
 0.5 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 626 
 
 
 - 
 
 
 - 
 
 
 626 
 
 0.6 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 22,466 
 
 
 - 
 
 
 - 
 
 
 22,466 
 
 22.5 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 3,281 
 
 
 - 
 
 
 - 
 
 
 3,281 
 
 3.3 
%
 
 
United States Bonds
 
 
 - 
 
 
 10,352 
 
 
 - 
 
 
 - 
 
 
 10,352 
 
 10.3 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
 
 
 3,952 
 
 
 726 
 
 
 - 
 
 
 - 
 
 
 4,678 
 
 4.7 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 67 
 
 
 67 
 
 0.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 62,954 
 
$
 36,825 
 
$
 - 
 
$
 67 
 
$
 99,846 
 
 100.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

(a)
Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.

Determination of Pension Expense

The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility.  This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return.

The accumulated benefit obligation for the pension plans is as follows:

Accumulated Benefit Obligation
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Qualified Pension Plan
 
$
 653,968 
 
$
 560,443 
 
$
 512,798 
 
$
 248,472 
 
$
 256,083 
Nonqualified Pension Plans
 
 
 200 
 
 
 326 
 
 
 6 
 
 
 1,387 
 
 
 1,115 
Total as of December 31, 2013
 
$
 654,168 
 
$
 560,769 
 
$
 512,804 
 
$
 249,859 
 
$
 257,198 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated Benefit Obligation
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Qualified Pension Plan
 
$
 708,476 
 
$
 603,448 
 
$
 1,048,796 
 
$
 269,738 
 
$
 273,860 
Nonqualified Pension Plans
 
 
 191 
 
 
 200 
 
 
 796 
 
 
 1,287 
 
 
 1,098 
Total as of December 31, 2012
 
$
 708,667 
 
$
 603,648 
 
$
 1,049,592 
 
$
 271,025 
 
$
 274,958 


 
302

 
 
For the underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans as of December 31, 2013 and 2012 were as follows:

 
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Projected Benefit Obligation
$
 663,231 
 
$
 574,699 
 
$
 523,643 
 
$
 1,394 
 
$
 1,124 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated Benefit Obligation
 
$
 654,168 
 
$
 560,769 
 
$
 512,804 
 
$
 1,387 
 
$
 1,115 
Fair Value of Plan Assets
 
 
 627,995 
 
 
 559,143 
 
 
 501,634 
 
 
 - 
 
 
 - 
Underfunded Accumulated Benefit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Obligation as of December 31, 2013
 
$
 (26,173)
 
$
 (1,626)
 
$
 (11,170)
 
$
 (1,387)
 
$
 (1,115)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Projected Benefit Obligation
$
 718,460 
 
$
 618,973 
 
$
 1,068,186 
 
$
 279,685 
 
$
 1,098 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated Benefit Obligation
 
$
 708,667 
 
$
 603,648 
 
$
 1,049,592 
 
$
 271,025 
 
$
 1,098 
Fair Value of Plan Assets
 
 
 621,570 
 
 
 552,026 
 
 
 1,015,115 
 
 
 264,823 
 
 
 - 
Underfunded Accumulated Benefit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Obligation as of December 31, 2012
 
$
 (87,097)
 
$
 (51,622)
 
$
 (34,477)
 
$
 (6,202)
 
$
 (1,098)

Estimated Future Benefit Payments and Contributions

The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded nonqualified benefits.  For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan.   For OPEB plans, expected payments include the payment of unfunded benefits.  The following table provides the estimated contributions and payments by Registrant Subsidiary for 2014:

 
 
 
 
Other Postretirement
Company
 
Pension Plans
 
Benefit Plans
 
 
(in thousands)
APCo
 
$
 12,231 
 
$
 3,222 
I&M
 
 
 7,339 
 
 
 - 
OPCo
 
 
 8,717 
 
 
 - 
PSO
 
 
 3,530 
 
 
 - 
SWEPCo
 
 
 1,296 
 
 
 - 


 
303

 


The tables below reflect the total benefits expected to be paid from the plan or from the Registrant Subsidiary’s assets.  The payments include the participants’ contributions to the plan for their share of the cost.  In November 2012, changes to the retiree medical coverage were announced.  Effective for retirements after December 2012, contributions to retiree medical coverage were capped reducing exposure to future medical cost inflation.  Effective for employees hired after December 2013, retiree medical coverage will not be provided.  The impact of the changes is reflected in the Benefit Plan Obligation tables as plan amendments.  Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results.  The estimated payments for the pension benefits and OPEB are as follows:

Pension Plans
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
2014 
 
$
 48,130 
 
$
 37,708 
 
$
 40,701 
 
$
 22,353 
 
$
 23,013 
2015 
 
 
 48,537 
 
 
 38,835 
 
 
 40,772 
 
 
 22,786 
 
 
 23,830 
2016 
 
 
 49,024 
 
 
 39,293 
 
 
 40,857 
 
 
 23,234 
 
 
 23,751 
2017 
 
 
 49,432 
 
 
 40,929 
 
 
 40,655 
 
 
 22,859 
 
 
 23,929 
2018 
 
 
 50,990 
 
 
 41,453 
 
 
 40,225 
 
 
 23,705 
 
 
 24,658 
Years 2019 to 2023, in Total
 
 
 248,890 
 
 
 218,392 
 
 
 196,692 
 
 
 108,884 
 
 
 116,545 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement Benefit Plans:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Benefit Payments
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
2014 
 
$
 26,823 
 
$
 16,665 
 
$
 18,026 
 
$
 7,737 
 
$
 8,343 
2015 
 
 
 27,438 
 
 
 17,533 
 
 
 18,368 
 
 
 8,114 
 
 
 8,709 
2016 
 
 
 27,976 
 
 
 18,350 
 
 
 18,622 
 
 
 8,380 
 
 
 9,098 
2017 
 
 
 28,234 
 
 
 18,794 
 
 
 18,708 
 
 
 8,522 
 
 
 9,417 
2018 
 
 
 28,884 
 
 
 19,124 
 
 
 18,957 
 
 
 8,609 
 
 
 9,718 
Years 2019 to 2023, in Total
 
 
 144,245 
 
 
 101,425 
 
 
 95,926 
 
 
 45,916 
 
 
 52,406 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement Benefit Plans:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Medicare Subsidy Receipts
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
2014 
 
$
 252 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 - 
2015 
 
 
 260 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
2016 
 
 
 268 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
2017 
 
 
 271 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
2018 
 
 
 272 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Years 2019 to 2023, in Total
 
 
 1,378 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 


 
304

 

Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the years ended December 31, 2013, 2012 and 2011:

 
 
 
 
 
Other Postretirement
APCo
 
Pension Plans
 
Benefit Plans
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
 
2013 
 
2012 
 
2011 
 
 
 
(in thousands)
Service Cost
 
$
 6,171 
 
$
 7,565 
 
$
 7,199 
 
$
 2,566 
 
$
 5,387 
 
$
 4,983 
Interest Cost
 
 
 27,662 
 
 
 30,211 
 
 
 32,293 
 
 
 13,454 
 
 
 18,462 
 
 
 19,468 
Expected Return on Plan Assets
 
 
 (37,041)
 
 
 (41,944)
 
 
 (41,833)
 
 
 (18,147)
 
 
 (16,753)
 
 
 (17,985)
Amortization of Transition Obligation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 780 
 
 
 1,167 
Amortization of Prior Service Cost (Credit)
 
 
 198 
 
 
 475 
 
 
 917 
 
 
 (10,050)
 
 
 (2,862)
 
 
 (171)
Amortization of Net Actuarial Loss
 
 
 25,025 
 
 
 20,339 
 
 
 16,570 
 
 
 12,249 
 
 
 10,526 
 
 
 5,839 
Net Periodic Benefit Cost
 
 
 22,015 
 
 
 16,646 
 
 
 15,146 
 
 
 72 
 
 
 15,540 
 
 
 13,301 
Capitalized Portion
 
 
 (7,529)
 
 
 (6,525)
 
 
 (5,604)
 
 
 (25)
 
 
 (6,092)
 
 
 (4,921)
Net Periodic Benefit Cost Recognized in
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
$
 14,486 
 
$
 10,121 
 
$
 9,542 
 
$
 47 
 
$
 9,448 
 
$
 8,380 

 
 
 
 
 
Other Postretirement
I&M
 
Pension Plans
 
Benefit Plans
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
 
2013 
 
2012 
 
2011 
 
 
 
(in thousands)
Service Cost
 
$
 8,736 
 
$
 9,908 
 
$
 9,447 
 
$
 3,219 
 
$
 6,621 
 
$
 6,119 
Interest Cost
 
 
 24,100 
 
 
 26,245 
 
 
 27,726 
 
 
 8,221 
 
 
 12,785 
 
 
 13,610 
Expected Return on Plan Assets
 
 
 (32,826)
 
 
 (37,566)
 
 
 (36,856)
 
 
 (13,183)
 
 
 (12,847)
 
 
 (13,886)
Amortization of Transition Obligation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 132 
 
 
 188 
Amortization of Prior Service Cost (Credit)
 
 
 195 
 
 
 407 
 
 
 744 
 
 
 (9,421)
 
 
 (2,383)
 
 
 (237)
Amortization of Net Actuarial Loss
 
 
 21,688 
 
 
 17,569 
 
 
 14,144 
 
 
 7,526 
 
 
 7,050 
 
 
 3,566 
Net Periodic Benefit Cost (Credit)
 
 
 21,893 
 
 
 16,563 
 
 
 15,205 
 
 
 (3,638)
 
 
 11,358 
 
 
 9,360 
Capitalized Portion
 
 
 (4,576)
 
 
 (3,114)
 
 
 (3,163)
 
 
 760 
 
 
 (2,135)
 
 
 (1,947)
Net Periodic Benefit Cost (Credit)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recognized in Expense
 
$
 17,317 
 
$
 13,449 
 
$
 12,042 
 
$
 (2,878)
 
$
 9,223 
 
$
 7,413 

 
 
 
 
 
Other Postretirement
OPCo
 
Pension Plans
 
Benefit Plans
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
 
2013 
 
2012 
 
2011 
 
 
 
(in thousands)
Service Cost
 
$
 5,285 
 
$
 11,003 
 
$
 10,230 
 
$
 2,882 
 
$
 8,748 
 
$
 7,827 
Interest Cost
 
 
 21,939 
 
 
 45,194 
 
 
 48,350 
 
 
 9,494 
 
 
 24,189 
 
 
 25,497 
Expected Return on Plan Assets
 
 
 (29,919)
 
 
 (68,401)
 
 
 (65,464)
 
 
 (13,468)
 
 
 (22,555)
 
 
 (24,514)
Curtailment
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 605 
Amortization of Transition Obligation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 104 
 
 
 150 
Amortization of Prior Service Cost (Credit)
 
 
 157 
 
 
 743 
 
 
 1,474 
 
 
 (6,962)
 
 
 (3,873)
 
 
 (212)
Amortization of Net Actuarial Loss
 
 
 19,833 
 
 
 30,439 
 
 
 24,828 
 
 
 8,633 
 
 
 13,669 
 
 
 7,298 
Net Periodic Benefit Cost
 
 
 17,295 
 
 
 18,978 
 
 
 19,418 
 
 
 579 
 
 
 20,282 
 
 
 16,651 
Capitalized Portion
 
 
 (6,192)
 
 
 (7,060)
 
 
 (6,932)
 
 
 (207)
 
 
 (7,545)
 
 
 (5,944)
Net Periodic Benefit Cost Recognized in
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
$
 11,103 
 
$
 11,918 
 
$
 12,486 
 
$
 372 
 
$
 12,737 
 
$
 10,707 


 
305

 
 
 
 
 
 
 
Other Postretirement
PSO
 
Pension Plans
 
Benefit Plans
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
 
2013 
 
2012 
 
2011 
 
 
 
(in thousands)
Service Cost
 
$
 5,562 
 
$
 5,951 
 
$
 5,760 
 
$
 1,372 
 
$
 2,836 
 
$
 2,621 
Interest Cost
 
 
 10,993 
 
 
 12,301 
 
 
 13,285 
 
 
 3,793 
 
 
 5,797 
 
 
 6,046 
Expected Return on Plan Assets
 
 
 (15,675)
 
 
 (18,015)
 
 
 (17,464)
 
 
 (6,089)
 
 
 (5,922)
 
 
 (6,264)
Amortization of Prior Service Cost (Credit)
 
 
 297 
 
 
 (948)
 
 
 (950)
 
 
 (4,289)
 
 
 (1,079)
 
 
 (75)
Amortization of Net Actuarial Loss
 
 
 9,845 
 
 
 8,206 
 
 
 6,757 
 
 
 3,476 
 
 
 3,189 
 
 
 1,553 
Net Periodic Benefit Cost (Credit)
 
 
 11,022 
 
 
 7,495 
 
 
 7,388 
 
 
 (1,737)
 
 
 4,821 
 
 
 3,881 
Capitalized Portion
 
 
 (3,384)
 
 
 (2,533)
 
 
 (2,379)
 
 
 533 
 
 
 (1,629)
 
 
 (1,249)
Net Periodic Benefit Cost (Credit)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recognized in Expense
 
$
 7,638 
 
$
 4,962 
 
$
 5,009 
 
$
 (1,204)
 
$
 3,192 
 
$
 2,632 

 
 
 
 
 
Other Postretirement
SWEPCo
 
Pension Plans
 
Benefit Plans
 
 
 
Years Ended December 31,
 
 
 
2013 
 
2012 
 
2011 
 
2013 
 
2012 
 
2011 
 
 
 
(in thousands)
Service Cost
 
$
 7,011 
 
$
 7,099 
 
$
 6,573 
 
$
 1,693 
 
$
 3,324 
 
$
 3,029 
Interest Cost
 
 
 11,454 
 
 
 12,537 
 
 
 13,331 
 
 
 4,301 
 
 
 6,673 
 
 
 6,969 
Expected Return on Plan Assets
 
 
 (16,509)
 
 
 (18,866)
 
 
 (18,380)
 
 
 (6,881)
 
 
 (6,795)
 
 
 (7,200)
Amortization of Prior Service Cost (Credit)
 
 
 349 
 
 
 (793)
 
 
 (795)
 
 
 (5,156)
 
 
 (933)
 
 
 258 
Amortization of Net Actuarial Loss
 
 
 10,214 
 
 
 8,330 
 
 
 6,759 
 
 
 3,928 
 
 
 3,659 
 
 
 1,785 
Net Periodic Benefit Cost (Credit)
 
 
 12,519 
 
 
 8,307 
 
 
 7,488 
 
 
 (2,115)
 
 
 5,928 
 
 
 4,841 
Capitalized Portion
 
 
 (3,518)
 
 
 (2,924)
 
 
 (2,636)
 
 
 594 
 
 
 (2,087)
 
 
 (1,704)
Net Periodic Benefit Cost (Credit)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Recognized in Expense
 
$
 9,001 
 
$
 5,383 
 
$
 4,852 
 
$
 (1,521)
 
$
 3,841 
 
$
 3,137 


 
306

 

Estimated amounts expected to be amortized to net periodic benefit costs (credits) and the impact on each Registrant Subsidiary’s balance sheet during 2014 are shown in the following tables:

 
 
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
Pension Plan - Components
 
(in thousands)
Net Actuarial Loss
 
$
 16,971 
 
$
 14,708 
 
$
 13,398 
 
$
 6,682 
 
$
 6,932 
Prior Service Cost
 
 
 198 
 
 
 195 
 
 
 157 
 
 
 296 
 
 
 349 
Total Estimated 2014 Amortization
$
 17,169 
 
$
 14,903 
 
$
 13,555 
 
$
 6,978 
 
$
 7,281 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension Plans -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expected to be Recorded as
 
 
 
 
 
 
 
 
 
 
Regulatory Asset
 
$
 17,075 
 
$
 14,010 
 
$
 13,555 
 
$
 6,978 
 
$
 7,281 
Deferred Income Taxes
 
 
 33 
 
 
 313 
 
 
 - 
 
 
 - 
 
 
 - 
Net of Tax AOCI
 
 
 61 
 
 
 580 
 
 
 - 
 
 
 - 
 
 
 - 
Total
$
 17,169 
 
$
 14,903 
 
$
 13,555 
 
$
 6,978 
 
$
 7,281 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
Other Postretirement Benefit Plans -
 
(in thousands)
Components
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Actuarial Loss
 
$
 4,339 
 
$
 2,341 
 
$
 2,406 
 
$
 1,094 
 
$
 1,223 
Prior Service Credit
 
 
 (10,050)
 
 
 (9,421)
 
 
 (6,922)
 
 
 (4,290)
 
 
 (5,156)
Total Estimated 2014 Amortization
$
 (5,711)
 
$
 (7,080)
 
$
 (4,516)
 
$
 (3,196)
 
$
 (3,933)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement Benefit Plans - Expected to be Recorded as
 
 
 
 
 
 
 
 
 
 
Regulatory Asset
 
$
 (3,344)
 
$
 (6,446)
 
$
 (4,516)
 
$
 (3,196)
 
$
 (2,485)
Deferred Income Taxes
 
 
 (828)
 
 
 (222)
 
 
 - 
 
 
 - 
 
 
 (507)
Net of Tax AOCI
 
 
 (1,539)
 
 
 (412)
 
 
 - 
 
 
 - 
 
 
 (941)
Total
$
 (5,711)
 
$
 (7,080)
 
$
 (4,516)
 
$
 (3,196)
 
$
 (3,933)

American Electric Power System Retirement Savings Plan

The Registrant Subsidiaries participate in an AEP sponsored defined contribution retirement savings plan, the American Electric Power System Retirement Savings Plan, for substantially all employees who are not members of the United Mine Workers of America (UMWA).  This qualified plan offers participants an opportunity to contribute a portion of their pay, includes features under Section 401(k) of the Internal Revenue Code and provides for company matching contributions.  The matching contributions to the plan are 100% of the first 1% of eligible employee contributions and 70% of the next 5% of contributions.

The following table provides the cost for matching contributions to the retirement savings plans by Registrant Subsidiary for the years ended December 31, 2013, 2012 and 2011:
 
 
       Years Ended December 31,    
Company  
  2013
   2012    2011  
      (in thousands)  
APCo     7,366    7,579    7,432  
I&M       10,010      9,706      9,541  
OPCo       6,502      10,798      10,166  
PSO       3,784      3,732      3,626  
SWEPCo       4,970      4,890      4,438  
 

 
307

 

UMWA Benefits

APCo and I&M provide UMWA pension, health and welfare benefits for certain unionized mining employees, retirees and their survivors who meet eligibility requirements.  UMWA trustees make final interpretive determinations with regard to all benefits.  The pension benefits are administered by UMWA trustees and contributions are made to their trust funds.  APCo and I&M administer the health and welfare benefits and pay them from their general assets.

The UMWA pension benefits are administered through a multiemployer plan that is different from single-employer plans as an employer’s contributions may be used to provide benefits to employees of other participating employers.  Required contributions not made by an employer may result in other employers bearing the unfunded plan obligations, while a withdrawing employer may be subject to a withdrawal liability.  UMWA pension benefits are provided through the United Mine Workers of America 1974 Pension Plan (Employer Identification Number: 52-1050282, Plan Number 002), which under the Pension Protection Act of 2006 (PPA) was in Seriously Endangered Status for the plan years ending June 30, 2013 and 2012, without utilization of extended amortization provisions.  The Plan adopted a funding improvement plan in May 2012, as required under the PPA.

Contributions to the UMWA pension plan in 2013, 2012 and 2011 were immaterial and represent less than 5% of the total contributions in the plan’s latest annual report for the years ended June 30, 2013, 2012 and 2011.  The contributions did not include a surcharge.  There are no minimum contributions for future years.

8.   BUSINESS SEGMENTS

The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business.  The Registrant Subsidiaries’ other activities are insignificant.  The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.

9.   DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, natural gas, coal and emission allowances.  These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk.  These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates.  AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Risk Management Strategies

The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies.  The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries.  To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options.  Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.”  Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business.  AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries’ commodity portfolio.  For disclosure purposes,
 
 
308

 
such risks are grouped as “Commodity,” as these risks are related to energy risk management activities.  AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies.  For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.”  The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors.

As a result of corporate separation, OPCo’s December 31, 2013 FTR price risk relates to congestion during the June 2012 - May 2015 Ohio ESP period.  Additional risk includes interest rate risk.

The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of December 31, 2013 and 2012:

 
Notional Volume of Derivative Instruments
 
December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Primary Risk
 
Unit of
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exposure
 
Measure
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
 
(in thousands)
Commodity:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Power
 
MWhs
 
 
 48,995 
 
 
 33,231 
 
 
 34,843 
 
 
 13,469 
 
 
 17,057 
 
Coal
 
Tons
 
 
 31 
 
 
 3,389 
 
 
 - 
 
 
 1,013 
 
 
 1,692 
 
Natural Gas
 
MMBtus
 
 
 2,477 
 
 
 1,680 
 
 
 - 
 
 
 - 
 
 
 - 
 
Heating Oil and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline
 
Gallons
 
 
 1,089 
 
 
 521 
 
 
 1,108 
 
 
 614 
 
 
 699 
 
Interest Rate
 
USD
 
$
 12,720 
 
$
 8,627 
 
$
 - 
 
$
 - 
 
$
 - 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Foreign Currency
 
USD
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 - 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notional Volume of Derivative Instruments
 
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Primary Risk
 
Unit of
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exposure
 
Measure
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
 
(in thousands)
Commodity:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Power
 
MWhs
 
 
 94,059 
 
 
 64,791 
 
 
 132,188 
 
 
 - 
 
 
 - 
 
Coal
 
Tons
 
 
 1,401 
 
 
 2,711 
 
 
 3,033 
 
 
 1,980 
 
 
 1,312 
 
Natural Gas
 
MMBtus
 
 
 10,077 
 
 
 6,922 
 
 
 14,163 
 
 
 - 
 
 
 - 
 
Heating Oil and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline
 
Gallons
 
 
 1,050 
 
 
 532 
 
 
 1,260 
 
 
 616 
 
 
 585 
 
Interest Rate
 
USD
 
$
 24,146 
 
$
 16,584 
 
$
 33,934 
 
$
 - 
 
$
 - 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Foreign Currency
 
USD
 
$
 - 
 
$
 200,000 
 
$
 - 
 
$
 - 
 
$
 - 

Fair Value Hedging Strategies

AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt.  Certain interest rate derivative transactions effectively modify an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate.  Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.


 
309

 

Cash Flow Hedging Strategies

AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities.  Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases.  The Registrant Subsidiaries do not hedge all commodity price risk.

The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility.  AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases.  For disclosure purposes, these contracts are included with other hedging activities as “Commodity.”  The Registrant Subsidiaries do not hedge all fuel price risk.

AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure.  Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate.  AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt.  The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures.  The Registrant Subsidiaries do not hedge all interest rate exposure.

At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers.  In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar.  The Registrant Subsidiaries do not hedge all foreign currency exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheet at fair value.  The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes.  If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions.  In order to determine the relevant fair values of the derivative instruments, the Registrant Subsidiaries also apply valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due.  Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions.  Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts.  Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles.  Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period.  This is particularly true for longer term contracts.  Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.


 
310

 

According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral.  For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the December 31, 2013 and 2012 balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:

 
 
 
December 31,
 
 
 
2013 
 
2012 
 
 
 
Cash Collateral
 
Cash Collateral
 
Cash Collateral
 
Cash Collateral
 
 
 
Received
 
Paid
 
Received
 
Paid
 
 
 
Netted Against
 
Netted Against
 
Netted Against
 
Netted Against
 
 
 
Risk Management
 
Risk Management
 
Risk Management
 
Risk Management
Company
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
 
 
(in thousands)
APCo
 
$
 - 
 
$
 2,993 
 
$
 1,262 
 
$
 11,029 
I&M
 
 
 - 
 
 
 2,030 
 
 
 867 
 
 
 7,576 
OPCo
 
 
 - 
 
 
 - 
 
 
 1,774 
 
 
 15,500 
PSO
 
 
 - 
 
 
 1 
 
 
 - 
 
 
 - 
SWEPCo
 
 
 - 
 
 
 3 
 
 
 - 
 
 
 - 


 
311

 

The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the balance sheets as of December 31, 2013 and 2012:

Fair Value of Derivative Instruments
December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in thousands)
Current Risk Management Assets
 
$
46,431 
 
$
389 
 
$
 
$
46,820 
 
$
(25,649)
 
$
21,171 
Long-term Risk Management Assets
 
 
20,948 
 
 
 
 
 
 
20,948 
 
 
(4,000)
 
 
16,948 
Total Assets
 
 
67,379 
 
 
389 
 
 
 
 
67,768 
 
 
(29,649)
 
 
38,119 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
37,010 
 
 
313 
 
 
 
 
37,323 
 
 
(28,431)
 
 
8,892 
Long-term Risk Management Liabilities
 
 
14,452 
 
 
 
 
 
 
14,452 
 
 
(4,211)
 
 
10,241 
Total Liabilities
 
 
51,462 
 
 
313 
 
 
 
 
51,775 
 
 
(32,642)
 
 
19,133 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
15,917 
 
$
76 
 
$
 
$
15,993 
 
$
2,993 
 
$
18,986 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in thousands)
Current Risk Management Assets
 
$
127,645 
 
$
338 
 
$
 
$
127,983 
 
$
(97,023)
 
$
30,960 
Long-term Risk Management Assets
 
 
60,498 
 
 
215 
 
 
 
 
60,713 
 
 
(26,353)
 
 
34,360 
Total Assets
 
 
188,143 
 
 
553 
 
 
 
 
188,696 
 
 
(123,376)
 
 
65,320 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
119,430 
 
 
1,182 
 
 
 
 
120,612 
 
 
(103,914)
 
 
16,698 
Long-term Risk Management Liabilities
 
 
47,281 
 
 
424 
 
 
 
 
47,705 
 
 
(29,229)
 
 
18,476 
Total Liabilities
 
 
166,711 
 
 
1,606 
 
 
 
 
168,317 
 
 
(133,143)
 
 
35,174 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
21,432 
 
$
(1,053)
 
$
 
$
20,379 
 
$
9,767 
 
$
30,146 

 
312

 
 
Fair Value of Derivative Instruments
December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in thousands)
Current Risk Management Assets
 
$
33,229 
 
$
234 
 
$
 
$
33,463 
 
$
(18,075)
 
$
15,388 
Long-term Risk Management Assets
 
 
14,208 
 
 
 
 
 
 
14,208 
 
 
(2,713)
 
 
11,495 
Total Assets
 
 
47,437 
 
 
234 
 
 
 
 
47,671 
 
 
(20,788)
 
 
26,883 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
26,779 
 
 
212 
 
 
 
 
26,991 
 
 
(19,962)
 
 
7,029 
Long-term Risk Management Liabilities
 
 
9,802 
 
 
 
 
 
 
9,802 
 
 
(2,856)
 
 
6,946 
Total Liabilities
 
 
36,581 
 
 
212 
 
 
 
 
36,793 
 
 
(22,818)
 
 
13,975 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
10,856 
 
$
22 
 
$
 
$
10,878 
 
$
2,030 
 
$
12,908 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in thousands)
Current Risk Management Assets
 
$
93,268 
 
$
220 
 
$
 
$
93,488 
 
$
(66,514)
 
$
26,974 
Long-term Risk Management Assets
 
 
41,553 
 
 
148 
 
 
 
 
41,701 
 
 
(18,132)
 
 
23,569 
Total Assets
 
 
134,821 
 
 
368 
 
 
 
 
135,189 
 
 
(84,646)
 
 
50,543 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
82,433 
 
 
807 
 
 
19,524 
 
 
102,764 
 
 
(71,247)
 
 
31,517 
Long-term Risk Management Liabilities
 
 
33,714 
 
 
292 
 
 
 
 
34,006 
 
 
(20,108)
 
 
13,898 
Total Liabilities
 
 
116,147 
 
 
1,099 
 
 
19,524 
 
 
136,770 
 
 
(91,355)
 
 
45,415 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
18,674 
 
$
(731)
 
$
(19,524)
 
$
(1,581)
 
$
6,709 
 
$
5,128 

 
313

 
 
Fair Value of Derivative Instruments
December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in thousands)
Current Risk Management Assets
 
$
3,269 
 
$
162 
 
$
 
$
3,431 
 
$
(349)
 
$
3,082 
Long-term Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
 
3,269 
 
 
162 
 
 
 
 
3,431 
 
 
(349)
 
 
3,082 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
349 
 
 
 
 
 
 
349 
 
 
(349)
 
 
Long-term Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
Total Liabilities
 
 
349 
 
 
 
 
 
 
349 
 
 
(349)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
2,920 
 
$
162 
 
$
 
$
3,082 
 
$
 
$
3,082 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in thousands)
Current Risk Management Assets
 
$
183,064 
 
$
464 
 
$
 
$
183,528 
 
$
(139,215)
 
$
44,313 
Long-term Risk Management Assets
 
 
85,023 
 
 
303 
 
 
 
 
85,326 
 
 
(37,038)
 
 
48,288 
Total Assets
 
 
268,087 
 
 
767 
 
 
 
 
268,854 
 
 
(176,253)
 
 
92,601 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
171,397 
 
 
1,658 
 
 
 
 
173,055 
 
 
(148,900)
 
 
24,155 
Long-term Risk Management Liabilities
 
 
66,448 
 
 
596 
 
 
 
 
67,044 
 
 
(41,079)
 
 
25,965 
Total Liabilities
 
 
237,845 
 
 
2,254 
 
 
 
 
240,099 
 
 
(189,979)
 
 
50,120 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
30,242 
 
$
(1,487)
 
$
 
$
28,755 
 
$
13,726 
 
$
42,481 

 
314

 
 
Fair Value of Derivative Instruments
December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in thousands)
Current Risk Management Assets
 
$
1,078 
 
$
84 
 
$
 
$
1,162 
 
$
 
$
1,167 
Long-term Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
 
1,078 
 
 
84 
 
 
 
 
1,162 
 
 
 
 
1,167 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
81 
 
 
 
 
 
 
81 
 
 
 
 
85 
Long-term Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
Total Liabilities
 
 
81 
 
 
 
 
 
 
81 
 
 
 
 
85 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
997 
 
$
84 
 
$
 
$
1,081 
 
$
 
$
1,082 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in thousands)
Current Risk Management Assets
 
$
1,657 
 
$
42 
 
$
 
$
1,699 
 
$
(1,190)
 
$
509 
Long-term Risk Management Assets
 
 
 
 
 
 
 
 
 
 
31 
 
 
31 
Total Assets
 
 
1,657 
 
 
42 
 
 
 
 
1,699 
 
 
(1,159)
 
 
540 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
7,021 
 
 
17 
 
 
 
 
7,038 
 
 
(1,190)
 
 
5,848 
Long-term Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
31 
 
 
31 
Total Liabilities
 
 
7,021 
 
 
17 
 
 
 
 
7,038 
 
 
(1,159)
 
 
5,879 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
(5,364)
 
$
25 
 
$
 
$
(5,339)
 
$
 
$
(5,339)

 
315

 
 
Fair Value of Derivative Instruments
December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in thousands)
Current Risk Management Assets
 
$
1,233 
 
$
97 
 
$
 
$
1,330 
 
$
(151)
 
$
1,179 
Long-term Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
 
1,233 
 
 
97 
 
 
 
 
1,330 
 
 
(151)
 
 
1,179 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
154 
 
 
 
 
 
 
154 
 
 
(154)
 
 
Long-term Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
Total Liabilities
 
 
154 
 
 
 
 
 
 
154 
 
 
(154)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
1,079 
 
$
97 
 
$
 
$
1,176 
 
$
 
$
1,179 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
Gross Amounts
 
Gross
 
Net Amounts of
 
 
 
Management
 
 
 
 
 
of Risk
 
Amounts
 
Assets/Liabilities
 
 
 
Contracts
 
Hedging Contracts
 
Management
 
Offset in the
 
Presented in the
 
 
 
 
 
 
 
 
Interest Rate
 
Assets/
 
Statement of
 
Statement of
 
 
 
 
 
 
 
and Foreign
 
Liabilities
 
Financial
 
Financial
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Recognized
 
Position (b)
 
Position (c)
 
 
 
(in thousands)
Current Risk Management Assets
 
$
2,804 
 
$
41 
 
$
 
$
2,845 
 
$
(2,150)
 
$
695 
Long-term Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
 
2,804 
 
 
41 
 
 
 
 
2,845 
 
 
(2,150)
 
 
695 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
3,261 
 
 
17 
 
 
 
 
3,278 
 
 
(2,150)
 
 
1,128 
Long-term Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
Total Liabilities
 
 
3,261 
 
 
17 
 
 
 
 
3,278 
 
 
(2,150)
 
 
1,128 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
(457)
 
$
24 
 
$
 
$
(433)
 
$
 
$
(433)

 
(a) Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."
 
(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging."
 
