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

x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2010

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
 
1-2680
 
Columbus Southern Power Company (An Ohio Corporation)
 
31-4154203
 
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
   
Columbus Southern Power Company
 
None
   
Indiana Michigan Power Company
 
None
   
Ohio Power Company
 
None
   
Public Service Company of Oklahoma
 
6% Senior Notes, Series B, Due 2032
 
New York Stock Exchange
Southwestern Electric Power Company
 
None
   


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

Registrant
 
Title of each class
American Electric Power Company, Inc.
 
None
Appalachian Power Company
 
4.50% Cumulative Preferred Stock, Voting, no par value
Columbus Southern Power Company
 
None
Indiana Michigan Power Company
 
None
Ohio Power Company
 
4.50% Cumulative Preferred Stock, Voting, $100 par value
Public Service Company of Oklahoma
 
None
Southwestern Electric Power Company
 
4.28% Cumulative Preferred Stock, Voting, $100 par value
   
4.65% Cumulative Preferred Stock, Voting, $100 par value
   
5.00% Cumulative Preferred Stock, Voting, $100 par value

 
 
 
Indicate by check mark if the registrants American Electric Power Company, Inc., and Appalachian Power Company is each a well-known seasoned issuer, as defined in Rule 405 on the Securities Act.
Yes   x
No.   o
     
Indicate by check mark if the registrants Columbus Southern 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.   x
     
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.   x
     
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   x
No.   o
     
Indicate by check mark whether American Electric Power Company, Inc. has 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   x
No.   o
Indicate by check mark whether Appalachian Power Company, Columbus Southern 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 registrants were required to submit and post such files).
 
Yes   o
No.   o
Indicate by check mark if disclosure of delinquent filers with respect to Appalachian Power Company, Ohio Power Company, Public Service Company of Oklahoma or Southwestern Electric Power Company 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 registrant’s knowledge, in definitive proxy or information statements of Appalachian Power Company, Ohio Power Company, Public Service Company of Oklahoma or Southwestern Electric Power Company incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
x
 
     
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                                            x
 
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, Columbus Southern 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                                            x (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.   x


Columbus Southern Power Company and Indiana Michigan 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, 2010, 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, 2010
American Electric Power Company, Inc.
 
$15,530,071,139
 
480,807,156
       
($6.50 par value)
Appalachian Power Company
 
None
 
13,499,500
       
(no par value)
Columbus Southern Power Company
 
None
 
16,410,426
       
(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, Columbus Southern 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, 2010:
Part II
American Electric Power Company, Inc.
 
Appalachian Power Company
 
Columbus Southern 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 2011 Annual Meeting of Shareholders.
Part III
   
Portions of Information Statements of the following companies for 2011 Annual Meeting of Shareholders:
Part III
Appalachian Power Company
 
Ohio Power Company
 
Public Service Company of Oklahoma
 
Southwestern Electric Power Company
 


This combined Form 10-K is separately filed by American Electric Power Company, Inc., Appalachian Power Company, Columbus Southern 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
Number
 
Page
Number
 
Glossary of Terms
i
 
Forward-Looking Information
iv
PART I
1
 
Business
 
   
General
1
   
Utility Operations
11
   
AEP River Operations
23
   
Generation and Marketing
23
1
A
Risk Factors
24
1
B
Unresolved Staff Comments
36
2
 
Properties
36
   
Generation Facilities
36
   
Transmission and Distribution Facilities
38
   
Titles
38
   
System Transmission Lines and Facility Siting
38
   
Construction Program
39
   
Potential Uninsured Losses
39
3
 
Legal Proceedings
40
4
 
(Removed and Reserved)
40
   
Executive Officers of the Registrant
40
PART II
5
 
Market For Registrants’ Common Equity, Related Stockholder Matters And Issuer Purchases Of Equity Securities
42
6
 
Selected Financial Data
42
7
 
Management’s Discussion And Analysis Of Financial Condition And Results Of Operations
42
7
A
Quantitative And Qualitative Disclosures About Market Risk
42
8
 
Financial Statements And Supplementary Data
42
9
 
Changes In And Disagreements With Accountants On Accounting And Financial Disclosure
43
9
A
Controls And Procedures
43
9
B
Other Information
43
PART III
10
 
Directors, Executive Officers and Corporate Governance
44
11
 
Executive Compensation
45
12
 
Security Ownership Of Certain Beneficial Owners and Management And Related Stockholder Matters
45
13
 
Certain Relationships and Related Transactions, And Director Independence
46
14
 
Principal Accounting Fees And Services
46
PART IV
15
 
Exhibits and Financial Statement Schedules
48
   
Financial Statements
48
   
Signatures
49
   
Index to Financial Statement Schedules
S-1
   
Reports of Independent Registered Public Accounting Firm
S-2
   
Exhibit Index
E-1


 
 
 

GLOSSARY OF TERMS

The following abbreviations or acronyms used in this Form 10-K are defined below:
 
Abbreviation or Acronym
 
Definition
AECC
 
Arkansas Electric Cooperative Corporation, an unaffiliated corporation
AEGCo
 
AEP Generating Company, an electric utility subsidiary of AEP
AEP or parent
 
American Electric Power Company, Inc.
AEP East companies
 
APCo, CSPCo, I&M, KPCo and OPCo
AEP Power Pool
 
APCo, CSPCo, I&M, KPCo and OPCo, as parties to the Interconnection Agreement
AEP River Operations
 
AEP’s inland river transportation subsidiary, AEP River Operations LLC (formerly AEP MEMCO LLC), operating primarily on the Ohio, Illinois, and lower Mississippi rivers
AEPSC
 
American Electric Power Service Corporation, a service company subsidiary of AEP
AEP System or the System
 
The American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries
AEP West companies
 
PSO, SWEPCo, TCC and TNC
AEP Utilities
 
AEP Utilities, Inc., a subsidiary of AEP, formerly, Central and South West Corporation
AFUDC
 
Allowance for funds used during construction (the net cost of borrowed funds, and a reasonable rate of return on other funds, used for construction under regulatory accounting)
ALJ
 
Administrative law judge
APCo
 
Appalachian Power Company, a public utility subsidiary of AEP
APSC
 
Arkansas Public Service Commission
Buckeye
 
Buckeye Power, Inc., an unaffiliated corporation
CAA
 
Clean Air Act
CAAA
 
Clean Air Act Amendments of 1990
CCS
 
Carbon capture and storage technology
CERCLA
 
Comprehensive Environmental Response, Compensation and Liability Act of 1980
CO 2
 
Carbon dioxide and other greenhouse gases
Cook Plant
 
The Donald C. Cook Nuclear Plant, owned by I&M, and located near Bridgman, Michigan
CSPCo
 
Columbus Southern Power Company, a public utility subsidiary of AEP
CSW
 
Central and South West Corporation, a public utility holding company that merged with AEP in June 2000.
CSW Operating Agreement
 
Agreement, dated January 1, 1997, as amended, originally by and among PSO, SWEPCo, TCC and TNC, currently by and between PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third party sales.  AEPSC acts as the agent for the parties.
DOE
 
United States Department of Energy
DP&L
 
The Dayton Power and Light Company, an unaffiliated utility company
Duke Ohio
 
Duke Energy Ohio, Inc.
EMF
 
Electric and Magnetic Fields
EPA
 
United States Environmental Protection Agency
EPACT
 
The Energy Policy Act of 2005
ERCOT
 
Electric Reliability Council of Texas
ESP
 
Electric Security Plans, filed with the PUCO, pursuant to the Ohio Amendments
ETEC
 
East Texas Electric Cooperative
FERC
 
Federal Energy Regulatory Commission
FPA
 
Federal Power Act
I&M
 
Indiana Michigan Power Company, a public utility subsidiary of AEP
IGCC
 
Integrated Gasification Combined Cycle
 

 
i
 

Abbreviation or Acronym
 
Definition
Interconnection Agreement
 
Agreement, dated July 6, 1951, as amended, by and among APCo, CSPCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants
IURC
 
Indiana Utility Regulatory Commission
KgPCo
 
Kingsport Power Company, a public utility subsidiary of AEP
KPCo
 
Kentucky Power Company, a public utility subsidiary of AEP
KPSC
 
Kentucky Public Service Commission
Lawrenceburg Plant
 
A 1,146 MW gas-fired unit owned by AEGCo and located near Lawrenceburg, Indiana
LLWPA
 
Low-Level Waste Policy Act of 1980
LPSC
 
Louisiana Public Service Commission
 
   
MISO
 
Midwest Independent Transmission System Operator
Moody’s
 
Moody’s Investors Service, Inc.
MW
 
Megawatt
NO x
 
Nitrogen oxide
NPC
 
National Power Cooperatives, Inc., an unaffiliated corporation
NRC
 
Nuclear Regulatory Commission
NSR Consent Decree
 
The 2007 settlement with the Federal EPA, the United States Department of Justice, certain states and special interest groups that ended the litigation which had alleged that APCo, CSPCo, I&M and OPCo violated the new source review requirements of the CAA.
OASIS
 
Open Access Same-time Information System
OATT
 
Open Access Transmission Tariff, filed with FERC
OCC
 
Corporation Commission of the State of Oklahoma
Ohio Act
 
Ohio electric restructuring legislation
Ohio Amendments
 
Amendments to the Ohio Act adopted in April 2008 which required electric utilities to adjust their rates by filing an ESP with the PUCO
OPCo
 
Ohio Power Company, a public utility subsidiary of AEP
OSS
 
Off-system sales
OVEC
 
Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo together own a 43.47% equity interest
PJM
 
PJM Interconnection, L.L.C., a regional transmission organization
PM
 
Particulate Matter
Power Pool
 
The pooled generation resources of AEP East companies established under the Interconnection Agreement
PSO
 
Public Service Company of Oklahoma, a public utility subsidiary of AEP
PUCO
 
Public Utilities Commission of Ohio
PUCT
 
Public Utility Commission of Texas
RCRA
 
Resource Conservation and Recovery Act of 1976, as amended
REP
 
Texas retail electricity provider
Rockport Plant
 
A generating plant owned and partly leased by AEGCo and I&M (two 1,300 MW, coal-fired) located near Rockport, Indiana
ROE
 
Return on Equity
RTO
 
Regional Transmission Organization
SEC
 
Securities and Exchange Commission
S&P
 
Standard & Poor’s Ratings Service
SO 2
 
Sulfur dioxide
SPP
 
Southwest Power Pool
SWEPCo
 
Southwestern Electric Power Company, a public utility subsidiary of AEP
TA
 
Transmission Agreement dated April 1, 1984 by and among APCo, CSPCo, I&M, KPCo, KgPCo, OPCo and WPCo, which allocates costs and benefits in connection with the operation of transmission assets

 
ii
 

Abbreviation or Acronym
 
Definition
TCA
 
Transmission Coordination Agreement dated January 1, 1997, restated and amended, as approved by FERC in 2002, by and among, PSO, SWEPCo, TNC and AEPSC, in connection with the operation of the transmission assets of the three public utility subsidiaries
TCC
 
AEP Texas Central Company, formerly Central Power and Light Company, a public utility subsidiary of AEP
Texas Act
 
Texas electric restructuring legislation
TNC
 
AEP Texas North Company, formerly West Texas Utilities Company, a public utility subsidiary of AEP
TVA
 
Tennessee Valley Authority
VSCC
 
Virginia State Corporation Commission
WPCo
 
Wheeling Power Company, a public utility subsidiary of AEP
WVPSC
 
West Virginia Public Service Commission

 
iii
 
FORWARD-LOOKING INFORMATION
 
This report made by the registrants 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 Financial Discussion and Analysis,” 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 such as those below and as further described in our Risk Factors that could cause actual results to differ materially from those projected. Forward-looking statements in this document speak only 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 and growth in, or contraction within, our service territory and changes in market demand and demographic patterns.
·
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 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 generating capacity and the performance of our generating plants.
·
Our ability to resolve I&M’s Donald C. Cook Nuclear Plant Unit 1 restoration and outage-related issues through warranty, insurance and the regulatory process.
·
Our ability to recover regulatory assets and stranded costs in connection with deregulation.
·
Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·
Our ability to build or acquire generating capacity, including the Turk Plant, and transmission line 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 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 and cost recovery of our plants.
·
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, natural gas and other energy-related commodities.
·
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 debt.
·
Volatility and changes in markets for electricity, natural gas, coal, nuclear fuel and other energy-related commodities.
·
Changes in utility regulation, including the implementation of ESPs and related regulation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP.
·
Accounting pronouncements periodically issued by accounting standard-setting bodies.
 
 
iv
 
 
·
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.
·
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.
·
Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.
·
Our ability to recover through rates or prices any remaining unrecovered investment in generating units that may be retired before the end of their previously projected useful lives.

 
v
 


 
PART I

ITEM 1.                      BUSINESS

GENERAL

OVERVIEW AND DESCRIPTION OF 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 generating and 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 legislation in Michigan, Ohio, and the ERCOT area of Texas has caused AEP public utility subsidiaries in those states to unbundle previously integrated regulated rates for their retail customers.

The AEP System is an integrated electric utility system. As a result, 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.

At December 31, 2010, the subsidiaries of AEP had a total of 18,712 employees. Because it is a holding company rather than an operating company, AEP has no employees. The public utility subsidiaries of AEP are:

APCo   (organized in Virginia in 1926) is engaged in the generation, transmission and distribution of electric power to approximately 957,000 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. At December 31, 2010, APCo and its wholly owned subsidiaries had 2,186 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 unaffiliated utility companies: Carolina Power & Light Company, Duke Carolina and Virginia Electric and Power Company. APCo has several points of interconnection with 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.

CSPCo   (organized in Ohio in 1937, the earliest direct predecessor company having been organized in 1883) is engaged in the generation, transmission and distribution of electric power to approximately 749,000 retail customers in Ohio, and in supplying and marketing electric power at wholesale to other electric utilities, municipalities and other market participants. At December 31, 2010, CSPCo had 1,082 employees. CSPCo’s service area is comprised of two areas in Ohio, which include portions of twenty-five counties. One area includes the City of Columbus and the other is a predominantly rural area in south central Ohio. Among the principal industries served are primary metals, chemicals and allied products, health services and electronic machinery. In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for CSPCo to merge into OPCo, effective in October 2011.  Decisions are pending from the PUCO and the FERC.  In addition to its AEP System interconnections, CSPCo is interconnected with the following unaffiliated utility companies: Duke Ohio, DP&L and Ohio Edison Company.  CSPCo is a member of PJM.
 
 
1
 
I&M   (organized in Indiana in 1925) is engaged in the generation, transmission and distribution of electric power to approximately 582,000 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.  At December 31, 2010, I&M had 2,705 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. Since 1975, I&M has leased and operated the assets of the municipal system of the City of Fort Wayne, Indiana.  Subject to regulatory approval, I&M has agreed to purchase these assets.  In addition to its AEP System interconnections, I&M is interconnected with the following unaffiliated utility companies: Central Illinois Public Service Company, Duke Ohio, Commonwealth Edison Company, Consumers Energy 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.

KPCo   (organized in Kentucky in 1919) is engaged in the generation, transmission and distribution of electric power to approximately 174,000 retail customers in an area in eastern Kentucky, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants.  At December 31, 2010, KPCo had 417 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 unaffiliated utility companies: Kentucky Utilities Company and East Kentucky Power Cooperative Inc. KPCo is also interconnected with TVA.  KPCo is a member of PJM.

KgPCo (organized in Virginia in 1917) provides electric service to approximately 47,000 retail customers in Kingsport and eight neighboring communities in northeastern Tennessee. Kingsport Power Company does not own any generating facilities and is a member of PJM. It purchases electric power from APCo for distribution to its customers. At December 31, 2010, Kingsport Power Company had 52 employees.

OPCo   (organized in Ohio in 1907 and re-incorporated in 1924) is engaged in the generation, transmission and distribution of electric power to approximately 706,000 retail customers in the northwestern, east central, eastern and southern sections of Ohio, and in supplying and marketing electric power at wholesale to other electric utility companies, municipalities and other market participants. At December 31, 2010, OPCo had 2,100 employees. Among the principal industries served by OPCo are primary metals, chemical manufacturing, petroleum refining, and rubber and plastic products. In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for CSPCo to merge into OPCo, effective in October 2011.  Decisions are pending from the PUCO and the FERC.  In addition to its AEP System interconnections, OPCo is interconnected with the following unaffiliated utility companies: Duke Ohio, The Cleveland Electric Illuminating Company, DP&L, 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.

PSO   (organized in Oklahoma in 1913) is engaged in the generation, transmission and distribution of electric power to approximately 532,000 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. At December 31, 2010, PSO had 1,150 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.

SWEPCo   (organized in Delaware in 1912) is engaged in the generation, transmission and distribution of electric power to approximately 520,000 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. At December 31, 2010, SWEPCo had 1,382 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.
 
 
2
 
SWEPCO also owns and operates a lignite coal mining operation.  In addition to its AEP System interconnections, SWEPCo is interconnected with Cleco Corp., Empire District Electric Co., Entergy Corp. and Oklahoma Gas & Electric Co.  SWEPCo is a member of SPP.
 
TCC (organized in Texas in 1945) is engaged in the transmission and distribution of electric power to approximately 775,000 retail customers through REPs in southern Texas. TCC has sold all of its generation assets.  At December 31, 2010, TCC had 1,006 employees. Among the principal industries served by TCC are chemical and petroleum refining, chemicals and allied products, oil and gas extraction, food processing, metal refining, plastics, and machinery equipment. In addition to its AEP System interconnections, TCC is a member of ERCOT.

TNC   (organized in Texas in 1927) is engaged in the transmission and distribution of electric power to approximately 186,000 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.  At December 31, 2010, TNC had 319 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.

WPCo (organized in West Virginia in 1883 and reincorporated in 1911) 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 OPCo for distribution to its customers. At December 31, 2010, WPCo had 52 employees.

AEGCo   (organized in Ohio in 1982) is an electric generating company. AEGCo sells power at wholesale to I&M, CSPCo and KPCo. AEGCo has no employees.

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.  At December 31, 2010, AEPSC had 5,132 employees.
 
 
3
 
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 year ended December 31, 2010 are as follows:

Description
 
AEP System (a)
   
APCo
   
CSPCo
   
I&M
 
 
 
(in thousands)
 
UTILITY OPERATIONS:
 
 
   
 
   
 
   
 
 
Retail Sales
 
 
   
 
   
 
   
 
 
Residential Sales
  $ 5,125,000     $ 1,221,563     $ 883,766     $ 496,605  
Commercial Sales
    3,406,000       559,718       751,724       364,908  
Industrial Sales
    2,840,000       653,762       254,342       400,140  
PJM Net Charges
    (42,000 )     (14,008 )     (7,852 )     (7,998 )
Provision for Rate Refund
    (52,000 )     4,147       (50,000 )     -  
Other Retail Sales
    207,000       74,331       7,053       6,610  
Total Retail
    11,484,000       2,499,513       1,839,033       1,260,265  
Wholesale
                               
Off-System Sales
    1,812,000       439,689       223,799       474,472  
Transmission
    181,000       (20,518 )     (14,399 )     (139 )
Total Wholesale
    1,993,000       419,171       209,400       474,333  
Other Electric Revenues
    145,000       31,499       14,822       740  
Other Operating Revenues
    65,000       8,713       2,792       15,368  
Sales to Affiliates
    -       316,207       82,994       445,021  
Total Utility Operating Revenues
    13,687,000       3,275,103       2,149,041       2,195,727  
OTHER
    740,000       -       -       -  
TOTAL REVENUES
  $ 14,427,000     $ 3,275,103     $ 2,149,041     $ 2,195,727  

(a)
Includes revenues of other subsidiaries not shown.  Intercompany transactions have been eliminated for the year ended December 31, 2010.

Description
 
OPCo
   
PSO
   
SWEPCo
 
 
 
(in thousands)
 
UTILITY OPERATIONS:
 
 
   
 
   
 
 
Retail Sales
 
 
   
 
   
 
 
Residential Sales
  $ 735,551     $ 523,997     $ 496,454  
Commercial Sales
    464,770       337,856       392,193  
Industrial Sales
    660,952       222,087       275,229  
PJM Net Charges
    (9,295 )     -       -  
Provision for Rate Refund
    -       (55 )     (6,375 )
Other Retail Sales
    10,957       72,125       7,800  
Total Retail
    1,862,935       1,156,010       1,165,301  
Wholesale
                       
Off-System Sales
    311,246       46,364       240,935  
Transmission
    (16,288 )     30,039       44,336  
Total Wholesale
    294,958       76,403       285,271  
Other Electric Revenues
    1,313       14,503       18,942  
Other Operating Revenues
    17,509       3,218       2,150  
Sales to Affiliates
    1,046,992       23,528       51,870  
Total Utility Operating Revenues
    3,223,707       1,273,662       1,523,534  
OTHER
    -       -       -  
TOTAL REVENUES
  $ 3,223,707     $ 1,273,662     $ 1,523,534  
 
 
4
 
FINANCING

General

Companies within the AEP System generally use short-term debt to finance working capital needs.  Short-term debt is also 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 Financial Discussion and Analysis , included in the 2010 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. At December 31, 2010, 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 Financial Discussion and Analysis , included in the 2010 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 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.  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 Federal EPA have imposed more stringent SO 2 and NOx 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.
 
 
5
 
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.  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 standard is under development.  In 2009 the Obama Administration reconsidered the ozone standard and proposed a more stringent standard, which is expected to be finalized in 2011.  Federal EPA has also adopted a new short-term standard for SO 2, a lower standard for NO 2, , and a lower standard for lead.  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 Financial Discussion and Analysis under the headings entitled Environmental Matters—Clean Air Act Requirements.   In July 2010, the Federal EPA issued a proposed rule to replace CAIR (the Transport Rule) that would impose new and more stringent requirements to control SO 2 and NO x emissions from fossil fuel-fired electric generating units in 31 states and the District of Columbia.  For additional information regarding the Transport Rule, see Management’s Financial Discussion and Analysis under the headings entitled Environmental Matters—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 2005, the Federal EPA issued a Clean Air Mercury Rule (CAMR) setting New Source Performance Standards (NSPS) for mercury emissions from new and modified coal-fired power plants and requiring all states to issue new SIPs including mercury requirements for existing coal-fired power plants.  For additional information regarding CAMR, see Management’s Financial Discussion and Analysis under the headings entitled Environmental Matters—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.  For additional information regarding CAVR, see Management’s Financial Discussion and Analysis under the headings entitled Environmental Matters—Clean Air Act Requirements.

In January 2009, the Federal EPA issued a determination that 37 states (including Indiana, Ohio, Oklahoma, Texas and Virginia) failed to submit SIP’s fulfilling the Regional Haze program requirements by the deadline, and commencing a 2-year period for the development of a Federal Implementation Plan (FIP) in these states.  Oklahoma subsequently submitted a proposed SIP to Federal EPA, but anticipates that Federal EPA will disapprove the plan and propose a FIP in early 2011.  We are unable to predict if or how the remand of CAIR or the development of a FIP to satisfy CAVR in certain states may affect our compliance obligations for the Regional Haze programs.

 
6
 
Greenhouse Gas Emissions :  In the absence of comprehensive climate change legislation, 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 Federal EPA action taken to regulate CO 2 emissions, see Management’s Financial Discussion and Analysis under the headings entitled Environmental Matters—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 generating 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.  To the extent our costs are relatively higher than our competitors’ costs, such as operators of nuclear generation, it could reduce our off-system sales or cause us to lose customers in jurisdictions that permit customers to choose their supplier of generation service.

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.  Certain states, including Ohio, Michigan, Texas and Virginia, passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements.  We are taking steps to comply with these 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 2004, the Federal EPA issued a final rule requiring all large existing power plants with once-through cooling water systems to meet certain standards to reduce mortality of aquatic organisms pinned against the plant’s cooling water intake screen or entrained in the cooling water.  The standards varied based on the water bodies from which the plants draw their cooling water.

In July 2007, the Federal EPA suspended the 2004 rule, except for the requirement that permitting agencies develop best professional judgment (BPJ) controls for existing facility cooling water intake structures that reflect the best technology available for minimizing adverse environmental impact.  The result is that the BPJ control standard for cooling water intake structures in effect prior to the 2004 rule is used as the applicable standard by permitting agencies pending finalization of revised rules by the Federal EPA.

In April 2009, the U.S. Supreme Court issued a decision that allows the Federal EPA the discretion to rely on cost-benefit analysis in setting national performance standards and in providing for cost-benefit variances from those standards as part of the regulations.  We cannot predict if or how the Federal EPA will apply this decision to any revision of the regulations or what effect it may have on similar requirements adopted by the states.  We expect Federal EPA to issue revised rules in 2011.

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 NPDES program.  These standards were last updated over 20 years ago, and EPA has issued two rounds of information collection requests to inform its rulemaking.  In October 2009, Federal EPA issued a final report for the power plant sector and determined that revisions to its existing standards are necessary, but EPA has not yet proposed any specific requirements.  Until new standards are proposed, we cannot predict the outcome or impact of these rules on our operations.
 
 
7
 
Coal Ash Regulation

Our operations produce a number of different coal combustion products, including flyash, bottom ash, gypsum, and other materials.  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 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.  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 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 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 Financial Discussion and Analysis under the headings entitled Environmental Matters—Coal Combustion Residual Rule.

Global Warming

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 U.S. 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 94 million metric tons during the 2003 to 2009 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, 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, supporting incentives to invest in more nuclear generation, carbon capture and storage and other advanced coal technologies, increasing energy efficiency and investing in renewable resources, where there is regulatory support. Meanwhile the U.S. EPA began regulating CO 2 emissions from large stationary sources such as power plants in 2011 by issuing a series of rules under the NSR prevention of significant deterioration and Title V operating permit programs in the states.

For additional information on legislative and regulatory responses to global warming, including limitations on CO 2 emissions, see Management’s Financial Discussion and Analysis under the headings entitled Environmental Matters – Global Warming . Specific steps taken to reduce CO 2 emissions include the following:

Carbon Capture and Storage

The 20 MW CCS Validation Project at the Mountaineer Plant in West Virginia successfully captured over 27,000 metric tons of CO 2 between 2009 and 2010 and stored over 17,000 metric tons underground.  In January 2011, we began preliminary engineering and design work for a second, commercial-scale coal-derived CO 2 capture and storage system at the Mountaineer Plant. We are also updating our estimates for the costs related to the commercial scale project.  We will evaluate the updated estimates before any decision is made to seek the necessary regulatory approvals to build the commercial scale project.  The project will be partially funded through the U.S. Department of Energy’s Clean Coal Power Initiative. AEP was awarded federal grant funding of $334 million, which represents approximately half the expected cost of this project, exclusive of asset retirement obligations.
 
 
8
 
Renewable Sources of Energy

Some of our states have laws or commission orders that establish requirements or goals for renewable and/or alternative energy (Louisiana, Ohio, Arkansas, Michigan, West Virginia, Texas, Virginia and Oklahoma) and we are taking steps to comply with these rules in a timely fashion. A key sustainability commitment we made is to increase renewable power by an additional 2,000 MW from 2007 levels by 2011, subject to regulatory approval. By the end of 2010, AEP secured through power purchase agreements an additional 1,111 MW of renewable power.

End User Energy Efficiency

Energy efficiency is a high priority for AEP because it can be a cost-effective way to reduce energy demand and potentially delay the need for new power plants. We work collaboratively with regulators, technical experts, environmental groups and others to develop and implement efficiency and demand response programs. From 2008 through 2010, we have achieved approximately 321 MW and 1,072,000 MWh of demand and energy reductions, respectively. We have a company 2012 goal to reduce 1,000 MW of demand and 2,250,000 MWh of energy consumption. We expect to surpass our energy reduction target subject to regulatory approvals, appropriate cost recovery, and continued customer demand for programs. In 2010, we invested over $70 million throughout most of our service territory in energy efficiency initiatives.

gridSMART   ®

AEP’s gridSMART ® initiative is designed to demonstrate the potential benefits of the smart grid by integrating advanced grid technologies into existing electric networks.  AEP is deploying smart grid technologies in several jurisdictions with regulatory support.

·  
AEP Ohio is deploying a comprehensive suite of smart grid technologies in an innovative demonstration project with 110,000 customers.  The $150 million project is being funded through a $75 million federal grant, PUCO cost recovery support, and vendor in-kind contributions.

·  
AEP Texas is deploying a 970,000 meter smart grid network, along with $1 million in energy use display devices for low income customers.  The $308 million project is targeted for completion by the end of 2013.  We are recovering the costs through an 11-year surcharge.

·  
I&M has deployed a smart grid network to 10,000 customers.  The $7 million project is initially being funded pursuant to a settlement agreement approved by the IURC.  Ongoing expenses will be considered in future rate cases.

·  
With partial cost recovery support from the OCC, PSO is deploying a 15,000 smart meter network.

Current and Projected CO 2 Emissions:   Our total CO 2 emissions in 2009 (including our ownership in the Kyger Creek and Clifty Creek plants) were approximately 136 million metric tons.  We estimate that our 2010 emissions were approximately 140 million metric tons .  Emissions in 2011 and beyond will be affected by continued changes in our generation portfolio, market prices, the pace and scale of the economic recovery in our jurisdictions, available capital, weather, and other factors.  We expect overall increases in CO 2 emissions during the next few years to be small, if at all realized, 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 a shareholder proposal several years ago, our Board of Directors created an ad hoc committee to evaluate our actions to mitigate the economic impact from future policies to reduce CO 2 and other emissions. Our Board of Directors continually reviews the risks posed by and our actions in response to environmental issues and in connection with its assessment of our strategic plan. The Board of Directors is frequently informed of any new material environmental issues, including changes to regulations and proposed legislation. The Board’s Committee on Directors and Corporate Governance oversees the company’s annual Corporate Accountability Report, which includes information on environmental issues. Environmental planning and policy leadership are criteria incorporated into our executive compensation plan.
 
 
9
 
Other environmental issues and matters

·  
Litigation with the federal and/or certain state governments and certain special interest groups regarding regulated air emissions and/or whether emissions from coal-fired generating plants cause or contribute to global warming. See Management’s Financial Discussion and Analysis under the heading entitled Litigation - Environmental Litigation and Note 6 to the consolidated financial statements entitled Commitments, Guarantees and Contingencies , included in the 2010 Annual Reports, for further information.

·  
CERCLA, which 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 2010 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 2008, 2009 and 2010 and the current estimates for 2011, 2012 and 2013 are shown below, in each case excluding AFUDC or capitalized interest. 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 generating 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 2011 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. While we expect to recover our expenditures for pollution control technologies, replacement generation and associated operating costs from customers through regulated rates (in regulated jurisdictions) or market prices, without such recovery those costs could adversely affect future results of operations and cash flows, and possibly financial condition.  The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the AEP System.  See Management’s Financial Discussion and Analysis under the heading entitled Environmental Matters and   Note 6 to the consolidated financial statements, entitled Commitments, Guarantees and Contingencies, included in the 2010 Annual Reports, for more information regarding environmental expenditures in general.
 
Historical and Projected Environmental Investments
             
 
2008
2009
2010
2011
2012
2013
 
Actual
Actual
Actual
Estimate
Estimate
Estimate
(in thousands)
Total AEP System*
$886,800
$457,200
$303,800
$223,100
$340,300
$678,500
APCo
361,200
191,900
202,700
112,100
125,700
182,500
CSPCo
162,800
73,800
52,100
20,700
18,800
28,000
I&M
22,400
19,600
8,100
1,500
700
4,400
OPCo
311,800
151,000
45,300
50,300
69,000
193,700
PSO
5,000
1,000
1,200
7,400
6,100
5,100
SWEPCo**
12,000
10,700
(10,500)
10,300
28,000
89,200

*  Includes expenditures of the subsidiaries shown and other subsidiaries not shown. The figures reflect construction expenditures, not investments in subsidiary companies.  Excludes discontinued operations.

**  SWEPCo 2010 actual environmental cost includes reclassifications of project costs for suspended capital projects.
 
 
10
 
Electric and Magnetic Fields

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 adversely affected unless these costs can be recovered from customers.

UTILITY OPERATIONS

GENERAL

Utility operations constitute most of AEP’s business operations.  Utility operations include (i) the generation, transmission and distribution of electric power to retail customers and (ii) the supplying and marketing of electric power at wholesale (through the electric generation function) to other electric utility companies, municipalities and other market participants.  AEPSC, as agent for AEP’s public utility subsidiaries, performs marketing, generation dispatch, fuel procurement and power-related risk management and trading activities.

ELECTRIC GENERATION

Facilities

AEP’s public utility subsidiaries own or lease approximately 37,000 MW of domestic generation. See Item 2 — Properties for more information regarding AEP’s generation capacity.

AEP Power Pool

APCo, CSPCo, I&M, KPCo, OPCo, and AEPSC are parties to the Interconnection Agreement, which was originally approved by the FERC in 1951 and subsequently amended in 1951, 1962, 1975, 1979 (twice) and 1980.  This agreement defines how the member companies share the costs and benefits associated with their generating plants. This sharing is based upon each company’s “member load ratio.” The member load ratio is calculated monthly by dividing each company’s highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all member companies. The member load ratio multiplied by the aggregate generation capacity of all the member companies determines each member company's capacity obligation.  The difference between each member company's obligation and its own generation capacity determines the capacity surplus or deficit of each member company.  The agreement requires the deficit companies to make monthly capacity equalization payments to the surplus companies based on the surplus companies' average fixed cost of generation.  Member companies that deliver energy to other member companies to meet their internal load requirements are reimbursed at average variable costs.  In addition, all member companies share off-system sales margins based upon each member company's member load ratio.  Consequently, the agreement provides a strong risk sharing and mitigation arrangement among the member companies.  As of December 31, 2010, the member-load-ratios were as follows:

 
Peak
Demand
(MW)
Member-Load
Ratio
(%)
APCo
7,623
32.8
CSPCo
4,289
18.5
I&M
4,474
19.3
KPCo
1,596
  6.9
OPCo
5,235
22.5
 
 
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APCo, CSPCo, I&M, KPCo and OPCo are parties to the AEP System Interim Allowance Agreement (Allowance Agreement), which has been approved by the FERC and provides, 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, 2008, 2009 and 2010:

 
2008
2009
2010
 
(in thousands)
APCo
$575,300
$668,700
$757,900
CSPCo
233,200
257,600
230,400
I&M
(153,000)
(100,900)
(236,900)
KPCo
65,000
31,600
49,400
OPCo
(720,500)
(857,000)
(800,800)

Notification of Termination of the Power Pool

Much has changed since the Interconnection Agreement was originally executed in 1951. These changes include evolving environmental regulations; the introduction of “open access” to transmission facilities; the implementation of RTOs, including PJM, which is a robust generation power pool that has generating capacity of over 167,000 MWs, movement towards industry deregulation; increased competition in wholesale generation markets; and the effects of these changes on such things as costs, load and the array of supply and demand-side resources available to the AEP-East operating companies today.

Consequently, in December 2010, each Power Pool member gave written notice to the other members, and AEPSC, the Pool’s agent, of its decision to terminate the Interconnection Agreement, effective January 1, 2014 or such other date as approved by FERC, subject to state regulatory input. This decision to terminate is subject to ongoing evaluation by AEP.  Because the Interconnection Agreement is a rate schedule on file at FERC, its termination will not be effective until accepted for filing by FERC.  The Interim Allowance Agreement would also be terminated on the same date.

By giving notice to terminate the Interconnection Agreement and the Interim Allowance Agreement, the Power Pool members are providing a timeline within which all Power Pool members will decide how they will respond to the impacts from modifying or terminating the Interconnection Agreement.  The result of this process might be a modified or different type of Pool. Final resolution could involve bilateral contracts or sales of generating assets from surplus members to deficit members. If the Power Pool members do not reach a consensus, the Power Pool members could revoke their notices of termination and the Interconnection Agreement would remain in place.

CSW Operating Agreement

PSO, SWEPCo and AEPSC are parties to the CSW Operating Agreement, which has been approved by the FERC. The CSW Operating Agreement requires these public utility subsidiaries to maintain adequate annual planning reserve margins and requires the subsidiaries that have capacity in excess of the required margins to make such capacity available for sale to other public utility subsidiary parties 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 the use of more costly alternatives.  Revenues and costs arising from third party sales in their region are generally shared based on the amount of energy each west zone public utility subsidiary contributes that is sold to third parties.

The following table shows the net (credits) or charges allocated among the parties under the CSW Operating Agreement during the years ended December 31, 2008, 2009 and 2010:

 
2008
2009
2010
 
(in thousands)
PSO
$(57,000)
$(22,762)
$20,222
SWEPCo
   59,900
   22,762
   (20,222)

 
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Power generated by or allocated or provided under the Interconnection Agreement or CSW 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. See Regulation — Rates under Item 1, Utility Operations .

Under both the Interconnection Agreement and CSW Operating Agreement, power that is not needed to serve the native load of our public utility subsidiaries is sold in the wholesale market by AEPSC on behalf of those subsidiaries.  See Risk Management and Trading , below , for a discussion of the trading and marketing of such power.

AEP’s System Integration Agreement provides for the integration and coordination of AEP’s East companies, PSO and SWEPCo. 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). It is designed to function as an umbrella agreement in addition to the Interconnection Agreement and the CSW Operating Agreement, each of which controls the distribution of costs and benefits for activities within each zone.

Risk Management and Trading

As agent for AEP’s public utility subsidiaries, AEPSC sells excess power into the market and engages in power, natural gas, coal and emissions allowances risk management and trading activities focused in regions in which AEP traditionally operates and in adjacent regions. These activities primarily involve the purchase and sale of electricity (and to a lesser extent, natural gas, coal and emissions allowances) under physical forward contracts at fixed and variable prices. These contracts include physical transactions, over-the-counter swaps and exchange-traded futures and options. The majority of physical forward contracts are typically settled by netting into offsetting contracts.   These transactions are executed with numerous counterparties or on exchanges. 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, 2010, counterparties have posted approximately $28 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 had posted approximately $172 million with counterparties and exchanges).  Since open trading contracts are valued based on market prices of various commodities, exposures change daily. See Management’s Financial Discussion and Analysis , included in the 2010 Annual Reports, under the heading entitled Quantitative and Qualitative Disclosures About Risk Management Activities   for additional information.

Fuel Supply

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

 
2008
2009
2010
Coal and Lignite
86%
88%
82%
Natural Gas
6%
6%
 8%
Nuclear
8%
5%
 9%
Hydroelectric and other
<1%
1%
<1%

Price increases in one or more fuel sources relative to other fuels may result in increased use of other fuels. Variations in the generation of nuclear power are primarily related to a 2008 forced outage caused by a low pressure turbine blade failure event.  The unit returned to service in December 2009.

           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.  Electric demand experienced a slight increase in 2010 which resulted in a slight increase in coal and lignite tons consumed.  In response to continued lower consumption rates at certain locations during 2010, AEP continued to work with coal suppliers to better match deliveries with consumption and minimize the impact on fuel inventory costs, carrying costs and cash.  System wide, inventory levels were reduced by 11 days in 2010.

 
13
 
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 8,100 railcars, 672 barges, 17 towboats and a coal handling terminal with 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 coal and other dry-bulk commodity transportation operations that are not part of AEP’s Utility Operations segment.

During 2010, spot market prices for coal generally increased throughout the year.  Among other things, these increases are due to higher international demand for U.S. coals, and increased mining costs related to regulatory and permitting issues. Most of the coal purchased by AEP is procured through term contracts.  The price we pay under a number of these contracts is often lower than the spot market price for similar coal.  As term contracts expire they are replaced with new agreements, often at higher prices.  The price we paid for coal delivered in 2010 decreased from the prior year, due in part to the expiration of several high spot market contracts that were entered into in 2007 and 2008 for 2009 and the reopening of some contracts to current market prices.

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:

 
2008
2009
2010
Total coal delivered to AEP System plants (thousands of tons)
77,054
75,909
64,614
Average price per ton of purchased coal
$47.14
$49.54
$44.82

     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, 2010, the System’s coal inventory was approximately 50 days of full load burn.

In cases of emergency or shortage, AEP has developed programs to conserve coal supplies at its plants. Such programs have been filed and reviewed with federally approved electric reliability organizations.  In some cases, the relevant state regulatory agency has prescribed actions to be taken under specified circumstances by System companies, subject to the jurisdiction of such agency.

The FERC has adopted regulations relating, among other things, to the circumstances under which, in the event of fuel emergencies or shortages, it might order electric utilities to generate and transmit electric power to other regions or systems experiencing fuel shortages, and to ratemaking principles by which such electric utilities would be compensated. In addition, the federal government is authorized, under prescribed conditions, to reallocate coal and to require the transportation thereof, for the use at power plants or major fuel-burning installations experiencing fuel shortages.

    Natural Gas : Through its public utility subsidiaries, AEP consumed nearly 134 billion cubic feet of natural gas during 2010 for generating power. This represents a significant increase from 2009 due to lower natural gas prices and the addition of the 508 MW combined-cycle unit at SWEPCO’s J. Lamar Stall facility and the overall increased natural gas demand throughout AEP’s system. Many of the 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 long-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.
 
      N uclear: 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 requirements.
 
 
14
 
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 anticipates that the Cook Plant has sufficient storage capacity for its spent nuclear fuel to permit normal operations through 2013.  I&M has entered into an agreement to provide for onsite dry cask storage.  Initial loading of spent nuclear fuel into the dry casks is tentatively scheduled to begin in 2012.
 
                        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.  In 2009, when the most recent study was done, the estimated cost of decommissioning and disposal of low-level radioactive waste for the Cook Plant ranged from $831 million to $1.5 billion in 2009 non-discounted dollars.  At December 31, 2010, the total decommissioning trust fund balance for the Cook Plant was approximately $1.2 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; and

·  
Availability of a DOE 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 2010 Annual Reports, for information with respect to nuclear waste and decommissioning.

Low-Level Radioactive Waste : The LLWPA 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, but Utah licenses a low-level radioactive waste disposal site which currently accepts low-level radioactive waste from Michigan.  I&M ships some of its low level waste to a facility in Utah. There is currently no set date limiting I&M’s access to the Utah facility.   I&M stores the remaining type of low-level waste onsite.  In order to have capacity for the duration of its licensed operation of Cook Plant for onsite storage of waste not shipped to Utah, I&M will have to modify its existing facilities sometime in the next ten to fifteen years.

Structured Arrangements Involving Capacity, Energy, and Ancillary Services

In January 2000, OPCo and NPC, an affiliate of Buckeye, entered into an agreement relating to the construction and operation of a 510 MW gas-fired electric generating peaking facility to be owned by NPC, called the Mone Plant.  OPCo is entitled to 100% of the power generated by the Mone Plant, and is responsible for the fuel and other costs of the facility through May 2012, as extended. Following that, NPC and OPCo will be entitled to 80% and 20%, respectively, of the power of the Mone Plant, and both parties will generally be responsible for their allocable portion of the fuel and other costs of the facility.
 
 
15
 
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 KPCo and AEGCo, 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.

CSPCo : The Unit Power Agreement between AEGCo and CSPCo, dated March 15, 2007, provides for the sale by AEGCo to CSPCo of all the capacity and associated unit contingent energy and ancillary services available to AEGCo at the Lawrenceburg Plant that are scheduled and dispatched by CSPCo.  CSPCo 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 CSPCo, 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 as set forth in the agreement.

OVEC : AEP and several unaffiliated utility companies jointly own OVEC.  The aggregate equity participation of AEP in OVEC is 43.47%.  Until 2001, OVEC supplied from its generating capacity the power requirements of a uranium enrichment plant near Portsmouth, Ohio owned by the DOE.  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, CSPCo, 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, will expire by its terms in March 2026.  Negotiations are in process among the owners to extend this agreement until 2040.  AEP and the other owners have authorized environmental investments related to their ownership interests.  As of December 2010, OVEC’s Board of Directors has authorized capital expenditures totaling approximately $1.35 billion in connection with the engineering and construction of flue gas desulfurization projects and the associated scrubber waste disposal landfills at its two generating plants.  OVEC has completed the financing of approximately $950 million for these projects through debt issuances and would expect to finance the remaining cost by issuing additional debt.

ELECTRIC TRANSMISSION AND DISTRIBUTION

General

AEP’s public utility subsidiaries (other than AEGCo) 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, in combination with electric power, to retail customers of AEP’s 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 –Utility Operations - Regulation—Rates . The FERC regulates and approves the rates for wholesale transmission transactions. See Item 1 –Utility Operations - Regulation—FERC .  As discussed below, some transmission services also are separately sold to non-affiliated companies.
 
 
16
 
AEP’s public utility subsidiaries (other than AEGCo) 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 –Utility Operations - Competition .

AEP Transmission Pool

Transmission Agreement:   APCo, CSPCo, I&M, KPCo and OPCo operate their transmission lines as a single interconnected and coordinated system in the AEP East transmission zone and are parties to the Transmission Agreement (TA), defining how they share the costs and benefits associated with their relative ownership of the bulk transmission system (lines operated at 138kV and above and stations containing extra high voltage equipment). The TA has been approved by the FERC. Sharing under the TA is based upon each company’s “member-load-ratio.”  The member-load-ratio is calculated monthly by dividing such company’s highest monthly peak demand for the last twelve months by the aggregate of the highest monthly peak demand for the last twelve months for all east zone operating companies.  The respective peak demands and member-load-ratios as of December 31, 2010 are set forth above in the section titled ELECTRIC GENERATION – AEP Power Pool and CSW Operating Agreement.

In October 2010, the FERC approved our request to amend the TA effective November 1, 2010.  KgPCo and WPCo were added as parties to the TA.  In addition, the amendments generally provide for the allocation of PJM transmission costs on the basis of the TA parties’ 12-month coincident peak and reimburse transmission revenues based on individual cost of service instead of the member-load ratio method previously used.

The following table shows the net (credits) or charges allocated among the parties to the TA during the years ended December 31, 2008, 2009 and 2010:

 
2008
2009
2010
 
(in thousands)
APCo
$(29,000)
$(12,500)
$(16,000)
CSPCo
55,000
51,300
42,500
I&M
(37,000)
(38,400)
(25,200)
KPCo
(2,000)
(8,800)
(8,000)
OPCo
13,000
8,400
6,700

Transmission Coordination Agreement , OATT, and ERCOT Protocols :   PSO, SWEPCo, TNC and AEPSC are parties to the TCA.  Under the TCA, a coordinating committee is charged with the responsibility of (i) overseeing the coordinated planning of the transmission facilities of the parties to the agreement, including the performance of transmission planning studies, (ii) the interaction of such subsidiaries with independent system operators and other regional bodies interested in transmission planning and (iii) 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 (with respect to PSO and SWEPCo) and PUCT-approved protocols for ERCOT (with respect to TCC and TNC).

The following table shows the net (credits) or charges allocated pursuant to the TCA, SPP OATT and ERCOT protocols as described above during the years ended December 31, 2008, 2009 and 2010:

 
2008
2009
2010
 
(in thousands)
PSO
$8,200
$11,000
$10,500
SWEPCo
(8,200)
(11,000)
(10,500)
TCC
1,500
1,700
2,100
TNC
(1,500)
(1,700)
(2,100)

 
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Transmission Services for Non-Affiliates:   In addition to providing transmission services in connection with their own power sales, AEP’s public utility subsidiaries through RTOs also provide transmission services for non-affiliated companies. See Item 1 –Utility Operations – 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 and AEP West companies. The System Transmission Integration Agreement functions as an umbrella agreement in addition to the TA and the TCA. The System Transmission Integration Agreement contains two service schedules that govern:

·  
The allocation of transmission costs and revenues and

·  
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

The AEP East Companies are members of PJM, and SWEPCo and PSO 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. The remaining AEP West companies (TCC and TNC) are members of ERCOT. See Note 4 to the consolidated financial statements, entitled Rate Matters , included in the 2010 Annual Reports under the heading entitled Regional Transmission Rate Proceedings at the FERC for additional information regarding RTOs.

REGULATION

General

Except for transmission and/or retail generation sales in certain of its jurisdictions, AEP’s public utility subsidiaries’ retail rates and certain other matters are subject to traditional cost-based regulation by the state utility commissions.  AEP’s subsidiaries are also subject to regulation by the FERC under the FPA with respect to wholesale power and transmission service transactions as well as certain unbundled retail transmission rates mainly in Ohio.  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 public utility subsidiaries are also subject to the regulatory provisions of EPACT, much of which is administered by the FERC.  EPACT provides the FERC limited “backstop” transmission siting authority as well as increased utility merger oversight.

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 (i) a utility’s adjusted revenues and expenses during a defined test period and (ii) 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.
 
 
18
 
Public utilities have traditionally financed capital investments until the new asset was 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 difficult 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, securitization, formula rates and the inclusion of future test-year projections into rates.

In many jurisdictions, the rates of AEP’s public utility subsidiaries are generally based on the cost of providing traditional bundled electric service (i.e., generation, transmission and distribution service). In the ERCOT area of Texas, our utilities have exited the generation business and they currently charge unbundled cost-based rates for transmission and distribution service only.  In Ohio, rates for electric service are unbundled for generation, transmission and distribution service.  Historically, the state regulatory frameworks in the service area of the AEP System 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 2010 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.

Ohio : CSPCo and OPCo provide “default” retail electric service to customers at unbundled rates pursuant to the Ohio Act.  CSPCo and OPCo exclusively provide distribution and transmission services to retail customers within their service territories at cost-based rates approved by the PUCO.  Transmission services are provided at OATT rates based on rates established by the FERC.  CSPCo and OPCo’s generation/supply rates are subject to their Electric Security Plans that the PUCO modified and approved in a March 2009 order.   The order established standard service offer rates in effect through 2011.  The order also provides a fuel adjustment clause for the three-year period of the ESP.  The order has been appealed by various parties to the Supreme Court of Ohio.  Although the Supreme Court of Ohio has rejected or dismissed a number of procedural and other challenges to the order, the order remains on appeal with that Court with oral arguments scheduled in February 2011.  In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for CSPCo to merge into OPCo, effective in October 2011.  Decisions are pending from the PUCO and the FERC.  Approval of the merger will not affect their rates until such time as the PUCO approves new rates.

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 a fuel adjustment factor to retail kilowatt-hour sales. The factor is generally adjusted annually and is based upon forecasted fuel and purchased energy costs. Over or under collections of fuel costs for prior periods are returned to or recovered from customers in the year following when new annual factors are established.

Texas :   Retail customers in TCC’s and TNC’s ERCOT service area of Texas are served through non-affiliated Retail Electric Providers (“REPs”).  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.  Effective September 2009, competition in the SPP area of Texas has been delayed until certain steps defined by statute and by PUCT rule have been accomplished. As such, the PUCT continues to approve base and fuel rates for SWEPCo’s Texas operations on a cost of service basis.
 
 
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Virginia :   APCo currently provides retail electric service in Virginia at unbundled rates approved by the VSCC.  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.  APCo is permitted to retain a minimum of 25% of the margins from its off-system sales with the remaining margins from such sales credited against its fuel adjustment clause factor with a true-up to actual.  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 clause which trues-up to actual expenses.

Other Jurisdictions : The public utility subsidiaries of AEP also provide service at cost based regulated bundled rates in Arkansas, Kentucky, Louisiana and Tennessee and regulated unbundled rates in Michigan.  These jurisdictions provide for the timely recovery of fuel costs through fuel adjustment clauses that true-up to actual expenses.
 
 
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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 (1)
 
Percentage of OSS Profits
Shared with Ratepayers
 
AEP Utility
Subsidiaries
Operating in
that Jurisdiction
 
Authorized
Return on
Equity (2)
 
 
 
 
 
 
 
 
 
 
Ohio
32%
No sharing included in ESPs
OPCo
(3)
 
CSPCo
(3)
 
 
 
 
 
 
 
Texas
12%
Not Applicable in ERCOT
TCC (4)
9.96%
 
TNC (4)
9.96%
 
90% in SPP
SWEPCo
10.33%
 
 
 
 
 
 
 
Virginia
12%
75%
APCo
10.53%
 
 
 
 
 
 
 
West Virginia
11%
100%
APCo
10.50%
 
WPCo
10.50%
 
 
 
 
 
 
 
Oklahoma
10%
75%
PSO
10.15%
 
 
 
 
 
 
 
Indiana
9%
50% after certain level (5)
I&M
10.50%
 
 
 
 
 
 
 
Kentucky
5%
60% below and above certain level (6)
KPCo
10.50%
 
 
 
 
 
 
 
Louisiana
4%
50% to 100% after certain levels (7)
SWEPCo
10.57%
 
 
 
 
 
 
 
Arkansas
2%
50% to 100% after certain levels (8)
SWEPCo
10.25%
 
 
 
 
 
 
 
Michigan
2%
75%
I&M
10.35%
 
 
 
 
 
 
 
Tennessee
1%
Not Applicable
KgPCo
12.00%

(1)  
Represents the percentage of revenues from sales to retail customers from AEP utility companies operating in each state to the total AEP System revenues from sales to retail customers for the year ended December 31, 2010.
(2)  
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.
(3)  
CSPCo’s and OPCo’s generation revenues are governed by its Electric Security Plans (ESPs) filed and approved by the PUCO.  Starting in January 2009, the ESPs became effective which authorized rate increases during the ESP period, subject to caps that limit the rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011.  Some rate components and increases are exempt from the cap limitations.  The ESPs also provided for a fuel adjustment clause for the three-year period of the ESP.
(4)  
Operating in the ERCOT region of Texas and consists of distribution and transmission functions.  Generation operations were divested in compliance with the Texas electric restructuring.
(5)  
There is an annual $37.5 million credit established for off-system sales in base rates.  If the off-system sales profits exceed the amount built into base rates, I&M reimburses ratepayers 50% of the excess.
(6)  
Starting in July 2010, there is an annual $15.3 million credit established for off-system sales in base rates.  If the monthly off-system sales profits do not meet the monthly level built into base rates, ratepayers reimburse KPCo 60% of the shortfall.  If the monthly off-system sales profits exceed the monthly level built into base rates, KPCo reimburses ratepayers 60% of the excess.
(7)  
Below $874,000, 100% is shared with customers; from $874,001 to $1,314,000, 85% is shared with customers; above $1,314,000, 50% is shared with customers.
(8)  
Below $758,600, 100% is shared with customers; from $758,601 to $1,167,078, 85% is shared with customers; above $1,167,078, 50% is shared with customers.

 
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FERC

Under the FPA, 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 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 (i) approving contracts for wholesale sales to municipal and cooperative utilities and (ii) 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 control area of the SPP, AEP has market-rate authority from the FERC, under which much of its 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 OASIS, 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.  The AEP East Companies are members of PJM. SWEPCo and PSO 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 limited “backstop” transmission siting authority as well as increased utility merger oversight.