(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
 

 
 
316

 
The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the years ended December 31, 2013, 2012 and 2011:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
 Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Location of Gain (Loss)
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Electric Generation, Transmission and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
$
 2,019 
 
$
 10,624 
 
$
 4,886 
 
$
 371 
 
$
 647 
Sales to AEP Affiliates
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Fuel and Other Consumables Used for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Regulatory Assets (a)
 
 
 (4)
 
 
 (26)
 
 
 (5,795)
 
 
 2,956 
 
 
 424 
Regulatory Liabilities (a)
 
 
 (338)
 
 
 (9,062)
 
 
 2,920 
 
 
 999 
 
 
 1,462 
Total Gain (Loss) on Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
$
 1,677 
 
$
 1,536 
 
$
 2,011 
 
$
 4,326 
 
$
 2,533 

Amount of Gain (Loss) Recognized on
Risk Management Contracts
 Year Ended December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Location of Gain (Loss)
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Electric Generation, Transmission and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
$
 (1,149)
 
$
 11,437 
 
$
 11,978 
 
$
 163 
 
$
 398 
Sales to AEP Affiliates
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Fuel and Other Consumables Used for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Regulatory Assets (a)
 
 
 (7,835)
 
 
 (9,204)
 
 
 (14,104)
 
 
 (5,304)
 
 
 (6,274)
Regulatory Liabilities (a)
 
 
 7,314 
 
 
 (889)
 
 
 - 
 
 
 (19)
 
 
 (13)
Total Gain (Loss) on Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
$
 (1,670)
 
$
 1,344 
 
$
 (2,126)
 
$
 (5,160)
 
$
 (5,889)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of Gain (Loss) Recognized on
Risk Management Contracts
 Year Ended December 31, 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Location of Gain (Loss)
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Electric Generation, Transmission and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
$
 2,843 
 
$
 12,786 
 
$
 27,292 
 
$
 297 
 
$
 547 
Sales to AEP Affiliates
 
 
 154 
 
 
 92 
 
 
 196 
 
 
 3 
 
 
 4 
Fuel and Other Consumables Used for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation
 
 
 - 
 
 
 - 
 
 
 (2)
 
 
 - 
 
 
 - 
Regulatory Assets (a)
 
 
 373 
 
 
 (1,470)
 
 
 (17,928)
 
 
 (1,421)
 
 
 (1,709)
Regulatory Liabilities (a)
 
 
 2,552 
 
 
 (5,178)
 
 
 (105)
 
 
 708 
 
 
 (118)
Total Gain (Loss) on Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
$
 5,922 
 
$
 6,230 
 
$
 9,453 
 
$
 (413)
 
$
 (1,276)

 
(a)
Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.”  Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis.

 
317

 
The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship.  Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes.  Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income.  Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances.  However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO and SWEPCo) for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

Accounting for Fair Value Hedging Strategies

For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change.

The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income.  During 2013, 2012 and 2011, the Registrant Subsidiaries did not designate any fair value hedging strategies.

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income.  The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged.  During 2013, 2012 and 2011, APCo, I&M and OPCo designated power, coal and natural gas derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the statements of income.  During 2013, 2012 and 2011, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur.  During 2013, I&M designated interest rate derivatives as cash flow hedges.  During 2012, I&M and SWEPCo designated interest rate derivatives as cash flow hedges.  During 2011, APCo, I&M and SWEPCo designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.  During 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges.  During 2012 and 2011, SWEPCo designated foreign currency derivatives as cash flow hedges.

 
318

 
During 2013, 2012 and 2011, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 2.

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets as of December 31, 2013 and 2012 were:

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Balance Sheets
December 31, 2013
 
 
 
 
Hedging Assets (a)
 
Hedging Liabilities (a)
 
AOCI Gain (Loss) Net of Tax
 
 
 
 
 
Interest Rate
 
 
 
Interest Rate
 
 
 
Interest Rate
 
 
 
 
 
and Foreign
 
 
 
and Foreign
 
 
 
and Foreign
Company
 
Commodity
 
Currency
 
Commodity
 
Currency
 
Commodity
 
Currency
 
 
 
(in thousands)
APCo
 
$
 363 
 
$
 - 
 
$
 287 
 
$
 - 
 
$
 94 
 
$
 3,090 
I&M
 
 
 216 
 
 
 - 
 
 
 194 
 
 
 - 
 
 
 46 
 
 
 (15,976)
OPCo
 
 
 162 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 105 
 
 
 6,974 
PSO
 
 
 84 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 57 
 
 
 5,701 
SWEPCo
 
 
 97 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 66 
 
 
 (13,304)

 
 
 
Expected to be Reclassified to
 
 
 
 
 
 
 
Net Income During the Next
 
 
 
 
 
 
 
Twelve Months
 
 
 
 
 
 
 
 
 
 
 
Maximum Term for  
 
 
 
 
 
Interest Rate
 
Exposure to  
 
 
 
 
 
and Foreign
 
Variability of Future  
Company
 
Commodity
 
Currency
 
Cash Flows  
 
 
 
(in thousands)
 
(in months)  
APCo
 
$
 94 
 
$
 (806)
 
 
 12   
I&M
 
 
 46 
 
 
 (1,568)
 
 
 12   
OPCo
 
 
 105 
 
 
 1,363 
 
 
 12   
PSO
 
 
 57 
 
 
 759 
 
 
 12   
SWEPCo
 
 
 66 
 
 
 (2,267)
 
 
 12   

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Balance Sheets
December 31, 2012
 
 
 
 
Hedging Assets (a)
 
Hedging Liabilities (a)
 
AOCI Gain (Loss) Net of Tax
 
 
 
 
 
Interest Rate
 
 
 
Interest Rate
 
 
 
Interest Rate
 
 
 
 
 
and Foreign
 
 
 
and Foreign
 
 
 
and Foreign
Company
 
Commodity
 
Currency
 
Commodity
 
Currency
 
Commodity
 
Currency
 
 
 
(in thousands)
APCo
 
$
 302 
 
$
 - 
 
$
 1,355 
 
$
 - 
 
$
 (644)
 
$
 2,077 
I&M
 
 
 200 
 
 
 - 
 
 
 931 
 
 
 19,524 
 
 
 (446)
 
 
 (19,647)
OPCo
 
 
 416 
 
 
 - 
 
 
 1,903 
 
 
 - 
 
 
 (912)
 
 
 8,095 
PSO
 
 
 25 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 21 
 
 
 6,460 
SWEPCo
 
 
 24 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 22 
 
 
 (15,571)
 
 
 
319

 

 
 
 
 
Expected to be Reclassified to
 
 
 
Net Income During the Next
 
 
 
Twelve Months
 
 
 
 
 
Interest Rate
 
 
 
 
 
and Foreign
Company
 
Commodity
 
Currency
 
 
 
(in thousands)
APCo
 
$
 (507)
 
$
 (1,013)
I&M
 
 
 (355)
 
 
 (1,600)
OPCo
 
 
 (720)
 
 
 1,359 
PSO
 
 
 21 
 
 
 759 
SWEPCo
 
 
 22 
 
 
 (2,267)

 
(a)
Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets.

The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.

Credit Risk

AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.  AEPSC, on behalf of the Registrant Subsidiaries, uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements.  These master agreements facilitate the netting of cash flows associated with a single counterparty.  Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk.  The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold.  The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy.  In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.

 
320

 
Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade.  The amount of collateral required fluctuates based on market prices and total exposure.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts.  The Registrant Subsidiaries have not experienced a downgrade below investment grade.  The following tables represent: (a) the Registrant Subsidiaries’ fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of December 31, 2013 and 2012:

 
 
 
December 31, 2013
 
 
 
Liabilities for
 
Amount of Collateral the
 
Amount
 
 
 
Derivative Contracts
 
Registrant Subsidiaries
 
Attributable to
 
 
 
with Credit
 
Would Have Been
 
RTO and ISO
Company
 
Downgrade Triggers
 
Required to Post
 
Activities
 
 
 
(in thousands)
APCo
 
$
 575 
 
$
 2,747 
 
$
 2,539 
I&M
 
 
 390 
 
 
 1,863 
 
 
 1,722 
OPCo
 
 
 349 
 
 
 - 
 
 
 - 
PSO
 
 
 - 
 
 
 2,930 
 
 
 410 
SWEPCo
 
 
 - 
 
 
 713 
 
 
 519 

 
 
 
December 31, 2012
 
 
 
Liabilities for
 
Amount of Collateral the
 
Amount
 
 
 
Derivative Contracts
 
Registrant Subsidiaries
 
Attributable to
 
 
 
with Credit
 
Would Have Been
 
RTO and ISO
Company
 
Downgrade Triggers
 
Required to Post
 
Activities
 
 
 
(in thousands)
APCo
 
$
 2,159 
 
$
 3,699 
 
$
 3,510 
I&M
 
 
 1,483 
 
 
 2,540 
 
 
 2,411 
OPCo
 
 
 3,034 
 
 
 5,198 
 
 
 4,933 
PSO
 
 
 - 
 
 
 1,509 
 
 
 1,429 
SWEPCo
 
 
 - 
 
 
 1,778 
 
 
 1,683 
 

 
 
321

 
In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable.  These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts.  The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries’ contractual netting arrangements as of December 31, 2013 and 2012:

 
 
 
December 31, 2013
 
 
 
Liabilities for
 
 
 
Additional
 
 
 
Contracts with Cross
 
 
 
Settlement
 
 
 
Default Provisions
 
 
 
Liability if Cross
 
 
 
Prior to Contractual
 
Amount of Cash
 
Default Provision
Company
 
Netting Arrangements
 
Collateral Posted
 
is Triggered
 
 
 
(in thousands)
APCo
 
$
 19,648 
 
$
 - 
 
$
 18,568 
I&M
 
 
 13,326 
 
 
 - 
 
 
 12,594 
OPCo
 
 
 - 
 
 
 - 
 
 
 - 
PSO
 
 
 3 
 
 
 - 
 
 
 3 
SWEPCo
 
 
 3 
 
 
 - 
 
 
 3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2012
 
 
 
Liabilities for
 
 
 
Additional
 
 
 
Contracts with Cross
 
 
 
Settlement
 
 
 
Default Provisions
 
 
 
Liability if Cross
 
 
 
Prior to Contractual
 
Amount of Cash
 
Default Provision
Company
 
Netting Arrangements
 
Collateral Posted
 
is Triggered
 
 
 
(in thousands)
APCo
 
$
 49,465 
 
$
 1,822 
 
$
 30,160 
I&M
 
 
 53,499 
 
 
 1,252 
 
 
 40,240 
OPCo
 
 
 69,516 
 
 
 2,561 
 
 
 42,386 
PSO
 
 
 - 
 
 
 - 
 
 
 - 
SWEPCo
 
 
 - 
 
 
 - 
 
 
 - 
 

 
 
322

 
10.   FAIR VALUE MEASUREMENTS

Fair Value Measurements of Long-term Debt

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs.  These instruments are not marked-to-market.  The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of December 31, 2013 and 2012 are summarized in the following table:

 
 
December 31,
 
 
2013 
 
2012 
Company
 
Book Value
 
Fair Value
 
Book Value
 
Fair Value
 
 
(in thousands)
APCo
 
$
 4,194,357 
 
$
 4,587,079 
 
$
 3,702,442 
 
$
 4,555,143 
I&M
 
 
 2,039,016 
 
 
 2,174,891 
 
 
 2,057,666 
 
 
 2,372,017 
OPCo
 
 
 2,735,175 
 
 
 3,007,191 
 
 
 3,860,440 
 
 
 4,560,337 
PSO
 
 
 999,810 
 
 
 1,111,149 
 
 
 949,871 
 
 
 1,175,759 
SWEPCo
 
 
 2,043,332 
 
 
 2,214,730 
 
 
 2,046,228 
 
 
 2,400,509 

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value.  See “Nuclear Trust Funds” section of Note 1.

The following is a summary of nuclear trust fund investments as of December 31, 2013 and 2012:

 
 
 
 
December 31,
 
 
 
 
2013 
 
2012 
 
 
 
 
Estimated
 
Gross
 
Other-Than-
 
Estimated
 
Gross
 
Other-Than-
 
 
 
Fair
Unrealized
Temporary
Fair
Unrealized
Temporary
 
 
 
Value
Gains
Impairments
Value
Gains
Impairments
 
 
 
 
(in thousands)
 
Cash and Cash Equivalents
 
$
 18,804 
 
$
 - 
 
$
 - 
 
$
 16,783 
 
$
 - 
 
$
 - 
 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 
 608,875 
 
 
 26,114 
 
 
 (3,824)
 
 
 647,918 
 
 
 58,268 
 
 
 (747)
 
 
Corporate Debt
 
 
 36,782 
 
 
 2,450 
 
 
 (1,123)
 
 
 35,399 
 
 
 4,903 
 
 
 (1,352)
 
 
State and Local Government
 
 
 254,638 
 
 
 748 
 
 
 (370)
 
 
 270,090 
 
 
 1,006 
 
 
 (863)
 
 
  Subtotal Fixed Income Securities
 
 900,295 
 
 
 29,312 
 
 
 (5,317)
 
 
 953,407 
 
 
 64,177 
 
 
 (2,962)
 
Equity Securities - Domestic
 
 
 1,012,511 
 
 
 505,538 
 
 
 (81,677)
 
 
 735,582 
 
 
 284,599 
 
 
 (76,557)
 
Spent Nuclear Fuel and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decommissioning Trusts
 
$
 1,931,610 
 
$
 534,850 
 
$
 (86,994)
 
$
 1,705,772 
 
$
 348,776 
 
$
 (79,519)

The following table provides the securities activity within the decommissioning and SNF trusts for the years ended December 31, 2013, 2012 and 2011:

 
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
(in thousands)
Proceeds from Investment Sales
$
 858,406 
 
$
 987,550 
 
$
 1,110,909 
Purchases of Investments
 
 909,998 
 
 
 1,045,422 
 
 
 1,166,690 
Gross Realized Gains on Investment Sales
 
 18,326 
 
 
 24,605 
 
 
 33,382 
Gross Realized Losses on Investment Sales
 
 8,108 
 
 
 8,881 
 
 
 22,159 

The adjusted cost of fixed income securities was $872 million and $889 million as of December 31, 2013 and 2012, respectively.  The adjusted cost of equity securities was $506 million and $451 million as of December 31, 2013 and 2012, respectively.

 
323

 
The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2013 was as follows:

 
Fair Value of
 
Fixed Income
 
Securities
 
(in thousands)
Within 1 year
$
 79,100 
1 year – 5 years
 
 383,623 
5 years – 10 years
 
 187,800 
After 10 years
 
 249,772 
Total
$
 900,295 

Fair Value Measurements of Financial Assets and Liabilities

For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1.

The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 and 2012.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in management’s valuation techniques.
 
 
324

 

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013
APCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Cash Deposits (e)
$
 2,714 
 
$
 - 
 
$
 - 
 
$
 36 
 
$
 2,750 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
 
 827 
 
 
 54,448 
 
 
 12,097 
 
 
 (29,616)
 
 
 37,756 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 389 
 
 
 - 
 
 
 (26)
 
 
 363 
Total Risk Management Assets
 
 827 
 
 
 54,837 
 
 
 12,097 
 
 
 (29,642)
 
 
 38,119 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 3,541 
 
$
 54,837 
 
$
 12,097 
 
$
 (29,606)
 
$
 40,869 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 700 
 
$
 49,220 
 
$
 1,535 
 
$
 (32,609)
 
$
 18,846 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 313 
 
 
 - 
 
 
 (26)
 
 
 287 
Total Risk Management Liabilities
$
 700 
 
$
 49,533 
 
$
 1,535 
 
$
 (32,635)
 
$
 19,133 

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2012
APCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 4,161 
 
$
 166,916 
 
$
 17,058 
 
$
 (123,117)
 
$
 65,018 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 498 
 
 
 - 
 
 
 (196)
 
 
 302 
Total Risk Management Assets
$
 4,161 
 
$
 167,414 
 
$
 17,058 
 
$
 (123,313)
 
$
 65,320 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 1,959 
 
$
 158,665 
 
$
 6,079 
 
$
 (132,884)
 
$
 33,819 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 1,551 
 
 
 - 
 
 
 (196)
 
 
 1,355 
Total Risk Management Liabilities
$
 1,959 
 
$
 160,216 
 
$
 6,079 
 
$
 (133,080)
 
$
 35,174 

 
325

 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013
I&M
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 561 
 
$
 38,667 
 
$
 8,205 
 
$
 (20,766)
 
$
 26,667 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 234 
 
 
 - 
 
 
 (18)
 
 
 216 
Total Risk Management Assets
 
 561 
 
 
 38,901 
 
 
 8,205 
 
 
 (20,784)
 
 
 26,883 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (c)
 
 8,082 
 
 
 - 
 
 
 - 
 
 
 10,722 
 
 
 18,804 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 - 
 
 
 608,875 
 
 
 - 
 
 
 - 
 
 
 608,875 
 
Corporate Debt
 
 - 
 
 
 36,782 
 
 
 - 
 
 
 - 
 
 
 36,782 
 
State and Local Government
 
 - 
 
 
 254,638 
 
 
 - 
 
 
 - 
 
 
 254,638 
 
 
Subtotal Fixed Income Securities
 
 - 
 
 
 900,295 
 
 
 - 
 
 
 - 
 
 
 900,295 
Equity Securities - Domestic (d)
 
 1,012,511 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,012,511 
Total Spent Nuclear Fuel and Decommissioning Trusts
 
 1,020,593 
 
 
 900,295 
 
 
 - 
 
 
 10,722 
 
 
 1,931,610 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 1,021,154 
 
$
 939,196 
 
$
 8,205 
 
$
 (10,062)
 
$
 1,958,493 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 475 
 
$
 35,061 
 
$
 1,041 
 
$
 (22,796)
 
$
 13,781 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 212 
 
 
 - 
 
 
 (18)
 
 
 194 
Total Risk Management Liabilities
$
 475 
 
$
 35,273 
 
$
 1,041 
 
$
 (22,814)
 
$
 13,975 

 
326

 
 
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
 
December 31, 2012
I&M
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 2,858 
 
$
 120,242 
 
$
 11,717 
 
$
 (84,474)
 
$
 50,343 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 330 
 
 
 - 
 
 
 (130)
 
 
 200 
Total Risk Management Assets
 
 2,858 
 
 
 120,572 
 
 
 11,717 
 
 
 (84,604)
 
 
 50,543 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (c)
 
 6,508 
 
 
 - 
 
 
 - 
 
 
 10,275 
 
 
 16,783 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 - 
 
 
 647,918 
 
 
 - 
 
 
 - 
 
 
 647,918 
 
Corporate Debt
 
 - 
 
 
 35,399 
 
 
 - 
 
 
 - 
 
 
 35,399 
 
State and Local Government
 
 - 
 
 
 270,090 
 
 
 - 
 
 
 - 
 
 
 270,090 
 
 
Subtotal Fixed Income Securities
 
 - 
 
 
 953,407 
 
 
 - 
 
 
 - 
 
 
 953,407 
Equity Securities - Domestic (d)
 
 735,582 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 735,582 
Total Spent Nuclear Fuel and Decommissioning Trusts
 
 742,090 
 
 
 953,407 
 
 
 - 
 
 
 10,275 
 
 
 1,705,772 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 744,948 
 
$
 1,073,979 
 
$
 11,717 
 
$
 (74,329)
 
$
 1,756,315 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 1,346 
 
$
 110,621 
 
$
 4,176 
 
$
 (91,183)
 
$
 24,960 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 1,061 
 
 
 - 
 
 
 (130)
 
 
 931 
 
Interest Rate/Foreign Currency Hedges
 
 - 
 
 
 19,524 
 
 
 - 
 
 
 - 
 
 
 19,524 
Total Risk Management Liabilities
$
 1,346 
 
$
 131,206 
 
$
 4,176 
 
$
 (91,313)
 
$
 45,415 

 
327

 
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2013
OPCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Cash Deposits (e)
$
 19,387 
 
$
 - 
 
$
 - 
 
$
 12 
 
$
 19,399 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
 
 - 
 
 
 - 
 
 
 3,269 
 
 
 (349)
 
 
 2,920 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 162 
 
 
 - 
 
 
 - 
 
 
 162 
Total Risk Management Assets
 
 - 
 
 
 162 
 
 
 3,269 
 
 
 (349)
 
 
 3,082 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 19,387 
 
$
 162 
 
$
 3,269 
 
$
 (337)
 
$
 22,481 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 - 
 
$
 - 
 
$
 349 
 
$
 (349)
 
$
 - 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Total Risk Management Liabilities
$
 - 
 
$
 - 
 
$
 349 
 
$
 (349)
 
$
 - 

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2012
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Cash Deposits (e)
$
 - 
 
$
 26 
 
$
 - 
 
$
 39 
 
$
 65 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
 
 5,848 
 
 
 238,254 
 
 
 23,973 
 
 
 (175,890)
 
 
 92,185 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 688 
 
 
 - 
 
 
 (272)
 
 
 416 
Total Risk Management Assets
 
 5,848 
 
 
 238,942 
 
 
 23,973 
 
 
 (176,162)
 
 
 92,601 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 5,848 
 
$
 238,968 
 
$
 23,973 
 
$
 (176,123)
 
$
 92,666 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 2,753 
 
$
 226,536 
 
$
 8,544 
 
$
 (189,616)
 
$
 48,217 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 2,175 
 
 
 - 
 
 
 (272)
 
 
 1,903 
Total Risk Management Liabilities
$
 2,753 
 
$
 228,711 
 
$
 8,544 
 
$
 (189,888)
 
$
 50,120 

 
328

 
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2013
PSO
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 - 
 
$
 1,078 
 
$
 - 
 
$
 5 
 
$
 1,083 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 84 
 
 
 - 
 
 
 - 
 
 
 84 
Total Risk Management Assets
$
 - 
 
$
 1,162 
 
$
 - 
 
$
 5 
 
$
 1,167 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 - 
 
$
 81 
 
$
 - 
 
$
 4 
 
$
 85 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Total Risk Management Liabilities
$
 - 
 
$
 81 
 
$
 - 
 
$
 4 
 
$
 85 

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2012
PSO
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 - 
 
$
 1,657 
 
$
 - 
 
$
 (1,142)
 
$
 515 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 42 
 
 
 - 
 
 
 (17)
 
 
 25 
Total Risk Management Assets
$
 - 
 
$
 1,699 
 
$
 - 
 
$
 (1,159)
 
$
 540 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 - 
 
$
 7,021 
 
$
 - 
 
$
 (1,142)
 
$
 5,879 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 17 
 
 
 - 
 
 
 (17)
 
 
 - 
Total Risk Management Liabilities
$
 - 
 
$
 7,038 
 
$
 - 
 
$
 (1,159)
 
$
 5,879 

 
329

 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2013
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (e)
$
 15,871 
 
$
 - 
 
$
 - 
 
$
 1,370 
 
$
 17,241 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
 
 - 
 
 
 1,233 
 
 
 - 
 
 
 (151)
 
 
 1,082 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 97 
 
 
 - 
 
 
 - 
 
 
 97 
Total Risk Management Assets
 
 - 
 
 
 1,330 
 
 
 - 
 
 
 (151)
 
 
 1,179 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 15,871 
 
$
 1,330 
 
$
 - 
 
$
 1,219 
 
$
 18,420 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 - 
 
$
 154 
 
$
 - 
 
$
 (154)
 
$
 - 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Total Risk Management Liabilities
$
 - 
 
$
 154 
 
$
 - 
 
$
 (154)
 
$
 - 

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2012
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 - 
 
$
 2,804 
 
$
 - 
 
$
 (2,133)
 
$
 671 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 41 
 
 
 - 
 
 
 (17)
 
 
 24 
Total Risk Management Assets
$
 - 
 
$
 2,845 
 
$
 - 
 
$
 (2,150)
 
$
 695 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (b)
$
 - 
 
$
 3,261 
 
$
 - 
 
$
 (2,133)
 
$
 1,128 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 17 
 
 
 - 
 
 
 (17)
 
 
 - 
Total Risk Management Liabilities
$
 - 
 
$
 3,278 
 
$
 - 
 
$
 (2,150)
 
$
 1,128 

(a)
Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”
(b)
Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
(c)
Amounts in “Other” column primarily represent accrued interest receivables from financial institutions.  Level 1 amounts primarily represent investments in money market funds.
(d)
Amounts represent publicly traded equity securities and equity-based mutual funds.
(e)
Amounts in “Other” column primarily represent cash deposits with third parties.  Level 1 and Level 2 amounts primarily represent investments in money market funds.

There have been no transfers between Level 1 and Level 2 during the years ended December 31, 2013, 2012 and 2011.

 
330

 
The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:

Year Ended December 31, 2013
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance as of December 31, 2012
 
$
 10,979 
 
$
 7,541 
 
$
 15,429 
 
$
 - 
 
$
 - 
Realized Gain (Loss) Included in Net Income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(or Changes in Net Assets) (a) (b)
 
 
 (3,568)
 
 
 (2,466)
 
 
 (5,042)
 
 
 - 
 
 
 - 
Unrealized Gain (Loss) Included in Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income (or Changes in Net Assets) Relating
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
to Assets Still Held at the Reporting Date (a)
 
 
 - 
 
 
 - 
 
 
 328 
 
 
 - 
 
 
 - 
Realized and Unrealized Gains (Losses)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Included in Other Comprehensive Income
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Purchases, Issuances and Settlements (c)
 
 
 481 
 
 
 390 
 
 
 765 
 
 
 - 
 
 
 - 
Transfers into Level 3 (d) (e)
 
 
 1,340 
 
 
 911 
 
 
 1,874 
 
 
 - 
 
 
 - 
Transfers out of Level 3 (e) (f)
 
 
 (925)
 
 
 (637)
 
 
 (1,303)
 
 
 - 
 
 
 - 
Transfer of OPCo Generation to Parent
 
 
 - 
 
 
 - 
 
 
 (12,051)
 
 
 - 
 
 
 - 
Changes in Fair Value Allocated to Regulated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jurisdictions (g)
 
 
 2,255 
 
 
 1,425 
 
 
 2,920 
 
 
 - 
 
 
 - 
Balance as of December 31, 2013
 
$
 10,562 
 
$
 7,164 
 
$
 2,920 
 
$
 - 
 
$
 - 

Year Ended December 31, 2012
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance as of December 31, 2011
 
$
 1,971 
 
$
 1,263 
 
$
 2,666 
 
$
 - 
 
$
 - 
Realized Gain (Loss) Included in Net Income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(or Changes in Net Assets) (a) (b)
 
 
 (5,204)
 
 
 (3,554)
 
 
 (7,452)
 
 
 - 
 
 
 - 
Unrealized Gain (Loss) Included in Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income (or Changes in Net Assets) Relating
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
to Assets Still Held at the Reporting Date (a)
 
 
 - 
 
 
 - 
 
 
 5,401 
 
 
 - 
 
 
 - 
Realized and Unrealized Gains (Losses)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Included in Other Comprehensive Income
 
 
 23 
 
 
 13 
 
 
 28 
 
 
 - 
 
 
 - 
Purchases, Issuances and Settlements (c)
 
 
 11,200 
 
 
 7,734 
 
 
 16,214 
 
 
 - 
 
 
 - 
Transfers into Level 3 (d) (e)
 
 
 1,392 
 
 
 860 
 
 
 1,909 
 
 
 - 
 
 
 - 
Transfers out of Level 3 (e) (f)
 
 
 (1,930)
 
 
 (1,144)
 
 
 (2,527)
 
 
 - 
 
 
 - 
Changes in Fair Value Allocated to Regulated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jurisdictions (g)
 
 
 3,527 
 
 
 2,369 
 
 
 (810)
 
 
 - 
 
 
 - 
Balance as of December 31, 2012
 
$
 10,979 
 
$
 7,541 
 
$
 15,429 
 
$
 - 
 
$
 - 
 
 
 
331

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2011
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance as of December 31, 2010
 
$
 5,131 
 
$
 3,108 
 
$
 6,583 
 
$
 1 
 
$
 2 
Realized Gain (Loss) Included in Net Income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(or Changes in Net Assets) (a) (b)
 
 
 (2,154)
 
 
 (1,261)
 
 
 (2,711)
 
 
 - 
 
 
 - 
Unrealized Gain (Loss) Included in Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income (or Changes in Net Assets) Relating
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
to Assets Still Held at the Reporting Date (a)
 
 
 - 
 
 
 - 
 
 
 7,741 
 
 
 - 
 
 
 - 
Realized and Unrealized Gains (Losses)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Included in Other Comprehensive Income
 
 
 (73)
 
 
 (47)
 
 
 (100)
 
 
 - 
 
 
 - 
Purchases, Issuances and Settlements (c)
 
 
 1,574 
 
 
 847 
 
 
 1,858 
 
 
 - 
 
 
 - 
Transfers into Level 3 (d) (e)
 
 
 2,488 
 
 
 1,531 
 
 
 3,257 
 
 
 - 
 
 
 - 
Transfers out of Level 3 (e) (f)
 
 
 (3,003)
 
 
 (1,906)
 
 
 (4,032)
 
 
 - 
 
 
 - 
Changes in Fair Value Allocated to Regulated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jurisdictions (g)
 
 
 (1,992)
 
 
 (1,009)
 
 
 (9,930)
 
 
 (1)
 
 
 (2)
Balance as of December 31, 2011
 
$
 1,971 
 
$
 1,263 
 
$
 2,666 
 
$
 - 
 
$
 - 

(a)
Included in revenues on the statements of income.
(b)
Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)
Represents the settlement of risk management commodity contracts for the reporting period.
(d)
Represents existing assets or liabilities that were previously categorized as Level 2.
(e)
Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
(f)
Represents existing assets or liabilities that were previously categorized as Level 3.
(g)
Relates to the net gains (losses) of those contracts that are not reflected on the statements of income.  These net gains (losses) are recorded as regulatory assets/liabilities.

The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of December 31, 2013 and 2012:

Significant Unobservable Inputs
December 31, 2013
APCo
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value
 
Valuation
 
Significant
 
Forward Price Range
 
 
Assets
 
Liabilities
 
Technique
 
Unobservable Input (a)
 
Low
 
High
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
 
$
 9,359 
 
$
 960 
 
Discounted Cash Flow
 
Forward Market Price 
 
 13.04 
 
 80.50 
FTRs
 
 
 2,738 
 
 
 575 
 
Discounted Cash Flow
 
Forward Market Price 
 
 
 (5.10)
 
 
 10.44 
Total
 
$
12,097 
 
$
1,535 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Significant Unobservable Inputs
December 31, 2012
APCo
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value
 
Valuation
 
Significant
 
Forward Price Range
 
 
Assets
 
Liabilities
 
Technique
 
Unobservable Input (a)
 
Low
 
High
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
 
$
 15,310 
 
$
 3,920 
 
Discounted Cash Flow
 
Forward Market Price 
 
 9.40 
 
 68.80 
FTRs
 
 
 1,748 
 
 
 2,159 
 
Discounted Cash Flow
 
Forward Market Price 
 
 
 (3.21)
 
 
 14.79 
Total
 
$
17,058 
 
$
6,079 
 
 
 
 
 
 
 
 
 
 
 

 
 
332

 
Significant Unobservable Inputs
December 31, 2013
I&M
 
 
 
 
 
 
 
 
 
 
 
Fair Value
 
Valuation
 
Significant
 
Forward Price Range
 
 
Assets
 
Liabilities
 
Technique
 
Unobservable Input (a)
 
Low
 
High
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
 
$
 6,348 
 
$
 651 
 
Discounted Cash Flow
 
Forward Market Price 
 
 13.04 
 
 80.50 
FTRs
 
 
 1,857 
 
 
 390 
 
Discounted Cash Flow
 
Forward Market Price 
 
 
 (5.10)
 
 
 10.44 
Total
 
$
8,205 
 
$
1,041 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Significant Unobservable Inputs
December 31, 2012
I&M
 
 
 
 
 
 
 
 
 
 
 
Fair Value
 
Valuation
 
Significant
 
Forward Price Range
 
 
Assets
 
Liabilities
 
Technique
 
Unobservable Input (a)
 
Low
 
High
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
 
$
 10,516 
 
$
 2,693 
 
Discounted Cash Flow
 
Forward Market Price 
 
 9.40 
 
 68.80 
FTRs
 
 
 1,201 
 
 
 1,483 
 
Discounted Cash Flow
 
Forward Market Price 
 
 
 (3.21)
 
 
 14.79 
Total
 
$
11,717 
 
$
4,176 
 
 
 
 
 
 
 
 
 
 

Significant Unobservable Inputs
December 31, 2013
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value
 
Valuation
 
Significant
 
Forward Price Range
 
 
Assets
 
Liabilities
 
Technique
 
Unobservable Input (a)
 
Low
 
High
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
 
$
 - 
 
$
 - 
 
Discounted Cash Flow
 
Forward Market Price 
 
 - 
 
 - 
FTRs
 
 
 3,269 
 
 
 349 
 
Discounted Cash Flow
 
Forward Market Price 
 
 
 (5.10)
 
 
 10.44 
Total
 
$
3,269 
 
$
349 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Significant Unobservable Inputs
December 31, 2012
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value
 
Valuation
 
Significant
 
Forward Price Range
 
 
Assets
 
Liabilities
 
Technique
 
Unobservable Input (a)
 
Low
 
High
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
Energy Contracts
 
$
 21,516 
 
$
 5,510 
 
Discounted Cash Flow
 
Forward Market Price 
 
 9.40 
 
 68.80 
FTRs
 
 
 2,457 
 
 
 3,034 
 
Discounted Cash Flow
 
Forward Market Price 
 
 
 (3.21)
 
 
 14.79 
Total
 
$
23,973 
 
$
8,544 
 
 
 
 
 
 
 
 
 
 
                                 
(a) Represents market prices in dollars per MWh. 
 