COMPETITION

Under current Ohio legislation, electric generation is sold in a competitive market in Ohio, and our native load customers in Ohio have the ability to switch to alternative suppliers for their electric generation service.  Competitive power suppliers are targeting retail customers by offering alternative generation service.   A growing number of CSPCo's commercial retail customers have switched to alternative generation providers while additional Ohio customers have provided notice of their intent to switch.  In 2010, CSPCo lost about 3% of its total load due to customer switching.  These evolving market conditions will continue to impact CSPCo’s results of operations.  To date, OPCo’s customer losses have been insignificant.   In February 2010, the PUCO granted a retail supply subsidiary of AEP a certificate to operate as a competitive retail electric service provider in Ohio.

The 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 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 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.

 
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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 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.

AEP RIVER OPERATIONS

Our AEP River Operations Segment transports 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 generating plants.  We charge affiliated customers rates that reflect our costs.  AEP River Operations includes approximately 2,581 barges, 45 towboats and 26 harbor boats that we own or lease. 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 – Utility Operations - 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), information timeliness and equipment. 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 and inefficient older river locks operated by others may also limit our operations when certain of the waterways we serve are closed.

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.

GENERATION AND MARKETING

Our Generation and Marketing Segment consists of non-utility generating assets and a competitive power supply and energy trading and marketing business.  We enter into short and long-term transactions to buy or sell capacity, energy and ancillary services primarily in the ERCOT market, and to a lesser extent Ohio in PJM and MISO.  As of December 31, 2010, 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.  In 2006, TNC transferred
 
 
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its coal-fired generation capacity to comply with the separation requirements of the Texas Act.  The power obtained from the Oklaunion power station is marketed and sold in ERCOT.  We are regulated by the PUCT for transactions inside ERCOT and by the FERC for transactions outside of ERCOT.  While peak load in ERCOT typically occurs in the summer, we do not necessarily expect seasonal variation in our operations.  In 2010, we started operations of a retail energy business in the State of Ohio.  The purpose of this operation is to sell competitive power supply to residential, commercial and industrial customers in the deregulated areas of Ohio.

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.   (Applies to each registrant.)

Our business plan calls for extensive investment in capital improvements and additions, including the installation of environmental upgrades and retrofits, construction and/or acquisition of additional generation units and 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.  While we may seek to limit the impact of any denied recovery by attempting to reduce the scope of our capital investment, there can be no assurance as to the effectiveness of any such mitigation efforts, particularly with respect to previously incurred costs and commitments.

We may not fully recover all of the investment in and expenses related to the Turk Plant.    (Applies to AEP and SWEPCo)

SWEPCo is in the process of building the John W. Turk Plant (the “Turk Plant”) in southwest Arkansas and holds a 73% ownership interest in the planned 600MW coal-fired generating facility.  Its construction and anticipated operation has resulted in numerous legal challenges, including:

·  
the validity of the air permit issued by the Arkansas Pollution Control and Ecology Commission in connection with the operation of the Turk Plant;
·  
the validity of the wetlands permit issued by the U.S. Army Corps of Engineers in connection with the construction and operation of the Turk Plant;
·  
the validity of the authority granted by the APSC to build three transmission lines and facilities needed to transmit power from the Turk Plant;
·  
whether SWEPCo is required to obtain APSC approval to construct the Turk Plant without pursuing authority to seek recovery of the originally approved 88 MW portion of Turk Plant costs in Arkansas retail rates; and
·  
a complaint filed in the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of Interior and the U.S. Fish and Wildlife Service seeking a temporary restraining order and preliminary injunction to stop construction of the Turk Plant asserting claims of violations of various federal and state laws.

If SWEPCo is unable to complete the Turk Plant construction and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.
 
 
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Our request for rate recovery in Ohio for distribution service may not be approved in its entirety.    (Applies to AEP, CSPCo and OPCo)

In January 2011, CSPCo and OPCo filed a notice of intent with the PUCO to file for an annual increase in distribution rates of $34 million and $59 million, respectively, either as individual companies, or, if their proposed merger is approved, as a single merged entity.  The increase is based upon an 11.15% return on common equity to be effective January 2012. If the PUCO denies all or part of the requested rate recovery, it could reduce future net income and cash flows.

Our request for rate recovery in Ohio for generation service may not be approved in its entirety.    (Applies to AEP, CSPCo and OPCo)

In January 2011, CSPCo and OPCo filed an application with the PUCO to approve the new ESP that includes a standard service offer pricing for generation effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  The requested increase in 2012 is $54 million and in 2013 is $106 million.  If the PUCO denies all or part of the requested rate recovery, it could reduce future net income and cash flows.

Ohio may require us to refund revenue that we have collected. (Applies to AEP, CSPCo 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 rate adjustments result in significantly excessive earnings, the excess amount could be returned to customers.  In September 2010, CSPCo and OPCo filed their 2009 significantly excessive earnings filings with the PUCO.  In January 2011, the PUCO ruled that CSPCo generated approximately $43 million in significantly excessive earnings during 2009. The ruling is subject to rehearing by the PUCO and could be appealed in the courts.  If rehearing or a final appeal, if any, results in findings of additional significantly excessive earnings, then further amounts will be returned to customers. CSPCo and OPCo must file their 2010 significantly excessive earnings filings with the PUCO. If the PUCO determines that CSPCo’s and/or OPCo’s 2010 earnings were significantly excessive, CSPCo and/or OPCo may be required to return a portion of their revenues to customers.
 
Ohio may require us to refund fuel costs that we have collected. (Applies to OPCo)

The PUCO selected an outside consultant to conduct an audit of recovery under the fuel adjustment clause for the period of January 2009 through December 2009.  The audit report included a recommendation that the PUCO should review whether any proceeds from a 2008 coal contract settlement agreement which totaled $72 million should reduce OPCo’s under-recovery balance.  Of the total proceeds, approximately $58 million was recognized as a reduction to fuel expense prior to 2009 and $14 million reduced fuel expense in 2009 and 2010.  If the PUCO orders any portion of the $58 million or other future adjustments be used to reduce the current year fuel adjustment clause deferral, it would reduce future net income and cash flows and impact financial condition.

Ohio may require us to refund rider revenue that we have collected. (Applies to CSPCo and OPCo)

The PUCO approved recovery of an Economic Development Rider (EDR) by CSPCo and OPCo.  An intervenor in that proceeding has filed a notice of appeal of that award with the Supreme Court of Ohio.  As of December 31, 2010, CSPCo and OPCo have incurred $38 million and $30 million, respectively, in EDR costs including carrying costs.  If CSPCo and OPCo are not ultimately permitted to recover their deferrals it would reduce future net income and cash flows and impact financial condition.

 
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Our request for rate recovery in West Virginia may not be approved in its entirety.    (Applies to AEP and APCo)

In May 2010, APCo and WPCo filed a request with the WVPSC to increase annual base rates by $156 million based on an 11.75% return on common equity to be effective March 2011.  If the WVPSC denies all or part of the requested rate recovery, it could reduce future net income and cash flows.

Oklahoma may require us to refund fuel costs that we have collected. (Applies to PSO)

In July 2009, the OCC initiated a proceeding to review PSO’s fuel and purchased power adjustment clause for the calendar year 2008 and also initiated a prudence review of the related costs.  In March 2010, the Oklahoma Attorney General and an intervenor recommended the fuel clause adjustment rider be amended to decrease the shareholder’s portion of off-system sales margins from 25% to 10%.  That intervenor also recommended that the OCC conduct a comprehensive review of all affiliate transactions during 2007 and 2008.  In July 2010, additional testimony regarding the 2007 transfer of ERCOT trading contracts to AEP Energy Partners was filed.  Included in this testimony were unquantified refund recommendations relating to re-pricing of contract transactions.  If the OCC were to issue an unfavorable decision, it would reduce future net income and cash flows and impact financial condition.

Our future access to assets used to serve a major customer is in question.   (Applies to I&M)

Since 1975 I&M has leased certain energy delivery assets from the City of Fort Wayne, Indiana under a long-term lease that expired on February 28, 2010.  As a result of a court-sponsored mediation process, I&M agreed to purchase the leased assets from Fort Wayne.  The agreement was signed in October 2010 and is subject to approval by the IURC.  If the IURC does not approve the agreement or the recovery of the costs resulting from the agreement or the lease, it could reduce future net income and cash flows.

We may not recover costs incurred to begin construction on projects that are canceled.   (Applies to 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 a regulatory 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 and other costs.   (Applies to 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.  Traditionally, we have 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.  Long lead times in construction, the high costs of plant and equipment and difficult capital markets have heightened the risks involved in our capital investments 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.   (Applies to 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:

·  
major facility or equipment failure;
·  
an environmental event such as a serious spill or release;
·  
fires, floods, droughts, earthquakes, hurricanes or other natural disasters;
·  
wars, terrorist acts or threats and other catastrophic events;
·  
significant health impairments or disease events, and;
·  
other serious operational problems.

We are exposed to nuclear generation risk. (Applies to 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 8-9% of the electricity we generate.  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 if insurance coverage is inadequate (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); and,

·  
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.

 
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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.

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.   (Applies to 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.

The amount we charged third parties for using our transmission facilities is subject to refund.   (Applies to AEP, APCo, CSPCo, I&M and OPCo.)

In July 2003, the FERC issued an order directing PJM and MISO to make compliance filings for their respective tariffs to eliminate the transaction-based charges for through and out (T&O) transmission service on transactions where the energy is delivered within those RTOs.  To mitigate the impact of lost T&O revenues, the FERC approved temporary replacement seams elimination cost allocation (SECA) transition rates beginning in December 2004 and extending through March 2006.  Because intervenors objected to this decision, the SECA fees we collected ($220 million) are subject to refund.  Some claims for refund have been settled, and we have recorded a provision for estimated settlement refunds for the remaining unsettled $108 million of gross SECA revenues collected.  Any payments in excess of the reserve balance could harm our results of operations and financial position.

We could be subject to higher costs and/or penalties related to mandatory reliability standards. (Applies to 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. These standards, which previously were being applied on a voluntary basis, became mandatory in June 2007. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and is 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.

At times, demand for power could exceed our supply capacity.   (Applies to each registrant.)

We are currently obligated to supply power in parts of eleven states.  From time to time, because of unforeseen circumstances, the demand for power required to meet these obligations could exceed our available generation capacity.  If this occurs, we would have to buy power from the market.  This would increase the pressure on our short-term debt financing capacity in times of tight liquidity.  We may not always have the ability to pass these costs on to our customers, and the time lag between incurring costs and recovery can be long.  Since these situations most often occur during periods of peak demand, it is possible that the market price for power at that time would be very high. Even if a supply shortage were brief, we could suffer substantial losses that could reduce our results of operations.
 
 
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Risks Related to Market, Economic or Financial Volatility

If we are unable to access capital markets on reasonable terms, it could have an adverse impact on our net income, cash flows and financial condition.   (Applies to 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 have an adverse impact on net income, cash flows and financial condition.

Downgrades in our credit ratings could negatively affect our ability to access capital and/or to operate our power trading businesses.   (Applies to 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 our financial condition could be harmed and future results of operations could be adversely affected.

Our power trading business relies on the investment grade ratings of our individual public utility subsidiaries’ senior unsecured long-term debt.  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.

Our pension plan will require additional significant contributions. (Applies to each registrant.)

The performance of the capital markets affects the value of the assets that are held in trust to satisfy future obligations under our defined benefit pension plan.  The volatility of the capital markets in the past years has led to a decline in the market value of these assets. Also, a decline in interest rates on corporate bonds in 2010 has impacted the benchmark discount rate in a way that results in a higher calculated pension liability. Accordingly, our future required contributions to fund obligations under our defined benefit plan could increase significantly.

AEP has no income or cash flow apart from dividends paid or other obligations due it from its subsidiaries.   (Applies to 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. In addition, any payment of dividends, distributions or advances by the utility subsidiaries to AEP could be subject to regulatory restrictions.  AEP indebtedness and common stock dividends are structurally subordinated to all subsidiary indebtedness and preferred stock obligations.
 
 
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Our operating results may fluctuate on a seasonal or quarterly basis and with general economic conditions.    (Applies to 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. (Applies to 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.    (Applies to 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.    (Applies to each registrant.)

We are exposed to changes in the price and availability of coal and the price and availability to transport coal because most of our generating capacity is coal-fired.  We have contracts of varying durations for the supply of coal for most of our existing generation capacity, 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.  According to our estimates, we have procured sufficient emission allowances to cover nearly all of our projected needs for the next two years as well as a majority of our needs beyond that timeframe.  At some future point, additional costs may be incurred if forthcoming regulation changes require supplemental allowances for compliance.  If and when we obtain additional allowances those purchases may not be on as favorable terms as those currently obtained.
 
 
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We also own natural gas-fired facilities, which increases our exposure to market prices of natural gas.  Natural gas prices tend to be more volatile than prices for other fuel sources.  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.

Prices for coal, natural gas and emission allowances have shown material upward and downward swings in the recent 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.  Since the prices we obtain for power may not change at the same rate as the change in coal, emission allowances or natural gas costs, we may be unable to pass on the changes in costs to our customers.

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.

Risks Relating to State Restructuring

Our customers have recently begun to select alternative electric generation service providers, as allowed by Ohio legislation. (Applies to AEP and CSPCo)
 
Under current Ohio legislation, electric generation is sold in a competitive market in Ohio, and our native load customers in Ohio have the ability to switch to alternative suppliers for their electric generation service.  Competitive power suppliers are targeting retail customers by offering alternative generation service.   A growing number of CSPCo's commercial retail customers have switched to alternative generation providers while additional Ohio customers have provided notice of their intent to switch.  In 2010, CSPCo lost about 3% of its total load due to customer switching.  To date, OPCo’s losses have not been significant.  These evolving market conditions will continue to impact CSPCo's results of operations.

There is uncertainty as to our recovery of stranded costs resulting from industry restructuring in Texas.    (Applies to AEP.)

Restructuring legislation in Texas required utilities with stranded costs to use market-based methods to value certain generating assets for determining stranded costs.  We elected to use the sale of assets method to determine the market value of TCC’s generation assets for stranded cost purposes.  In general terms, the amount of stranded costs under this market valuation methodology is the amount by which the book value of generating assets, including regulatory assets and liabilities that were not securitized, exceeds the market value of the generation assets, as measured by the net proceeds from the sale of the assets.  In May 2005, TCC filed its stranded cost quantification application with the PUCT seeking recovery of $2.4 billion of net stranded generation costs and other recoverable true-up items.  A final order was issued in April 2006.  In the final order, the PUCT determined TCC’s net stranded generation costs and other recoverable true-up items to be approximately $1.475 billion.  We have appealed the PUCT’s final order seeking additional recovery consistent with the Texas Restructuring Legislation and related rules, other parties have appealed the PUCT’s final order as unwarranted or too large.  Management cannot predict the ultimate outcome of any future court appeals or any future remanded PUCT proceeding.

Collection of our revenues in Texas is concentrated in a limited number of REPs.    (Applies to 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 2010, TCC’s largest customer accounted for 25% of its operating revenue and its second largest customer accounted for 13% of its operating revenue; TNC’s largest customer (a non-utility affiliate) accounted for 29% of its operating revenues and its second largest customer accounted for 16% 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 adversely affect the timing and receipt of our cash flows and thereby have an adverse effect on our liquidity.

 
31
 
Risks Related to Owning and Operating Generation Assets and Selling Power

Our costs of compliance with existing environmental laws are significant.    (Applies to 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 generating plants are potentially 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.  These expenditures have been significant in the past, and we expect that they will increase in the future.  Costs of compliance with environmental regulations could adversely affect our net income and financial position, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increase.  While we expect to recover our expenditures for pollution control technologies, replacement generation and associated operating costs from customers through regulated rates (in regulated jurisdictions) or market prices, without such recovery those costs 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 .    (Applies to each registrant)

In June 2009, the U.S. House of Representatives passed the American Clean Energy Security Act (ACES).  ACES is a comprehensive energy and global warming bill that includes a number of provisions that would directly affect our business, including energy efficiency and renewable electricity standards, funding for carbon capture and sequestration demonstration projects, CO 2   emission standards, and an economy-wide cap and trade program for large sources of CO 2   emissions that would reduce emissions by 17% in 2020 and just over 80% by 2050 from 2005 levels.  Costs of compliance with the proposed legislation could adversely affect our net income and financial position.  This legislation did not become law.

Separately, in December 2009, the Federal EPA issued a final endangerment finding under the CAA regarding emissions from motor vehicles.  Several groups have filed challenges to the endangerment finding.  The endangerment finding will lead to regulation of CO 2   and other gases under existing laws.  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 us 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.  While we expect that costs of complying with new CO 2 and other GHG emission standards will be treated like all other reasonable costs of serving customers and should be recoverable from customers as costs of doing business, without such recovery those costs could reduce our future net income and cash flows and harm our financial condition.

Courts adjudicating nuisance and other similar claims against us may order us to limit or reduce our CO 2 emissions.    (Applies to each registrant)

In 2004, eight states and the City of New York filed an action in Federal District Court for the Southern District of New York against AEP, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority.  The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants.  The actions allege that CO 2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming, and sought injunctive relief in the form of specific emission reduction commitments from the defendants.  The Second Circuit Court of Appeals reinstated this lawsuit on appeal after the lower court had dismissed it.  The U.S. Supreme Court has agreed to hear the defendants’ request for appeal.

 
32
 
The trial court adjudicating the reinstated nuisance claims may order the defendants, including us, to limit or reduce CO 2 emissions.  This or similar 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.  While management believes such costs should be recoverable from customers as costs of doing business, without such recovery those costs could reduce our future net income and cash flows and harm our financial condition.

If these or other future actions are resolved against us, substantial modifications of our existing coal-fired power plants could be required.  In addition, we could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay penalties and/or halt operations.  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.

We may not fully recover the costs of repairing or replacing damaged equipment in Cook Plant Unit 1 and may be required to pay additional accidental outage insurance proceeds to ratepayers.    (Applies to AEP and I&M)

Cook Plant Unit 1 is a 1,084 MW nuclear generating unit located in Bridgman, Michigan.  In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in significant turbine damage and a small fire on the electric generator.  This equipment, located in the turbine building, is separate and isolated from the nuclear reactor.  The turbine rotors that caused the vibration were installed in 2006 and were within the vendor’s warranty period.  The warranty provides for the repair or replacement of the turbine rotors if the damage was caused by a defect in materials or workmanship.  Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $ 395 million.  Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process.  I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power.  If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.

Our revenues and results of operations from selling power are subject to market risks that are beyond our control.   (Applies to 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 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.
 
 
33
 
Volatility in market prices for fuel and power may result from:

·  
weather 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; and
·  
federal, state and foreign energy and environmental regulation and legislation.

Our power trading (including coal, gas and emission allowances trading and power marketing) and risk management policies cannot eliminate the risk associated with these activities.   (Applies to each registrant.)

Our power trading (including coal, gas and emission allowances trading and power marketing) activities expose us to risks of commodity price movements.   We attempt to manage our exposure 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 and 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.

Our financial performance may be adversely affected if we are unable to operate our electric generating facilities successfully.   (Applies to each registrant.)

Our performance is highly dependent on the successful operation of our electric generating facilities.   Operating electric generating 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;
·  
fuel supply interruptions caused by transportation constraints, adverse weather, non-performance by our suppliers and other factors; and
·  
catastrophic events such as fires, earthquakes, explosions, hurricanes, terrorism, floods or other similar occurrences.

A decrease or elimination of revenues from power produced by our electric generating facilities or an increase in the cost of operating the facilities would adversely affect our results of operations.
 
 
34
 
Parties with whom we have contracts may fail to perform their obligations, which could harm our results of operations.   (Applies to 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.   (Applies to each registrant.)

We depend on transmission facilities owned and operated by other unaffiliated 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 for electricity and gas, 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.

We do not fully hedge against price changes in commodities.   (Applies to each registrant.)

We routinely enter into contracts to purchase and sell electricity, natural gas, coal and emission allowances as part of our power marketing and energy and emission allowances trading operations.   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.

We manage our exposure by establishing risk limits and entering into contracts to offset some of our positions (i.e., to hedge our exposure to demand, market effects of weather and other changes in commodity prices).   However, we do not always hedge the entire exposure of our operations from commodity price volatility.   To the extent we do not hedge against commodity price volatility, our results of operations and financial position may be improved or diminished based upon our success in the market.

Financial derivatives reforms could increase the liquidity needs and costs of our commercial trading operations.   (Applies to each registrant.)

In July 2010, federal legislation was enacted to reform financial markets that significantly alter how over-the-counter (OTC) derivatives are regulated.  The law increased regulatory oversight of OTC energy derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the Commodity Futures Trading Commission (CFTC), (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits.  The law gives the CFTC authority to exempt end users of energy commodities which could reduce, but not eliminate, the applicability of these measures to us and other end users.  These requirements could cause our OTC transactions to be more costly and have an adverse effect on our liquidity 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.

 
35
 

ITEM 1B.                            UNRESOLVED STAFF COMMENTS

None.

ITEM 2.                      PROPERTIES

GENERATION FACILITIES

UTILITY OPERATIONS

At December 31, 2010, the AEP System owned (or leased where indicated) generating plants, all situated in the states in which our electric utilities serve retail customers, with net power capabilities (winter rating) shown in the following table:

Company
 
Stations
 
Coal
MW
   
Natural Gas
MW
   
Nuclear
MW
   
Lignite
MW
   
Hydro
MW
   
Oil
MW
   
Total
MW
 
AEGCo
    2  
(a)
    1,310       1,186                               2,496  
APCo
    17  
(b)(c)
    5,093       516                   677             6,286  
CSPCo
    7  
(d)
    2,388       1,347                           3       3,738  
I&M
    9  
(a)
    2,305               2,191 (e)           15               4,511  
KPCo
    1         1,078                                             1,078  
OPCo
    8  
(b)(c)
    8,482                             26               8,508  
PSO
    8  
(f)
    1,026       3,554                             25       4,605  
SWEPCo
    11  
(g)
    1,848       2,668               850                       5,366  
TNC
    6  
(f)(h)
    377       262                               8       647  
System Totals
    69         23,907       9,533       2,191       850       718       36       37,235  
Percentage of System Totals
              64.2       25.6       5.9       2.3       1.9       0.1          

(a)
Unit 1 of the Rockport Plant is owned one-half by AEGCo and one-half by I&M. Unit 2 of the Rockport Plant is leased one-half by AEGCo and one-half by I&M. The leases terminate in 2022 unless extended.

(b)
Unit 3 of the John E. Amos Plant is owned one-third by APCo and two-thirds by OPCo.

(c)
APCo owns Units 1 and 3 and OPCo owns Units 2, 4 and 5 of Philip Sporn Plant, respectively.

(d)
CSPCo owns generating units in common with Duke Ohio and DP&L. Its percentage ownership interest is reflected in this table.

(e)
Cook Unit 1 currently is not operating at the full capacity set forth here.  For further information, see Cook Nuclear Plant below.

(f)
PSO and TNC, along with Oklahoma Municipal Power Authority and The Public Utilities Board of the City of Brownsville, Texas, are joint owners of the Oklaunion power station. PSO and TNC’s ownership interest is reflected in this portion of the table.  TNC has transferred its interest to a non-utility affiliate through 2027.

(g)
SWEPCo owns generating units in common with Cleco Corporation and other unaffiliated parties. Only its ownership interest is reflected in this table.

(h)
TNC’s gas-fired and oil-fired generation has been deactivated.
 
        
 
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     Cook Nuclear Plant

The following table provides operating information relating 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
Net Capacity Factors
     
2010
82.2%(a)
 
80.8%
2009
2.8%(a)
 
83.1%
2008
59.2%(a)
 
96.6%
2007
                 97.4%
 
83.8%
       
(a)  
 Unit 1 Net Capacity Factor for 2008 through 2010 was impacted by a 2008 forced outage caused by a low pressure turbine blade failure event. The reduced capacity repaired turbine is projected to be replaced with a full capacity turbine in late 2011.

New Generation

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in-service in 2012.  SWEPCo owns 73% of the Turk Plant and will operate the completed facility.  AEGCo is currently constructing the Dresden Plant, a new 580 MW combined-cycle natural gas generating unit in Ohio, which is expected to be in-service in 2012.  We resumed work on the Dresden Plant  in the first quarter of 2011.

GENERATION AND MARKETING

In addition to the generating facilities described above, AEP has ownership interests in other electrical generating facilities. Information concerning these facilities at December 31, 2010 is listed below.

 
Facility
Fuel
Location
Capacity
Total MW
       
Desert Sky Wind Farm
Wind
Texas
161
       
Trent Wind Farm
Wind
Texas
150
Total
 
311

 
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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:

 
Total Overhead Circuit Miles of
Transmission and Distribution Lines
 
Circuit Miles of
765kV Lines
AEP System  (a)
224,703
(b)
 
2,116
 
APCo
52,233
   
734
 
CSPCo (a)
15,697
   
—
 
I&M
22,005
   
615
 
KgPCo
1,358
   
—
 
KPCo
11,087
   
258
 
OPCo
30,754
   
509
 
PSO
21,126
   
—
 
SWEPCo
21,759
   
—
 
TCC
29,686
   
—
 
TNC
17,289
   
—
 
WPCo
1,708
   
—
 

(a)
Includes 766 miles of 345,000-volt jointly owned lines.
(b)
Includes 73 miles of overhead transmission lines not identified with an operating company.

TRANSMISSION INITIATIVES

We continue our pursuit of transmission opportunities throughout the U.S.  In 2009, we announced that our recently formed transmission company, AEP Transmission Company, LLC, will pursue new transmission investments within our retail service territories.  Through joint ventures with various other companies, we have existing and/or planned transmission projects and opportunities outside of our retail service territories.  We plan to invest approximately $273 million in these projects in 2011.  See Management’s Financial Discussion and Analysis included in the 2010 Annual Reports under the heading Transmission Initiatives , for more information.

TITLES

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 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.

SYSTEM TRANSMISSION LINES AND FACILITY SITING

Laws in the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Texas, Tennessee, 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.
 
 
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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 $2.5 billion of construction expenditures for 2011, excluding the debt and equity components of 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, and the ability to access capital.

CONSTRUCTION EXPENDITURES

The following table shows construction expenditures (including environmental expenditures) during 2008, 2009 and 2010 and a current estimate of 2011 construction expenditures.  Actual amounts for 2008, 2009 and 2010 exclude the equity component of AFUDC and assets acquired under leases.  Budgeted amounts for 2011 exclude the debt and equity components of AFUDC and assets acquired under leases. 

   
2008
Actual
   
2009
Actual
   
2010
Actual
   
2011
Estimate (b)
 
   
(in thousands)
 
Total AEP System (a)
  $ 3,800,000     $ 2,792,000     $ 2,345,000     $ 2,506,000  
APCo
    696,767       543,587       534,334       450,100  
CSPCo
    433,014       302,699       235,901       186,900  
I&M
    352,335       332,775       333,238       304,900  
OPCo
    706,315       417,601       276,736       264,100  
PSO
    285,826       175,122       194,896       169,200  
SWEPCo
    692,162       596,581       420,485       441,500  

(a)  
Includes expenditures of other subsidiaries not shown. The figures reflect construction expenditures, not investments in subsidiary companies.  Excludes discontinued operations.
      (b)
Excludes Sabine Mining.

The System construction program is reviewed continuously and is revised from time to time in response to changes in estimates of customer demand, business and economic conditions, the cost and availability of capital, environmental requirements and other factors. Changes in construction schedules and costs, and in estimates and projections of needs for additional facilities, as well as variations from currently anticipated levels of net earnings, Federal income and other taxes, and other factors affecting cash requirements, may increase or decrease the estimated capital requirements for the System’s construction program.

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 generating plants and costs of replacement power. Unless allowed to be recovered through rates, future losses or liabilities which are not completely insured could have a material adverse effect on results of operations and the financial condition 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.
 
 
39
 
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.                  REMOVED AND RESERVED

EXECUTIVE OFFICERS OF THE REGISTRANTS

AEP.   The following persons are, or may be deemed, executive officers of AEP.  Their ages are given as of February 1, 2011.

Name
 
Age
 
Office (a)
Michael G. Morris
 
64
 
Chairman of the Board and Chief Executive Officer
Nicholas K. Akins
 
50
 
President
Carl L. English
 
64
 
Vice Chairman
D. Michael Miller
 
63
 
Senior Vice President, General Counsel and Secretary
Robert P. Powers
 
56
 
President-AEP Utilities
Brian X. Tierney
 
43
 
Executive Vice President and Chief Financial Officer
Susan Tomasky
 
57
 
President – AEP Transmission

(a)  
All of the executive officers have been employed by AEPSC or System companies in various capacities (AEP, as such, has no employees) for the past five years.  Mr. Akins became an executive officer of AEP in June 2006, Mr. English in August, 2004, Mr. Miller in July 2010, Mr. Powers in October 2001, Mr. Tierney in January 2008 and Ms. Tomasky in January 2000.  All of the above officers are appointed annually for a one-year term by the board of directors of AEP.

APCo, OPCo , PSO and SWEPCo.   The names of the executive officers of APCo, OPCo, PSO and SWEPCo, the positions they hold with these companies, their ages as of February 1, 2011, and a brief account of their business experience during the past five years appear below. The directors and executive officers of APCo, OPCo, PSO and SWEPCo are elected annually to serve a one-year term.

Name
 
Age
 
Position
 
Period
Michael G. Morris (a)(b)
 
64
 
Chairman of the Board, Chief Executive Officer and Director of AEP
 
2004-Present
       
Chairman of the Board, Chief Executive Officer and Director of APCo, OPCo, PSO and SWEPCo
 
2004-Present
Nicholas K. Akins (a)
 
50
 
President of AEP
Executive Vice President of AEP, Vice President
 
2011-Present
 
       
and Director of APCo, OPCo, PSO and SWEPCo
 
2006-Present
       
President and Chief Operating Officer of SWEPCo
 
2004-2006
Carl L. English (a)
 
64
 
Vice Chairman
 
2010 - Present
       
Chief Operating Officer
 
2008-2010
       
President-AEP Utilities of AEP
 
2004-2007
       
Director and Vice President of APCo, OPCo, PSO and SWEPCo
 
2004-Present
D. Michael Miller (c)
 
63
 
Senior Vice President, General Counsel and Secretary of AEP
Deputy General Counsel of AEPSC
Director of APCo, OPCo, PSO and SWEPCo
 
2010-Present
2002-2010
2010-Present
Robert P. Powers (a)
 
56
 
President-AEP Utilities of AEP
 
2008-Present
       
Executive Vice President of AEP
 
2004-2007
       
Director and Vice President of APCo and OPCo
 
2001-Present
       
Director and Vice President of PSO and SWEPCo
 
2008-Present
Brian X. Tierney (a)
 
43
 
Executive Vice President
 
2008-Present
       
Chief Financial Officer
 
2009-Present
       
Director and Vice President of APCo and OPCo
 
2008-Present
 
 
40
 
       
Director and Vice President of PSO and SWEPCo
 
2009-Present
       
Senior Vice President—Commercial Operations of AEPSC
 
2005-2007
Susan Tomasky (a)
 
57
 
President-AEP Transmission
 
2008-Present
       
Executive Vice President of AEP
 
2004-Present
       
Chief Financial Officer of AEP
 
2001-2006
       
Vice President and Director of APCo, OPCo, PSO and SWEPCo
 
2000-Present

(a)
Messrs. Morris, Akins, English, Powers and Tierney and Ms. Tomasky are directors of CSPCo and I&M.
 
(b)
Mr. Morris is a director of Alcoa, Inc. and The Hartford Financial Services Group, Inc.
 
(c)
Mr. Miller is a director of CSPCo.
 

The persons listed below are the Presidents, and therefore are also executive officers, of APCo, OPCo, PSO and SWEPCo, respectively.
 
APCo:
 
Name
 
Age
 
Position
 
Period
Charles R. Patton  
51
  President and Chief Operating Officer of APCo  
2010-Present
        Executive Vice President of AEP  
2009-2010
        Senior Vice President-Regulatory and Public Policy of AEP  
2008-2009
        President and Chief Operating Officer of TCC and TNC  
2004-2008
        Director and Vice President of PSO and SWEPCo   2009-2010
 
OPCo:
Name
 
Age
 
Position
 
Period
Joseph Hamrock
 
47
 
President and Chief Operating Officer of CSPCo and OPCo
 
2008-Present
       
Senior Vice President and Chief Information Officer of AEPSC
 
2003-2007

PSO:
Name
 
Age
 
Position
 
Period
Stuart Solomon
 
49
    President and Chief Operating Officer of PSO     2004-Present

SWEPCo:
Name
 
Age
 
Position
 
Period
 
Venita McCellon-Allen     50    President and Chief Operating Officer of SWEPCo    2010-Present  
         Executive Vice President of AEP    2008-2010  
         Director and Vice President of APCo and OPCo     2009-2010  
         Director and Vice President of PSO and SWEPCo    2008-2009  
         President and Chief Operating Officer of SWEPCo    2006-2008  
          Senior Vice President-Shared Services of AEPSC    2004-2006  
         Director of APCo, OPCo and SWEPCo     2004-2006  
 
41
 

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 2010 Annual Report.

APCo, CSPCo, 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 2008, 2009 and 2010 are incorporated by reference to the material under Statements of Changes in Common Shareholder’s Equity and Comprehensive Income (Loss) and Note 14 to the consolidated financial statements entitled Financing Activities under the heading Dividend Restrictions in the 2010 Annual Reports.

During the quarter ended December 31, 2010, 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

CSPCo and I&M .   Omitted pursuant to Instruction I(2)(a).

AEP, APCo, OPCo , PSO and SWEPCo .  The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the 2010 Annual Reports.

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

CSPCo and I&M .  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 Financial Discussion and Analysis in the 2010 Annual Reports.

AEP, APCo, OPCo , PSO and SWEPCo .  The information required by this item is incorporated herein by reference to the material under Management’s Financial Discussion and Analysis in the 2010 Annual Reports .

ITEM 7A.                          QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo . The information required by this item is incorporated herein by reference to the material under Management’s Financial Discussion and Analysis—Quantitative and Qualitative Disclosures about Market and Credit Risk   in the 2010 Annual Reports.

ITEM 8.                      FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA

AEP, APCo, CSPCo, 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.

 
42
 
ITEM 9.                      CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo.        None.

ITEM 9A.                      CONTROLS AND PROCEDURES

During 2010, management, including the principal executive officer and principal financial officer of each of American Electric Power Company, Inc., Appalachian Power Company, Columbus Southern 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 Registrants 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, 2010, 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.

There have been no changes 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 of 2010 that materially affected, or are reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

Management is required to assess and report on the effectiveness of its internal control over financial reporting as of December 31, 2010. As a result of that assessment, management determined that there were no material weaknesses as of December 31, 2010 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 2010 Annual Report of each Registrant.

ITEM 9B.                      OTHER INFORMATION

None.
 
 
43
 
PART III

ITEM 10.                      DIRECTORS, EXECUTIVE OFFICERS
AND CORPORATE GOVERNANCE

CSPCo and I&M . 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 2011 Annual Meeting of Shareholders 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 2011 annual meeting of shareholders.

APCo, OPCo, PSO and SWEPCo:

Directors and Executive Officers.    Certain of the information called for in this Item 10, including the information relating to directors, is incorporated herein by reference to the definitive information statement for each company (which will be filed with the SEC under the Exchange Act) relating to 2011 Annual Meeting of Shareholders under the captions “Election of Directors” and “Director Nomination Process.”

Audit Committee.   Each of APCo, OPCo, PSO and SWEPCo is a controlled subsidiary of AEP and does not have a separate audit committee.

Code of Ethics.   AEP’s Principles of Business Conduct is the code of ethics that applies to the Chief Executive Officer, Chief Financial Officer and principal accounting officer of  APCo, OPCo, PSO and SWEPCo The discussion of AEP’s Principles of Business Conduct above is incorporated herein by reference.  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 the Chief Executive Officer, Chief Financial Officer or principal accounting officer of APCo, OPCo, PSO and SWEPCo, as applicable, that company will disclose the nature of such amendment or waiver on AEP’s website, www.aep.com , or in a report on Form 8-K.
 
 
44
 
ITEM 11.                      EXECUTIVE COMPENSATION

CSPCo and I&M .   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 2011 Annual Meeting including under the captions “Compensation Discussion and Analysis,” “Executive Compensation” and “Director Compensation”. The information set forth under the subcaption “Human Resources 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.

APCo , OPCo , PSO and SWEPCO .  Certain of the information called for in this Item 11 is incorporated herein by reference to the definitive information statement for each company (which will be filed with the SEC under the Exchange Act) relating to 2011 Annual Meeting of Shareholders including under the captions “Compensation Discussion and Analysis,” “Executive Compensation” and “Director Compensation”. The information set forth under the subcaption “Human Resources 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.

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

CSPCo and I&M. 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 2011 Annual Meeting of Shareholders under the caption “Share Ownership of Certain Beneficial Owners and Management" and "Share Ownership of Directors and Executive Officers" .

APCo , OPCo , PSO and SWEPCO . The information relating to Security Ownership of Certain Beneficial Owners is incorporated herein by reference to the definitive information statement for each company (which will be filed with the SEC under the Exchange Act) relating to the 2011 Annual Meeting under the caption “Share Ownership of Certain Beneficial Owners and Management" and "Share Ownership of Directors and Executive Officers".
 
 
45
 
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, 2010:

 
 
 
 
 
Plan Category
 
 
Number of securities to be issued upon exercise of outstanding options warrants and rights
(a)
 
 
Weighted average exercise price of outstanding options, warrants and rights
(b)
 
 
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))(2)
(c)
Equity compensation plans approved by security holders(1)
 
 
1,557,813
 
$32.88
 
18,836,851
Equity compensation plans not approved by security holders
 
0
 
0
 
0
Total
 
1,557,813
 
$32.88
 
18,836,851

 
(1) Consists of shares to be issued upon exercise of outstanding options granted under the Amended and  Restated American Electric Power System Long-Term Incentive Plan.
 
(2) 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 1,185,633 higher if equity compensation that is paid in cash were not deducted from this column.
 
ITEM 13.                      CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

CSPCo and I&M :   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 2011 Annual Meeting under the captions “Transactions with Related Persons” and “Director Independence.”

APCo , OPCo , PSO and SWEPCo:      Certain Relationships and Related Transactions.   There were no related person transactions involving APCo, OPCo, PSO or SWEPCo.  All of those companies' directors are not independent by virtue of being directors, officers or employees of AEP or  APCo, OPCo, PSO or SWEPCo.

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 2011 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.”

APCo , OPCo , PSO and SWEPCo .  The information called for by this Item 14 is incorporated herein by reference to the definitive information statement for each company (which will be filed with the SEC under the Exchange Act) relating to the 2011 Annual Meeting under the captions “Independent Registered Public Accounting Firm,” and “AEP's Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of the Independent Auditor.”
 
 
46
 
CSPCo and I&M.

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 2011 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, 2009 and 2010, 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.

 
CSPCo
I&M
 
2010
2009
2010
2009
Audit Fees
$871,146
$1,038,130
$1,393,624
$1,612,867
Audit-Related Fees
6,500
25,994
6,500
37,851
Tax Fees
9,000
25,536
12,000
39,304
TOTAL
$886,646
$1,089,660
$1,412,124
$1,690,022

 
 
47
 
 PART IV

ITEM 15.                      EXHIBITS, FINANCIAL STATEMENT SCHEDULES

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

 
Page
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, 2010, 2009 and 2008; Consolidated Balance Sheets as of December 31, 2010 and 2009; Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008; Consolidated Statements of Changes in Equity and Comprehensive Income (Loss) for the years ended December 31, 2010, 2009 and 2008; Notes to Consolidated Financial Statements.
 
APCo, CSPCo and I&M:
 
Consolidated Statements of Income for the years ended December 31, 2010, 2009 and 2008; Consolidated Statements of Changes in Common Shareholder’s Equity and Comprehensive Income (Loss) for the years ended December 31, 2010, 2009 and 2008; Consolidated Balance Sheets as of December 31, 2010 and 2009; Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008; Notes to Financial Statements of Registrant Subsidiaries; Report of Independent Registered Public Accounting Firm.
 
OPCo and SWEPCo:
 
Consolidated Statements of Income for the years ended December 31, 2010, 2009 and 2008; Consolidated Statements of Changes in Equity and Comprehensive Income (Loss) for the years ended December 31, 2010, 2009 and 2008; Consolidated Balance Sheets as of December 31, 2010 and 2009; Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008; Notes to Financial Statements of Registrant Subsidiaries; Report of Independent Registered Public Accounting Firm.
 
PSO:
 
Statements of Operations for the years ended December 31, 2010, 2009 and 2008; Statements of Changes in Common Shareholder’s Equity and Comprehensive Income (Loss) for the years ended December 31, 2010, 2009 and 2008; Balance Sheets as of December 31, 2010 and 2009; Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008; Notes to Financial Statements of Registrant Subsidiaries; Report of Independent Registered Public Accounting Firm.
 
   2.    Financial Statement Schedules:
 
         Financial Statement Schedules are listed in the Index to 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, CSPCo, 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

 
48
 
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, 2011

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 /   Michael G. Morris
 
Chairman of the Board,
 
February 25, 2011
(Michael G. Morris)
 
Chief Executive Officer and Director
   
         
         
(ii)           Principal Financial Officer:
       
         
/s/    Brian X. Tierney
 
Executive Vice President and
 
February 25, 2011
(Brian X. Tierney)
 
Chief Financial Officer
   
         
(iii)           Principal Accounting Officer:
       
         
/s/    Joseph M. Buonaiuto
 
Senior Vice President, Controller and
 
February 25, 2011
(Joseph M. Buonaiuto)
 
Chief Accounting Officer
   
         
(iv)           A Majority of the Directors:
       
         
* E. R. Brooks
       
* Donald M. Carlton
       
* James F. Cordes
       
*Ralph D. Crosby, Jr.
       
* Linda A. Goodspeed
       
*T homas E. H oaglin
       
* Lester A. Hudson, Jr.
       
*Lionel L. Nowell, III
       
*Richard L. Sandor
       
* Kathryn D. Sullivan
       
*Sara Martinez Tucker
       
*John F. Turner
       
         
           
*By:
/s/    Brian X. Tierney
     
February 25, 2011
 
(Brian X. Tierney, Attorney-in-Fact)
       

 
49
 

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
 
Columbus Southern Power Company
 
Ohio Power Company
 
Public Service Company of Oklahoma
 
Southwestern Electric Power Company

 
By:
/s/    Brian X. Tierney
   
(Brian X. Tierney, Vice President
and Chief Financial Officer)

Date: February 25, 2011

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 /   Michael G. Morris
 
Chairman of the Board,
 
February 25, 2011
(Michael G. Morris)
 
Chief Executive Officer and Director
   
         
(ii)           Principal Financial Officer:
       
         
/s/    Brian X. Tierney
 
Vice President,
 
February 25, 2011
(Brian X. Tierney)
 
Chief Financial Officer and Director
   
         
(iii)           Principal Accounting Officer:
       
         
/s/    Joseph M. Buonaiuto
 
Controller and
 
February 25, 2011
(Joseph M. Buonaiuto)
 
Chief Accounting Officer
   
         
(iv)           A Majority of the Directors:
       
         
*Nicholas K. Akins
       
*Carl L. English
       
*D. Michael Miller
       
*Robert P. Powers
       
*Barbara D. Radous
       
*Susan Tomasky
       
*Dennis E. Welch
       
         
*By:
/s/    Brian X. Tierney
     
February 25, 2011
 
(Brian X. Tierney, Attorney-in-Fact)
       

 
50
 

 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 Vice President
and Chief Financial Officer)

Date: February 25, 2011

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 /   Michael G. Morris
 
Chairman of the Board,
 
February 25, 2011
(Michael G. Morris)
 
Chief Executive Officer and Director
   
         
(ii)           Principal Financial Officer:
       
         
/s/    Brian X. Tierney
 
Vice President,
 
February 25, 2011
(Brian X. Tierney)
 
Chief Financial Officer and Director
   
         
(iii)           Principal Accounting Officer:
       
         
/s/    Joseph M. Buonaiuto
 
Controller and
 
February 25, 2011
(Joseph M. Buonaiuto)
 
Chief Accounting Officer
   
         
(iv)           A Majority of the Directors:
       
         
*Nicholas K. Akins
       
*Sarah L. Bodner
       
*Paul Chodak, III
       
*J. Edward Ehler
       
*Carl L. English
       
*Allen R. Glassburn
       
*scott m. krawec
       
*Daniel V. Lee
       
*Marc E. Lewis
       
*Robert P. Powers
       
*Susan Tomasky
       
         
*By:
/s/    Brian X. Tierney
     
February 25, 2011
 
(Brian X. Tierney, Attorney-in-Fact)
       

 
51
 


INDEX TO FINANCIAL STATEMENT SCHEDULES

 
Page
   
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
     Schedule I — Condensed Notes to Condensed Financial Information
S-3
   
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
 
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
     Schedule II — Valuation and Qualifying Accounts and Reserves
 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
     Schedule II — Valuation and Qualifying Accounts and Reserves
 
OHIO POWER COMPANY CONSOLIDATED
     Schedule II — Valuation and Qualifying Accounts and Reserves
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
     Schedule II — Valuation and Qualifying Accounts and Reserves
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
     Schedule II — Valuation and Qualifying Accounts and Reserves
 

 
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, 2010 and 2009, and for each of the three years in the period ended December 31, 2010, and the Company's internal control over financial reporting as of December 31, 2010, and have issued our reports thereon dated February 25, 2011 (which report on the consolidated financial statements expresses an unqualified opinion and includes an explanatory paragraph relating to the adoption of a new accounting pronouncement in 2010); such consolidated financial statements and our reports are included in the Company’s 2010 Annual Report (filed as Exhibit 13 to the 2010 Annual Report on Form 10-K of American Electric Power Company, Inc.) 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, 2011
 
 

 
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
We have audited the financial statements of Appalachian Power Company and subsidiaries, Columbus Southern Power Company and subsidiaries, Indiana Michigan Power Company and subsidiaries, Ohio Power Company Consolidated, Public Service Company of Oklahoma and Southwestern Electric Power Company Consolidated (collectively, the “Companies”) as of December 31, 2010 and 2009, and for each of the three years in the period ended December 31, 2010, and have issued our reports thereon dated February 25, 2011 (which report on the financial statements of Southwestern Electric Power Company Consolidated expresses an unqualified opinion and includes an explanatory paragraph relating to the adoption of a new accounting pronouncement in 2010); such financial statements and our reports are included in the Companies' 2010 Annual Reports (filed as Exhibit 13 to the 2010 Annual Reports on Form 10-K of Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company) and are incorporated herein by reference.  Our audits also included the financial statement schedules 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, 2011
 

 
S-2
 


SCHEDULE I
 
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
 
CONDENSED FINANCIAL INFORMATION
 
CONDENSED STATEMENTS OF INCOME
 
For the Years Ended December 31, 2010, 2009 and 2008
 
(in millions, except per-share and share amounts)
 
 
 
 
   
 
   
 
 
 
 
2010
   
2009
   
2008
 
REVENUES
 
 
   
 
   
 
 
Affiliated Revenues
  $ 4     $ 2     $ 1  
 
                       
EXPENSES
                       
Other Operation
    54       18       15  
 
                       
OPERATING LOSS
    (50 )     (16 )     (14 )
 
                       
Other Income (Expense):
                       
Interest Income
    22       45       77  
Interest Expense
    (52 )     (84 )     (112 )
 
                       
LOSS BEFORE EQUITY EARNINGS
    (80 )     (55 )     (49 )
 
                       
Equity Earnings of Unconsolidated Subsidiaries
    1,291       1,412       1,429  
 
                       
NET INCOME
  $ 1,211     $ 1,357     $ 1,380  
 
                       
WEIGHTED AVERAGE NUMBER OF BASIC AEP
                       
COMMON SHARES OUTSTANDING
    479,373,306       458,677,534       402,083,847  
 
                       
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE
                       
TO AEP COMMON SHAREHOLDERS
  $ 2.53     $ 2.96     $ 3.43  
 
                       
WEIGHTED AVERAGE NUMBER OF DILUTED AEP
                       
COMMON SHARES OUTSTANDING
    479,601,442       458,982,292       403,640,708  
 
                       
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE
                       
TO AEP COMMON SHAREHOLDERS
  $ 2.53     $ 2.96     $ 3.42  
 
                       
See Condensed Notes to Condensed Financial Information.
 

 
S-3
 


SCHEDULE I
 
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
 
CONDENSED FINANCIAL INFORMATION
 
CONDENSED BALANCE SHEETS
 
ASSETS
 
December 31, 2010 and 2009
 
(in millions)
 
 
 
 
 
2010
   
2009
 
CURRENT ASSETS
 
 
   
 
 
Cash and Cash Equivalents
  $ 231     $ 233  
Other Temporary Investments
    99       33  
Advances to Affiliates
    556       257  
Accounts Receivable:
               
   General
    18       27  
   Affiliated Companies
    113       11  
       Total Accounts Receivable
    131       38  
Prepayments and Other Current Assets
    7       7  
TOTAL CURRENT ASSETS
    1,024       568  
 
               
PROPERTY, PLANT AND EQUIPMENT
               
General
    2       2  
Total Property, Plant and Equipment
    2       2  
Accumulated Depreciation and Amortization
    2       2  
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET
    -       -  
 
               
OTHER NONCURRENT ASSETS
               
Investments in Unconsolidated Subsidiaries
    14,297       13,861  
Affiliated Notes Receivable
    295       575  
Deferred Charges and Other Noncurrent Assets
    70       70  
TOTAL OTHER NONCURRENT ASSETS
    14,662       14,506  
 
               
TOTAL ASSETS
  $ 15,686     $ 15,074  
 
               
See Condensed Notes to Condensed Financial Information.
               

 
S-4
 


SCHEDULE I
 
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
 
CONDENSED FINANCIAL INFORMATION
 
CONDENSED BALANCE SHEETS
 
LIABILITIES AND EQUITY
 
December 31, 2010 and 2009
 
(dollars in millions)
 
 
 
 
 
2010
   
2009
 
CURRENT LIABILITIES
 
 
 
Advances from Affiliates
  $ 295     $ 289  
Accounts Payable:
               
General
    5       -  
Affiliated Companies
    544       460  
Long-term Debt Due Within One Year
    -       490  
Short Term Debt
    650       119  
Accrued Interest
    2       11  
Other Current Liabilities
    2       4  
TOTAL CURRENT LIABILITIES
    1,498       1,373  
 
               
NONCURRENT LIABILITIES
               
Long-term Debt
    552       544  
Deferred Credits and Other Noncurrent Liabilities
    14       17  
TOTAL NONCURRENT LIABILITIES
    566       561  
 
               
TOTAL LIABILITIES
    2,064       1,934  
 
               
 
               
COMMON SHAREHOLDERS' EQUITY
               
Common Stock – Par Value – $6.50 Per Share:
               
 
 
2010
   
2009
                 
Shares Authorized
    600,000,000       600,000,000                  
Shares Issued
    501,114,881       498,333,265                  
(20,307,725 shares and 20,278,858 shares were held in treasury at December 31, 2010
               
    and 2009, respectively)
    3,257       3,239  
Paid-in Capital
    5,904       5,824  
Retained Earnings
    4,842       4,451  
Accumulated Other Comprehensive Income (Loss)
    (381 )     (374 )
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY
    13,622       13,140  
 
               
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY
  $ 15,686     $ 15,074  
 
               
See Condensed Notes to Condensed Financial Information.
               

 
S-5
 


SCHEDULE I
 
AMERICAN ELECTRIC POWER COMPANY, INC. (Parent)
 
CONDENSED FINANCIAL INFORMATION
 
CONDENSED STATEMENTS OF CASH FLOWS
 
For the Years Ended December 31, 2010, 2009 and 2008
 
(in millions)
 
 
 
 
   
 
   
 
 
 
 
2010
   
2009
   
2008
 
OPERATING ACTIVITIES
 
 
   
 
   
 
 
Net Income
  $ 1,211     $ 1,357     $ 1,380  
Adjustments to Reconcile Net Income to Net Cash Flows
                       
   from Operating Activities:
                       
   Equity Earnings of Unconsolidated Subsidiaries
    (1,291 )     (1,412 )     (1,429 )
   Cash Dividend Received from Unconsolidated Subsidiaries
    854       530       383  
   Change in Other Noncurrent Assets
    -       5       (3 )
   Change in Other Noncurrent Liabilities
    14       6       44  
   Changes in Certain Components of Working Capital:
                       
     Accounts Receivable, Net
    (93 )     14       (20 )
     Accounts Payable
    89       29       1  
     Other Current Assets
    -       -       2  
     Other Current Liabilities
    (12 )     (3 )     (4 )
Net Cash Flows from Operating Activities
    772       526       354  
 
                       
INVESTING ACTIVITIES
                       
Purchases of Investment Securities
    (333 )     (66 )     (869 )
Sales of Investment Securities
    267       36       935  
Change in Advances to Affiliates, Net
    (299 )     1,441       (1,110 )
Capital Contributions to Unconsolidated Subsidiaries
    (6 )     (1,154 )     (481 )
Issuance of Notes Receivable to Affiliated Companies
    (20 )     (25 )     -  
Repayments of Notes Receivable from Affiliated Companies
    300       5       5  
Other Investing Activities
    -       1       -  
Net Cash Flows from (Used for) Investing Activities
    (91 )     238       (1,520 )
 
                       
FINANCING ACTIVITIES
                       
Issuance of Common Stock, Net
    93       1,728       159  
Issuance of Long-term Debt
    -       -       305  
Commercial Paper and Credit Facility Borrowings
    466       -       1,969  
Change in Short-term Debt, Net
    80       119       (659 )
Retirement of Long-term Debt
    (490 )     -       -  
Change in Advances from Affiliates, Net
    6       (3 )     288  
Commercial Paper and Credit Facility Repayments
    (15 )     (1,969 )     -  
Dividends Paid on Common Stock
    (820 )     (753 )     (660 )
Other Financing Activities
    (3 )     (4 )     (1 )
Net Cash Flows from (Used for) Financing Activities
    (683 )     (882 )     1,401  
 
                       
Net Increase (Decrease) in Cash and Cash Equivalents
    (2 )     (118 )     235  
Cash and Cash Equivalents at Beginning of Period
    233       351       116  
Cash and Cash Equivalents at End of Period
  $ 231     $ 233     $ 351  
 
                       
See Condensed Notes to Condensed Financial Information.
                       

 
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, 2010.  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.  The AEP System’s current consolidated federal income tax is allocated to the 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 2010 Annual Reports.

3.   FINANCING ACTIVITIES

Long-term Debt
 
 
 
 
 
 
 
 
 
Interest Rate at
 
 
 
Outstanding at
 
 
December 31,
 
Interest Rate Ranges at December 31,
 
December 31,
Type of Debt and Maturity
 
2010 
 
2010 
 
2009 
 
2010 
 
2009 
 
 
 
 
 
 
 
 
(in millions)
Senior Unsecured Notes
 
 
 
 
 
 
 
 
 
 
 
 
 
2010-2015
 
5.25%
 
5.25%
 
5.25%-5.375%
 
$
 243 
 
$
 733 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Junior Subordinated Debentures
 
 
 
 
 
 
 
 
 
 
 
 
 
2063 
 
8.75%
 
8.75%
 
8.75%
 
 
 315 
 
 
 315 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unamortized Discount (net)
 
 
 
 
 
 
 
 
 (6)
 
 
 (14)
Total Long-term Debt Outstanding
 
 
 
 
 
 
 
 
 552 
 
 
 1,034 
Less Portion Due Within One Year
 
 
 
 
 
 
 
 
 - 
 
 
 490 
Long-term Portion
 
 
 
 
 
 
 
$
 552 
 
$
 544 

Long-term debt outstanding at December 31, 2010 is payable as follows:

 
 
 
 
 
 
 
 
 
 
 
After
 
 
 
2011 
 
2012 
 
2013 
 
2014 
 
2015 
 
2015 
 
Total
 
(in millions)
Principal Amount
$
 - 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 243 
 
$
 315 
 
$
 558 
Unamortized Discount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (6)
Total Long-term Debt Outstanding
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
at December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$
 552 

 
S-8
 
Short-term Debt
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Parent's outstanding short-term debt was as follows:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31,
 
 
 
 
2010 
 
2009 
 
 
 
 
Outstanding
 
Weighted Average
 
Outstanding
 
Weighted Average
 
Type of Debt
Amount
Interest Rate
 
Amount
Interest Rate
 
 
 
(in millions)
 
 
 
 
(in millions)
 
 
 
 
Commercial Paper
 
$
 650 
 
 0.52 
%
 
$
 119 
 
 0.26 
%
 
Total Short-term Debt
 
$
 650 
 
 
 
 
$
 119 
 
 
 

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 $1 million, $3 million and $9 million for the years ended December 31, 2010, 2009 and 2008, 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 $2 million, $11 million and $37 million for the years ended December 31, 2010, 2009 and 2008, 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 $18 million, $29 million and $28 million for the years ended December 31, 2010, 2009 and 2008, 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 thousands)
Deducted from Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated Provision for Uncollectible
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Accounts:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2010
 
$
 37,399 
 
$
 36,699 
 
$
 (1,036)
 
$
 31,507 
 
$
 41,555 
 
 
Year Ended December 31, 2009
 
 
 42,388 
 
 
 31,867 
 
 
 (2,850)
 
 
 34,006 
 
 
 37,399 
 
 
Year Ended December 31, 2008
 
 
 52,046 
 
 
 27,598 
 
 
 365 
 
 
 37,621 
 
 
 42,388 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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, 2010
 
$
 5,408 
 
$
 6,573 
 
$
 292 
 
$
 5,606 
 
$
 6,667 
 
 
Year Ended December 31, 2009
 
 
 6,176 
 
 
 4,198 
 
 
 (137)
 
 
 4,829 
 
 
 5,408 
 
 
Year Ended December 31, 2008
 
 
 13,948 
 
 
 3,477 
 
 
 289 
 
 
 11,538 
 
 
 6,176 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Recoveries offset by reclasses to other liabilities.
(b)
Uncollectible accounts written off.

CSPCo
 
 
 
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, 2010
 
$
 3,481 
 
$
 16 
 
$
 (404)
 
$
 1,509 
 
$
 1,584 
 
 
Year Ended December 31, 2009
 
 
 2,895 
 
 
 1,362 
 
 
 (775)
 
 
 1 
 
 
 3,481 
 
 
Year Ended December 31, 2008
 
 
 2,563 
 
 
 332 
 
 
 - 
 
 
 - 
 
 
 2,895 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Recoveries offset by reclasses to other liabilities.
(b)
Uncollectible accounts written off.

 
S-10
 
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, 2010
 
$
 2,265 
 
$
 (139)
(c)
$
 (424)
 
$
 10 
 
$
 1,692 
 
 
Year Ended December 31, 2009
 
 
 3,310 
 
 
 78 
 
 
 (783)
 
 
 340 
 
 
 2,265 
 
 
Year Ended December 31, 2008
 
 
 2,711 
 
 
 599 
 
 
 - 
 
 
 - 
 
 
 3,310 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Recoveries offset by reclasses to other liabilities.
(b)
Uncollectible accounts written off.
(c)
Recoveries on previous reserve balance.

OPCo
 
 
 
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, 2010
 
$
 2,665 
 
$
 43 
 
$
 (524)
 
$
 - 
 
$
 2,184 
 
 
Year Ended December 31, 2009
 
 
 3,586 
 
 
 16 
 
 
 (933)
 
 
 4 
 
 
 2,665 
 
 
Year Ended December 31, 2008
 
 
 3,396 
 
 
 191 
 
 
 - 
 
 
 1 
 
 
 3,586 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Recoveries offset by reclasses to other liabilities.
(b)
Uncollectible accounts written off.

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, 2010
 
$
 304 
 
$
 709 
 
$
 - 
 
$
 42 
 
$
 971 
 
 
Year Ended December 31, 2009
 
 
 20 
 
 
 284 
 
 
 - 
 
 
 - 
 
 
 304 
 
 
Year Ended December 31, 2008
 
 
 - 
 
 
 20 
 
 
 - 
 
 
 - 
 
 
 20 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Recoveries on accounts previously written off.
(b)
Uncollectible accounts written off.

 
S-11
 
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, 2010
 
$
 64 
 
$
 400 
 
$
 166 
 
$
 42 
 
$
 588 
 
 
Year Ended December 31, 2009
 
 
 135 
 
 
 - 
 
 
 - 
 
 
 71 
 
 
 64 
 
 
Year Ended December 31, 2008
 
 
 143 
 
 
 - 
 
 
 - 
 
 
 8 
 
 
 135 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Recoveries on accounts previously written off.
(b)
Uncollectible accounts written off.

 
S-12
 

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:
REGISTRANT: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 April 28, 2009.
 
2009 Form 10-K, Ex 3(b)
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)
 
Purchase Agreement dated as of March 8, 2005, between AEP and Merrill Lynch International.
 
Form 10-Q, Ex 4(a), March 31, 2005
4(c)
 
Junior Subordinated Indenture dated as of March 1, 2008 between AEP and The Bank of New York as Trustee.
 
Registration Statement 333-156387, Ex 4(c)(d)
4(d)
 
Second Amended and Restated $1.5 Billion Credit Agreement, dated as of March 31, 2008, 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.
 
Form 10-Q, Ex 10(a) September 30, 2008
4(e)
 
Second Amended and Restated $1.5 Billion Credit Agreement, dated as of March 31, 2008, among AEP, the banks, financial institutions and other institutional lenders listed on the signature pages thereof, and Barclays Bank plc as Administrative Agent.
 
Form 10-Q, Ex 10(b) September 30, 2008
4(f)
 
$650 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(c) September 30, 2008
4(g)
 
Amendment, dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(d) September 30, 2008
4(h)
 
$350 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10 (e) September 30, 2008
4(i)
 
Amendment, dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(f) September 30, 2008
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    Form 10-Q, Ex 10(b), March 31, 2006 

 
E-1
 


Exhibit Designation  
 
Nature of Exhibit
 
 
Previously Filed as Exhibit to:
 
 
 PSO, SWEPCo and AEPSC, Issued on February 10, 2006, Effective May 1, 2006.
 
 
10(c)
 
Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent, as amended.
 
1985 Form 10-K, Ex 10(b)
1988 Form 10-K, Ex 10(b)(2)
10(d)
 
Restated and Amended Transmission Coordination Agreement, dated April 15, 2002, among PSO, SWEPCo,  TNC and AEPSC.
 
2009 Form 10-K, Ex 10(d)
10(e)(1)
 
Amended and Restated Operating Agreement dated as of June 2, 1997, of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power Company.
 
2004 Form 10-K, Ex 10(e)(1)
10(e)(2)
 
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)(3)
 
Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power Company.
 
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.
 
Form 8-K, Ex 10.1 dated October 9, 2007
†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)
 
AEP Stock Unit Accumulation Plan for Non-Employee Directors, as amended.
 
2003 Form 10-K, Ex 10(k)(2)
†10(k)(1)
 
First Amendment to AEP Stock Unit Accumulation Plan for Non-Employee Directors dated as of February 9, 2007.
 
2006 Form 10-K, Ex 10(j)(2)(A)
†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).
   
†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)
†10(m)(1)
 
Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 15, 2003.
 
2003 Form 10-K, Ex 10(m)(1)
†10(m)(1)(A)
 
Amendment to Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 9, 2008.
 
2008 Form 10-K, Ex 10(m)(1)(A)
†10(m)(2)
 
Memorandum of agreement between Susan Tomasky and AEPSC dated January 3, 2001.
 
2000 Form 10-K, Ex 10(s)
†10(m)(3)
 
Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers.
 
2002 Form 10-K, Ex 10(m)(4)
†10(m)(3)(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(m)(4)
 
Letter Agreement dated June 9, 2004 between AEPSC and Carl English.
 
Form 10-Q, Ex 10(b), September 30, 2004
†10(n)
 
AEP System Senior Officer Annual Incentive Compensation Plan, amended and restated effective December 13, 2006.
 
 
Form 8-K, Ex 10.1 dated April 25, 2007
†10(o)(1)
 
AEP System Survivor Benefit Plan, effective January 27, 1998.
 
Form 10-Q, Ex 10, September 30, 1998

 
E-2
 

  Exhibit Designation  
 
Nature of Exhibit
 
 
Previously Filed as Exhibit to:
†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)(1)(B)
 
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(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(s)
 
AEP Change In Control Agreement, effective November 1, 2009.
 
2009 Form 10-K, Ex 10(s)
*†10(t)(1)
 
Amended and Restated AEP System Long-Term Incentive Plan.
 
Form 10-Q, Ex 10, March 31, 2010
†10(t)(2)
 
Form of Performance Share Award Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.
 
Form 10-Q, Ex 10(c), September 30, 2004
†10(t)(3)
 
Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.
 
Form 10-Q, Ex 10(a), March 31, 2005
†10(t)(3)(A)
 
Amendment to Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.
 
2008 Form 10-K, Ex 10(t)(3)(A)
†10(u)
 
AEP System Stock Ownership Requirement Plan Amended and Restated Effective January 1, 2010.
 
2010 Form 10-K, Ex 10(u)
†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)
*12
 
Statement re: Computation of Ratios.
   
*13
 
Copy of those portions of the AEP 2010 Annual Report (for the fiscal year ended December 31, 2010) 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
   
101.SCH
 
XBRL Taxonomy Extension Schema
   
101.CAL
 
XBRL Taxonomy Extension Calculation
   
101.DEF
 
XBRL Taxonomy Extension Definition
   
101.LAB
 
XBRL Taxonomy Extension Labels
   
101.PRE
 
XBRL Taxonomy Extension Presentation
   
REGISTRANT:APCo‡File No. 1-3457
   
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)

 
E-3
 

Exhibit Designation  
 
Nature of Exhibit
 
 
Previously Filed as Exhibit to:
 
 
 
 
 
 
 
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)
4(b)
 
Company Order and Officer’s Certificate to The Bank of New York Mellon, dated May 24, 2010 establishing terms of 3.40% Senior Notes due 2015.
 
Form 8-K, Ex 4(a) dated May 24, 2010
4(c)
 
$650 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex10(c) September 30, 2008
4(d)
 
Amendment, dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(d) September 30, 2008
4(e)
 
$350 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(e) September 30, 2008
4(f)
 
Amendment, dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(f) September 30, 2008
10(a)(1)
 
Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended.
 
Registration Statement No. 2-60015, Ex 5(a)
Registration Statement No. 2-63234, Ex 5(a)(1)(B) Registration Statement No 2-66301, Ex 5(a)(1)(C) Registration Statement No. 2-67728, Ex 5(a)(1)(D)
1989 Form 10-K, Ex 10(a)(1)(F)
1992 Form 10-K, Ex 10(a)(1)(B)
10(a)(2)
 
Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended March 13, 2006.
 
2005 Form 10-K, Ex 10(a)(2)
10(a)(3)
 
Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended.
 
Registration Statement No. 2-60015, Ex 5(e)
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, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent, as amended.
 
1985 Form 10-K, Ex 10(b)
1988 Form 10-K, Ex 10(b)(2)
10(d)(1)
 
Amended and Restated Operating Agreement of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power Company.
 
2004 Form 10-K, Ex 10(d)(1)
10(d)(2)
 
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)(3)
 
Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power Company.
 
2004 Form 10-K, Ex 10(d)(3)

 
E-4
 

Exhibit Designation  
 
Nature of Exhibit
 
 
Previously Filed as Exhibit to:
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.
 
Form 8-K, Ex 10.1 dated October 9, 2007
†10(g)
 
AEP System Senior Officer Annual Incentive Compensation Plan amended and restated effective December 13, 2006.
 
Form 8-K, Ex 10.1 dated  April 25, 2007
†10(h)(1)
 
AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2008.
 
2008 Form 10-K, Ex 10(h)(1)
*†10(h)(2)
 
AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2011 (Non-Qualified).
   
†10(h)(3)
 
AEPSC Umbrella Trust for Executives.
 
1993 Form 10-K, Ex 10(g)(3), File No. 1-3525
†10(h)(3)(A)
 
First Amendment to AEPSC Umbrella Trust for Executives.
 
2008 Form 10-K, Ex 10(h)(3)(A)
†10(i)
 
Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 15, 2003.
 
2003 Form 10-K, Ex 10(m)(1)
†10(i)(A)
 
Amendment to Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 9, 2008.
 
2008 Form 10-K, Ex 10(i)(A)
†10(i)(2)
 
Memorandum of Agreement between Susan Tomasky and AEPSC dated January 3, 2001.
 
2000 Form 10-K, Ex 10(s), File No. 1-3525
†10(i)(3)
 
Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers.
 
2002 Form 10-K, Ex 10(m)(4)
†10(i)(3)(A)
 
Amendment to Employment Agreement dated December 9, 2008 between AEPSC and Robert P. Powers.
 
2008 Form 10-K, Ex 10(i)(4)(A)
†10(i)(4)
 
Letter Agreement dated June 9, 2004 between AEPSC and Carl English.
 
Form 10-Q, Ex 10(b), September 30, 2004
†10(j)
 
AEP System Senior Officer Annual Incentive Compensation Plan, amended and restated effective December 13, 2006.
 
Form 8-K, Ex 10.1 dated April 25, 2007
†10(k)(1)
 
AEP System Survivor Benefit Plan, effective January 27, 1998.
 
Form 10-Q, Ex 10, September 30, 1998
†10(k)(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(k)(1)(B)
 
Second Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 1, 2008.
 
2008 Form 10-K, Ex 10(k)(1)(B)
†10(l)
 
AEP Change In Control Agreement, effective November 1, 2009.
 
2009 10-K, Ex 10(l)
*†10(m)(1)
 
Amended and Restated AEP System Long-Term Incentive Plan.
 
Form 10-Q, Ex 10, March 31, 2010
†10(m)(2)
 
Form of Performance Share Award Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.
 
Form 10-Q, Ex 10(c), November 5, 2004
†10(m)(3)
 
Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.
 
Form 10-Q, Ex 10(a), March 31, 2005
†10(m)(3)(A)
 
Amendment to Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.
 
2008 Form 10-K, Ex10(m)(3)(A)
†10(n)
 
 AEP System Stock Ownership Requirement Plan Amended and Restated Effective January 1, 2010.
 
2009 Form 10-K, Ex 10(n)
†10(o)
 
Central and South West System Special Executive Retirement Plan Amended and Restated effective January 1, 2009.
 
2008 Form 10-K, Ex 10(n)
†10(p)
 
AEP System Incentive Compensation Deferral Plan Amended and Restated as of January 1, 2008.
 
2008 Form 10-K, Ex 10(o)
†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(q)
  *12   Statement re: Computation of Ratios.    

 
E-5
 
Exhibit Designation  
 
Nature of Exhibit
 
 
Previously Filed as Exhibit to:
*13
 
Copy of those portions of the APCo 2010 Annual Report (for the fiscal year ended December 31, 2010) which are incorporated by reference in this filing.
   
21
 
List of subsidiaries of APCo.
 
2006 Form 10-K, Ex 21, File No. 1-3525
*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.
   
REGISTRANT:CSPCo‡File No. 1-2680
   
3(a)
 
Composite of Amended Articles of Incorporation of CSPCo, dated May 19, 1994.
 
1994 Form 10-K, Ex 3(c)
3(b)
 
Amended Code of Regulations of CSPCo.
 
Form 10-Q, Ex 3(b) June 30, 2008
4(a)
 
Indenture (for unsecured debt securities), dated as of September 1, 1997, between CSPCo 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(b)
 
Indenture (for unsecured debt securities), dated as of February 1, 2003, between CSPCo 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(c)
 
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(d)
 
Company Order and Officer’s Certificate to Deutsche Bank Trust Company Americas, dated March 16, 2010 establishing terms of floating rate notes Series A due 2012.
 
Form 8-K, Ex 4(a) dated March 16, 2010
4(e)
 
$650 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(c) September 30, 2008
4(f)
 
Amendment, dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(d) September 30, 2008
4(g)
 
$350 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
 
Form 10-Q, Ex 10(e) September 30, 2008
4(h)
 
Amendment, dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as
 
Form 10-Q, Ex 10(f) September 30, 2008

 
E-6
 

Exhibit Designation  
 
Nature of Exhibit
 
 
Previously Filed as Exhibit to:
    Administrative Agent.     
10(a)(1)
 
Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended.
 
Registration Statement No. 2-60015, Ex 5(a)
Registration Statement No. 2-63234, Ex 5(a)(1)(B)
Registration Statement No. 2-66301, Ex 5(a)(1)(C)
Registration Statement No. 2-67728, Ex 5(a)(1)(B)
APCo 1989 Form 10-K, Ex 10(a)(1)(F), File No. 1-3457
APCo 1992 Form 10-K, Ex 10(a)(1)(B), File No.1-3457
10(a)(2)
 
Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended March 13, 2006.
 
2005 Form 10-K, Ex 10(a)(2)
10(a)(3)
 
Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended.
 
Registration Statement No. 2-60015, Ex 5(e)
10(b)(1)
 
Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KPCo, OPCo and I&M and 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)(2)
 
Unit Power Agreement, dated March 15, 2007 between AEGCo and CSPCo.
 
2007 Form 10-K, Ex 10(b)(2)
10(c)
 
Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo, and with AEPSC as agent, as amended.
 
1985 Form 10-K, Ex 10(b), File No. 1-3525
1988 Form 10-K, Ex 10(b)(2) File No. 1-3525
10(d)(1)
 
Amended and Restated Operating Agreement of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power Company.
 
2004 Form 10-K, Ex 10(d)(1)
10(d)(2)
 
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)(3)
 
Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power Company.
 
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.
 
Form 8-K, Ex 10.1 dated October 9, 2007
*12
 
Statement re: Computation of Ratios.
   
*13
 
Copy of those portions of the CSPCo 2010 Annual Report (for the fiscal year ended December 31, 2010) which are incorporated by reference in this filing.
   
21
 
List of subsidiaries of CSPCo.
 
2006 Form 10-K, Ex 21, File No. 1-3525
*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.
   
REGISTRANT:                                I&M‡           File No. 1-3570
   
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)

 
E-7
 

 
 
 
Nature of Exhibit
 
 
Previously Filed as Exhibit to:
4(b)
 
Company Order and Officer’s Certificate to The Bank of New York, dated January 15, 2009 establishing terms of 7.00% Senior Notes,  Series I due 2019.
 
Form 8-K, Ex 4(a) dated January 15, 2009
4(c)
 
$650 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex.10(c) September 30, 2008
4(d)
 
Amendment, dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex.10(d) September 30, 2008
4(e)
 
$350 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex.10(e) September 30, 2008
4(f)
 
Amendment, dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex.10(f) September 30, 2008
10(a)(1)
 
Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended.
 
Registration Statement No. 2-60015, Ex 5(a)
Registration Statement No. 2-63234, Ex 5(a)(1)(B)
Registration Statement No. 2-66301, Ex 5(a)(1)(C)
Registration Statement No. 2-67728, Ex 5(a)(1)(D)
APCo 1989 Form 10-K, Ex 10(a)(1)(F), File No. 1-3457
APCo 1992 Form 10-K, Ex 10(a)(1)(B), File No. 1-3457
10(a)(2)
 
Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended, March 13, 2006.
 
2005 Form 10-K, Ex 10(a)(2)
10(a)(3)
 
Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended.
 
Registration Statement No. 2-60015, Ex 5(e)
10(a)(4)
 
Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended.
 
Registration Statement No. 2-60015, Ex 5(c)
Registration Statement No. 2-67728, Ex 5(a)(3)(B)
APCo 1992 Form 10-K, Ex 10(a)(2)(B), File No. 1-3457
10(b)(1)
 
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)(2)
 
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, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent, as amended.
 
 
 
1985 Form 10-K, Ex 10(b), File No. 1-3525
1988 Form 10-K, File No. 1-3525, Ex 10(b)(2)
10(d)(1)
 
Amended and Restated Operating Agreement of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power Company.
 
2004 Form 10-K, Ex 10(d)(1)
10(d)(2)
 
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)(3)
 
Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo,
 
2004 Form 10-K, Ex 10(d)(3)

 
E-8
 

Exhibit Designation  
 
Nature of Exhibit
 
 
Previously Filed as Exhibit to:
 
 
 Kingsport Power Company and Wheeling Power Company.
 
 
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.
 
Form 8-K, Ex 10.1 dated October 9, 2007
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.
   
*13
 
Copy of those portions of the I&M 2010 Annual Report (for the fiscal year ended December 31, 2010) which are incorporated by reference in this filing.
   
21
 
List of subsidiaries of I&M.
 
2006 Form 10-K, Ex 21, File No. 1-3525
*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.
   
REGISTRANT:OPCo‡File No.1-6543
   
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
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)
4(b)
 
Company Order and Officer’s Certificate to Deutsche Bank Trust Company Americas, dated April 5, 2007, establishing terms of Floating Rate Notes, Series B.
 
Form 8-K, Ex 4(a) dated April 5, 2007
4(c)
 
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(d)
 
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(e)
 
$650 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(c) September 30, 2008
4(f)
 
Amendment, dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(d) September 30, 2008
4(g)
 
$350 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M,
 
Form 10-Q, Ex 10(e) September 30, 2008

 
E-9
 
Exhibit Designation  
 
  Nature of Exhibit
 
 
Previously Filed as Exhibit to:
 
 
KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
 
4(h)
 
Amendment, dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(f) September 30, 2008
10(a)(1)
 
Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Energy Research and Development Administration, as amended.
 
Registration Statement No. 2-60015, Ex 5(a)
Registration Statement No. 2-63234, Ex 5(a)(1)(B)
Registration Statement No. 2-66301, Ex 5(a)(1)(C)
Registration Statement No. 2-67728, Ex 5(a)(1)(D)
APCo 1989 Form 10-K, Ex 10(a)(1)(F), File No. 1-3457
APCo 1992 Form 10-K, Ex 10(a)(1)(B), File No. 1-3457
10(a)(2)
 
Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended, March 13, 2006.
 
2005 Form 10-K, Ex 10(a)(2)
10(a)(3)
 
Power Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric Corporation, as amended.
 
Registration Statement No. 2-60015, Ex 5(e)
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, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and with AEPSC as agent.
 
1985 Form 10-K, Ex 10(b), File No. 1-3525
1988 Form 10-K, Ex 10(b)(2), File No. 1-3525
10(d)(1)
 
Amended and Restated Operating Agreement of PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power Company.
 
2004 Form 10-K, Ex 10(d)(1)
10(d)(2)
 
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)(3)
 
Master Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power Company.
 
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.
 
Form 8-K, Item Ex 10.1 dated October 9, 2007
10(g)(1)
 
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)
10(g)(2)
 
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(h)
 
AEP System Senior Officer Annual Incentive Compensation Plan amended and restated effective December 13, 2006.
 
Form 8-K, Ex 10.1 dated  April 25, 2007
†10(i)(1)
 
AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2008.
 
2008 Form 10-K, Ex 10(j)(1)
*†10(i)(2)
 
AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2011. (Non-Qualified).
   
†10(i)(3)
 
AEPSC Umbrella Trust for Executives.
 
1993 Form 10-K, Ex 10(g)(3), File No. 1-3525
†10(i)(3)(A)
 
First Amendment to AEPSC Umbrella Trust for
Executives.
 
2008 Form 10-K, Ex 10(j)(3)(A)

 
E-10
 

Exhibit Designation  
 
Nature of Exhibit
 
 
Previously Filed as Exhibit to:
†10(j)(1)
 
Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 15, 2003.
 
2003 Form 10-K, Ex 10(m)(1)
†10(j)(1)(A)
 
Amendment to Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 9, 2008.
 
2008 Form 10-K, Ex 10(k)(1)(A )
†10(j)(2)
 
Memorandum of agreement between Susan Tomasky and AEPSC dated January 3, 2001.
 
2000 Form 10-K, Ex 10(s), File No. 1-3525
†10(j)(3)
 
Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers.
 
2002 Form 10-K, Ex 10(m)(4)
†10(j)(3)(A)
 
Amendment to Employment Agreement dated December 9, 2008 between AEPSC and Robert P. Powers.
 
2008 Form 10-K, Ex 10(k)(4)(A)
†10(j)(4)
 
Letter Agreement dated June 9, 2004 between AEPSC and Carl English.
 
Form 10-Q, Ex 10(b), September 30, 2004, File No. 1-3525
†10(k)
 
AEP System Senior Officer Annual Incentive Compensation Plan, amended and restated effective December 13, 2006.
 
Form 8-K, Ex 10.1 dated April 25, 2007
†10(l)(1)
 
AEP System Survivor Benefit Plan, effective January 27, 1998.
 
Form 10-Q, Ex 10, September 30, 1998
†10(l)(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(l)(1)(B)
 
Second Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 1, 2008.
 
2008 Form 10-K, Ex 10(m)(1)(B)
†10(m)
 
AEP Change In Control Agreement, effective November 1, 2009.
 
2009 Form 10-K, Ex 10(m)
*†10(n)(1)
 
Amended and Restated AEP System Long-Term Incentive Plan.
 
Form 10-Q, Ex 10, March 31, 2010
†10(o)
 
Form of Performance Share Award Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.
 
Form 10-Q, Ex 10(c), November 5, 2004,
File No. 1-3525
†10(p)(1)
 
Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.
 
Form 10-Q, Ex 10(a), March 31, 2005
†10(p)(1)(A)
 
Amendment to Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.
 
2008 Form 10-K, Ex 10(q)(1)(A)
†10(q)
 
  AEP System Stock Ownership Requirement Plan Amended and Restated Effective January 1, 2010.
 
2009 Form 10-K, Ex 10(q)
†10(r)
 
Central and South West System Special Executive Retirement Plan Amended and Restated effective January 1, 2009.
 
2008 Form 10, Ex 10(s)
†10(s)
 
AEP System Incentive Compensation Deferral Plan Amended and Restated as of January 1, 2008.
 
2008 Form 10, Ex 10(t)
†10(t)
 
AEP System Nuclear Performance Long Term Incentive Compensation Plan dated August 1, 1998.
 
2002 Form 10-K, Ex 10(r)
†10(u)
 
Nuclear Key Contributor Retention Plan Amended and Restated as of January 1, 2008.
 
2008 Form 10, Ex 10(v)
*12
 
Statement re: Computation of Ratios.
   
*13
 
Copy of those portions of the OPCo 2010 Annual Report (for the fiscal year ended December 31, 2010) which are incorporated by reference in this filing.
   
21
 
List of subsidiaries of OPCo.
 
2006 Form 10-K, Ex 21, File No. 1-3525
*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.
   

 
E-11
 

Exhibit Designation  
 
Nature of Exhibit
 
 
Previously Filed as Exhibit to:
REGISTRANT:                                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)
 
$650 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(c) September 30, 2008
4(d)
 
Amendment, dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(d) September 30, 2008
4(e)
 
$350 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(e) September 30, 2008
4(f)
 
Amendment, dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(f) September 30, 2008
10(a)
 
Restated and Amended Operating Agreement, among PSO, SWEPCo and AEPSC, Issued on February 10, 2006, Effective May 1, 2006.
 
Form 10-Q, Ex 10(a), March 31, 2006
10(b)
 
Restated and Amended Transmission Coordination Agreement, dated April 15, 2002, among PSO, SWEPCo,  TNC and AEPSC.
 
 
 
2009 Form 10-K Ex 10(b)
†10(c)
 
AEP System Senior Officer Annual Incentive Compensation Plan amended and restated effective December 13, 2006.
 
Form 8-K, Ex 10.1 dated  April 25, 2007
†10(d)(1)
 
AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2008.
 
2008 Form 10-K, Ex 10(d)(1)
*†10(d)(2)
 
AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2011 (Non-Qualified).
   
†10(d)(3)
 
AEPSC Umbrella Trust for Executives.
 
1993 Form 10-K, Ex 10(g)(3), File No. 1-3525
†10(d)(3)(A)
 
First Amendment to AEPSC Umbrella Trust for Executives.
 
2008 Form 10-K, Ex 10(d)(3)(A)
  †10(e)(1)   Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 15, 2003.   2003 Form 10-K, Ex 10(m)(1)

 
E-12
 

Exhibit Designation  
 
Nature of Exhibit
 
 
Previously Filed as Exhibit to:
†10(e)(1)(A)
 
Amendment to Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 9, 2008.
 
2008 Form 10-K, Ex 10(e)(A)
†10(e)(2)
 
Memorandum of Agreement between Susan Tomasky and AEPSC dated January 3, 2001.
 
2000 Form 10-K, Ex 10(s), File No. 1-3525
†10(e)(3)
 
Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers.
 
2002 Form 10-K, Ex 10(m)(4)
†10(e)(3)(A)
 
Amendment to Employment Agreement dated December 9, 2008 between AEPSC and Robert P. Powers.
 
2008 Form 10-K, Ex 10(e)(4)(A)
†10(e)(4)
 
Letter Agreement dated June 9, 2004 between AEPSC and Carl English.
 
Form 10-Q, Ex 10(b), September 30, 2004
†10(f)
 
AEP System Senior Officer Annual Incentive Compensation Plan, amended and restated effective December 13, 2006.
 
Form 8-K, Ex 10.1 dated April 25, 2007
†10(g)(1)
 
AEP System Survivor Benefit Plan, effective January 27, 1998.
 
Form 10-Q, Ex 10, September 30, 1998
†10(g)(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(g)(1)(B)
 
 Second Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 1, 2008.
 
2008 Form 10-K, Ex 10(g)(1)(B)
†10(h)
 
AEP Change In Control Agreement, effective November 1, 2009.
 
2009 Form 10-K, Ex 10(h)
*†10(i)(1)
 
Amended and Restated AEP System Long-Term Incentive Plan.
 
Form 10-Q, Ex 10, March 31, 2010
†10(i)(2)
 
Form of Performance Share Award Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.
 
Form 10-Q, Ex 10(c), November 5, 2004
†10(i)(3)
 
Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.
 
Form 10-Q, Ex 10(a), March 31, 2005
†10(i)(3)(A)
 
Amendment to Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.
 
2008 Form 10-K, Ex 10(i)(3)(A)
†10(j)
 
AEP System Stock Ownership Requirement Plan Amended and Restated Effective January 1, 2010.
 
2009 Form 10-K, Ex 10(j)
†10(k)
 
Central and South West System Special Executive Retirement Plan Amended and Restated effective January 1, 2009.
 
2008 Form 10-K, Ex 10(j)
†10(l)
 
AEP System Incentive Compensation Deferral Plan Amended and Restated as of January 1, 2008.
 
2008 Form 10-K, Ex 10(k)
†10(m)
 
AEP System Nuclear Performance Long Term Incentive Compensation Plan dated August 1, 1998.
 
2002 Form 10-K, Ex 10(p)
†10(n)
 
Nuclear Key Contributor Retention Plan Amended and Restated as of January 1, 2008.
 
2008 Form 10-K, Ex 10(m)
*12
 
Statement re: Computation of Ratios.
   
*13
 
Copy of those portions of the PSO 2010 Annual Report (for the fiscal year ended December 31, 2010) which are incorporated by reference in this filing.
   
21
 
List of subsidiaries of PSO.
 
2006 Form 10-K, Ex 21, File No. 1-3525
*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.
   

 
E-13
 

Exhibit Designation  
 
Nature of Exhibit
 
 
Previously Filed as Exhibit to:
  REGISTRANT:      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)
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)
 
$650 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(c) September 30, 2008
4(d)
 
Amendment, dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(d) September 30, 2008
4(e)
 
$350 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(e) September 30, 2008
4(f)
 
Amendment, dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
 
Form 10-Q, Ex 10(f) September 30, 2008
10(a)
 
Restated and Amended Operating Agreement, among PSO, TCC, TNC, SWEPCo and AEPSC, Issued on February 10, 2006, Effective May 1, 2006.
 
Form 10-Q, Ex 10(a), March 31, 2006
10(b)
 
Restated and Amended Transmission Coordination Agreement, dated April 15, 2002, among PSO, SWEPCo,  TNC and AEPSC.
 
Form 2009 10-K, Ex 10(b)
†10(c)
 
AEP System Senior Officer Annual Incentive Compensation Plan amended and restated effective December 13, 2006.
 
Form 8-K, Ex 10.1 dated  April 25, 2007
†10(d)(1)
 
AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2008.
 
2008 Form 10-K, Ex 10(d)(1)
*†10(d)(2)
 
AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2011 (Non-Qualified).
   
†10(d)(3)
 
AEPSC Umbrella Trust for Executives.
 
1993 Form 10-K, Ex 10(g)(3), File No. 1-3525
†10(d)(3)(A)
 
First Amendment to AEPSC Umbrella Trust for Executives.
 
2008 Form 10-K, Ex 10(d)(3)(A)
†10(e)(1)
 
Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 15, 2003.
 
2003 Form 10-K, Ex 10(m)(1)

 
E-14
 
   
 
Nature of Exhibit
 
 
Previously Filed as Exhibit to:
†10(e)(1)(A)
 
Amendment to Employment Agreement between AEP, AEPSC and Michael G. Morris dated December 9, 2008.
 
2008 Form 10-K, Ex 10(e)(A)
†10(e)(2)
 
Memorandum of Agreement between Susan Tomasky and AEPSC dated January 3, 2001.
 
2000 Form 10-K, Ex 10(s), File No. 1-3525
†10(e)(3)
 
Employment Agreement dated July 29, 1998 between AEPSC and Robert P. Powers.
 
2002 Form 10-K, Ex 10(m)(4)
†10(e)(3)(A)
 
Amendment to Employment Agreement dated December 9, 2008 between AEPSC and Robert P. Powers.
 
2008 Form 10-K, Ex 10(e)(4)(A)
†10(e)(4)
 
Letter Agreement dated June 9, 2004 between AEPSC and Carl English.
 
Form 10-Q, Ex 10(b), September 30, 2004
†10(f)
 
AEP System Senior Officer Annual Incentive Compensation Plan, amended and restated effective December 13, 2006.
 
Form 8-K, Ex 10.1 dated April 25, 2007
†10(g)(1)
 
AEP System Survivor Benefit Plan, effective January 27, 1998.
 
Form 10-Q, Ex 10, September 30, 1998
†10(g)(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(g)(1)(B)
 
 Second Amendment to AEP System Survivor Benefit Plan, as amended and restated effective January 1, 2008.
 
2008 Form 10-K, Ex 10(g)(1)(B)
†10(h)
 
AEP Change In Control Agreement, effective November 1, 2009.
 
2009 Form 10-K, Ex 10(h)
*†10(i)(1)
 
Amended and Restated AEP System Long-Term Incentive Plan.
 
Form 10-Q, Ex 10, March 31, 2010
†10(i)(2)
 
Form of Performance Share Award Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.
 
AEP Form 10-Q, Ex 10(c), November 5, 2004
†10(i)(3)
 
Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.
 
Form 10-Q, Ex 10(a), March 31, 2005
†10(i)(3)(A)
 
Amendment to Form of Restricted Stock Unit Agreement furnished to participants of the AEP System Long-Term Incentive Plan, as amended.
 
2008 Form 10-K, Ex 10(i)(3)(A)
†10(j)
 
AEP System Stock Ownership Requirement Plan Amended and Restated Effective January 1, 2010.
 
2009 Form 10-K, Ex 10(j)
†10(k)
 
Central and South West System Special Executive Retirement Plan Amended and Restated effective January 1, 2009.
 
2008 Form 10-K, Ex 10(j)
†10(l)
 
AEP System Incentive Compensation Deferral Plan Amended and Restated as of January 1, 2008.
 
2008 Form 10-K, Ex 10(k)
†10(m)
 
AEP System Nuclear Performance Long Term Incentive Compensation Plan dated August 1, 1998.
 
2002 Form 10-K, Ex 10(p)
†10(n)
 
Nuclear Key Contributor Retention Plan Amended and Restated as of January 1, 2008.
 
2008 Form 10-K, Ex 10(m)
*12
 
Statement re: Computation of Ratios.
   
*13
 
Copy of those portions of the SWEPCo 2010 Annual Report (for the fiscal year ended December 31, 2010) which are incorporated by reference in this filing.
   
21
 
List of subsidiaries of SWEPCo.
 
2006 Form 10-K, Ex 21, File No. 1-3525
*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.
   
 
 
E-15
 
 
‡ 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-16
 
Exhibit 10
AMERICAN ELECTRIC POWER SYSTEM
SUPPLEMENTAL RETIREMENT SAVINGS PLAN

(As Amended and Restated Effective January 1, 2011)


ARTICLE I

PURPOSES AND EFFECTIVE DATE

1.1  The American Electric Power System Supplemental Retirement Savings Plan was established to provide to eligible employees a tax-deferred savings opportunity otherwise not available to them under the terms of the American Electric Power System Retirement Savings Plan because of contribution restrictions imposed by the Internal Revenue Code.

1.2  The original effective date of the American Electric Power System Supplemental Retirement Savings Plan is January 1, 1994.  The Plan was most recently amended and restated effective January 1, 2008 pursuant to a document that was signed on December 31, 2008.  Except as otherwise specified herein, the effective date of this Amended and Restated American Electric Power System Supplemental Retirement Savings Plan is January 1, 2011. This amended and restated Plan continues to apply to all deferrals of compensation made under the Plan, unless specifically provided otherwise herein.


ARTICLE II

DEFINITIONS

2.1  “Account” means the separate memo account established and maintained by the Company or the recordkeeper employed by the Company to record Contributions allocated to a Participant's Account and to record any related Investment Income on the Fund or Funds selected by the Participant. The portion of the Account attributable to Compensation earned and vested prior to January 1, 2005 (excluding, for this purpose incentive compensation attributable to 2004 that was subject to discretionary adjustment and first available for payment subsequent to December 31, 2004) shall be referred to as the Participant’s “Legacy SRSP Account Balance.” The portion of the Account attributable to Compensation other than that described in the immediately preceding sentence shall be referred to as the Participant’s “Active SRSP Account Balance.”

2.2  “Applicable Federal Rate” means 120% of the applicable federal long-term rate, with monthly compounding (as prescribed under Section 1274(d) of the Code), published for the December immediately prior to the Plan Year.

2.3  “Claims Reviewer” means the person or committee designated by American Electric Power Service Corporation (or by a duly authorized person) as responsible for the review of claims for benefits under the Plan in accordance with Section 7.1. Until changed, the Claims Reviewer shall be the Director – Compensation and Executive Benefits.

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

2.5  “Committee” means the committee designated by American Electric Power Service Corporation (or by a duly authorized person) as responsible for the administration of the Plan.

2.6  “Company” means the American Electric Power Service Corporation and its subsidiaries and affiliates.
 
 
2.7  “Company Contributions” means the matching contributions made by the Company pursuant to section 3.2.

2.8  “Compensation” means a Participant's regular straight time pay, or base salary or wage including any base wage or salary lump sum payment made as part of the Company’s regular compensation program that may be paid in lieu of or in addition to a base wage or salary increase, salary or wage reductions made pursuant to sections 125, 402(e)(3) or 132(f) of the Code and contributions to this Plan, sick pay and salary continuation, overtime pay, shift and Sunday premium payments, safety focus payouts and incentive compensation paid pursuant to the terms of annual incentive compensation plans up to a Plan Year maximum of two million dollars ($2,000,000) provided that Compensation shall not include non-annual bonuses (such as but not limited to project bonuses and sign-on bonuses), severance pay, relocation payments, employee referral pay, meal allowance pay, or any other form of additional compensation that is not considered to be part of base salary, base wage, overtime pay or annual incentive compensation.  For this purpose, safety focus payouts shall be considered paid pursuant to the terms of an annual incentive plan, although such payouts may be determined and paid on a quarterly basis.  Notwithstanding anything stated in the preceding sentences to the contrary, Compensation shall be determined   after any deferral thereof pursuant to the American Electric Power System Stock Ownership Requirement Plan, as amended, or pursuant to a pay reduction agreement under the American Electric Power System Incentive Compensation Deferral Plan, as amended.

2.9  “Contributions” means, as the context may require, Participant Contributions and Company Contributions.

2.10  “Corporation” means the American Electric Power Company, Inc., a New York corporation.

2.11  “Eligible Employee” means any employee of the Company who is designated by the Company as eligible to participate in this Plan, provided that effective for deferral election periods that begin after June 1, 2005, such employee must be employed at exempt salary grade 28 or higher.  Individuals not directly compensated by the Company or who are not treated by the Company as an active employee shall not be considered Eligible Employees.

2.12  “ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time.

2.13 “Executive Officer” means Participant who, with respect to AEP, is subject to the disclosure requirements set forth in Section 16 of the Securities Exchange Act of 1934, as amended.

 
2
 
2.14  “First Date Available” or “FDA” means (a) with respect to Key Employees, the last day of the month coincident with or next following the date that is six (6) months after the date of the Participant’s or Former Participant’s Termination; and (b) with respect to all other Participants and Former Participants, the last day of the month coincident with or next following the date that is one (1) month after the date of the Participant’s Termination; provided, however, that the FDA with respect to an Executive Officer shall be no earlier than the December 31 of the calendar year of such Executive Officer’s Termination.

2.15  “Former Participant” means a Participant whose employment has Terminated or a Participant who is no longer an Eligible Employee, but whose Account has a balance greater than zero.

2.16  “Fund” means, except as the Committee may otherwise specify, the Interest Bearing Account and   the investment options made available to participants in the Savings Plan, as revised from time to time.  The investment options under the Savings Plan were revised effective on or about July 5, 2006 in connection with a transition of the recordkeeping and trustee services from Fidelity Management Trust Company to affiliates of JP Morgan Chase Bank, NA.  The investments made available through the self-directed brokerage account option thereupon being offered under the Savings Plan shall not be available to Participants in this Plan.

2.17  “Investment Income” means with respect to Participant Contributions and Company Contributions the earnings, gains and losses that would be attributable to the investment of such Contributions in a Fund or Funds.

2.18  “Interest Bearing Account” means an investment option to be made available to Participants in this Plan in which the Contributions attributed to this option are credited with interest at the Applicable Federal Rate.

2.19  “Key Employee” means a Participant who is classified as a “specified employee” at the time of Termination in accordance with the policies adopted by the Committee in order to comply with the requirements of Section 409A(a)(2)(B)(i) of the Code and the guidance issued thereunder.

2.20  “Next Date Available” or “NDA” means the June 30 of the calendar year immediately following the calendar year in which falls the Participant’s Termination.

2.21  “Participant” means an Eligible Employee who elects to defer part or all of his or her Incentive Compensation.  Except to the extent otherwise specified in this Plan, references to a Participant shall be considered to include a Former Participant.

2.22  “Participant Contributions” means contributions made by the Participant pursuant to an executed Pay Reduction Agreement subject to the Participant Contribution limits contained in Article III.

2.23  “Pay Reduction Agreement” means an agreement between the Company and the Participant in which the Participant irrevocably elects to reduce his or her Compensation for the Plan Year and the Company agrees to treat the amount of the Compensation reduction as a Participant Contribution to this Plan.

 
3
 
2.24  “Plan” means this American Electric Power System Supplemental Retirement Savings Plan, as amended from time to time.

2.25  “Plan Year” means the twelve-month period commencing each January 1 and ending the following December 31.

2.26  “Savings Plan” means the American Electric Power System Retirement Savings Plan, a plan intended to be qualified under section 401(a) of the Code, as amended from time to time.

2.27  “Termination” means termination of employment with the Company and its subsidiaries and affiliates for any reason; provided that effective with respect to Participants whose employment terminates on or after January 1, 2005, determinations as to the circumstances that will be considered a Termination (including a disability and leave of absence) shall be made in a manner consistent with the written policies adopted by the HR Committee from time to time to the extent such policies are consistent with the requirements imposed under Code 409A(a)(2)(A)(i).

2.28  “2005 Distribution Election Period” means the period or periods designated by the Committee during which Participants (or Former Participants) are given the opportunity to select among the distribution options set forth in Article V, provided that any such period shall end no later than December 31, 2005.

2.29  “2006 Distribution Election Period” means the period or periods designated by the Committee during which Participants (or Former Participants) are given the opportunity to select among the distribution options set forth in Article V, provided that any such period shall end no later than December 31, 2006.

2.30  “2010 Annual Incentive Compensation” means annual incentive compensation earned from the Company by an Eligible Employee for the 2010 calendar year that would become payable (if not deferred) no later than March 15, 2011, determined after any deferral thereof pursuant to the American Electric Power System Stock Ownership Requirement Plan, as amended, or pursuant to a pay reduction agreement under the American Electric Power System Incentive Compensation Deferral Plan, as amended.
 
 
4
 
ARTICLE III

PARTICIPATION

3.1  An Eligible Employee shall become a Participant by timely submitting a Pay Reduction Agreement during an applicable deferral election period to defer part of the Eligible Employee’s Compensation to which such election relates. Pay Reduction Agreements submitted for Plan Years on or after January 1, 2011 shall not apply with respect to Compensation earned on or after January 1, 2011 except to the extent of such Compensation received by the Eligible Employee that exceeds the amount of the limit imposed by Code Section 401(a)(17) on annual compensation taken into account for  purposes of tax qualified retirement plans with respect to such Plan Year; provided, however, that this limitation shall not apply with respect to 2010 Annual Incentive Compensation. The Pay Reduction Agreement shall be in such form as may reasonably be required by the Committee and shall be executed at the time and in the manner prescribed by the Committee.

3.2  For purposes of Section 3.1, the election period during which Compensation may be subject to an effective deferral election shall be determined as follows:

(a)           To the extent that the Compensation is “performance-based compensation” (within the meaning of Section 409A(a)(4)(B)(iii) of the Code) that is based on services performed over a period of at least 12 months, the election period shall end no later than six (6) months before the end of the performance period.

(b)           To the extent that the Compensation is not described in paragraph (a), the election period shall end on or before December 31 of the calendar year prior to the year in which the services on which the Compensation is based are to be performed.

(c)           Notwithstanding (a) and (b), in the case of the first year in which an Eligible Employee becomes eligible to participate in the Plan, and the Participant has not previously become a Participant in another plan that is required to be aggregated with this Plan under Treasury Regulation Section 1.409A-1(c)(2) or other guidance of the Code, the election period shall end within 30 days after the date such Eligible Employee became eligible to participate and such election shall apply only with respect to Compensation paid for services performed subsequent to the election.

No election shall be effective to defer any Compensation that would otherwise be paid to the Participant before the period for which the Pay Reduction Agreement is effective.

Notwithstanding the foregoing, the deferral election period for an Eligible Employee identified by the Company as having an inadequate opportunity to enroll in the Plan with regard to the 2005 calendar year shall be extended into January 2005, provided that such election shall be applied only to Compensation that had not been paid nor become payable at the time the election is submitted.

3.3  If a deferral election is not made by the end of the election period prescribed by the Company with regard to certain Compensation that may be earned by an Eligible Employee, no portion of such Compensation shall be deferred for such Eligible Employee.

 
5
 
3.4  Participant Contributions made by a Participant pursuant to an executed Pay Reduction Agreement shall be made by payroll deductions from such Compensation payable to the Participant to which the Pay Reduction Agreement relates.  Participant Contributions are to be made in multiples of one (1) whole percentage of Compensation, not to exceed 50 percent of Compensation for any pay date that is eligible for deferral pursuant to Section 3.1 (or 20% of 2010 Annual Incentive Compensation).

3.5  Subject to the limitation contained in section 3.6,

(a)           Effective for Plan Years ending on or before December 31, 2008, the Company shall credit to the Plan on behalf of each Participant an amount equal to 75% of the amount contributed to the Plan by the Participant, not in excess of 6% of a Participant's Compensation as of each pay date.

(b)           Effective for Plan Years beginning on or after January 1, 2009, the Company shall credit to the Plan on behalf of each Participant an amount equal to

 
(i)
100% of the amount contributed to the Plan by the Participant, not in excess of 1% of a Participant's Compensation  as of each pay date, plus

 
(ii)
70% of the amount in excess of 1%, but not in excess of 6%, of such Participant's Compensation, contributed to the Plan by such Participant as of each pay date.

3.6  The amount of Company Contributions credited to the Plan on behalf of a Participant in combination with the contributions made by the Company to the Savings Plan on behalf of the Participant as of each pay date during a Plan Year, shall, in the aggregate be equal to the lesser of (a) (i)   100% of the amount contributed to this Plan and the Savings Plan by the Participant, not in excess of 1% of a Participant's Compensation  as of that pay date, plus (ii) 70% of the amount in excess of 1%, but not in excess of 6%, of such Participant's Compensation, contributed to this Plan and the Savings Plan by such Participant as of such pay date, or (b) 4.5% of the Participant's Compensation paid as of that pay date.  If the aggregate contributions exceed the lesser limitation described in the preceding sentence, the Company Contributions credited to the Participant's Account under this Plan shall be reduced until the aggregate Company Contributions made under both the Savings Plan and this Plan do not exceed the limitation.

3.7  Participant Contributions and Company Contributions shall be credited to the Participant’s Account as follows:

(a)           Contributions related to Compensation that had been earned and vested prior to January 1, 2005 have been credited to the Participant’s Legacy SRSP Account Balance.  No additional Contributions shall be credited to a Legacy SRSP Account Balance.

(b)           Contributions related to Compensation that is earned or vested on or after January 1, 2005 shall be credited to the Participant’s Active SRSP Account Balance.  This shall include the Contributions under this Plan relating to incentive compensation attributable to 2004 that was subject to discretionary adjustment and first available for payment subsequent to December 31, 2004.

 
6
 
3.8           The Termination (or any subsequent re-employment) of a Participant after such Participant has submitted an election to defer any Compensation shall not affect the terms of such election with respect to the Compensation to which such election relates, subject, however, to the provisions for the distribution of any such deferred Compensation pursuant to the provisions of Article V.


ARTICLE IV

INVESTMENT OF CONTRIBUTIONS

4.1  Participant Contributions and Company Contributions (without regard to whether such Contributions have been allocated to such Participant’s Legacy SRSP Account Balance or Active SRSP Account Balance) shall be credited with earnings as if invested in the Funds selected by the Participant.  To the extent the Participant fails to select Funds for the investment of Contributions under the Plan, the Participant shall be deemed to have selected the Interest Bearing Account. The Participant may change the selected Funds by providing notification in accordance with the Plan’s procedures.  Any change in the Funds selected by the Participant shall be implemented in accordance with the Plan’s procedures.

4.2  A Participant may elect to transfer all or a portion of the amounts credited to his Account from any Fund or Funds to any other Fund or Funds by providing notification in accordance with the Plan’s procedures.  Such transfers between Funds may be made in any whole percentage or dollar amounts and shall be implemented in accordance with the Plan’s procedures.

4.3  The amount credited to each Participant's Account shall be determined daily based upon the fair market value of the Fund or Funds to which that Account is allocated.  The fair market value calculation for a Participant's Account shall be made after all Contributions, withdrawals, distributions, Investment Income and transfers for the day are recorded.  A Participant’s Account, as adjusted from time to time, shall continue to be credited with Investment Income until the balance of the Account is zero and the Committee anticipates no additional Contributions from such Participant.

4.4  The Plan is an unfunded non-qualified deferred compensation plan and therefore the Contributions credited to a Participant's Account and the investment of those Contributions in the Fund or Funds selected by the Participant are memo accounts that represent general, unsecured liabilities of the Company payable exclusively out of the general assets of the Company. In the event that the Company becomes insolvent, the Participants shall be considered as general unsecured creditors of the Company.  The Participant’s rights to benefits under this Plan shall not be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge encumbrance, attachment or garnishment by creditors of any Participant or any beneficiary.

 
7
 

ARTICLE V

DISTRIBUTIONS

5.1           Upon a Participant’s termination of employment with the Company and its subsidiaries and affiliates for any reason, the Company shall cause the Participant to be paid the full amount credited to his or her Account in accordance with the following rules:

(a)            Legacy SRSP Account Balance. Amounts that are credited to the Participant's Legacy SRSP Account Balance:

 
(1)
Shall be distributed to the Participant in one of the following optional forms as selected by the Participant:

 
(A)
A single lump-sum payment, or

 
(B)
In annual installment payments over not less than two nor more than ten years.

 
(2)
Shall be paid in the form of distribution selected by the Participant pursuant to paragraph (1) shall commence within 60 days after the date elected by the Participant on an effective distribution election form.  Such date elected by the Participant shall be either (A) the date of the Participant’s Termination (provided, however, if the Participant was an Executive Officer at the time of his or her Termination, the earliest commencement date (for account valuation purposes) shall be December 31 of the year of such Executive Officer’s Termination) or (2) the first, second, third, fourth or fifth anniversary of the Participant’s Termination, as selected by the Participant.