 
333

 
11.   INCOME TAXES

The details of the Registrant Subsidiaries’ income taxes as reported are as follows:

Year Ended December 31, 2013
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Income Tax Expense (Credit):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current
 
$
 58,441 
 
$
 (49,067)
 
$
 92,625 
 
$
 7,689 
 
$
 (10,866)
 
Deferred
 
 
 75,714 
 
 
 129,109 
 
 
 134,463 
 
 
 53,788 
 
 
 81,888 
 
Deferred Investment Tax Credits
 
 
 (1,220)
 
 
 (4,931)
 
 
 (1,418)
 
 
 4,408 
 
 
 (1,561)
Income Tax Expense
 
$
 132,935 
 
$
 75,111 
 
$
 225,670 
 
$
 65,885 
 
$
 69,461 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2012
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Income Tax Expense (Credit):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current
 
$
 28,307 
 
$
 (9,221)
 
$
 100,447 
 
$
 18,634 
 
$
 (214,353)
 
Deferred
 
 
 138,460 
 
 
 53,067 
 
 
 45,685 
 
 
 48,916 
 
 
 260,761 
 
Deferred Investment Tax Credits
 
 
 (1,240)
 
 
 (4,502)
 
 
 (1,849)
 
 
 (856)
 
 
 (550)
Income Tax Expense
 
$
 165,527 
 
$
 39,344 
 
$
 144,283 
 
$
 66,694 
 
$
 45,858 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2011
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Income Tax Expense (Credit):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current
 
$
 (15,136)
 
$
 (86,471)
 
$
 96,893 
 
$
 6,904 
 
$
 40,727 
 
Deferred
 
 
 107,565 
 
 
 141,014 
 
 
 119,184 
 
 
 61,581 
 
 
 16,726 
 
Deferred Investment Tax Credits
 
 
 (2,569)
 
 
 (2,783)
 
 
 (2,380)
 
 
 (856)
 
 
 (550)
Income Tax Expense
 
$
 89,860 
 
$
 51,760 
 
$
 213,697 
 
$
 67,629 
 
$
 56,903 

Shown below for each Registrant Subsidiary is a reconciliation of the difference between the amounts of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported:

APCo
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
(in thousands)
Net Income
$
 193,211 
 
$
 257,503 
 
$
 162,758 
Income Tax Expense
 
 132,935 
 
 
 165,527 
 
 
 89,860 
Pretax Income
$
 326,146 
 
$
 423,030 
 
$
 252,618 
 
 
 
 
 
 
 
 
 
Income Taxes on Pretax Income at Statutory Rate (35%)
$
 114,151 
 
$
 148,061 
 
$
 88,416 
Increase (Decrease) in Income Taxes Resulting from the Following Items:
 
 
 
 
 
 
 
 
 
 
Depreciation
 
 20,286 
 
 
 20,424 
 
 
 17,923 
 
 
Investment Tax Credits, Net
 
 (1,220)
 
 
 (1,240)
 
 
 (2,569)
 
 
State and Local Income Taxes, Net
 
 2,707 
 
 
 3,175 
 
 
 (35,532)
 
 
Removal Costs
 
 (6,454)
 
 
 (6,641)
 
 
 (4,447)
 
 
AFUDC
 
 (1,420)
 
 
 (1,145)
 
 
 (5,314)
 
 
Medicare Subsidy
 
 - 
 
 
 382 
 
 
 4,908 
 
 
Valuation Allowance
 
 5,062 
 
 
 5,674 
 
 
 30,541 
 
 
Other
 
 (177)
 
 
 (3,163)
 
 
 (4,066)
Income Tax Expense
$
 132,935 
 
$
 165,527 
 
$
 89,860 
 
 
 
 
 
 
 
 
 
Effective Income Tax Rate
 
 40.8 
%
 
 
 39.1 
%
 
 
 35.6 
%
 
 
 
334

 

 
I&M
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
(in thousands)
Net Income
$
 177,504 
 
$
 118,457 
 
$
 149,674 
Income Tax Expense
 
 75,111 
 
 
 39,344 
 
 
 51,760 
Pretax Income
$
 252,615 
 
$
 157,801 
 
$
 201,434 
 
 
 
 
 
 
 
 
 
Income Taxes on Pretax Income at Statutory Rate (35%)
$
 88,415 
 
$
 55,230 
 
$
 70,502 
Increase (Decrease) in Income Taxes Resulting from the Following Items:
 
 
 
 
 
 
 
 
 
 
Depreciation
 
 10,057 
 
 
 8,659 
 
 
 7,895 
 
 
Investment Tax Credits, Net
 
 (4,931)
 
 
 (4,502)
 
 
 (2,783)
 
 
State and Local Income Taxes, Net
 
 (882)
 
 
 (1,559)
 
 
 (1,376)
 
 
Removal Costs
 
 (9,432)
 
 
 (5,490)
 
 
 (5,566)
 
 
AFUDC
 
 (10,555)
 
 
 (7,218)
 
 
 (9,223)
 
 
Other
 
 2,439 
 
 
 (5,776)
 
 
 (7,689)
Income Tax Expense
$
 75,111 
 
$
 39,344 
 
$
 51,760 
 
 
 
 
 
 
 
 
 
Effective Income Tax Rate
 
 29.7 
%
 
 
 24.9 
%
 
 
 25.7 
%

OPCo
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
(in thousands)
Net Income
$
 409,980 
 
$
 343,534 
 
$
 464,993 
Income Tax Expense
 
 225,670 
 
 
 144,283 
 
 
 213,697 
Pretax Income
$
 635,650 
 
$
 487,817 
 
$
 678,690 
 
 
 
 
 
 
 
 
 
Income Taxes on Pretax Income at Statutory Rate (35%)
$
 222,478 
 
$
 170,736 
 
$
 237,542 
Increase (Decrease) in Income Taxes Resulting from the Following Items:
 
 
 
 
 
 
 
 
 
 
Depreciation
 
 6,759 
 
 
 5,239 
 
 
 6,368 
 
 
Investment Tax Credits, Net
 
 (1,418)
 
 
 (1,849)
 
 
 (2,380)
 
 
State and Local Income Taxes, Net
 
 3,327 
 
 
 (18,291)
 
 
 (3,222)
 
 
Parent Company Loss Benefit
 
 (2,154)
 
 
 (11,915)
 
 
 (7,117)
 
 
Other
 
 (3,322)
 
 
 363 
 
 
 (17,494)
Income Tax Expense
$
 225,670 
 
$
 144,283 
 
$
 213,697 
 
 
 
 
 
 
 
 
 
Effective Income Tax Rate
 
 35.5 
%
 
 
 29.6 
%
 
 
 31.5 
%

PSO
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
(in thousands)
Net Income
$
 97,796 
 
$
 114,141 
 
$
 124,628 
Income Tax Expense
 
 65,885 
 
 
 66,694 
 
 
 67,629 
Pretax Income
$
 163,681 
 
$
 180,835 
 
$
 192,257 
 
 
 
 
 
 
 
 
 
Income Taxes on Pretax Income at Statutory Rate (35%)
$
 57,288 
 
$
 63,292 
 
$
 67,290 
Increase (Decrease) in Income Taxes Resulting from the Following Items:
 
 
 
 
 
 
 
 
 
 
Depreciation
 
 164 
 
 
 (10)
 
 
 (165)
 
 
Investment Tax Credits, Net
 
 (776)
 
 
 (781)
 
 
 (781)
 
 
State and Local Income Taxes, Net
 
 5,423 
 
 
 6,953 
 
 
 4,744 
 
 
Tax Adjustments
 
 5,268 
 
 
 201 
 
 
 (1,827)
 
 
Other
 
 (1,482)
 
 
 (2,961)
 
 
 (1,632)
Income Tax Expense
$
 65,885 
 
$
 66,694 
 
$
 67,629 
 
 
 
 
 
 
 
 
 
Effective Income Tax Rate
 
 40.3 
%
 
 
 36.9 
%
 
 
 35.2 
%


 
335

 
 
SWEPCo
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
(in thousands)
Net Income
$
 153,819 
 
$
 202,513 
 
$
 165,126 
Income Tax Expense
 
 69,461 
 
 
 45,858 
 
 
 56,903 
Pretax Income
$
 223,280 
 
$
 248,371 
 
$
 222,029 
 
 
 
 
 
 
 
 
 
Income Taxes on Pretax Income at Statutory Rate (35%)
$
 78,148 
 
$
 86,930 
 
$
 77,710 
Increase (Decrease) in Income Taxes Resulting from the Following Items:
 
 
 
 
 
 
 
 
 
 
Depreciation
 
 3,086 
 
 
 2,105 
 
 
 (7)
 
 
Depletion
 
 (3,472)
 
 
 (3,276)
 
 
 (1,506)
 
 
Investment Tax Credits, Net
 
 (1,561)
 
 
 (550)
 
 
 (550)
 
 
State and Local Income Taxes, Net
 
 (1,453)
 
 
 (18,010)
 
 
 4,004 
 
 
AFUDC
 
 (2,381)
 
 
 (19,879)
 
 
 (16,962)
 
 
Other
 
 (2,906)
 
 
 (1,462)
 
 
 (5,786)
Income Tax Expense
$
 69,461 
 
$
 45,858 
 
$
 56,903 
 
 
 
 
 
 
 
 
 
Effective Income Tax Rate
 
 31.1 
%
 
 
 18.5 
%
 
 
 25.6 
%

The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant Subsidiary:

APCo
 
December 31,
 
 
2013 
 
2012 
 
 
(in thousands)
Deferred Tax Assets
 
$
 548,966 
 
$
 526,665 
Deferred Tax Liabilities
 
 
 (2,788,306)
 
 
 (2,467,063)
Net Deferred Tax Liabilities
 
$
 (2,239,340)
 
$
 (1,940,398)
 
 
 
 
 
 
 
Property Related Temporary Differences
 
$
 (1,725,853)
 
$
 (1,416,426)
Amounts Due from Customers for Future Federal Income Taxes
 
 
 (94,775)
 
 
 (100,520)
Deferred State Income Taxes
 
 
 (246,247)
 
 
 (230,490)
Regulatory Assets
 
 
 (104,824)
 
 
 (161,274)
Securitized Assets
 
 
 (130,834)
 
 
 - 
Deferred Income Taxes on Other Comprehensive Loss
 
 
 (1,589)
 
 
 16,099 
Deferred Fuel and Purchased Power
 
 
 24,646 
 
 
 (115,900)
Net Operating Loss Carryforward
 
 
 45,177 
 
 
 69,580 
Tax Credit Carryforward
 
 
 21,940 
 
 
 13,199 
Valuation Allowance
 
 
 (41,277)
 
 
 (36,215)
All Other, Net
 
 
 14,296 
 
 
 21,549 
Net Deferred Tax Liabilities
 
$
 (2,239,340)
 
$
 (1,940,398)

I&M
 
December 31,
 
 
2013 
 
2012 
 
 
(in thousands)
Deferred Tax Assets
 
$
 843,630 
 
$
 831,724 
Deferred Tax Liabilities
 
 
 (2,043,810)
 
 
 (1,842,791)
Net Deferred Tax Liabilities
 
$
 (1,200,180)
 
$
 (1,011,067)
 
 
 
 
 
 
 
Property Related Temporary Differences
 
$
 (390,829)
 
$
 (351,682)
Amounts Due from Customers for Future Federal Income Taxes
 
 
 (39,137)
 
 
 (37,633)
Deferred State Income Taxes
 
 
 (137,162)
 
 
 (112,388)
Deferred Income Taxes on Other Comprehensive Loss
 
 
 8,351 
 
 
 15,553 
Accrued Nuclear Decommissioning
 
 
 (553,794)
 
 
 (475,223)
Net Operating Loss Carryforward
 
 
 15,690 
 
 
 31,233 
Regulatory Assets
 
 
 (59,008)
 
 
 (88,696)
All Other, Net
 
 
 (44,291)
 
 
 7,769 
Net Deferred Tax Liabilities
 
$
 (1,200,180)
 
$
 (1,011,067)
 

 
 
336

 
OPCo
 
December 31,
 
 
2013 
 
2012 
 
 
(in thousands)
Deferred Tax Assets
 
$
 183,085 
 
$
 505,003 
Deferred Tax Liabilities
 
 
 (1,477,691)
 
 
 (2,851,068)
Net Deferred Tax Liabilities
 
$
 (1,294,606)
 
$
 (2,346,065)
 
 
 
 
 
 
 
Property Related Temporary Differences
 
$
 (841,607)
 
$
 (2,061,841)
Amounts Due from Customers for Future Federal Income Taxes
 
 
 (51,946)
 
 
 (59,291)
Deferred State Income Taxes
 
 
 (28,569)
 
 
 (90,001)
Regulatory Assets
 
 
 (215,535)
 
 
 (190,273)
Deferred Income Taxes on Other Comprehensive Loss
 
 
 (3,812)
 
 
 89,236 
Impairment Loss
 
 
 - 
 
 
 100,459 
Deferred Fuel and Purchased Power
 
 
 (176,192)
 
 
 (199,997)
All Other, Net
 
 
 23,055 
 
 
 65,643 
Net Deferred Tax Liabilities
 
$
 (1,294,606)
 
$
 (2,346,065)

PSO
 
December 31,
 
 
2013 
 
2012 
 
 
(in thousands)
Deferred Tax Assets
 
$
 107,567 
 
$
 101,561 
Deferred Tax Liabilities
 
 
 (936,791)
 
 
 (835,054)
Net Deferred Tax Liabilities
 
$
 (829,224)
 
$
 (733,493)
 
 
 
 
 
 
 
Property Related Temporary Differences
 
$
 (736,160)
 
$
 (640,859)
Amounts Due from Customers for Future Federal Income Taxes
 
 
 (31)
 
 
 (1,325)
Deferred State Income Taxes
 
 
 (99,126)
 
 
 (95,378)
Regulatory Assets
 
 
 (39,414)
 
 
 (57,367)
Deferred Income Taxes on Other Comprehensive Loss
 
 
 (3,100)
 
 
 (3,489)
Deferred Federal Income Taxes on Deferred State Income Taxes
 
 
 40,362 
 
 
 39,050 
Net Operating Loss Carryforward
 
 
 4,314 
 
 
 3,892 
Tax Credit Carryforward
 
 
 565 
 
 
 401 
All Other, Net
 
 
 3,366 
 
 
 21,582 
Net Deferred Tax Liabilities
 
$
 (829,224)
 
$
 (733,493)

SWEPCo
 
December 31,
 
 
2013 
 
2012 
 
 
(in thousands)
Deferred Tax Assets
 
$
 359,529 
 
$
 286,133 
Deferred Tax Liabilities
 
 
 (1,453,710)
 
 
 (1,260,281)
Net Deferred Tax Liabilities
 
$
 (1,094,181)
 
$
 (974,148)
 
 
 
 
 
 
 
Property Related Temporary Differences
 
$
 (1,172,431)
 
$
 (997,337)
Amounts Due from Customers for Future Federal Income Taxes
 
 
 (43,116)
 
 
 (43,090)
Deferred State Income Taxes
 
 
 (118,179)
 
 
 (98,630)
Regulatory Assets
 
 
 (5,290)
 
 
 (12,922)
Deferred Income Taxes on Other Comprehensive Loss
 
 
 4,548 
 
 
 9,618 
Impairment Loss - Turk Plant
 
 
 21,295 
 
 
 21,700 
Net Operating Loss Carryforward
 
 
 189,128 
 
 
 104,738 
All Other, Net
 
 
 29,864 
 
 
 41,775 
Net Deferred Tax Liabilities
 
$
 (1,094,181)
 
$
 (974,148)


 
337

 

AEP System Tax Allocation Agreement

The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System.  The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense.  The tax benefit of the Parent is allocated to its subsidiaries with taxable income.  With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

Federal and State Income Tax Audit Status

The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2011.  The Registrant Subsidiaries completed the examination of the years 2007 and 2008 in April 2011 and settled all outstanding issues on appeal for the years 2001 through 2006 in October 2011.  The settlements did not materially impact the Registrant Subsidiaries’ net income, cash flows or financial condition.  The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013.  Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters.  In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions.  Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income.

The Registrant Subsidiaries file income tax returns in various state and local jurisdictions.  These taxing authorities routinely examine their tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions.  However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities.  Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income.  The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009.

Net Income Tax Operating Loss Carryforward

In 2011, APCo and I&M recognized federal net income tax operating losses of $313 million and $123 million, respectively, driven primarily by bonus depreciation, pension plan contributions and other book versus tax temporary differences.  In 2012, SWEPCo recognized a federal net income tax operating loss of $858 million driven primarily by bonus depreciation.  APCo, I&M, OPCo, PSO and SWEPCo also had state net income tax operating loss carryforwards as indicated in the table below.

 
 
 
 
 
State Net Income
 
 
 
 
 
 
 
Tax Operating
 
 
 
 
 
 
Loss
 
Year of
Company
 
State
 
Carryforward
 
Expiration
 
 
 
 
 
(in thousands)
 
 
 
APCo
 
Tennessee 
 
$
 8,810 
 
 
2026 
APCo
 
Virginia 
 
 
 300,637 
 
 
2031 
APCo
 
West Virginia 
 
 
 489,860 
 
 
2032 
I&M
 
Indiana 
 
 
 50,425 
 
 
2033 
OPCo
 
West Virginia 
 
 
 235,636 
 
 
2032 
PSO
 
Oklahoma 
 
 
 110,615 
 
 
2033 
SWEPCo
 
Louisiana 
 
 
 422,946 
 
 
2028 
SWEPCo
 
Oklahoma 
 
 
 2,835 
 
 
2033 

 
338

 
As a result, APCo, I&M, OPCo, PSO and SWEPCo recognized deferred federal and/or state and local income tax benefits in 2011 and/or 2012 and/or 2013.  At the end of 2013, APCo, I&M and SWEPCo have $12 million, $13 million and $167 million, respectively, of unrealized federal net operating loss carryforward.  Management anticipates future taxable income will be sufficient to realize the remaining net income tax operating loss tax benefits before the federal carryforward expires after 2032.  Management also anticipates future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the state carryforward expires for each state.

Tax Credit Carryforward

Federal and state net income tax operating losses sustained in 2011 and 2009 along with lower federal and state taxable income in 2010 resulted in unused federal and state income tax credits.  As of December 31, 2013, the Registrant Subsidiaries have federal tax credit carryforwards and APCo and PSO have state tax credit carryforwards as indicated in the table below.  If these credits are not utilized, federal general business tax credits will expire in the years 2029 through 2032 and state coal tax credits will expire in the years 2014 through 2022.

 
 
 
 
 
Federal Tax
 
 
 
State Tax
 
 
 
 
 
Credit
 
 
 
 
Credit
 
 
Total Federal
 
Carryforward
 
Total State
 
Carryforward
 
 
Tax Credit
 
Subject to
 
Tax Credit
 
Subject to
Company
 
Carryforward
 
Expiration
 
Carryforward
 
Expiration
 
 
(in thousands)
APCo
 
$
 21,432 
 
$
 8,504 
 
$
 76,481 
 
$
 28,255 
I&M
 
 
 2,587 
 
 
 2,587 
 
 
 - 
 
 
 - 
OPCo
 
 
 20,000 
 
 
 1,714 
 
 
 - 
 
 
 - 
PSO
 
 
 565 
 
 
 543 
 
 
 21,114 
 
 
 21,114 
SWEPCo
 
 
 884 
 
 
 759 
 
 
 - 
 
 
 - 

The Registrant Subsidiaries anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused.  APCo does not anticipate that state taxable income will be sufficient in future periods to realize the tax benefits of all state tax credits before they expire unused and a valuation allowance has been provided accordingly.

Valuation Allowance

Management assesses past results and future operations to estimate and evaluate available positive and negative evidence to determine whether sufficient future taxable income will be generated to use existing deferred tax assets.  A significant piece of objective negative information evaluated was the net income tax operating losses sustained in 2012, 2011 and 2009.  The positive evidence considered by management includes the history of positive pretax income and the fact that the tax losses resulted from temporary differences that will reverse in future periods.  On the basis of the evaluation of all available positive and negative evidence, as of December 31, 2013, a valuation allowance of $41.3 million for state tax credits, net of federal tax, has been recorded by APCo in order to recognize only the portion of the deferred tax assets that, more likely than not, will be realized.  The amount of the deferred tax assets realizable, however, could be adjusted if estimates of future taxable income during the carryforward period are materially impacted.

 
339

 
Uncertain Tax Positions

The Registrant Subsidiaries recognize interest accruals related to uncertain tax positions in interest income or expense as applicable and penalties in Other Operation expense in accordance with the accounting guidance for “Income Taxes.”

The following tables show amounts reported for interest expense, interest income and reversal of prior period interest expense:

 
 
Years Ended December 31,
 
 
2013 
 
2012 
 
 
 
 
 
 
Reversal of
 
 
 
 
 
Reversal of
 
 
 
 
 
 
Prior Period
 
 
 
 
 
Prior Period
 
 
Interest
 
Interest
 
Interest
 
Interest
 
Interest
 
Interest
Company
 
Expense
 
Income
 
Expense
 
Expense
 
Income
 
Expense
 
 
(in thousands)
APCo
 
$
 - 
 
$
 1,089 
 
$
 - 
 
$
 62 
 
$
 - 
 
$
 183 
I&M
 
 
 - 
 
 
 597 
 
 
 - 
 
 
 1,355 
 
 
 - 
 
 
 - 
OPCo
 
 
 - 
 
 
 1,892 
 
 
 - 
 
 
 266 
 
 
 - 
 
 
 504 
PSO
 
 
 - 
 
 
 135 
 
 
 - 
 
 
 259 
 
 
 - 
 
 
 294 
SWEPCo
 
 
 215 
 
 
 - 
 
 
 - 
 
 
 286 
 
 
 - 
 
 
 271 

 
 
Year Ended December 31, 2011
 
 
 
 
 
 
Reversal of
 
 
 
 
 
 
 
 
Prior Period
 
 
Interest
 
Interest
 
Interest
Company
 
Expense
 
Income
 
Expense
 
 
(in thousands)
APCo
 
$
 737 
 
$
 3,229 
 
$
 2,416 
I&M
 
 
 - 
 
 
 2,681 
 
 
 638 
OPCo
 
 
 1,213 
 
 
 5,173 
 
 
 4,019 
PSO
 
 
 239 
 
 
 344 
 
 
 3,123 
SWEPCo
 
 
 1,382 
 
 
 1,991 
 
 
 2,255 

The following table shows balances for amounts accrued for the receipt of interest:

 
 
December 31,
Company
 
2013 
 
2012 
 
 
(in thousands)
APCo
 
$
 - 
 
$
 - 
I&M
 
 
 - 
 
 
 - 
OPCo
 
 
 - 
 
 
 - 
PSO
 
 
 209 
 
 
 15 
SWEPCo
 
 
 172 
 
 
 - 

The following table shows balances for amounts accrued for the payment of interest and penalties:

 
 
December 31,
Company
 
2013 
 
2012 
 
 
(in thousands)
APCo
 
$
 158 
 
$
 271 
I&M
 
 
 957 
 
 
 1,337 
OPCo
 
 
 407 
 
 
 451 
PSO
 
 
 562 
 
 
 424 
SWEPCo
 
 
 1,167 
 
 
 1,061 


 
340

 
 
The reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
(in thousands)
Balance as of January 1, 2013
$
 5,253 
 
$
 15,085 
 
$
 11,052 
 
$
 2,273 
 
$
 9,553 
Increase - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 a Prior Period
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Decrease - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 a Prior Period
 
 (4,089)
 
 
 (11,921)
 
 
 (8,966)
 
 
 (103)
 
 
 (3,158)
Increase - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 the Current Year
 
 - 
 
 
 - 
 
 
 - 
 
 
 14 
 
 
 1,301 
Decrease - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 the Current Year
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Decrease - Settlements with Taxing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Authorities
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (94)
Decrease - Lapse of the Applicable
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Statute of Limitations
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Balance as of December 31, 2013
$
 1,164 
 
$
 3,164 
 
$
 2,086 
 
$
 2,184 
 
$
 7,602 

 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
(in thousands)
Balance as of January 1, 2012
$
 7,311 
 
$
 14,071 
 
$
 43,565 
 
$
 3,585 
 
$
 9,031 
Increase - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 a Prior Period
 
 - 
 
 
 2,266 
 
 
 1,360 
 
 
 421 
 
 
 2,806 
Decrease - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 a Prior Period
 
 (384)
 
 
 (1,252)
 
 
 (13,582)
 
 
 (92)
 
 
 (775)
Increase - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 the Current Year
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Decrease - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 the Current Year
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Decrease - Settlements with Taxing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Authorities
 
 (1,674)
 
 
 - 
 
 
 (20,291)
 
 
 - 
 
 
 - 
Decrease - Lapse of the Applicable
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Statute of Limitations
 
 - 
 
 
 - 
 
 
 - 
 
 
 (1,641)
 
 
 (1,509)
Balance as of December 31, 2012
$
 5,253 
 
$
 15,085 
 
$
 11,052 
 
$
 2,273 
 
$
 9,553 

 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
(in thousands)
Balance as of January 1, 2011
$
 13,267 
 
$
 17,871 
 
$
 68,655 
 
$
 9,845 
 
$
 14,410 
Increase - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 a Prior Period
 
 5,990 
 
 
 9,256 
 
 
 11,330 
 
 
 1,339 
 
 
 14,355 
Decrease - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 a Prior Period
 
 (2,100)
 
 
 (8,622)
 
 
 (20,299)
 
 
 (1,171)
 
 
 (2,706)
Increase - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 the Current Year
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Decrease - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 the Current Year
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Decrease - Settlements with Taxing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Authorities
 
 (2,587)
 
 
 (1,424)
 
 
 (6,935)
 
 
 (1,178)
 
 
 (12,997)
Decrease - Lapse of the Applicable
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Statute of Limitations
 
 (7,259)
 
 
 (3,010)
 
 
 (9,186)
 
 
 (5,250)
 
 
 (4,031)
Balance as of December 31, 2011
$
 7,311 
 
$
 14,071 
 
$
 43,565 
 
$
 3,585 
 
$
 9,031 


 
341

 
 
Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date.  The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for each Registrant Subsidiary was as follows:

Company
 
2013 
 
2012 
 
2011 
 
 
(in thousands)
APCo
 
$
 - 
 
$
 - 
 
$
 806 
I&M
 
 
 1,220 
 
 
 1,220 
 
 
 654 
OPCo
 
 
 674 
 
 
 674 
 
 
 21,177 
PSO
 
 
 827 
 
 
 818 
 
 
 1,882 
SWEPCo
 
 
 4,357 
 
 
 3,512 
 
 
 3,717 

Federal Tax Legislation – Affecting APCo, I&M, OPCo, PSO and SWEPCo

The American Taxpayer Relief Act of 2012 (the 2012 Act) was enacted in January 2013.  Included in the 2012 Act was a one-year extension of 50% bonus depreciation.  The 2012 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2011.  The enacted provisions will not materially impact the Registrant Subsidiaries’ net income or financial condition but did have a favorable impact on cash flows in 2013.

Federal Tax Regulations

In 2013, the U.S. Treasury Department issued final and re-proposed regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014.  In addition, the IRS issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry.  The impact of these final regulations is not material to net income, cash flows or financial condition except for an approximate $10 million reduction to I&M’s cash flows in 2014.

State Tax Legislation – Affecting APCo, I&M and OPCo

Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rate from 8.5% to 6.5%.  The 8.5% Indiana corporate income tax rate will be reduced 0.5% each year beginning after June 30, 2012 with the final reduction occurring in years beginning after June 30, 2015.

In May 2011, Michigan repealed its Business Tax regime and replaced it with a traditional corporate net income tax rate of 6%, effective January 1, 2012.

During the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds.  As a result, the West Virginia corporate income tax rate will be reduced from 7.0% to 6.5% in 2014.  The enacted provisions will not materially impact the Registrant Subsidiaries’ net income, cash flows or financial condition.

12.   LEASES

Leases of property, plant and equipment are for remaining periods up to 36 years and require payments of related property taxes, maintenance and operating costs.  The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.


 
342

 

Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations.  Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period.  Capital leases for nonregulated property are accounted for as if the assets were owned and financed.  The components of rental costs are as follows:

Year Ended December 31, 2013
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Net Lease Expense on Operating Leases
 
$
 17,500 
 
$
 95,606 
 
$
 57,814 
 
$
 4,131 
 
$
 6,328 
Amortization of Capital Leases
 
 
 6,293 
 
 
 11,307 
 
 
 7,800 
 
 
 4,099 
 
 
 15,456 
Interest on Capital Leases
 
 
 1,410 
 
 
 1,870 
 
 
 4,125 
 
 
 782 
 
 
 8,153 
Total Lease Rental Costs
 
$
 25,203 
 
$
 108,783 
 
$
 69,739 
 
$
 9,012 
 
$
 29,937 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2012
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Net Lease Expense on Operating Leases
 
$
 15,633 
 
$
 95,509 
 
$
 59,836 
 
$
 5,283 
 
$
 5,797 
Amortization of Capital Leases
 
 
 7,429 
 
 
 8,429 
 
 
 10,906 
 
 
 3,839 
 
 
 14,793 
Interest on Capital Leases
 
 
 1,782 
 
 
 1,738 
 
 
 3,307 
 
 
 815 
 
 
 9,041 
Total Lease Rental Costs
 
$
 24,844 
 
$
 105,676 
 
$
 74,049 
 
$
 9,937 
 
$
 29,631 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2011
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Net Lease Expense on Operating Leases
 
$
 13,488 
 
$
 94,317 
 
$
 59,983 
 
$
 6,532 
 
$
 5,990 
Amortization of Capital Leases
 
 
 7,880 
 
 
 8,762 
 
 
 13,118 
 
 
 4,438 
 
 
 12,694 
Interest on Capital Leases
 
 
 1,898 
 
 
 2,115 
 
 
 3,753 
 
 
 1,098 
 
 
 9,651 
Total Lease Rental Costs
 
$
 23,266 
 
$
 105,194 
 
$
 76,854 
 
$
 12,068 
 
$
 28,335 

The following table shows the property, plant and equipment under capital leases and related obligations recorded on the Registrant Subsidiaries’ balance sheets.  Unless shown as a separate line on the balance sheet due to materiality, current capital lease obligations are included in Other Current Liabilities and long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrant Subsidiaries’ balance sheets.