Each Participant shall select the form of distribution [as set forth in paragraph (1)] and benefit commencement date [as set forth in paragraph (2)] with regard to the amounts that are credited to the Participant's Legacy SRSP Account Balance when the Participant first elects to participate in the Plan.  The Participant may amend his or her distribution election with regard to amounts that are credited to the Participant's Legacy SRSP Account Balance at any time prior to the date that is at least twelve (12) months prior to the Participant's Termination by submitting a distribution election form in accordance with the Plan’s procedures.  If the Participant has not submitted an effective distribution election with regard to amounts that are credited to the Participant's Legacy SRSP Account Balance at the time of his Termination, the distribution of the amounts that are credited to the Participant's Legacy SRSP Account Balance shall be in the form of a single lump sum payment made within 60 days after the Participant's Termination.  Notwithstanding the preceding sentence, distribution to a Participant who was an Executive Officer at the time of his Termination, but who has not submitted an effective distribution election with regard to amounts that are credited to the Participant's Legacy SRSP Account Balance at the time of his Termination, shall be in the form of a single lump sum payment within 60 days after the December 31 of the calendar year of the Participant’s Termination.

(b)            Active SRSP Account Balance .  With regard to the Participant’s Active SRSP Account Balance the following rules shall apply:

 
8
 
 
(1)
Form of Distribution .  The Company shall cause the Participant to be paid the full amount credited to his or her Active SRSP Account Balance in accordance with his or her effective election in one of the following forms:

 
(A)
A single lump sum distribution

 
(i)
as of the First Date Available; or

 
(ii)
as of the Next Date Available; or

 
(iii)
as of the fifth anniversary of the First Date Available; or

 
(iv)
as of the fifth anniversary of the Next Date Available; or

 
(B)
In five (5) annual installments commencing

 
(i)
as of the First Date Available; or

 
(ii)
as of the Next Date Available; or

 
(iii)
as of the fifth anniversary of the First Date Available; or

 
(iv)
as of the fifth anniversary of the Next Date Available; or

 
(C)
In ten (10) annual installments commencing.

 
(i)
as of the First Date Available; or

 
(ii)
as of the Next Date Available.

 
(2)
Effective Election .  For this purpose, a Participant’s election with respect to the distribution of his or her Active SRSP Account Balance shall not be effective unless all of the following requirements are satisfied.

 
(A)
The election is submitted to the Company in writing in a form determined by the Committee to be acceptable;

 
(B)
The election is submitted timely.  For purposes of this paragraph, a distribution election will be considered “timely” only if it is submitted prior to the Participant’s Termination and it satisfies the requirements of (i), (ii), (iii) or (iv), below, as may be applicable:

 
(i)
Submitted within the applicable election period (as determined in accordance with Section 3.2), but only if the distribution election is
 
 
9
 
 
 
submitted in connection with the Participant’s initial deferral election under this Plan; or

 
(ii)
Submitted during the 2005 Distribution Election Period, but only with regard to the first distribution election form submitted by such Participant during that period; or

 
(iii)
Submitted during the 2006 Distribution Election Period by a Participant who then has an Active SRSP Account Balance but who was not an Eligible Employee for purposes of a deferral election for 2006 by reason of the change in the definition of Eligible Employee set forth in Section 2.11, but only with regard to the last distribution election form submitted by such Participant during that period; or

 
(iv)
If the Participant is submitting the election to change the timing or form of distribution that is then in effect with respect to the Participant’s Active SRSP Account Balance other than an effective distribution election submitted as part of the 2005 Distribution Election Period or 2006 Distribution Election Period, such election must be submitted at least one year prior to the date of the Participant’s Termination.

 
(C)
If the Participant is submitting the election pursuant to paragraph (b)(2)(B)(iv) to change the timing or form of distribution that is then in effect with respect to the Participant’s Active SRSP Account Balance (i.e., the Participant is not submitting an election with his initial deferral election [(B)(i)] nor during the 2005 or 2006 Distribution Election Period [(B)(ii) & (B)(iii)], the newly selected option must result in the further deferral of the first scheduled payment from the Participant’s Active Account balance by at least 5 years.  For purposes of compliance with the rule set forth in Section 409A(a) of the Code (and the regulations issued thereunder), each distribution option described in Section 5.1(b)(1) shall be treated as a single payment as of the first scheduled payment date. The requirement included in the prior plan document that the newly elected option not result in the acceleration of any scheduled payment under the replaced option shall be disregarded.

 
(D)
If the Participant is submitting the election pursuant to paragraph (b)(2)(B)(iii) to change the timing or form of distribution that is then in effect with respect to the Participant’s Active SRSP Account Balance, the newly selected option may not defer payments that the Participant would have received in 2006 if not for the new distribution election nor cause payments to be made in 2006 if not for the new distribution election.

 
(3)
If a Participant fails to submit an effective distribution election with regard to his Active SRSP Account Balance that satisfies the requirements of Section 5.1(b)(2)(B)(i) (with his timely initial deferral election) or Section 5.1(b)(2)(B)(ii) (during the 2005 Distribution Election Period) or Section 5.1(b)(2)(B)(iii) (during the 2006 Distribution Election
 
 
10
 
 
 
Period), as applicable, by the date of such initial deferral election or the last day of the 2005 or 2006 Distribution Election Period, respectively, as applicable, such Participant shall be considered to have elected a distribution of his or her Active SRSP Account Balance in a single lump sum as of the First Date Available.

 
(4)
Notwithstanding any other provision of this Plan to the contrary, if a Participant whose Termination occurs on or before June 30, 2005 fails to submit an effective distribution election with regard to his Active SRSP Account Balance that satisfies the requirements of this Section 5.1(b), the deferral election with respect to Contributions credited to such Participant’s Active SRSP Account Balance shall terminated and the entire balance of such Participant’s Active SRSP Account Balance shall be distributed to such Participant in a single lump sum as soon as administratively practicable after the Termination of such Participant.

5.2           (a)           For purposes of this Article, the amount to be distributed to a Participant shall be based upon the value of such individual’s Legacy SRSP Account Balance or Active SRSP Account Balance (as applicable) determined as of the applicable distribution date (or, if that is not a business day, then as of the immediately preceding business day) and shall be paid to such individual as soon as administratively practicable thereafter.

(b)           Notwithstanding any other provision of this Article,

 
(1)
if the Participant’s Account is $10,000 or less on the Participant’s First Date Available (determined without regard to any delay by reason of a Participant’s being an Executive Officer), the Committee may require that the full value of the Participant’s Account be distributed as of the First Date Available (determined without regard to any delay by reason of a Participant’s being an Executive Officer) in a single, lump sum distribution regardless of the form elected by such Participant, provided that such payment is consistent with the limited cash-out right described in Treasury Regulation Section 1.409A-3(j)(4)(v) or other guidance of the Code in that the payment results in the termination and liquidation of the entirety of the Participant’s interest under each nonqualified deferred compensation plan (including all agreements, methods, programs, or other arrangements with respect to which deferrals of compensation are treated as having been deferred under a single nonqualified deferred compensation plan under Treasury Regulation 1.409A-1(c)(2) or other guidance of the Code) that is associated with this Plan; and the total payment with respect to any such single nonqualified deferred compensation plan is not greater than the applicable dollar amount under Code Section 402(g)(1)(B).  Provided, however,

 
(2)
payment to a Participant under any provision of this Plan will be delayed at any time that the Committee reasonably anticipates that the making of such payment will violate Federal securities laws or other applicable law; provided however, that any payments so delayed shall be paid at the earliest date at which the Committee reasonably anticipates that the making of such payment will not cause such violation.

 
11
 
5.3  If an annual distribution is selected, the amount to be distributed in any one-year shall be determined by dividing the Participant’s Legacy SRSP Account Balance or Active SRSP Account Balance (as appropriate) by the number of years remaining in the elected distribution period.   The Participant electing annual distributions shall have the right to direct changes in the investment of the Account in a Fund or Funds in accordance with Article IV until the amount credited to the Account is reduced to zero.


ARTICLE VI

BENEFICIARIES

6.1  Each Participant may designate a beneficiary or beneficiaries who shall receive the balance of the Participant's Account if the Participant dies prior to the complete distribution of the Participant's Account.  Any designation, or change or rescission of a beneficiary designation shall be made by the Participant’s completion, signature and submission to the Committee of the appropriate beneficiary form prescribed by the Committee.  A beneficiary form shall take effect as of the date the form is signed provided that the Committee receives it before taking any action or making any payment to another beneficiary named in accordance with this Plan and any procedures implemented by the Committee.  If any payment is made or other action is taken before a beneficiary form is received by the Committee, any changes made on a form received thereafter will not be given any effect.  If a Participant fails to designate a beneficiary, or if none of the beneficiaries named by the Participant survive the Participant, the Participant’s Account will be paid to the Participant’s estate.  Unless clearly specified otherwise in an applicable court order presented to the Committee prior to the Participant’s death, the designation of a Participant’s spouse as a beneficiary shall be considered automatically revoked as to that spouse upon the legal termination of the Participant’s marriage to that spouse.

6.2  Distribution to a Participant’s beneficiary shall be in the form of a single lump-sum payment within 60 days after the Committee makes a final determination as to the beneficiary or beneficiaries entitled to receive such distribution.


ARTICLE VII

CLAIMS PROCEDURE

7.1  The following procedures shall apply with respect to claims for benefits under the Plan.

(a)           Any Participant or beneficiary who believes he or she is entitled to receive a distribution under the Plan which he or she did not receive or that amounts credited to his or her Account are inaccurate, may file a written claim signed by the Participant, beneficiary or authorized representative with the Claims Reviewer, specifying the basis for the claim.  The Claims Reviewer shall provide a claimant with written or electronic notification of its determination on the claim within ninety days after such claim was filed; provided, however, if the Claims Reviewer determines special circumstances require an extension of time for processing the claim, the claimant shall receive within the initial ninety-day period a written notice of the extension for a period of up to ninety days from the end of the initial
 
 
12
 
ninety day period.  The extension notice shall indicate the special circumstances requiring the extension and the date by which the Plan expects to render the benefit determination.

(b)           If the Claims Reviewer renders an adverse benefit determination under paragraph (a), the notification to the claimant shall set forth, in a manner calculated to be understood by the claimant:

 
(1)
the specific reasons for the denial of the claim;

 
(2)
specific reference to the provisions of the Plan upon which the denial of the claim was based;

 
(3)
a description of any additional material or information necessary for the claimant to perfect the claim and an explanation of why such material or information is necessary, and

 
(4)
an explanation of the review procedure specified in Section 7.2, and the time limits applicable to such procedures, including a statement of the claimant’s right to bring a civil action under section 502(a) of the Employee Retirement Income Security Act of 1974, as amended, following an adverse benefit determination on review.

7.2  The following procedures shall apply with respect to the review on appeal of an adverse determination on a claim for benefits under the Plan.

(a)           Within sixty days after the receipt by the claimant of an adverse benefit determination, the claimant may appeal such denial by filing with the Committee a written request for a review of the claim.  If such an appeal is filed within the sixty day period, the Committee, or a duly appointed representative of the Committee, shall conduct a full and fair review of such claim that takes into account all comments, documents, records and other information submitted by the claimant relating to the claim, without regard to whether such information was submitted or considered in the initial benefit determination.  The claimant shall be entitled to submit written comments, documents, records and other information relating to the claim for benefits and shall be provided, upon request and free of charge, reasonable access to, and copies of all documents, records and other information relevant to the claimant’s claim for benefits.  If the claimant requests a hearing on the claim and the Committee concludes such a hearing is advisable and schedules such a hearing, the claimant shall have the opportunity to present the claimant’s case in person or by an authorized representative at such hearing.

(b)           The claimant shall be notified of the Committee’s benefit determination on review within sixty days after receipt of the claimant’s request for review, unless the Committee determines that special circumstances require an extension of time for processing the review.  If the Committee determines that such an extension is required, written notice of the extension shall be furnished to the claimant within the initial sixty-day period.  Any such extension shall not exceed a period of sixty days from the end of the initial period. The extension notice shall indicate the special circumstances requiring the extension and the date by which the Plan expects to render the benefit determination.

(c)           The Committee shall provide a claimant with written or electronic notification of the Plan’s benefit determination on review.  The determination of the Committee shall be final and binding
 
 
13
 
on all interested parties.  Any adverse benefit determination on review shall set forth, in a manner calculated to be understood by the claimant:

 
(1)
the specific reason(s) for the adverse determination;

 
(2)
reference to the specific provisions of the Plan on which the determination was based;

 
(3)
a statement that the claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information relevant to the claimant’s claim for benefits; and

 
(4)
a statement of the claimant’s right to bring an action under Section 502(a) of ERISA.


ARTICLE VIII

ADMINISTRATION

8.1  The Committee shall have full discretionary power and authority (i) to administer and interpret the terms and conditions of the Plan; (ii) to establish reasonable procedures with which Participants must comply to exercise any right or privilege established hereunder; and (iii) to be permitted to delegate its responsibilities or duties hereunder to any person or entity.  The rights and duties of the Participants and all other persons and entities claiming an interest under the Plan shall be subject to, and bound by, actions taken by or in connection with the exercise of the powers and authority granted under this Article.

8.2  The Committee may employ agents, attorneys, accountants, or other persons and allocate or delegate to them powers, rights, and duties all as the Committee may consider necessary or advisable to properly carry out the administration of the Plan.

8.3  The Company shall maintain, or cause to be maintained, records showing the individual balances of each Participant's Account.  Statements setting forth the value of the amount credited to the Participant's Account as of a particular date shall be made available to each Participant no less often than quarterly.  The maintenance of the Account records and the distribution of statements may be delegated to a recordkeeper by either the Company or the Committee.


 
14
 
ARTICLE IX

AMENDMENT OR TERMINATION

The Company intends to continue the Plan indefinitely but reserves the right, in its sole discretion, to modify the Plan from time to time, or to terminate the Plan entirely or to direct the permanent discontinuance or temporary suspension of Contributions under the Plan.  Notwithstanding the foregoing provisions of this Article, no modification, termination, discontinuance or suspension shall reduce the benefits accrued for the benefit of any Participant or beneficiary under the Plan as of the date of such modification, termination, discontinuance or suspension.


ARTICLE X

MISCELLANEOUS

10.1  Nothing in the Plan shall (a) interfere with or limit in any way the right of the Company to terminate any Participant's employment at any time; nor (b) confer upon a Participant any right to continue in the employ of the Company.

10.2  In the event the Committee, in its sole discretion, shall find that a Participant or beneficiary is unable to care for his or her affairs because of illness or accident, the Committee may direct that any payment due the Participant or the beneficiary be paid to the duly appointed personal representative of the Participant or beneficiary, and any such payment so made shall be a complete discharge of the liabilities of the Plan and the Company with respect to such Participant or beneficiary.

10.3  Each Participant agrees that as a condition of participation in the Plan, the Company may withhold from any distribution hereunder all amounts determined by the Company as required by law or otherwise as determined by the Company to be then due and payable by the Participant or his beneficiary to the Company.

10.4  The Company intends the following with respect to this Plan: (1) Section 451(a) of the Code would apply to the Participant's recognition of gross income as a result of participation herein; (2) the Participants will not recognize gross income as a result of participation in the Plan unless and until and then only to the extent that distributions are received; (3) the Company will not receive a deduction for amount credited to any Account unless and until and then only to the extent that amounts are actually distributed; (4) the provisions of Parts 2, 3, and 4 of Subtitle B of Title I of ERISA shall not be applicable; and (5) the design and administration of the Plan are intended to comply with the requirements of Section 409A of the Code, to the extent such section is effective and applicable to amounts deferred hereunder.  However, no Eligible Employee, Participant, Former Participant, beneficiary or any other person shall have any recourse against the Corporation, the Company, the Committee or any of their affiliates, employees, agents, successors, assigns or other representatives if any of those conditions are determined not to be satisfied.

10.5  The Plan shall be construed and administered according to the applicable provisions of ERISA and the laws of the State of Ohio.

 
15
 
10.6  Neither a Participant nor any other person shall have any right to sell, assign, transfer, pledge, mortgage or otherwise encumber, transfer, alienate or convey in advance of actual receipt, the amounts, if any, payable under this Plan.  Such amounts payable, or any part thereof, and all rights to such amounts payable are not assignable and are not transferable.  No part of the amounts payable shall, prior to actual payment, be subject to seizure, attachment, garnishment or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by a Participant or any other person.  Additionally, no part of any amounts payable shall, prior to actual payment, be transferable by operation of law in the event of a Participant’s or any other person’s bankruptcy or insolvency or be transferable to a spouse as a result of a property settlement or otherwise, except that if necessary to comply with a “qualified domestic relations order,” as defined in ERISA Section 206(d), pursuant to which a court has determined that a spouse or former spouse of a Participant has an interest in the Participant’s benefits under the Plan, the Committee shall distribute the spouse’s or former spouse’s interest in the Participant’s benefits under the Plan to such spouse or former spouse in accordance with the Participant’s election under this Plan as to the time and form of payment.


American Electric Power Service Corporation has caused this amendment and restatement of the American Electric Power System Supplemental Retirement Savings Plan to be signed as of this 15th day of December, 2010.



 
AMERICAN ELECTRIC POWER SERVICE CORPORATION
   
   
 
By   /s/ Genevieve A. Tuchow
 
Genevieve A. Tuchow, Vice President, Human Resources

 
16
 
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,
 
   
2006
 
2007
 
2008
 
2009
   2010   
EARNINGS
                            
Income Before Income Tax Expense and Equity Earnings
 
$
1,483
 
$
1,663
 
$
2,015
 
$
1,938
 
$
1,849
 
Fixed Charges (as below)
   
999
   
1,146
   
1,240
   
1,237
   
1,254
 
Preferred Security Dividend Requirements of
   Consolidated Subsidiaries
     (4 )     (4 )     (4 )      (4 )    (4 ) 
Total Earnings
 
$
2,478
 
$
2,805
 
$
3,251
  $
3,171
 
$
3,099
 
                                 
FIXED CHARGES
                               
Interest Expense
 
$
729
 
$
838
 
$
957
  $ 973  
$
999  
Credit for Allowance for Borrowed Funds Used
   During Construction
   
82
   
79
   
75
    67     53  
Estimated Interest Element in Lease Rentals     184     225     204     193     198  
Preferred Security Dividend Requirements of
   Consolidated Subsidiaries
     4      4      4      4      4  
Total Fixed Charges
 
$
999
 
$
1,146
 
$
1,240
  $
1,237
 
$
1,254
 
                                 
Ratio of Earnings to Fixed Charges
   
2.48
   
2.44
   
2.62
   
2.56
   
2.47
 




2010 Annual Reports

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









Audited Financial Statements and
Management’s Financial Discussion and Analysis








 



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

   
Page
Glossary of Terms
 
i
     
Forward-Looking Information
 
iv
     
AEP Common Stock and Dividend Information
 
vi
       
American Electric Power Company, Inc. and Subsidiary Companies:
   
 
Selected Consolidated Financial Data
 
1
 
Management’s Financial Discussion and Analysis
 
2
 
Quantitative and Qualitative Disclosures About Market and Credit Risk
 
33
 
Reports of Independent Registered Public Accounting Firm
 
37-38
 
Management's Report on Internal Control Over Financial Reporting
 
39
 
Consolidated Financial Statements
 
40
 
Index of Notes to Consolidated Financial Statements
 
45
       
Appalachian Power Company and Subsidiaries:
   
 
Selected Consolidated Financial Data
 
139
 
Management’s Financial Discussion and Analysis
 
140
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
150
 
Report of Independent Registered Public Accounting Firm
 
151
 
Management's Report on Internal Control Over Financial Reporting
 
152
 
Consolidated Financial Statements
 
153
 
Index of Notes to Financial Statements of Registrant Subsidiaries
 
158
       
Columbus Southern Power Company and Subsidiaries:
   
 
Management’s Narrative Financial Discussion and Analysis
 
160
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
164
 
Report of Independent Registered Public Accounting Firm
 
165
 
Management's Report on Internal Control Over Financial Reporting
 
166
 
Consolidated Financial Statements
 
167
 
Index of Notes to Financial Statements of Registrant Subsidiaries
 
172
       
Indiana Michigan Power Company and Subsidiaries:
   
 
Management’s Narrative Financial Discussion and Analysis
 
174
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
178
 
Report of Independent Registered Public Accounting Firm
 
179
 
Management's Report on Internal Control Over Financial Reporting
 
180
 
Consolidated Financial Statements
 
181
 
Index of Notes to Financial Statements of Registrant Subsidiaries
 
186
       
Ohio Power Company Consolidated:
   
 
Selected Consolidated Financial Data
 
188
 
Management’s Financial Discussion and Analysis
 
189
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
199
 
Report of Independent Registered Public Accounting Firm
 
200
 
Management's Report on Internal Control Over Financial Reporting
 
201
 
Consolidated Financial Statements
 
202
 
Index of Notes to Financial Statements of Registrant Subsidiaries
 
207
 
 
 
 
       
Public Service Company of Oklahoma:
   
 
Selected Financial Data
 
209
 
Management’s Financial Discussion and Analysis
 
210
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
218
 
Report of Independent Registered Public Accounting Firm
 
219
 
Management's Report on Internal Control Over Financial Reporting
 
220
 
Financial Statements
 
221
 
Index of Notes to Financial Statements of Registrant Subsidiaries
 
226
       
Southwestern Electric Power Company Consolidated:
   
 
Selected Consolidated Financial Data
 
228
 
Management’s Financial Discussion and Analysis
 
229
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
237
 
Report of Independent Registered Public Accounting Firm
 
238
 
Management's Report on Internal Control Over Financial Reporting
 
239
 
Consolidated Financial Statements
 
240
 
Index of Notes to Financial Statements of Registrant Subsidiaries
 
245
       
Notes to Financial Statements of Registrant Subsidiaries
 
246
       
Combined Management’s Discussion and Analysis of Registrant Subsidiaries
 
405

 
 
 

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.
AEP Consolidated
 
AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit
 
AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East companies
 
APCo, CSPCo, I&M, KPCo and OPCo.
AEP Foundation
 
AEP charitable organization created in 2005 for charitable contributions in the communities in which AEP’s subsidiaries operate.
AEP Power Pool
 
Members are APCo, CSPCo, I&M, KPCo and OPCo.  The Pool shares the generation, cost of generation and resultant wholesale off-system sales of the member companies.
AEP System or the System
 
American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
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, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC
 
Allowance for Funds Used During Construction.
AOCI
 
Accumulated Other Comprehensive Income.
APCo
 
Appalachian Power Company, an AEP electric utility subsidiary.
APSC
 
Arkansas Public Service Commission.
ASU
 
Accounting Standard Update.
CAA
 
Clean Air Act.
CLECO
 
Cleco Corporation, 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.
CSPCo
 
Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW
 
Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW 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.
CTC
 
Competition Transition Charge.
CWIP
 
Construction Work in Progress.
DCC Fuel
 
DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC consolidated variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DETM
 
Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
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.
ERCOT
 
Electric Reliability Council of Texas.
ERISA
 
Employee Retirement Income Security Act of 1974, as amended.
ESP    Electric Security Plans, filed with the PUCO, pursuant to the Ohio Amendments.
 
 
i
 
ETA
 
Electric Transmission America, LLC an equity interest joint venture with MidAmerican Energy Holdings Company formed to own and operate electric transmission facilities in North America outside of ERCOT.
ETT
 
Electric Transmission Texas, LLC, an equity interest joint venture between AEP Utilities, Inc. 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.
IGCC
 
Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
Interconnection Agreement
 
Agreement, dated July 6, 1951, as amended, by and among APCo, CSPCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants.
IRS
 
Internal Revenue Service.
IURC
 
Indiana Utility Regulatory Commission.
I&M
 
Indiana Michigan Power Company, an AEP electric utility subsidiary.
JMG
 
JMG Funding LP.
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 AEP Power Pool transactions to its members.
MMBtu
 
Million British Thermal Units.
MPSC
 
Michigan Public Service Commission.
MTM
 
Mark-to-Market.
MW
 
Megawatt.
NEIL
 
Nuclear Electric Insurance Limited.
NO x
 
Nitrogen oxide.
Nonutility Money Pool
 
AEP’s Nonutility Money Pool.
NSR
 
New Source Review.
OCC
 
Corporation Commission of the State of Oklahoma.
OPCo
 
Ohio Power Company, an AEP electric utility subsidiary.
OPEB
 
Other Postretirement Benefit Plans.
OTC
 
Over the counter.
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
 
ii
 
 
Term
 
Meaning
     
PUCT
 
Public Utility Commission of Texas.
Registrant Subsidiaries
 
AEP subsidiaries which are SEC registrants; APCo, CSPCo, 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 generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana, owned by AEGCo and I&M.
RTO
 
Regional Transmission Organization.
Sabine
 
Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity.
SIA
 
System Integration Agreement.
SNF
 
Spent Nuclear Fuel.
SO 2
 
Sulfur Dioxide.
SPP
 
Southwest Power Pool.
Stall Unit
 
J. Lamar Stall Unit at Arsenal Hill Plant.
SWEPCo
 
Southwestern Electric Power Company, an AEP electric utility subsidiary.
TA
 
Transmission Agreement dated April 1, 1984 by and among APCo, CSPCo, I&M, KPCo and OPCo, which allocates costs and benefits in connection with the operation of transmission assets.
TCC
 
AEP Texas Central Company, an AEP electric utility subsidiary.
TEM
 
SUEZ Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing, Inc.).
TNC
 
AEP Texas North Company, an AEP electric utility subsidiary.
Transition Funding
 
AEP Texas Central Transition Funding I LLC and AEP Texas Central Transition Funding II 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.
Utility Money Pool
 
AEP System’s Utility Money Pool.
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.
     

 
iii
 


 
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 Financial Discussion and Analysis,” 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 speak only 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 and growth in, or contraction within, our service territory and changes in market demand and demographic patterns.
·
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 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 generating capacity and the performance of our generating plants.
·
Our ability to resolve I&M’s Donald C. Cook Nuclear Plant Unit 1 restoration and outage-related issues through warranty, insurance and the regulatory process.
·
Our ability to recover regulatory assets and stranded costs in connection with deregulation.
·
Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·
Our ability to build or acquire generating capacity, including the Turk Plant, and transmission line 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 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 and cost recovery of our plants.
·
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, natural gas and other energy-related commodities.
·
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 debt.
·
Volatility and changes in markets for electricity, natural gas, coal, nuclear fuel and other energy-related commodities.
·
Changes in utility regulation, including the implementation of ESPs and related regulation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP.
·
Accounting pronouncements periodically issued by accounting standard-setting bodies.
 
 
iv
 
· 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.
·
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.
·
Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.
·
Our ability to recover through rates or prices any remaining unrecovered investment in generating units that may be retired before the end of their previously projected useful lives.

AEP and its Registrant Subsidiaries expressly disclaim any obligation to update any forward-looking information.
 

 
 
v
 
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, 2010
 
$
 37.94 
 
$
 34.92 
 
$
 35.98 
 
$
 0.46 
September 30, 2010
 
 
 36.93 
 
 
 31.87 
 
 
 36.23 
 
 
 0.42 
June 30, 2010
 
 
 35.00 
 
 
 28.17 
 
 
 32.30 
 
 
 0.42 
March 31, 2010
 
 
 36.86 
 
 
 32.68 
 
 
 34.18 
 
 
 0.41 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2009
 
$
 36.51 
 
$
 29.59 
 
$
 34.79 
 
$
 0.41 
September 30, 2009
 
 
 32.36 
 
 
 28.07 
 
 
 30.99 
 
 
 0.41 
June 30, 2009
 
 
 29.16 
 
 
 24.75 
 
 
 28.89 
 
 
 0.41 
March 31, 2009
 
 
 34.34 
 
 
 24.00 
 
 
 25.26 
 
 
 0.41 

AEP common stock is traded principally on the New York Stock Exchange.  At December 31, 2010, AEP had approximately 91,000 registered shareholders.
 
5 YEAR CUMULATIVE TOTAL RETURN
 
 
vi
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2010 
 
2009 
 
2008 
 
2007 
 
2006 
 
 
 
(dollars in millions, except per share amounts)
STATEMENTS OF INCOME DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 14,427 
 
$
 13,489 
 
$
 14,440 
 
$
 13,380 
 
$
 12,622 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating Income
$
 2,663 
 
$
 2,771 
 
$
 2,787 
 
$
 2,319 
 
$
 1,966 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Before Discontinued Operations and Extraordinary Loss
$
 1,218 
 
$
 1,370 
 
$
 1,376 
 
$
 1,153 
 
$
 1,001 
Discontinued Operations, Net of Tax
 
 - 
 
 
 - 
 
 
 12 
 
 
 24 
 
 
 10 
Income Before Extraordinary Loss
 
 1,218 
 
 
 1,370 
 
 
 1,388 
 
 
 1,177 
 
 
 1,011 
Extraordinary Loss, Net of Tax
 
 - 
 
 
 (5)
 
 
 - 
 
 
 (79)
 
 
 - 
Net Income
 
 1,218 
 
 
 1,365 
 
 
 1,388 
 
 
 1,098 
 
 
 1,011 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Less:  Net Income Attributable to Noncontrolling Interests
 
 4 
 
 
 5 
 
 
 5 
 
 
 6 
 
 
 6 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS
 
 1,214 
 
 
 1,360 
 
 
 1,383 
 
 
 1,092 
 
 
 1,005 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Less:  Preferred Stock Dividend Requirements of Subsidiaries
 
 3 
 
 
 3 
 
 
 3 
 
 
 3 
 
 
 3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
$
 1,211 
 
$
 1,357 
 
$
 1,380 
 
$
 1,089 
 
$
 1,002 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
BALANCE SHEETS DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and Equipment
$
 53,740 
 
$
 51,684 
 
$
 49,710 
 
$
 46,145 
 
$
 42,021 
Accumulated Depreciation and Amortization
 
 18,066 
 
 
 17,340 
 
 
 16,723 
 
 
 16,275 
 
 
 15,240 
Total Property, Plant and Equipment – Net
$
 35,674 
 
$
 34,344 
 
$
 32,987 
 
$
 29,870 
 
$
 26,781 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 50,455 
 
$
 48,348 
 
$
 45,155 
 
$
 40,319 
 
$
 37,877 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total AEP Common Shareholders’ Equity
$
 13,622 
 
$
 13,140 
 
$
 10,693 
 
$
 10,079 
 
$
 9,412 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling Interests
$
 - 
 
$
 - 
 
$
 17 
 
$
 18 
 
$
 18 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
$
 60 
 
$
 61 
 
$
 61 
 
$
 61 
 
$
 61 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt (a)
$
 16,811 
 
$
 17,498 
 
$
 15,983 
 
$
 14,994 
 
$
 13,698 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Obligations Under Capital Leases (a)
$
 474 
(b)
$
 317 
 
$
 325 
 
$
 371 
 
$
 291 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
AEP COMMON STOCK DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Before Discontinued Operations and Extraordinary Loss
$
 2.53 
 
$
 2.97 
 
$
 3.40 
 
$
 2.87 
 
$
 2.52 
Discontinued Operations, Net of Tax
 
 - 
 
 
 - 
 
 
 0.03 
 
 
 0.06 
 
 
 0.02 
Income Before Extraordinary Loss
 
 2.53 
 
 
 2.97 
 
 
 3.43 
 
 
 2.93 
 
 
 2.54 
Extraordinary Loss, Net of Tax
 
 - 
 
 
 (0.01)
 
 
 - 
 
 
 (0.20)
 
 
 - 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Basic Earnings per Share Attributable to AEP Common Shareholders
$
 2.53 
 
$
 2.96 
 
$
 3.43 
 
$
 2.73 
 
$
 2.54 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted Average Number of Basic Shares Outstanding (in millions)
 
 479 
 
 
 459 
 
 
 402 
 
 
 399 
 
 
 394 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Market Price Range:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
High
$
 37.94 
 
$
 36.51 
 
$
 49.11 
 
$
 51.24 
 
$
 43.13 
 
 
Low
$
 28.17 
 
$
 24.00 
 
$
 25.54 
 
$
 41.67 
 
$
 32.27 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year-end Market Price
$
 35.98 
 
$
 34.79 
 
$
 33.28 
 
$
 46.56 
 
$
 42.58 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Dividends Paid per AEP Common Share
$
 1.71 
 
$
 1.64 
 
$
 1.64 
 
$
 1.58 
 
$
 1.50 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dividend Payout Ratio
 
67.59%
 
 
55.41%
 
 
47.8%
 
 
57.9%
 
 
59.1%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Book Value per AEP Common Share
$
 28.32 
 
$
 27.49 
 
$
 26.35 
 
$
 25.17 
 
$
 23.73 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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 FINANCIAL DISCUSSION AND ANALYSIS

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.

We operate an extensive portfolio of assets including:

·
Almost 39,000 megawatts of generating capacity, one of the largest complements of generation in the U.S., the majority of which provides a significant cost advantage in most of our market areas.
·
Approximately 39,000 miles of transmission lines, including 2,116 miles of 765kV lines, the backbone of the electric interconnection grid in the Eastern U.S.
·
Approximately 220,000 miles of distribution lines that deliver electricity to 5.3 million customers.
·
Substantial commodity transportation assets (more than 9,000 railcars, approximately 3,300 barges, 62 towboats, 29 harbor boats and a coal handling terminal with 18 million tons of annual capacity).

Economic Conditions

Retail margins increased during 2010 due to successful rate proceedings in various jurisdictions and higher residential and commercial demand for electricity as a result of favorable weather throughout our service territories.  Industrial sales increased 5% in 2010 in comparison to the recessionary lows of 2009.  We forecast a 1% increase in commercial sales and 2% increases in both our residential and industrial sales in 2011 as a result of anticipated slow economic growth.  Our forecasted industrial sales growth of 2% is due to the announcement of increased production by Ormet, a large aluminum manufacturer in Ohio, and announced expansions of several refineries in our Texas service territory.
 
Regulatory Activity

The table below summarizes our significant 2010 regulatory activities:
 
            Annual        
 
 
 
Annual
 
Rider
 
Approved
 
 
 
 
 
Approved
 
Surcharge
 
Return on
 
 
 
 
 
Base Rate
 
Rate
 
Common
 
Effective
Jurisdiction
 
Change
 
Change
 
Equity
 
Date
 
 
(in millions)
 
 
 
 
Kentucky
 
$
 63.7 
 
$
 - 
 
10.50%
 
July 2010
 
 
 
 
 
 
 
 
 
 
 
Michigan
 
 
 35.7 
 
 
 3.3 
(a)
10.35%
 
December 2010
 
 
 
 
 
 
 
 
 
 
 
Oklahoma
 
 
 30.3 
 
 
 (30.3)
 
10.15%
 
February 2011
 
 
 
 
 
 
 
 
 
 
 
Texas
 
 
 15.0 
 
 
 10.0 
(b)
10.33%
 
May 2010
 
 
 
 
 
 
 
 
 
 
 
Virginia
 
 
 61.5 
 
 
 - 
 
10.53%
 
August 2010
 
 
 
 
 
 
 
 
 
 
 
 
(a)
The MPSC granted I&M recovery of $6.6 million of customer choice
 
implementation costs over a two year period beginning April 2011.
(b)
The PUCT granted SWEPCo a $10 million one-year surcharge rider to recover
 
additional vegetation management costs which began in May 2010.

 
2
 
In Ohio, several notices of appeal are outstanding at the Supreme Court of Ohio relating to significant issues in the determination of the approved 2009 – 2011 ESP rates.  In January 2011, the PUCO issued an order that determined that OPCo’s 2009 earnings were not significantly excessive but determined relevant CSPCo 2009 earnings were significantly excessive.  As a result, the PUCO ordered CSPCo to refund $43 million of its earnings to customers, which was recorded on CSPCo’s December 2010 books.  Also, in January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer pricing for generation effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  Customer class rates individually vary, but on average, customers would experience net base generation increases of 1.4% in 2012 and 2.7% for the period January 2013 through May 2014.

In West Virginia, a settlement agreement was filed with the WVPSC in December 2010 to increase annual base rates by $60 million, effective March 2011.  The settlement agreement allows APCo to defer and amortize up to $18 million of previously expensed 2009 incremental storm expenses over a period of eight years.  A decision from the WVPSC is expected in March 2011.

Cost Reduction Initiatives

Due to the continued slow recovery in the U.S. economy and a corresponding negative impact on energy consumption, the AEP System implemented cost reduction initiatives in the second quarter of 2010 to reduce its workforce by 11.5% and reduce Other Operation and Maintenance spending.  Achieving these goals involved identifying process improvements, streamlining organizational designs and developing other efficiencies that will deliver additional savings.  In 2010, we recorded $293 million of pretax expense related to these cost reduction initiatives.  Starting with the third quarter of 2010, we realized cost savings in Other Operation and Maintenance expenses on our Consolidated Statements of Income and anticipate continued savings to help offset future inflationary impacts.

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW coal generating unit in Arkansas, which is expected to be in service in 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  SWEPCo’s share of construction costs is currently estimated to cost $1.3 billion, excluding AFUDC, plus an additional $125 million for transmission, excluding AFUDC.  The APSC, LPSC and PUCT approved SWEPCo’s original application to build the Turk Plant.  Various proceedings are pending that challenge the Turk Plant’s construction, its approved wetlands and air permits and its transmission line certificate of environmental compatibility and public need.  In 2010, the motions for preliminary injunction were partially granted and upheld on appeal pending a hearing.  According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop.  Mitigation measures required by the permit are authorized and may be completed.  The preliminary injunction affects portions of the water intake and associated piping and portions of the transmission lines.  A hearing on SWEPCo’s appeal is scheduled for March 2011.

In June 2010, the Arkansas Supreme Court denied motions for rehearing filed by the APSC and SWEPCo related to the reversal of the APSC’s earlier grant of a Certificate of Environmental Compatibility and Public Need (CECPN) for SWEPCo’s 88 MW Arkansas portion of the Turk Plant.  As a result, in June 2010, SWEPCo filed notice with the APSC of its intent to proceed with construction of the Turk Plant but that SWEPCo no longer intends to pursue a CECPN to seek recovery of its Arkansas portion of Turk Plant costs in Arkansas retail rates.  The APSC issued an order which reversed and set aside the previously granted CECPN.

Management expects that SWEPCo will ultimately be able to complete construction of the Turk Plant and related transmission facilities and place those facilities in service.  However, if SWEPCo is unable to complete the Turk Plant construction and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.  See “Turk Plant” section of Note 4.

 
3
 
Settlement with Bank of America

In February 2011, we reached a settlement with BOA and paid $425 million in full settlement of all claims against us.  We also received title to 55 BCF of cushion gas in the Bammel storage facility as part of the settlement.  The effect of the settlement had no impact on our financial statements for the year ended December 31, 2010.  We do not expect the effect of the settlement to have a material impact on our 2011 consolidated net income.

Ohio Customer Choice

In our Ohio service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service.  As of December 31, 2010, approximately 5,000 Ohio retail customers (primarily CSPCo customers) have switched to alternative CRES providers.  As a result, in comparison to 2009, we lost approximately $16 million of generation related gross margin in 2010 and currently forecast incremental lost margins of approximately $54 million for 2011.  We anticipate recovery of a portion of this lost margin through off-system sales and our newly created CRES provider.  Our CRES provider will target retail customers in Ohio, both within and outside of our retail service territory.

Termination of AEP Power Pool

Originally approved by the FERC in 1951 and subsequently amended in 1951, 1962, 1975 1979 (twice) and 1980, the Interconnection Agreement establishes the AEP Power Pool which permits the AEP East companies to pool their generation assets on a cost basis.  In December 2010, each member gave notice to AEPSC and the other AEP Power Pool members of its decision to terminate the Interconnection Agreement effective January 1, 2014 or such other date approved by the FERC, subject to state regulatory input.  It is unknown at this time whether the AEP Power Pool will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers or if each company will choose to operate independently.  The decision to terminate is subject to management’s ongoing evaluation.  The AEP Power Pool members may revoke their notices of termination.  If members of the current AEP Power Pool experience decreases in revenues or increases in costs as a result of the termination of the AEP Power Pool and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could have an adverse impact on future net income and cash flows.

Transmission Agreement

The AEP East companies are parties to a Transmission Agreement defining how they share the costs associated with their relative ownership of transmission assets.  This sharing was based upon each company’s MLR until the FERC approved a new Transmission Agreement effective November 1, 2010.  The new Transmission Agreement will be phased-in for retail rates over periods of up to four years, adds KGPCo and WPCo as parties to the agreement and changes the allocation method.  Our recovery mechanism for transmission costs is through our base rates.  State regulatory phase-in of the new agreement may limit our ability to fully recover our transmission costs.

Cook Plant Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator. Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $395 million.  Management believes that I&M should recover a significant portion of repair and replacement costs through the turbine vendor’s warranty, insurance and the regulatory process.  I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power.  The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors.  As a result, the replacement of the repaired turbine rotors and other equipment is scheduled for the Unit 1 planned outage in the fall of 2011.  If the ultimate costs of the incident are not covered by warranty, insurance or through the related regulatory process or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note 6.

 
4
 
Texas Restructuring Appeals

Pursuant to PUCT restructuring orders, TCC securitized net recoverable stranded generation costs of $2.5 billion and is recovering the principal and interest on the securitization bonds through the end of 2020.  TCC also refunded other net true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider under PUCT restructuring orders.  TCC and intervenors appealed the PUCT’s true-up related orders.  After rulings from the Texas District Court and the Texas Court of Appeals, TCC, the PUCT and intervenors filed petitions for review with the Texas Supreme Court.  Review is discretionary and the Texas Supreme Court has not yet determined if it will grant review.  See “Texas Restructuring Appeals” section of Note 4.

Mountaineer Carbon Capture and Storage

Product Validation Facility (PVF)

APCo and ALSTOM Power, Inc., an unrelated third party, jointly constructed a CO 2 capture validation facility, which was placed into service in September 2009.  APCo also constructed and owns the necessary facilities to store the CO 2 .  In APCo’s July 2009 Virginia base rate filing and May 2010 West Virginia base rate filing, APCo requested recovery of and a return on its Virginia and West Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion.  In July 2010, the Virginia SCC issued a base rate order that denied recovery of the Virginia share of the PVF costs, which resulted in a pretax write-off of approximately $54 million in the second quarter of 2010.  In December 2010, a settlement agreement was filed with the WVPSC to increase annual base rates by $60 million, effective March 2011.  A decision from the WVPSC is expected in March 2011.  As of December 31, 2010, APCo has recorded a noncurrent regulatory asset of $60 million related to the PVF.  If APCo cannot recover its remaining investments in and expenses related to the PVF, it would reduce future net income and cash flows and impact financial condition.  See “Mountaineer Carbon Capture and Storage Project” section of Note 4.

Carbon Capture and Sequestration Project with the Department of Energy (DOE)

During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale carbon capture and sequestration (CCS) facility under consideration at the Mountaineer Plant.  AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project.  The DOE will fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million.  A Front-End Engineering and Design (FEED) study, scheduled for completion during the third quarter of 2011, will refine the total cost estimate for the CCS facility.  Results from the FEED study will be evaluated by management before any decision is made to seek the necessary regulatory approvals to build the CCS facility.  As of December 31, 2010, APCo has incurred $14 million in total costs and has received $5 million of DOE funding resulting in a net $9 million balance included in Construction Work In Progress on the Consolidated Balance Sheets.  If APCo is unable to recover the costs of the CCS project, it would reduce future net income and cash flows.  See “Mountaineer Carbon Capture and Storage Project” section of Note 4.

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 state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be.  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 materially affect our net income.

ENVIRONMENTAL ISSUES

We are implementing a substantial capital investment program and incurring additional operational costs to comply with new 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 from fossil fuel-fired power plants and new proposals governing the beneficial use and disposal of coal combustion products.
 
 
 
5
 
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 are also engaged in the development of possible future requirements to reduce CO 2 emissions to address concerns about global climate change.

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.  Notable developments in CAA regulatory requirements affecting our operations are discussed briefly below.

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 D.C. Circuit Court of Appeals issued a decision remanding CAIR to the Federal EPA.  CAIR remains in effect while a new rulemaking is conducted.  Nearly all of the states in which our power plants are located are covered by CAIR.  In July 2010, the Federal EPA issued a proposed rule (Transport Rule) to replace CAIR that would impose new and more stringent requirements to control SO 2 and NO x emissions from fossil fuel-fired electric generating units in 31 states and the District of Columbia.  Each state covered by the Transport Rule is assigned an allowance budget for SO 2 and/or NO x .  Limited interstate trading is allowed on a sub-regional basis and intrastate trading is allowed among generating units.  Certain of our western states (Texas, Arkansas and Oklahoma) would be subject to only the seasonal NO x program, with new limits that are proposed to take effect in 2012.  The remainder of the states in which we operate would be subject to seasonal and annual NO x programs and an annual SO 2 emissions reduction program that takes effect in two phases.  The first phase becomes effective in 2012 and requires approximately one million tons per year more SO 2 emission reductions across the region than would have been required under CAIR.  The second phase takes effect in 2014 and reduces SO 2 emissions by an additional 800,000 tons per year.  The SO 2 and NO x programs rely on newly-created allowances rather than relying on the CAIR NO x allowances or the Title IV Acid Rain Program allowances used in the CAIR rule.  The time frames for and stringency of the additional 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, as these features could accelerate unit retirements, increase capital requirements, constrain operations, decrease reliability and unfavorably impact financial condition if the increased costs are not recovered in rates or market prices.  The Federal EPA requested comments on a scheme based exclusively on intrastate trading of allowances or a scheme that establishes unit-by-unit emission rates.  Either of these options would provide less flexibility and exacerbate the negative impact of the rule.  The proposal indicates that the requirements are expected to be finalized in June 2011 and be effective January 1, 2012.

The Federal EPA issued a Clean Air Mercury Rule (CAMR) setting mercury standards for new coal-fired power plants and requiring all states to issue new state implementation plans (SIPs) including mercury requirements for existing coal-fired power plants.  The CAMR was vacated and remanded to the Federal EPA by the D.C. Circuit Court of Appeals in 2008.

Under the terms of a consent decree, the Federal EPA is required to issue final maximum achievable control technology (MACT) standards for coal and oil-fired power plants by November 2011.  The Federal EPA has substantial discretion in determining how to structure the MACT standards.  We will urge the Federal EPA to carefully consider all of the options available so that costly and inefficient control requirements are not imposed regardless of unit size, age or other operating characteristics.  However, we have approximately 5,000 MW of older coal units, including 2,000 MW of older coal-fired capacity already subject to control requirements under the NSR consent decree, for which it may be economically inefficient to install scrubbers or other environmental controls.  The timing and ultimate disposition of those units will be affected by: (a) the MACT standards and other environmental regulations, (b) the economics of maintaining the units, (c) demand for electricity, (d) availability and cost of replacement power and (e) regulatory decisions about cost recovery of the remaining investment in those units.

The Federal EPA issued a 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.  CAVR will be implemented
 
6
 
through individual SIPs or, if SIPs are not adequate or are not developed on schedule, through federal implementation plans (FIPs).  The Federal EPA has proposed disapproval of SIPs in a few states, and proposed more stringent control requirements for affected units in those states.  If the Federal EPA takes such action in the states where our facilities are located, it could increase the costs of compliance, accelerate the installation of required controls, and/or force the premature retirement of existing units.

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 and final rules limiting CO 2 emissions from new motor vehicles in May 2010.  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 is reconsidering whether to include CO 2 emissions in a number of stationary source standards, including standards that apply to new and modified electric utility units and announced a settlement agreement to issue proposed new source performance standards for utility boilers.  It is not possible at this time to estimate the costs of compliance with these new standards, but they may be material.

The Federal EPA has also issued new, more stringent national ambient air quality standards (NAAQS) for SO 2 , NO x   and lead, and is currently reviewing the NAAQS for ozone and PM.  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.

Estimated Air Quality Environmental Investments

The CAIR, CAVR and the consent decree signed to settle the NSR litigation require us to make significant additional investments, some of which are estimable.  Our estimates are subject to significant uncertainties and will be affected by any changes in the outcome of several interrelated variables and assumptions, including: (a) the timing of implementation, (b) required levels of reductions, (c) methods for allocation of allowances and (d) our selected compliance alternatives and their costs.  These obligations may also be affected or altered by the development of new regulations described above.  In short, we cannot estimate our compliance costs with certainty and the actual costs to comply could differ significantly from the estimates discussed below.

The CAIR, CAVR and commitments in the consent decree will require installation of additional controls on our power plants through 2020.  We plan to install additional scrubbers on 6,770 MW for SO 2 control.  From 2011 to 2020, we estimate total environmental investment to meet these requirements of $10.6 billion including investment in scrubbers and other SO 2 equipment of approximately $5.9 billion.  These estimates are highly uncertain due to the variability associated with: (a) the states’ implementation of these regulatory programs, including the potential for SIPs or FIPS that impose standards more stringent than CAIR or CAVR, (b) additional rulemaking activities in response to the court decisions remanding the CAIR and CAMR, (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 and (f) other factors.  Associated operational and maintenance expenses will also increase during those years.  We cannot estimate these additional operational and maintenance costs due to the uncertainties described above, but they are expected to be significant.  Estimated construction expenditures are subject to periodic review and modification.

We will seek recovery of expenditures for pollution control technologies, replacement or additional generation and associated operating costs from customers through our regulated rates.  We should be able to recover these expenditures through market prices in deregulated jurisdictions.  If not, those costs could adversely affect future net income, cash flows and possibly financial condition.

Coal Combustion Residual Rule

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 our coal-fired electric generating units.  The rule contains two alternative proposals, one that would impose federal hazardous waste disposal and management
 
7
 
standards on these materials and one that 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.

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.  We estimate that the potential compliance costs associated with the proposed solid waste management alternative could be as high as $3.9 billion for units across the AEP System.  Regulation of these materials as hazardous wastes would significantly increase these costs.  We will seek recovery of expenditures for pollution control technologies and associated costs from customers through our regulated rates (in regulated jurisdictions).  We should be able to recover these expenditures through market prices in deregulated jurisdictions.  If not, these costs could adversely affect future net income, cash flows and possibly financial condition.

Global Warming

National public policy makers and regulators in the 11 states we serve have conflicting views on global warming.  We are focused on taking, in the short term, actions that we see as prudent, 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.

We believe that this is a global issue and that the United States should assume a leadership role in developing a new international approach that will address growing emissions of CO 2 and other greenhouse gases (generally referred to as CO 2 in this discussion) from all nations, including developing countries.  We support a reasonable approach to CO 2 emission reductions that recognizes a reliable and affordable electric supply is vital to economic stability and that allows sufficient time for technology development.  We proposed to national policy makers that national and international policy for reasonable CO 2   controls should involve the following principles:

·
Comprehensiveness
·
Cost-effectiveness
·
Realistic emission reduction objectives
·
Reliable monitoring and verification mechanisms
·
Incentives to develop and deploy CO 2 reduction technologies
·
Removal of regulatory or economic barriers to CO 2 emission reductions
·
Recognition for early actions/investments in CO 2 reduction/mitigation
·
Inclusion of adjustment provisions if largest emitters in developing world do not take action

For additional information on global warming, see Part I of the Annual Report under the headings entitled “Business – General – Environmental and Other Matters – Global Warming.”

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 discussed above.

Our fossil fuel-fired generating units are very 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 impact the ultimate retirement of older, less-efficient, coal-fired units.  To the extent we install additional controls on our generating plants to limit CO 2 emissions and receive regulatory approvals to increase our rates, cost recovery could have a positive effect on future earnings.  Prudently incurred capital investments made by our subsidiaries in
 
8
 
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.  In addition, to the extent our costs are relatively higher than our competitors’ costs, such as operators of nuclear and natural gas based generation, it could reduce our off-system sales or cause us to lose customers in jurisdictions that permit customers to choose their supplier of generation service.

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.  Certain of our states have passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements (including Ohio, Michigan, Texas and Virginia).  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 by an additional 2,000 MW from 2007 levels by 2011.  By the end of 2010, we secured, through power purchase agreements, an additional 1,111 MW of wind power.  To the extent demand for renewable energy from wind power increases, it could have a positive effect on future earnings from our transmission activities.  For example, a project in Texas would build new transmission lines to transport electricity from planned wind energy generation in west Texas to more densely populated areas in eastern Texas.

We have taken measurable, voluntary actions to reduce and offset our CO 2 emissions.  We participated in a number of voluntary programs to monitor, mitigate and reduce CO 2 emissions, but many of these programs have been discontinued due to anticipated legislative or regulatory actions.  Through the end of 2009, we reduced our emissions by a cumulative 94 million metric tons from adjusted baseline levels in 1998 through 2001 as a result of these voluntary actions.  Our total CO 2 emissions in 2009 were 136 million metric tons.  We estimate that our 2010 emissions were approximately 140 million metric tons.

Certain groups have filed lawsuits alleging that emissions of CO 2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others.  We have been named in pending lawsuits, which we are vigorously defending.  It is not possible to predict the outcome of these lawsuits or their impact on our operations or financial condition.  See “Carbon Dioxide Public Nuisance Claims” and “Alaskan Villages’ Claims” sections of Note 6.

Future federal and state legislation or regulations that mandate limits on the emission of CO 2 would 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.  As a result, mandatory limits could have a material adverse impact on our net income, cash flows and financial condition.

Global warming creates the potential for physical and financial risk.  The materiality of the risks depends on whether any physical changes occur quickly or over several decades and the extent and nature of those changes.  Physical risks from climate change could include changes in weather conditions.  Our customers’ energy needs currently vary with weather conditions, primarily temperature and humidity.  For residential customers, heating and cooling today represent their largest energy use.  To the extent weather patterns change significantly, customers’ energy use could increase or decrease depending on the duration and magnitude of any changes.  Increased energy use due to weather changes could require us to invest in more generating assets, transmission and other infrastructure to serve increased load, driving the overall cost of electricity higher.  Decreased energy use due to weather changes could affect our financial condition through lower sales and decreased revenues.  Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions and increased storm restoration costs.  We may not recover all costs related to mitigating these physical and financial risks.  Weather conditions outside of our service territory could also have an impact on our revenues, either directly through changes in the patterns of our off-system power purchases and sales or indirectly through demographic changes as people adapt to changing weather.  We buy and sell electricity depending upon system needs and market opportunities.  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.

 
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To the extent climate change impacts a region’s economic health, it could 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, 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.
 
RESULTS OF OPERATIONS

SEGMENTS

Our primary business is our electric utility operations.  Within our Utility Operations 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.  While our Utility Operations segment remains our primary business segment, other segments include our AEP River Operations segment with significant barging activities and our Generation and Marketing segment, which includes our nonregulated generating, marketing and risk management activities primarily in the ERCOT market area and to a lesser extent Ohio in PJM and MISO.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

Our reportable segments and their related business activities are as follows:

Utility Operations
 
·
Generation of electricity for sale to U.S. retail and wholesale customers.
 
·
Electricity transmission and distribution in the U.S.

AEP River Operations
 
·
Commercial barging operations that annually transport approximately 39 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.  Approximately 46% of the barging is for transportation of agricultural products, 25% for coal, 11% for steel and 18% for other commodities.

Generation and Marketing
 
·
Wind farms and marketing and risk management activities primarily in ERCOT and to a lesser extent Ohio in PJM and MISO.

The table below presents our consolidated Income (Loss) Before Discontinued Operations and Extraordinary Loss by segment for the years ended December 31, 2010, 2009 and 2008.

 
Years Ended December 31,
 
 
2010
 
2009
 
2008
 
 
(in millions)
 
Utility Operations
  $ 1,201     $ 1,329     $ 1,123  
AEP River Operations
    37       47       55  
Generation and Marketing
    25       41       65  
All Other (a)
    (45 )     (47 )     133  
Income Before Discontinued Operations and Extraordinary Loss
  $ 1,218     $ 1,370     $ 1,376  

(a)
While not considered a business segment, All Other includes:
 
·
Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense, and other nonallocated costs.
 
·
Tax and interest expense adjustments related to our UK operations which were sold in 2004 and 2002.
 
·
Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005.  These contracts are financial derivatives which settle and expire in 2011.
 
·
The 2008 cash settlement of a purchase power and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in 2006.  The cash settlement of $255 million ($ 164 million, net of tax) is included in Net Income.
 
·
Revenue sharing related to the Plaquemine Cogeneration Facility.

 
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AEP CONSOLIDATED

2010 Compared to 2009

Income Before Discontinued Operations and Extraordinary Loss in 2010 decreased $152 million compared to 2009 primarily due to $185 million of charges incurred (net of tax) related to cost reduction initiatives.  In 2010, we conducted cost reduction initiatives to reduce both labor and non-labor expenses.

Average basic shares outstanding increased to 479 million in 2010 from 459 million in 2009 primarily due to the April 2009 issuance of 69 million shares of AEP common stock.  Actual shares outstanding were 481 million as of December 31, 2010.

2009 Compared to 2008

Income Before Discontinued Operations and Extraordinary Loss in 2009 decreased $6 million compared to 2008 primarily due to income in 2008 from the cash settlement of a purchase power and sale agreement with TEM offset by an increase in income from our Utility Operations segment.  The increase in Utility Operations segment net income primarily relates to rate increases in our Indiana, Ohio, Oklahoma and Virginia service territories partially offset by lower industrial sales as well as lower off-system sales margins due to lower sales volumes and lower market prices.

Average basic shares outstanding increased to 459 million in 2009 from 402 million in 2008 primarily due to the April 2009 issuance of 69 million shares of AEP common stock.  Actual shares outstanding were 478 million as of December 31, 2009.

Our results of operations are discussed below by operating segment.

UTILITY OPERATIONS

We believe that a discussion of the results from our Utility Operations segment on a gross margin basis is most appropriate in order to further understand the key drivers of the segment.  Gross margin represents total revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances and purchased power.

 
 
Years Ended December 31,
 
 
 
2010
   
2009
   
2008
 
 
 
(in millions)
 
Total Revenues
  $ 13,791     $ 12,803     $ 13,566  
Fuel and Purchased Power
    4,996       4,420       5,622  
Gross Margin
    8,795       8,383       7,944  
Depreciation and Amortization
    1,598       1,561       1,450  
Other Operating Expenses
    4,573       4,162       4,114  
Operating Income
    2,624       2,660       2,380  
Other Income, Net
    169       138       173  
Interest Expense
    942       916       915  
Income Tax Expense
    650       553       515  
Income Before Discontinued Operations and Extraordinary Loss
  $ 1,201     $ 1,329     $ 1,123  

 
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KWH Sales/Degree Days
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Summary of KWH Energy Sales for Utility Operations
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
2010 
 
2009 
 
2008 
 
 
(in millions of KWH)
Retail:
 
 
 
 
 
 
 
 
 
Residential
 
 61,944 
 
 
 58,232 
 
 
 58,892 
 
Commercial
 
 50,748 
 
 
 49,925 
 
 
 50,382 
 
Industrial
 
 57,333 
 
 
 54,428 
 
 
 64,508 
 
Miscellaneous
 
 3,083 
 
 
 3,048 
 
 
 3,114 
Total Retail (a)
 
 173,108 
 
 
 165,633 
 
 
 176,896 
 
Wholesale
 
 32,581 
 
 
 29,670 
 
 
 43,068 
 
 
 
 
 
 
 
 
 
Total KWHs
 
 205,689 
 
 
 195,303 
 
 
 219,964 
 
 
 
 
 
 
 
 
 
 
(a)  Includes energy delivered to customers served by AEP's Texas Wires Companies.

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 Utility Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2010 
 
2009 
 
2008 
 
 
 
(in degree days)
 
Eastern Region
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 3,222 
 
 
 3,018 
 
 
 3,154 
 
Normal - Heating (b)
 
 2,983 
 
 
 3,040 
 
 
 3,018 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 1,307 
 
 
 816 
 
 
 949 
 
Normal - Cooling (b)
 
 1,002 
 
 
 1,011 
 
 
 986 
 
 
 
 
 
 
 
 
 
 
 
 
Western Region
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 1,112 
 
 
 970 
 
 
 992 
 
Normal - Heating (b)
 
 980 
 
 
 984 
 
 
 1,010 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (d)
 
 2,515 
 
 
 2,439 
 
 
 2,252 
 
Normal - Cooling (b)
 
 2,339 
 
 
 2,344 
 
 
 2,320 
 
 
 
 
 
 
 
 
 
 
 
 
(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 cooling degree days are calculated on a 65 degree temperature base.
 
(d)
Western Region cooling degree days are calculated on a 65 degree temperature base for PSO/SWEPCo and
 
 
 a 70 degree temperature base for TCC/TNC.

 
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2010 Compared to 2009
 
 
Reconciliation of Year Ended December 31, 2009 to Year Ended December 31, 2010
Income from Utility Operations Before Discontinued Operations and Extraordinary Loss
(in millions)
 
 
 
 
Year Ended December 31, 2009
 
$
 1,329 
 
 
 
 
Changes in Gross Margin:
 
 
 
Retail Margins
 
 
 601 
Off-system Sales
 
 
 53 
Transmission Revenues
 
 
 15 
Other Revenues
 
 
 (257)
Total Change in Gross Margin
 
 
 412 
 
 
 
 
Total Expenses and Other:
 
 
 
Other Operation and Maintenance
 
 
 (351)
Depreciation and Amortization
 
 
 (37)
Taxes Other Than Income Taxes
 
 
 (60)
Interest and Investment Income
 
 
 5 
Carrying Costs Income
 
 
 23 
Allowance for Equity Funds Used During Construction
 
 
 (5)
Interest Expense
 
 
 (26)
Equity Earnings of Unconsolidated Subsidiaries
 
 
 8 
Total Expenses and Other
 
 
 (443)
 
 
 
 
Income Tax Expense
 
 
 (97)
 
 
 
 
Year Ended December 31, 2010
 
$
 1,201 

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 power were as follows:

·
Retail Margins increased $601 million primarily due to the following:
 
·
Successful rate proceedings in our service territories which include:
   
·
A $138 million increase in the recovery of E&R costs in Virginia, costs related to the Transmission Rate Adjustment Clause in Virginia and construction financing costs in West Virginia.
   
·
A $49 million increase in the recovery of advanced metering costs in Texas.
   
·
A $43 million net rate increase for KPCo.
   
·
A $42 million net rate increase for SWEPCo.
   
·
A $39 million net rate increase for I&M.
   
·
A $37 million net rate increase for PSO.
   
·
A $14 million net rate increase in our other jurisdictions.
   
·
For the increases described above, $183 million of these increases relate to riders/trackers which have corresponding increases in other expense items.
 
·
A $229 million increase in weather-related usage primarily due to a 60% increase in cooling degree days in our eastern service territory and 7% and 15% increases in heating degree days in our eastern and western service territories, respectively.
 
·
A $78 million increase due to higher fuel and purchased power costs recorded in 2009 related to the Cook Plant Unit 1 (Unit 1) shutdown.  This increase was offset by a corresponding decrease in Other Revenues as discussed below.
 
These increases were partially offset by:
 
·
A $43 million decrease due to a refund provision for the 2009 Significantly Excessive Earnings Test (SEET).
 
·
A $38 million decrease due to the termination of an I&M unit power agreement.
 
 
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·
Margins from Off-system Sales increased $53 million primarily due to increased prices and higher physical sales volumes in our eastern service territory, partially offset by lower trading and marketing margins.
·
Transmission Revenues increased $15 million primarily due to increased revenues in the ERCOT, PJM and SPP regions.
·
Other Revenues decreased $257 million primarily due to the Cook Plant accidental outage insurance proceeds of $185 million which ended when Unit 1 returned to service in December 2009.  I&M reduced customer bills by approximately $78 million in 2009 for the cost of replacement power resulting from the Unit 1 outage.  This decrease in insurance proceeds was offset by a corresponding increase in Retail Margins as discussed above.  Other Revenues also decreased due to lower gains on sales of emission allowances of $29 million, partially offset by sharing with customers in certain fuel clauses.  This decrease in gains on sales of emission allowances was the result of lower market prices.

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

·
Other Operation and Maintenance expenses increased $351 million primarily due to the following:
 
·
A $280 million increase due to expenses related to the cost reduction initiatives.  In 2010, management conducted cost reduction initiatives to reduce both labor and non-labor expenses.
 
·
A $114 million increase in demand side management, energy efficiency and vegetation management programs and other related expenses.    All of these expenses are currently recovered dollar-for-dollar in rate recovery riders/trackers in Gross Margin.
 
·
A $54 million increase due to the write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the Virginia SCC.
 
These increases were partially offset by:
 
·
An $89 million decrease in storm expenses.
·
Depreciation and Amortization increased $37 million primarily due to new environmental improvements placed in service at APCo, CSPCo and OPCo and placing the Stall Unit in service at SWEPCo partially offset by lower depreciation in Arkansas and Texas as a result of SWEPCo’s recent base rate orders.
·
Taxes Other Than Income Taxes increased $60 million primarily due to the employer portion of payroll taxes incurred related to the cost reduction initiatives and higher franchise and property taxes.
·
Carrying Costs Income increased $23 million primarily due to environmental construction in Virginia and a higher under-recovered fuel balance for OPCo.
·
Interest Expense increased $26 million primarily due to an increase in long-term debt and a decrease in the debt component of AFUDC due to completed environmental improvements at APCo, CSPCo and OPCo.
·
Income Tax Expense increased $97 million primarily due to the regulatory accounting treatment of state income taxes, other book/tax differences which are accounted for on a flow-through basis and the tax treatment associated with the future reimbursement of Medicare Part D prescription drug benefits, partially offset by a decrease in pretax book income.
 
 
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2009 Compared to 2008
 
 
Reconciliation of Year Ended December 31, 2008 to Year Ended December 31, 2009
Income from Utility Operations Before Discontinued Operations and Extraordinary Loss
(in millions)
 
 
 
 
Year Ended December 31, 2008
 
$
 1,123 
 
 
 
 
Changes in Gross Margin:
 
 
 
Retail Margins
 
 
 549 
Off-system Sales
 
 
 (333)
Transmission Revenues
 
 
 25 
Other Revenues
 
 
 198 
Total Change in Gross Margin
 
 
 439 
 
 
 
 
Total Expenses and Other:
 
 
 
Other Operation and Maintenance
 
 
 (46)
Depreciation and Amortization
 
 
 (111)
Taxes Other Than Income Taxes
 
 
 (2)
Interest and Investment Income
 
 
 (38)
Carrying Costs Income
 
 
 (36)
Allowance for Equity Funds Used During Construction
 
 
 37 
Interest Expense
 
 
 (1)
Equity Earnings of Unconsolidated Subsidiaries
 
 
 2 
Total Expenses and Other
 
 
 (195)
 
 
 
 
Income Tax Expense
 
 
 (38)
 
 
 
 
Year Ended December 31, 2009
 
$
 1,329 

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 power were as follows:

·
Retail Margins increased $549 million primarily due to the following:
 
·
Successful rate proceedings in our service territories which include:
   
·
A $187 million increase related to the PUCO’s approval of our Ohio ESPs.
   
·
A $170 million increase related to base rates and recovery of E&R costs in Virginia and construction financing costs in West Virginia.
   
·
A $75 million net rate increase for PSO.
   
·
A $42 million net rate increase for I&M.
   
·
A $50 million net rate increase in our other jurisdictions.
 
·
A $201 million increase in fuel margins in Ohio primarily due to the deferral of fuel costs by CSPCo and OPCo in 2009.  The PUCO’s March 2009 approval of CSPCo’s and OPCo’s ESPs allows for the deferral of fuel and related costs related to the ESP period.
 
·
A $102 million increase due to the December 2008 provision for refund of off-system sales margins as ordered by the FERC related to the SIA.
 
·
A $68 million increase due to lower PJM and other costs as the result of lower generation sales.
 
These increases were partially offset by:
 
·
A $214 million decrease in margins from industrial sales due to reduced operating levels and suspended operations by certain large industrial customers in our service territories.
 
·
A $78 million decrease in fuel margins due to higher fuel and purchased power costs related to the Cook Plant Unit 1 shutdown.  This decrease in fuel margins was offset by a corresponding increase in Other Revenues as discussed below.
 
·
A $52 million decrease in weather-related usage primarily due to a 14% decrease in cooling degree days in our eastern service territory.
 
·
A $29 million decrease related to favorable coal contract amendments in 2008.
 
 
15
 
 
  ·   Margins from Off-system Sales decreased $333 million primarily due to lower physical sales volumes and lower margins in our eastern service territory reflecting lower market prices, partially offset by higher trading and marketing margins.
·
Transmission Revenues increased $25 million primarily due to increased rates in the ERCOT and SPP regions.
·
Other Revenues increased $198 million primarily due to the Cook Plant accidental outage insurance proceeds of $185 million which ended when Unit 1 returned to service in December 2009.  I&M reduced customer bills by approximately $78 million in 2009 for the cost of replacement power resulting during the outage period.  This decrease in insurance proceeds was offset by a corresponding increase in Retail Margins as discussed above.

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

·
Other Operation and Maintenance expenses increased $46 million primarily due to the following:
 
·
The 2008 deferral of $74 million of previously expensed Oklahoma ice storm costs resulting from an OCC order approving recovery of January and December 2007 ice storm expenses.
 
·
A $64 million increase in administrative and general expenses primarily for employee benefits.
 
·
A $48 million increase in storm restoration expenses due to the December 2009 winter storm in Tennessee, Virginia and West Virginia.
 
·
A $32 million increase in demand side management, energy efficiency and vegetation management programs.
 
·
A $29 million increase in recoverable transmission service expenses.
 
·
A $14 million increase due to the completion of reliability deferrals in Virginia in December 2008 and the decrease of environmental deferrals in Virginia in 2009.
 
These increases were partially offset by:
 
·
A $67 million decrease in distribution and customer account expenses.
 
·
A $51 million decrease in transmission expenses related to cost recovery rider amortization in Ohio and rate adjustment clause deferrals in Virginia.
 
·
A $43 million decrease in other operating expenses including lower charitable contributions.
 
·
A $39 million decrease in RTO fees, forestry and other transmission expenses.
 
·
A $15 million decrease in plant outages and other plant operating and maintenance expenses, including lower removal costs.
·
Depreciation and Amortization increased $111 million primarily due to higher depreciable property balances as the result of environmental improvements placed in service at OPCo and various other property additions and higher depreciation rates for OPCo related to shortened depreciable lives for certain generating facilities.
·
Interest and Investment Income decreased $38 million primarily due to lower interest income related to federal income tax refunds filed with the IRS and the recognition of other-than-temporary losses related to equity investments held by our protected cell of EIS in 2009.
·
Carrying Costs Income decreased $36 million primarily due to the completion of reliability deferrals in Virginia in December 2008 and the decrease of environmental deferrals in Virginia in 2009.
·
Allowance for Equity Funds Used During Construction increased $37 million as a result of construction at SWEPCo’s Turk Plant and Stall Unit and the reapplication of “Regulated Operations” accounting guidance for the generation portion of SWEPCo’s Texas retail jurisdiction effective the second quarter of 2009.
·
Interest Expense increased $1 million primarily due to a $52 million increase in interest expense related to increased long-term debt borrowings partially offset by interest expense of $47 million recorded in 2008 related to the 2008 SIA adjustment for off-system sales margins in accordance with the FERC’s 2008 order.
·
Income Tax Expense increased $38 million primarily due to an increase in pretax book income offset by the regulatory accounting treatment of state income taxes and other book/tax differences which are accounted for on a flow-through basis.

 
16
 
AEP RIVER OPERATIONS

2010 Compared to 2009

Income Before Discontinued Operations and Extraordinary Loss from our AEP River Operations segment decreased from $47 million in 2009 to $37 million in 2010 primarily due to expenses related to cost reduction initiatives, increased interest expense on new equipment financing, a property casualty loss in 2010 and a gain on the sale of two older towboats in 2009.

2009 Compared to 2008

Income Before Discontinued Operations and Extraordinary Loss from our AEP River Operations segment decreased from $55 million in 2008 to $47 million in 2009 primarily due to lower revenues as a result of a weak import market.

GENERATION AND MARKETING

2010 Compared to 2009

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment decreased from $41 million in 2009 to $25 million in 2010 primarily due to reduced inception gains from ERCOT marketing activities, reduced plant performance due to lower power prices in ERCOT, partially offset by positive hedging activities on our generation assets and increased income from our wind farm operations.

2009 Compared to 2008

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment decreased from $65 million in 2008 to $41 million in 2009 primarily due to lower gross margins at the Oklaunion Generating Station as a result of lower power prices in ERCOT and decreased generation from our wind farm operations.

ALL OTHER

2010 Compared to 2009

Income Before Discontinued Operations and Extraordinary Loss from All Other increased from a loss of $47 million in 2009 to a loss of $45 million in 2010 primarily due to gains on the sale of our remaining shares of Intercontinental Exchange, Inc. (ICE) and a decrease in various parent related expenses partially offset by a contribution to AEP’s charitable foundation and losses on the sales of assets.

2009 Compared to 2008

Income Before Discontinued Operations and Extraordinary Loss from All Other decreased from income of $133 million in 2008 to a loss of $47 million in 2009.  In 2008, we had after-tax income of $164 million from a litigation settlement of a purchase power and sale agreement with TEM.

AEP SYSTEM INCOME TAXES

2010 Compared to 2009

Income Tax Expense increased $68 million in comparison to 2009 primarily due to the regulatory accounting treatment of state income taxes, other book/tax differences which are accounted for on a flow-through basis and the tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits, offset in part by a decrease in pretax book income.


 
17
 
 
2009 Compared to 2008

Income Tax Expense decreased $67 million in comparison to 2008 primarily due to a decrease in pretax book income and the regulatory accounting treatment of state income taxes and other book/tax differences which are accounted for on a flow-through basis.

FINANCIAL CONDITION
 
We measure our financial condition by the strength of our balance sheet and the liquidity provided by our cash flows.  Target debt to equity ratios are usually maintained for each subsidiary and often credit arrangements contain ratios as covenants that must be met for borrowing to continue.

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

 
 
December 31,
 
 
2010 
 
2009 
 
 
(dollars in millions)
Long-term Debt, including amounts due within one year
$
 16,811 
 
 52.8 
%
 
$
 17,498 
 
 56.8 
%
Short-term Debt
 
 1,346 
 
 4.2 
 
 
 
 126 
 
 0.4 
 
Total Debt
 
 18,157 
 
 57.0 
 
 
 
 17,624 
 
 57.2 
 
Preferred Stock of Subsidiaries
 
 60 
 
 0.2 
 
 
 
 61 
 
 0.2 
 
AEP Common Equity
 
 13,622 
 
 42.8 
 
 
 
 13,140 
 
 42.6 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Debt and Equity Capitalization
$
 31,839 
 
 100.0 
%
 
$
 30,825 
 
 100.0 
%

Our ratio of debt-to-total capital decreased from 57.2% in 2009 to 57% in 2010 primarily due to an increase in common equity.

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.  At December 31, 2010, we had $3.4 billion in aggregate credit facility commitments to support our operations.  Additional liquidity is available from cash from operations and a sale of receivables 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.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  At December 31, 2010, our available liquidity was approximately $2.5 billion as illustrated in the table below:

 
 
 
Amount
 
 
Maturity
 
 
 
(in millions)
 
 
 
 
 
 
 
 
 
 
 
Commercial Paper Backup:
 
 
 
 
 
 
 
Revolving Credit Facility
 
$
 1,454 
 
 
April 2012
 
Revolving Credit Facility
 
 
 1,500 
 
 
June 2013
Revolving Credit Facility
 
 
 478 
 
 
April 2011
Total
 
 
 3,432 
 
 
 
Cash and Cash Equivalents
 
 
 294 
 
 
 
Total Liquidity Sources
 
 
 3,726 
 
 
 
Less:
AEP Commercial Paper Outstanding
 
 
 650 
 
 
 
 
Letters of Credit Issued
 
 
 601 
 
 
 
 
 
 
 
 
 
 
 
Net Available Liquidity
 
$
 2,475 
 
 
 
 
 
 
 
 
 
 
 

 
 
18
 
We have credit facilities totaling $3.4 billion, of which two $1.5 billion credit facilities support our commercial paper program.  In June 2010, we terminated one of the $1.5 billion credit facilities that was scheduled to mature in March 2011 and replaced it with a new $1.5 billion credit facility which matures in 2013.  These credit facilities also allow us to issue letters of credit in an amount up to $1.35 billion.  In June 2010, we also reduced the credit facility that matures in April 2011 from $627 million to $478 million.  This facility is fully utilized for letters of credit providing liquidity support for Pollution Control Bonds.  In March 2011, we intend to replace the revolving credit facility of $478 million with bilateral letters of credit or refinance the bonds.  We may redeem some portion of the Pollution Control Bonds supported by the facility.

We use our commercial paper program to meet the short-term borrowing needs of the 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 2010 was $868 million.  The weighted-average interest rate for our commercial paper during 2010 was 0.43%.

Securitized Accounts Receivables

In 2010, we renewed our receivables securitization agreement.  The agreement provides a commitment of $750 million from bank conduits to purchase receivables.  A commitment of $375 million expires in July 2011 and the remaining commitment of $375 million expires in July 2013.  We intend to extend or replace the agreement expiring in July 2011 on or before its maturity.
 
Debt Covenants and Borrowing Limitations

Our revolving 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 revolving credit agreements. At December 31, 2010, this contractually-defined percentage was 53.3%.  Nonperformance under these covenants could result in an event of default under these credit agreements.  At December 31, 2010, 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 and in a majority of our non-exchange traded commodity contracts which would permit the 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 revolving 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.  At December 31, 2010, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.46 per share in January 2011.  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, charter provisions and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.

We have the option to defer interest payments on the AEP Junior Subordinated Debentures for one or more periods of up to 10 consecutive years per period.  During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.

We do not believe restrictions related to our various financing arrangements, charter provisions and regulatory requirements will have any significant impact on Parent’s ability to access cash to meet the payment of dividends on its common stock.


 
19
 
 
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,
 
 
 
2010
   
2009
   
2008
 
 
 
(in millions)
 
Cash and Cash Equivalents at Beginning of Period
  $ 490     $ 411     $ 178  
Net Cash Flows from Operating Activities
    2,662       2,475       2,581  
Net Cash Flows Used for Investing Activities
    (2,523 )     (2,916 )     (4,027 )
Net Cash Flows from (Used for) Financing Activities
    (335 )     520       1,679  
Net Increase (Decrease) in Cash and Cash Equivalents
    (196 )     79       233  
Cash and Cash Equivalents at End of Period
  $ 294     $ 490     $ 411  

Cash from operations and short-term borrowings provides working capital and allows us to meet other short-term cash needs.
 
Operating Activities
 
 
 
   
 
   
 
 
 
Years Ended December 31,
 
 
2010
 
2009
 
2008
 
 
(in millions)
 
Net Income
  $ 1,218     $ 1,365     $ 1,388  
Depreciation and Amortization
    1,641       1,597       1,483  
Other
    (197 )     (487 )     (290 )
Net Cash Flows from Operating Activities
  $ 2,662     $ 2,475     $ 2,581  

Net Cash Flows from Operating Activities were $2.7 billion in 2010 consisting primarily of Net Income of $1.2 billion and $1.6 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.  Other includes a $656 million increase in securitized receivables under the application of new accounting guidance for “Transfers and Servicing” related to our sale of receivables agreement.  Significant changes in other items include an increase in under-recovered fuel primarily due to the deferral of fuel under the FAC in Ohio and higher fuel costs in Oklahoma, accrued tax benefits and the favorable impact of a decrease in fuel inventory.  Deferred Income Taxes increased primarily due to a change in tax versus book temporary differences from operations.  Accrued Taxes, Net increased primarily as a result of the receipt of a federal income tax refund of $419 million related to a net operating loss in 2009 that was carried back to 2007 and 2008.  We also contributed $500 million to our qualified pension trust in 2010.

Net Cash Flows from Operating Activities were $2.5 billion in 2009 consisting primarily of Net Income of $1.4 billion and $1.6 billion of noncash Depreciation and Amortization.  Other represents 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.  Significant changes in other items include the negative impact on cash of an increase in coal inventory reflecting decreased customer demand for electricity, an increase in under-recovered fuel primarily in Ohio and West Virginia and an increase in accrued tax benefits resulting from a net income tax operating loss in 2009.  Deferred Income Taxes increased primarily due to the American Recovery and Reinvestment Act of 2009 extending bonus depreciation provisions, a one-time change in tax accounting method and an increase in tax versus book temporary differences from operations.

 
20
 
Net Cash Flows from Operating Activities were $2.6 billion in 2008 consisting primarily of Net Income of $1.4 billion and $1.5 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.  Net Cash Flows from Operating Activities increased in 2008 due to the TEM settlement.  Under-recovered fuel costs and fuel, materials and supplies inventories increased working capital requirements due to the higher cost of coal and natural gas.  Deferred Income Taxes increased primarily due to the enactment of the Economic Stimulus Act which enhanced expensing
provisions for certain assets placed in service in 2008 and provided for a 50% bonus depreciation provision for certain assets placed in service in 2008.
 
Investing Activities
 
 
 
   
 
   
 
 
 
Years Ended December 31,
 
 
2010
 
2009
 
2008
 
 
(in millions)
 
Construction Expenditures
  $ (2,345 )   $ (2,792 )   $ (3,800 )
Acquisitions of Nuclear Fuel
    (91 )     (169 )     (192 )
Acquisitions of Assets
    (155 )     (104 )     (160 )
Proceeds from Sales of Assets
    187       278       90  
Other
    (119 )     (129 )     35  
Net Cash Flows Used for Investing Activities
  $ (2,523 )   $ (2,916 )   $ (4,027 )

Net Cash Flows Used for Investing Activities were $2.5 billion in 2010 primarily due to Construction Expenditures for environmental, new generation, distribution and transmission investments.  Proceeds from Sales of Assets in 2010 include $139 million for sales of Texas transmission assets to ETT.

Net Cash Flows Used for Investing Activities were $2.9 billion in 2009 primarily due to Construction Expenditures for our new generation, environmental and distribution investments.  Proceeds from Sales of Assets in 2009 includes $104 million relating to the sale of a portion of Turk Plant to joint owners as planned and $95 million for sales of Texas transmission assets to ETT.

Net Cash Flows Used for Investing Activities were $4 billion in 2008 primarily due to Construction Expenditures for distribution, environmental and new generation investments.
 
Financing Activities
 
 
 
   
 
   
 
 
 
Years Ended December 31,
 
 
2010
 
2009
 
2008
 
 
(in millions)
 
Issuance of Common Stock, Net
  $ 93     $ 1,728     $ 159  
Issuance/Retirement of Debt, Net
    497       (360 )     2,266  
Dividends Paid on Common Stock
    (824 )     (758 )     (666 )
Other
    (101 )     (90 )     (80 )
Net Cash Flows from (Used for) Financing Activities
  $ (335 )   $ 520     $ 1,679  

Net Cash Flows Used for Financing Activities were $335 million in 2010.  Our net debt issuances were $497 million.  The net issuances included issuances of $952 million of notes and $326 million of pollution control bonds, a $­­­531 million increase in commercial paper outstanding and retirements of $1.6 billion of notes, $148 million of securitization bonds and $222 million of pollution control bonds.  Our short-term debt securitized by receivables increased $656 million under the application of new accounting guidance for “Transfers and Servicing” related to our sale of receivables agreement.  We paid common stock dividends of $824 million.

Net Cash Flows from Financing Activities were $520 million in 2009.  Issuance of Common Stock, Net of $1.7 billion is comprised of our issuance of 69 million shares of common stock with net proceeds of $1.64 billion and additional shares through our dividend reinvestment, employee savings and incentive programs.  Our net debt retirements were $360 million. The net retirements included the repayment of $2 billion outstanding under our credit facilities and retirement of $816 million of long-term debt and issuances of $1.9 billion of senior unsecured and debt notes and $431 million of pollution control bonds.  We paid common stock dividends of $758 million.

 
21
 
Net Cash Flows from Financing Activities were $1.7 billion in 2008 primarily due to the borrowing under our credit facility to provide liquidity during the 2008 credit market.  We paid common stock dividends of $666 million.

The following financing activities occurred during 2010:

AEP Common Stock:

·  
During 2010, we issued 3 million shares of common stock under our incentive compensation, employee savings and dividend reinvestment plans and received net proceeds of $93 million.

Debt:

·  
During 2010, we issued approximately $1.3 billion of long-term debt, including $650 million of senior notes at interest rates ranging from 3.4% to 6.2%, $150 million of senior notes at a variable interest rate, $326 million of pollution control revenue bonds at interest rates ranging from 2.875% to 5.375%, $84 million of notes at a 4% interest rate and $68 million of notes at a variable interest rate.  The proceeds from these issuances were used to fund long-term debt maturities and our construction programs.
·  
During 2010, we entered into $1 billion of interest rate derivatives and settled $172 million of such transactions.  The settlements resulted in net cash payments of $6 million.  As of December 31, 2010, we had in place $907 million of notional interest rate derivatives designated as cash flow and fair value hedges.

In 2011:

·  
In January 2011, TCC retired $92 million of its outstanding Securitization Bonds.
·  
In January 2011, PSO issued $250 million of 4.4% Senior Unsecured Notes due 2021.
·  
In January 2011, PSO gave notice to retire $200 million of 6% Senior Unsecured Notes due in 2032 on February 28, 2011.
·  
In February 2011, APCo issued $65 million of 2% Pollution Control Bonds due 2041 with a 2012 mandatory put date.
·  
We expect to refinance approximately $1 billion of the $1.3 billion of long-term debt that will mature in 2011.

BUDGETED CONSTRUCTION EXPENDITURES

We forecast approximately $2.5 billion and $2.6 billion of construction expenditures excluding AFUDC and capitalized interest for 2011 and 2012, respectively.  For 2012 through 2014, we forecast annual construction expenditures to average between $2.6 billion and $3.1 billion.  The projected increases are generally the result of required environmental investment to comply with Federal EPA rules and additional transmission spending.  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 estimated expenditures include amounts for completion of the Turk and Dresden Plants.  Both plants are scheduled for completion in 2012.  We resumed work on Dresden in the first quarter of 2011.  The 2011 estimated construction expenditures include generation, transmission and distribution related investments, as well as expenditures for compliance with environmental regulations as follows:

 
Budgeted
 
Construction
 
Expenditures
 
(in millions)
Environmental
  $ 223
Generation
    813
Transmission
    594
Distribution
    776
Other
    100
Total
  $ 2,506

 
22
 
OFF-BALANCE SHEET ARRANGEMENTS

In prior periods, under a limited set of circumstances, we entered into off-balance sheet arrangements for various reasons including accelerating cash collections, reducing operational expenses and spreading risk of loss to third parties.  Our current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements and transfers of customer accounts receivable that we enter in the normal course of business.  The following identifies significant off-balance sheet arrangements:

AEP Credit

AEP Credit has a receivables securitization agreement with bank conduits.  Under this agreement, AEP Credit securitizes an interest in a portion of the receivables it acquires from affiliated utilities with the bank conduits and receives cash.  Effective January 1, 2010, we record the receivables and debt related to AEP Credit on our Consolidated Balance Sheet.
 
At December 31, 2009, AEP Credit had $631 million of securitized receivables outstanding.  See “ASU 2009-16 ‘Transfers and Servicing’ (ASU 2009-16)” section of Note 2.

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 each company are $887 million as of December 31, 2010.

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 $36 million for the remaining railcars as of December 31, 2010.  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.  At December 31, 2010, the maximum potential loss was approximately $25 million ($17 million, net of tax) 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.
 
 
23
 
CONTRACTUAL OBLIGATION INFORMATION

Our contractual cash obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in our footnotes.  The following table summarizes our contractual cash obligations at December 31, 2010:

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)
 
$
 1,346 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 1,346 
Interest on Fixed Rate Portion of Long-term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt (b)
 
 
 909 
 
 
 1,709 
 
 
 1,467 
 
 
 7,778 
 
 
 11,863 
Fixed Rate Portion of Long-term Debt (c)
 
 
 752 
 
 
 2,009 
 
 
 2,431 
 
 
 10,947 
 
 
 16,139 
Variable Rate Portion of Long-term Debt (d)
 
 
 557 
 
 
 150 
 
 
 - 
 
 
 - 
 
 
 707 
Capital Lease Obligations (e)
 
 
 100 
 
 
 159 
 
 
 106 
 
 
 286 
 
 
 651 
Noncancelable Operating Leases (e)
 
 
 306 
 
 
 547 
 
 
 467 
 
 
 1,349 
 
 
 2,669 
Fuel Purchase Contracts (f)
 
 
 2,810 
 
 
 3,974 
 
 
 2,543 
 
 
 3,718 
 
 
 13,045 
Energy and Capacity Purchase Contracts (g)
 
 
 69 
 
 
 199 
 
 
 204 
 
 
 1,101 
 
 
 1,573 
Construction Contracts for Capital Assets (h)
 
 
 1,031 
 
 
 1,407 
 
 
 1,636 
 
 
 3,143 
 
 
 7,217 
Total
 
$
 7,880 
 
$
 10,154 
 
$
 8,854 
 
$
 28,322 
 
$
 55,210 

(a)
Represents principal only excluding interest.
(b)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2010 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 0.29% and 1.31% at December 31, 2010.
(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 contractual obligations for energy and capacity purchase contracts.
(h)
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 $119 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, 2010, we expect to make contributions to our pension plans totaling $158 million in 2011.  Estimated contributions of $158 million in 2012 and $158 million in 2013 may vary significantly based on market returns, changes in actuarial assumptions and other factors.  Based upon the benefit obligation and fair value of assets available to pay pension benefits, our pension plans were 80.3% funded as of December 31, 2010.

 
24
 
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.  At December 31, 2010, 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)
 
$
 601 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 601 
Guarantees of the Performance of Outside Parties (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 65 
 
 
 65 
Guarantees of Our Performance (c)
 
 
 1,457 
 
 
 18 
 
 
 20 
 
 
 41 
 
 
 1,536 
Total Commercial Commitments
 
$
 2,058 
 
$
 18 
 
$
 20 
 
$
 106 
 
$
 2,202 

(a)
We enter into standby letters of credit (LOCs) with third parties.  These LOCs cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits, debt service reserves and variable rate Pollution Control Bonds.  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 $601 million with maturities ranging from January 2011 to November 2011.  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   American Recovery and Reinvestment Tax Act of 2009 provided for several new grant programs, expanded tax credits and extended the 50% bonus depreciation provision enacted in the Economic Stimulus Act of 2008.  The Small Business Jobs Act, enacted in September 2010, included a one-year extension of the 50% bonus depreciation provision.  The Tax Relief, Unemployment Insurance Reauthorization and the Job Creation Act of 2010 extended the life of research and development, employment and several energy tax credits originally scheduled to expire at the end of 2010.  In addition, this act extended the time for claiming bonus depreciation and increased the deduction to 100% starting in September 2010 through 2011 and decreasing the deduction to 50% for 2012.

These enacted provisions will have no material impact on net income or financial condition but will have a favorable impact on cash flows in 2011 and are expected to result in material future cash flow benefits.

TRANSMISSION INITIATIVES

AEP Transmission Company, LLC (Utility Operations segment)

In 2006, we formed AEP Transmission Company, LLC (AEP Transco).  In 2009, AEP Transco formed seven wholly-owned transmission companies.  Upon approval of FERC interim rates, the transmission companies began recognizing revenues in July 2010 for their respective investments in PJM and SPP.  The transmission companies have been established in Ohio, Oklahoma and Michigan.  Applications for establishment of AEP Kentucky Transmission Company, Inc. and AEP West Virginia Transmission Company, Inc. have been filed with the KPSC and the WVPSC, respectively, and are pending approval.  Other filings with commissions will be made in 2011.  These seven companies consist of:

AEP East Transmission companies:
·  
AEP Appalachian Transmission Company, Inc. (covering Virginia)
·  
AEP Indiana Michigan Transmission Company, Inc.
·  
AEP Kentucky Transmission Company, Inc.
·  
AEP Ohio Transmission Company, Inc.
·  
AEP West Virginia Transmission Company, Inc.
AEP West Transmission companies:
·  
AEP Oklahoma Transmission Company, Inc.
·  
AEP Southwestern Transmission Company, Inc. (covering Arkansas and Louisiana)

 
25
 
AEPSC and other AEP subsidiaries provide services to the transmission companies through service agreements.  Therefore, the transmission companies do not have any employees.

AEP Transco owns all of the transmission companies’ equity.  The transmission companies do not have outstanding debt and have not received capital contributions.  All of the transmission companies’ capital needs are provided by Parent and AEP Transco.  For the transmission companies listed above, we forecast approximately $160 million of construction expenditures for 2011.
 
Joint Venture Initiatives (Utility Operations segment)
 
We are currently participating in the following joint venture initiatives:
 
 
 
 
 
 
 
 
Total
 
 
AEP's Equity
 
 
 
 
 
 
 
 
 
 
Estimated
 
 
Method
 
 
 
 
 
 
Projected
 
 
 
Project Costs
 
 
Investment at
 
Approved
Project
 
 
 
Completion
 
Owners
 
at
 
 
December 31,
 
Return on
Name
 
Location
 
Date
 
(Ownership %)
 
Completion
 
 
2010 
 
Equity
 
 
 
 
 
 
 
 
 
(in thousands)
 
 
 
 
ETT
 
Texas
 
2017 
 
MEHC Texas
 
$
 3,100,000 
(a)
 
$
 110,323 
 
 9.96 
%
 
 
 
(ERCOT)
 
 
 
Transco, LLC (50%)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
AEP (50%)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PATH (b)
 
West
 
2015 (c)
 
Allegheny Energy (50%)
 
 
 2,100,000 
(d)
 
 
 23,621 
 
 14.3 
%
(e)
 
 
Virginia
 
 
 
AEP (50%)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prairie Wind
 
Kansas
 
2014 
 
Westar Energy (50%)
 
 
 225,000 
 
 
 
 784 
 
 12.8 
%
 
 
 
 
 
 
 
ETA (50%) (f)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pioneer
 
Indiana
 
2016 
 
Duke Energy (50%)
 
 
 1,000,000 
 
 
 
 - 
 
 12.54 
%
 
 
 
 
 
 
 
AEP (50%)
 
 
 
 
 
 
 
 
 
 
 

(a)
In addition to ETT’s current total estimated project costs of $3.1 billion, ETT plans to invest in additional transmission projects in ERCOT over the next several years.  Future projects will be evaluated on a case-by-case basis.
(b)
In September 2007, AEP Transmission Holding Company, LLC and AET PATH Company, LLC, a subsidiary of Allegheny Energy, Inc., formed a joint venture by creating Potomac-Appalachian Transmission Highline, LLC (PATH) and its subsidiaries.  The PATH subsidiaries will operate as transmission utilities owning certain electric transmission assets within PJM.
(c)
PJM has directed the construction of the PATH Project and placement of the project into service by June 2015, at the latest.
(d)
PATH consists of the “West Virginia Series,” which is owned equally by subsidiaries of Allegheny Energy Inc. and AEP, and the “Allegheny Series” which is wholly-owned by a subsidiary of Allegheny Energy Inc.  The total project is estimated to cost approximately $2.1 billion.  Our estimated share of the project cost is approximately $700 million.  In February 2011, the “Ohio Series” was dissolved, which was owned equally by subsidiaries of Allegheny Energy Inc. and AEP.
(e)
An October 2010 FERC order set the 14.3% return on equity for hearing.
(f)
Electric Transmission America, LLC (ETA) is a 50/50 joint venture with MidAmerican Energy Holdings Company (MEHC) America Transco, LLC and AEP Transmission Holding Company, LLC.  ETA will be utilized as a vehicle to invest in selected transmission projects located in North America, outside of ERCOT.  AEP Transmission Holding Company, LLC owns 25% of Prairie Wind through its ownership interest in ETA.

For our joint ventures listed above, we forecast approximately $113 million of equity contributions in 2011 to support construction and other expenditures.

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 DHLC, CSPCo, through its ownership of Conesville Coal Preparation Company (CCPC), and OPCo, through its use of the Conner Run fly ash impoundment, are subject to the provisions of the Mine Act.

 
26
 
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, CCPC and Conner Run received the following notices of violation and proposed assessments under the Mine Act for the quarter ended December 31, 2010:

 
 
 
DHLC
 
CCPC
 
Conner Run
Number of Citations for Violations of Mandatory Health or Safety Standards under 104 *
 
 
 1 
 
 
 - 
 
 
 - 
Number of Orders Issued under 104(b) *
 
 
 - 
 
 
 - 
 
 
 - 
Number of Citations and Orders for Unwarrantable Failure to Comply with Mandatory Health or
 
 
 
 
 
 
 
 
 
 
Safety Standards under 104(d) *
 
 
 - 
 
 
 - 
 
 
 - 
Number of Flagrant Violations under 110(b)(2) *
 
 
 - 
 
 
 - 
 
 
 - 
Number of Imminent Danger Orders Issued under 107(a) *
 
 
 - 
 
 
 - 
 
 
 - 
Total Dollar Value of Proposed Assessments
 
$
 1,026 
 
$
 - 
 
$
 - 
Number of Mining-related Fatalities
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
 
 
 
 
 
 
 
* References to sections under the Mine Act
 
 
 
 
 
 
 
 
 

DHLC currently has two legal actions pending before the Mine Safety and Health Administration (MSHA) challenging four violations issued by MSHA following an employee fatality in March 2009.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW 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 our consolidated 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 disclosure relating to them.

We believe that the current assumptions and other considerations used to estimate amounts reflected in our consolidated 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 consolidated 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 our expense recognition with the recovery of such expense in regulated revenues.  Likewise, we match income with the regulated revenues from our customers in the same accounting period.  We also record liabilities for refunds, or probable refunds, to customers that have not been made.

 
27
 
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.  Examples of new events 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, 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 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 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 included in Revenue on our Consolidated Statements of Income were $46 million, $55 million and $72 million for the years ended December 31, 2010, 2009 and 2008, respectively.  The increases in unbilled electric revenues are primarily due to rate increases and changes in weather.  Accrued unbilled revenues for the Utility Operations segment were $549 million and $503 million as of December 31, 2010 and 2009, respectively.

Assumptions and Approach Used

For each operating company, we compute the monthly estimate for unbilled revenues as net generation 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.

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.

 
28
 
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 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 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 as approved by our regulators.  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 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.  For assets held for sale, an impairment is recognized if the expected net sales price is less than its book value.  For regulated assets, 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.

 
29
 
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.  We perform depreciation studies to determine composite depreciation rates and related lives which are subject to periodic review by state regulatory commissions.  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 to be paid to 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 medical and life insurance benefits for retired employees (Postretirement Plans).  The Pension Plans and Postretirement Plans are collectively 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.

The following table shows the net periodic cost of the Plans:

 
   
Years Ended December 31,
Net Periodic Benefit Cost
 
2010
 
2009
 
2008
 
 
(in millions)
Pension Plans
    $ 141     $ 96     $ 51
Postretirement Plans
      111       141       80

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 2011, 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.  We anticipate that the investment managers we employ for the Plans will invest the assets to generate future returns averaging 7.75% for the Qualified Plan and 7.5% for the Postretirement Plans.

 
30
 
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/
 
 
2011
 
Expected
 
2011
 
Expected
 
 
Target
 
Long-Term
 
Target
 
Long-Term
 
 
Asset
 
Rate of
 
Asset
 
Rate of
 
 
Allocation
 
Return
 
Allocation
 
Return
Equity
    50 %     9.00 %     66 %     9.00 %
Real Estate
    5 %     7.60 %     - %     - %
Fixed Income
    39 %     5.75 %     32 %     5.75 %
Other Investments
    5 %     10.50 %     - %     - %
Cash and Cash Equivalents
    1 %     3.00 %     2 %     3.00 %
Total
    100 %             100 %        

We regularly review the actual asset allocation and periodically rebalance the investments to our targeted allocation.  We believe that 7.75% for the Pension Plan and 7.5% for the Postretirement Plans are reasonable long-term rates of return on the Plans’ assets despite the recent market volatility.  The Pension Plan’s assets had an actual gain of 13.4% and 17.1% for the years ended December 31, 2010 and 2009, respectively.  The Postretirement Plans’ assets had an actual gain of 11.3% and 23.7% for the years ended December 31, 2010 and 2009, 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, 2010, we had cumulative losses of approximately $285 million that remain to be recognized in the calculation of the market-related value of assets.  These unrecognized net actuarial losses will result in increases in the future pension costs depending on several factors, including whether such losses 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 similar to those included in the Moody’s Aa bond index is constructed with a duration 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 at December 31, 2010 under this method was 5.05% for the Qualified Plan, 4.95% for the Nonqualified Plans and 5.25% for the Postretirement Plans.  Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on the Pension Plans’ assets of 7.75%, discount rates of 5.05% and 4.95% and various other assumptions, we estimate that the pension costs for the Pension Plans will approximate $144 million, $166 million and $194 million in 2011, 2012 and 2013, respectively.  Based on an expected rate of return on the Postretirement Plans’ assets of 7.5%, a discount rate of 5.25% and various other assumptions, we estimate costs will approximate $82 million, $78 million and $74 million in 2011, 2012 and 2013, 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.

The value of the Pension Plan’s assets increased to $3.9 billion at December 31, 2010 from $3.4 billion at December 31, 2009 primarily due to a $500 million contribution.  During 2010, the Qualified Plan paid $465 million and the Nonqualified Plans paid $15 million in benefits to plan participants.  The value of the Postretirement Plans’ assets increased to $1.5 billion at December 31, 2010 from $1.3 billion at December 31, 2009 primarily due to investment gains and contributions.  The Postretirement Plans paid $142 million in benefits to plan participants during 2010.

 
31
 
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
·  
Rate of compensation increase
·  
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:

 
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
+0.5%
 
-0.5%
 
+0.5%
 
-0.5%
 
 
(in millions)
Effect on December 31, 2010 Benefit Obligations
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
$
 (233)
 
$
 256 
 
$
 (132)
 
$
 147 
Compensation Increase Rate
 
 
 11 
 
 
 (10)
 
 
 - 
 
 
 - 
Cash Balance Crediting Rate
 
 
 43 
 
 
 (38)
 
 
N/A
 
 
N/A
Health Care Cost Trend Rate
 
 
N/A
 
 
N/A
 
 
 114 
 
 
 (101)
 
 
 
 
 
 
 
 
 
 
 
 
 
Effect on 2010 Periodic Cost
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
 
 (20)
 
 
 22 
 
 
 (12)
 
 
 14 
Compensation Increase Rate
 
 
 4 
 
 
 (3)
 
 
 1 
 
 
 (1)
Cash Balance Crediting Rate
 
 
 10 
 
 
 (9)
 
 
N/A
 
 
N/A
Health Care Cost Trend Rate
 
 
N/A
 
 
N/A
 
 
 18 
 
 
 (16)
Expected Return on Plan Assets
 
 
 (20)
 
 
 20 
 
 
 (6)
 
 
 6 
 
 
 
 
 
 
 
 
 
 
 
 
 
N/A Not Applicable
 
 
 
 
 
 
 
 
 
 
 
 

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.

We maintain trust funds for each regulatory jurisdiction.  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
 
 
32
 
Decommissioning Trusts on our Consolidated Balance Sheets.  We record these securities at fair value.  We utilize our trustee’s external pricing service in our estimate of the fair value of the underlying investments held in these 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.  See “Investments Held in Trust for Future Liabilities” section of Note 1 and “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11.

NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Pronouncements Adopted During 2010

We adopted ASU 2009-16 “Transfers and Servicing” effective January 1, 2010.  The adoption of this standard resulted in AEP Credit’s transfers of receivables being accounted for as financings with the receivables and short-term debt recorded on our balance sheet.

We adopted the prospective provisions of ASU 2009-17 “Consolidations” effective January 1, 2010.  We no longer consolidate DHLC effective with the adoption of this standard.

See Note 2 for further discussion of 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, contingencies, financial instruments, emission allowances, fair value measurements, leases, insurance, hedge accounting, consolidation policy and discontinued operations.  We also expect to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP.  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 AND CREDIT RISK

Market Risks

Our Utility Operations segment is exposed to certain market risks as a major power producer and transacts in wholesale electricity, coal and emission allowance trading 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 because occasionally we 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 Generation and Marketing segment, operating primarily within ERCOT and to a lesser extent Ohio in PJM and MISO, primarily transacts in wholesale energy marketing contracts.  This segment is exposed to certain market risks as a marketer of wholesale 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.

All Other includes natural gas operations which holds forward natural gas contracts that were not sold with the natural gas pipeline and storage assets.  These contracts are financial derivatives, which gradually settle and completely expire in 2011.  Our risk objective is to keep these positions generally risk neutral through maturity.

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 electricity, coal, natural gas and emission allowances and to a lesser degree other commodities 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 group in accordance with the market risk policy 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 (CORC) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures.  The CORC consists of our President, Chief Financial Officer, 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 CORC.

 
33
 
The following table summarizes the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2009:

 
MTM Risk Management Contract Net Assets (Liabilities)
 
Year Ended December 31, 2010
 
 
 
 
Generation
 
 
 
 
 
 
Utility
and
 
 
 
 
Operations
Marketing
All Other
Total
 
 
(in millions)
Total MTM Risk Management Contract Net Assets (Liabilities)
 
 
 
 
 
 
 
 
 
 
 
 
at December 31, 2009
$
 134 
 
$
 147 
 
$
 (3)
 
$
 278 
(Gain) Loss from Contracts Realized/Settled During the Period and
 
 
 
 
 
 
 
 
 
 
 
 
Entered in a Prior Period
 
 (81)
 
 
 (16)
 
 
 5 
 
 
 (92)
Fair Value of New Contracts at Inception When Entered During the
 
 
 
 
 
 
 
 
 
 
 
 
Period (a)
 
 17 
 
 
 8 
 
 
 - 
 
 
 25 
Net Option Premiums Received for Unexercised or Unexpired
 
 
 
 
 
 
 
 
 
 
 
 
Option Contracts Entered During the Period
 
 (1)
 
 
 - 
 
 
 - 
 
 
 (1)
Changes in Fair Value Due to Valuation Methodology Changes on
 
 
 
 
 
 
 
 
 
 
 
 
Forward Contracts (b)
 
 (2)
 
 
 (2)
 
 
 - 
 
 
 (4)
Changes in Fair Value Due to Market Fluctuations During the
 
 
 
 
 
 
 
 
 
 
 
 
Period (c)
 
 6 
 
 
 3 
 
 
 - 
 
 
 9 
Changes in Fair Value Allocated to Regulated Jurisdictions (d)
 
 18 
 
 
 - 
 
 
 - 
 
 
 18 
Total MTM Risk Management Contract Net Assets
 
 
 
 
 
 
 
 
 
 
 
 
at December 31, 2010
$
 91 
 
$
 140 
 
$
 2 
 
 
 233 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Cash Flow Hedge Contracts
 
 
 
 
 
 
 
 
 
 
 11 
Interest Rate and Foreign Currency Cash Flow Hedge Contracts
 
 
 
 
 
 
 
 
 
 
 21 
Fair Value Hedge Contracts
 
 
 
 
 
 
 
 
 
 
 6 
Collateral Deposits
 
 
 
 
 
 
 
 
 
 
 101 
Total MTM Derivative Contract Net Assets at December 31, 2010
 
 
 
 
 
 
 
 
 
$
 372 

(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)
Reflects changes in methodology in calculating the credit and discounting liability fair value adjustments.
(c)
Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(d)
Relates to the net gains (losses) of those contracts that are not reflected on the Consolidated 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.
 
 
34
 
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, 2010, our credit exposure net of collateral to sub investment grade counterparties was approximately 5.3%, 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, 2010, 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
 
$
 666 
 
$
 19 
 
$
 647 
 
 
 1 
 
$
 189 
Split Rating
 
 
 2 
 
 
 - 
 
 
 2 
 
 
 1 
 
 
 2 
Noninvestment Grade
 
 
 4 
 
 
 3 
 
 
 1 
 
 
 2 
 
 
 1 
No External Ratings:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Internal Investment Grade
 
 
 215 
 
 
 - 
 
 
 215 
 
 
 2 
 
 
 123 
 
Internal Noninvestment Grade
 
 
 59 
 
 
 11 
 
 
 48 
 
 
 1 
 
 
 32 
Total as of December 31, 2010
 
$
 946 
 
$
 33 
 
$
 913 
 
 
 7 
 
$
 347 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total as of December 31, 2009
 
$
 846 
 
$
 58 
 
$
 788 
 
 
 12 
 
$
 317 

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, 2010, a near term typical change in commodity prices is not expected to have a material effect on our 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, 2010
       
December 31, 2009
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
(in millions)
       
(in millions)
$-
 
$2
 
$1
 
$-
       
$1
 
$2
 
$1
 
$-

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.

 
35
 
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 four 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 or the CORC 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, 2010 and 2009, the estimated EaR on our debt portfolio for the following twelve months was $5 million and $4 million, respectively.

 
36
 


 
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, 2010 and 2009, and the related consolidated statements of income, changes in equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010.  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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
 
 
As discussed in Note 2 to the consolidated financial statements, the Company adopted FASB Accounting Standards Update No. 2009-16, Transfers and Servicing (Topic 860): Accounting for Transfers of Financial Assets , effective January 1, 2010.
 
 
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, 2010, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2011 expressed an unqualified opinion on the Company's internal control over financial reporting.
 
 
/s/ Deloitte & Touche LLP
 
 
Columbus, Ohio
February 25, 2011
 

 
37
 


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, 2010, based on criteria established in Internal Control — Integrated Framework 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, 2010, based on the criteria established in Internal Control — Integrated Framework 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, 2010 of the Company and our report dated February 25, 2011 expressed an unqualified opinion on those financial statements and included an explanatory paragraph relating to the Company’s adoption of a new accounting pronouncement.
 