December 31, 2013
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Property, Plant and Equipment Under
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital Leases:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Generation
 
$
 13,531 
 
$
 18,324 
 
$
 - 
 
$
 9,675 
 
$
 34,476 
Other Property, Plant and Equipment
 
 
 18,720 
 
 
 130,249 
 
 
 26,532 
 
 
 15,413 
 
 
 157,853 
Total Property, Plant and Equipment
 
 
 32,251 
 
 
 148,573 
 
 
 26,532 
 
 
 25,088 
 
 
 192,329 
Accumulated Amortization
 
 
 11,379 
 
 
 15,356 
 
 
 9,800 
 
 
 10,957 
 
 
 66,637 
Net Property, Plant and Equipment
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Under Capital Leases
 
$
 20,872 
 
$
 133,217 
 
$
 16,732 
 
$
 14,131 
 
$
 125,692 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Obligations Under Capital Leases:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncurrent Liability
 
$
 15,718 
 
$
 87,000 
 
$
 11,212 
 
$
 10,222 
 
$
 105,086 
Liability Due Within One Year
 
 
 5,154 
 
 
 46,210 
 
 
 5,520 
 
 
 3,909 
 
 
 17,899 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Obligations Under Capital Leases
 
$
 20,872 
 
$
 133,210 
 
$
 16,732 
 
$
 14,131 
 
$
 122,985 

December 31, 2012
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Property, Plant and Equipment Under
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital Leases:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Generation
 
$
 11,798 
 
$
 19,102 
 
$
 39,080 
 
$
 3,624 
 
$
 27,745 
Other Property, Plant and Equipment
 
 
 20,944 
 
 
 22,697 
 
 
 35,666 
 
 
 15,614 
 
 
 154,166 
Total Property, Plant and Equipment
 
 
 32,742 
 
 
 41,799 
 
 
 74,746 
 
 
 19,238 
 
 
 181,911 
Accumulated Amortization
 
 
 10,282 
 
 
 13,154 
 
 
 27,513 
 
 
 6,738 
 
 
 50,440 
Net Property, Plant and Equipment
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Under Capital Leases
 
$
 22,460 
 
$
 28,645 
 
$
 47,233 
 
$
 12,500 
 
$
 131,471 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Obligations Under Capital Leases:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncurrent Liability
 
$
 16,375 
 
$
 22,842 
 
$
 36,381 
 
$
 8,864 
 
$
 114,161 
Liability Due Within One Year
 
 
 6,085 
 
 
 5,803 
 
 
 14,707 
 
 
 3,636 
 
 
 17,599 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Obligations Under Capital Leases
 
$
 22,460 
 
$
 28,645 
 
$
 51,088 
 
$
 12,500 
 
$
 131,760 
 
 
 
343

 
Future minimum lease payments consisted of the following as of December 31, 2013:

Capital Leases
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
2014 
 
$
 5,930 
 
$
 49,685 
 
$
 6,224 
 
$
 4,548 
 
$
 25,172 
2015 
 
 
 4,789 
 
 
 39,468 
 
 
 3,217 
 
 
 3,174 
 
 
 22,837 
2016 
 
 
 4,247 
 
 
 31,053 
 
 
 2,762 
 
 
 2,828 
 
 
 19,871 
2017 
 
 
 3,610 
 
 
 9,512 
 
 
 2,697 
 
 
 2,834 
 
 
 21,247 
2018 
 
 
 2,602 
 
 
 4,338 
 
 
 2,136 
 
 
 1,798 
 
 
 11,134 
Later Years
 
 
 2,079 
 
 
 10,244 
 
 
 1,914 
 
 
 1,127 
 
 
 55,475 
Total Future Minimum Lease
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Payments
 
 
 23,257 
 
 
 144,300 
 
 
 18,950 
 
 
 16,309 
 
 
 155,736 
Less Estimated Interest Element
 
 
 2,385 
 
 
 11,090 
 
 
 2,218 
 
 
 2,178 
 
 
 32,751 
Estimated Present Value of Future
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Minimum Lease Payments
 
$
 20,872 
 
$
 133,210 
 
$
 16,732 
 
$
 14,131 
 
$
 122,985 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncancelable Operating Leases
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
2014 
 
$
 16,327 
 
$
 98,819 
 
$
 11,986 
 
$
 2,241 
 
$
 5,010 
2015 
 
 
 12,976 
 
 
 95,935 
 
 
 10,817 
 
 
 2,004 
 
 
 4,369 
2016 
 
 
 12,111 
 
 
 90,431 
 
 
 10,097 
 
 
 1,654 
 
 
 3,721 
2017 
 
 
 11,661 
 
 
 84,624 
 
 
 9,575 
 
 
 1,487 
 
 
 3,338 
2018 
 
 
 10,737 
 
 
 83,525 
 
 
 8,292 
 
 
 1,123 
 
 
 2,887 
Later Years
 
 
 46,452 
 
 
 341,472 
 
 
 31,627 
 
 
 2,031 
 
 
 14,823 
Total Future Minimum Lease
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Payments
 
$
 110,264 
 
$
 794,806 
 
$
 82,394 
 
$
 10,540 
 
$
 34,148 

Master Lease Agreements

The Registrant Subsidiaries lease certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee.  Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.  As of December 31, 2013, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows:

 
 
Maximum
Company
 
Potential Loss
 
 
(in thousands)
APCo
 
$
 3,696 
I&M
 
 
 2,548 
OPCo
 
 
 4,555 
PSO
 
 
 1,354 
SWEPCo
 
 
 2,366 


Rockport Lease

AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant).  The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors.


 
344

 

The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022.  The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M.  The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note.  The lease term is for 33 years with potential renewal options.  At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant.  AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt.  I&M’s future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2013 are as follows:

Future Minimum Lease Payments
 
I&M
 
 
 
(in thousands)
2014 
 
$
 73,854 
2015 
 
 
 73,854 
2016 
 
 
 73,854 
2017 
 
 
 73,854 
2018 
 
 
 73,854 
Later Years
 
 
 295,416 
Total Future Minimum Lease Payments
 
$
 664,686 

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease is accounted for as an operating lease.  In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignment is accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $13 million and $15 million for I&M and SWEPCo, respectively, for the remaining railcars as of December 31, 2013.  These obligations are included in the future minimum lease payments schedule earlier in this note.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 83% of the projected fair value of the equipment under the current five-year lease term to 77% at the end of the 20-year term.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  The maximum potential losses related to the guarantee are approximately $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term.  However, management believes that the fair value would produce a sufficient sales price to avoid any loss.

Sabine Dragline Lease

During 2009, Sabine entered into capital lease arrangements with a nonaffiliated company to finance the purchase of two electric draglines to be used for Sabine’s mining operations totaling $47 million.  The amounts included in the lease represented the aggregate fair value of the existing equipment and a sale-and-leaseback transaction for additional dragline rebuild costs required to keep the dragline operational.  These capital lease assets are included in Other Property, Plant and Equipment on SWEPCo’s December 31, 2013 and 2012 balance sheets.  The short-term and long-term capital lease obligations are included in Obligations Under Capital Leases on SWEPCo’s December 31, 2013 and 2012 balance sheets.  The future payment obligations are included in SWEPCo’s future minimum lease payments schedule earlier in this note.

I&M Nuclear Fuel Lease

In November 2013, I&M entered into a sale-and-leaseback transaction with IMP 11-2013, a nonaffiliated Ohio trust, to lease nuclear fuel for I&M’s Cook Plant.  In November 2013, I&M sold a portion of its unamortized nuclear fuel inventory to the trust for $110 million.  The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 54 months.  The future payment obligations of $110 million are included in I&M’s future minimum lease payments schedule earlier in this note.  The net capital lease asset is included in Other Property, Plant and Equipment and the short-term and long-term capital lease obligations are included in
 
 
345

 
Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities, respectively, on I&M’s December 31, 2013 balance sheet.  The future minimum lease payments for the sale-and-leaseback transaction as of December 31, 2013 are as follows, based on estimated fuel burn:

Future Minimum Lease Payments
 
I&M
 
 
 
(in thousands)
2014 
 
$
 42,567 
2015 
 
 
 32,198 
2016 
 
 
 26,888 
2017 
 
 
 5,762 
2018 
 
 
 2,398 
Total Future Minimum Lease Payments
 
$
 109,813 

13.   FINANCING ACTIVITIES

Preferred Stock

In December 2011, the Registrant Subsidiaries redeemed all of their outstanding preferred stock, resulting in a loss, which is included in Preferred Stock Dividend Requirements Including Capital Stock Expense on the statements of income.  The par value of preferred stock redeemed and the loss recorded by the Registrant Subsidiaries was as follows:

 
 
 
Par Value of
 
Loss on
Company
 
Stock Redeemed
 
Redemption
 
 
 
 
(in thousands)
APCo
 
$
 17,736 
 
$
 1,013 
I&M
 
 
 8,072 
 
 
 314 
OPCo
 
 
 16,613 
 
 
 488 
PSO
 
 
 4,882 
 
 
 254 
SWEPCo
 
 
 4,694 
 
 
 369 

 
 
 
 
 
 
Number of Shares Redeemed
 
 
 
 
 
 
Year Ended December 31,
Company
 
Series
 
2011
APCo
 
4.50 
%
 
 177,465
I&M
 
4.12 
%
 
 11,055
I&M
 
4.125 
%
 
 55,257
I&M
 
4.56 
%
 
 14,412
OPCo
 
4.08 
%
 
 14,495
OPCo
 
4.20 
%
 
 22,824
OPCo
 
4.40 
%
 
 31,482
OPCo
 
4.50 
%
 
 97,357
PSO
 
4.00 
%
 
 44,508
PSO
 
4.24 
%
 
 4,310
SWEPCo
 
4.28 
%
 
 7,386
SWEPCo
 
4.65 
%
 
 1,907
SWEPCo
 
5.00 
%
 
 37,665


 
346

 

Long-term Debt

There are certain limitations on establishing liens against the Registrant Subsidiaries’ assets under their respective indentures.  None of the long-term debt obligations of the Registrant Subsidiaries have been guaranteed or secured by AEP or any of its affiliates.

The following details long-term debt outstanding as of December 31, 2013 and 2012:

 
 
 
 
Weighted
 
 
 
 
 
 
 
 
Average
 
 
 
 
 
 
 
 
Interest
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rate as of
 
 
 
Outstanding as of
 
 
 
 
December 31,
 
Interest Rate Ranges as of December 31,
 
December 31,
Company
 
Maturity
 
2013 
 
2013 
 
2012 
 
2013 
 
2012 
Senior Unsecured Notes
 
 
 
 
 
 
 
 
 
(in thousands)
APCo (a)
 
2013-2038
 
5.88%
 
3.40%-7.95%
 
0.685%-7.95%
 
$
 2,893,220 
 
$
 3,167,559 
I&M
 
2014-2037
 
5.80%
 
3.20%-7.00%
 
5.05%-7.00%
 
 
 1,246,235 
 
 
 1,171,080 
OPCo (a)
 
2013-2035
 
5.87%
 
4.85%-6.60%
 
4.85%-6.60%
 
 
 2,169,487 
 
 
 3,142,615 
PSO
 
2016-2037
 
5.52%
 
4.40%-6.625%
 
4.40%-6.625%
 
 
 896,705 
 
 
 896,364 
SWEPCo
 
2015-2040
 
5.56%
 
3.55%-6.45%
 
3.55%-6.45%
 
 
 1,823,007 
 
 
 1,822,653 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pollution Control Bonds (b)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo
 
2013-2038 (c)
1.76%
 
0.05%-5.375%
 
0.12%-5.375%
 
 
 532,500 
 
 
 532,500 
I&M
 
2013-2025 (c)
3.79%
 
0.04%-6.25%
 
0.11%-6.25%
 
 
 226,569 
 
 
 266,531 
OPCo
 
2013-2042 (c)
3.57%
 
2.875%-5.80%
 
0.13%-5.80%
 
 
 296,825 
 
 
 517,825 
PSO
 
 2014-2020
 
5.03%
 
4.45%-5.25%
 
4.45%-5.25%
 
 
 46,360 
 
 
 46,360 
SWEPCo
 
 2015-2018
 
4.28%
 
3.25%-4.95%
 
3.25%-4.95%
 
 
 135,200 
 
 
 135,200 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes Payable - Affiliated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo (d)
 
2015 
 
3.125%
 
3.125%
 
 
 
 
 86,000 
 
 
 - 
OPCo (a)
 
2015 
 
 
 
 
 
5.25%
 
 
 - 
 
 
 200,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes Payable - Nonaffiliated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
I&M
 
2013-2017
 
1.68%
 
1.164%-4.00%
 
1.913%-5.44%
 
 
 177,540 
 
 
 224,376 
SWEPCo
 
2024-2032
 
5.11%
 
4.58%-6.37%
 
4.58%-6.37%
 
 
 85,125 
 
 
 88,375 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Securitization Bonds
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo (e)
 
2024-2031
 
2.77%
 
2.008%-3.772%
 
 
 
 
 380,282 
 
 
 - 
OPCo (e)
 
2018-2020
 
1.38%
 
0.958%-2.049%
 
 
 
 
 267,403 
 
 
 - 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel Obligation (f)
 
 
 
 
 
 
 
 
 
 
 
 
I&M
 
 
 
 
 
 
 
 
 
 
 265,391 
 
 
 265,249 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Long-term Debt
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo (a)
 
2015-2026
 
1.29%
 
1.188%-13.718%
 
13.718%
 
 
 302,355 
 
 
 2,383 
I&M
 
2015-2025
 
2.35%
 
1.67%-6.00%
 
1.72%-6.00%
 
 
 123,281 
 
 
 130,430 
OPCo
 
2028 
 
1.15%
 
1.15%
 
 
 
 
 1,460 
 
 
 - 
PSO (g)
 
2016-2027
 
1.67%
 
1.491%-3.00%
 
3.00%
 
 
 56,745 
 
 
 7,147 

 
(a) In July 2013, AGR, APCo, KPCo and OPCo entered into a $1 billion term credit facility due in May 2015 to provide liquidity during the corporate separation process.  In 2013, OPCo borrowed $1 billion under the credit facility and retired other certain debt.  On December 31, 2013, OPCo assigned the $1 billion in credit facility borrowings to AGR upon the transfer of OPCo's generation assets to AGR.  Also on December 31, 2013, AGR subsequently assigned a portion of the borrowings to APCo in the amount of $300 million upon AGR's transfer of certain of those generation assets.  
(b)  For certain series of pollution control bonds, interest rates are subject to periodic adjustment.  Certain series may be purchased on demand at periodic interest adjustment dates.  Letters of credit from banks and insurance policies support certain series. 
(c)  Certain pollution control bonds are subject to redemption earlier than the maturity date.  Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets.  
(d)  In 2013, APCo issued $86 million in Long Term Debt - Affiliated to AGR. 
(e)  In 2013, APCo and OPCo issued $380 million and $267 million, respectively, of Securitization Bonds (see Note 15). 
(f)  Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see "SNF Disposal" section of Note 5). 
(g) In 2013, PSO issued a $50 million three-year credit facility to be used for general corporate purposes.
 
 
347

 
Long-term debt outstanding as of December 31, 2013 is payable as follows:

 
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
2014 
$
 342,360 
 
$
 294,845 
 
$
 438,595 
 
$
 34,115 
 
$
 3,250 
2015 
 
 908,562 
 
 
 267,729 
 
 
 131,504 
 
 
 427 
 
 
 306,750 
2016 
 
 88,372 
 
 
 18,398 
 
 
 395,945 
 
 
 200,440 
 
 
 3,250 
2017 
 
 273,492 
 
 
 7,310 
 
 
 46,387 
 
 
 454 
 
 
 253,250 
2018 
 
 23,972 
 
 
 1,570 
 
 
 397,045 
 
 
 467 
 
 
 384,950 
After 2018
 
 2,564,396 
 
 
 1,453,359 
 
 
 1,331,217 
 
 
 767,201 
 
 
 1,093,875 
Principal Amount
 
 4,201,154 
 
 
 2,043,211 
 
 
 2,740,693 
 
 
 1,003,104 
 
 
 2,045,325 
Unamortized Discount, Net
 
 (6,797)
 
 
 (4,195)
 
 
 (5,518)
 
 
 (3,294)
 
 
 (1,993)
Total Long-term Debt
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding
$
 4,194,357 
 
$
 2,039,016 
 
$
 2,735,175 
 
$
 999,810 
 
$
 2,043,332 

In January 2014 and February 2014, I&M retired $5 million and $19 million, respectively, of Notes Payable related to DCC Fuel.

In January 2014, OPCo retired $225 million of 4.85% Senior Unsecured Notes due in 2014.

As of December 31, 2013, trustees held, on behalf of I&M and OPCo, $40 million and $460 million, respectively, of their reacquired Pollution Control Bonds.

Dividend Restrictions

The Registrant Subsidiaries pay dividends to Parent provided funds are legally available.  Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

Federal Power Act

The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.”  The term “capital account” is not defined in the Federal Power Act or its regulations.  Management understands “capital account” to mean the book value of the common stock.

Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants.  Because of their respective ownership of such plants, this reserve applies to APCo and I&M.

None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.

Leverage Restrictions

Pursuant to the credit agreement leverage restrictions, APCo, I&M and PSO must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%.  As of December 31, 2013, $12 million of I&M’s retained earnings and none of APCo’s or PSO’s retained earnings have restrictions related to the payment of dividends to Parent.

Utility Money Pool – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds a majority of AEP’s nonutility subsidiaries.  The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC.   The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of December 31, 2013 and 2012 are included in Advances to Affiliates and Advances from Affiliates,
 
 
348

 
respectively, on each of the Registrant Subsidiaries’ balance sheets.  The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the years ended December 31, 2013 and 2012 are described in the following tables:

Year Ended December 31, 2013:

 
 
 
 
 
 
 
 
 
 
 
Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loans to
 
 
 
 
 
Maximum
 
Maximum
 
Average
 
Average
 
(Borrowings from)
 
Authorized
 
 
Borrowings
 
Loans
 
Borrowings
 
Loans
 
the Utility
 
Short-term
 
 
from the Utility
 
to the Utility
 
from the Utility
 
to the Utility
 
Money Pool as of
 
Borrowing
Company
 
Money Pool
 
Money Pool
 
Money Pool
 
Money Pool
 
December 31, 2013
 
Limit
 
 
(in thousands)
APCo
 
$
 331,771 
 
$
 202,377 
 
$
 141,128 
 
$
 28,659 
 
$
 92,485 
 
$
 600,000 
I&M
 
 
 23,135 
 
 
 403,905 
 
 
 8,308 
 
 
 256,730 
 
 
 55,863 
 
 
 500,000 
OPCo
 
 
 410,456 
 
 
 415,605 
 
 
 190,384 
 
 
 50,230 
 
 
 339,070 
 
 
 600,000 
PSO
 
 
 46,806 
 
 
 109,607 
 
 
 18,754 
 
 
 28,771 
 
 
 (36,772)
 
 
 300,000 
SWEPCo
 
 
 24,553 
 
 
 153,830 
 
 
 6,020 
 
 
 33,546 
 
 
 (9,180)
 
 
 350,000 

Year Ended December 31, 2012:

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loans to
 
 
 
 
Maximum
 
Maximum
 
Average
 
Average
 
(Borrowings from)
 
Authorized
 
 
Borrowings
 
Loans
 
Borrowings
 
Loans
 
the Utility
 
Short-term
 
 
from the Utility
 
to the Utility
 
from the Utility
 
to the Utility
 
Money Pool as of
 
Borrowing
Company
 
Money Pool
 
Money Pool
 
Money Pool
 
Money Pool
 
December 31, 2012
 
Limit
 
 
(in thousands)
APCo
 
$
 350,153 
 
$
 23,504 
 
$
 161,363 
 
$
 22,821 
 
$
 (150,941)
 
$
 600,000 
I&M
 
 
 - 
 
 
 362,733 
 
 
 - 
 
 
 202,439 
 
 
 116,977 
 
 
 500,000 
OPCo
 
 
 126,975 
 
 
 290,356 
 
 
 47,820 
 
 
 105,154 
 
 
 116,422 
 
 
 600,000 
PSO
 
 
 - 
 
 
 177,778 
 
 
 - 
 
 
 92,697 
 
 
 10,558 
 
 
 300,000 
SWEPCo
 
 
 227,087 
 
 
 173,778 
 
 
 147,338 
 
 
 78,994 
 
 
 153,829 
 
 
 350,000 

The activity in the above table does not include short-term lending activity of OPCo’s former wholly-owned subsidiary, AGR.  In January 2013, AGR became a participant in the Nonutility Money Pool.  In November 2013, AGR’s participation in the Nonutility Money Pool ended as AGR became a direct borrower from Parent.  On December 31, 2013, OPCo contributed the assets and liabilities of AGR to Parent as part of corporate separation.  For the year ended December 31, 2013, AGR had the following activity in the Nonutility Money Pool or from Parent:

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Borrowings
 
Year Ended
 
Maximum
 
Maximum
 
Average
 
Average
 
From as of
 
December 31, 2013
 
Borrowings From
 
Loans To
 
Borrowings From
 
Loans To
 
December 31, 2013
 
 
 
(in thousands)
 
Nonutility Money Pool
 
$
 1,047 
 
$
 1,027 
 
$
 316 
 
$
 208 
 
$
 - 
 
Parent
 
 
 1,178 
 
 
 - 
 
 
 1,078 
 
 
 - 
 
 
 - 
(a)
 
(a)  The borrowings of AGR from Parent as of December 31, 2013 are no longer associated with OPCo.

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:

 
 
Years Ended December 31,
 
 
 
2013 
 
 
2012 
 
 
2011 
Maximum Interest Rate
 
 0.43 
%
 
 
 0.56 
%
 
 
0.56 
%
Minimum Interest Rate
 
 0.24 
%
 
 
 0.39 
%
 
 
0.06 
%

 
349

 
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the years ended December 31, 2013, 2012 and 2011 are summarized for all Registrant Subsidiaries in the following table:

 
 
Average Interest Rate
 
Average Interest Rate
 
 
 for Funds Borrowed
 
 for Funds Loaned
 
 
from the Utility Money Pool for
 
to the Utility Money Pool for
 
 
Years Ended December 31,
 
Years Ended December 31,
Company
 
2013 
 
2012 
 
2011 
 
2013 
 
2012 
 
2011 
APCo
 
 0.33 
%
 
 0.47 
%
 
 0.42 
%
 
 0.33 
%
 
 0.47 
%
 
 0.32 
%
I&M
 
 0.36 
%
 
 - 
%
 
 0.39 
%
 
 0.32 
%
 
 0.46 
%
 
 0.38 
%
OPCo
 
 0.33 
%
 
 0.47 
%
 
 0.45 
%
 
 0.32 
%
 
 0.47 
%
 
 0.35 
%
PSO
 
 0.34 
%
 
 - 
%
 
 0.41 
%
 
 0.33 
%
 
 0.46 
%
 
 0.32 
%
SWEPCo
 
 0.34 
%
 
 0.53 
%
 
 0.40 
%
 
 0.36 
%
 
 0.45 
%
 
 0.33 
%

AGR’s maximum, minimum and average interest rates for funds either borrowed from or loaned to the Nonutility Money Pool or Parent for the year ended December 31, 2013 are summarized in the following table:

 
 
Maximum
 
Minimum
 
Maximum
 
Minimum
 
Average
 
Average
 
 
Interest Rate
 
Interest Rate
 
Interest Rate
 
Interest Rate
 
Interest Rate
 
Interest Rate
Year Ended
 
for Funds
 
for Funds
 
for Funds
 
for Funds
 
for Funds
 
for Funds
December 31, 2013
 
Borrowed
 
Borrowed
 
Loaned
 
Loaned
 
Borrowed
 
Loaned
Nonutility Money Pool
 
 0.66 
%
 
 0.53 
%
 
 0.35 
%
 
 0.32 
%
 
 0.58 
%
 
 0.34 
%
Parent
 
 0.34 
%
 
 0.24 
%
 
 - 
%
 
 - 
%
 
 0.28 
%
 
 - 
%

Interest expense related to short-term borrowing activities with the Utility Money Pool, the Nonutility Money Pool and Parent is included in Interest Expense on each of the Registrant Subsidiaries’ statements of income.  The Registrant Subsidiaries incurred interest expense for all short-term borrowing activities as follows:

 
 
Years Ended December 31,
Company
 
2013 
 
2012 
 
2011 
 
 
 
 
 
(in thousands)
 
 
 
APCo
 
$
 414 
 
$
 772 
 
$
198 
I&M
 
 
 70 
 
 
 - 
 
 
20 
OPCo
 
 
 503 
 
 
 555 
 
 
12 
PSO
 
 
 25 
 
 
 11 
 
 
85 
SWEPCo
 
 
 5 
 
 
 977 
 
 
174 

Interest income related to short-term lending activities with the Utility Money Pool, the Nonutility Money Pool and Parent is included in Interest Income on each of the Registrant Subsidiaries’ statements of income.  The Registrant Subsidiaries earned interest income for all short-term lending activities as follows:

 
 
Years Ended December 31,
Company
 
2013 
 
2012 
 
2011 
 
 
 
 
 
(in thousands)
 
 
 
APCo
 
$
 109 
 
$
 123 
 
$
 313 
I&M
 
 
 924 
 
 
 963 
 
 
 226 
OPCo
 
 
 233 
 
 
 1,038 
 
 
 820 
PSO
 
 
 58 
 
 
 435 
 
 
 250 
SWEPCo
 
 
 113 
 
 
 320 
 
 
 32 


 
350

 

Short-term Debt

The Registrant Subsidiaries’ outstanding short-term debt was as follows:

 
 
 
 
 
December 31,
 
 
 
 
 
 
2013 
 
2012 
 
 
 
 
 
Outstanding
 
Interest
 
Outstanding
 
Interest
Company
 
Type of Debt
Amount
Rate (a)
 
Amount
Rate (a)
 
 
 
 
 
(in thousands)
 
 
 
 
(in thousands)
 
 
 
SWEPCo
 
Line of Credit – Sabine
 
$
 - 
 
 - 
%
 
$
 2,603 
 
 1.82 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Weighted average rate.

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 5.

Sale of Receivables – AEP Credit

Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables.  APCo does not have regulatory authority to sell its West Virginia accounts receivable.  The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income.  The Registrant Subsidiaries manage and service their customer accounts receivable sold.

In June 2013, AEP Credit amended its receivables securitization agreement to extend through June 2014.  The agreement provides a commitment of $700 million from bank conduits to purchase receivables.  AEP Credit amended a commitment of $385 million to now expire in June 2014.  The remaining commitment of $315 million expires in June 2015.  AEP Credit intends to extend or replace the agreement expiring in June 2014 on or before its maturity.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of December 31, 2013 and 2012 was as follows:

 
 
 
December 31,
Company
 
2013 
 
2012 
 
 
 
(in thousands)
APCo
 
$
 156,599 
 
$
 153,719 
I&M
 
 
 139,257 
 
 
 123,447 
OPCo
 
 
 324,287 
 
 
 300,675 
PSO
 
 
 115,260 
 
 
 85,530 
SWEPCo
 
 
 149,337 
 
 
 132,449 

The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:

 
 
 
Years Ended December 31,
Company
 
2013 
 
2012 
 
2011 
 
 
 
(in thousands)
APCo
 
$
 6,471 
 
$
 6,883 
 
$
 9,612 
I&M
 
 
 6,510 
 
 
 6,121 
 
 
 6,168 
OPCo
 
 
 21,573 
 
 
 20,312 
 
 
 18,851 
PSO
 
 
 5,604 
 
 
 7,054 
 
 
 6,363 
SWEPCo
 
 
 5,917 
 
 
 6,140 
 
 
 5,672 


 
351

 

The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:

 
 
 
Years Ended December 31,
Company
 
2013 
 
2012 
 
2011 
 
 
 
(in thousands)
APCo
 
$
 1,442,983 
 
$
 1,353,920 
 
$
 1,248,253 
I&M
 
 
 1,458,803 
 
 
 1,344,260 
 
 
 1,323,068 
OPCo
 
 
 2,620,483 
 
 
 2,952,723 
 
 
 3,461,758 
PSO
 
 
 1,232,363 
 
 
 1,157,174 
 
 
 1,299,190 
SWEPCo
 
 
 1,533,840 
 
 
 1,481,925 
 
 
 1,495,397 

14.   RELATED PARTY TRANSACTIONS

For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 11 in addition to “Utility Money Pool – AEP System” and “Sale of Receivables – AEP Credit” sections of Note 13.

Interconnection Agreement

In accordance with management’s December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014.  The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated.

APCo, I&M, KPCo, OPCo and AEPSC were parties to the Interconnection Agreement which defined the sharing of costs and benefits associated with the respective generation plants.  This sharing was based upon each AEP utility subsidiary’s MLR and was calculated monthly on the basis of each AEP utility subsidiary’s maximum peak demand in relation to the sum of the maximum peak demands of all four AEP utility subsidiaries during the preceding 12 months.

Effective January 1, 2014, the FERC approved the creation of the Power Coordination Agreement among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.  Also effective January 1, 2014, the FERC approved the Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent to address open commitments related to the termination of the Interconnection Agreement and responsibilities to PJM.  See “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters in Note 3.

Prior to January 1, 2014, power, natural gas and risk management activities were conducted by AEPSC and profits and losses were allocated under the SIA to members of the Interconnection Agreement, PSO and SWEPCo.  Risk management activities involved the purchase and sale of power and natural gas under physical forward contracts at fixed and variable prices.  In addition, the risk management of power, and to a lesser extent natural gas contracts, included exchange traded futures and options and OTC options and swaps.  The majority of these transactions represented physical forward contracts in the AEP System’s traditional marketing area and were typically settled by entering into offsetting contracts.  In addition, AEPSC entered into transactions for the purchase and sale of power and natural gas options, futures and swaps, and for the forward purchase and sale of power outside of the AEP System’s traditional marketing area.

Operating Agreement

PSO, SWEPCo and AEPSC are parties to the Operating Agreement which was approved by the FERC.  The Operating Agreement requires PSO and SWEPCo to maintain adequate annual planning reserve margins and requires that capacity in excess of the required margins be made available for sale to other operating companies as capacity commitments.  Parties are compensated for energy delivered to recipients based upon the deliverer’s incremental cost plus a portion of the recipient’s savings realized by the purchaser that avoids more costly alternatives.  Revenues and costs arising from third party sales are generally shared based on the amount of energy PSO or SWEPCo contributes that is sold to third parties.  In January 2014, the FERC approved the modification of the Operating Agreement to address changes resulting from the anticipated March 2014 implementation of a “Day-Ahead” power market by the SPP.
 
 
352

 
System Integration Agreement (SIA)

The SIA provides for the integration and coordination of AEP East Companies’ and AEP West Companies’ zones.  This includes joint dispatch of generation within the AEP System and the distribution, between the two zones, of costs and benefits associated with the transfers of power between the two zones (including sales to third parties and risk management and trading activities).  The SIA is designed to function as an umbrella agreement in addition to the Interconnection Agreement (prior to January 1, 2014) and the Operating Agreement, each of which controls the distribution of costs and benefits within a zone.

Power generated, allocated or provided under the Interconnection Agreement or the Operating Agreement to any Registrant Subsidiary is primarily sold to customers by such Registrant Subsidiary at rates approved (other than in Ohio) by the public utility commission in the jurisdiction of sale.  In Ohio, such rates are based on a statutory formula as that jurisdiction transitions to the use of market rates for generation.

Under both the Interconnection Agreement and the Operating Agreement, power generated that is not needed to serve the native load of any Registrant Subsidiary is sold in the wholesale market by AEPSC on behalf of the generating subsidiary.

Affiliated Revenues and Purchases

The following tables show the revenues derived from sales under the Interconnection Agreement, direct sales to affiliates, net transmission agreement sales, natural gas contracts with AEPES and other revenues for the years ended December 31, 2013, 2012 and 2011:

Related Party Revenues
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sales under Interconnection Agreement
 
$
 193,651 
 
$
 218,164 
 
$
 924,313 
 
$
 - 
 
$
 - 
 
Direct Sales to East Affiliates
 
 
 129,014 
 
 
 - 
 
 
 152,689 
 
 
 14 
 
 
 1 
 
Direct Sales to West Affiliates
 
 
 578 
 
 
 391 
 
 
 804 
 
 
 10,761 
 
 
 35,410 
 
Direct Sales to AEPEP
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (136)
 
Transmission Agreement and Transmission
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Coordination Agreement Sales
 
 
 461 
 
 
 (681)
 
 
 53,405 
 
 
 - 
 
 
 14,715 
 
Other Revenues
 
 
 23,780 
 
 
 1,525 
 
 
 35,643 
 
 
 3,471 
 
 
 1,822 
 
Total Affiliated Revenues
 
$
 347,484 
 
$
 219,399 
 
$
 1,166,854 
 
$
 14,246 
 
$
 51,812 

Related Party Revenues
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Year Ended December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sales under Interconnection Agreement
 
$
 166,733 
 
$
 265,923 
 
$
 643,486 
 
$
 - 
 
$
 - 
 
Direct Sales to East Affiliates
 
 
 124,519 
 
 
 - 
 
 
 136,142 
 
 
 34 
 
 
 142 
 
Direct Sales to West Affiliates
 
 
 314 
 
 
 218 
 
 
 454 
 
 
 18,861 
 
 
 23,695 
 
Direct Sales to AEPEP
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (583)
 
Transmission Agreement and Transmission
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Coordination Agreement Sales
 
 
 (1,289)
 
 
 758 
 
 
 26,295 
 
 
 8 
 
 
 12,338 
 
Other Revenues
 
 
 27,922 
 
 
 1,509 
 
 
 40,917 
 
 
 3,700 
 
 
 1,849 
 
Total Affiliated Revenues
 
$
 318,199 
 
$
 268,408 
 
$
 847,294 
 
$
 22,603 
 
$
 37,441 

Related Party Revenues
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Year Ended December 31, 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sales under Interconnection Agreement
 
$
 186,788 
 
$
 308,336 
 
$
 823,703 
 
$
 - 
 
$
 - 
 
Direct Sales to East Affiliates
 
 
 126,737 
 
 
 - 
 
 
 115,120 
 
 
 124 
 
 
 3,535 
 
Direct Sales to West Affiliates
 
 
 1,492 
 
 
 908 
 
 
 1,936 
 
 
 10,624 
 
 
 43,714 
 
Direct Sales to AEPEP
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (637)
 
Transmission Agreement and Transmission
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Coordination Agreement Sales
 
 
 2,348 
 
 
 9,379 
 
 
 3,375 
 
 
 111 
 
 
 8,962 
 
Natural Gas Contracts with AEPES
 
 
 154 
 
 
 92 
 
 
 196 
 
 
 3 
 
 
 4 
 
Other Revenues
 
 
 42,283 
 
 
 1,469 
 
 
 33,669 
 
 
 3,330 
 
 
 2,037 
 
Total Affiliated Revenues
 
$
 359,802 
 
$
 320,184 
 
$
 977,999 
 
$
 14,192 
 
$
 57,615 
 

 
 
353

 
The following tables show the purchased power expenses incurred for purchases under the Interconnection Agreement and from affiliates for the years ended December 31, 2013, 2012 and 2011:

Related Party Purchases
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Year Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Purchases under Interconnection Agreement
 
$
 830,954 
 
$
 181,688 
 
$
 199,283 
 
$
 - 
 
$
 - 
 
Direct Purchases from East Affiliates
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,481 
 
 
 411 
 
Direct Purchases from West Affiliates
 
 
 5 
 
 
 3 
 
 
 6 
 
 
 35,410 
 
 
 10,761 
 
Purchases from AEGCo
 
 
 - 
 
 
 251,518 
 
 
 148,459 
 
 
 - 
 
 
 - 
 
Natural Gas Purchases from AEPES
 
 
 - 
 
 
 - 
 
 
 1,984 
 
 
 - 
 
 
 - 
 
Total Affiliated Purchases
 
$
 830,959 
 
$
 433,209 
 
$
 349,732 
 
$
 36,891 
 
$
 11,172 

Related Party Purchases
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Year Ended December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Purchases under Interconnection Agreement
 
$
 661,185 
 
$
 147,502 
 
$
 174,240 
 
$
 - 
 
$
 - 
 
Direct Purchases from East Affiliates
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 683 
 
 
 368 
 
Direct Purchases from West Affiliates
 
 
 53 
 
 
 36 
 
 
 75 
 
 
 23,695 
 
 
 18,861 
 
Purchases from AEGCo
 
 
 - 
 
 
 238,866 
 
 
 203,583 
 
 
 - 
 
 
 - 
 
Natural Gas Purchases from AEPES
 
 
 - 
 
 
 - 
 
 
 2,808 
 
 
 - 
 
 
 - 
 
Total Affiliated Purchases
 
$
 661,238 
 
$
 386,404 
 
$
 380,706 
 
$
 24,378 
 
$
 19,229 

Related Party Purchases
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Year Ended December 31, 2011
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Purchases under Interconnection Agreement
 
$
 818,943 
 
$
 124,598 
 
$
 326,871 
 
$
 - 
 
$
 - 
 
Direct Purchases from East Affiliates
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 6,378 
 
 
 1,184 
 
Direct Purchases from West Affiliates
 
 
 239 
 
 
 147 
 
 
 312 
 
 
 43,714 
 
 
 10,624 
 
Purchases from AEGCo
 
 
 - 
 
 
 228,739 
 
 
 185,741 
 
 
 - 
 
 
 - 
 
Natural Gas Purchases from AEPES
 
 
 - 
 
 
 - 
 
 
 2,689 
 
 
 - 
 
 
 - 
 
Total Affiliated Purchases
 
$
 819,182 
 
$
 353,484 
 
$
 515,613 
 
$
 50,092 
 
$
 11,808 

The above summarized related party revenues and expenses are reported in Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates on the Registrant Subsidiaries’ statements of income.  Since the Registrant Subsidiaries are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses.