 
/s/ Deloitte & Touche LLP
 
 
Columbus, Ohio
February 25, 2011

 
38
 

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, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment, AEP’s internal control over financial reporting was effective as of December 31, 2010.

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.

 
39
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 2010, 2009 and 2008
 (in millions, except per-share and share amounts)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2010 
 
2009 
 
2008 
REVENUES
 
 
 
 
 
 
 
 
 
Utility Operations
 
$
 13,687 
 
$
 12,733 
 
$
 13,326 
Other Revenues
 
 
 740 
 
 
 756 
 
 
 1,114 
TOTAL REVENUES
 
 
 14,427 
 
 
 13,489 
 
 
 14,440 
EXPENSES
 
 
 
 
 
 
 
 
 
Fuel and Other Consumables Used for Electric Generation
 
 
 4,029 
 
 
 3,478 
 
 
 4,474 
Purchased Electricity for Resale
 
 
 1,000 
 
 
 1,053 
 
 
 1,281 
Other Operation
 
 
 3,132 
 
 
 2,620 
 
 
 2,856 
Maintenance
 
 
 1,142 
 
 
 1,205 
 
 
 1,053 
Gain on Settlement of TEM Litigation
 
 
 - 
 
 
 - 
 
 
 (255)
Depreciation and Amortization
 
 
 1,641 
 
 
 1,597 
 
 
 1,483 
Taxes Other Than Income Taxes
 
 
 820 
 
 
 765 
 
 
 761 
TOTAL EXPENSES
 
 
 11,764 
 
 
 10,718 
 
 
 11,653 
 
 
 
 
 
 
 
 
 
 
 
OPERATING INCOME
 
 
 2,663 
 
 
 2,771 
 
 
 2,787 
 
 
 
 
 
 
 
 
 
 
 
Other Income (Expense):
 
 
 
 
 
 
 
 
 
Interest and Investment Income
 
 
 38 
 
 
 11 
 
 
 57 
Carrying Costs Income
 
 
 70 
 
 
 47 
 
 
 83 
Allowance for Equity Funds Used During Construction
 
 
 77 
 
 
 82 
 
 
 45 
Interest Expense
 
 
 (999)
 
 
 (973)
 
 
 (957)
 
 
 
 
 
 
 
 
 
 
 
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
 
 
 1,849 
 
 
 1,938 
 
 
 2,015 
 
 
 
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 643 
 
 
 575 
 
 
 642 
Equity Earnings of Unconsolidated Subsidiaries
 
 
 12 
 
 
 7 
 
 
 3 
 
 
 
 
 
 
 
 
 
 
 
INCOME BEFORE DISCONTINUED OPERATIONS AND EXTRAORDINARY LOSS
 
 
 1,218 
 
 
 1,370 
 
 
 1,376 
 
 
 
 
 
 
 
 
 
 
 
DISCONTINUED OPERATIONS, NET OF TAX
 
 
 - 
 
 
 - 
 
 
 12 
 
 
 
 
 
 
 
 
 
 
 
INCOME BEFORE EXTRAORDINARY LOSS
 
 
 1,218 
 
 
 1,370 
 
 
 1,388 
 
 
 
 
 
 
 
 
 
 
 
EXTRAORDINARY LOSS, NET OF TAX
 
 
 - 
 
 
 (5)
 
 
 - 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME
 
 
 1,218 
 
 
 1,365 
 
 
 1,388 
 
 
 
 
 
 
 
 
 
 
 
Less:  Net Income Attributable to Noncontrolling Interests
 
 
 4 
 
 
 5 
 
 
 5 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS
 
 
 1,214 
 
 
 1,360 
 
 
 1,383 
 
 
 
 
 
 
 
 
 
 
 
Less: Preferred Stock Dividend Requirements of Subsidiaries
 
 
 3 
 
 
 3 
 
 
 3 
 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
 1,211 
 
$
 1,357 
 
$
 1,380 
 
 
 
 
 
 
 
 
 
 
 
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
 
 
479,373,306 
 
 
458,677,534 
 
 
402,083,847 
 
 
 
 
 
 
 
 
 
 
 
BASIC EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
 
 
 
 
 
 
 
 
Income Before Discontinued Operations and Extraordinary Loss
 
$
 2.53 
 
$
 2.97 
 
$
 3.40 
Discontinued Operations, Net of Tax
 
 
 - 
 
 
 - 
 
 
 0.03 
Income Before Extraordinary Loss
 
 
 2.53 
 
 
 2.97 
 
 
 3.43 
Extraordinary Loss, Net of Tax
 
 
 - 
 
 
 (0.01)
 
 
 - 
 
 
 
 
 
 
 
 
 
 
 
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
 2.53 
 
$
 2.96 
 
$
 3.43 
 
 
 
 
 
 
 
 
 
 
 
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING
 
 
479,601,442 
 
 
458,982,292 
 
 
403,640,708 
 
 
 
 
 
 
 
 
 
 
 
DILUTED EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
 
 
 
 
 
 
 
 
Income Before Discontinued Operations and Extraordinary Loss
 
$
 2.53 
 
$
 2.97 
 
$
 3.39 
Discontinued Operations, Net of Tax
 
 
 - 
 
 
 - 
 
 
 0.03 
Income Before Extraordinary Loss
 
 
 2.53 
 
 
 2.97 
 
 
 3.42 
Extraordinary Loss, Net of Tax
 
 
 - 
 
 
 (0.01)
 
 
 - 
 
 
 
 
 
 
 
 
 
 
 
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
 
 
 
 
 
 
 
 
 
 
SHAREHOLDERS
 
$
 2.53 
 
$
 2.96 
 
$
 3.42 
 
 
 
 
 
 
 
 
 
 
 
CASH DIVIDENDS PAID PER SHARE
 
$
 1.71 
 
$
 1.64 
 
$
 1.64 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 

 
40
 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2010, 2009 and 2008
(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, 2007
 
 422 
 
$
 2,743 
 
$
 4,352 
 
$
 3,138 
 
$
 (154)
 
$
 18 
 
$
 10,097 
Adoption of Guidance for Split-Dollar Life Insurance
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
   Accounting, Net of Tax of $6
 
 
 
 
 
 
 
 
 
 
 (10)
 
 
 
 
 
 
 
 
 (10)
Adoption of Guidance for Fair Value Accounting,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
   Net of Tax of $0
 
 
 
 
 
 
 
 
 
 
 (1)
 
 
 
 
 
 
 
 
 (1)
Issuance of Common Stock
 
 4 
 
 
 28 
 
 
 131 
 
 
 
 
 
 
 
 
 
 
 
 159 
Reissuance of Treasury Shares
 
 
 
 
 
 
 
 40 
 
 
 
 
 
 
 
 
 
 
 
 40 
Common Stock Dividends
 
 
 
 
 
 
 
 
 
 
 (660)
 
 
 
 
 
 (6)
 
 
 (666)
Preferred Stock Dividend Requirements of Subsidiaries
 
 
 
 
 
 
 
 
 
 
 (3)
 
 
 
 
 
 
 
 
 (3)
Other Changes in Equity
 
 
 
 
 
 
 
 4 
 
 
 
 
 
 
 
 
 
 
 
 4 
SUBTOTAL – EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 9,620 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $2
 
 
 
 
 
 
 
 
 
 
 
 
 
 4 
 
 
 
 
 
 4 
 
 
Securities Available for Sale, Net of Tax of $9
 
 
 
 
 
 
 
 
 
 
 
 
 
 (16)
 
 
 
 
 
 (16)
 
 
Amortization of Pension and OPEB Deferred Costs,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $7
 
 
 
 
 
 
 
 
 
 
 
 
 
 12 
 
 
 
 
 
 12 
 
 
Pension and OPEB Funded Status, Net of Tax of $161
 
 
 
 
 
 
 
 
 
 
 
 
 
 (298)
 
 
 
 
 
 (298)
NET INCOME
 
 
 
 
 
 
 
 
 
 
 1,383 
 
 
 
 
 
 5 
 
 
 1,388 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,090 
TOTAL EQUITY – DECEMBER 31, 2008
 
 426 
 
 
 2,771 
 
 
 4,527 
 
 
 3,847 
 
 
 (452)
 
 
 17 
 
 
 10,710 
Issuance of Common Stock
 
 72 
 
 
 468 
 
 
 1,311 
 
 
 
 
 
 
 
 
 
 
 
 1,779 
Common Stock Dividends
 
 
 
 
 
 
 
 
 
 
 (753)
 
 
 
 
 
 (5)
 
 
 (758)
Preferred Stock Dividend Requirements of Subsidiaries
 
 
 
 
 
 
 
 
 
 
 (3)
 
 
 
 
 
 
 
 
 (3)
Purchase of JMG
 
 
 
 
 
 
 
 37 
 
 
 
 
 
 
 
 
 (18)
 
 
 19 
Other Changes in Equity
 
 
 
 
 
 
 
 (51)
 
 
 
 
 
 
 
 
 1 
 
 
 (50)
SUBTOTAL – EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 11,697 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income, Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $4
 
 
 
 
 
 
 
 
 
 
 
 
 
 7 
 
 
 
 
 
 7 
 
 
Securities Available for Sale, Net of Tax of $6
 
 
 
 
 
 
 
 
 
 
 
 
 
 11 
 
 
 
 
 
 11 
 
 
Reapplication of Regulated Operations Accounting
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Guidance for Pensions, Net of Tax of $8
 
 
 
 
 
 
 
 
 
 
 
 
 
 15 
 
 
 
 
 
 15 
 
 
Amortization of Pension and OPEB Deferred Costs,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $13
 
 
 
 
 
 
 
 
 
 
 
 
 
 23 
 
 
 
 
 
 23 
 
 
Pension and OPEB Funded Status, Net of Tax of $12
 
 
 
 
 
 
 
 
 
 
 
 
 
 22 
 
 
 
 
 
 22 
NET INCOME
 
 
 
 
 
 
 
 
 
 
 1,360 
 
 
 
 
 
 5 
 
 
 1,365 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,443 
TOTAL EQUITY – DECEMBER 31, 2009
 
 498 
 
 
 3,239 
 
 
 5,824 
 
 
 4,451 
 
 
 (374)
 
 
 - 
 
 
 13,140 
Issuance of Common Stock
 
 3 
 
 
 18 
 
 
 75 
 
 
 
 
 
 
 
 
 
 
 
 93 
Common Stock Dividends
 
 
 
 
 
 
 
 
 
 
 (820)
 
 
 
 
 
 (4)
 
 
 (824)
Preferred Stock Dividend Requirements of Subsidiaries
 
 
 
 
 
 
 
 
 
 
 (3)
 
 
 
 
 
 
 
 
 (3)
Other Changes in Equity
 
 
 
 
 
 
 
 5 
 
 
 
 
 
 
 
 
 
 
 
 5 
SUBTOTAL – EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 12,411 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $14
 
 
 
 
 
 
 
 
 
 
 
 
 
 26 
 
 
 
 
 
 26 
 
 
Securities Available for Sale, Net of Tax of $4
 
 
 
 
 
 
 
 
 
 
 
 
 
 (8)
 
 
 
 
 
 (8)
 
 
Amortization of Pension and OPEB Deferred Costs,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $12
 
 
 
 
 
 
 
 
 
 
 
 
 
 22 
 
 
 
 
 
 22 
 
 
Pension and OPEB Funded Status, Net of Tax of $25
 
 
 
 
 
 
 
 
 
 
 
 
 
 (47)
 
 
 
 
 
 (47)
NET INCOME
 
 
 
 
 
 
 
 
 
 
 1,214 
 
 
 
 
 
 4 
 
 
 1,218 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,211 
TOTAL EQUITY – DECEMBER 31, 2010
 
 501 
 
$
 3,257 
 
$
 5,904 
 
$
 4,842 
 
$
 (381)
 
$
 - 
 
$
 13,622 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements.

 
41
 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31, 2010 and 2009
(in millions)
 
 
 
2010 
 
2009 
CURRENT ASSETS
 
 
 
 
 
 
Cash and Cash Equivalents
 
$
 294 
 
$
 490 
Other Temporary Investments
 
 
 
 
 
 
 
(December 31, 2010 amount includes $287 related to Transition Funding and EIS)
 
 
 416 
 
 
 363 
Accounts Receivable:
 
 
 
 
 
 
 
Customers
 
 
 683 
 
 
 492 
 
Accrued Unbilled Revenues
 
 
 195 
 
 
 503 
 
Pledged Accounts Receivable - AEP Credit
 
 
 949 
 
 
 - 
 
Miscellaneous
 
 
 137 
 
 
 92 
 
Allowance for Uncollectible Accounts
 
 
 (41)
 
 
 (37)
 
 
Total Accounts Receivable
 
 
 1,923 
 
 
 1,050 
Fuel
 
 
 837 
 
 
 1,075 
Materials and Supplies
 
 
 611 
 
 
 586 
Risk Management Assets
 
 
 232 
 
 
 260 
Accrued Tax Benefits
 
 
 389 
 
 
 547 
Regulatory Asset for Under-Recovered Fuel Costs
 
 
 81 
 
 
 85 
Margin Deposits
 
 
 88 
 
 
 89 
Prepayments and Other Current Assets
 
 
 145 
 
 
 211 
TOTAL CURRENT ASSETS
 
 
 5,016 
 
 
 4,756 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
 
 
 
 
 
 
Electric:
 
 
 
 
 
 
 
Generation
 
 
 24,352 
 
 
 23,045 
 
Transmission
 
 
 8,576 
 
 
 8,315 
 
Distribution
 
 
 14,208 
 
 
 13,549 
Other Property, Plant and Equipment (including nuclear fuel and coal mining)
 
 
 3,846 
 
 
 3,744 
Construction Work in Progress
 
 
 2,758 
 
 
 3,031 
Total Property, Plant and Equipment
 
 
 53,740 
 
 
 51,684 
Accumulated Depreciation and Amortization
 
 
 18,066 
 
 
 17,340 
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET
 
 
 35,674 
 
 
 34,344 
 
 
 
 
 
 
 
OTHER NONCURRENT ASSETS
 
 
 
 
 
 
Regulatory Assets
 
 
 4,943 
 
 
 4,595 
Securitized Transition Assets
 
 
 1,742 
 
 
 1,896 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 1,515 
 
 
 1,392 
Goodwill
 
 
 76 
 
 
 76 
Long-term Risk Management Assets
 
 
 410 
 
 
 343 
Deferred Charges and Other Noncurrent Assets
 
 
 1,079 
 
 
 946 
TOTAL OTHER NONCURRENT ASSETS
 
 
 9,765 
 
 
 9,248 
 
 
 
 
 
 
 
TOTAL ASSETS
 
$
 50,455 
 
$
 48,348 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 
42
 
 
 
 
 
 
 
 
 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
December 31, 2010 and 2009
(dollars in millions)
 
 
 
2010 
 
2009 
CURRENT LIABILITIES
 
 
Accounts Payable
 
$
 1,061 
 
$
 1,158 
Short-term Debt:
 
 
 
 
 
 
 
Securitized Debt for Receivables - AEP Credit
 
 
 690 
 
 
 - 
 
Other Short-term Debt
 
 
 656 
 
 
 126 
 
 
Total Short-term Debt
 
 
 1,346 
 
 
 126 
Long-term Debt Due Within One Year
 
 
 1,309 
 
 
 1,741 
Risk Management Liabilities
 
 
 129 
 
 
 120 
Customer Deposits
 
 
 273 
 
 
 256 
Accrued Taxes
 
 
 702 
 
 
 632 
Accrued Interest
 
 
 281 
 
 
 287 
Regulatory Liability for Over-Recovered Fuel Costs
 
 
 17 
 
 
 76 
Deferred Gain and Accrued Litigation Costs
 
 
 448 
 
 
 - 
Other Current Liabilities
 
 
 952 
 
 
 931 
TOTAL CURRENT LIABILITIES
 
 
 6,518 
 
 
 5,327 
 
 
 
 
 
 
 
NONCURRENT LIABILITIES
 
 
 
 
 
 
Long-term Debt
 
 
 
 
 
 
 
(December 31, 2010 amount includes $1,857 related to Transition Funding, DCC Fuel and Sabine)
 
 
 15,502 
 
 
 15,757 
Long-term Risk Management Liabilities
 
 
 141 
 
 
 128 
Deferred Income Taxes
 
 
 7,359 
 
 
 6,420 
Regulatory Liabilities and Deferred Investment Tax Credits
 
 
 3,171 
 
 
 2,909 
Asset Retirement Obligations
 
 
 1,394 
 
 
 1,254 
Employee Benefits and Pension Obligations
 
 
 1,893 
 
 
 2,189 
Deferred Credits and Other Noncurrent Liabilities
 
 
 795 
 
 
 1,163 
TOTAL NONCURRENT LIABILITIES
 
 
 30,255 
 
 
 29,820 
 
 
 
 
 
 
 
TOTAL LIABILITIES
 
 
 36,773 
 
 
 35,147 
 
 
 
 
 
 
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
 
 
 60 
 
 
 61 
 
 
 
 
 
 
 
Rate Matters (Note 4)
 
 
 
 
 
 
Commitments and Contingencies (Note 6)
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY
 
 
 
 
 
 
Common Stock – Par Value – $6.50 Per Share:
 
 
 
 
 
 
 
 
 
2010 
 
2009 
 
 
 
 
 
 
 
 
Shares Authorized
600,000,000 
 
600,000,000 
 
 
 
 
 
 
 
 
Shares Issued
501,114,881 
 
498,333,265 
 
 
 
 
 
 
 
(20,307,725 shares and 20,278,858 shares were held in treasury at December 31,
 
 
 
 
 
 
 
2010 and 2009, respectively)
 
 
 3,257 
 
 
 3,239 
Paid-in Capital
 
 
 5,904 
 
 
 5,824 
Retained Earnings
 
 
 4,842 
 
 
 4,451 
Accumulated Other Comprehensive Income (Loss)
 
 
 (381)
 
 
 (374)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY
 
 
 13,622 
 
 
 13,140 
 
 
 
 
 
 
 
TOTAL EQUITY
 
 
 13,622 
 
 
 13,140 
 
 
 
 
 
 
 
TOTAL LIABILITIES AND EQUITY
 
$
 50,455 
 
$
 48,348 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 

 
43
 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2010, 2009 and 2008
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2010 
 
2009 
 
2008 
OPERATING ACTIVITIES
 
 
 
 
 
 
 
 
 
Net Income
 
$
 1,218 
 
$
 1,365 
 
$
 1,388 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 1,641 
 
 
 1,597 
 
 
 1,483 
 
 
Deferred Income Taxes
 
 
 809 
 
 
 1,244 
 
 
 498 
 
 
Provision for SIA Refund
 
 
 - 
 
 
 - 
 
 
 149 
 
 
Discontinued Operations, Net of Tax
 
 
 - 
 
 
 - 
 
 
 (12)
 
 
Extraordinary Loss, Net of Tax
 
 
 - 
 
 
 5 
 
 
 - 
 
 
Carrying Costs Income
 
 
 (70)
 
 
 (47)
 
 
 (83)
 
 
Allowance for Equity Funds Used During Construction
 
 
 (77)
 
 
 (82)
 
 
 (45)
 
 
Mark-to-Market of Risk Management Contracts
 
 
 30 
 
 
 (59)
 
 
 (140)
 
 
Amortization of Nuclear Fuel
 
 
 139 
 
 
 63 
 
 
 88 
 
 
Pension Contributions to Qualified Plan Trust
 
 
 (500)
 
 
 - 
 
 
 - 
 
 
Property Taxes
 
 
 (21)
 
 
 (17)
 
 
 (13)
 
 
Fuel Over/Under-Recovery, Net
 
 
 (253)
 
 
 (474)
 
 
 (272)
 
 
Gains on Sales of Assets, Net
 
 
 (14)
 
 
 (15)
 
 
 (17)
 
 
Change in Other Noncurrent Assets
 
 
 (75)
 
 
 (137)
 
 
 (244)
 
 
Change in Other Noncurrent Liabilities
 
 
 202 
 
 
 244 
 
 
 8 
 
Changes in Certain Components of Working Capital:
 
 
 
 
 
 
 
 
 
 
 
 
Accounts Receivable, Net
 
 
 (866)
 
 
 41 
 
 
 71 
 
 
 
Fuel, Materials and Supplies
 
 
 221 
 
 
 (475)
 
 
 (183)
 
 
 
Margin Deposits
 
 
 1 
 
 
 (3)
 
 
 (40)
 
 
 
Accounts Payable
 
 
 (36)
 
 
 8 
 
 
 (94)
 
 
 
Customer Deposits
 
 
 14 
 
 
 2 
 
 
 (48)
 
 
 
Accrued Taxes, Net
 
 
 179 
 
 
 (470)
 
 
 4 
 
 
 
Accrued Interest
 
 
 (8)
 
 
 17 
 
 
 30 
 
 
 
Other Current Assets
 
 
 72 
 
 
 (70)
 
 
 (29)
 
 
 
Other Current Liabilities
 
 
 56 
 
 
 (262)
 
 
 82 
Net Cash Flows from Operating Activities
 
 
 2,662 
 
 
 2,475 
 
 
 2,581 
 
 
 
 
 
 
 
 
 
 
INVESTING ACTIVITIES
 
 
 
 
 
 
 
 
 
Construction Expenditures
 
 
 (2,345)
 
 
 (2,792)
 
 
 (3,800)
Change in Other Temporary Investments, Net
 
 
 (4)
 
 
 16 
 
 
 45 
Purchases of Investment Securities
 
 
 (1,918)
 
 
 (853)
 
 
 (1,922)
Sales of Investment Securities
 
 
 1,817 
 
 
 748 
 
 
 1,917 
Acquisitions of Nuclear Fuel
 
 
 (91)
 
 
 (169)
 
 
 (192)
Acquisitions of Assets
 
 
 (155)
 
 
 (104)
 
 
 (160)
Proceeds from Sales of Assets
 
 
 187 
 
 
 278 
 
 
 90 
Other Investing Activities
 
 
 (14)
 
 
 (40)
 
 
 (5)
Net Cash Flows Used for Investing Activities
 
 
 (2,523)
 
 
 (2,916)
 
 
 (4,027)
 
 
 
 
 
 
 
 
 
 
FINANCING ACTIVITIES
 
 
 
 
 
 
 
 
 
Issuance of Common Stock, Net
 
 
 93 
 
 
 1,728 
 
 
 159 
Issuance of Long-term Debt
 
 
 1,270 
 
 
 2,306 
 
 
 2,774 
Commercial Paper and Credit Facility Borrowings
 
 
 565 
 
 
 127 
 
 
 2,055 
Change in Short-term Debt, Net
 
 
 770 
 
 
 119 
 
 
 (660)
Retirement of Long-term Debt
 
 
 (1,993)
 
 
 (816)
 
 
 (1,824)
Commercial Paper and Credit Facility Repayments
 
 
 (115)
 
 
 (2,096)
 
 
 (79)
Principal Payments for Capital Lease Obligations
 
 
 (95)
 
 
 (82)
 
 
 (97)
Dividends Paid on Common Stock
 
 
 (824)
 
 
 (758)
 
 
 (666)
Dividends Paid on Cumulative Preferred Stock
 
 
 (3)
 
 
 (3)
 
 
 (3)
Other Financing Activities
 
 
 (3)
 
 
 (5)
 
 
 20 
Net Cash Flows from (Used for) Financing Activities
 
 
 (335)
 
 
 520 
 
 
 1,679 
 
 
 
 
 
 
 
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents
 
 
 (196)
 
 
 79 
 
 
 233 
Cash and Cash Equivalents at Beginning of Period
 
 
 490 
 
 
 411 
 
 
 178 
Cash and Cash Equivalents at End of Period
 
$
 294 
 
$
 490 
 
$
 411 
 
 
 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements.
 
 
 
 
 
 
 
 
 

 
44
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

   
1.
Organization and Summary of Significant Accounting Policies
2.
New Accounting Pronouncements and Extraordinary Item
3.
Goodwill and Other Intangible Assets
4.
Rate Matters
5.
Effects of Regulation
6.
Commitments, Guarantees and Contingencies
7.
Acquisitions, Dispositions and Discontinued Operations
8.
Benefit Plans
9.
Business Segments
10.
Derivatives and Hedging
11.
Fair Value Measurements
12.
Income Taxes
13.
Leases
14.
Financing Activities
15.
Stock-Based Compensation
16.
Property, Plant and Equipment
17.
Cost Reduction Initiatives
18.
Unaudited Quarterly Financial Information

 
45
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

The principal business conducted by seven of our electric utility operating companies is the generation, transmission and distribution of electric power.  TCC exited the generation business and along with KGPCo and WPCo, provides only transmission and distribution services.  TNC engages in the transmission and distribution of electric power and is a part owner in the Oklaunion Plant operated by PSO.  TNC leases their entire portion of the output of the plant through 2027 to a nonutility affiliate.  AEGCo is a regulated electricity generation business whose function is to provide power to our regulated electric utility operating companies.  These companies are subject to regulation by the FERC under the Federal Power Act and the Energy Policy Act of 2005.  These companies 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.

We also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States.  In addition, our operations include nonregulated wind farms and barging operations and we provide various energy-related services.

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 that a nonregulated affiliate can bill an affiliated public utility company 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.  They 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 cost-based due to PSO and SWEPCo having 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.  They 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 aligning generation/power supply rates over time with market rates.  In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing and is conducted by REPs.  Through its nonregulated subsidiaries, AEP enters 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.  Effective November 2009, AEP had no active REPs in ERCOT.  SWEPCo operates in the SPP area which includes a portion of Texas.  In 2009, the Texas legislature amended its restructuring legislation for the generation portion of SWEPCo’s Texas retail jurisdiction to delay indefinitely restructuring requirements.  As a result, SWEPCo reapplied accounting guidance for “Regulated Operations” to its Texas generation operations.

 
46
 
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.  CSPCo’s and 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.  CSPCo’s and OPCo’s retail transmission rates in Ohio and APCo’s retail transmission rates in Virginia are based on the FERC’s Open Access Transmission Tariff (OATT) rates that are cost-based.  Although I&M’s retail transmission rates in Michigan and TCC’s and TNC’s retail transmission rates in Texas are unbundled, retail transmission rates are regulated, on a cost basis, by the state regulatory commissions.  Bundled retail transmission rates are regulated, on a cost basis, by the state commissions.

In addition, the FERC regulates the SIA, the Interconnection Agreement, the CSW Operating Agreement, the System Transmission Integration Agreement, the Transmission Agreement, the Transmission Coordination Agreement and the AEP System Interim Allowance Agreement, all of which allocate shared system costs and revenues to the utility subsidiaries that are parties to each agreement.

Principles of Consolidation

Our consolidated financial statements include our wholly-owned and majority-owned subsidiaries and variable interest entities (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 our Consolidated Balance Sheets; equity earnings are included in Equity Earnings of Unconsolidated Subsidiaries on our Consolidated 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 our Consolidated Statements of Income and our proportionate share of the assets and liabilities are reflected on our Consolidated Balance Sheets.

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, power to direct the VIE and other factors.  We believe that significant assumptions and judgments were applied consistently.  Also, see the “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.

We are the primary beneficiary of Sabine, DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, AEP Credit, Transition Funding and a protected cell of EIS.  As of January 1, 2010, we are no longer the primary beneficiary of DHLC as defined by the new accounting guidance for “Variable Interest Entities.”  In addition, we have not provided material financial or other support to Sabine, DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, Transition Funding, our protected cell of EIS and AEP Credit that was not previously contractually required.  We hold a significant variable interest in Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series) and DHLC.

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 for 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, 2010, 2009 and 2008 were $133 million, $ 99 million and $110 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on our Consolidated Balance Sheets.

 
47
 
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 its assets and liabilities.  Our insurance premium payments to the protected cell for the years ended December 31, 2010, 2009 and 2008 were $ 35 million, $30 million and $ 28 million, respectively.  See the tables below for the classification of the protected cell’s assets and liabilities on our Consolidated Balance Sheets.  The amount reported as equity is the protected cell’s policy holders’ surplus.

In September 2009, I&M entered into a nuclear fuel sale and leaseback transaction with DCC Fuel LLC.  In April 2010, I&M entered into a nuclear fuel sale and leaseback transaction with DCC Fuel II LLC.  In December 2010, I&M entered into a nuclear fuel sale and leaseback transaction with DCC Fuel III LLC.  DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC (collectively DCC Fuel) were 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.  DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC are separate legal entities from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on the DCC Fuel LLC and DCC Fuel II LLC leases are made semi-annually and began in April 2010 and October 2010, respectively.  Payments on the DCC Fuel III LLC lease are made monthly and will begin in January 2011.  Payments on the leases for the year ended December 31, 2010 were $59 million.  No payments were made to DCC Fuel in 2009.  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 48, 54 and 54 month lease term, respectively.  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.  See the tables below for the classification of DCC Fuel’s assets and liabilities on our Consolidated 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 Parent 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 has concluded that we are the primary beneficiary and are required to consolidate its assets and liabilities.  See the tables below for the classification of AEP Credit’s assets and liabilities on our Consolidated Balance Sheets.  See the “ASU 2009-17 ‘Consolidation’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.  Also, see “Securitized Accounts Receivables – AEP Credit” section of Note 14.

DHLC is a mining operator who sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  SWEPCo and CLECO share the executive board seats and its voting rights equally.  Each entity guarantees a 50% share 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.  Based on the shared control of DHLC’s operations, management concluded as of January 1, 2010 that SWEPCo is no longer the primary beneficiary and is no longer required to consolidate DHLC.  SWEPCo’s total billings from DHLC for the years ended December 31, 2010, 2009 and 2008 were $ 56 million, $43 million and $ 44 million, respectively.  See the tables below for the classification of DHLC’s assets and liabilities on our Consolidated Balance Sheets at December 31, 2009 as well as our investment and maximum exposure as of December 31, 2010.  As of January 1, 2010, DHLC is reported as an equity investment in Deferred Charges and Other Noncurrent Assets on our Consolidated Balance Sheets.  Also, see the “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.

Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas restructuring law.  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 $1.8 billion at December 31, 2010 and are included in current and long-term debt on the Consolidated Balance Sheets.  Transition Funding has securitized transition assets of $1.7 billion at December 31, 2010, which are presented separately on the face of the Consolidated Balance Sheets.  The securitized transition assets represent the right to
 
 
48
 
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.

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, 2010
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SWEPCo
 
I&M
 
Protected Cell
 
 
 
Transition
 
 
Sabine
DCC Fuel
of EIS
AEP Credit
 
Funding
ASSETS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Assets
 
$
 50 
 
$
 92 
 
$
 131 
 
$
 924 
 
$
 214 
Net Property, Plant and Equipment
 
 
 139 
 
 
 173 
 
 
 - 
 
 
 - 
 
 
 - 
Other Noncurrent Assets
 
 
 34 
 
 
 112 
 
 
 1 
 
 
 10 
 
 
 1,746 
Total Assets
 
$
 223 
 
$
 377 
 
$
 132 
 
$
 934 
 
$
 1,960 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Liabilities
 
$
 33 
 
$
 79 
 
$
 33 
 
$
 886 
 
$
 221 
Noncurrent Liabilities
 
 
 190 
 
 
 298 
 
 
 85 
 
 
 1 
 
 
 1,725 
Equity
 
 
 - 
 
 
 - 
 
 
 14 
 
 
 47 
 
 
 14 
Total Liabilities and Equity
 
$
 223 
 
$
 377 
 
$
 132 
 
$
 934 
 
$
 1,960 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2009
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SWEPCo
 
SWEPCo
 
I&M
 
Protected Cell
 
 
 
 
 
Sabine
DHLC
DCC Fuel
of EIS
 
 
 
ASSETS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Assets
 
$
 51 
 
$
 8 
 
$
 47 
 
$
 130 
 
 
 
Net Property, Plant and Equipment
 
 
 149 
 
 
 44 
 
 
 89 
 
 
 - 
 
 
 
Other Noncurrent Assets
 
 
 35 
 
 
 11 
 
 
 57 
 
 
 2 
 
 
 
Total Assets
 
$
 235 
 
$
 63 
 
$
 193 
 
$
 132 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Liabilities
 
$
 36 
 
$
 17 
 
$
 39 
 
$
 36 
 
 
 
Noncurrent Liabilities
 
 
 199 
 
 
 38 
 
 
 154 
 
 
 74 
 
 
 
Equity
 
 
 - 
 
 
 8 
 
 
 - 
 
 
 22 
 
 
 
Total Liabilities and Equity
 
$
 235 
 
$
 63 
 
$
 193 
 
$
 132 
 
 
 

Our investment in DHLC was:

 
December 31, 2010
 
As Reported on
 
 
 
the Consolidated
Maximum
 
Balance Sheets
Exposure
 
(in millions)
Capital Contribution from SWEPCo
$
 6 
 
$
 6 
Retained Earnings
 
 2 
 
 
 2 
SWEPCo's Guarantee of Debt
 
 - 
 
 
 48 
 
 
 
 
 
 
Total Investment in DHLC
$
 8 
 
$
 56 

 
49
 
In September 2007, we and Allegheny Energy Inc. (AYE) formed a joint venture by creating Potomac-Appalachian Transmission Highline, LLC (PATH).  PATH is a series limited liability company and was created to construct a high-voltage transmission line project in the PJM region.  PATH consists of the “Ohio Series,” the “West Virginia Series (PATH-WV),” both owned equally by AYE and AEP, and the “Allegheny Series” which is 100% owned by AYE.  Provisions exist within the PATH-WV agreement that make it a VIE.  The “Ohio Series” does not include the same provisions that make PATH-WV a VIE.  Neither the “Ohio Series” nor “Allegheny Series” are considered VIEs.  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 our Consolidated Balance Sheets.  We and AYE share the returns and losses equally in PATH-WV.  Our subsidiaries and AYE’s subsidiaries provide services to the PATH companies through service agreements.  At the current time, PATH-WV has no debt outstanding.  However, when debt is issued, the debt to equity ratio in each series should be consistent with other regulated utilities.  The entities recover costs through regulated rates.

Given the structure of the entity, we may be required to provide future financial support to PATH-WV in the form of a capital call.  This would be considered an increase to our investment in the entity.  Our maximum exposure to loss is to the extent of our investment.  The likelihood of such a loss is remote since the FERC approved PATH-WV’s request for regulatory recovery of cost and a return on the equity invested.

Our investment in PATH-WV was:

 
December 31,
 
2010 
 
2009 
 
As Reported on
 
 
 
 
As Reported on
 
 
 
 
the Consolidated
Maximum
the Consolidated
Maximum
 
Balance Sheets
Exposure
Balance Sheets
Exposure
 
 
 
(in millions)
 
 
 
Capital Contribution from AEP
$
 18 
 
$
 18 
 
$
 13 
 
$
 13 
Retained Earnings
 
 6 
 
 
 6 
 
 
 3 
 
 
 3 
 
 
 
 
 
 
 
 
 
 
 
 
Total Investment in PATH-WV
$
 24 
 
$
 24 
 
$
 16 
 
$
 16 

Accounting for the Effects of Cost-Based Regulation

As the owner of rate-regulated electric public utility companies, our consolidated 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 (future revenue reductions or refunds) to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues and income with its passage to customers through the reduction of regulated revenues.  Due to the passage of legislation requiring restructuring and a transition to customer choice and market-based rates, we discontinued the application of “Regulated Operations” accounting treatment for the generation portion of our business in Ohio for CSPCo and OPCo and in Texas for TNC.  In 2009, the Texas legislature amended its restructuring legislation for the generation portion of SWEPCo’s Texas retail jurisdiction to delay indefinitely restructuring requirements.  As a result, SWEPCo reapplied accounting guidance for “Regulated Operations” to its Texas generation operations.

Accounting guidance for “Discontinuation of Rate-Regulated Operations” requires the recognition of an impairment of stranded net regulatory assets and stranded plant costs if they are not recoverable in regulated rates.  In addition, an enterprise is required to eliminate from its balance sheet the effects of any actions of regulators that had been recognized as regulatory assets and regulatory liabilities.  Such impairments and adjustments are classified as an extraordinary item.  Consistent with accounting guidance for “Discontinuation of Rate-Regulated Operations,” SWEPCo recorded an extraordinary reduction in earnings and shareholder’s equity from the reapplication of “Regulated Operations” accounting guidance in 2009.

 
50
 
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 marketable securities that we intend to hold for less than one year, investments by our protected cell of EIS and funds held by trustees primarily for the payment of debt.

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.

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.  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 our Consolidated 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 CSPCo, 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.  Prior to January 1, 2010, this transaction constituted a sale of receivables in accordance with the accounting guidance for “Transfers and Servicing,” allowing the receivables to be removed from our Consolidated Balance Sheets (see “Securitized
 
 
51
 
Accounts Receivable – AEP Credit” section of Note 14).  See “ASU 2009-16 ‘Transfers and Servicing’ ” section of Note 2 for a discussion of the impact of accounting guidance effective January 1, 2010 whereby such future transactions do not constitute a sale of receivables and are accounted for as financings.

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.  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

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.  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 our Consolidated Balance Sheets.  We record the consumption of allowances in the production of energy in Fuel and Other Consumables Used for Electric Generation on our Consolidated Statements of Income at an average cost.  We record allowances held for speculation in Prepayments and Other Current Assets on our Consolidated Balance Sheets.  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 Utility Operations Revenue on our Consolidated 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.

Property, Plant and Equipment and Equity Investments

Regulated

Electric utility property, plant and equipment for our rate-regulated operations are stated at original purchase cost. Additions, major replacements and betterments are added to the plant accounts.  Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation under the group composite method of 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.  Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in the original cost, less salvage, being charged to accumulated depreciation.  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.”  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.

 
52
 
Nonregulated

Our nonregulated operations generally follow the policies of our cost-based 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

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.  For nonregulated operations, including generating assets in Ohio and certain generating assets in Texas, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest”.  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.

Valuation of Nonderivative Financial Instruments

The book values of Cash and Cash Equivalents, Accounts Receivable, Short-term Debt and Accounts Payable 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.

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 or 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.

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 non-binding 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 and 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.  Long-dated and illiquid complex or structured transactions and FTRs can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.

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 plans.

 
53
 
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.  Fixed income securities do not trade on an exchange and do not have an official closing price.  Pricing vendors calculate bond valuations using financial models and matrices.  Fixed income securities are typically classified as Level 2 holdings because their valuation inputs are based on observable market data.  Observable inputs used for valuing fixed income securities are benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, bids, offers, reference data and economic events.  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 real estate and private equity investments that are valued using methods requiring judgment including appraisals.

Items classified as Level 2 are primarily investments in individual fixed income securities.  These fixed income securities are valued using models with input data as follows :

 
 
Type of Fixed Income Security
 
 
United States
 
 
 
State and Local
Type of Input
 
Government
 
Corporate Debt
 
Government
 
 
 
 
 
 
 
Benchmark Yields
 
X
 
X
 
X
Broker Quotes
 
X
 
X
 
X
Discount Margins
 
X
 
X
 
 
Treasury Market Update
 
X
 
 
 
 
Base Spread
 
X
 
X
 
X
Corporate Actions
 
 
 
X
 
 
Ratings Agency Updates
 
 
 
X
 
X
Prepayment Schedule and
 
 
 
 
 
 
   History
 
 
 
 
 
X
Yield Adjustments
 
X
 
 
 
 

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.  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 fuel cost disallowance becomes probable, we adjust our FAC deferrals and record provisions for estimated refunds to recognize these probable outcomes.  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.

Changes in fuel costs, including purchased power in Kentucky for KPCo, in Indiana and Michigan for I&M, in Texas, Louisiana and Arkansas for SWEPCo, in Oklahoma for PSO and in Virginia and West Virginia (prior to 2009) for APCo are reflected in rates in a timely manner through the FAC.  Beginning in 2009, changes in fuel costs, including purchased power in Ohio for CSPCo and OPCo and in West Virginia for APCo are reflected in rates through FAC phase-in plans.  All of the profits from off-system sales are given to customers through the FAC in West Virginia for APCo.  A portion of profits from off-system sales are shared with customers through the FAC and other rate mechanisms in Oklahoma for PSO, Texas, Louisiana and Arkansas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan (all areas of Michigan beginning in December 2010) for I&M.  Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent (prior to 2009 for CSPCo and OPCo in Ohio and currently in Texas for AEP Energy Partners, Inc.), changes in fuel costs or sharing of off-system sales impacted earnings.

 
54
 
Revenue Recognition

Regulatory Accounting

Our consolidated 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 our Consolidated 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.

Traditional Electricity Supply and Delivery Activities

Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services.  We recognize the revenues on our Consolidated 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 RTO operating in the east service territory.  We purchase power from PJM to supply our customers.  Generally, these power sales and purchases are reported on a net basis as revenues on our Consolidated 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 our Consolidated Statements of Income.  Other RTOs in which we operate 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 our Consolidated 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 our Consolidated 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 electricity, natural gas, coal and emission allowances marketing and risk management activities focused on wholesale markets where we own assets and on adjacent markets.  Our activities include the purchase and sale of energy under forward contracts at fixed and variable prices and the buying and selling of financial energy contracts, which include exchange traded futures and options, as well as over-the-counter options and swaps.  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 the unrealized and realized gains and losses on wholesale marketing and risk management transactions that are accounted for using MTM in Revenues on our Consolidated Statements of Income on a net basis.  In jurisdictions subject to cost-based regulation, we defer the 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 our Consolidated Balance Sheets as Risk Management Assets or Liabilities as appropriate.

 
55
 
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 our Consolidated 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 our Consolidated 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).

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 order to match costs with nuclear refueling cycles, 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.  We defer distribution tree trimming costs for PSO above the level included in base rates and amortize those deferrals commensurate with recovery through a rate rider in Oklahoma.

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.

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.

 
56
 
Government Grants

In 2010, APCo received final approval for a federal stimulus grant for a commercial scale Carbon Capture and Sequestration facility under consideration at the Mountaineer Plant.  Also in 2010, CSPCo received final approval for a federal stimulus grant for the gridSMART ® demonstration program.  For each project, APCo and CSPCo are reimbursed by the Department of Energy for allowable costs incurred during the billing period.  These reimbursements result in the reduction of Other Operation and Maintenance expenses on our Consolidated Statements of Income or a reduction in Construction Work in Progress on our Consolidated Balance Sheets.

Debt and Preferred Stock

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.  Some jurisdictions require that these costs be expensed upon reacquisition.  We report gains and losses on the reacquisition of debt for operations not subject to cost-based rate regulation in Interest Expense on our Consolidated Statements of Income.

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 amortization expense in Interest Expense on our Consolidated Statements of Income.

Where reflected in rates, we include redemption premiums paid to reacquire preferred stock of utility subsidiaries in paid-in capital and amortize the premiums to retained earnings commensurate with recovery in rates.  We credit the excess of par value over costs of preferred stock reacquired to paid-in capital and reclassify the excess to retained earnings upon the redemption of the entire preferred stock series.

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, currently 10 years, 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 allocation and periodically rebalance the investments to targeted allocation 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.

 
57
 
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 optimizing 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.

The target asset allocation and allocation ranges are as follows:

Pension Plan Assets
 
Minimum
 
Target
 
Maximum
Domestic Equity
 
 30.0 
%
 
 35.0 
%
 
 40.0 
%
International and Global Equity
 
 10.0 
%
 
 15.0 
%
 
 20.0 
%
Fixed Income
 
 35.0 
%
 
 39.0 
%
 
 45.0 
%
Real Estate
 
 4.0 
%
 
 5.0 
%
 
 6.0 
%
Other Investments
 
 1.0 
%
 
 5.0 
%
 
 7.0 
%
Cash
 
 0.5 
%
 
 1.0 
%
 
 3.0 
%
 
 
 
 
 
 
 
OPEB Plans Assets
 
Minimum
 
Target
 
Maximum
Equity
 
 61.0 
%
 
 66.0 
%
 
 71.0 
%
Fixed Income
 
 29.0 
%
 
 32.0 
%
 
 37.0 
%
Cash
 
 1.0 
%
 
 2.0 
%
 
 4.0 
%

The investment policy for each benefit plan contains various investment limitations.  The investment policies establish concentration limits for securities.  Investment policies prohibit the benefit trust funds from purchasing 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.
·  
Individual stock must be less 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 one issuer
·  
20% in non-US dollar denominated
·  
5% private placements
·  
5% convertible securities
·  
60% for bonds rated AA+ or lower
·  
50% for bonds rated A+ or lower
·  
10% for bonds rated BBB- or lower

 
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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 classified as Level 1.

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 six 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 (V EBA) 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.

 
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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 our Consolidated 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 equity and debt 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-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 spent nuclear fuel 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).

Components of Accumulated Other Comprehensive Income (Loss) (AOCI)

AOCI is included on our Consolidated Balance Sheets in our equity section.  Our components of AOCI as of December 31, 2010 and 2009 are shown in the following table:

 
 
December 31,
Components
 
2010 
 
2009 
 
 
(in millions)
Securities Available for Sale, Net of Tax
 
$
 4 
 
$
 12 
Cash Flow Hedges, Net of Tax
 
 
 11 
 
 
 (15)
Amortization of Pension and OPEB Deferred Costs, Net of Tax
 
 
 57 
 
 
 35 
Pension and OPEB Funded Status, Net of Tax
 
 
 (453)
 
 
 (406)
Total
 
$
 (381)
 
$
 (374)

Stock-Based Compensation Plans

At December 31, 2010, we had stock options, performance units, restricted shares 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.

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 HR 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 do not become payable to executives until after their service ends.  Dividends paid on career shares are reinvested as additional career shares.

 
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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 our Consolidated Statements of Income for the years ended December 31, 2010, 2009 and 2008 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, 2010, 2009 and 2008, 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.

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
 
2010 
 
2009 
 
2008 
 
 
 
(in millions)
Income Before Discontinued Operations and Extraordinary Loss
 
$
 1,211 
 
$
 1,362 
 
$
 1,368 
Discontinued Operations, Net of Tax
 
 
 - 
 
 
 - 
 
 
 12 
Extraordinary Loss, Net of Tax
 
 
 - 
 
 
 (5)
 
 
 - 
Net Income
 
$
 1,211 
 
$
 1,357 
 
$
 1,380 

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 our Consolidated Statements of Income:
 
 
 
 
 
Years Ended December 31,
 
 
 
 
2010 
 
2009 
 
2008 
 
 
 
 
(in millions, except per share data)
 
 
 
 
 
 
 
$/share
 
 
 
 
$/share
 
 
 
 
$/share
Earnings Attributable to AEP Common Shareholders
 
$
 1,211 
 
 
 
 
$
 1,357 
 
 
 
 
$
 1,380 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted Average Number of Basic Shares Outstanding
 
 
 479.4 
 
$
 2.53 
 
 
 458.7 
 
$
 2.96 
 
 
 402.1 
 
$
 3.43 
Weighted Average Dilutive Effect of:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Performance Share Units
 
 
 0.1 
 
 
 - 
 
 
 0.3 
 
 
 - 
 
 
 1.2 
 
 
 0.01 
 
 
Stock Options
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 0.1 
 
 
 - 
 
 
Restricted Stock Units
 
 
 0.1 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 0.1 
 
 
 - 
 
 
Restricted Shares
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 0.1 
 
 
 - 
Weighted Average Number of Diluted Shares Outstanding
 
 
 479.6 
 
$
 2.53 
 
 
 459.0 
 
$
 2.96 
 
 
 403.6 
 
$
 3.42 

 
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The assumed conversion of stock options does not affect net earnings for purposes of calculating diluted earnings per share.

Options to purchase 136,250, 452,216 and 470,016 shares of common stock were outstanding at December 31, 2010, 2009 and 2008, respectively, but were not included in the computation of diluted earnings per share attributable to AEP common shareholders.  Since the options’ exercise prices were greater than the average market price of the common shares, the effect would have been antidilutive.

CSPCo and OPCo Revised Depreciation Rates

Effective January 1, 2009, we revised book depreciation rates for CSPCo and OPCo generating plants consistent with a completed depreciation study.  OPCo’s overall higher depreciation rates primarily related to shortened depreciable lives for certain OPCo generating facilities.  In comparing 2009 and 2008, the change in depreciation rates resulted in a net increase (decrease) in depreciation expense of:

 
 
Depreciation
 
 
Expense Variance
 
 
Years Ended
 
 
December 31,
 
 
2009/2008
 
 
(in millions)
CSPCo
 
$
 (18)
OPCo
 
 
 71 

The net change in depreciation rates resulted in a decrease to our net-of-tax, basic earnings per share of $0.08 for the year ended December 31, 2009.
 
Supplementary Information
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Years Ended December 31,
 
Related Party Transactions
 
2010 
 
2009 
 
2008 
 
 
 
(in millions)
 
AEP Consolidated Revenues – Utility Operations:
 
 
 
 
 
 
 
 
 
 
 
Ohio Valley Electric Corporation (43.47% owned)
 
$
 (20)
(a)
$
 - 
 
$
 (54)
(b)
AEP Consolidated Revenues – Other Revenues:
 
 
 
 
 
 
 
 
 
 
 
Ohio Valley Electric Corporation – Barging and Other
 
 
 
 
 
 
 
 
 
 
 
 
Transportation Services (43.47% Owned)
 
 
 29 
 
 
 31 
 
 
 32 
 
AEP Consolidated Expenses – Purchased Electricity
 
 
 
 
 
 
 
 
 
 
  for Resale:
 
 
 
 
 
 
 
 
 
 
 
Ohio Valley Electric Corporation (43.47% Owned)
 
 
 302 
(c)
 
 286 
 
 
 263 
 

(a)
The AEP Power Pool purchased power from OVEC to serve off-system sales in an agreement that began in January 2010 and ended in June 2010.
(b)
The AEP Power Pool purchased power from OVEC as part of risk management activities in an agreement that ended in December 2008.
(c)
The AEP Power Pool purchased power from OVEC to serve retail sales in an agreement that began in January 2010 and ended in June 2010.  The total amount reported in 2010 includes $10 million related to this agreement.

 
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Years Ended December 31,
 
Cash Flow Information
 
2010 
 
2009 
 
2008 
 
 
 
 
 
(in millions)
 
Cash Paid (Received) for:
 
 
 
 
 
 
 
 
 
 
 
Interest, Net of Capitalized Amounts
 
$
 958 
 
$
 924 
 
$
 853 
 
 
Income Taxes
 
 
 (268)
 
 
 (98)
 
 
 233 
 
Noncash Investing and Financing Activities:
 
 
 
 
 
 
 
 
 
 
 
Acquisitions Under Capital Leases
 
 
 225 
 
 
 86 
 
 
 62 
 
 
Assumption of Liabilities Related to Acquisitions
 
 
 8 
 
 
 - 
 
 
 - 
 
Government Grants Included in Accounts Receivable at December 31,
 
 
 10 
 
 
 - 
 
 
 - 
 
Construction Expenditures Included in Accounts Payable at December 31,
 
 
 267 
 
 
 348 
 
 
 460 
 
Acquisition of Nuclear Fuel Included in Accounts Payable at December 31,
 
 
 - 
 
 
 - 
 
 
 38 
 
Noncash Donation Expense Related to Issuance of Treasury Shares to
 
 
 
 
 
 
 
 
 
 
 
AEP Foundation
 
 
 - 
 
 
 - 
 
 
 40 

Transmission Investments

We participate in certain joint ventures which involve the development, construction, ownership and operation of transmission facilities.  These investments are recorded using the equity method and reported as Deferred Charges and Other Noncurrent Assets on our Consolidated Balance Sheets.

Adjustments to Securitized Accounts Receivable Disclosure

In the “Securitized Accounts Receivable – AEP Credit” section of Note 14, we expanded our disclosure to reflect certain prior period amounts related to our securitization agreement that were not previously disclosed.  These omissions were not material to our financial statements and had no impact on our previously reported net income, changes in shareholders’ equity, financial position or cash flows.

2.   NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM

NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of final pronouncements, we review the new accounting literature to determine its relevance, if any, to our business.  The following represents a summary of final pronouncements that impact our financial statements.

Pronouncements Adopted During 2010

The following standards were effective during 2010.  Consequently, their impact is reflected in the financial statements.  The following paragraphs discuss their impact.

ASU 2009-16 “Transfers and Servicing” (ASU 2009-16)

In 2009, the FASB issued ASU 2009-16 clarifying when a transfer of a financial asset should be recorded as a sale.  The standard defines participating interest to establish specific conditions for a sale of a portion of a financial asset.  This standard must be applied to all transfers after the effective date.

We adopted ASU 2009-16 effective January 1, 2010.  AEP Credit securitizes an interest in receivables it acquires from certain of its affiliates to bank conduits and receives cash.  As of December 31, 2009, AEP Credit owed $656 million to bank conduits related to receivable sales outstanding.  Upon adoption of ASU 2009-16, future transactions do not constitute a sale of receivables and are accounted for as financings.  Effective January 2010, we record the receivables and related debt on our Consolidated Balance Sheet.

 
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ASU 2009-17 “Consolidations” (ASU 2009-17)

In 2009, the FASB issued ASU 2009-17 amending the analysis an entity must perform to determine if it has a controlling financial interest in a VIE.  In addition to presentation and disclosure guidance, ASU 2009-17 provides that the primary beneficiary of a VIE must have both:

·  
The power to direct the activities of the VIE that most significantly impact the VIE’s economic performance.
·  
The obligation to absorb the losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

We adopted the prospective provisions of ASU 2009-17 effective January 1, 2010 and deconsolidated DHLC.  DHLC was deconsolidated due to the shared control between SWEPCo and CLECO.  After January 1, 2010, we report DHLC using the equity method of accounting.

This standard increased our disclosure requirements for AEP Credit and Transition Funding, wholly-owned consolidated subsidiaries.  See “Variable Interest Entities” section of Note 1 for further discussion.

EXTRAORDINARY ITEM

SWEPCo Texas Restructuring

In August 2006, the PUCT adopted a rule extending the delay in implementation of customer choice in SWEPCo’s SPP area of Texas until no sooner than January 1, 2011.  In May 2009, the governor of Texas signed a bill related to SWEPCo’s SPP area of Texas that requires continued cost of service regulation until certain stages have been completed and approved by the PUCT such that fair competition is available to all Texas retail customer classes.  Based upon the signing of the bill, SWEPCo re-applied “Regulated Operations” accounting guidance for the generation portion of SWEPCo’s Texas retail jurisdiction effective second quarter of 2009.  Management believes that a return to competition in the SPP area of Texas will not occur.  The reapplication of “Regulated Operations” accounting guidance resulted in an $8 million ($5 million, net of tax) extraordinary loss.