System Transmission Integration Agreement

AEP’s System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP East Companies’ and AEP West Companies’ zones.  Similar to the SIA, the System Transmission Integration Agreement functions as an umbrella agreement in addition to the Transmission Agreement (TA) and the Transmission Coordination Agreement (TCA).  The System Transmission Integration Agreement contains two service schedules that govern:

·  
The allocation of transmission costs and revenues.
·  
The allocation of third-party transmission costs and revenues and AEP System dispatch costs.

The System Transmission Integration Agreement anticipates that additional service schedules may be added as circumstances warrant.

APCo, I&M, KGPCo, KPCo, OPCo and WPCo are parties to the TA, effective November 2010, which defines how transmission costs through PJM OATT are allocated among the AEP East Companies, KGPCo and WPCo on a 12-month average coincident peak basis.


 
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The following table shows the net charges recorded by the Registrant Subsidiaries for the years ended December 31, 2013, 2012 and 2011 related to the TA:

 
 
 
Years Ended December 31,
Company
 
2013 
 
2012 
 
2011 
 
 
(in thousands)
APCo
 
$
 40,609 
 
$
 20,264 
 
$
 4,608 
I&M
 
 
 19,947 
 
 
 5,689 
 
 
 1,538 
OPCo
 
 
 8,946 
 
 
 6,090 
 
 
 17,186 

The charges shown above are recorded in Other Operation expenses on the statements of income.

PSO, SWEPCo and AEPSC are parties to the TCA, dated January 1, 1997, revised 1999 and 2011, as restated and amended, by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries.  The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the parties to the agreement.  This includes the performance of transmission planning studies, the interaction of such companies with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such a tariff.

Under the TCA, the parties to the agreement delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf.  The allocations have been governed by the FERC-approved OATT for the SPP.

The following table shows the net (revenues) expenses allocated among parties to the TCA pursuant to the SPP OATT protocols as described above for the years ended December 31, 2013, 2012 and 2011:

 
 
 
Years Ended December 31,
Company
 
2013 
 
2012 
 
2011 
 
 
(in thousands)
PSO
 
$
 14,700 
 
$
 12,300 
 
$
 9,000 
SWEPCo
 
 
 (14,700)
 
 
 (12,300)
 
 
 (9,000)

The net (revenues) expenses shown above are recorded in Sales to AEP Affiliates on SWEPCo’s statements of income and Other Operation expenses on PSO’s statements of income.

Unit Power Agreements (UPA)

Lawrenceburg UPA between OPCo and AEGCo

In March 2007, OPCo and AEGCo entered into a 10-year UPA for the entire output from the Lawrenceburg Generating Station effective with AEGCo’s purchase of the plant in May 2007.  The UPA has an option for an additional two-year period.  I&M operates the plant under an agreement with AEGCo.  Under the UPA, OPCo pays AEGCo for the capacity, depreciation, fuel, operation and maintenance and tax expenses.  These payments are due regardless of whether the plant is operating.  The fuel and operation and maintenance payments are based on actual costs incurred.  All expenses are trued up periodically.

The Lawrenceburg UPA was assigned by OPCo to AGR effective January 1, 2014.  Also effective January 1, 2014, the FERC issued an order approving a Power Supply Agreement between AGR and OPCo.  See “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters in Note 3.

UPA between AEGCo and I&M

A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility.  Subsequently, I&M assigns 30% of the power to KPCo.  See the "UPA between AEGCo and KPCo" section below.  I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to
 
 
355

 
receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC.  The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances.

UPA between AEGCo and KPCo

Pursuant to an assignment between I&M and KPCo and a UPA between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant.  KPCo pays to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement.  The KPCo UPA ends in December 2022.

Cook Coal Terminal

On August 1, 2013, OPCo transferred ownership of Cook Coal Terminal to AEGCo.  Cook Coal Terminal performs coal transloading services at cost for APCo, I&M and OPCo.  OPCo included revenues for these services in Other Revenues – Affiliated and expenses in Other Operation expenses on the statements of income.  The coal transloading expenses in 2013, 2012 and 2011 were as follows:

AEGCo
 
 
 
 
 
 
 
 
 
 
Year Ended
 
 
 
 
 
December 31,
 
 
Company
 
2013 
 
 
 
 
(in thousands)
 
 
I&M
 
$
 6,820 
 
 
OPCo
 
 
 322 
 

OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
Company
 
2013 
 
2012 
 
2011 
 
 
 
(in thousands)
 
APCo
 
$
 (11)
(a) 
$
 942 
 
$
 31 
 
I&M
 
 
 15,596 
(b) 
 
 32,639 
(b) 
 
 21,852 
(b) 
                     
(a)  Includes annual true-up of 2012 estimated revenues. 
(b)  Includes $7.3 million, $14.5 million and $9.3 million in 2013, 2012 and 2011, respectively, of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013. 
 
APCo, I&M and OPCo recorded the cost of transloading services in Fuel on the balance sheets.


 
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Cook Coal Terminal also performs railcar maintenance services at cost for APCo, I&M, PSO and SWEPCo.  Beginning on August 1, 2013, Cook Coal Terminal also performs railcar maintenance services at cost for OPCo.  OPCo included revenues for these services in Sales to AEP Affiliates and expenses in Other Operation expenses on the statements of income.  The railcar maintenance revenues in 2013, 2012 and 2011 were as follows:

AEGCo
 
 
 
 
 
 
 
 
 
 
Year Ended
 
 
 
 
 
December 31,
 
 
Company
 
2013 
 
 
 
 
(in thousands)
 
 
I&M
 
$
 1,073 
 
 
OPCo
 
 
 41 
 
 
PSO
 
 
 106 
 
 
SWEPCo
 
 
 1,237 
 

OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
Company
 
2013 
 
2012 
 
2011 
 
 
 
(in thousands)
 
APCo
 
$
 3 
 
$
 88 
 
$
 9 
 
I&M
 
 
 1,285 
(a) 
 
 3,343 
(a) 
 
 3,012 
(a) 
PSO
 
 
 59 
 
 
 281 
 
 
 542 
 
SWEPCo
 
 
 1,204 
 
 
 2,102 
 
 
 2,348 
 
                     
(a)  Includes $608 thousand, $1.5 million and $1.3 million in 2013, 2012 and 2011, respectively, of amounts purchased by I&M on behalf of AEGCo for Rockport Plant through July 31, 2013. 

APCo, I&M, OPCo, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on the balance sheets.

SWEPCo Railcar Facility

SWEPCo operates a railcar maintenance facility in Alliance, Nebraska.  The facility performs maintenance on its own railcars as well as railcars belonging to I&M, PSO and third parties.  SWEPCo billed I&M $873 thousand and $1.6 million for railcar services provided in 2013 and 2012, respectively, and billed PSO $279 thousand and $232 thousand in 2013 and 2012, respectively.  These billings for SWEPCo, and costs for I&M and PSO, are recorded in Fuel on the balance sheets.

I&M Barging, Urea Transloading and Other Services

I&M provides barging, urea transloading and other transportation services to affiliates.  Urea is a chemical used to control NO x emissions at certain generation plants in the AEP System.  I&M recorded revenues from barging, transloading and other services in Other Revenues – Affiliated on the statements of income.  The affiliated companies recorded these costs paid to I&M as fuel expenses or other operation expenses.  The amounts of affiliated expenses were:

 
 
 
Years Ended December 31,
Company
 
2013 
 
2012 
 
2011 
 
 
(in thousands)
AEGCo
 
$
 19,719 
 
$
 19,961 
 
$
 15,460 
APCo
 
 
 30,876 
 
 
 34,725 
 
 
 27,455 
KPCo
 
 
 50 
 
 
 74 
 
 
 122 
OPCo
 
 
 40,562 
 
 
 39,956 
 
 
 36,980 
AEP River Operations LLC (Nonutility
 
 
 
 
 
 
 
 
 
 
Subsidiary of AEP)
 
 
 22,648 
 
 
 20,917 
 
 
 25,356 

 
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Services Provided by AEP River Operations LLC

AEP River Operations LLC provides services for barge towing, chartering and general and administrative expenses to I&M.  The costs are recorded by I&M as Other Operation expenses.  For the years ended December 31, 2013, 2012 and 2011, I&M recorded expenses of $24 million, $24 million and $24 million, respectively, for these activities.

Central Machine Shop

APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System.  APCo defers the cost of performing these services on the balance sheet, then transfers the cost to the affiliate for reimbursement.  The AEP subsidiaries recorded these billings as capital or maintenance expenses depending on the nature of the services received.  These billings are recoverable from customers.  The following table provides the amounts billed by APCo to the following affiliates:

 
 
 
Years Ended December 31,
Company
 
2013 
 
2012 
 
2011 
 
 
(in thousands)
AEGCo
 
$
 26 
 
$
 80 
 
$
 102 
I&M
 
 
 2,451 
 
 
 1,280 
 
 
 2,157 
KPCo
 
 
 687 
 
 
 277 
 
 
 298 
OPCo
 
 
 4,679 
 
 
 3,838 
 
 
 3,684 
PSO
 
 
 606 
 
 
 1,198 
 
 
 53 
SWEPCo
 
 
 168 
 
 
 145 
 
 
 946 

Affiliate Railcar Agreement

Certain AEP subsidiaries have an agreement providing for the use of each other’s leased or owned railcars when available.  The agreement specifies that the company using the railcar will be billed, at cost, by the company furnishing the railcar.  The AEP subsidiaries recorded these costs or reimbursements as costs or reduction of costs, respectively, in Fuel on the balance sheets and such costs are recoverable from customers.  The following tables show the net effect of the railcar agreement on the balance sheets:

December 31, 2013
Billing Company
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Billed Company
 
AGR
 
APCo
 
I&M
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
AGR
 
$
 - 
 
$
 698 
 
$
 33 
 
$
 2 
 
$
 19 
APCo
 
 
 775 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
I&M
 
 
 (391)
 
 
 507 
 
 
 - 
 
 
 195 
 
 
 854 
PSO
 
 
 (90)
 
 
 20 
 
 
 595 
 
 
 - 
 
 
 329 
SWEPCo
 
 
 (245)
 
 
 140 
 
 
 1,395 
 
 
 43 
 
 
 - 

December 31, 2012
Billing Company
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Billed Company
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
APCo
 
$
 - 
 
$
 2 
 
$
 1,960 
 
$
 - 
 
$
 2 
I&M
 
 
 148 
 
 
 - 
 
 
 889 
 
 
 48 
 
 
 843 
KPCo
 
 
 98 
 
 
 - 
 
 
 41 
 
 
 - 
 
 
 - 
OPCo
 
 
 854 
 
 
 170 
 
 
 - 
 
 
 5 
 
 
 99 
PSO
 
 
 204 
 
 
 322 
 
 
 74 
 
 
 - 
 
 
 176 
SWEPCo
 
 
 543 
 
 
 1,468 
 
 
 321 
 
 
 21 
 
 
 - 


 
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OVEC

AEP, OPCo and several nonaffiliated utility companies jointly own OVEC.  As of December 31, 2013, AEP’s and OPCo’s ownership and investment in OVEC were as follows:

 
 
 
December 31, 2013
Company
 
Ownership
 
Investment
 
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
AEP
 
 39.17 
 
$
 3,978 
OPCo
 
 4.30 
 
 
 430 
Total
 
 43.47 
 
$
 4,408 

OVEC’s owners, along with APCo and I&M, are members to an intercompany power agreement.  Participants of this agreement are entitled to receive and obligated to pay for all OVEC generating capacity, approximately 2,200 MWs, in proportion to their respective power participation ratios.  The aggregate power participation ratio of certain AEP utility subsidiaries, including APCo, I&M and OPCo, is 43.47%.  The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and provide a return on capital.  In 2011, the intercompany power agreement was extended until June 2040.

AEP, OPCo and other nonaffiliated owners authorized environmental investments related to their ownership interests and OVEC’s Board of Directors authorized capital expenditures totaling $1.4 billion in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at OVEC’s two generation plants.  These environmental projects were funded through debt issuances.  As of December 31, 2013, both generation plants were operating with new environmental controls.

Purchased Power from OVEC

The amounts of power purchased by the Registrant Subsidiaries from OVEC for the years ended December 31, 2013, 2012 and 2011 were:

 
 
 
Years Ended December 31,
Company
 
2013 
 
2012 
 
2011 
 
 
(in thousands)
APCo
 
$
 104,396 
 
$
 98,417 
 
$
 114,311 
I&M
 
 
 52,230 
 
 
 49,239 
 
 
 57,192 
OPCo
 
 
 132,607 
 
 
 125,013 
 
 
 145,207 

The amounts shown above are recoverable from customers and are included in Purchased Electricity for Resale on the statements of income.

Purchases from OVEC under the Interconnection Agreement

In 2011, the parties to the Interconnection Agreement purchased power from OVEC to serve off-system sales and retail sales.  These purchases are reported in Purchased Electricity for Resale on the statements of income.  The following table shows the amounts recorded for the year ended December 31, 2011:

 
 
 
Year Ended
Company
 
December 31, 2011
 
 
(in thousands)
APCo
 
$
 21,110 
I&M
 
 
 12,942 
OPCo
 
 
 27,566 


 
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Sales and Purchases of Property

Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property.  There were no gains or losses recorded on the transactions.  The following tables show the sales and purchases, recorded at net book value, for the years ended December 31, 2013, 2012 and 2011:

Sales
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
Company
 
2013 
 
2012 
 
2011 
 
 
(in thousands)
APCo
 
$
 3,212 
 
$
 6,643 
 
 3,978 
I&M
 
 
 5,031 
 
 
 3,296 
 
 
 441 
OPCo
 
 
 59,818 
 
 
 4,163 
 
 
 12,113 
PSO
 
 
 5,651 
 
 
 1,782 
 
 
 442 
SWEPCo
 
 
 1,617 
 
 
 1,731 
 
 
 650 

Purchases
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
Company
 
2013 
 
2012 
 
2011 
 
 
(in thousands)
APCo
 
$
 5,199 
 
$
 2,522 
 
 2,312 
I&M
 
 
 964 
 
 
 285 
 
 
 3,678 
OPCo
 
 
 5,311 
 
 
 10,608 
 
 
 3,045 
PSO
 
 
 1,710 
 
 
 1,867 
 
 
 475 
SWEPCo
 
 
 8,440 
 
 
 7,266 
 
 
 2,993 

The amounts above are recorded in Property, Plant and Equipment on the balance sheets.

Global Borrowing Notes

As of December 31, 2012, AEP had an intercompany note in place with OPCo.  The debt is reflected in Long-term Debt – Affiliated on OPCo’s balance sheet.  OPCo accrued interest for its share of the global borrowing and remitted the interest to AEP.  The accrued interest is reflected in Accrued Interest on OPCo’s balance sheet.

Intercompany Billings

The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical.  The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies.  The billings for services are made at cost and include no compensation for the use of equity capital.

15.   VARIABLE INTEREST ENTITIES

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE.  A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.  Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.”  In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors.  Management believes that significant assumptions and judgments were applied consistently.  In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.

 
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SWEPCo is the primary beneficiary of Sabine.  I&M is the primary beneficiary of DCC Fuel.  OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding.  APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding.  SWEPCo holds a significant variable interest in DHLC.  Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC.  I&M and OPCo each hold a significant variable interest in AEGCo.

Sabine is a mining operator providing mining services to SWEPCo.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee.  In addition, SWEPCo determines how much coal will be mined each year.  Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine.  SWEPCo’s total billings from Sabine for the years ended December 31, 2013, 2012 and 2011 were $155 million, $147 million and $128 million, respectively.  See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s balance sheets.

The balances below represent the assets and liabilities of Sabine that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
December 31, 2013 and 2012
(in thousands)
 
 
Sabine
 
 
2013 
 
2012 
ASSETS
 
 
 
 
 
 
Current Assets
 
$
 66,478 
 
$
 56,535 
Net Property, Plant and Equipment
 
 
 157,274 
 
 
 170,436 
Other Noncurrent Assets
 
 
 51,211 
 
 
 55,076 
Total Assets
 
$
 274,963 
 
$
 282,047 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
Current Liabilities
 
$
 32,812 
 
$
 31,446 
Noncurrent Liabilities
 
 
 241,673 
 
 
 250,340 
Equity
 
 
 478 
 
 
 261 
Total Liabilities and Equity
 
$
 274,963 
 
$
 282,047 

I&M has nuclear fuel lease agreements with DCC Fuel II LLC, DCC Fuel IV LLC, DCC Fuel V LLC and DCC Fuel VI LLC (collectively DCC Fuel).  DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions.  Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on the leases for the years ended December 31, 2013, 2012 and 2011 were $153 million, $127 million and $85 million, respectively.  The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months.  Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The capital leases are eliminated upon consolidation.  In October 2013, the lease agreements ended for DCC Fuel LLC and DCC Fuel III LLC.  See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s balance sheets.


 
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The balances below represent the assets and liabilities of DCC Fuel that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
December 31, 2013 and 2012
(in thousands)
 
 
DCC Fuel
ASSETS
 
2013 
 
2012 
Current Assets
 
$
 117,762 
 
$
 132,886 
Net Property, Plant and Equipment
 
 
 156,820 
 
 
 176,065 
Other Noncurrent Assets
 
 
 60,450 
 
 
 92,473 
Total Assets
 
$
 335,032 
 
$
 401,424 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
Current Liabilities
 
$
 107,815 
 
$
 120,873 
Noncurrent Liabilities
 
 
 227,217 
 
 
 280,551 
Equity
 
 
 - 
 
 
 - 
Total Liabilities and Equity
 
$
 335,032 
 
$
 401,424 

Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property.  Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant.  Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding.  The securitized bonds totaled $267 million as of December 31, 2013, and are included in current and long-term debt on the balance sheet.  Ohio Phase-in-Recovery Funding has securitized assets of $132 million as of December 31, 2013, which is presented separately on the face of the balance sheet.  The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO.  In August 2013, securitization bonds were issued.  The securitization bonds are payable only from and secured by the securitized assets.  The bondholders have no recourse to OPCo or any other AEP entity.  OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs.

The balances below represent the assets and liabilities of Ohio Phase-in-Recovery Funding that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.

OHIO POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
December 31, 2013
(in thousands)
 
 
Ohio
 
 
Phase-in-
 
 
Recovery
 
 
Funding
ASSETS
 
2013 
Current Assets
 
$
 23,198 
Other Noncurrent Assets (a)
 
 
 251,409 
Total Assets
 
$
 274,607 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
Current Liabilities
 
$
 36,470 
Noncurrent Liabilities
 
 
 236,800 
Equity
 
 
 1,337 
Total Liabilities and Equity
 
$
 274,607 
       
(a) Includes an intercompany item eliminated in consolidation of $116 million.  


 
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Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo's under-recovered ENEC deferral balance.  Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo's equity interest could potentially be significant.  Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding.  The securitized bonds totaled $380 million as of December 31, 2013, and are included in current and long-term debt on the balance sheet.   Appalachian Consumer Rate Relief Funding has securitized assets of $369 million as of December 31, 2013, which is presented separately on the face of the balance sheet.  The phase-in recovery property represents the right to impose and collect WV deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC.  In November 2013, securitization bonds were issued.  The securitization bonds are payable only from and secured by the securitized assets.  The bondholders have no recourse to APCo or any other AEP entity.  APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs.

The balances below represent the assets and liabilities of Appalachian Consumer Rate Relief Funding that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
December 31, 2013
(in thousands)
 
 
Appalachian
 
 
Consumer
 
 
Rate Relief
 
 
Funding
ASSETS
 
2013 
Current Assets
 
$
 5,891 
Net Property, Plant and Equipment
 
 
 - 
Other Noncurrent Assets (a)
 
 
 378,029 
Total Assets
 
$
 383,920 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
Current Liabilities
 
$
 14,000 
Noncurrent Liabilities
 
 
 368,018 
Equity
 
 
 1,902 
Total Liabilities and Equity
 
$
 383,920 
       
(a)  Includes an intercompany item eliminated in consolidation of $4 million.      
 
DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  SWEPCo and CLECO share the executive board seats and voting rights equally.  Each entity guarantees 50% of DHLC’s debt.  SWEPCo and CLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee.  SWEPCo’s total billings from DHLC for the years ended December 31, 2013, 2012 and 2011 were $60 million, $77 million and $62 million, respectively.  SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC.  SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets.

 
363

 
SWEPCo’s investment in DHLC was:

 
December 31,
 
2013 
 
2012 
 
As Reported on
 
Maximum
 
As Reported on
 
Maximum
 
the Balance Sheet
 
Exposure
 
the Balance Sheet
 
Exposure
 
(in thousands)
Capital Contribution from SWEPCo
$
 7,643 
 
$
 7,643 
 
$
 7,643 
 
$
 7,643 
Retained Earnings
 
 1,600 
 
 
 1,600 
 
 
 946 
 
 
 946 
SWEPCo's Guarantee of Debt
 
 - 
 
 
 61,348 
 
 
 - 
 
 
 49,564 
 
 
 
 
 
 
 
 
 
 
 
 
Total Investment in DHLC
$
 9,243 
 
$
 70,591 
 
$
 8,589 
 
$
 58,153 

AEPSC provides certain managerial and professional services to AEP’s subsidiaries.  AEP is the sole equity owner of AEPSC.  AEP management controls the activities of AEPSC.  The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost.  AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered.  AEPSC finances its operations through cost reimbursement from other AEP subsidiaries.  There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business.  AEPSC and its billings are subject to regulation by the FERC.  AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations.  AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure.  However, AEP subsidiaries do not have control over AEPSC.  AEPSC is consolidated by AEP.  In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.

Total AEPSC billings to the Registrant Subsidiaries were as follows:

 
 
Years Ended December 31,
Company
 
2013 
 
2012 
 
2011 
 
 
(in thousands)
APCo
 
$
 174,393 
 
$
 195,176 
 
$
 195,787 
I&M
 
 
 119,343 
 
 
 127,232 
 
 
 126,505 
OPCo
 
 
 255,485 
 
 
 277,232 
 
 
 279,652 
PSO
 
 
 85,974 
 
 
 89,199 
 
 
 84,028 
SWEPCo
 
 
 125,441 
 
 
 136,642 
 
 
 130,148 

The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows:

 
 
December 31,
 
 
2013 
 
2012 
 
 
As Reported on
 
Maximum
 
As Reported on
 
Maximum
Company
 
the Balance Sheet
 
Exposure
 
the Balance Sheet
 
Exposure
 
 
(in thousands)
APCo
 
$
 20,191 
 
$
 20,191 
 
$
 29,819 
 
$
 29,819 
I&M
 
 
 12,864 
 
 
 12,864 
 
 
 17,911 
 
 
 17,911 
OPCo
 
 
 31,425 
 
 
 31,425 
 
 
 39,323 
 
 
 39,323 
PSO
 
 
 10,596 
 
 
 10,596 
 
 
 13,381 
 
 
 13,381 
SWEPCo
 
 
 13,520 
 
 
 13,520 
 
 
 19,669 
 
 
 19,669 
 

 
 
364

 
AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP.  AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station.  AEGCo sells all the output from the Rockport Plant to I&M and KPCo.   AEGCo has a UPA associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014.  AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo.  I&M is considered to have a significant interest in AEGCo due to these transactions.  I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations.  In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP.  For additional information regarding AEGCo’s lease, see “Rockport Lease” section of Note 12.

Total billings from AEGCo were as follows:

 
 
Years Ended December 31,
Company
 
2013 
 
2012 
 
2011 
 
 
(in thousands)
I&M
 
$
 251,518 
 
$
 238,865 
 
$
 228,739 
OPCo
 
 
 148,459 
 
 
 203,582 
 
 
 185,741 

The carrying amount and classification of variable interest in AEGCo's accounts payable are as follows:

 
 
December 31,
 
 
2013 
 
2012 
 
 
As Reported on
 
Maximum
 
As Reported on
 
Maximum
Company
 
the Balance Sheet
 
Exposure
 
the Balance Sheet
 
Exposure
 
 
(in thousands)
I&M
 
$
 23,916 
 
$
 23,916 
 
$
 25,498 
 
$
 25,498 
OPCo
 
 
 12,810 
 
 
 12,810 
 
 
 16,302 
 
 
 16,302 

 
365

 
16.   PROPERTY, PLANT AND EQUIPMENT

Depreciation, Depletion and Amortization

The Registrant Subsidiaries provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class.  The following tables provide annual property information for the Registrant Subsidiaries:

APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2013 
 
Regulated
 
Nonregulated
 
 
 
 
 
 
Annual
 
 
 
 
 
 
 
 
 
Annual
 
 
 
 
Functional
 
Property,
 
 
 
Composite
 
 
 
 
 
Property,
 
 
 
Composite
 
 
 
 
Class of
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
Property
 
Equipment
 
Depreciation
 
Rate
 
Life Ranges
 
Equipment
 
Depreciation
 
Rate
 
Life Ranges
 
 
(in thousands)
 
 
 
 
(in years)
 
(in thousands)
 
 
 
 
(in years)
Generation
 
$
 6,745,172 
 
$
 2,306,545 
 
 3.0 
%
 
 40 
-
 121 
 
$
 - 
 
$
 - 
 
NA
 
NA
Transmission
 
 
 2,160,660 
 
 
 490,143 
 
 1.6 
%
 
 25 
-
 87 
 
 
 - 
 
 
 - 
 
NA
 
NA
Distribution
 
 
 3,139,150 
 
 
 674,351 
 
 3.5 
%
 
 11 
-
 52 
 
 
 - 
 
 
 - 
 
NA
 
NA
CWIP
 
 
 184,701 
 
 
 (19,297)
 
NM
 
NM
 
 
 - 
 
 
 - 
 
NA
 
NA
Other
 
 
 323,758 
 
 
 153,797 
 
 7.3 
%
 
 24 
-
 55 
 
 
 33,759 
 
 
 12,451 
 
NM
 
NM
Total
 
$
 12,553,441 
 
$
 3,605,539 
 
 
 
 
 
 
 
 
$
 33,759 
 
$
 12,451 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2012 
 
Regulated
 
Nonregulated
 
 
 
 
 
 
Annual
 
 
 
 
 
 
 
 
 
Annual
 
 
 
 
Functional
 
Property,
 
 
 
Composite
 
 
 
 
 
Property,
 
 
 
Composite
 
 
 
 
Class of
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
Property
 
Equipment
 
Depreciation
 
Rate
 
Life Ranges
 
Equipment
 
Depreciation
 
Rate
 
Life Ranges
 
 
(in thousands)
 
 
 
 
(in years)
 
(in thousands)
 
 
 
 
(in years)
Generation
 
$
 5,632,665 
 
$
 1,928,562 
 
 3.0 
%
 
 40 
-
 121 
 
$
 - 
 
$
 - 
 
NA
 
NA
Transmission
 
 
 2,042,144 
 
 
 468,633 
 
 1.6 
%
 
 25 
-
 87 
 
 
 - 
 
 
 - 
 
NA
 
NA
Distribution
 
 
 2,991,898 
 
 
 641,504 
 
 3.4 
%
 
 13 
-
 57 
 
 
 - 
 
 
 - 
 
NA
 
NA
CWIP
 
 
 266,247 
 
 
 (19,379)
 
NM
 
NM
 
 
 - 
 
 
 - 
 
NA
 
NA
Other
 
 
 340,027 
 
 
 164,932 
 
 6.8 
%
 
 24 
-
 55 
 
 
 33,300 
 
 
 12,387 
 
NM
 
NM
Total
 
$
 11,272,981 
 
$
 3,184,252 
 
 
 
 
 
 
 
 
$
 33,300 
 
$
 12,387 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2011 
 
Regulated
 
Nonregulated
 
 
 
Annual Composite
 
Depreciable
 
Annual Composite
 
Depreciable
Functional Class of Property
 
Depreciation Rate
 
Life Ranges
 
Depreciation Rate
 
Life Ranges
 
 
 
 
 
 
(in years)
 
 
 
 
(in years)
Generation
 
 2.6 
%
 
 40 
-
 121 
 
NA
 
NA
Transmission
 
 1.6 
%
 
 25 
-
 87 
 
NA
 
NA
Distribution
 
 3.2 
%
 
 11 
-
 52 
 
NA
 
NA
CWIP
NM
 
NM 
 
NA
 
NA
Other
 
 6.6 
%
 
 24 
-
 55 
 
NM
 
NM
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NA
Not applicable.
NM
Not meaningful.

 
366

 
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2013 
 
Regulated
 
Nonregulated
 
 
 
 
 
 
Annual
 
 
 
 
 
 
 
 
 
Annual
 
 
 
 
Functional
 
Property,
 
 
 
Composite
 
 
 
 
 
Property,
 
 
 
Composite
 
 
 
 
Class of
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
Property
 
Equipment
 
Depreciation
 
Rate
 
Life Ranges
 
Equipment
 
Depreciation
 
Rate
 
Life Ranges
 
 
(in thousands)
 
 
 
 
(in years)
 
(in thousands)
 
 
 
 
(in years)
Generation
 
$
 3,577,906 
 
$
 1,887,333 
 
 1.9 
%
 
 59 
-
 132 
 
$
 - 
 
$
 - 
 
NA
 
NA
Transmission
 
 
 1,304,225 
 
 
 420,295 
 
 1.5 
%
 
 50 
-
 75 
 
 
 - 
 
 
 - 
 
NA
 
NA
Distribution
 
 
 1,625,057 
 
 
 390,014 
 
 2.8 
%
 
 15 
-
 70 
 
 
 - 
 
 
 - 
 
NA
 
NA
CWIP
 
 
 427,164 
 
 
 (18,824)
 
NM
 
NM
 
 
 - 
 
 
 - 
 
NA
 
NA
Other
 
 
 1,268,597 
 
 
 509,426 
 
 4.9 
%
 
 14 
-
 45 
 
 
 152,764 
 
 
 111,105 
 
NM
 
NM
Total
 
$
 8,202,949 
 
$
 3,188,244 
 
 
 
 
 
 
 
 
$
 152,764 
 
$
 111,105 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2012 
 
Regulated
 
Nonregulated
 
 
 
 
 
 
Annual
 
 
 
 
 
 
 
 
 
Annual
 
 
 
 
Functional
 
Property,
 
 
 
Composite
 
 
 
 
 
Property,
 
 
 
Composite
 
 
 
 
Class of
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
Property
 
Equipment
 
Depreciation
 
Rate
 
Life Ranges
 
Equipment
 
Depreciation
 
Rate
 
Life Ranges
 
 
(in thousands)
 
 
 
 
(in years)
 
(in thousands)
 
 
 
 
(in years)
Generation
 
$
 4,062,733 
 
$
 2,130,136 
 
 1.7 
%
 
 59 
-
 132 
 
$
 - 
 
$
 - 
 
NA
 
NA
Transmission
 
 
 1,278,236 
 
 
 411,825 
 
 1.5 
%
 
 46 
-
 75 
 
 
 - 
 
 
 - 
 
NA
 
NA
Distribution
 
 
 1,553,358 
 
 
 373,342 
 
 2.5 
%
 
 14 
-
 70 
 
 
 - 
 
 
 - 
 
NA
 
NA
CWIP
 
 
 341,063 
 
 
 65,449 
 
NM
 
NM
 
 
 - 
 
 
 - 
 
NA
 
NA
Other
 
 
 573,836 
 
 
 141,291 
 
 9.6 
%
 
 14 
-
 40 
 
 
 151,477 
 
 
 110,092 
 
NM
 
NM
Total
 
$
 7,809,226 
 
$
 3,122,043 
 
 
 
 
 
 
 
 
$
 151,477 
 
$
 110,092 
 
 
 
 
 
 
 
 
2011 
 
Regulated
 
Nonregulated
 
 
 
Annual Composite
 
Depreciable
 
Annual Composite
 
Depreciable
Functional Class of Property
 
Depreciable Rate
 
Life Ranges
 
Depreciable Rate
 
Life Ranges
 
 
 
 
 
 
(in years)
 
 
 
 
(in years)
Generation
 
 1.6 
%
 
 59 
-
 132 
 
NA
 
NA
Transmission
 
 1.4 
%
 
 46 
-
 75 
 
NA
 
NA
Distribution
 
 2.4 
%
 
 14 
-
 70 
 
NA
 
NA
CWIP
NM 
 
NM 
 
NA
 
NA
Other
 
 7.4 
%
 
NM 
 
NM 
 
NM 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NA
Not applicable.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NM
Not meaningful.
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
367

 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2013 
 
Regulated
 
Nonregulated
 
 
 
 
 
 
Annual
 
 
 
 
 
 
 
 
 
Annual
 
 
 
 
Functional
 
Property,
 
 
 
Composite
 
 
 
 
 
Property,
 
 
 
Composite
 
 
 
 
Class of
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
Property
 
Equipment
 
Depreciation
 
Rate
 
Life Ranges
 
Equipment
 
Depreciation
 
Rate
 
Life Ranges
 
 
(in thousands)
 
 
 
 
(in years)
 
(in thousands)
 
 
 
 
(in years)
Transmission
 
$
 2,011,289 
 
$
 814,849 
 
 2.3 
%
 
 39 
-
 60 
 
$
 - 
 
$
 - 
 
NA
 
NA
Distribution
 
 
 3,877,532 
 
 
 1,023,313 
 
 2.7 
%
 
 12 
-
 60 
 
 
 - 
 
 
 - 
 
NA
 
NA
CWIP
 
 
 185,428 
 
 
 (29,825)
 
NM
 
NM
 
 
 - 
 
 
 - 
 
NM
 
NM
Other
 
 
 354,195 
 
 
 163,894 
 
 7.5 
%
 
 25 
-
 50 
 
 
 10,378 
 
 
 811 
 
NM
 
NM
Total
 
$
 6,428,444 
 
$
 1,972,231 
 
 
 
 
 
 
 
 
$
 10,378 
 
$
 811 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2012 
 
Regulated
 
Nonregulated
 
 
 
 
 
 
Annual
 
 
 
 
 
 
 
 
 
Annual
 
 
 
 
Functional
 
Property,
 
 
 
Composite
 
 
 
 
 
Property,
 
 
 
Composite
 
 
 
 
Class of
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
Property
 
Equipment
 
Depreciation
 
Rate
 
Life Ranges
 
Equipment
 
Depreciation
 
Rate
 
Life Ranges
 
 
(in thousands)
 
 
 
 
(in years)
 
(in thousands)
 
 
 
 
(in years)
Generation
 
$
 - 
 
$
 - 
 
NA
 
NA
 
$
 8,673,296 
 
$
 3,200,427 
 
 3.0 
%
 
 35 
-
 66 
Transmission
 
 
 2,013,737 
 
 
 809,199 
 
 2.3 
%
 
 39 
-
 60 
 
 
 - 
 
 
 - 
 
NA
 
NA
Distribution
 
 
 3,722,745 
 
 
 1,011,324 
 
 2.7 
%
 
 12 
-
 60 
 
 
 - 
 
 
 - 
 
NA
 
NA
CWIP
 
 
 147,408 
 
 
 (21,198)
 
NM
 
NM
 
 
 207,089 
 
 
 1,350 
 
NM
 
NM
Other
 
 
 427,412 
 
 
 224,153 
 
 7.3 
%
 
 25 
-
 50 
 
 
 143,742 
 
 
 17,550 
 
NM
 
NM
Total
 
$
 6,311,302 
 
$
 2,023,478 
 
 
 
 
 
 
 
 
$
 9,024,127 
 
$
 3,219,327 
 
 
 
 
 
 
 

2011 
 
Regulated
 
Nonregulated
 
 
 
Annual Composite
 
 
 
 
 
Annual Composite
 
 
 
 
 
 
 
Depreciation
 
Depreciable
 
Depreciation
 
Depreciable
Functional Class of Property
 
Rate
 
Life Ranges
 
Rate
 
Life Ranges
 
 
 
 
 
 
(in years)
 
 
 
 
(in years)
Generation
NA
 
NA
 
 3.2 
%
 
 35 
-
 66 
Transmission
 
 2.3 
%
 
 27 
-
 70 
 
NA
 
NA
Distribution
 
 3.7 
%
 
 12 
-
 56 
 
NA
 
NA
CWIP
NM 
 
NM 
 
NM 
 
NM 
Other
 
 8.7 
%
 
NM 
 
NM 
 
NM 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NA
Not applicable.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NM
Not meaningful.
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
368

 


PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2013 
 
Regulated
 
Nonregulated
 
 
 
 
 
 
Annual
 
 
 
 
 
 
 
 
 
Annual
 
 
 
 
Functional
 
Property,
 
 
 
Composite
 
 
 
 
 
Property,
 
 
 
Composite
 
 
 
 
Class of
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
Property
 
Equipment
 
Depreciation
 
Rate
 
Life Ranges
 
Equipment
 
Depreciation
 
Rate
 
Life Ranges
 
 
(in thousands)
 
 
 
 
(in years)
 
(in thousands)
 
 
 
 
(in years)
Generation
 
$
 1,203,221 
 
$
 583,486 
 
 1.7 
%
 
 35 
-
 70 
 
$
 - 
 
$
 - 
 
NA
 
NA
Transmission
 
 
 731,312 
 
 
 186,040 
 
 1.9 
%
 
 40 
-
 75 
 
 
 - 
 
 
 - 
 
NA
 
NA
Distribution
 
 
 1,986,032 
 
 
 365,299 
 
 2.3 
%
 
 30 
-
 65 
 
 
 - 
 
 
 - 
 
NA
 
NA
CWIP
 
 
 175,890 
 
 
 (15,138)
 
NM
 
NM
 
 
 - 
 
 
 - 
 
NA
 
NA
Other
 
 
 387,856 
 
 
 203,841 
 
 4.1 
%
 
 5 
-
 40 
 
 
 5,170 
 
 
 (6)
 
NM
 
NM
Total
 
$
 4,484,311 
 
$
 1,323,528 
 
 
 
 
 
 
 
 
$
 5,170 
 
$
 (6)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2012 
 
Regulated
 
Nonregulated
 
 
 
 
 
 
Annual
 
 
 
 
 
 
 
 
 
Annual
 
 
 
 
Functional
 
Property,
 
 
 
Composite
 
 
 
 
 
Property,
 
 
 
Composite
 
 
 
 
Class of
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
Property
 
Equipment
 
Depreciation
 
Rate
 
Life Ranges
 
Equipment
 
Depreciation
 
Rate
 
Life Ranges
 
 
(in thousands)
 
 
 
 
(in years)
 
(in thousands)
 
 
 
 
(in years)
Generation
 
$
 1,346,530 
 
$
 654,989 
 
 1.7 
%
 
 35 
-
 70 
 
$
 - 
 
$
 - 
 
NA
 
NA
Transmission
 
 
 706,917 
 
 
 176,187 
 
 1.9 
%
 
 40 
-
 75 
 
 
 - 
 
 
 - 
 
NA
 
NA
Distribution
 
 
 1,859,557 
 
 
 345,207 
 
 2.4 
%
 
 30 
-
 65 
 
 
 - 
 
 
 - 
 
NA
 
NA
CWIP
 
 
 95,170 
 
 
 (9,281)
 
NM
 
NM
 
 
 - 
 
 
 - 
 
NA
 
NA
Other
 
 
 205,373 
 
 
 111,837 
 
 6.6 
%
 
 5 
-
 40 
 
 
 5,176 
 
 
 2 
 
NM
 
NM
Total
 
$
 4,213,547 
 
$
 1,278,939 
 
 
 
 
 
 
 
 
$
 5,176 
 
$
 2 
 
 
 
 
 
 
 

2011 
 
Regulated
 
Nonregulated
 
 
 
Annual Composite
 
 
 
 
 
Annual Composite
 
 
 
 
 
 
 
Depreciation
 
Depreciable
 
Depreciation
 
Depreciable
Functional Class of Property
 
Rate
 
Life Ranges
 
Rate
 
Life Ranges
 
 
 
 
 
 
(in years)
 
 
 
 
(in years)
Generation
 
 1.8 
%
 
 9 
-
 70 
 
NA
 
NA
Transmission
 
 1.9 
%
 
 40 
-
 75 
 
NA
 
NA
Distribution
 
 2.4 
%
 
 30 
-
 65 
 
NA
 
NA
CWIP
 
NM 
 
NM 
 
NA
 
NA
Other
 
 8.3 
%
 
 5 
-
 35 
 
NM 
 
NM 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NA
Not applicable.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NM
Not meaningful.
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
369

 


SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2013 
 
Regulated
 
Nonregulated
 
 
 
 
 
 
Annual
 
 
 
 
 
 
 
 
Annual
 
 
 
 
Functional
 
Property,
 
 
 
Composite
 
 
 
 
 
Property,
 
 
Composite
 
 
 
 
Class of
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
 
Plant and
 
Accumulated
Depreciation
 
Depreciable
Property
 
Equipment
 
Depreciation
 
Rate
 
Life Ranges
 
Equipment
 
Depreciation
Rate
 
Life Ranges
 
 
(in thousands)
 
 
 
 
(in years)
 
(in thousands)
 
 
 
(in years)
Generation (a)
 
$
 3,764,429 
 
$
 1,062,166 
 
 2.2 
%
 
 40 
-
 70 
 
$
 - 
 
$
 - 
NA
 
NA
Transmission
 
 
 1,165,167 
 
 
 312,567 
 
 2.3 
%
 
 50 
-
 70 
 
 
 - 
 
 
 - 
NA
 
NA
Distribution
 
 
 1,843,912 
 
 
 563,087 
 
 2.6 
%
 
 25 
-
 65 
 
 
 - 
 
 
 - 
NA
 
NA
CWIP (a)
 
 
 281,849 
 
 
 (7,355)
 
NM
 
NM
 
 
 - 
 
 
 - 
NA
 
NA
Other
 
 
 574,131 
 
 
 326,871 
 
 5.0 
%
 
 7 
-
 51 
 
 
 295,099 
 
 
 134,316 
NM
 
NM
Total
 
$
 7,629,488 
 
$
 2,257,336 
 
 
 
 
 
 
 
 
$
 295,099 
 
$
 134,316 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2012 
 
Regulated
 
Nonregulated
 
 
 
 
 
 
Annual
 
 
 
 
 
 
 
 
Annual
 
 
 
 
Functional
 
Property,
 
 
 
Composite
 
 
 
 
 
Property,
 
 
Composite
 
 
 
 
Class of
 
Plant and
 
Accumulated
 
Depreciation
 
Depreciable
 
Plant and
 
Accumulated
Depreciation
 
Depreciable
Property
 
Equipment
 
Depreciation
 
Rate
 
Life Ranges
 
Equipment
 
Depreciation
Rate
 
Life Ranges
 
 
(in thousands)
 
 
 
 
(in years)
 
(in thousands)
 
 
 
(in years)
Generation (a)
 
$
 3,888,230 
 
$
 1,092,566 
 
 2.2 
%
 
 35 
-
 65 
 
$
 - 
 
$
 - 
NA
 
NA
Transmission
 
 
 1,115,795 
 
 
 301,159 
 
 2.3 
%
 
 50 
-
 70 
 
 
 - 
 
 
 - 
NA
 
NA
Distribution
 
 
 1,758,988 
 
 
 556,904 
 
 2.6 
%
 
 25 
-
 65 
 
 
 - 
 
 
 - 
NA
 
NA
CWIP (a)
 
 
 99,783 
 
 
 (8,294)
 
NM
 
NM
 
 
 - 
 
 
 - 
NA
 
NA
Other
 
 
 397,643 
 
 
 225,254 
 
 6.6 
%
 
 7 
-
 47 
 
 
 290,611 
 
 
 116,669 
NM
 
NM
Total
 
$
 7,260,439 
 
$
 2,167,589 
 
 
 
 
 
 
 
 
$
 290,611 
 
$
 116,669 
 
 
 
 
 
 

2011 
 
 
Regulated
 
 
Nonregulated
 
 
 
Annual Composite
 
 
 
 
 
Annual Composite
 
 
 
 
 
 
 
Depreciation
 
Depreciable
 
Depreciation
 
Depreciable
Functional Class of Property
 
Rate
 
Life Ranges
 
Rate
 
Life Ranges
 
 
 
 
 
 
(in years)
 
 
 
 
(in years)
Generation
 
 2.1 
%
 
 35 
-
 68 
 
NA
 
NA
Transmission
 
 2.3 
%
 
 50 
-
 70 
 
NA
 
NA
Distribution
 
 2.6 
%
 
 25 
-
 65 
 
NA
 
NA
CWIP
 
NM 
 
NM 
 
NM 
 
NM 
Other
 
 6.9 
%
 
 7 
-
 47 
 
NM 
 
NM 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
SWEPCo's regulated section includes amounts related to SWEPCo's Arkansas jurisdictional share of the Turk Plant.
NA
Not applicable.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NM
Not meaningful.
 
 
 
 
 
 
 
 
 
 
 
 
 
 

SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset's estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment.  SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages.  SWEPCo includes these costs in fuel expense.

For regulated operations, the composite depreciation rate generally includes a component for nonasset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization.  Actual removal costs incurred are charged to Accumulated Depreciation and Amortization.  Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability.  For nonregulated operations, non-ARO removal costs are expensed as incurred.


 
370

 
 
Asset Retirement Obligations (ARO)

The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities as well as asbestos removal.  I&M records ARO for the decommissioning of the Cook Plant.  The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned.  Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use.  The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely.  The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected.

As of December 31, 2013 and 2012, I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.2 billion and $1.2 billion, respectively.  These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets.  As of December 31, 2013 and 2012, the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.6 billion and $1.4 billion, respectively.  These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets.

The following is a reconciliation of the 2013 and 2012 aggregate carrying amounts of ARO by Registrant Subsidiary:

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contribution/
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(Distribution)
 
 
 
 
 
 
ARO as of
 
 
 
 
 
 
 
Revisions in
 
of OPCo
 
ARO as of
 
 
 
December 31,
 
Accretion
 
Liabilities
 
Liabilities
 
Cash Flow
 
Generation
 
December 31,
Company
 
2012 
 
Expense
 
Incurred
 
Settled
 
Estimates
 
Assets
 
2013 
 
 
(in thousands)
APCo (a)(d)
 
$
 115,168 
 
$
 7,343 
 
$
 - 
 
$
 (7,298)
 
$
 7,083 
 
$
 30,311 
 
$
 152,607 
I&M (a)(b)(d)
 
 
 1,192,313 
 
 
 72,658 
 
 
 - 
 
 
 (635)
 
 
 (9,152)
 
 
 - 
 
 
 1,255,184 
OPCo (a)(d)
 
 
 269,940 
 
 
 14,957 
 
 
 158 
 
 
 (9,788)
 
 
 53,208 
 
 
 (327,178)
 
 
 1,297 
PSO (a)(d)
 
 
 21,999 
 
 
 1,703 
 
 
 - 
 
 
 (755)
 
 
 (19)
 
 
 - 
 
 
 22,928 
SWEPCo (a)(c)(d)
 
 
 78,017 
 
 
 4,912 
 
 
 4,191 
 
 
 (2,699)
 
 
 3,209 
 
 
 - 
 
 
 87,630 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ARO as of
 
 
 
 
 
 
 
Revisions in
 
ARO as of
 
 
 
 
 
 
December 31,
 
Accretion
 
Liabilities
 
Liabilities
 
Cash Flow
 
December 31,
 
 
 
Company
 
2011 
 
Expense
 
Incurred
 
Settled
 
Estimates
 
2012 
 
 
 
 
 
(in thousands)
APCo (a)(d)
 
$
 112,767 
 
$
 7,264 
 
$
 - 
 
$
 (8,921)
 
$
 4,058 
 
$
 115,168 
 
 
 
I&M (a)(b)(d)
 
 
 1,013,122 
 
 
 53,848 
 
 
 - 
 
 
 (806)
 
 
 126,149 
 
 
 1,192,313 
 
 
 
OPCo (a)(d)
 
 
 241,828 
 
 
 15,113 
 
 
 - 
 
 
 (8,294)
 
 
 21,293 
 
 
 269,940 
 
 
 
PSO (a)(d)
 
 
 19,623 
 
 
 1,572 
 
 
 84 
 
 
 (949)
 
 
 1,669 
 
 
 21,999 
 
 
 
SWEPCo (a)(c)(d)
 
 
 67,183 
 
 
 5,511 
 
 
 17,380 
 
 
 (3,831)
 
 
 (8,226)
 
 
 78,017 
 
 
 

(a)
Includes ARO related to ash disposal facilities.
(b)
Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.2 billion as of December 31, 2013 and 2012.
(c)
Includes ARO related to Sabine and DHLC.
(d)
Includes ARO related to asbestos removal.


 
371

 


Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization

The Registrant Subsidiaries’ amounts of allowance for equity funds used during construction are summarized in the following table:

 
 
Years Ended December 31,
Company
 
2013 
 
2012 
 
2011 
 
 
(in thousands)
APCo
 
 2,353 
 
 1,684 
 
 9,212 
I&M
 
 
 19,943 
 
 
 9,724 
 
 
 15,395 
OPCo
 
 
 4,961 
 
 
 3,492 
 
 
 5,549 
PSO
 
 
 4,187 
 
 
 2,007 
 
 
 1,317 
SWEPCo
 
 
 7,338 
 
 
 57,054 
 
 
 48,731 

The Registrant Subsidiaries’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table:

 
 
Years Ended December 31,
Company
 
2013 
 
2012 
 
2011 
 
 
(in thousands)
APCo
 
 1,522 
 
 1,347 
 
 6,257 
I&M
 
 
 9,752 
 
 
 4,717 
 
 
 7,838 
OPCo
 
 
 10,102 
 
 
 9,046 
 
 
 2,350 
PSO
 
 
 2,272 
 
 
 1,098 
 
 
 822 
SWEPCo
 
 
 4,262 
 
 
 48,499 
 
 
 40,904 

Jointly-owned Electric Facilities

The Registrant Subsidiaries have electric facilities that are jointly-owned with affiliated and nonaffiliated companies.  Using its own financing, each participating company is obligated to pay its share of the costs of any such jointly-owned facilities in the same proportion as its ownership interest.  Each Registrant Subsidiary’s proportionate share of the operating costs associated with such facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows:

 
 
 
 
 
 
 
 
Company’s Share as of December 31, 2013
 
 
 
 
 
 
 
 
 
 
Construction
 
 
 
 
Fuel
Percent of
Utility Plant
Work in
Accumulated
Company
Type
Ownership
 in Service
Progress
Depreciation
 
 
 
 
 
 
 
 
(in thousands)
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rockport Generating Plant, Unit 1 (b)
 
Coal
 
 50.0 
%
 
$
 797,485 
 
$
 54,577 
 
$
 471,787 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oklaunion Generating Station, Unit 1 (g)
 
Coal
 
 15.6 
%
 
$
 93,555 
 
$
 1,844 
 
$
 57,576 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dolet Hills Generating Station, Unit 1 (h)
 
Lignite
 
 40.2 
%
 
$
 261,685 
 
$
 47,131 
 
$
 197,720 
Flint Creek Generating Station, Unit 1 (i)
 
Coal
 
 50.0 
%
 
 
 122,566 
 
 
 54,281 
 
 
 65,546 
Pirkey Generating Station, Unit 1 (i)
 
Lignite
 
 85.9 
%
 
 
 519,158 
 
 
 28,833 
 
 
 375,718 
Turk Generating Plant (i)
 
Coal
 
 73.33 
%
 
 
 1,638,044 
 
 
 13,081 
 
 
 35,455 
Total
 
 
 
 
 
 
$
 2,541,453 
 
$
 143,326 
 
$
 674,439 


 
372

 



 
 
 
 
 
 
 
 
Company’s Share as of December 31, 2012
 
 
 
 
 
 
 
 
 
 
Construction
 
 
 
 
Fuel
Percent of
Utility Plant
Work in
Accumulated
Company
Type
Ownership
 in Service
Progress
Depreciation
 
 
 
 
 
 
 
 
(in thousands)
APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
John E. Amos Generating Station, Unit 3 (a)
 
Coal
 
 33.33 
%
 
$
 563,470 
 
$
 14,188 
 
$
 108,441 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rockport Generating Plant, Unit 1 (b)
 
Coal
 
 50.0 
%
 
$
 762,737 
 
$
 55,420 
 
$
 456,436 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
John E. Amos Generating Station, Unit 3 (a)
 
Coal
 
 66.67 
%
 
$
 995,005 
 
$
 14,093 
 
$
 213,163 
W.C. Beckjord Generating Station, Unit 6 (c)
 
Coal
 
 12.5 
%
 
 
 - 
 
 
 - 
 
 
 - 
Conesville Generating Station, Unit 4 (d)
 
Coal
 
 43.5 
%
 
 
 310,342 
 
 
 26,067 
 
 
 58,677 
J.M. Stuart Generating Station (e)
 
Coal
 
 26.0 
%
 
 
 541,719 
 
 
 11,151 
 
 
 180,687 
Wm. H. Zimmer Generating Station (c)
 
Coal
 
 25.4 
%
 
 
 807,431 
 
 
 1,817 
 
 
 387,209 
Transmission
 
NA
 
(f)
 
 
 
 69,148 
 
 
 4,101 
 
 
 50,516 
Total
 
 
 
 
 
 
$
 2,723,645 
 
$
 57,229 
 
$
 890,252 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oklaunion Generating Station, Unit 1 (g)
 
Coal
 
 15.6 
%
 
$
 93,218 
 
$
 939 
 
$
 57,060 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dolet Hills Generating Station, Unit 1 (h)
 
Lignite
 
 40.2 
%
 
$
 262,649 
 
$
 7,523 
 
$
 195,336 
Flint Creek Generating Station, Unit 1 (i)
 
Coal
 
 50.0 
%
 
 
 121,052 
 
 
 14,272 
 
 
 64,348 
Pirkey Generating Station, Unit 1 (i)
 
Lignite
 
 85.9 
%
 
 
 513,833 
 
 
 16,029 
 
 
 371,015 
Turk Generating Plant (i)
 
Coal
 
 73.33 
%
 
 
 1,612,618 
 
 
 (2,669)
 
 
 59 
Total
 
 
 
 
 
 
$
 2,510,152 
 
$
 35,155 
 
$
 630,758 

 
(a)  Operated by APCo.
(b)  Operated by I&M. 
(c)  Operated by Duke Energy Corporation, a nonaffiliated company.  AEP's portion Beckjord Plant, Unit 6 was impaired in the fourth quarter of 2012.  See "Impairments" section of Note 6. 
(d)  Operated by OPCo. 
(e)  Operated by The Dayton Power & Light Company, a nonaffiliated company.
(f)  Varying percentages of ownership.
(g)  Operated by PSO and also jointly-owned (54.7%) by TNC.
(h)  Operated by CLECO, a nonaffiliated company. 
(i)  Operated by SWEPCo. 
NA  Not applicable.
 
 
 
373

 
17.   SUSTAINABLE COST REDUCTIONS

In April 2012, management initiated a process to identify strategic repositioning opportunities and efficiencies that will result in sustainable cost savings.  Management selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate current employee benefit programs.  The process resulted in involuntary severances and was completed by the end of the first quarter of 2013.  The severance program provides two weeks of base pay for every year of service along with other severance benefits.

The Registrant Subsidiaries recorded charges to Other Operation expense in 2012 primarily related to severance benefits as a result of the sustainable cost reductions initiative.  The total amount incurred in 2012 by Registrant Subsidiary was as follows:

Company
 
Total Cost Incurred
 
 
(in thousands)
APCo
 
$
 8,472 
I&M
 
 
 5,678 
OPCo
 
 
 13,498 
PSO
 
 
 3,675 
SWEPCo
 
 
 5,709 

The Registrant Subsidiaries’ sustainable cost reduction activity for the year ended December 31, 2013 is described in the following table:

 
 
 
 
 
Expense
 
Incurred by
 
 
 
 
 
 
Remaining
 
 
Balance as of
 
Allocation from
 
Registrant
 
 
 
 
 
 
 
Balance as of
Company
 
December 31, 2012
 
AEPSC
 
Subsidiaries
 
Settled
 
Adjustments
 
December 31, 2013
 
 
(in thousands)
APCo
 
$
 1,321 
 
$
 1,016 
 
$
 - 
 
$
 (1,574)
 
$
 (741)
 
$
 22 
I&M
 
 
 1,357 
 
 
 736 
 
 
 - 
 
 
 (1,690)
 
 
 (381)
 
 
 22 
OPCo
 
 
 3,450 
 
 
 1,354 
 
 
 6,114 
 
 
 (8,846)
 
 
 (1,637)
 
 
 435 
PSO
 
 
 652 
 
 
 325 
 
 
 - 
 
 
 (485)
 
 
 (472)
 
 
 20 
SWEPCo
 
 
 627 
 
 
 621 
 
 
 - 
 
 
 (1,628)
 
 
 396 
 
 
 16 

These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the statements of income.  The remaining liability is included in Other Current Liabilities on the balance sheets.  Management does not expect additional costs to be incurred related to this initiative.


 
374

 

18.   UNAUDITED QUARTERLY FINANCIAL INFORMATION

In management’s opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations for interim periods.  Quarterly results are not necessarily indicative of a full year’s operations because of various factors.  The unaudited quarterly financial information for each Registrant Subsidiary is as follows:

Quarterly Periods Ended:
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
 
March 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 951,494 
 
$
 583,393 
 
$
 1,233,790 
 
$
 262,289 
 
$
 394,317 
 
Operating Income
 
 164,560 
 
 
 81,230 
 
 
 244,813 
 
 
 33,552 
 
 
 50,639 
 
Net Income
 
 70,548 
 
 
 43,457 
 
 
 129,774 
 
 
 13,693 
 
 
 11,548 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
June 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 746,504 
 
$
 549,501 
 
$
 1,102,994 
 
$
 324,687 
 
$
 420,173 
 
Operating Income
 
 92,072 
 
 
 77,533 
 
 
 73,072 
(a)
 
 58,471 
 
 
 77,032 
 
Net Income
 
 29,862 
 
 
 40,754 
 
 
 21,056 
(a)
 
 28,432 
 
 
 30,227 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
September 30, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 849,733 
 
$
 638,865 
 
$
 1,279,176 
 
$
 411,083 
 
$
 552,933 
 
Operating Income
 
 147,692 
 
 
 102,364 
 
 
 312,795 
 
 
 95,832 
 
 
 52,359 
(b)
Net Income
 
 62,625 
 
 
 57,880 
 
 
 178,901 
 
 
 51,096 
 
 
 7,920 
(b)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 869,675 
 
$
 595,100 
 
$
 1,146,655 
 
$
 297,463 
 
$
 428,380 
 
Operating Income
 
 101,954 
(c)
 
 60,734 
 
 
 162,418 
 
 
 23,380 
 
 
 163,813 
(d)
Net Income
 
 30,176 
(c)
 
 35,413 
 
 
 80,249 
 
 
 4,575 
 
 
 104,124 
(d)

Quarterly Periods Ended:
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
 
March 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 805,476 
 
$
 546,207 
 
$
 1,237,223 
 
$
 300,531 
 
$
 348,986 
 
Operating Income
 
 169,190 
 
 
 76,325 
 
 
 269,619 
 
 
 33,490 
 
 
 55,368 
 
Net Income
 
 75,311 
 
 
 39,221 
 
 
 150,830 
 
 
 12,648 
 
 
 36,395 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
June 30, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 716,461 
 
$
 510,876 
 
$
 1,113,750 
 
$
 317,311 
 
$
 390,946 
 
Operating Income
 
 143,426 
 
 
 64,803 
 
 
 210,004 
 
 
 69,299 
 
 
 72,976 
 
Net Income
 
 62,332 
 
 
 29,810 
 
 
 101,423 
 
 
 35,211 
 
 
 54,902 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
September 30, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 864,198 
 
$
 598,204 
 
$
 1,359,816 
 
$
 372,872 
 
$
 485,169 
 
Operating Income
 
 142,722 
 
 
 80,486 
 
 
 279,109 
 
 
 106,196 
 
 
 120,008 
 
Net Income
 
 63,191 
 
 
 39,254 
 
 
 151,510 
 
 
 58,103 
 
 
 89,218 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 890,796 
 
$
 544,824 
 
$
 1,217,407 
 
$
 242,224 
 
$
 352,733 
 
Operating Income (Loss)
 
 142,122 
 
 
 26,080 
 
 
 (81,785)
(e)
 
 21,965 
 
 
 27,544 
 
Net Income (Loss)
 
 56,669 
 
 
 10,172 
 
 
 (60,229)
(e)
 
 8,179 
 
 
 21,998 
 

(a)     Includes an impairment for Muskingum River Plant, Unit 5 (see Note 6).
(b)     Includes a regulatory disallowance for the Turk Plant (see Note 3).
(c)     Includes a regulatory disallowance for Amos Plant, Unit 3 (see Note 6).
(d)     Includes the reversal of regulatory disallowance for the Turk Plant (see Note 3).
(e)     Includes impairments for certain Ohio generation plants (see Note 6).

 
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COMBINED MANAGEMENT’S NARRATIVE DISCUSSION
AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the Registrant Subsidiaries’ management’s discussion and analysis.  The information in this section completes the information necessary for management’s discussion and analysis of financial condition and net income and is meant to be read with (a) Management’s Narrative Discussion and Analysis of Results of Operations, (b) financial statements, (c) footnotes and (d) the schedules of each individual registrant.

EXECUTIVE OVERVIEW

Repositioning Efforts

In April 2012, management initiated a process to identify strategic repositioning opportunities and efficiencies that resulted in sustainable cost savings.  This process included evaluations of employee and retiree benefit programs as well as evaluations of the functional effectiveness and staffing levels of the AEP System’s finance and accounting, information technology, generation and supply chain and procurement organizations.  While certain aspects of this program have been completed, continuous improvement initiatives in generation, distribution, transmission, supply chain, procurement and the corporate center continues to yield cost savings for many of the Registrant Subsidiaries, allowing management to direct many of these savings into infrastructure and other areas of the AEP System.

Customer Demand

In comparison to 2012, AEP's weather-normalized retail sales decreased 1.6% for the year ended December 31, 2013.  AEP's industrial sales declined 4.5% partially due to lower production levels at Ormet, a large aluminum company.  Ormet had a contract to purchase power from OPCo through 2018.  In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down its operations effective immediately.  The loss of Ormet's load will not have a material impact on future gross margin.  Power previously sold to Ormet will be available to be sold into wholesale markets.

In 2014, management anticipates AEP's weather-normalized retail sales will decline by 1.1%.  Excluding Ormet, total AEP weather-normalized retail sales are projected to increase by 0.1% in 2014.  The largest decline is projected to occur in AEP's industrial class, principally due to Ormet’s decision to shut down.  Excluding Ormet, the industrial class is projected to grow by 1.2% in 2014, primarily related to a number of new oil and natural gas expansions, especially around the major shale gas areas within AEP's footprint.  AEP's weather-normalized residential sales are projected to decline by 0.9% in 2014, continuing the recent trend of declining use per customer related to higher saturations of energy efficient appliances and the promotion of utility sponsored energy efficiency programs.  AEP's commercial class energy sales are projected to remain flat compared to 2013.

LITIGATION

Potential Uninsured Losses

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to damage to the Cook Plant and costs of replacement power in the event of a nuclear incident at the Cook Plant.  Future losses or liabilities, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition.

ENVIRONMENTAL ISSUES

The Registrant Subsidiaries are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements.  The Registrant Subsidiaries will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO 2 , NO x , PM and hazardous air pollutants (HAPs) from fossil fuel-fired power plants, proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.
 