3.   GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

The changes in our carrying amount of goodwill for the years ended December 31, 2010 and 2009 by operating segment are as follows:
 

 
Utility
 
AEP River
 
AEP
 
Operations
 
Operations
 
Consolidated
 
(in millions)
Balance at December 31, 2008
$
 37 
 
$
 39 
 
$
 76 
Impairment Losses
 
 - 
 
 
 - 
 
 
 - 
Balance at December 31, 2009
 
 37 
 
 
 39 
 
 
 76 
Impairment Losses
 
 - 
 
 
 - 
 
 
 - 
Balance at December 31, 2010
$
 37 
 
$
 39 
 
$
 76 

In the fourth quarters of 2010 and 2009, 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.

 
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Other Intangible Assets

Acquired intangible assets subject to amortization were $1.2 million and $10.3 million at December 31, 2010 and 2009, respectively, net of accumulated amortization and are included in Deferred Charges and Other Noncurrent Assets on our Consolidated Balance Sheets.  The amortization life, gross carrying amount and accumulated amortization by major asset class are as follows:
 

 
 
 
December 31,
 
 
 
2010 
 
2009 
 
 
 
Gross
 
 
 
Gross
 
 
 
Amortization
 
Carrying
 
Accumulated
 
Carrying
 
Accumulated
 
Life
 
Amount
 
Amortization
 
Amount
 
Amortization
 
(in years)
 
(in millions)
Easements
10 
 
$
 2.2 
 
$
 2.2 
 
$
 2.2 
 
$
 1.9 
Purchased Technology
10 
 
 
 10.9 
 
 
 9.7 
 
 
 10.9 
 
 
 8.6 
Advanced Royalties
15 
 
 
 - 
 
 
 - 
 
 
 29.4 
 
 
 21.7 
Total
 
 
$
 13.1 
 
$
 11.9 
 
$
 42.5 
 
$
 32.2 

Amortization of intangible assets was $ 1 million, $3 million and $3 million for 2010, 2009 and 2008, respectively.  Our estimated total amortization is $1 million for 2011 and $138 thousand for 2012.

The Advanced Royalties asset class relates to the lignite mine of DHLC, a wholly-owned subsidiary of SWEPCo.  As of January 1, 2010, SWEPCo no longer consolidates DHLC, but rather it is reported as an equity investment, resulting in the elimination of a review of this asset by SWEPCo.  Also, see “ASU 2009-17 ‘Consolidations’” section of Note 2 for discussion of impact of new accounting guidance effective January 1, 2010.

Other than goodwill, we have no intangible assets that are not subject to amortization.

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.

CSPCo and OPCo Rate Matters
 

Ohio Electric Security Plan Filings

2009 – 2011 ESPs

The PUCO issued an order in March 2009 that modified and approved CSPCo’s and OPCo’s ESPs which established rates at the start of the April 2009 billing cycle.  The ESPs are in effect through 2011.  The order also limited annual rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011.  Some rate components and increases are exempt from these limitations.  CSPCo and OPCo collected the 2009 annualized revenue increase over the last nine months of 2009.

The order provided a FAC for the three-year period of the ESP.  The FAC was phased in to avoid having the resultant rate increases exceed the ordered annual caps described above.  The FAC is subject to quarterly true-ups, annual accounting audits and prudency reviews.  See the “2009 Fuel Adjustment Clause Audit” section below.  The order allowed CSPCo and OPCo to defer any unrecovered FAC costs resulting from the annual caps and accrued associated carrying charges at CSPCo’s and OPCo’s weighted average cost of capital.  Any deferred FAC regulatory asset balance at the end of the three-year ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018.  That recovery will include deferrals associated with the Ormet interim arrangement and is subject to the PUCO’s ultimate decision regarding the Ormet interim arrangement deferrals plus related carrying charges.  See the “Ormet Interim Arrangement” section below.  The FAC deferral as of December 31, 2010 was $ 476 million for OPCo excluding $30 million of unrecognized equity carrying costs.

 
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Discussed below are the significant outstanding uncertainties related to the ESP order:

The Ohio Consumers’ Counsel filed a notice of appeal with the Supreme Court of Ohio raising several issues including alleged retroactive ratemaking, recovery of carrying charges on certain environmental investments, Provider of Last Resort (POLR) charges and the decision not to offset rates by off-system sales margins.  A decision from the Supreme Court of Ohio is pending.
 
In November 2009, the Industrial Energy Users-Ohio filed a notice of appeal with the Supreme Court of Ohio challenging components of the ESP order including the POLR charge, the distribution riders for gridSMART ® and enhanced reliability, the PUCO’s conclusion and supporting evaluation that the modified ESPs are more favorable than the expected results of a market rate offer, the unbundling of the fuel and non-fuel generation rate components, the scope and design of the fuel adjustment clause and the approval of the plan after the 150-day statutory deadline.  A decision from the Supreme Court of Ohio is pending.

In April 2010, the Industrial Energy Users-Ohio filed an additional notice of appeal with the Supreme Court of Ohio challenging alleged retroactive ratemaking, CSPCo's and OPCo's abilities to collect through the FAC amounts deferred under the Ormet interim arrangement and the approval of the plan after the 150-day statutory deadline.  A decision from the Supreme Court of Ohio is pending.
 
Ohio law requires that the PUCO determine, following the end of each year of the ESP, if rate adjustments included in the ESP resulted in significantly excessive earnings under the Significantly Excessive Earnings Test (SEET).  If the rate adjustments, in the aggregate, result in significantly excessive earnings, the excess amount could be returned to customers.  In September 2010, CSPCo and OPCo filed their 2009 SEET filings with the PUCO.  CSPCo’s and OPCo’s returns on common equity were 20.84% and 10.81%, respectively, including off-system sales margins.  In January 2011, the PUCO issued an order that determined a return on common equity for 2009 in excess of 17.6% would be significantly excessive.  The PUCO determined that OPCo’s 2009 earnings were not significantly excessive but determined relevant CSPCo earnings, excluding off-system sales margins, to be 19.73%, which exceeded the PUCO determined threshold by 2.13%.  As a result, the PUCO ordered CSPCo to refund $43 million ($ 28 million net of tax) of its earnings to customers, which was recorded as a revenue provision on CSPCo’s December 2010 books.  The PUCO ordered that the significantly excessive earnings be applied first to CSPCo’s FAC deferral, including unrecognized equity carrying costs, as of the date of the order, with any remaining balance to be credited to CSPCo’s customers on a per kilowatt basis which began with the first billing cycle in February 2011 through December 2011.  Several parties, including CSPCo and OPCo, have filed requests for rehearing with the PUCO, which remain pending.  CSPCo and OPCo are required to file their 2010 SEET filing with the PUCO in 2011.  Based upon the approach in the PUCO 2009 order, management does not currently believe that there are significantly excessive earnings in 2010.

Management is unable to predict the outcome of the various ongoing ESP proceedings and litigation discussed above.  If these proceedings, including future SEET filings, result in adverse rulings, it could reduce future net income and cash flows and impact financial condition.

Proposed January 2012 – May 2014 ESP

In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing on a combined company basis for generation effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  The ESP also includes alternative energy resource requirements and addresses provisions regarding distribution service, energy efficiency requirements, economic development, job retention in Ohio and other matters.  The SSO presents redesigned generation rates by customer class.  Customer class rates individually vary, but on average, customers will experience net base generation increases of 1.4% in 2012 and 2.7% for the period January 2013 through May 2014.

Proposed CSPCo and OPCo Merger

In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo.  Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company.  In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo.  CSPCo and OPCo requested the reorganization transaction be effective in October 2011.  Decisions are pending from the PUCO and the FERC.

 
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Requested Sporn Unit 5 Shutdown and Proposed Distribution Rider

In October 2010, OPCo filed an application with the PUCO for the approval of a December 2010 closure of Sporn Unit 5 and the simultaneous establishment of a new non-bypassable distribution rider, outside the rate caps established in the 2009 – 2011 ESP proceeding.  The proposed rider would recover the net book value of the unit as well as related materials and supplies as of December 2010, which is estimated to be $ 59 million, as well as future closure costs incurred after December 2010.  OPCo also requested authority to record the future closure costs as a regulatory asset or regulatory liability with a weighted average cost of capital carrying charge to be included in the proposed non-bypassable distribution rider after they are incurred.  Also in October 2010, OPCo filed a retirement notification with PJM pending PUCO approval of OPCo’s application to close Sporn Unit 5, which was granted by PJM.  Pending PUCO approval, Sporn Unit 5 continues to operate.  Management is unable to predict the outcome of this proceeding.

2009 Fuel Adjustment Clause Audit

As required under the ESP orders, the PUCO selected an outside consultant to conduct the audit of the FAC for the period of January 2009 through December 2009.  In May 2010, the outside consultant provided their confidential audit report to the PUCO.  The audit report included a recommendation that the PUCO should review whether any proceeds from a 2008 coal contract settlement agreement which totaled $72 million should reduce OPCo’s FAC under-recovery balance.  Of the total proceeds, approximately $58 million was recognized as a reduction to fuel expense prior to 2009 and $14 million reduced fuel expense in 2009 and 2010.  Hearings were held in August 2010.  If the PUCO orders any portion of the $58 million previously recognized or potential other future adjustments be used to reduce the current year FAC deferral, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

CSPCo, OPCo and Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet.  This interim arrangement was approved by the PUCO and was effective from January 2009 through September 2009.  In March 2009, the PUCO approved a FAC in the ESP filings.  The approval of the FAC, together with the PUCO approval of the interim arrangement, provided the basis to record regulatory assets for the difference between the approved market price and the rate paid by Ormet.  The Industrial Energy Users-Ohio, CSPCo and OPCo filed Notices of Appeal regarding aspects of this decision with the Supreme Court of Ohio.  A hearing at the Supreme Court of Ohio was held in February 2011.  Through September 2009, the last month of the interim arrangement, CSPCo and OPCo had $ 30 million and $34 million, respectively, of deferred FAC related to the interim arrangement including recognized carrying charges.  These amounts exclude $ 1 million and $1 million, respectively, of unrecognized equity carrying costs.  In November 2009, CSPCo and OPCo requested that the PUCO approve recovery of the deferrals under the interim agreement plus a weighted average cost of capital carrying charge.  The interim arrangement deferrals are included in CSPCo’s and OPCo’s FAC phase-in deferral balances.  See “Ohio Electric Security Plan Filings” section above.  In the ESP proceeding, intervenors requested that CSPCo and OPCo be required to refund the Ormet-related regulatory assets and requested that the PUCO prevent CSPCo and OPCo from collecting the Ormet-related revenues in the future.  The PUCO did not take any action on this request in the ESP proceeding.  The intervenors raised the issue again in response to CSPCo’s and OPCo’s November 2009 filing to approve recovery of the deferrals under the interim agreement.  If CSPCo and OPCo are not ultimately permitted to fully recover their requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

Economic Development Rider

In April 2010, the Industrial Energy Users-Ohio filed a notice of appeal of the 2009 PUCO-approved Economic Development Rider (EDR) with the Supreme Court of Ohio.  The EDR collects from ratepayers the difference between the standard tariff and lower contract billings to qualifying industrial customers, subject to PUCO approval.  The Industrial Energy Users-Ohio raised several issues including claims that (a) the PUCO lost jurisdiction over CSPCo’s and OPCo’s ESP proceedings and related proceedings when the PUCO failed to issue ESP orders within the 150-day statutory deadline, (b) the EDR should not be exempt from the ESP annual rate limitations and (c) CSPCo and OPCo should not be allowed to apply a weighted average long-term debt carrying cost on deferred EDR regulatory assets.

 
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In June 2010, Industrial Energy Users-Ohio filed a notice of appeal of the 2010 PUCO-approved EDR with the Supreme Court of Ohio.  The Industrial Energy Users-Ohio raised the same issues as noted in the 2009 EDR appeal plus a claim that CSPCo and OPCo should not be able to take the benefits of the higher ESP rates while simultaneously challenging the ESP orders.

As of December 31, 2010, CSPCo and OPCo have incurred $ 38 million and $30 million, respectively, in EDR costs including carrying costs.  Of these costs, CSPCo and OPCo have collected $ 35 million and $26 million, respectively, through the EDR, which CSPCo and OPCo began collecting in January 2010.  The remaining $ 3 million and $4 million for CSPCo and OPCo, respectively, are recorded as EDR regulatory assets.  If CSPCo and OPCo are not ultimately permitted to recover their deferrals or are required to refund revenue collected, it would reduce future net income and cash flows and impact financial condition.

Environmental Investment Carrying Cost Rider

In February 2010, CSPCo and OPCo filed an application with the PUCO to establish an Environmental Investment Carrying Cost Rider to recover carrying costs for 2009 through 2011 related to environmental investments made in 2009.  The carrying costs include both a return of and on the environmental investments as well as related administrative and general expenses and taxes.  In August 2010, the PUCO issued an order approving a rider of approximately $26 million and $34 million for CSPCo and OPCo, respectively, effective September 2010.  The implementation of the rider will likely not impact cash flows since this rider is subject to the rate increase caps authorized by the PUCO in the ESP proceedings, but will increase the ESP phase-in plan deferrals associated with the FAC.

Ohio IGCC Plant

In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant.  Through December 31, 2010, CSPCo and OPCo have each collected $12 million in pre-construction costs authorized in a June 2006 PUCO order and each incurred $11 million in pre-construction costs.  As a result, CSPCo and OPCo each established a net regulatory liability of approximately $ 1 million.  The order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant before June 2011, all pre-construction costs that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest.  Intervenors have filed motions with the PUCO requesting all pre-construction costs be refunded to Ohio ratepayers with interest.

CSPCo and OPCo will not start construction of an IGCC plant until existing statutory barriers are addressed and sufficient assurance of regulatory cost recovery exists.   Management cannot predict the outcome of any cost recovery litigation concerning the Ohio IGCC plant or what effect, if any, such litigation would have on future net income and cash flows.  However, if CSPCo and OPCo were required to refund all or some of the pre-construction costs collected and the costs incurred were not recoverable in another jurisdiction, it would reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in service in 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, plus an additional $125 million for transmission, excluding AFUDC.  SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $ 125 million for transmission, excluding AFUDC.  As of December 31, 2010, excluding costs attributable to its joint owners, SWEPCo has capitalized approximately $1 billion of expenditures (including AFUDC and capitalized interest of $ 137 million and related transmission costs of $66 million).  As of December 31, 2010, the joint owners and SWEPCo have contractual construction commitments of approximately $321 million (including related transmission costs of $3 million).  SWEPCo’s share of the contractual construction commitments is $235 million.  If the plant is cancelled, the joint owners and SWEPCo would incur contractual construction cancellation fees, based on construction status as of December 31, 2010, of approximately $121   million (including related transmission cancellation fees of $ 1 million).  SWEPCo’s share of the contractual construction cancellation fees would be approximately $89 million.

 
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Discussed below are the significant outstanding uncertainties related to the Turk Plant:

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the 88 MW SWEPCo Arkansas jurisdictional share of the Turk Plant.  Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN.  The Arkansas Supreme Court ultimately concluded that the APSC erred in determining the need for additional power supply resources in a proceeding separate from the proceeding in which the APSC granted the CECPN.  However, the Arkansas Supreme Court approved the APSC’s procedure of granting CECPNs for transmission facilities in dockets separate from the Turk Plant CECPN proceeding.  SWEPCo filed a notice with the APSC of its intent to proceed with construction of the Turk Plant but that SWEPCo no longer intends to pursue a CECPN to seek recovery of the originally approved 88 MW portion of Turk Plant costs in Arkansas retail rates.  In June 2010, the APSC issued an order which reversed and set aside the previously granted CECPN.

The PUCT issued an order approving 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 construction cost, excluding AFUDC and 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.  SWEPCo appealed the PUCT’s order contending the two cost cap restrictions are unlawful.  The Texas Industrial Energy Consumers filed an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant was unnecessary to serve retail customers.  In February 2010, the Texas District Court affirmed the PUCT’s order in all respects.  In March 2010, SWEPCo and the Texas Industrial Energy Consumers appealed this decision to the Texas Court of Appeals.

The LPSC approved SWEPCo’s application to construct the Turk Plant.  The Sierra Club filed a complaint with the LPSC to begin an investigation into the construction of the Turk Plant.  In November 2010, the LPSC dismissed the complaint.

In November 2008, SWEPCo received its required air permit approval from the Arkansas Department of Environmental Quality and commenced construction at the site.  The Arkansas Pollution Control and Ecology Commission (APCEC) upheld the air permit.  The parties who unsuccessfully appealed the air permit to the APCEC filed a notice of appeal with the Circuit Court of Hempstead County, Arkansas.   In December 2010, the Circuit Court affirmed the APCEC.  In January 2011, the same parties asked the Arkansas Court of Appeals to overturn the Circuit Court’s December 2010 decision.  A decision from the Arkansas Court of Appeals is pending.

A wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009.  In 2010, the Sierra Club, the Audubon Society and others filed a complaint in the Federal District Court for the Western District of Arkansas against the U.S. Army Corps of Engineers challenging the process used and the terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts, and sought a preliminary injunction to halt construction and for a temporary restraining order.  In July 2010, the Hempstead County Hunting Club also filed a complaint with the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of the Interior and the U.S. Fish and Wildlife Service seeking a temporary restraining order and preliminary injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws.  The plaintiffs’ federal law claims challenge the process used and terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts.  The plaintiffs’ state law claims challenge SWEPCo's ability to construct the Turk Plant without obtaining a certificate from the APSC.  In 2010, the motions for preliminary injunction were partially granted and upheld on appeal pending a hearing.  According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop.  Mitigation measures required by the permit are authorized and may be completed.  The preliminary injunction affects portions of the water intake and associated piping and portions of the transmission lines.  A hearing on SWEPCo’s appeal is scheduled for March 2011.  In October 2010, the Federal District Court certified issues relating to the state law claims to the Arkansas Supreme Court, including whether those claims are within the primary jurisdiction of the APSC.  The Arkansas Supreme Court accepted the request.

 
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In January 2009, SWEPCo was granted CECPNs by the APSC to build three transmission lines and facilities authorized by the SPP and needed to transmit power from the Turk Plant.  Intervenors appealed the CECPN decisions in April 2009 to the Arkansas Court of Appeals.  In July 2010, the Hempstead County Hunting Club and other appellants filed with the Arkansas Court of Appeals emergency motions to stay the transmission CECPNs to prohibit SWEPCo from taking ownership of private property and undertaking construction of the transmission lines.  The Arkansas Court of Appeals issued a decision in July 2010 remanding all transmission line CECPN appeals to the APSC.  As a result, a stay was not ordered and construction continues on the affected transmission lines.  In January 2011, the appellants filed requests to withdraw their appeals at the Court of Appeals and the APSC postponed a scheduled hearing pending a ruling on those requests.  In February 2011, the Court of Appeals dismissed the appeals, and the APSC subsequently closed the remand docket, finding the CECPN decisions final and non-appealable.  As previously discussed, the preliminary injunction issued by the Federal District Court related to the wetlands permit also impacts the uncompleted construction on portions of the transmission lines.

Management expects that SWEPCo will ultimately be able to complete construction of the Turk Plant and related transmission facilities and place those facilities in service.  However, if SWEPCo is unable to complete the Turk Plant construction, including the related transmission facilities, and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.

Stall Unit

SWEPCo constructed the Stall Unit, an intermediate load 500 MW natural gas-fired combustion turbine combined cycle generating unit, at its existing Arsenal Hill Plant located in Shreveport, Louisiana.  The LPSC and the APSC issued orders capping SWEPCo’s Stall Unit construction costs at $ 445 million including AFUDC and excluding related transmission costs.  The Stall Unit was placed in service in June 2010.  As of December 31, 2010, the Stall Unit cost applicable to the cap was $426 million, including $ 49 million of AFUDC.  Management does not expect the final costs of the Stall Unit to exceed the ordered cap.  In July 2010, the Stall Unit was placed into Arkansas rates.  SWEPCo received CWIP treatment for a portion of the Stall Unit in the 2009 Texas Base Rate Filing.  See “2009 Texas Base Rate Filing” section below.  The Stall Unit will be phased into Louisiana rates between October 2010 and October 2011.

2009 Texas Base Rate Filing

In August 2009, SWEPCo filed a rate case with the PUCT to increase its base rates by approximately $75 million annually including a return on common equity of 11.5%.  The filing included requests for financing cost riders of $ 32 million related to construction of the Stall Unit and Turk Plant, a vegetation management rider of $16 million and other requested increases of $ 27 million.  In April 2010, a settlement agreement was approved by the PUCT to increase SWEPCo’s base rates by approximately $15 million annually, effective May 2010, including a return on common equity of 10.33%, which consists of $5 million related to construction of the Stall Unit and $ 10 million in other increases.  In addition, the settlement agreement decreased annual depreciation expense by $17 million and allowed SWEPCo a $ 10 million one-year surcharge rider to recover additional vegetation management costs that SWEPCo must spend within two years.

Texas Fuel Reconciliation

In May 2010, various intervenors, including the PUCT staff, filed testimony recommending disallowances ranging from $ 3 million to $30 million in SWEPCo’s $ 755 million fuel and purchased power costs reconciliation for the period January 2006 through March 2009.  In July 2010, Cities Advocating Reasonable Deregulation filed testimony regarding the 2007 transfer of ERCOT trading contracts to AEPEP.  The testimony included unquantified refund recommendations relating to re-pricing of contract transactions.

In September 2010, the Administrative Law Judges issued a Proposal for Decision (PFD) that recommended a disallowance of a significant portion of the charges under a ten-year gas transportation agreement that began in 2009 for the Mattison Plant located in northwest Arkansas.  In January 2011, the PUCT issued an order which overturned a portion of the PFD that recommended a finding of imprudence on the Mattison gas contract.  The impact of this order had an immaterial impact on SWEPCo’s financial statements.

 
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TCC and TNC Rate Matters

TEXAS RESTRUCTURING

Texas Restructuring Appeals

Pursuant to PUCT restructuring orders, TCC securitized net recoverable stranded generation costs of $ 2.5 billion and is recovering the principal and interest on the securitization bonds through the end of 2020.  TCC also refunded other net true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider under PUCT restructuring orders.  TCC and intervenors appealed the PUCT’s true-up related orders.  After rulings from the Texas District Court and the Texas Court of Appeals, TCC, the PUCT and intervenors filed petitions for review with the Texas Supreme Court.  Review is discretionary and the Texas Supreme Court has not yet determined if it will grant review.  The Texas Supreme Court requested a full briefing which has concluded.  The following represent issues where either the Texas District Court or the Texas Court of Appeals recommended the PUCT decision be modified:

·  
The Texas District Court judge determined that the PUCT erred by applying an invalid rule to determine the carrying cost rate for the true-up of stranded costs.  The Texas Court of Appeals reversed the District Court’s unfavorable decision.  An October 2010 decision of the Texas Supreme Court addressing the same issue for another utility upholds the Court of Appeals determination.

·  
The Texas District Court judge determined that the PUCT improperly reduced TCC’s net stranded plant costs for commercial unreasonableness. This favorable decision was affirmed by the Texas Court of Appeals.

·  
The Texas Court of Appeals determined that the PUCT erred by not reducing stranded costs by the “excess earnings” that had already been refunded to affiliated Retail Electric Providers (REPs).  This decision could be unfavorable unless the PUCT allows TCC to recover the refunds previously made to the REPs.  See the “TCC Excess Earnings” section below.

Management cannot predict the outcome of the pending court proceedings and the PUCT remand decisions.  If TCC ultimately succeeds in its appeals, it could have a favorable effect on future net income, cash flows and possibly financial condition.  If intervenors succeed in their appeals, it could reduce future net income and cash flows and possibly impact financial condition.

TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes

In 2006, the PUCT reduced recovery of the amount securitized by $ 103 million of tax benefits and associated carrying costs related to TCC’s generation assets.  In 2006, TCC obtained a private letter ruling from the IRS which confirmed that such reduction was an IRS normalization violation.  In order to avoid a normalization violation, the PUCT agreed to allow TCC to defer refunding the tax benefits of $103 million plus interest through the CTC refund period pending resolution of the normalization issue.  In 2008, the IRS issued final regulations, which supported the IRS’ private letter ruling which would make the refunding of or the reduction of the amount securitized by such tax benefits a normalization violation.  After the IRS issued its final regulations, at the request of the PUCT, the Texas Court of Appeals remanded the tax normalization issue to the PUCT for the consideration of additional evidence including the IRS regulations.  TCC is not accruing interest on the $103 million because it is not probable that the PUCT will order TCC to violate the normalization provision of the Internal Revenue Code.  If interest were accrued, management estimates interest expense would have been approximately $ 22 million higher for the period July 2008 through December 2010.

Management believes that the PUCT will ultimately allow TCC to retain the deferred amounts, which would have a favorable effect on future net income and cash flows.  Although unexpected, if the PUCT fails to issue a favorable order and orders TCC to return the tax benefits to customers, the resulting normalization violation could result in TCC’s repayment to the IRS of Accumulated Deferred Investment Tax Credits (ADITC) on all property, including transmission and distribution property.  This amount approximates $101 million as of December 31, 2010.  It could also lead to a loss of TCC’s right to claim accelerated tax depreciation in future tax returns.  If TCC is required to repay its ADITC to the IRS and is also required to refund ADITC plus unaccrued interest to customers, it would reduce future net income and cash flows and impact financial condition.

 
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TCC Excess Earnings

In 2005, a Texas appellate court issued a decision finding that a PUCT order requiring TCC to refund to the Retail Electric Providers (REPs) excess earnings prior to and outside of the true-up process was unlawful under the Texas Restructuring Legislation.  From 2002 to 2005, TCC refunded $ 55 million of excess earnings, including interest, under the overturned PUCT order.  On remand, the PUCT must determine how to implement the Court of Appeals decision given that the unauthorized refunds were made to the REPs in lieu of reducing stranded costs in the true-up proceeding.

Certain parties have taken positions that, if adopted, could result in TCC being required to refund excess earnings and interest through the true-up process without receiving a refund from the REPs.  If this were to occur, it would reduce future net income and cash flows and impact financial condition.  Management cannot predict the outcome of the excess earnings remand.

OTHER TEXAS RATE MATTERS

Texas Base Rate Appeal

TCC filed a base rate case in 2006 seeking to increase base rates.  The PUCT issued an order in 2007 which increased TCC’s base rates by $ 20 million, eliminated a merger credit rider of $20 million and reduced depreciation rates by $ 7 million.  The PUCT decision was appealed by TCC and various intervenors.  On appeal, the Texas District Court affirmed the PUCT in most respects and the Texas Court of Appeals affirmed the Texas District Court’s decision.  The order became final with an August 2010 Texas Court of Appeals mandate.

ETT 2007 Formation Appeal

ETT is a joint venture between AEP Utilities, Inc. and MidAmerican Energy Holdings Company Texas Transco, LLC.  TCC and TNC have sold transmission assets both in service and under construction to ETT.  The PUCT approved ETT's initial rates, a request for a transfer of in-service assets and CWIP and a certificate of convenience and necessity (CCN) to operate as a stand alone transmission utility in ERCOT.  ETT was allowed a 9.96% return on common equity.  Intervenors appealed the PUCT’s decision but the Texas Court of Appeals affirmed the PUCT's decision in all material respects.  The deadline to appeal this decision to the Texas Supreme Court has expired.

In a separate development, the Texas governor signed a new law that clarifies the PUCT’s authority to grant CCNs to transmission only utilities such as ETT.  ETT filed an application with the PUCT for a CCN under the new law.  In March 2010, the PUCT approved the application for a CCN under the new law.

APCo and WPCo Rate Matters

2009 Virginia Base Rate Case

In July 2009, APCo filed a generation and distribution base rate increase with the Virginia SCC of $154 million annually based on a 13.35% return on common equity.  Interim rates, subject to refund, became effective in December 2009 but were discontinued in February 2010 when newly enacted Virginia legislation suspended the collection of interim rates.  In July 2010, the Virginia SCC issued an order approving a $ 62 million increase based on a 10.53% return on common equity.  The order denied recovery of the Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility, which resulted in a pretax write-off of $ 54 million in Other Operation.  See “Mountaineer Carbon Capture and Storage Project” section below.  In addition, the order allowed the deferral of approximately $25 million of incremental storm expense incurred in 2009.  Approximately $ 3 million, including interest, was refunded to customers in September 2010 related to the collection of interim rates.

2010 West Virginia Base Rate Case

In May 2010, APCo and WPCo filed a request with the WVPSC to increase annual base rates by $ 156 million based on an 11.75% return on common equity to be effective March 2011.  The filing also included a request for recovery of and a return on the West Virginia jurisdictional share of the Mountaineer Carbon Capture and Storage Product
 
 
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Validation Facility.  In December 2010, a settlement agreement was filed with the WVPSC to increase annual base rates by $ 60 million, effective March 2011.  The settlement agreement allows APCo to defer and amortize up to $18 million of previously expensed 2009 incremental storm expenses over a period of eight years.  A decision from the WVPSC is expected in March 2011.

Mountaineer Carbon Capture and Storage Project

Product Validation Facility (PVF)

APCo and ALSTOM Power, Inc., an unrelated third party, jointly constructed a CO 2 capture validation facility, which was placed into service in September 2009.  APCo also constructed and owns the necessary facilities to store the CO 2 .  In October 2009, APCo started injecting CO 2 into the underground storage facilities.  The injection of CO 2 required the recording of an asset retirement obligation and an offsetting regulatory asset.  As of December 31, 2010, APCo has recorded a noncurrent regulatory asset of $60 million related to the PVF.

In APCo’s July 2009 Virginia base rate filing, APCo requested recovery of and a return on its Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion.  In July 2010, the Virginia SCC issued a base rate order that denied recovery of the Virginia share of the PVF costs.  See “2009 Virginia Base Rate Case” section above.

In APCo’s and WPCo’s May 2010 West Virginia base rate filing, APCo and WPCo requested recovery of and a return on their West Virginia jurisdictional share of the project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion.  In December 2010, a settlement agreement was filed with the WVPSC to increase annual base rates by $ 60 million, effective March 2011.  A decision from the WVPSC is expected in March 2011.  If APCo cannot recover its remaining investment in and expenses related to the PVF, it would reduce future net income and cash flows and impact financial condition.

Carbon Capture and Sequestration Project with the Department of Energy (DOE)

During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale carbon capture and sequestration (CCS) facility under consideration at the Mountaineer Plant.  AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project.  The DOE will fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million.  A Front-End Engineering and Design (FEED) study, scheduled for completion during the third quarter of 2011, will refine the total cost estimate for the CCS facility.  Results from the FEED study will be evaluated by management before any decision is made to seek the necessary regulatory approvals to build the CCS facility.  As of December 31, 2010, APCo has incurred $ 14 million in total costs and has received $5 million of DOE funding resulting in a net $ 9 million balance included in Construction Work In Progress on the Consolidated Balance Sheets.  If APCo is unable to recover the costs of the CCS project, it would reduce future net income and cash flows.
 
APCo’s Filings for an IGCC Plant

In 2008, the Virginia SCC issued an order denying APCo’s request for a surcharge rate mechanism to provide for the timely recovery of pre-construction costs and the ongoing financing costs of the project during the construction period, as well as the capital costs, operating costs and a return on common equity once the facility is placed into commercial operation. The order was based upon the Virginia SCC's finding that the estimated cost of the plant was uncertain and may escalate.  The Virginia SCC also expressed concerns that the estimated costs did not include a retrofitting of carbon capture and sequestration facilities.  During 2009, based on the order received in Virginia, the WVPSC removed the IGCC case as an active case from its docket and indicated that the conditional CPCN granted in 2008 must be reconsidered if and when APCo proceeds with the IGCC plant.

Through December 31, 2010, 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 $ 9 million applicable to its Virginia jurisdiction.

APCo will not start construction of the IGCC plant until sufficient assurance of full cost recovery exists in Virginia and West Virginia.  If the plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs which, if not recoverable, would reduce future net income and cash flows and impact financial condition.

 
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APCo’s and WPCo’s Expanded Net Energy Charge (ENEC) Filing

In September 2009, the WVPSC issued an order approving APCo’s and WPCo’s March 2009 ENEC request.  The approved order provided for recovery of an under-recovered balance plus a projected increase in ENEC costs over a four-year phase-in period with an overall increase of $ 355 million and a first-year increase of $124 million, effective October 2009.  The WVPSC also approved a fixed annual carrying cost rate of 4%, effective October 2009, to be applied to the incremental deferred regulatory asset balance that will result from the phase-in plan and lowered annual coal cost projections by $27 million.

In June 2010, the WVPSC approved a settlement agreement for $ 96 million, including $10 million of construction surcharges related to APCo’s and WPCo’s second year ENEC increase.  The settlement agreement provided for recovery of the amounts related to the renegotiated coal contracts and allows APCo to accrue weighted average cost of capital carrying charge on the excess under-recovery balance due to the ENEC phase-in as adjusted for the impacts of Accumulated Deferred Income Taxes.  As of December 31, 2010, APCo’s ENEC under-recovery balance was $ 361 million, excluding $3 million of unrecognized equity carrying costs, which is included in noncurrent regulatory assets.  The new rates became effective in July 2010.

PSO Rate Matters

PSO Fuel and Purchased Power

2006 and Prior Fuel and Purchased Power

The OCC filed a complaint with the FERC related to the allocation of off-system sales margins (OSS) among the AEP operating companies in accordance with a FERC-approved allocation agreement.  The FERC issued an adverse ruling in 2008.  As a result, PSO recorded a regulatory liability in 2008 to return reallocated OSS to customers.  Starting in March 2009, PSO refunded the additional reallocated OSS to its customers through February 2010.

A reallocation of purchased power costs among AEP West companies for periods prior to 2002 resulted in an under-recovery of $ 42 million of PSO fuel costs.  PSO recovered the $42 million by offsetting it against an existing fuel over-recovery during the period June 2007 through May 2008.  The Oklahoma Industrial Energy Consumers (OIEC) contended that PSO should not have collected the $ 42 million without specific OCC approval.  In December 2010, the OCC issued orders which approved PSO’s 2006 and prior fuel and purchased power costs without any adjustments.

2008 Fuel and Purchased Power

In July 2009, the OCC initiated a proceeding to review PSO’s fuel and purchased power adjustment clause for the calendar year 2008 and also initiated a prudence review of the related costs.  In March 2010, the Oklahoma Attorney General and the OIEC recommended the fuel clause adjustment rider be amended so that the shareholder’s portion of off-system sales margins decrease from 25% to 10%.  The OIEC also recommended that the OCC conduct a comprehensive review of all affiliate transactions during 2007 and 2008.  In July 2010, additional testimony regarding the 2007 transfer of ERCOT trading contracts to AEPEP was filed.  The testimony included unquantified refund recommendations relating to re-pricing of contract transactions.  Hearings are currently scheduled for March 2011.  If the OCC were to issue an unfavorable decision, it could reduce future net income and cash flows and impact financial condition.

2008 Oklahoma Base Rate Appeal

In January 2009, the OCC issued a final order approving an $ 81 million increase in PSO’s non-fuel base revenues based on a 10.5% return on common equity.  The new rates reflecting the final order were implemented with the first billing cycle of February 2009.  PSO and intervenors appealed various issues but the Court of Civil Appeals affirmed the OCC's decision.  No parties sought rehearing or appeal and, as a result, this case has concluded.

 
74
 
2010 Oklahoma Base Rate Case

In July 2010, PSO filed a request with the OCC to increase annual base rates by $82 million, including $30 million that is currently being recovered through a rider.  The requested net annual increase to ratepayers would be $52 million.  The requested increase included a $24 million increase in depreciation and an 11.5% return on common equity.  In January 2011, the OCC approved a settlement agreement which did not change annual revenue or depreciation rates, but transferred $30 million into base rates that was previously being recovered through a capital investment rider.  The order provided a 10.15% return on common equity and new rates were effective in February 2011.

I&M Rate Matters

Indiana Fuel Clause Filing (Cook Plant Unit 1 Fire and Shutdown)

I&M filed applications with the IURC to increase its fuel adjustment charge by approximately $ 53 million for the period of April 2009 through September 2009.  The filings sought increases for previously under-recovered fuel clause expenses.

As fully discussed in the “Cook Plant Unit 1 Fire and Shutdown” section of Note 6, Cook Plant Unit 1 (Unit 1) was shut down in September 2008 due to significant turbine damage and a small fire on the electric generator.  Unit 1 was placed back into service in December 2009 at slightly reduced power.  The unit outage resulted in increased replacement power fuel costs.  The filing only requested the cost of replacement power through mid-December 2008, the date when I&M began receiving accidental outage insurance proceeds.  I&M committed to absorb the remaining costs of replacement power through the date the unit returned to service, which occurred in December 2009.

I&M reached an agreement with intervenors, which was approved by the IURC in March 2009, to collect its existing prior period under-recovery regulatory asset deferral balance over twelve months instead of over six months as initially proposed.  Under the agreement, the fuel factors were placed into effect, subject to refund, and a subdocket was established to consider issues relating to the Unit 1 shutdown including the treatment of the accidental outage insurance proceeds.  I&M maintains a separate accidental outage policy with NEIL.  In 2009, I&M recorded $185 million in revenue under the policy and reduced the cost of replacement power in customers’ bills by $78 million.

In October 2010, the Indiana/Michigan Industrial Group and the Indiana Office of Utility Consumer Counselor filed testimony which recommended I&M pay to customers a portion of the accidental outage insurance proceeds up to the extent not previously paid to customers through the fuel adjustment clause or needed to cover costs not covered by I&M’s property damage insurance policy.  In January 2011, a settlement agreement was filed with the IURC.  The settlement stated (a) that I&M will credit an additional $14 million to customers through the fuel adjustment clause, (b) that the parties to the settlement will not oppose the need to replace the existing low-pressure turbine at Cook Unit 1, and (c) that the parties to the settlement agree that the cost of the replacement should not be offset by the accidental outage insurance proceeds received by I&M.  In February 2011, the IURC approved the settlement agreement as filed.
 
Michigan 2009 Power Supply Cost Recovery (PSCR) Reconciliation (Cook Plant Unit 1 Fire and Shutdown)

In March 2010, I&M filed its 2009 PSCR reconciliation with the MPSC.  The filing included an adjustment to exclude from the PSCR the incremental fuel cost of replacement power due to the Unit 1 outage from mid-December 2008 through December 2009, the period during which I&M received and recognized the accidental outage insurance proceeds.  Management believes that I&M is entitled to retain the accidental outage insurance proceeds since it made customers whole regarding the replacement power costs.  In October 2010, a settlement agreement was filed with the MPSC which included deferring the Unit 1 outage issue to the 2010 PSCR reconciliation, which will be filed in March 2011.  If any fuel clause revenues or accidental outage insurance proceeds have to be paid to customers, it would reduce future net income and cash flows and impact financial condition.  See the “Cook Plant Unit 1 Fire and Shutdown” section of Note 6.

 
75
 
Michigan Base Rate Filing

In January 2010, I&M filed with the MPSC a request for a $63 million increase in annual base rates based on an 11.75% return on common equity.  Starting with the August 2010 billing cycle, I&M, with MPSC authorization, implemented a $ 44 million interim rate increase.  The interim increase excluded new trackers and regulatory assets for which I&M was not currently incurring expenses.  In October 2010, a settlement agreement was approved by the MPSC to increase annual base rates by $36 million based on a 10.35% return on common equity, effective December 2010, plus separate recovery of approximately $7 million of customer choice implementation costs over a two year period beginning April 2011.  In addition, the approved revenue requirement includes the amortization of $6 million in previously expensed restructuring costs over five years, which I&M deferred in October 2010 and began amortizing in December 2010.  Also, the approved settlement agreement provided for sharing of off-system sales margins between customers (75%) and I&M ( 25%) with customers receiving a credit in future Power Supply Cost Recovery proceedings for their jurisdictional share of any off-system sales margins.  Through December 2010, I&M recorded a provision for refund of $3 million, including interest, related to interim rates that were in effect through November 2010.  In January 2011, I&M filed an application with the MPSC requesting the MPSC find that $3 million, including interest, is the total amount to be refunded to customers.  I&M is proposing to refund this amount to customers during April 2011.  A decision from the MPSC is pending.

Kentucky Rate Matters

Kentucky Base Rate Filing

In December 2009, KPCo filed a base rate case with the KPSC to increase base revenues by $124 million annually based on an 11.75% return on common equity.  The base rate case also requested recovery of deferred storm restoration expenses over a three-year period.  In June 2010, the KPSC approved a settlement agreement to increase base revenues by $64 million annually based on a 10.5% return on common equity.  The settlement agreement included recovery of $23 million of deferred storm restoration expenses over five years.  New rates became effective with the first billing cycle of July 2010.

FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund

In 2004, AEP eliminated transaction-based through-and-out transmission service (T&O) charges in accordance with FERC orders and collected, at the FERC’s direction, load-based charges, referred to as RTO SECA, to partially mitigate the loss of T&O revenues on a temporary basis through March 2006.  Intervenors objected to the temporary SECA rates.  The FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund.  The AEP East companies recognized gross SECA revenues of $ 220 million from 2004 through 2006 when the SECA rates terminated.

In 2006, a FERC Administrative Law Judge (ALJ) issued an initial decision finding that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made.  The ALJ also found that any unpaid SECA rates must be paid in the recommended reduced amount.

AEP filed briefs jointly with other affected companies asking the FERC to reverse the decision.  In May 2010, the FERC issued an order that generally supports AEP’s position and required a compliance filing to be filed with the FERC by August 2010.  In June 2010, AEP and other affected companies filed a joint request for rehearing with the FERC.

In August 2010, the affected companies, including the AEP East companies, filed a compliance filing with the FERC.  If the compliance filing is accepted, the AEP East companies would have to pay refunds of approximately $20 million including estimated interest of $ 5 million.  The AEP East companies could also potentially receive payments up to approximately $10 million including estimated interest of $ 3 million.  A decision is pending from the FERC.
 
 
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The FERC has approved settlements applicable to $112 million of SECA revenue.  The AEP East companies provided reserves for net refunds for SECA settlements applicable to the remaining $108 million of SECA revenues collected.  Based on the AEP East companies’ analysis of the May 2010 order and the compliance filing, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the May 2010 order or the compliance filing be made final.  Management cannot predict the ultimate outcome of this proceeding at the FERC which could impact future net income and cash flows.

Modification of the Transmission Agreement (TA)

The AEP East companies are parties to the TA that provides for a sharing of the cost of transmission lines operated at 138-kV and above and transmission stations containing extra-high voltage facilities.  In June 2009, AEPSC, on behalf of the parties to the TA, filed with the FERC a request to modify the TA.  Under the proposed amendments, KGPCo and WPCo will be added as parties to the TA.  In addition, the amendments would provide for the allocation of PJM transmission costs generally on the basis of the TA parties’ 12-month coincident peak and reimburse transmission revenues based on individual cost of service instead of the MLR method used in the present TA.  In October 2010, the FERC approved a settlement agreement for the new TA effective November 1, 2010.  The impacts of the settlement agreement will be phased-in for retail rate making purposes in certain jurisdictions over periods of up to four years.

PJM/MISO Market Flow Calculation Settlement Adjustments

During 2009, an analysis conducted by MISO and PJM discovered several instances of unaccounted for power flows on numerous coordinated flowgates.  These flows affected the settlement data for congestion revenues and expenses and dated back to the start of the MISO market in 2005.  In January 2011, PJM and MISO reached a settlement agreement where the parties agreed to net various issues to zero.  This settlement was filed with the FERC in January 2011.  PJM and MISO are currently awaiting final approval from the FERC.

 
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5.   EFFECTS OF REGULATION

Regulatory assets are comprised of the following items:
 
 
 
 
 
December 31,
 
Remaining
 
 
 
 
 
2010 
 
2009 
 
Recovery Period
Current Regulatory Assets
 
(in millions)
 
 
Under-recovered Fuel Costs - earns a return
 
$
 73 
 
$
 85 
 
1 year
Under-recovered Fuel Costs - does not earn a return
 
 
 8 
 
 
 - 
 
1 year
Total Current Regulatory Assets
 
$
 81 
 
$
 85 
 
 
 
 
 
 
 
 
 
 
 
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
 
 
 
 
 
 
 
 
 
 
Customer Choice Deferrals - CSPCo, OPCo
 
$
 59 
 
$
 57 
 
 
 
 
Storm Related Costs - CSPCo, OPCo, TCC
 
 
 55 
 
 
 49 
 
 
 
 
Line Extension Carrying Costs - CSPCo, OPCo
 
 
 55 
 
 
 43 
 
 
 
 
Acquisition of Monongahela Power - CSPCo
 
 
 8 
 
 
 10 
 
 
 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 7 
 
 
 1 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
 
 
 
Mountaineer Carbon Capture and Storage Product Validation Facility - APCo
 
 
 60 
 
 
 111 
 
 
 
 
Environmental Rate Adjustment Clause - APCo
 
 
 56 
 
 
 25 
 
 
 
 
Storm Related Costs - APCo, KGPCo, PSO, SWEPCo
 
 
 45 
 
 
 - 
 
 
 
 
Deferred Wind Power Costs - APCo
 
 
 29 
 
 
 5 
 
 
 
 
Special Rate Mechanism for Century Aluminum - APCo
 
 
 13 
 
 
 12 
 
 
 
 
Acquisition of Monongahela Power - CSPCo
 
 
 4 
 
 
 - 
 
 
 
 
Transmission Rate Adjustment Clause - APCo
 
 
 - 
(a)
 
 26 
 
 
 
 
Storm Related Costs - KPCo
 
 
 - 
(b)
 
 24 
 
 
 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 4 
 
 
 18 
 
 
Total Regulatory Assets Not Yet Being Recovered
 
 
 395 
 
 
 381 
 
 
 
 
 
 
 
 
 
 
 
Regulatory assets being recovered:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
 
 
 
 
 
 
Fuel Adjustment Clause - OPCo
 
 
 476 
 
 
 341 
 
2 to 8 years
 
 
Expanded Net Energy Charge - APCo
 
 
 361 
(c)
 
 - 
 
3 years
 
 
Unamortized Loss on Reacquired Debt
 
 
 93 
 
 
 99 
 
33 years
 
 
Storm Related Costs - PSO
 
 
 38 
 
 
 53 
 
3 years
 
 
RTO Formation/Integration Costs
 
 
 21 
 
 
 23 
 
9 years
 
 
Red Rock Generating Facility - PSO
 
 
 10 
 
 
 11 
 
46 years
 
 
Economic Development Rider - CSPCo, OPCo
 
 
 1 
 
 
 12 
 
1 year
 
 
Other Regulatory Assets Being Recovered
 
 
 21 
 
 
 23 
 
various
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
 
 
 
Pension and OPEB Funded Status
 
 
 2,161 
 
 
 2,139 
 
13 years
 
 
Income Taxes, Net
 
 
 1,097 
 
 
 966 
 
37 years
 
 
Cook Nuclear Plant Refueling Outage Levelization - I&M
 
 
 54 
 
 
 22 
 
3 years
 
 
Postemployment Benefits
 
 
 51 
 
 
 52 
 
4 years
 
 
Storm Related Costs - KPCo
 
 
 21 
(b)
 
 - 
 
5 years
 
 
Transmission Rate Adjustment Clause - APCo
 
 
 19 
(a)
 
 - 
 
2 years
 
 
Asset Retirement Obligation - APCo, I&M
 
 
 15 
 
 
 16 
 
10 years
 
 
Restructuring Transition Costs - TCC
 
 
 14 
 
 
 25 
 
5 years
 
 
Off-system Sales Margin Sharing - I&M
 
 
 13 
 
 
 18 
 
1 year
 
 
Vegetation Management - PSO
 
 
 13 
 
 
 16 
 
1 year
 
 
Virginia Environmental and Reliability Costs Recovery - APCo
 
 
 4 
 
 
 76 
 
3 years
 
 
Expanded Net Energy Charge - APCo
 
 
 - 
(c)
 
 282 
 
 
 
 
Other Regulatory Assets Being Recovered
 
 
 65 
 
 
 40 
 
various
Total Regulatory Assets Being Recovered
 
 
 4,548 
 
 
 4,214 
 
 
 
 
 
 
 
 
 
 
 
Total Noncurrent Regulatory Assets
 
$
 4,943 
 
$
 4,595 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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(a)
Recovery of regulatory asset through the transmission rate adjustment clause.
(b)
Recovery of regulatory asset was granted during 2010.
(c)
The majority of the balance results from the ENEC phase-in plan and earns a weighted average cost of capital carrying charge.

Regulatory liabilities are comprised of the following items:

 
 
 
 
 
December 31,
 
Remaining
 
 
 
 
 
2010 
 
2009 
 
Refund Period
Current Regulatory Liability
 
(in millions)
 
 
Over-recovered Fuel Costs - pays a return
 
$
 16 
 
$
 65 
 
1 year
Over-recovered Fuel Costs - does not pay a return
 
 
 1 
 
 
 11 
 
1 year
Total Current Regulatory Liability
 
$
 17 
 
$
 76 
 
 
 
 
 
 
 
 
 
 
 
Noncurrent Regulatory Liabilities and
 
 
 
 
 
 
 
 
Deferred Investment Tax Credits
 
 
 
 
 
 
 
 
Regulatory liabilities not yet being paid:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Liabilities Currently Paying a Return
 
 
 
 
 
 
 
 
 
 
Refundable Construction Financing Costs - SWEPCo
 
$
 20 
 
$
 - 
 
 
 
 
Other Regulatory Liabilities Not Yet Being Paid
 
 
 - 
 
 
 3 
 
 
 
Regulatory Liabilities Currently Not Paying a Return
 
 
 
 
 
 
 
 
 
 
Over-Recovery of gridSMART® Costs - CSPCo, PSO
 
 
 10 
 
 
 9 
 
 
 
 
Other Regulatory Liabilities Not Yet Being Paid
 
 
 11 
 
 
 10 
 
 
Total Regulatory Liabilities Not Yet Being Paid
 
 
 41 
 
 
 22 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory liabilities being paid:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Liabilities Currently Paying a Return
 
 
 
 
 
 
 
 
 
 
Asset Removal Costs
 
 
 2,222 
 
 
 2,048 
 
(a)
 
 
Advanced Metering Infrastructure Surcharge - TCC, TNC
 
 
 61 
 
 
 30 
 
10 years
 
 
Deferred Investment Tax Credits
 
 
 32 
 
 
 41 
 
up to 12 years
 
 
Excess Earnings - SWEPCo, TNC
 
 
 13 
 
 
 11 
 
43 years
 
 
Transmission Cost Recovery Rider - CSPCo, OPCo
 
 
 2 
 
 
 25 
 
1 year
 
 
Other Regulatory Liabilities Being Paid
 
 
 2 
 
 
 2 
 
various
 
Regulatory Liabilities Currently Not Paying a Return
 
 
 
 
 
 
 
 
 
 
Excess Asset Retirement Obligations for Nuclear Decommissioning
 
 
 
 
 
 
 
 
 
 
 
Liability - I&M
 
 
 354 
 
 
 281 
 
(b)
 
 
Deferred Investment Tax Credits
 
 
 242 
 
 
 239 
 
up to 76 years
 
 
Unrealized Gain on Forward Commitments
 
 
 60 
 
 
 74 
 
5 years
 
 
Spent Nuclear Fuel Liability - I&M
 
 
 42 
 
 
 41 
 
(b)
 
 
Over-recovery of Transition Charges - TCC
 
 
 38 
 
 
 38 
 
9 years
 
 
Deferred State Income Tax Coal Credits - APCo
 
 
 29 
 
 
 28 
 
9 years
 
 
Over-recovery of PJM Expenses - I&M
 
 
 12 
 
 
 18 
 
1 year
 
 
Energy Efficiency/Peak Demand Reduction
 
 
 10 
 
 
 2 
 
2 years
 
 
Other Regulatory Liabilities Being Paid
 
 
 11 
 
 
 9 
 
various
Total Regulatory Liabilities Being Paid
 
 
 3,130 
 
 
 2,887 
 
 
 
 
 
 
 
 
 
 
 
Total Noncurrent Regulatory Liabilities and Deferred Investment Tax
 
 
 
 
 
 
 
 
 
Credits
 
$
 3,171 
 
$
 2,909 
 
 
 
 
 
 
 
 
 
 
 
(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 adverse 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.  We forecast approximately $2.5 billion and $2.6 billion of construction expenditures excluding AFUDC and capitalized interest for 2011 and 2012, respectively.  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 at December 31, 2010:

 
 
Less Than 1
 
 
 
 
 
After
 
 
Contractual Commitments
 
year
 
2-3 years
 
4-5 years
 
5 years
 
Total
 
 
(in millions)
Fuel Purchase Contracts (a)
 
$
 2,810 
 
$
 3,974 
 
$
 2,543 
 
$
 3,718 
 
$
 13,045 
Energy and Capacity Purchase Contracts (b)
 
 
 69 
 
 
 199 
 
 
 204 
 
 
 1,101 
 
 
 1,573 
Total
 
$
 2,879 
 
$
 4,173 
 
$
 2,747 
 
$
 4,819 
 
$
 14,618 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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 contractual commitments for energy and capacity purchase contracts.

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 excess of our ownership percentages.  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 gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

We have two $1.5 billion credit facilities, of which $750 million may be issued under one credit facility as letters of credit.  In June 2010, we terminated one of the $1.5 billion facilities that was scheduled to mature in March 2011 and replaced it with a new $1.5 billion credit facility which matures in 2013 and allows for the issuance of up to $600 million as letters of credit.  As of December 31, 2010, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $124 million with maturities ranging from January 2011 to November 2011.

In June 2010, we reduced a $627 million credit agreement to $478 million.  As of December 31, 2010, $477 million of letters of credit with maturities ranging from March 2011 to April 2011 were issued by subsidiaries under this credit agreement to support variable rate Pollution Control Bonds.

 
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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 approximately $65 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 Mining Company (Sabine), a consolidated variable interest entity.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study, we estimate the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  As of December 31, 2010, SWEPCo has collected approximately $49 million through a rider for final mine closure and reclamation costs, of which $2 million is recorded in Other Current Liabilities, $25 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $22 million is recorded in Asset Retirement Obligations on our Consolidated 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.  The status of certain sale agreements is discussed in the “Dispositions” section of Note 7.  These sale agreements include indemnifications with a maximum exposure related to the collective purchase price.  This maximum exposure of approximately $ 1 billion relates to the Bank of America (BOA) litigation indemnity pertaining to the sale of Houston Pipeline Company in 2005 (see “Enron Bankruptcy” section of this note), of which $448 million is recorded in Current Liabilities – Deferred Gain and Accrued Litigation Costs on the Consolidated Balance Sheet as of December 31, 2010.  In February 2011, all matters related to the BOA litigation were resolved and we paid BOA $425 million.  There are no material amounts recorded for any indemnifications other than the deferred gain (plus interest and attorneys’ fees) related to the BOA litigation which settled in February 2011.