 
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The Registrant Subsidiaries are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of I&M’s nuclear units.  AEP, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court.  Management is also engaged in the development of possible future requirements including the items discussed below and reductions of CO 2 emissions to address concerns about global climate change.  Management believes that further analysis and better coordination of these future environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

Management will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If the Registrant Subsidiaries are unable to recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of December 31, 2013, the AEP System had a total generating capacity of nearly 37,600 MWs, of which over 23,700 MWs are coal-fired.  Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on the coal-fired generating facilities.  For the Registrant Subsidiaries, management’s current ranges of estimates of environmental investments to comply with these proposed requirements are listed below:

 
 
 
2013 to 2020
 
 
 
Estimated Environmental Investment
Company
 
Low
 
High
 
 
(in millions) 
APCo
 
$
 310 
 
$
 360 
I&M
 
 
 410 
 
 
 470 
PSO
 
 
 280 
 
 
 320 
SWEPCo
 
 
 910 
 
 
 1,060 

For APCo, the projected environmental investments above include the conversions of 470 MWs of coal generation to natural gas capacity.  If natural gas conversion is not completed, the units could be retired sooner than planned.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules.  The cost estimates for each Registrant Subsidiary will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans or federal implementation plans that impose standards more stringent than the proposed rules, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on the units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.

 
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Subject to the factors listed above and based upon management’s continuing evaluation, management has given notice to the applicable RTOs of intent to retire the following plants or units of plants before or during 2016:

 
 
 
 
Generating
Company
 
Plant Name and Unit
 
Capacity
 
 
 
 
(in MWs) 
APCo
 
Clinch River Plant, Unit 3
 
 
 235 
APCo
 
Glen Lyn Plant
 
 
 335 
APCo
 
Kanawha River Plant
 
 
 400 
APCo/AGR
 
Sporn Plant, Units 1-4
 
 
 600 
I&M
 
Tanners Creek Plant, Units 1-4
 
 
 995 
PSO
 
Northeastern Station, Unit 4
 
 
 470 
SWEPCo
 
Welsh Plant, Unit 2
 
 
 528 

As of December 31, 2013, the net book value before cost of removal, including related material and supplies inventory and CWIP balances, of the plants in the table above was $750 million.

In addition, management is in the process of obtaining permits and other necessary regulatory approvals for either the conversion of some coal units to natural gas or installing emission control equipment on certain units.  The following table lists the plant that is either awaiting regulatory approval or is still being evaluated by management based on changes in emission requirements and demand for power:

 
 
 
 
Generating
Company
 
Plant Name and Unit
 
Capacity
 
 
 
 
(in MWs) 
PSO
 
Northeastern Station, Unit 3
 
 
 470 

As of December 31, 2013, the net book value before cost of removal, including related material and supplies inventory and CWIP balances, of the plant in the table above was $208 million.

Volatility in natural gas prices, pending environmental rules and other market factors could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of coal-fired units.  For regulated plants that may be closed early, management is seeking regulatory recovery of remaining net book values.  To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows.

Modification of the NSR Litigation Consent Decree

In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between AEP subsidiaries in the eastern area of the AEP System and the Department of Justice, the Federal EPA, eight northeastern states and other interested parties to settle claims that the AEP subsidiaries violated the NSR provisions of the CAA when they undertook various equipment repair and replacement projects over a period of nearly 20 years.  The consent decree’s terms include installation of environmental control equipment on certain generating units, a declining cap on SO 2 and NO x emissions from the AEP System and various mitigation projects.

The original consent decree requires certain types of control equipment to be installed at Muskingum River Plant, Unit 5, Big Sandy Plant, Unit 2 and the two units of the Rockport Plant in 2015, 2017 and 2019, respectively.  In January 2013, an agreement to modify the consent decree was reached and filed with the court.  The terms of the modification include more options for the affected units (including alternative control technologies, re-fueling and/or retirement), more stringent SO 2 emission caps for the AEP System and additional mitigation measures.  The modified consent decree was approved by the court in May 2013.  For the units of the Rockport Plant, the modified decree requires installation of dry sorbent injection technology for SO 2 control on both units in 2015.  In addition, the consent decree imposes a declining plant-wide cap on SO 2 emissions beginning in 2016.

 
378

 
Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions.  The states implement and administer many of these programs and could impose additional or more stringent requirements.

The Federal EPA issued the Clean Air Interstate Rule (CAIR) in 2005 requiring specific reductions in SO 2 and NO x emissions from power plants.  In 2008, the District of Columbia Circuit Court of Appeals issued a decision remanding CAIR to the Federal EPA.  The Federal EPA issued the Cross-State Air Pollution Rule (CSAPR) (discussed in detail below) in August 2011 to replace CAIR.  The CSAPR was challenged in the courts.  The U.S. Court of Appeals for the District of Columbia Circuit issued an order in December 2011 staying the effective date of the rule pending judicial review.  In 2012, a panel of the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing CAIR until a replacement rule is finalized.  That decision has been appealed to the U.S. Supreme Court.  Nearly all of the states in which the Registrant Subsidiaries’ power plants are located are covered by CAIR.
 
The Federal EPA issued final maximum achievable control technology (MACT) standards for coal and oil-fired power plants (discussed in detail below) in 2012.

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) to address regional haze in federal parks and other protected areas.  BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.  CAVR will be implemented through individual state implementation plans (SIPs) or, if SIPs are not adequate or are not developed on schedule, through federal implementation plans (FIPs).  The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas.  The Arkansas SIP was disapproved and the state is developing a revised submittal.  In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the CSAPR trading programs to use those programs in place of source-specific BART for SO 2 and NO x emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states.  This rule is being challenged in the U.S. Court of Appeals for the District of Columbia Circuit and its fate is uncertain given recent developments in the CSAPR litigation.

In 2009, the Federal EPA issued a final mandatory reporting rule for CO 2 and other greenhouse gases covering a broad range of facilities emitting in excess of 25,000 tons of CO 2 emissions per year.   The Federal EPA issued a final endangerment finding for greenhouse gas emissions from new motor vehicles in 2009.  The Federal EPA determined that greenhouse gas   emissions from stationary sources will be subject to regulation under the CAA beginning January 2011 and finalized its proposed scheme to streamline and phase-in regulation of stationary source CO 2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs through the issuance of final federal rules, SIP calls and FIPs.  The Federal EPA has proposed to include CO 2 emissions in standards that apply to new electric utility units and will consider whether such standards are appropriate for other source categories in the future.

The Federal EPA has also issued new, more stringent national ambient air quality standards (NAAQS) for PM, SO 2 , NO 2 and lead, and is currently reviewing the NAAQS for ozone.  States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for facilities as a result of those evaluations.  Management cannot currently predict the nature, stringency or timing of those requirements.

Notable developments in significant CAA regulatory requirements affecting the Registrant Subsidiaries’ operations are discussed in the following sections.

Cross-State Air Pollution Rule (CSAPR)

In 2011, the Federal EPA issued CSAPR.  Certain revisions to the rule were finalized in 2012.  CSAPR relies on newly-created SO 2 and NO x allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states.  Interstate trading of allowances is allowed on a restricted sub-regional basis.  Arkansas and Louisiana are subject only to the seasonal NO x program in the rule.  Texas is subject to the
 
 
379

 
annual programs for SO 2 and NO x in addition to the seasonal NO x program.  The annual SO 2 allowance budgets in Indiana, Ohio and West Virginia were reduced significantly in the rule .   A supplemental rule includes Oklahoma in the seasonal NO x program.  The supplemental rule was finalized in December 2011 with an increased NO x emission budget for the 2012 compliance year.  The Federal EPA issued a final Error Corrections Rule and further CSAPR revisions in 2012 to make corrections to state budgets and unit allocations and to remove the restrictions on interstate trading in the first phase of CSAPR.

Numerous affected entities, states and other parties filed petitions to review the CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit.  Several of the petitioners filed motions to stay the implementation of the rule pending judicial review.  In 2011, the court granted the motions for stay.  In 2012, the panel issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing the Clean Air Interstate Rule until a replacement rule is finalized.  The majority determined that the CAA does not allow the Federal EPA to “overcontrol” emissions in an upwind state and that the Federal EPA exceeded its statutory authority by failing to allow states an opportunity to develop their own implementation plans before issuing a FIP.  The Federal EPA and other respondents filed petitions for rehearing but in January 2013, the U.S. Court of Appeals for the District of Columbia Circuit denied all petitions for rehearing.  The petition for further review filed by the Federal EPA and other parties in the U.S. Supreme Court was granted in June 2013.  Separate appeals of the supplemental rule, the Error Corrections Rule and the further revisions have been filed, but are being held in abeyance.

The time frames and stringency of the required emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and its electric utility customers.  Management cannot predict the outcome of the pending litigation.

Mercury and Other Hazardous Air Pollutants Regulation

In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal on a site-wide 30-day rolling average basis.  In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  The effective date of the final rule was April 16, 2012 and compliance is required within three years.  The AEP System is participating through various organizations in the petitions for administrative reconsideration and judicial review that have been filed.  In 2012, the Federal EPA published a notice announcing that it would accept comments on its reconsideration of certain issues related to the new source standards, including clarification of the requirements that apply during periods of start-up and shut down, measurement issues and the application of variability factors that may have an impact on the level of the standards.  The Federal EPA issued revisions to the new source standards consistent with the proposed rule, except the start-up and shut down provisions in March 2013.  The Federal EPA is still considering additional changes to the start-up and shut down provisions.

The final rule contains a slightly less stringent PM limit for existing sources than the original proposal and allows operators to exclude periods of start-up and shut down from the emissions averaging periods.  The compliance time frame remains a serious concern.  A one-year administrative extension may be available if the extension is necessary for the installation of controls or to avoid a serious reliability problem.  In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades.  Management is concerned about the availability of compliance extensions and the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines.  The AEP System is participating in petitions for review filed in the U. S. Court of Appeals for the District of Columbia Circuit by several organizations of which companies in the AEP System are members.  Certain issues related to the standards for new coal-fired units have been severed from the main case and are being held in abeyance pending completion of the Federal EPA’s reconsideration proceeding.  The case is briefed and argued, and remains pending before the court.

 
380

 
Regional Haze – Oklahoma Affecting PSO

In 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze SIP submitted by the State of Oklahoma through the Department of Environmental Quality.  The Federal EPA proposed to approve all of the NO x control measures in the SIP and disapprove the SO 2 control measures for six electric generating units, including two units owned by PSO.  The Federal EPA finalized a FIP that would require these units to install technology capable of reducing SO 2 emissions to 0.06 pounds per million British thermal units within five years of the effective date of the FIP.  PSO filed a petition for review of the FIP in the Tenth Circuit Court of Appeals and engaged in settlement discussions with the Federal EPA, the State of Oklahoma and other parties.  In November 2012, PSO notified the court that the parties had reached agreement on a settlement that would provide for submission of a revised Regional Haze SIP requiring the retirement of one coal-fired unit of PSO’s Northeastern Station no later than 2016, installation of emission controls on the second coal-fired Northeastern unit in 2016 and retirement of the second unit no later than 2026.  The Tenth Circuit Court of Appeals is holding the appeal in abeyance pending implementation of the settlement.  A revised regional haze SIP was adopted by the State of Oklahoma and the Federal EPA approved the revised SIP in February 2014.  Upon publication of the final approval and withdrawal of the FIP, the Tenth Circuit proceeding will be dismissed.

CO 2 Regulation

In March 2012, the Federal EPA issued a proposal to regulate CO 2 emissions from new fossil fuel-fired electricity generating units.  The proposed rule establishes a new source performance standard of 1,000 pounds of CO 2 per megawatt hour of electricity generated, a rate that most natural gas combined cycle units can meet, but that is substantially below the emission rate of a new pulverized coal generator or an integrated gas combined cycle unit that uses coal for fuel.  As proposed, the rule does not apply to new gas-fired stationary combustion turbines used as peaking units, does not apply to existing, modified or reconstructed sources and does not apply to units whose CO 2 emission rate increases as a result of the addition of pollution control equipment to control criteria pollutant emissions or HAPs.  The rule is not anticipated to have a significant immediate impact on the AEP System since it does not apply to existing units or units that have already commenced construction.  New source performance standards affect units that have not yet received permits.  The proposed standards were challenged in the U.S. Court of Appeals for the District of Columbia Circuit.  That case was dismissed because the court determined that no final agency action had yet been taken.

In June 2013, President Obama issued a memorandum to the Administrator of the Federal EPA directing the agency to develop and issue a new proposal regulating carbon emissions from new electric generating units in September 2013.  The new proposal was issued in September 2013 and requires new large natural gas units to meet 1,000 pounds of CO 2 per MWh of electricity generated and small natural gas units to meet 1,100 pounds of CO 2 per MWh.  New coal-fired units are required to meet the 1,100 pounds of CO 2 per MWh limit, with the option to meet the tighter limits if they choose to average emissions over multiple years.  This proposal was published in the Federal Register in January 2014 and the March 2012 proposal has been withdrawn.

The Federal EPA was also directed to develop and issue a separate proposal regulating carbon emissions from existing, modified and reconstructed electric generating units before June 2014, to finalize those standards by June 2015 and to require states to submit revisions to their implementation plans including such standards no later than June 2016.  The President directed the Federal EPA, in developing this proposal, to directly engage states, leaders in the power sector, labor leaders and other stakeholders, to tailor the regulations to reduce costs, to develop market-based instruments and allow regulatory flexibilities and “assure that the standards are developed and implemented in a manner consistent with the continued provision of reliable and affordable electric power.”  Management cannot currently predict the impact these programs may have on future resource plans or the existing generating fleet, but the costs may be substantial.

In June 2012, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision upholding, in all material respects, the Federal EPA’s endangerment finding, its regulatory program for CO 2 emissions from new motor vehicles and its plan to phase-in regulation of CO 2 emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs. A petition for rehearing was filed which the court denied in December 2012. The U.S. Supreme Court granted several petitions for review and will determine whether the Federal EPA made a reasonable determination that adoption of the motor vehicle standards trigger PSD and Title V permitting obligations for stationary sources.  A decision is expected by June 2014.

 
 
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The Federal EPA also finalized a rule in June 2012 that retains the current thresholds for permitting stationary sources under the PSD and Title V operating permit programs at 100,000 tons per year for new sources and 75,000 tons per year for modified sources.  The Federal EPA also confirmed that it will re-evaluate these thresholds during its five-year review in 2016.  The AEP System’s generating units are large sources of CO 2 emissions and management will continue to evaluate permitting obligations in light of these thresholds.

Coal Combustion Residual Rule

In 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units.  The rule contains two alternative proposals.  One proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management.  Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and initiate closure within five years of the issuance of a final rule.  In 2011, the Federal EPA issued a notice of data availability requesting comments on a number of technical reports and other data received during the comment period for the original proposal and requesting comments on potential modeling analyses to update its risk assessment.  In 2013, the Federal EPA also issued a notice of data availability requesting comments on a narrow set of items.

Various environmental organizations and industry groups filed a petition seeking to establish deadlines for a final rule.  The Federal EPA opposed the petition and sought additional time to coordinate the issuance of a final rule with the issuance of new effluent limitations under the Clean Water Act for utility facilities.  In October 2013, the U.S. District Court for the District of Columbia issued a final order partially ruling in favor of the Federal EPA for dismissal of two counts, ruling in favor of the environmental organizations on one count and directing the Federal EPA to provide the court with a proposed schedule for completion of the rulemaking.  In January 2014, the parties filed a motion with the court to establish December 2014 as the Federal EPA’s deadline for publication of the rule.  The court will establish a deadline for the final rule following a comment period for interested parties.

In February 2014, the Federal EPA completed an evaluation of the beneficial uses of coal fly ash in concrete and wallboard and concluded that the Federal EPA supports these beneficial uses.   Currently, approximately 40% of the coal ash and other residual products from the AEP System’s generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses.  Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes.  In addition,  surface impoundments and landfills to manage these materials are currently used at the generating facilities. The Registrant Subsidiaries will incur significant costs to upgrade or close and replace their existing facilities under the proposed solid waste management alternative.  Regulation of these materials as hazardous wastes would significantly increase these costs.  As the rule is not final, management is unable to determine a range of potential costs that are reasonably possible of occurring but expect the costs to be significant.

Clean Water Act Regulations

In 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement.  Compliance with this standard is required within eight years of the effective date of the final rule.  The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment.  The proposed entrainment standard for new units at existing facilities requires either intake flows commensurate with closed cycle cooling or achieving entrainment reductions equivalent to 90% or greater of the reductions that could be achieved with closed cycle cooling.  Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority.  Management is evaluating the proposal and engaged in the collection of
 
 
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additional information regarding the feasibility of implementing this proposal at the AEP System’s facilities.  In June 2012, the Federal EPA issued additional Notices of Data Availability and requested public comments.  The AEP System submitted comments in July 2012.  Issuance of a final rule is expected in 2014.  Management is preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.

In addition, the Federal EPA issued an information collection request and is developing revised effluent limitation guidelines for electricity generating facilities.  A proposed rule was signed in April 2013 with a final rule expected in 2014.  The Federal EPA proposed eight options of increasing stringency and cost for fly ash and bottom ash transport water, scrubber wastewater, leachate from coal combustion byproduct landfills and impoundments and other wastewaters associated with coal-fired generating units, with four labeled preferred options.  Certain of the Federal EPA's preferred options have already been implemented or are part of the Registrant Subsidiaries’ long-term plans.  Management continues to review the proposal in detail to evaluate whether the plants are currently meeting the proposed limitations, what technologies have been incorporated into long-range plans and what additional costs might be incurred if the Federal EPA's most stringent options were adopted.  Management submitted detailed comments to the Federal EPA in September 2013 and participated in comments filed by various organizations of which the AEP System is a member.

Climate Change

National public policy makers and regulators in the 10 states the Registrant Subsidiaries serve have diverse views on climate change.  Management is currently focused on responding to these emerging views with prudent actions, such as improving energy efficiency, investing in developing cost-effective and less carbon-intensive technologies and evaluating assets across a range of plausible scenarios and outcomes.  Management is also an active participant in a variety of public policy discussions at state and federal levels to assure that proposed new requirements are feasible and the economies of the states served are not placed at a competitive disadvantage.

While comprehensive economy-wide regulation of CO 2 emissions might be achieved through future legislation, Congress has yet to enact such legislation.  The Federal EPA continues to take action to regulate CO 2 emissions under the existing requirements of the CAA.

Several states have adopted programs that directly regulate CO 2 emissions from power plants.  The majority of the states where the Registrant Subsidiaries have generating facilities passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements.  The Registrant Subsidiaries are taking steps to comply with these requirements.  In order to meet these requirements and as a key part of AEP’s corporate sustainability effort, management pledged to increase wind power.

The AEP System has taken measurable, voluntary actions to reduce and offset CO 2 emissions.  Management estimates that 2013 emissions were approximately 115 million metric tons.  This represents a reduction of 21% compared to 2005 CO 2 emissions of approximately 145 million metric tons.

Future federal and state legislation or regulations that mandate limits on the emission of CO 2 could result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs.  Excessive costs to comply with future legislation or regulations might force the Registrant Subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets.  Public perception may ultimately have a significant impact on future legislation and regulation that could adversely affect the Registrant Subsidiaries’ ability to recover their investments in coal-fired plants.

Climate change and its resultant impact on weather patterns could modify the Registrant Subsidiaries’ customers’ power usage.  Customers’ energy needs currently vary with weather conditions and the economy.  Increased or decreased energy usage could require the acquisition or construction of more generation and transmission assets or cause early retirement of such assets.  The timing and duration of extreme weather conditions may require more system backup and contribute to increased system stresses, including service interruptions and increased storm restoration costs.  Extreme weather conditions that create high energy demand could raise electricity prices, which could increase the cost of energy provided to customers and could provide opportunity for increased wholesale sales and higher margins.

 
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To the extent climate change impacts a region's economic health, it could also affect revenues.  The Registrant Subsidiaries’ financial performance is tied to the health of the regional economies served.  The price of energy, as a factor in a region's cost of living as well as an important input into the cost of goods, has an impact on the economic health of communities served.  The cost of additional regulatory requirements would normally be borne by consumers through higher prices for energy and purchased goods.

FINANCIAL CONDITION

BUDGETED CONSTRUCTION EXPENDITURES

The 2014 estimated construction expenditures by Registrant Subsidiary include distribution, transmission and generation related investments, as well as expenditures for compliance with environmental regulations as follows:

 
 
2014 Budgeted Construction Expenditures
Company
 
Environmental
 
Generation
 
Transmission
 
Distribution
 
Other
 
Total
 
 
 
(in millions)
APCo
 
$
 48 
 
$
 105 
 
$
 180 
 
$
 162 
 
$
 21 
 
$
 516 
I&M
 
 
 55 
 
 
 219 
 
 
 47 
 
 
 102 
 
 
 18 
 
 
 441 
OPCo
 
 
 - 
 
 
 - 
 
 
 90 
 
 
 292 
 
 
 24 
 
 
 406 
PSO
 
 
 66 
 
 
 38 
 
 
 67 
 
 
 164 
 
 
 11 
 
 
 346 
SWEPCo
 
 
 217 
 
 
 33 
 
 
 142 
 
 
 84 
 
 
 13 
 
 
 489 

For 2014, 2015 and 2016, management forecasts annual construction expenditures for the AEP System of $3.8 billion each year.  The budgeted amounts exclude equity AFUDC.  The expenditures are generally for distribution, transmission and required environmental investment to comply with Federal EPA rules.  Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  These construction expenditures will be funded through cash flows from operations and financing activities.  Generally, the Registrant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged.

SIGNIFICANT TAX LEGISLATION

The Small Business Jobs Act extended the time for claiming bonus depreciation and increased the deduction to 100% for 2011 and decreased the deduction to 50% for 2012.  The American Taxpayer Relief Act of 2012 provided for the extension of several business and energy industry tax deductions and credits, including the one year extension of 50% bonus depreciation to 2013.  The enacted provisions had no material impact on the Registrant Subsidiaries’ net income or financial condition but did have a favorable impact on cash flows in 2013.

CYBER SECURITY

Cyber security presents a heightened risk for electric utility systems because a cyber-attack could affect critical energy infrastructure.  Breaches to the cyber security of the grid or to the AEP System are potentially disruptive to people, property and commerce and create risk for business, investors and customers.  In February 2013, President Obama signed an executive order that addresses how government agencies will operate and support the functions in cyber security as well as redefine how the government interfaces with critical infrastructure, such as the electric grid.  The AEP System already operates under regulatory cyber security standards to protect critical infrastructure.  The cyber security framework that is being developed through this executive order will be reviewed by the FERC and the U.S. Department of Energy.  AEP participates in the process by submitting feedback through its industry trade group and sharing best practices already in place.  Critical cyber assets, such as data centers, power plants, transmission operations centers and business networks, are protected using multiple layers of cyber security and authentication.  The AEP System is constantly scanned for risks or threats.

Cyber hackers have been able to breach a number of very secure facilities, from federal agencies, banks and retailers to social media sites.  As these events become known and develop, AEP continually assess its cyber security tools and processes to determine where to strengthen its defenses.

 
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In recent years, management has taken additional steps to enhance AEP System’s capabilities for identifying risks or threats and has shared those threats with utility peers, industry and federal agencies.  The AEP System operates a Cyber Security Operations Center.  Funding for this included a grant from the American Recovery and Reinvestment Act – U.S. Department of Energy Smart Grid Demonstration Program.  This facility was initially designed as a pilot cyber threat and information-sharing center specifically for the electric sector and today is fully operational.

In 2013, as part of the industry’s continuing program to advance threat sharing and coordination, AEP participated in the North American Electric Reliability Corporation (NERC) GridEx II exercise.  This effort, led by NERC, tested and developed the coordination and interaction between utilities and various government agencies relative to potential cyber and physical threats against the nation’s electric grid.

In 2012, AEP signed a cooperative research and development agreement with the Department of Homeland Security’s Office of Cyber Security and Communications, further enhancing its ability to directly exchange information about cyber threats.  In addition, AEP continues to partner with a number of federal and industry groups to advance the national capabilities of cyber security.  AEP is working with the U.S. Department of Energy on several projects covering advanced cyber security and assessment tools.

AEP has partnered with a major defense contractor who has significant cyber security experience and technical capabilities developed through their work with the U.S. Department of Defense.  AEP works with a consortium of other utilities across the country, learning how best to share information about potential threats and collaborating with each other.  AEP continues to work with a nonaffiliated entity to conduct several seminars each year about recognizing and investigating cyber vulnerabilities.  Through these types of efforts, AEP is working to protect itself while helping its industry advance its cyber security capabilities.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES AND ACCOUNTING PRONOUNCEMENTS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures, including amounts related to legal matters and contingencies.  Management considers an accounting estimate to be critical if:

·  
It requires assumptions to be made that were uncertain at the time the estimate was made; and
·  
Changes in the estimate or different estimates that could have been selected could have a material effect on net income or financial condition.

Management discusses the development and selection of critical accounting estimates as presented below with the Audit Committee of AEP’s Board of Directors and the Audit Committee reviews the disclosures relating to them.

Management believes that the current assumptions and other considerations used to estimate amounts reflected in the financial statements are appropriate.  However, actual results can differ significantly from those estimates.

The sections that follow present information about the Registrant Subsidiaries’ critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop each estimate.

Regulatory Accounting

Nature of Estimates Required

The financial statements of the Registrant Subsidiaries with cost-based rate-regulated operations (APCo, I&M, PSO, SWEPCo and a portion of OPCo) reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.

 
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The Registrant Subsidiaries recognize regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) for the economic effects of regulation.  Specifically, the Registrant Subsidiaries match the timing of expense and income recognition with regulated revenues.  Liabilities are also recorded for refunds, or probable refunds, to customers that have not been made.

Assumptions and Approach Used

When incurred costs are probable of recovery through regulated rates, the Registrant Subsidiaries record them as regulatory assets on the balance sheet.  Management reviews the probability of recovery at each balance sheet date and whenever new events occur.  Similarly, the Registrant Subsidiaries record regulatory liabilities when a determination is made that a refund is probable or when ordered by a commission.   Examples of new events that affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation.  The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs as well as the return of revenues, rate of return earned on invested capital and timing and amount of assets to be recovered through regulated rates.  If recovery of a regulatory asset is no longer probable, that regulatory asset is written-off as a charge against earnings.  A write-off of regulatory assets or establishment of a regulatory liability may also reduce future cash flows since there will be no recovery through regulated rates.

Effect if Different Assumptions Used

A change in the above assumptions may result in a material impact on net income.  Refer to Note 4 for further detail related to regulatory assets and liabilities.

Revenue Recognition – Unbilled Revenues

Nature of Estimates Required

The Registrant Subsidiaries record revenues when energy is delivered to the customer.  The determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue accrual is recorded.  This estimate is reversed in the following month and actual revenue is recorded based on meter readings.  In accordance with the applicable state commission regulatory treatment in Arkansas, Louisiana, Oklahoma and Texas, PSO and SWEPCo do not record the fuel portion of unbilled revenue.

The changes in unbilled electricity utility revenues for the years ended December 31, 2013, 2012 and 2011 were as follows:

 
 
Years Ended December 31,
Company
 
2013 
 
2012 
 
2011 
 
 
(in thousands)
APCo
 
$
(11,600)
 
$
8,047 
 
$
 (41,979)
I&M
 
 
6,077 
 
 
(1,233)
 
 
 (2,628)
OPCo
 
 
(17,375)
 
 
(14,721)
 
 
 (20,449)
PSO
 
 
(3,842)
 
 
5,213 
 
 
 641 
SWEPCo
 
 
3,225 
 
 
2,302 
 
 
 643 

Assumptions and Approach Used

For each Registrant Subsidiary, the monthly estimate for unbilled revenues is computed as net generation (generation plus purchases less sales) less the current month’s billed KWh plus the prior month’s unbilled KWh.  However, due to meter reading issues, meter drift and other anomalies, a separate monthly calculation limits the unbilled estimate within a range of values.  This limiter calculation is derived from an allocation of billed KWh to the current month and previous month, on a cycle-by-cycle basis, and dividing the current month aggregated result by the billed KWh.  The limits are statistically set at one standard deviation from this percentage to determine the upper and lower limits of the range.  The unbilled estimate is compared to the limiter calculation and adjusted for variances exceeding the upper and lower limits.


 
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Effect if Different Assumptions Used

Significant fluctuations in energy demand for the unbilled period, weather, line losses or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate.  A 1% change in the limiter calculation when it is outside the range would increase or decrease unbilled revenues by 1% of the accrued unbilled revenues.

Accounting for Derivative Instruments

Nature of Estimates Required

Management considers fair value techniques, valuation adjustments related to credit and liquidity and judgments related to the probability of forecasted transactions occurring within the specified time period to be critical accounting estimates.  These estimates are considered significant because they are highly susceptible to change from period to period and are dependent on many subjective factors.

Assumptions and Approach Used

The Registrant Subsidiaries measure the fair values of derivative instruments and hedge instruments accounted for using MTM accounting based primarily on exchange prices and broker quotes.  If a quoted market price is not available, the fair value is estimated based on the best market information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and other assumptions.  Fair value estimates, based upon the best market information available, involve uncertainties and matters of significant judgment.  These uncertainties include projections of macroeconomic trends and future commodity prices, including supply and demand levels and future price volatility.

The Registrant Subsidiaries reduce fair values by estimated valuation adjustments for items such as discounting, liquidity and credit quality.  Liquidity adjustments are calculated by utilizing bid/ask spreads to estimate the potential fair value impact of liquidating open positions over a reasonable period of time.  Credit adjustments on risk management contracts are calculated using estimated default probabilities and recovery rates relative to the  counterparties or counterparties with similar credit profiles and contractual netting agreements.  With respect to hedge accounting, management assesses hedge effectiveness and evaluates a forecasted transaction’s probability of occurrence within the specified time period as provided in the original hedge documentation.

Effect if Different Assumptions Used

There is inherent risk in valuation modeling given the complexity and volatility of energy markets.  Therefore, it is possible that results in future periods may be materially different as contracts settle.

The probability that hedged forecasted transactions will not occur by the end of the specified time period could change operating results by requiring amounts currently classified in Accumulated Other Comprehensive Income (Loss) to be classified into operating income.

For additional information regarding derivatives, hedging and fair value measurements, see Notes 9 and 10.  See “Fair Value Measurements of Assets and Liabilities” section of Note 1 for fair value calculation policy.

Long-Lived Assets

Nature of Estimates Required

In accordance with the requirements of “Property, Plant and Equipment” accounting guidance, the Registrant Subsidiaries evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable including planned abandonments and a probable disallowance for rate-making on a plant under construction or the assets meet the held-for-sale criteria.  The Registrant Subsidiaries utilize a group composite method of depreciation to estimate the useful lives of long-lived assets.  The evaluations of long-lived, held-and-used assets may result from abandonments, significant decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used or
 
 
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in its physical condition, a significant adverse change in legal factors or in the business climate that could affect the value of an asset, as well as other economic or operations analyses.  If the carrying amount is not recoverable, the Registrant Subsidiary records an impairment to the extent that the fair value of the asset is less than its book value.  Performing an impairment evaluation involves a significant degree of estimation and judgment in areas such as identifying circumstances that indicate an impairment may exist, identifying and grouping affected assets and developing the undiscounted and discounted future cash flows (used to estimate fair value in the absence of market-based value, in some instances) associated with the asset.  For assets held for sale, an impairment is recognized if the expected net sales price is less than its book value.  For regulated assets, the earnings impact of an impairment charge could be offset by the establishment of a regulatory asset, if rate recovery is probable.

Assumptions and Approach Used

The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties other than in a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets in active markets, management estimates fair value using various internal and external valuation methods including cash flow projections or other market indicators of fair value such as bids received, comparable sales or independent appraisals.  Cash flow estimates are based on relevant information available at the time the estimates are made.  Estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.  Also, when measuring fair value, management evaluates the characteristics of the asset or liability to determine if market participants would take those characteristics into account when pricing the asset or liability at the measurement date.  Such characteristics include, for example, the condition and location of the asset or restrictions of the use of the asset.  Management performs depreciation studies that include a review of any external factors that may affect the useful life to determine composite depreciation rates and related lives which are subject to periodic review by state regulatory commissions for cost-based regulated assets.  The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.

Effect if Different Assumptions Used

In connection with the evaluation of long-lived assets in accordance with the requirements of “Property, Plant and Equipment” accounting guidance, the fair value of the asset can vary if different estimates and assumptions would have been used in the applied valuation techniques.  The estimate for depreciation rates takes into account the history of interim capital replacements and the amount of salvage expected.  In cases of impairment, the best estimate of fair value was made using valuation methods based on the most current information at that time.  Fluctuations in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including, but not limited to, differences in subsequent market conditions, the level of bidder interest, timing and terms of the transactions and management’s analysis of the benefits of the transaction.

Pension and Other Postretirement Benefits

AEP maintains a qualified, defined benefit pension plan (Qualified Plan), which covers substantially all nonunion and certain union employees, and unfunded, nonqualified supplemental plans (Nonqualified Plans) to provide benefits in excess of amounts permitted under the provisions of the tax law for participants in the Qualified Plan (collectively the Pension Plans).  Additionally, AEP entered into individual employment contracts with certain current and retired executives that provide additional retirement benefits as a part of the Nonqualified Plans.  AEP also sponsors other postretirement benefit plans to provide health and life insurance benefits for retired employees (Postretirement Plans).  The Pension Plans and Postretirement Plans are collectively referred to as the Plans.  The Registrant Subsidiaries participate in the Plans.

For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Investments Held in Trust for Future Liabilities” and “Fair Value Measurements of Assets and Liabilities” sections of Note 1.  See Note 7 for information regarding costs and assumptions for employee retirement and postretirement benefits.


 
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The following table shows the net periodic cost (credit) by Registrant Subsidiary for the Plans:

 
 
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
Years Ended December 31,
Net Periodic Cost (Credit)
 
2013 
 
2012 
 
2011 
 
2013 
 
2012 
 
2011 
 
 
 
(in thousands)
APCo
 
$
 22,015 
 
$
 16,646 
 
$
 15,146 
 
$
 72 
 
$
 15,540 
 
$
 13,301 
I&M
 
 
 21,893 
 
 
 16,563 
 
 
 15,205 
 
 
 (3,638)
 
 
 11,358 
 
 
 9,360 
OPCo
 
 
 17,295 
 
 
 18,978 
 
 
 19,418 
 
 
 579 
 
 
 20,282 
 
 
 16,651 
PSO
 
 
 11,022 
 
 
 7,495 
 
 
 7,388 
 
 
 (1,737)
 
 
 4,821 
 
 
 3,881 
SWEPCo
 
 
 12,519 
 
 
 8,307 
 
 
 7,488 
 
 
 (2,115)
 
 
 5,928 
 
 
 4,841 

The net periodic benefit cost is calculated based upon a number of actuarial assumptions, including expected long-term rates of return on the Plans’ assets.  In developing the expected long-term rate of return assumption for 2014, management evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions.  Management also considered historical returns of the investment markets and changes in tax rates which affect a portion of the Postretirement Plans’ assets.  Management anticipates that the investment managers employed for the Plans will invest the assets to generate future returns averaging 6% for the Qualified Plan and 6.75% for the Postretirement Plans.

The expected long-term rate of return on the Plans’ assets is based on AEP’s targeted asset allocation and expected investment returns for each investment category.  Assumptions for the Plans are summarized in the following table:

 
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
 
 
Assumed/
 
 
 
Assumed/
 
 
2014 
 
Expected
 
2014 
 
Expected
 
 
Target
 
Long-Term
 
Target
 
Long-Term
 
 
Asset
 
Rate of
 
Asset
 
Rate of
 
 
Allocation
 
Return
 
Allocation
 
Return
 
Equity
 30 
%
 
 8.00 
%
 
 66 
%
 
 7.80 
%
 
Fixed Income
 55 
%
 
 4.60 
%
 
 33 
%
 
 4.40 
%
 
Other Investments
 15 
%
 
 7.00 
%
 
%
 
 - 
%
 
Cash and Cash Equivalents
%
 
%
 
 1 
%
 
 3.00 
%
 
Total
 100 
%
 
 
 
 
 100 
%
 
 
 

Management regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation.  Management believes that 6% and 6.75% are reasonable estimates of the long-term rate of return on the Plans’ assets.  The Pension Plans’ assets had an actual gain of 8.1% and 13.8% for the years ended December 31, 2013 and 2012, respectively.  The Postretirement Plans’ assets had an actual gain of 14.3% and 15.4% for the years ended December 31, 2013 and 2012, respectively.  Management will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the assumptions as necessary.


 
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AEP bases the determination of pension expense or income on a market-related valuation of assets, which reduces year-to-year volatility.  This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets.  Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.  As of December 31, 2013, AEP had cumulative gains of approximately $207 million that remain to be recognized in the calculation of the market-related value of assets.  These unrecognized net actuarial gains may result in decreases in the future pension costs depending on several factors, including whether such gains at each measurement date exceed the corridor in accordance with “Compensation – Retirement Benefits” accounting guidance.  See the table below for the amount of cumulative gains by Registrant Subsidiary.

Cumulative Gains –
 
 
Deferred Asset Gain
 
December 31, 2013
 
 
(in thousands)
APCo
 
$
 27,644 
I&M
 
 
 24,613 
OPCo
 
 
 22,082 
PSO
 
 
 11,648 
SWEPCo
 
 
 12,279 

The method used to determine the discount rate that AEP utilizes for determining future obligations is a duration-based method in which a hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability.  The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.  The discount rate as of December 31, 2013 under this method was 4.7% for the Qualified Plan, 4.55% for the Nonqualified Plans and 4.7% for the Postretirement Plans.  Due to the effect of the unrecognized actuarial gains and based on an expected rate of return on the Pension Plans’ assets of 6%, discount rates of 4.7% and 4.55% and various other assumptions, management estimates that the pension costs by Registrant Subsidiary for all pension plans will approximate the amounts in the following table.  Based on an expected rate of return on the OPEB plans’ assets of 6.75%, a discount rate of 4.7% and various other assumptions, management estimates Postretirement Plan credits by Registrant Subsidiary will approximate the amounts in the following table.

 
 
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
Estimated Postretirement
 
Years Ended December 31,
Plan Costs (Credits)
 
2014 
 
2015 
 
2016 
 
2014 
 
2015 
 
2016 
 
 
 
(in thousands)
APCo
 
$
 19,138 
 
$
 12,538 
 
$
 12,004 
 
$
 (9,330)
 
$
 (10,987)
 
$
 (10,997)
I&M
 
 
 19,447 
 
 
 13,574 
 
 
 12,946 
 
 
 (10,840)
 
 
 (11,381)
 
 
 (11,359)
OPCo
 
 
 15,161 
 
 
 10,141 
 
 
 9,869 
 
 
 (9,369)
 
 
 (9,812)
 
 
 (9,755)
PSO
 
 
 10,317 
 
 
 7,842 
 
 
 7,903 
 
 
 (5,048)
 
 
 (5,294)
 
 
 (5,280)
SWEPCo
 
 
 11,823 
 
 
 9,343 
 
 
 9,446 
 
 
 (5,895)
 
 
 (6,183)
 
 
 (6,179)

Future actual costs will depend on future investment performance, changes in future discount rates and various other factors related to each Registrant Subsidiary’s populations participating in the Plans.  The actuarial assumptions used may differ materially from actual results.  The effects of a 50 basis point change to selective actuarial assumptions are included in the “Effect if Different Assumptions Used” section below.

In November 2012, management announced changes to the retiree medical coverage.  Effective for retirements after December 2012, management capped contributions to retiree medical costs reducing the Registrant Subsidiaries’ future exposure to medical cost inflation.  Effective for employees hired after December 2013, retiree medical coverage will not be provided.  This change will reduce costs of the plan beginning in 2013 as shown by the estimated credits for Postretirement Plans in the previous table.

 
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The value of AEP’s Pension Plans’ assets remained unchanged at $4.7 billion as of December 31, 2013 and 2012 primarily due to investment returns offsetting benefit payments.  During 2013, the Qualified Plan paid $324 million and the Nonqualified Plans paid $7 million in benefits to plan participants.  The value of AEP’s Postretirement Plans’ assets increased to $1.7 billion as of December 31, 2013 from $1.6 billion as of December 31, 2012 primarily due to investment returns and contributions from AEP System companies and the participants in excess of benefit payments.  The Postretirement Plans paid $140 million in benefits to plan participants during 2013.  See Note 7 for complete details by Registrant Subsidiary.

Nature of Estimates Required

The Registrant Subsidiaries participate in AEP sponsored pension and other retirement and postretirement benefit plans in various forms covering all employees who meet eligibility requirements.  These benefits are accounted for under “Compensation” and “Plan Accounting” accounting guidance.  The measurement of pension and postretirement benefit obligations, costs and liabilities is dependent on a variety of assumptions.

Assumptions and Approach Used

The critical assumptions used in developing the required estimates include the following key factors:

·  
Discount rate
·  
Compensation increase rate
·  
Cash balance crediting rate
·  
Health care cost trend rate
·  
Expected return on plan assets

Other assumptions, such as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience.

Effect if Different Assumptions Used

The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, longer or shorter life spans of participants or higher or lower lump sum versus annuity payout elections by plan participants.  These differences may result in a significant impact to the amount of pension and postretirement benefit expense recorded.  If a 50 basis point change were to occur for the following assumptions, the approximate effect on the financial statements would be as follows:

APCo
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
+0.5%
 
-0.5%
 
+0.5%
 
-0.5%
 
 
(in thousands)
Effect on December 31, 2013 Benefit Obligations
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
$
 (32,426)
 
$
 35,496 
 
$
 (13,669)
 
$
 14,960 
Compensation Increase Rate
 
 
 1,100 
 
 
 (1,004)
 
 
NA 
 
 
NA 
Cash Balance Crediting Rate
 
 
 4,663 
 
 
 (3,961)
 
 
NA 
 
 
NA 
Health Care Cost Trend Rate
 
 
NA 
 
 
NA 
 
 
 6,063 
 
 
 (6,225)
 
 
 
 
 
 
 
 
 
 
 
 
 
Effect on 2013 Periodic Cost
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
 
 (1,651)
 
 
 1,773 
 
 
 (825)
 
 
 908 
Compensation Increase Rate
 
 
 532 
 
 
 (489)
 
 
NA 
 
 
NA 
Cash Balance Crediting Rate
 
 
 1,562 
 
 
 (1,464)
 
 
NA 
 
 
NA 
Health Care Cost Trend Rate
 
 
NA 
 
 
NA 
 
 
 1,032 
 
 
 (1,070)
Expected Return on Plan Assets
 
 
 (2,974)
 
 
 2,974 
 
 
 (1,301)
 
 
 1,301 
 
 
 
 
 
 
 
 
 
 
 
 
 


 
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I&M
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
+0.5%
 
-0.5%
 
+0.5%
 
-0.5%
 
 
(in thousands)
Effect on December 31, 2013 Benefit Obligations
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
$
 (29,714)
 
$
 32,660 
 
$
 (7,866)
 
$
 8,594 
Compensation Increase Rate
 
 
 1,596 
 
 
 (1,466)
 
 
NA 
 
 
NA 
Cash Balance Crediting Rate
 
 
 5,527 
 
 
 (4,857)
 
 
NA 
 
 
NA 
Health Care Cost Trend Rate
 
 
NA 
 
 
NA 
 
 
 1,899 
 
 
 (2,469)
 
 
 
 
 
 
 
 
 
 
 
 
 
Effect on 2013 Periodic Cost
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
 
 (1,431)
 
 
 1,536 
 
 
 (355)
 
 
 381 
Compensation Increase Rate
 
 
 461 
 
 
 (424)
 
 
NA 
 
 
NA 
Cash Balance Crediting Rate
 
 
 1,353 
 
 
 (1,268)
 
 
NA 
 
 
NA 
Health Care Cost Trend Rate
 
 
NA 
 
 
NA 
 
 
 284 
 
 
 (368)
Expected Return on Plan Assets
 
 
 (2,576)
 
 
 2,576 
 
 
 (933)
 
 
 933 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPCo
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
+0.5%
 
-0.5%
 
+0.5%
 
-0.5%
 
 
(in thousands)
Effect on December 31, 2013 Benefit Obligations
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
$
 (24,436)
 
$
 26,709 
 
$
 (7,928)
 
$
 8,637 
Compensation Increase Rate
 
 
 1,145 
 
 
 (1,055)
 
 
NA 
 
 
NA 
Cash Balance Crediting Rate
 
 
 3,436 
 
 
 (3,055)
 
 
NA 
 
 
NA 
Health Care Cost Trend Rate
 
 
NA 
 
 
NA 
 
 
 2,456 
 
 
 (2,992)
 
 
 
 
 
 
 
 
 
 
 
 
 
Effect on 2013 Periodic Cost
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
 
 (1,304)
 
 
 1,400 
 
 
 (369)
 
 
 396 
Compensation Increase Rate
 
 
 420 
 
 
 (386)
 
 
NA 
 
 
NA 
Cash Balance Crediting Rate
 
 
 1,234 
 
 
 (1,156)
 
 
NA 
 
 
NA 
Health Care Cost Trend Rate
 
 
NA 
 
 
NA 
 
 
 295 
 
 
 (383)
Expected Return on Plan Assets
 
 
 (2,349)
 
 
 2,349 
 
 
 (970)
 
 
 970 
 
 
 
 
 
 
 
 
 
 
 
 
 
PSO
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
+0.5%
 
-0.5%
 
+0.5%
 
-0.5%
 
 
(in thousands)
Effect on December 31, 2013 Benefit Obligations
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
$
 (11,137)
 
$
 12,101 
 
$
 (3,694)
 
$
 4,035 
Compensation Increase Rate
 
 
 975 
 
 
 (921)
 
 
NA 
 
 
NA 
Cash Balance Crediting Rate
 
 
 3,515 
 
 
 (3,349)
 
 
NA 
 
 
NA 
Health Care Cost Trend Rate
 
 
NA 
 
 
NA 
 
 
 918 
 
 
 (1,171)
 
 
 
 
 
 
 
 
 
 
 
 
 
Effect on 2013 Periodic Cost
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
 
 (647)
 
 
 695 
 
 
 (166)
 
 
 178 
Compensation Increase Rate
 
 
 210 
 
 
 (192)
 
 
NA 
 
 
NA 
Cash Balance Crediting Rate
 
 
 612 
 
 
 (573)
 
 
NA 
 
 
NA 
Health Care Cost Trend Rate
 
 
NA 
 
 
NA 
 
 
 133 
 
 
 (172)
Expected Return on Plan Assets
 
 
 (1,163)
 
 
 1,163 
 
 
 (437)
 
 
 437 
 
 
 
 
 
 
 
 
 
 
 
 
 


 
392

 



SWEPCo
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
+0.5%
 
-0.5%
 
+0.5%
 
-0.5%
 
 
(in thousands)
Effect on December 31, 2013 Benefit Obligations
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
$
 (11,676)
 
$
 12,694 
 
$
 (4,212)
 
$
 4,607 
Compensation Increase Rate
 
 
 1,159 
 
 
 (1,091)
 
 
NA 
 
 
NA 
Cash Balance Crediting Rate
 
 
 4,368 
 
 
 (4,159)
 
 
NA 
 
 
NA 
Health Care Cost Trend Rate
 
 
NA 
 
 
NA 
 
 
 820 
 
 
 (1,119)
 
 
 
 
 
 
 
 
 
 
 
 
 
Effect on 2013 Periodic Cost
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
 
 (672)
 
 
 721 
 
 
 (184)
 
 
 198 
Compensation Increase Rate
 
 
 217 
 
 
 (199)
 
 
NA 
 
 
NA 
Cash Balance Crediting Rate
 
 
 636 
 
 
 (595)
 
 
NA 
 
 
NA 
Health Care Cost Trend Rate
 
 
NA 
 
 
NA 
 
 
 147 
 
 
 (191)
Expected Return on Plan Assets
 
 
 (1,209)
 
 
 1,209 
 
 
 (485)
 
 
 485 
 
NA   Not applicable.

ACCOUNTING PRONOUNCEMENTS

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, management cannot determine the impact on the reporting of the Registrant Subsidiaries’ operations and financial position that may result from any such future changes.  The FASB is currently working on several projects including revenue recognition, financial instruments, leases, insurance, hedge accounting and consolidation policy.  The ultimate pronouncements resulting from these and future projects could have an impact on future net income and financial position.


 
393

 


Exhibit 21
Subsidiaries of
American Electric Power Company, Inc.
As of December 31, 2013
Each company shown indented is a subsidiary of the company immediately above which is not indented to the same degree. Subsidiaries not indented are directly owned by American Electric Power Company, Inc.
 
 
Name of Company
 
Location of
Incorporation
American Electric Power Service Corporation
 
New York
AEP Energy Supply LLC
 
Delaware
AEP C&I Company, LLC
 
Delaware
AEP Energy Partners, Inc.
 
Delaware
AEP Generation Resources Inc.
 
Delaware
AEP Generating Company
 
Ohio
AEP Transmission Holding Company, LLC
 
Delaware
AEP Utilities, Inc.
 
Delaware
AEP Texas Central Company
 
Texas
AEP Texas Central Transition Funding LLC
 
Delaware
AEP Texas Central Transition Funding II LLC
 
Delaware
AEP Texas Central Transition Funding III LLC
 
Delaware
AEP Texas North Company
 
Texas
AEP Texas North Generation Company LLC
 
Delaware
Appalachian Power Company
 
Virginia
Appalachian Consumer Rate Relief Funding LLC
 
Delaware
Indiana Michigan Power Company
 
Indiana
Kentucky Power Company
 
Kentucky
Kingsport Power Company
 
Virginia
Ohio Power Company
 
Ohio
Ohio Phase-In-Recovery Funding LLC
 
Delaware
Ohio Valley Electric Corporation
 
Ohio
Indiana-Kentucky Electric Corporation
 
Indiana
Public Service Company of Oklahoma
 
Oklahoma
Southwestern Electric Power Company
 
Delaware
Wheeling Power Company
 
West Virginia

Exhibit 23
 
 
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
We consent to the incorporation by reference in Registration Statements No. 333-128273, 333-66048, 333-62278 and 333-178044 on Form S-8 and Registration Statements No. 333-178046 and 333-178522 on Form S-3 of our reports dated February 25, 2014 relating to the consolidated financial statements and financial statement schedules of American Electric Power Company, Inc. and subsidiary companies, and the effectiveness of American Electric Power Company, Inc. and subsidiary companies’ internal control over financial reporting, appearing in or incorporated by reference in the Annual Report on Form 10-K of American Electric Power Company, Inc. for the year ended December 31, 2013.
 
 
/s/  Deloitte & Touche LLP
 
 
Columbus, Ohio
February 25, 2014
Exhibit 23
 
 
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
We consent to the incorporation by reference in Registration Statement No. 333-182336 on Form S-3 of our reports dated February 25, 2014 relating to the financial statements and financial statement schedule of Appalachian Power Company and subsidiaries appearing in or incorporated by reference in the Annual Report on Form 10-K of Appalachian Power Company for the year ended December 31, 2013 .
 
 
/s/  Deloitte & Touche LLP
 
 
Columbus, Ohio
February 25, 2014
Exhibit 23
 
 
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
We consent to the incorporation by reference in Registration Statement No. 333-185087 on Form S-3 of our reports dated February 25, 2014 relating to the financial statements and financial statement schedule of Indiana Michigan Power Company and subsidiaries appearing in or incorporated by reference in the Annual Report on Form 10-K of Indiana Michigan Power Company for the year ended December 31, 2013.
 
 
/s/  Deloitte & Touche LLP
 
 
Columbus, Ohio
February 25, 2014
Exhibit 24

POWER OF ATTORNEY
 
AMERICAN ELECTRIC POWER COMPANY, INC.
Annual Report on Form 10-K for the Fiscal Year Ended
December 31, 2013


The undersigned directors of AMERICAN ELECTRIC POWER COMPANY, INC., a New York corporation (the "Company"), do hereby constitute and appoint NICHOLAS K. AKINS, JULIA A. SLOAT and BRIAN X. TIERNEY, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form 10-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 2013, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF the undersigned have hereunto set their hands this 24 th day of February, 2014.


/s/ Nicholas K. Akins
/s/ Richard C. Notebaert
Nicholas K. Akins
Richard C. Notebaert
   
/s/ David J. Anderson
/s/ Lionel L. Nowell, III
David J. Anderson
Lionel L. Nowell, III
   
/s/ J. Barnie Beasley, Jr.
/s/ Stephen S. Rasmussen
J. Barnie Beasley, Jr.
Stephen S. Rasmussen
   
/s/ Ralph D. Crosby, Jr.
/s/ Oliver G. Richard, III
Ralph D. Crosby, Jr.
Oliver G. Richard, III
   
/s/ Linda A. Goodspeed
/s/ Richard L. Sandor
Linda A. Goodspeed
Richard L. Sandor
   
/s/ Thomas E. Hoaglin
/s/ Sara Martinez Tucker
Thomas E. Hoaglin
Sara Martinez Tucker
   
/s/ Sandra Beach Lin
/s/ John F. Turner
Sandra Beach Lin
John F. Turner
   
/s/ Michael G. Morris
 
Michael G. Morris
 
   
Exhibit 24
 
POWER OF ATTORNEY
Annual Report on Form 10-K for the Fiscal Year Ended
December 31, 2013

The undersigned directors of the following companies (each respectively the "Company")
 
Company
State of Incorporation
Appalachian Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company
Virginia
Ohio
Oklahoma
Delaware

do hereby constitute and appoint NICHOLAS K. AKINS, JULIA A. SLOAT and BRIAN X. TIERNEY, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form 10-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 2013, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF the undersigned have hereunto set their hands this 24th day of February, 2014.


/s/ Nicholas K. Akins
/s/ Mark C. McCullough
Nicholas K. Akins
Mark C. McCullough
   
/s/ Lisa M. Barton
/s/ Robert P. Powers
Lisa M. Barton
Robert P. Powers
   
/s/ David M. Feinberg
/s/ Brian X. Tierney
David M. Feinberg
Brian X. Tierney
   
/s/ Lana L. Hillebrand
/s/ Dennis E. Welch
Lana L. Hillebrand
Dennis E. Welch
   
   
Exhibit 24
 
POWER OF ATTORNEY

INDIANA MICHIGAN POWER COMPANY
Annual Report on Form 10-K for the Fiscal Year Ended
December 31, 2013


The undersigned directors of INDIANA MICHIGAN POWER COMPANY, an Indiana corporation (the "Company"), do hereby constitute and appoint NICHOLAS K. AKINS, JULIA A. SLOAT and BRIAN X. TIERNEY, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form 10-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 2013, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF the undersigned have hereunto set their hands this 24th day of  February, 2014.


/s/s Nicholas K. Akins
/s/ Marc E. Lewis
Nicholas K. Akins
Marc E. Lewis
   
/s/ Lisa M. Barton
/s/ Mark C. McCullough
Lisa M. Barton
Mark C. McCullough
   
/s/ Sarah L. Bodner
/s/ Robert P. Powers
Sarah L. Bodner
Robert P. Powers
   
/s/ Paul Chodak, III
/s/ Carla E. Simpson
Paul Chodak, III
Carla E. Simpson
   
/s/ Thomas A. Kratt
/s/ Brian X. Tierney
Thomas A. Kratt
Brian X. Tierney
   
   
   
   
   
   
   
   
Exhibit 24
 
POWER OF ATTORNEY
Annual Report on Form 10-K for the Fiscal Year Ended
December 31, 2013

The undersigned directors of the following companies (each respectively the "Company")
 
Company
State of Incorporation
Appalachian Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company
Virginia
Ohio
Oklahoma
Delaware

do hereby constitute and appoint NICHOLAS K. AKINS, JULIA A. SLOAT and BRIAN X. TIERNEY, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form 10-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 2013, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF the undersigned have hereunto set their hands this 24th day of February, 2014.


/s/ Nicholas K. Akins
/s/ Mark C. McCullough
Nicholas K. Akins
Mark C. McCullough
   
/s/ Lisa M. Barton
/s/ Robert P. Powers
Lisa M. Barton
Robert P. Powers
   
/s/ David M. Feinberg
/s/ Brian X. Tierney
David M. Feinberg
Brian X. Tierney
   
/s/ Lana L. Hillebrand
/s/ Dennis E. Welch
Lana L. Hillebrand
Dennis E. Welch
   
   
Exhibit 24
 
POWER OF ATTORNEY
Annual Report on Form 10-K for the Fiscal Year Ended
December 31, 2013

The undersigned directors of the following companies (each respectively the "Company")
 
Company
State of Incorporation
Appalachian Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company
Virginia
Ohio
Oklahoma
Delaware

do hereby constitute and appoint NICHOLAS K. AKINS, JULIA A. SLOAT and BRIAN X. TIERNEY, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form 10-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 2013, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF the undersigned have hereunto set their hands this 24th day of February, 2014.


/s/ Nicholas K. Akins
/s/ Mark C. McCullough
Nicholas K. Akins
Mark C. McCullough
   
/s/ Lisa M. Barton
/s/ Robert P. Powers
Lisa M. Barton
Robert P. Powers
   
/s/ David M. Feinberg
/s/ Brian X. Tierney
David M. Feinberg
Brian X. Tierney
   
/s/ Lana L. Hillebrand
/s/ Dennis E. Welch
Lana L. Hillebrand
Dennis E. Welch
   
   
Exhibit 24
 
POWER OF ATTORNEY
Annual Report on Form 10-K for the Fiscal Year Ended
December 31, 2013

The undersigned directors of the following companies (each respectively the "Company")
 
Company
State of Incorporation
Appalachian Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company
Virginia
Ohio
Oklahoma
Delaware

do hereby constitute and appoint NICHOLAS K. AKINS, JULIA A. SLOAT and BRIAN X. TIERNEY, and each of them, their attorneys-in-fact and agents, to execute for them, and in their names, and in any and all of their capacities, the Annual Report of the Company on Form 10-K, pursuant to Section 13 of the Securities Exchange Act of 1934, for the fiscal year ended December 31, 2013, and any and all amendments thereto, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform every act and thing required or necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.

IN WITNESS WHEREOF the undersigned have hereunto set their hands this 24th day of February, 2014.


/s/ Nicholas K. Akins
/s/ Mark C. McCullough
Nicholas K. Akins
Mark C. McCullough
   
/s/ Lisa M. Barton
/s/ Robert P. Powers
Lisa M. Barton
Robert P. Powers
   
/s/ David M. Feinberg
/s/ Brian X. Tierney
David M. Feinberg
Brian X. Tierney
   
/s/ Lana L. Hillebrand
/s/ Dennis E. Welch
Lana L. Hillebrand
Dennis E. Welch
   
   
EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1.  
I have reviewed this report on Form 10-K of American Electric Power Company, Inc.;

2.  
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.  
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.  
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a.  
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.  
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.  
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.  
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.  
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.  
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.  
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:   February 25, 2014
By:           
 
/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer
EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1.   I have reviewed this report on Form 10-K of Appalachian Power Company;

 
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

 
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

                  a.  
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

                  b.  
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 
c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 
d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:   February 25, 2014
By:           
 
/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer
EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1.   I have reviewed this report on Form 10-K of Indiana Michigan Power Company;

 
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

 
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

                  a.  
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

                  b.  
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 
c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 
d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:   February 25, 2014
By:           
 
/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer
EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1.   I have reviewed this report on Form 10-K of Ohio Power Company;

 
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

 
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

                  a.  
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

                  b.  
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 
c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 
d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:   February 25, 2014
By:           
 
/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer
EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1.   I have reviewed this report on Form 10-K of Public Service Company of Oklahoma;

 
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

 
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

                  a.  
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

                  b.  
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 
c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 
d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:   February 25, 2014
By:           
 
/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer
EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1.   I have reviewed this report on Form 10-K of Southwestern Electric Power Company;

 
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

 
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

                  a.  
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

                  b.  
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 
c.
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 
d.
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 

Date:   February 25, 2014
By:           
 
/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer
EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1.  
I have reviewed this report on Form 10-K of American Electric Power Company, Inc.;

2.  
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.  
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.  
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

a.  
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.  
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.  
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.  
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.  
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.  
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.  
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:   February 25, 2014
By:           
 
/s/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer
EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1.   I have reviewed this report on Form 10-K of Appalachian Power Company;

 
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

 
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

                  a.  
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

                  b.  
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

                  c.  
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

                  d.  
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:   February 25, 2014
By:           
 
/s/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer
 EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1.   I have reviewed this report on Form 10-K of Indiana Michigan Power Company;

 
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

 
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

                  a.  
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

                  b.  
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

                  c.  
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

                  d.  
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:   February 25, 2014
By:           
 
/s/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer
EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1.   I have reviewed this report on Form 10-K of Ohio Power Company;

 
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

 
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

                  a.  
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

                  b.  
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

                  c.  
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

                  d.  
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:   February 25, 2014
By:           
 
/s/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer
EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1.   I have reviewed this report on Form 10-K of Public Service Company of Oklahoma;

 
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

 
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

                  a.  
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

                  b.  
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

                  c.  
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

                  d.  
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
 
 

 
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:   February 25, 2014
By:           
 
/s/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer
EXHIBIT 31(b)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1.   I have reviewed this report on Form 10-K of Southwestern Electric Power Company;

 
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

 
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

                  a.  
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

                  b.  
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

                  c.  
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

                  d.  
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
 
 

 
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 
a.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting that are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 
b.
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:   February 25, 2014
By:           
 
/s/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer
Exhibit 32(a)


This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Annual Report of American Electric Power Company, Inc. (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


February 25, 2014

 
A signed original of this written statement required by Section 906 has been provided to American Electric Power Company, Inc. and will be retained by American Electric Power Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.
Exhibit 32(a)


This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Annual Report of Appalachian Power Company (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


February 25, 2014


A signed original of this written statement required by Section 906 has been provided to Appalachian Power Company   and will be retained by Appalachian Power Company   and furnished to the Securities and Exchange Commission or its staff upon request.
Exhibit 32(a)


This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Annual Report of Indiana Michigan Power Company (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


February 25, 2014


A signed original of this written statement required by Section 906 has been provided to Indiana Michigan Power Company   and will be retained by Indiana Michigan Power Company   and furnished to the Securities and Exchange Commission or its staff upon request.
Exhibit 32(a)


This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Annual Report of Ohio Power Company (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


February 25, 2014


A signed original of this written statement required by Section 906 has been provided to Ohio Power Company   and will be retained by Ohio Power Company and furnished to the Securities and Exchange Commission or its staff upon request.
Exhibit 32(a)


This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Annual Report of Public Service Company of Oklahoma (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


February 25, 2014


A signed original of this written statement required by Section 906 has been provided to Public Service Company of Oklahoma   and will be retained by Public Service Company of Oklahoma   and furnished to the Securities and Exchange Commission or its staff upon request.
Exhibit 32(a)


This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Annual Report of Southwestern Electric Power Company (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Nicholas K. Akins
Nicholas K. Akins
Chief Executive Officer


February 25, 2014


A signed original of this written statement required by Section 906 has been provided to Southwestern Electric Power Company and will be retained by Southwestern Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.
Exhibit 32(b)


This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Annual Report of American Electric Power Company, Inc. (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer


February 25, 2014


A signed original of this written statement required by Section 906 has been provided to American Electric Power Company, Inc. and will be retained by American Electric Power Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.
Exhibit 32(b)


This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Annual Report of Appalachian Power Company (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer


February 25, 2014


A signed original of this written statement required by Section 906 has been provided to Appalachian Power Company   and will be retained by Appalachian Power Company   and furnished to the Securities and Exchange Commission or its staff upon request.
Exhibit 32(b)


This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Annual Report of Indiana Michigan Power Company (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer


February 25, 2014


A signed original of this written statement required by Section 906 has been provided to Indiana Michigan Power Company   and will be retained by Indiana Michigan Power Company   and furnished to the Securities and Exchange Commission or its staff upon request.
Exhibit 32(b)


This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Annual Report of Ohio Power Company (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer


February 25, 2014


A signed original of this written statement required by Section 906 has been provided to Ohio Power Company   and will be retained by Ohio Power Company and furnished to the Securities and Exchange Commission or its staff upon request.
Exhibit 32(b)


This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Annual Report of Public Service Company of Oklahoma (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer


February 25, 2014


A signed original of this written statement required by Section 906 has been provided to Public Service Company of Oklahoma   and will be retained by Public Service Company of Oklahoma   and furnished to the Securities and Exchange Commission or its staff upon request.
Exhibit 32(b)


This Certification is being furnished and shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section.  This Certification shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, except as otherwise stated in such filing.


Certification Pursuant to Section 1350 of Chapter 63
of Title 18 of the United States Code


In connection with the Annual Report of Southwestern Electric Power Company (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof, I, Brian X. Tierney, the chief financial officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Brian X. Tierney
Brian X. Tierney
Chief Financial Officer


February 25, 2014


A signed original of this written statement required by Section 906 has been provided to Southwestern Electric Power Company   and will be retained by Southwestern Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.
Exhibit 95
 
MINE SAFETY INFORMATION
 
The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations.  The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters.  SWEPCo, through its ownership of Dolet Hills Lignite Company (DHLC), and OPCo, through its use of the Connor Run fly ash impoundment, are subject to the provisions of the Mine Act.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act.  DHLC and Connor Run received the following notices of violation and proposed assessments under the Mine Act for the quarter ended December 31, 2013:

 
DHLC
Conner Run
Number of Citations for S&S Violations of Mandatory Health or Safety Standards under 104 *
0
0
Number of Orders Issued under 104(b) *
0
0
Number of Citations and Orders for Unwarrantable Failure to  Comply with Mandatory Health or Safety Standards under 104(d) *
0
0
Number of Flagrant Violations under 110(b)(2) *
0
0
Number of Imminent Danger Orders Issued under 107(a)
0
0
Total Dollar Value of Proposed Assessments **
$787
$0
Number of Mining-related Fatalities
0
0

* References to sections under the Mine Act.
** Assessments pertain to citations issued during the third quarter 2013.


DHLC currently has three legal actions pending before the Federal Mine Safety and Health Review Commission, although all but one have been settled and are awaiting approval of the settlement by the Commission.  Two related actions challenged four violations issued by MSHA following an employee fatality in March 2009 (this matter has been resolved, subject to Commission approval); the third legal action is challenging a (d)(1) citation issued in August 2010 related to a dragline boom issue.  A fourth action, involving the challenge of a 104(a) citation issued in July 2010 related to an oil leak on a drive conveyor gear box, was resolved and approved by the Commission in the fourth quarter 2013.