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

Federal EPA Complaint and Notice of Violation

The Federal EPA, certain special interest groups and a number of states alleged that APCo, CSPCo, I&M and OPCo modified certain units at their coal-fired generating plants in violation of the NSR requirements of the CAA.  Cases with similar allegations against CSPCo, Dayton Power and Light Company and Duke Energy Ohio, Inc. were also filed related to their jointly-owned units.  The cases were settled with the exception of a case involving a jointly-owned Beckjord unit which had a liability trial.  Following two liability trials, the jury found no liability at the jointly-owned Beckjord unit.  The defendants and the plaintiffs appealed to the Seventh Circuit Court of Appeals.  In October 2010, the Seventh Circuit dismissed all remaining claims in these cases.  Beckjord is operated by Duke Energy Ohio, Inc.
 
 
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SWEPCo Citizen Suit and Notice of Violation

In 2005, two special interest groups, Sierra Club and Public Citizen, filed a complaint alleging violations of the CAA at SWEPCo’s Welsh Plant.  In 2008, a consent decree resolved all claims in the case and in the pending appeal of an altered permit for the Welsh Plant.  The consent decree required SWEPCo to install continuous particulate emission monitors at the Welsh Plant, secure 65 MW of renewable energy capacity, fund $2 million in emission reduction, energy efficiency or environmental mitigation projects and pay a portion of plaintiffs’ attorneys’ fees and costs.

The Federal EPA issued a Notice of Violation (NOV) based on alleged violations of a percent sulfur in fuel limitation and the heat input values listed in a previous state permit similar to the claims made in the citizen suit.  The NOV also alleges that a permit alteration issued by the Texas Commission on Environmental Quality in 2007 was improper.  In March 2008, SWEPCo met with the Federal EPA to discuss the alleged violations.  The Federal EPA did not object to the settlement of the citizen suit and has taken no further action.  We are unable to predict the timing of any future action by the Federal EPA.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

Carbon Dioxide Public Nuisance Claims

In 2004, eight states and the City of New York filed an action in Federal District Court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority.  The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants.  The actions allege that CO 2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming and sought injunctive relief in the form of specific emission reduction commitments from the defendants.  The trial court dismissed the lawsuits.

In September 2009, the Second Circuit Court of Appeals issued a ruling on appeal remanding the cases to the Federal District Court for the Southern District of New York.  The Second Circuit held that the issues of climate change and global warming do not raise political questions and that Congress’ refusal to regulate CO 2 emissions does not mean that plaintiffs must wait for an initial policy determination by Congress or the President’s administration to secure the relief sought in their complaints.  The court stated that Congress could enact comprehensive legislation to regulate CO 2 emissions or that the Federal EPA could regulate CO 2 emissions under existing CAA authorities and that either of these actions could override any decision made by the district court under federal common law.  The Second Circuit did not rule on whether the plaintiffs could proceed with their state common law nuisance claims.  In December 2010, the defendants’ petition for review by the U.S. Supreme Court was granted.  Briefing is underway and the case will be heard in April 2011.  We believe the actions are without merit and intend to continue to defend against the 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.

We are unable to determine a range of potential losses that are reasonably possible of occurring.

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
 
 
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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.  The plaintiffs appealed the decision.  Briefing is complete and no date has been set for oral argument.  The defendants requested that the court defer setting this case for oral argument until after the Supreme Court issues its decision in the CO 2 public nuisance case discussed above.  We believe the action is without merit and intend to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

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 generating 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.  At December 31, 2010, our subsidiaries are named by the Federal EPA as a Potentially Responsible Party (PRP) for four 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 four 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 and recorded a provision of approximately $11 million.  As the remediation work is completed, I&M’s cost may continue to increase 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.

Amos Plant – State and Federal Enforcement Proceedings

In March 2010, we received a letter from the West Virginia Department of Environmental Protection, Division of Air Quality (DAQ), alleging that at various times in 2007 through 2009 the units at Amos Plant reported periods of excess opacity (indicator of compliance with particulate matter emission limits) that lasted for more than thirty consecutive minutes in a 24-hour period and that certain required notifications were not made.  We met with representatives of DAQ to discuss these occurrences and the steps we have taken to prevent a recurrence.  DAQ indicated that additional enforcement action may be taken, including imposition of a civil penalty of approximately $240 thousand.  We have denied that violations of the reporting requirements occurred and maintain that the proper reporting was done.  We continue to discuss the resolution of these issues with DAQ, but cannot predict the outcome of these discussions or the amount of any penalty that may be assessed.

 
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In March 2010, we received a request to show cause from the Federal EPA alleging that certain reporting requirements under Superfund and the Emergency Planning and Community Right-to-Know Act had been violated and inviting us to engage in settlement negotiations.  The request includes a proposed civil penalty of approximately $300 thousand.  We indicated our willingness to engage in good faith negotiations and provided additional information to representatives of the Federal EPA.  We have not admitted that any violations occurred or that the amount of the proposed penalty is reasonable.

Defective Environmental Equipment

As part of our continuing environmental investment program, we chose to retrofit wet flue gas desulfurization systems on several units utilizing the jet bubbling reactor (JBR) technology.  The retrofits on two Cardinal Plant units and a Conesville Plant unit are operational.  Due to unexpected operating results, we completed an extensive review in 2009 of the design and manufacture of the JBR internal components.  Our review concluded that there were fundamental design deficiencies and that inferior and/or inappropriate materials were selected for the internal fiberglass components.  We initiated discussions with Black & Veatch, the original equipment manufacturer, to develop a repair or replacement corrective action plan.  In 2010, we settled with Black & Veatch and resolved the issues involving the internal components and JBR vessel corrosion.  These settlements resulted in an immaterial increase in the capitalized costs of the projects for modification of the scope of the contracts.

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 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 2009.  According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste ranges from $831 million to $1.5 billion in 2009 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 amount recovered in rates was $14 million in 2010, $16 million in 2009 and $27 million in 2008.  Reduced annual decommissioning cost recovery amounts reflect the units’ longer estimated life and operating licenses granted by the NRC.  Decommissioning costs recovered from customers are deposited in external trusts.

At December 31, 2010 and 2009, the total decommissioning trust fund balance was $1.2 billion and $1.1 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, cash flows and possibly financial condition would be adversely affected 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.  At December 31, 2010 and 2009, 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 $307 million and $306 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.

 
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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 property damage, decommissioning and decontamination at the Cook Plant in the amount of $1.8 billion.  I&M purchases $1 billion of excess coverage for property damage, decommissioning and decontamination.  Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage.  I&M utilizes an industry mutual insurer for the placement of this insurance coverage.  Participation in this mutual insurance requires a contingent financial obligation of up to $41 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 $12.6 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 $117.5 million on each licensed reactor in the U.S. payable in annual installments of $17.5 million.  As a result, I&M could be assessed $235 million per nuclear incident payable in annual installments of $35 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 $12.2 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, net income, cash flows and financial condition could be adversely affected.

Cook Plant Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in significant turbine damage and a small fire on the electric generator.  This equipment, located in the turbine building, is separate and isolated from the nuclear reactor.  The turbine rotors that caused the vibration were installed in 2006 and are within the vendor’s warranty period.  The warranty provides for the repair or replacement of the turbine rotors if the damage was caused by a defect in materials or workmanship.  Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $395 million.  Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process.  I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power.  The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors.  As a result, the replacement of the repaired turbine rotors and other equipment is scheduled for the Unit 1 planned outage in the fall of 2011.

I&M maintains property insurance through NEIL with a $1 million deductible.  As of December 31, 2010, we recorded $46 million in Prepayments and Other Current Assets on our Consolidated Balance Sheets representing estimated recoverable amounts under the property insurance policy.  Through December 31, 2010, I&M received partial payments of $203 million from NEIL for the cost incurred to date to repair the property damage.

I&M also maintains a separate accidental outage policy with NEIL.  In 2009, I&M recorded $185 million in revenue under the policy and reduced the cost of replacement power in customers’ bills by $78 million.

NEIL is reviewing claims made under the insurance policies to ensure that claims associated with the outage are covered by the policies.  The review by NEIL includes the timing of the unit’s return to service and whether the return should have occurred earlier reducing the amount received under the accidental outage policy.  The treatment of the remaining accidental outage policy revenues through fuel clauses is discussed in “I&M Rate Matters” section of Note 4.  The treatment of property damage costs, replacement power costs and insurance proceeds will be the subject of future regulatory proceedings in Indiana and Michigan.  If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.

 
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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 have a material adverse effect on our net income, cash flows and financial condition.

Fort Wayne Lease

Since 1975, I&M has leased certain energy delivery assets from the City of Fort Wayne, Indiana under a long-term lease that expired on February 28, 2010.  I&M negotiated with Fort Wayne to purchase the assets at the end of the lease, but no agreement was reached prior to the end of the lease.

I&M and Fort Wayne reached a settlement agreement.  The agreement, signed in October 2010, is subject to approval by the IURC.  I&M filed a petition with the IURC seeking approval.  If the agreement is approved, I&M will purchase the remaining leased property and settle claims Fort Wayne asserted.  The agreement provides that I&M will pay Fort Wayne a total of $39 million, inclusive of interest, over 15 years and Fort Wayne will recognize that I&M is the exclusive electricity supplier in the Fort Wayne area.   I&M will seek recovery in rates of the payments made to Fort Wayne.  If the agreement is not approved by the IURC, the parties have the right to terminate the agreement and pursue other relief.

Enron Bankruptcy

In 2001, we purchased Houston Pipeline Company (HPL) from Enron.  Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.  In connection with our acquisition of HPL, we entered into an agreement with BAM Lease Company, which granted HPL the exclusive right to use approximately 55 billion cubic feet (BCF) of cushion gas required for the normal operation of the Bammel gas storage facility.  At the time of our acquisition of HPL, BOA and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of the cushion gas.  Also at the time of our acquisition, Enron and the BOA Syndicate released HPL from all prior and future liabilities and obligations in connection with the financing arrangement.  After the Enron bankruptcy, the BOA Syndicate informed HPL of a purported default by Enron under the terms of the financing arrangement.  This dispute was being litigated in federal courts in Texas and New York.

In 2007, the judge in the New York action issued a decision on all claims, including those that were pending trial in Texas, granting BOA summary judgment and dismissing our claims.  In August 2008, the New York court entered a final judgment of $346 million.  In May 2009, the judge awarded $20 million of attorneys’ fees to BOA.  In October 2010, the Court of Appeals affirmed the New York district court’s decision as to the final judgment of $346 million plus interest and reversed the New York district court decision as to the judgment dismissing our claims against BOA in the Southern District of Texas.

In 2005, we sold our interest in HPL and 30 BCF of working gas for approximately $1 billion.  Although the assets were legally transferred, we were unable to determine all costs associated with the transfer until the BOA litigation was resolved.  We indemnified the buyer of HPL against any damages up to the purchase price resulting from the BOA litigation, including the right to use the 55 BCF of natural gas through 2031.  As a result, we deferred the entire gain related to the sale of HPL (approximately $380 million) pending resolution of the Enron and BOA disputes.

 
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The deferred gain related to the sale of HPL, plus accrued interest and attorneys’ fees related to the New York court’s judgment was $448 million at December 31, 2010 and is included in Current Liabilities – Deferred Gain and Accrued Litigation Costs on the Consolidated Balance Sheet.  $441 million related to this matter was included in Deferred Credits and Other Noncurrent Liabilities on our Consolidated Balance Sheet at December 31, 2009.  The effect of this decision had no impact on consolidated net income for 2010.

In February 2011, we reached a settlement with BOA covering claims in both the New York and Texas proceedings and paid BOA $425 million.  The settlement covers all claims with BOA and Enron.  We received title to the 55 BCF of natural gas in the Bammel storage facility as part of the settlement.  We do not expect the effect of the settlement to have a material impact on our 2011 consolidated net income.

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.  These cases are at various pre-trial stages.  In 2008, we settled all of the cases pending against us in California.  The settlements did not impact 2008 earnings due to provisions made in prior periods.  We will continue to defend each remaining case where an AEP company is a defendant.  We believe the remaining exposure is immaterial.

7.   ACQUISITIONS, DISPOSITIONS AND DISCONTINUED OPERATIONS

ACQUISITIONS

2010

Valley Electric Membership Corporation (Utility Operations segment)

In November 2009, SWEPCo signed a letter of intent to purchase certain transmission and distribution assets of Valley Electric Membership Corporation (VEMCO).  In October 2010, SWEPCo finalized the purchase for approximately $102 million and began serving VEMCO’s 30,000 customers in Louisiana.

2009

Oxbow Lignite Company and Red River Mining Company (Utility Operations segment)

On December 29, 2009, SWEPCo   purchased 50% of the Oxbow Lignite Company, LLC (OLC) membership interest for $13 million.  CLECO acquired the remaining 50% membership interest in the OLC for $13 million.  The Oxbow Mine is located near Coushatta, Louisiana and will be used as one of the fuel sources for SWEPCo’s and CLECO’s jointly-owned Dolet Hills Generating Station.  SWEPCo will account for OLC as an equity investment.  Also, on December 29, 2009, DHLC purchased mining equipment and assets for $16 million from the Red River Mining Company.

2008

Erlbacher companies (AEP River Operations segment)

In June 2008, AEP River Operations purchased certain barging assets from Missouri Barge Line Company, Missouri Dry Dock and Repair Company and Cape Girardeau Fleeting, Inc. (collectively known as Erlbacher companies) for $35 million.  These assets were incorporated into AEP River Operations’ business which will diversify its customer base.

 
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DISPOSITIONS

2010

Electric Transmission Texas LLC (ETT) (Utility Operations segment)

TCC and TNC sold, at cost, $66 million and $73 million, respectively, of transmission facilities to ETT for the year ended December 31, 2010.

Intercontinental Exchange, Inc. (ICE) (All Other)

In April 2010, we sold our remaining 138,000 shares of ICE and recognized a $16 million gain ($10 million, net of tax).  We recorded the gain in Interest and Investment Income on our Consolidated Statements of Income for the year ended December 31, 2010.

2009

Electric Transmission Texas LLC (ETT) (Utility Operations segment)

In 2009, TCC and TNC sold, at cost, $93 million and $2 million, respectively, of transmission facilities to ETT.

2008

None

DISCONTINUED OPERATIONS

Management periodically assesses our overall business model and makes decisions regarding our continued support and funding of our various businesses and operations.  When it is determined that we will seek to exit a particular business or activity and we have met the accounting requirements for reclassification, we will reclassify those businesses or activities as discontinued operations.  The assets and liabilities of these discontinued operations are classified in Assets Held for Sale and Liabilities Held for Sale until the time that they are sold.

Certain of our operations were discontinued in 2008.  Results of operations of these businesses are classified as shown in the following table:

 
 
U.K.
 
 
 
Generation (a)
 
 
 
(in millions)
2010 Revenue
 
$
 - 
 
2010 Pretax Income
 
 
 - 
 
2010 Earnings, Net of Tax
 
 
 - 
 
 
 
 
 
 
2009 Revenue
 
$
 - 
 
2009 Pretax Income
 
 
 - 
 
2009 Earnings, Net of Tax
 
 
 - 
 
 
 
 
 
 
2008 Revenue
 
$
 2 
 
2008 Pretax Income
 
 
 2 
 
2008 Earnings, Net of Tax
 
 
 12 
 

(a)
The 2008 amounts relate primarily to favorable income tax reserve adjustments.

 
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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 medical 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
 
2010 
 
 
2009 
 
 
2010 
 
2009 
 
Discount Rate
 
 5.05 
%
 
 
 5.60 
%
 
 
 5.25 
%
 
 5.85 
%
 
Rate of Compensation Increase
 
 4.95 
%
(a)
 
 4.60 
%
(a)
 
                         N/A
 
                         N/A

     (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 .

     N/A   Not applicable

We use a duration-based method to determine the discount rate for our plans.  A hypothetical portfolio of high quality corporate bonds similar to those included in the Moody’s Aa bond index is constructed with a duration matching the benefit plan liability.  The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.

For 2010, 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 4.95%.

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
 
 
 
2010 
 
2009 
 
2008 
 
2010 
 
2009 
 
2008 
 
Discount Rate
 
 5.60 
%
 
 6.00 
%
 
 6.00 
%
 
 5.85 
%
 
 6.10 
%
 
 6.20 
%
 
Expected Return on Plan Assets
 
 8.00 
%
 
 8.00 
%
 
 8.00 
%
 
 8.00 
%
 
 7.75 
%
 
 8.00 
%
 
Rate of Compensation Increase
 
 4.60 
%
 
 5.90 
%
 
 5.90 
%
 
                 N/A
 
                 N/A
 
                 N/A
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
N/A   Not Applicable
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
89
 
The expected return on plan assets for 2010 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
 
2010 
 
2009 
 
Initial
 
 8.00 
%
 
 6.50 
%
 
Ultimate
 
 5.00 
%
 
 5.00 
%
 
Year Ultimate Reached
 
                 2016 
 
                 2012 

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
  $ 22     $ (18 )
 
               
Effect on the Health Care Component of the
               
Accumulated Postretirement Benefit Obligation
    255       (209 )

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.  At December 31, 2010, 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.

 
90
 
Benefit Plan Obligations, Plan Assets and Funded Status as of December 31, 2010 and 2009

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
 
 
 
2010
   
2009
   
2010
   
2009
 
Change in Benefit Obligation
 
(in millions)
 
Benefit Obligation at January 1
  $ 4,701     $ 4,301     $ 1,941     $ 1,843  
Service Cost
    111       104       47       42  
Interest Cost
    253       254       113       110  
Actuarial Loss
    222       290       164       32  
Plan Amendment Prior Service Credit
    -       -       (36 )     -  
Benefit Payments
    (480 )     (248 )     (142 )     (120 )
Participant Contributions
    -       -       29       25  
Medicare Subsidy
    -       -       9       9  
Benefit Obligation at December 31
  $ 4,807     $ 4,701     $ 2,125     $ 1,941  
 
                               
Change in Fair Value of Plan Assets
                               
Fair Value of Plan Assets at January 1
  $ 3,403     $ 3,161     $ 1,308     $ 1,018  
Actual Gain on Plan Assets
    420       482       149       235  
Company Contributions
    515       8       117       150  
Participant Contributions
    -       -       29       25  
Benefit Payments
    (480 )     (248 )     (142 )     (120 )
Fair Value of Plan Assets at December 31
  $ 3,858     $ 3,403     $ 1,461     $ 1,308  
 
                               
Underfunded Status at December 31
  $ (949 )   $ (1,298 )   $ (664 )   $ (633 )

Benefit Amounts Recognized on the Balance Sheets as of December 31, 2010 and 2009
 
 
 
 
   
 
   
 
   
 
 
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
December 31,
 
 
2010
 
2009
 
2010
 
2009
 
 
(in millions)
 
Other Current Liabilities - Accrued Short-term
 
 
   
 
   
 
   
 
 
Benefit Liability
  $ (8 )   $ (10 )   $ (4 )   $ (4 )
Employee Benefits and Pension Obligations -
                               
Accrued Long-term Benefit Liability
    (941 )     (1,288 )     (660 )     (629 )
Underfunded Status
  $ (949 )   $ (1,298 )   $ (664 )   $ (633 )

 
91
 
Amounts Included in AOCI and Regulatory Assets as of December 31, 2010 and 2009
 
 
 
 
Other Postretirement
 
Pension Plans
 
Benefit Plans
 
December 31,
 
2010
 
2009
 
2010
 
2009
 
Components
(in millions)
Net Actuarial Loss
  $ 2,129     $ 2,096     $ 638     $ 546  
Prior Service Cost (Credit)
    11       12       (20 )     3  
Transition Obligation
    -       -       3       43  
 
                               
Recorded as
                               
Regulatory Assets
  $ 1,764     $ 1,750     $ 388     $ 380  
Deferred Income Taxes
    132       125       81       74  
Net of Tax AOCI
    244       233       152       138  

Components of the change in amounts included in AOCI and Regulatory Assets during the years ended December 31, 2010 and 2009 are as follows:

 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
Years Ended December 31,
 
 
2010
 
2009
 
2010
 
2009
 
Components
(in millions)
 
Actuarial Loss (Gain) During the Year
  $ 121     $ 130     $ 121     $ (127 )
Prior Service Credit
    -       -       (36 )     -  
Amortization of Actuarial Loss
    (89 )     (59 )     (29 )     (42 )
Amortization of Transition Obligation
    -       -       (27 )     (27 )
Change for the Year
  $ 32     $ 71     $ 29     $ (196 )

 
92
 
Pension and Other Postretirement Plans’ Assets

The following table presents the classification of pension plan assets within the fair value hierarchy at December 31, 2010:

 
 
 
   
 
   
 
   
 
   
 
   
Year End
 
Asset Class
 
Level 1
   
Level 2
   
Level 3
   
Other
   
Total
   
Allocation
 
 
 
(in millions)
   
 
 
Equities:
 
 
   
 
   
 
   
 
   
 
   
 
 
Domestic
  $ 1,350     $ 2     $ -     $ -     $ 1,352       35.1 %
International
    403       -       -       -       403       10.4 %
Real Estate Investment Trusts
    112       -       -       -       112       2.9 %
Common Collective Trust -
                                               
International
    -       163       -       -       163       4.2 %
Subtotal - Equities
    1,865       165       -       -       2,030       52.6 %
 
                                               
Fixed Income:
                                               
United States Government and
                                               
Agency Securities
    -       634       -       -       634       16.4 %
Corporate Debt
    -       672       -       -       672       17.4 %
Foreign Debt
    -       127       -       -       127       3.3 %
State and Local Government
    -       23       -       -       23       0.6 %
Other - Asset Backed
    -       51       -       -       51       1.3 %
Subtotal - Fixed Income
    -       1,507       -       -       1,507       39.0 %
 
                                               
Real Estate
    -       -       83       -       83       2.2 %
 
                                               
Alternative Investments
    -       -       130       -       130       3.4 %
Securities Lending
    -       254       -       -       254       6.6 %
Securities Lending Collateral (a)
    -       -       -       (276 )     (276 )     (7.1 ) %
 
                                               
Cash and Cash Equivalents (b)
    -       127       -       2       129       3.3 %
Other - Pending Transactions and
                                               
Accrued Income (c)
    -       -       -       1       1       - %
 
                                               
Total
  $ 1,865     $ 2,053     $ 213     $ (273 )   $ 3,858       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 foreign currency holdings.
(c)  
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 real estate and alternative investments classified as Level 3 in the fair value hierarchy for AEP’s pension assets:

 
 
 
   
Alternative
   
Total
 
 
 
Real Estate
   
Investments
   
Level 3
 
 
 
(in millions)
 
Balance as of January 1, 2010
  $ 90     $ 106     $ 196  
Actual Return on Plan Assets
                       
Relating to Assets Still Held as of the Reporting Date
    (7 )     4       (3 )
Relating to Assets Sold During the Period
    -       1       1  
Purchases and Sales
    -       19       19  
Transfers into Level 3
    -       -       -  
Transfers out of Level 3
    -       -       -  
Balance as of December 31, 2010
  $ 83     $ 130     $ 213  

 
93
 
The following table presents the classification of OPEB plan assets within the fair value hierarchy at December 31, 2010:

 
 
 
   
 
   
 
   
 
   
 
   
Year End
 
Asset Class
 
Level 1
   
Level 2
   
Level 3
   
Other
   
Total
   
Allocation
 
 
 
(in millions)
   
 
 
Equities:
 
 
   
 
   
 
   
 
   
 
   
 
 
Domestic
  $ 584     $ -     $ -     $ -     $ 584       40.0 %
International
    220       -       -       -       220       15.1 %
Common Collective Trust -
                                               
Global
    -       115       -       -       115       7.9 %
Subtotal - Equities
    804       115       -       -       919       63.0 %
 
                                               
Fixed Income:
                                               
Common Collective Trust - Debt
    -       48       -       -       48       3.3 %
United States Government and
                                               
Agency Securities
    -       93       -       -       93       6.4 %
Corporate Debt
    -       110       -       -       110       7.5 %
Foreign Debt
    -       25       -       -       25       1.7 %
State and Local Government
    -       3       -       -       3       0.2 %
Other - Asset Backed
    -       1       -       -       1       0.1 %
Subtotal - Fixed Income
    -       280       -       -       280       19.2 %
 
                                               
Trust Owned Life Insurance:
                                               
International Equities
    -       49       -       -       49       3.3 %
United States Bonds
    -       163       -       -       163       11.1 %
 
                                               
Cash and Cash Equivalents (a)
    21       25       -       1       47       3.2 %
Other - Pending Transactions and
                                               
Accrued Income (b)
    -       -       -       3       3       0.2 %
 
                                               
Total
  $ 825     $ 632     $ -     $ 4     $ 1,461       100.0 %
 
                                               

(a)  
Amounts in "Other" column primarily represent foreign currency holdings.
(b)  
Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement.

 
94
 
The following table presents the classification of pension plan assets within the fair value hierarchy at December 31, 2009:

 
 
 
   
 
   
 
   
 
   
 
   
Year End
 
Asset Class
 
Level 1
   
Level 2
   
Level 3
   
Other
   
Total
   
Allocation
 
 
 
(in millions)
   
 
 
Equities:
 
 
   
 
   
 
   
 
   
 
   
 
 
Domestic
  $ 1,219     $ -     $ -     $ -     $ 1,219       35.8 %
International
    320       -       -       -       320       9.4 %
Real Estate Investment Trusts
    87       -       -       -       87       2.6 %
Common Collective Trust -
                                               
International
    -       161       -       -       161       4.7 %
Subtotal - Equities
    1,626       161       -       -       1,787       52.5 %
 
                                               
Fixed Income:
                                               
United States Government and
                                               
Agency Securities
    -       233       -       -       233       6.9 %
Corporate Debt
    -       831       -       -       831       24.4 %
Foreign Debt
    -       171       -       -       171       5.0 %
State and Local Government
    -       35       -       -       35       1.0 %
Other - Asset Backed
    -       27       -       -       27       0.8 %
Subtotal - Fixed Income
    -       1,297       -       -       1,297       38.1 %
 
                                               
Real Estate
    -       -       90       -       90       2.7 %
 
                                               
Alternative Investments
    -       -       106       -       106       3.1 %
Securities Lending
    -       173       -       -       173       5.1 %
Securities Lending Collateral (a)
    -       -       -       (196 )     (196 )     (5.8 ) %
 
                                               
Cash and Cash Equivalents (b)
    -       116       -       4       120       3.5 %
Other - Pending Transactions and
                                               
Accrued Income (c)
    -       -       -       26       26       0.8 %
 
                                               
Total
  $ 1,626     $ 1,747     $ 196     $ (166 )   $ 3,403       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 foreign currency holdings.
(c)  
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 real estate and alternative investments classified as Level 3 in the fair value hierarchy for the pension assets:

 
 
 
   
Alternative
   
Total
 
 
 
Real Estate
   
Investments
   
Level 3
 
 
 
(in millions)
 
Balance as of January 1, 2009
  $ 137     $ 106     $ 243  
Actual Return on Plan Assets
                       
Relating to Assets Still Held as of the Reporting Date
    (47 )     (14 )     (61 )
Relating to Assets Sold During the Period
    -       1       1  
Purchases and Sales
    -       13       13  
Transfers in and/or out of Level 3
    -       -       -  
Balance as of December 31, 2009
  $ 90     $ 106     $ 196  

 
95
 
The following table presents the classification of OPEB plan assets within the fair value hierarchy at December 31, 2009:

 
 
 
   
 
   
 
   
 
   
 
   
Year End
 
Asset Class
 
Level 1
   
Level 2
   
Level 3
   
Other
   
Total
   
Allocation
 
 
 
(in millions)
 
Equities:
 
 
   
 
   
 
   
 
   
 
   
 
 
Domestic
  $ 343     $ -     $ -     $ -     $ 343       26.2 %
International
    375       -       -       -       375       28.7 %
Common Collective Trust -
                                               
Global
    -       93       -       -       93       7.1 %
Subtotal - Equities
    718       93       -       -       811       62.0 %
 
                                               
Fixed Income:
                                               
Common Collective Trust - Debt
    -       38       -       -       38       2.9 %
United States Government and
                                               
Agency Securities
    -       42       -       -       42       3.2 %
Corporate Debt
    -       141       -       -       141       10.8 %
Foreign Debt
    -       32       -       -       32       2.4 %
State and Local Government
    -       6       -       -       6       0.5 %
Other - Asset Backed
    -       2       -       -       2       0.2 %
Subtotal - Fixed Income
    -       261       -       -       261       20.0 %
 
                                               
Trust Owned Life Insurance:
                                               
International Equities
    -       75       -       -       75       5.7 %
United States Bonds
    -       131       -       -       131       10.0 %
 
                                               
Cash and Cash Equivalents (a)
    7       14       -       1       22       1.7 %
Other - Pending Transactions and
                                               
Accrued Income (b)
    -       -       -       8       8       0.6 %
 
                                               
Total
  $ 725     $ 574     $ -     $ 9     $ 1,308       100.0 %
 
                                               
(a)  
Amounts in "Other" column primarily represent foreign currency holdings.
(b)  
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 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.

 
 
December 31,
 
Accumulated Benefit Obligation
 
2010
 
2009
 
 
 
(in millions)
 
Qualified Pension Plan
    $ 4,659     $ 4,539  
Nonqualified Pension Plans
      80       90  
Total
    $ 4,739     $ 4,629  
 
                 
 
 
96
 
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 at December 31, 2010 and 2009 were as follows:

 
Underfunded Pension Plans
 
 
December 31,
 
 
2010
 
2009
 
 
(in millions)
 
Projected Benefit Obligation
  $ 4,807     $ 4,701  
 
               
Accumulated Benefit Obligation
  $ 4,739     $ 4,629  
Fair Value of Plan Assets
    3,858       3,403  
Underfunded Accumulated Benefit Obligation
  $ (881 )   $ (1,226 )

Estimated Future Benefit Payments and Contributions

We expect contributions and payments for the pension plans of $158 million and the OPEB plans of $86 million during 2011.  The estimated pension benefit payments for the unfunded plan and contributions to the trust are at least the minimum amount required by ERISA plus payment of unfunded nonqualified benefits.  For the qualified pension plan, we may make additional discretionary contributions to maintain the funded status of the plan.  The contribution to the OPEB plans is generally based on the amount of the OPEB plans’ periodic benefit costs for accounting purposes as provided in agreements with state regulatory authorities, plus the additional discretionary contribution of our Medicare subsidy receipts.

The table below reflects the total benefits expected to be paid from the plan or from our assets, including both our share of the benefit cost and the participants’ share of the cost, which is funded by participant contributions to the plan.  Medicare subsidy receipts are shown in the year of the corresponding benefit payments, even though actual cash receipts are expected early in the following year.  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)
 
2011 
  $ 314     $ 143     $ 11  
2012 
    320       148       12  
2013 
    325       153       13  
2014 
    333       160       14  
2015 
    342       166       15  
Years 2016 to 2020, in Total
    1,811       931       95  
 

 
 
97
 
Components of Net Periodic Benefit Cost

The following table provides the components of our net periodic benefit cost for the plans for the years ended December 31, 2010, 2009 and 2008:

 
 
 
 
 
 
Other Postretirement
 
 
 
Pension Plans
 
Benefit Plans
 
 
 
 
Years Ended December 31,
 
 
 
 
2010 
 
2009 
 
2008 
 
2010 
 
2009 
 
2008 
 
 
 
 
(in millions)
 
Service Cost
 
$
 111 
 
$
 104 
 
$
 100 
 
$
 47 
 
$
 42 
 
$
 42 
 
Interest Cost
 
 
 253 
 
 
 254 
 
 
 249 
 
 
 113 
 
 
 110 
 
 
 113 
 
Expected Return on Plan Assets
 
 
 (312)
 
 
 (321)
 
 
 (336)
 
 
 (105)
 
 
 (80)
 
 
 (111)
 
Amortization of Transition Obligation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 27 
 
 
 27 
 
 
 27 
 
Amortization of Prior Service Cost
 
 
 - 
 
 
 - 
 
 
 1 
 
 
 - 
 
 
 - 
 
 
 - 
 
Amortization of Net Actuarial Loss
 
 
 89 
 
 
 59 
 
 
 37 
 
 
 29 
 
 
 42 
 
 
 9 
 
Net Periodic Benefit Cost
 
 
 141 
 
 
 96 
 
 
 51 
 
 
 111 
 
 
 141 
 
 
 80 
 
Capitalized Portion
 
 
 (44)
 
 
 (30)
 
 
 (16)
 
 
 (35)
 
 
 (44)
 
 
 (25)
 
Net Periodic Benefit Cost Recognized as Expense
 
$
 97 
 
$
 66 
 
$
 35 
 
$
 76 
 
$
 97 
 
$
 55 

Estimated amounts expected to be amortized to net periodic benefit costs and the impact on the balance sheet during 2011 are shown in the following table:

 
 
 
   
Other
 
 
 
 
   
Postretirement
 
 
 
Pension Plans
   
Benefit Plans
 
Components
 
(in millions)
 
Net Actuarial Loss
  $ 121     $ 33  
Prior Service Cost (Credit)
    1       (2 )
Transition Obligation
    -       2  
Total Estimated 2011 Amortization
  $ 122     $ 33  
 
               
Expected to be Recorded as
               
Regulatory Asset
  $ 99     $ 19  
Deferred Income Taxes
    8       5  
Net of Tax AOCI
    15       9  
Total
  $ 122     $ 33  

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.  We provided matching contributions of 75% of the first 6% of eligible compensation contributed by an employee in 2008.  Effective January 1, 2009, we match the first 1% of eligible employee contributions at 100% and the next 5% of contributions at 70%.  The cost for company matching contributions totaled $61 million in 2010, $74 million in 2009 and $71 million in 2008.

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.  Contributions and benefits paid were not material in 2010, 2009 and 2008.

 
98
 
9.   BUSINESS SEGMENTS

Our primary business is our electric utility operations.  Within our Utility Operations 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.  While our Utility Operations segment remains our primary business segment, other segments include our AEP River Operations segment with significant barging activities and our Generation and Marketing segment, which includes our nonregulated generating, marketing and risk management activities primarily in the ERCOT market area and to a lesser extent Ohio in PJM and MISO.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

Our reportable segments and their related business activities are as follows:

Utility Operations
·     Generation of electricity for sale to U.S. retail and wholesale customers.
·     Electricity transmission and distribution in the U.S.

AEP River Operations
    ·  
Commercial barging operations that annually transport approximately 39 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.  Approximately 46% of the barging is for transportation of agricultural products, 25% for coal, 11% for steel and 18% for other commodities.

Generation and Marketing
    ·  
Wind farms and marketing and risk management activities primarily in ERCOT and to a lesser extent Ohio in PJM and MISO.

The remainder of our activities is presented as All Other.  While not considered a business segment, All Other includes:

    ·  
Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense, and other nonallocated costs.
    ·  
Tax and interest expense adjustments related to our UK operations which were sold in 2004 and 2002.
    ·  
Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005.  These contracts are financial derivatives which settle and expire in 2011.
    ·  
The 2008 cash settlement of a purchase power and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in 2006.
    ·  
Revenue sharing related to the Plaquemine Cogeneration Facility.

 
99
 
The tables below present our reportable segment information for years ended December 31, 2010, 2009 and 2008 and balance sheet information as of December 31, 2010 and 2009.  These amounts include certain estimates and allocations where necessary.

 
 
 
 
 
Nonutility Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Generation
 
 
 
 
 
 
 
 
 
 
Utility
 
AEP River
 
and
 
All Other
Reconciling
 
 
 
Operations
 
Operations
 
Marketing
    (a)
Adjustments
Consolidated
 
 
(in millions)
Year Ended December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
External Customers
 
$
 13,687 
 
$
 566 
 
$
 173 
 
$
 1 
 
$
 - 
 
$
 14,427 
Other Operating Segments
 
 
 104 
 
 
 22 
 
 
 - 
 
 
 14 
 
 
 (140)
 
 
 - 
Total Revenues
 
$
 13,791 
 
$
 588 
 
$
 173 
 
$
 15 
 
$
 (140)
 
$
 14,427 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
$
 1,598 
 
$
 24 
 
$
 30 
 
$ 
 2 
 
$
 (13)
(b)
$
 1,641 
Interest Income
 
 
 8 
 
 
 - 
 
 
 2 
 
 
 31 
 
 
 (20)
 
 
 21 
Interest Expense
 
 
 942 
 
 
 14 
 
 
 20 
 
 
 58 
 
 
 (35)
(b)
 
 999 
Income Tax Expense (Credit)
 
 
 650 
 
 
 19 
 
 
 (20)
 
 
 (6)
 
 
 - 
 
 
 643 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss)
 
 
 1,201 
 
 
 37 
 
 
 25 
 
 
 (45)
 
 
 - 
 
 
 1,218 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gross Property Additions
 
 
 2,475 
 
 
 23 
 
 
 1 
 
 
 1 
 
 
 - 
 
 
 2,500 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nonutility Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Generation
 
 
 
 
 
 
 
 
 
 
Utility
 
AEP River
 
and
 
All Other
Reconciling
 
 
 
Operations
 
Operations
 
Marketing
 
(a)
 Adjustments
Consolidated
 
 
(in millions)
 Year Ended December 31, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
External Customers
 
$
 12,733 
(e)
$
 490 
 
$
 281 
 
$ 
 (15)
 
$
 - 
 
$
 13,489 
Other Operating Segments
 
 
 70 
(e)
 
 18 
 
 
 5 
 
 
 36 
 
 
 (129)
 
 
 - 
Total Revenues
 
$
 12,803 
 
$
 508 
 
$
 286 
 
$ 
 21 
 
$
 (129)
 
$
 13,489 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
$
 1,561 
 
$
 17 
 
$
 29 
 
$ 
 2 
 
$
 (12)
(b)
$
 1,597 
Interest Income
 
 
 4 
 
 
 - 
 
 
 - 
 
 
 47 
 
 
 (40)
 
 
 11 
Interest Expense
 
 
 916 
 
 
 5 
 
 
 21 
 
 
 86 
 
 
 (55)
(b)
 
 973 
Income Tax Expense (Credit)
 
 
 553 
 
 
 23 
 
 
 - 
 
 
 (1)
 
 
 - 
 
 
 575 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income (Loss) Before Discontinued
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operations and Extraordinary Loss
 
$
 1,329 
 
$
 47 
 
$
 41 
 
$ 
 (47)
 
$
 - 
 
$
 1,370 
Extraordinary Loss, Net of Tax
 
 
 (5)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (5)
Net Income (Loss)
 
$
 1,324 
 
$
 47 
 
$
 41 
 
$ 
 (47)
 
$
 - 
 
$
 1,365 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gross Property Additions
 
$
 2,813 
 
$
 81 
 
$
 1 
 
$ 
 1 
 
$
 - 
 
$
 2,896 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100
 
 
 
 
 
 
 
Nonutility Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Generation
 
 
 
 
 
 
 
 
 
 
Utility
 
AEP River
 
and
 
All Other
Reconciling
 
 
 
Operations
 
Operations
 
Marketing
 
(a)
 Adjustments
Consolidated
 
 
(in millions)
 Year Ended December 31, 2008
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
External Customers
 
$
 13,326 
(e)
$
 616 
 
$
 485 
 
$ 
 13 
 
$
 - 
 
$
 14,440 
Other Operating Segments
 
 
 240 
(e)
 
 30 
 
 
 (122)
 
 
 9 
 
 
 (157)
 
 
 - 
Total Revenues
 
$
 13,566 
 
$
 646 
 
$
 363 
 
$ 
 22 
 
$
 (157)
 
$
 14,440 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
$
 1,450 
 
$
 14 
 
$
 28 
 
$ 
 2 
 
$
 (11)
(b)
$
 1,483 
Interest Income
 
 
 42 
 
 
 - 
 
 
 1 
 
 
 78 
 
 
 (65)
 
 
 56 
Interest Expense
 
 
 915 
 
 
 5 
 
 
 22 
 
 
 94 
 
 
 (79)
(b)
 
 957 
Income Tax Expense
 
 
 515 
 
 
 26 
 
 
 17 
 
 
 84 
 
 
 - 
 
 
 642 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Before Discontinued
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operations and Extraordinary Loss
 
$
 1,123 
 
$
 55 
 
$
 65 
 
$ 
 133 
 
$
 - 
 
$
 1,376 
Discontinued Operations, Net of Tax
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 12 
 
 
 - 
 
 
 12 
Net Income
 
$
 1,123 
 
$
 55 
 
$
 65 
 
$ 
 145 
 
$
 - 
 
$
 1,388 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gross Property Additions
 
$
 3,871 
 
$
 116 
 
$
 2 
 
$ 
 (29)
(c)
$
 - 
 
$
 3,960 

 
 
 
 
 
 
 
Nonutility Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Generation
 
 
 
 
Reconciling
 
 
 
 
 
 
 
Utility
 
AEP River
 
and
 
All Other
 
 Adjustments
 
 
 
 
 
 
 
Operations
 
Operations
 
Marketing
 
(a)
 
(b)
 
 
Consolidated
 
 
 
 
(in millions)
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and Equipment
 
$
 52,822 
 
$
 574 
 
$
 584 
 
$
 11 
 
$
 (251)
 
 
$
 53,740 
Accumulated Depreciation and Amortization
 
 
 17,795 
 
 
 110 
 
 
 198 
 
 
 9 
 
 
 (46)
 
 
 
 18,066 
Total Property, Plant and Equipment - Net
 
$
 35,027 
 
$
 464 
 
$
 386 
 
$
 2 
 
$
 (205)
 
 
$
 35,674 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
 48,780 
 
$
 621 
 
$
 881 
 
$
 15,942 
 
$
 (15,769)
(d)
 
$
 50,455 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Investments in Equity Method Investees
 
 
 157 
 
 
 3 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
 160 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nonutility Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Generation
 
 
 
 
Reconciling
 
 
 
 
 
 
 
Utility
 
AEP River
 
and
 
All Other
 
 Adjustments
 
 
 
 
 
 
 
Operations
 
Operations
 
Marketing
 
(a)
 
(b)
 
 
Consolidated
 
 
 
 
(in millions)
December 31, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and Equipment
 
$
 50,905 
 
$
 436 
 
$
 571 
 
$
 10 
 
$
 (238)
 
 
$
 51,684 
Accumulated Depreciation and Amortization
 
 
 17,110 
 
 
 88 
 
 
 168 
 
 
 8 
 
 
 (34)
 
 
 
 17,340 
Total Property, Plant and Equipment - Net
 
$
 33,795 
 
$
 348 
 
$
 403 
 
$
 2 
 
$
 (204)
 
 
$
 34,344 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
 46,930 
 
$
 495 
 
$
 779 
 
$
 15,094 
 
$
 (14,950)
(d)
 
$
 48,348 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Investments in Equity Method Investees
 
 
 84 
 
 
 4 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
 88 

 
101
 
(a)
All Other includes:
·  
Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense, and other nonallocated costs.
·  
Tax and interest expense adjustments related to our UK operations which were sold in 2004 and 2002.
·  
Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005.  These contracts are financial derivatives which settle and expire in 2011.
·  
The 2008 cash settlement of a purchase power and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in 2006.  The cash settlement of $255 million ($164 million, net of tax) is included in Net Income.
·  
Revenue sharing related to the Plaquemine Cogeneration Facility.
(b)
Includes eliminations due to an intercompany capital lease.
(c)
Gross Property Additions for All Other includes construction expenditures of $8 million in 2008 related to the acquisition of turbines by one of our nonregulated, wholly-owned subsidiaries.  These turbines were refurbished and transferred to a generating facility within our Utility Operations segment in the fourth quarter of 2008.  The transfer of these turbines resulted in the elimination of $37 million from All Other and the addition of $37 million to Utility Operations.
(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.
(e)
PSO and SWEPCo transferred certain existing ERCOT energy marketing contracts to AEP Energy Partners, Inc. (AEPEP) (Generation and Marketing segment) and entered into intercompany financial and physical purchase and sales agreements with AEPEP.  As a result, we reported third-party net purchases or sales activity for these energy marketing contracts as Revenues from External Customers for the Utility Operations segment.  This was offset by the Utility Operations segment's related net sales (purchases) for these contracts with AEPEP in Revenues from Other Operating Segments of $(5) million and $122 million for the years ended December 31, 2009 and 2008, respectively.  The Generation and Marketing segment also reported these purchase or sales contracts with Utility Operations as Revenues from Other Operating Segments.  These affiliated contracts between PSO and SWEPCo with AEPEP ended in December 2009.

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, 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

Trading Strategies

Our strategy surrounding the use of derivative instruments for trading purposes focuses on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which we transact.

Risk Management Strategies

Our strategy surrounding the use of derivative instruments focuses on managing our risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. To accomplish our objectives, we primarily employ risk management contracts including physical forward purchase and sale contracts, financial forward purchase and sale contracts and financial swap instruments.  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 degree, heating oil and gasoline, emission allowance 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.

 
102
 
The following table represents the gross notional volume of our outstanding derivative contracts as of December 31, 2010 and 2009:

Notional Volume of Derivative Instruments
 
 
 
   
 
 
 
 
Volume
 
 
 
 
December 31,
 
Unit of
 
 
2010
   
2009
 
Measure
 
(in millions)
 
 
Commodity:
 
 
   
 
 
 
Power
    652       589  
MWHs
Coal
    63       60  
Tons
Natural Gas
    94       127  
MMBtus
Heating Oil and Gasoline
    6       6  
Gallons
Interest Rate
  $ 171     $ 216  
USD
 
               
 
Interest Rate and Foreign Currency
  $ 907     $ 83  
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.

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 activity 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 anticipated borrowings of fixed-rate debt.  Our anticipated 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.

 
103
 
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 in 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 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, 2010 and 2009 balance sheets, we netted $8 million and $12 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $109 million and $98 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.

 
104
 
The following tables represent the gross fair value impact of our derivative activity on our Consolidated Balance Sheets as of December 31, 2010 and 2009:

Fair Value of Derivative Instruments
 
December 31, 2010
 
 
 
 
 
Risk Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
Other
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)(c)
 
(a) (b)
 
Total
 
 
 
(in millions)
 
Current Risk Management Assets
    $ 1,023     $ 18     $ 30     $ (839 )   $ 232  
Long-term Risk Management Assets
      546       12       2       (150 )     410  
Total Assets
      1,569       30       32       (989 )     642  
 
                                         
Current Risk Management Liabilities
      995       13       2       (881 )     129  
Long-term Risk Management Liabilities
      387       6       3       (255 )     141  
Total Liabilities
      1,382       19       5       (1,136 )     270  
 
                                         
Total MTM Derivative Contract Net Assets
                                         
(Liabilities)
    $ 187     $ 11     $ 27     $ 147     $ 372  
 
                                         
Fair Value of Derivative Instruments
 
December 31, 2009
 
 
 
 
 
Risk Management
                                 
 
 
Contracts
 
Hedging Contracts
                 
 
                 
Interest Rate
                 
 
                 
and Foreign
 
Other
         
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
(a) (b)
 
Total
 
 
 
(in millions)
 
Current Risk Management Assets
    $ 1,078     $ 13     $ -     $ (831 )   $ 260  
Long-term Risk Management Assets
      614       -       -       (271 )     343  
Total Assets
      1,692       13       -       (1,102 )     603  
 
                                         
Current Risk Management Liabilities
      997       17       3       (897 )     120  
Long-term Risk Management Liabilities
      442       -       2       (316 )     128  
Total Liabilities
      1,439       17       5       (1,213 )     248  
 
                                         
Total MTM Derivative Contract Net Assets
                                         
(Liabilities)
    $ 253     $ (4 )   $ (5 )   $ 111     $ 355  

 
(a)
Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the Consolidated Balance Sheet on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."
 
(b)
Amounts represent counterparty netting of risk management and hedging contracts, associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging" and dedesignated risk management contracts.
 
(c)
At December 31, 2010, Risk Management Assets included $7 million and Risk Management Liabilities included $1 million related to fair value hedging strategies while the remainder related to cash flow hedging strategies.  At December 31, 2009, we only employed cash flow hedging strategies.

 
105
 
The table below presents our activity of derivative risk management contracts for the years ended December 31, 2010 and 2009:

Amount of Gain (Loss) Recognized on
 
Risk Management Contracts
 
 
 
Years Ended December 31,
 
Location of Gain (Loss)
 
2010
 
2009
 
 
 
(in millions)
 
Utility Operations Revenue
    $ 85     $ 144  
Other Revenue
      9       19  
Regulatory Assets (a)
      (9 )     (28 )
Regulatory Liabilities (a)
      38       (7 )
Total Gain (Loss) on Risk Management Contracts
    $ 123     $ 128  

 (a)  Represents realized and unrealized gains and losses subject to regulatory  accounting treatment recorded as either current or noncurrent on the  balance sheet.

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 Consolidated 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 Consolidated 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 Consolidated 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 our Consolidated Statements of Income.  During 2010, we recognized gains of $6 million on our hedging instruments, offsetting losses of $6 million on our long-term debt and an immaterial amount of hedge ineffectiveness.  During 2009, we did not employ any fair value hedging strategies.  During 2008, we employed fair value hedging strategies and recognized an immaterial loss and no hedge ineffectiveness.

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 our Consolidated 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).

 
106
 
Realized gains and losses on derivative contracts for the purchase and sale of power, coal, natural gas, and heating oil and gasoline designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on our Consolidated Statements of Income, or in Regulatory Assets or Regulatory Liabilities on our Consolidated Balance Sheets, depending on the specific nature of the risk being hedged.  During 2010, 2009 and 2008, we designated commodity derivatives as cash flow hedges.

We reclassify gains and losses on financial fuel derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our Consolidated Balance Sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our Consolidated Statements of Income.  During 2010 and 2009, 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) into Interest Expense in those periods in which hedged interest payments occur.  During 2010, 2009 and 2008, 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 our Consolidated Balance Sheets into Depreciation and Amortization expense on our Consolidated Statements of Income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.  During 2010, 2009 and 2008, we designated foreign currency derivatives as cash flow hedges.

During 2009, we recognized a $6 million gain in Interest Expense related to hedge ineffectiveness on interest rate derivatives designated in cash flow hedge strategies.  During 2010, 2009 and 2008, hedge ineffectiveness was immaterial or nonexistent for all of the other hedge strategies disclosed above.

 
107
 
The following tables provide details on designated, effective cash flow hedges included in AOCI on our Consolidated Balance Sheets and the reasons for changes in cash flow hedges for the years ended December 31,  2010 and 2009.  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, 2010
 
 
 
 
 
Interest Rate
   
 
 
 
 
 
 
and Foreign
   
 
 
 
Commodity
 
Currency
 
Total
 
 
(in millions)
 
Balance in AOCI as of December 31, 2009
  $ (2 )   $ (13 )   $ (15 )
Changes in Fair Value Recognized in AOCI
    9       13       22  
Amount of (Gain) or Loss Reclassified from AOCI
                       
to Income Statement/within Balance Sheet:
                       
Utility Operations Revenue
    -       -       -  
Other Revenue
    (7 )     -       (7 )
Purchased Electricity for Resale
    4       -       4  
Interest Expense
    -       4       4  
Regulatory Assets (a)
    3       -       3  
Regulatory Liabilities (a)
    -       -       -  
Balance in AOCI as of December 31, 2010
  $ 7     $ 4     $ 11  
 
                       
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
 
Year Ended December 31, 2009
 
 
       
Interest Rate
         
 
       
and Foreign
         
 
Commodity
 
Currency
 
Total
 
 
(in millions)
 
Balance in AOCI as of December 31, 2008
  $ 7     $ (29 )   $ (22 )
Changes in Fair Value Recognized in AOCI
    (6 )     11       5  
Amount of (Gain) or Loss Reclassified from AOCI
                       
to Income Statement/within Balance Sheet:
                       
Utility Operations Revenue
    (15 )     -       (15 )
Other Revenue
    (15 )     -       (15 )
Purchased Electricity for Resale
    29       -       29  
Interest Expense
    -       5       5  
Regulatory Assets (a)
    5       -       5  
Regulatory Liabilities (a)
    (7 )     -       (7 )
Balance in AOCI as of December 31, 2009
  $ (2 )   $ (13 )   $ (15 )

   (a)   Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

During 2008 we reclassified $7 million of gains from AOCI to net income.

 
108
 
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our Consolidated Balance Sheets at December 31, 2010 and 2009 were:

Impact of Cash Flow Hedges on our Consolidated Balance Sheet
 
December 31, 2010
 
 
 
 
   
 
   
 
 
 
 
 
 
Interest Rate
   
 
 
 
 
 
 
and Foreign
   
 
 
 
Commodity
 
Currency
 
Total
 
 
(in millions)
 
Hedging Assets (a)
  $ 13     $ 25     $ 38  
Hedging Liabilities (a)
    (2 )     (4 )     (6 )
AOCI Gain (Loss) Net of Tax
    7       4       11  
 
                       
Portion Expected to be Reclassified to Net
                       
Income During the Next Twelve Months
    3       (2 )     1  
 
                       
Impact of Cash Flow Hedges on our Consolidated Balance Sheet
 
December 31, 2009
 
 
                       
 
       
Interest Rate
         
 
       
and Foreign
         
 
Commodity
 
Currency
 
Total
 
 
(in millions)
 
Hedging Assets (a)
  $ 8     $ -     $ 8  
Hedging Liabilities (a)
    (12 )     (5 )     (17 )
AOCI Gain (Loss) Net of Tax
    (2 )     (13 )     (15 )
 
                       
Portion Expected to be Reclassified to Net
                       
Income During the Next Twelve Months
    (2 )     (4 )     (6 )

(a)
Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on our Consolidated Balance Sheets.

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, 2010, 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 is 41 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.

We use standardized master agreements which 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.

 
109
 
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.  We do not anticipate a downgrade below investment grade.  The following table represents: (a) our aggregate 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, 2010 and 2009:

 
 
 
 
December 31,
 
 
 
 
2010 
 
2009 
 
 
 
 
(in millions)
 
Liabilities for Derivative Contracts with Credit Downgrade Triggers
 
$
 20 
 
$
 10 
 
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post
 
 
45 
 
 
34 
 
Amount Attributable to RTO and ISO Activities
 
 
 44 
 
 
 29 

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 under outstanding debt in excess of $50 million.  On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts.  We do not anticipate a non-performance event under these provisions.  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, 2010 and 2009:

 
December 31,
 
 
2010
 
2009
 
 
(in millions)
 
Liabilities for Contracts with Cross Default Provisions Prior to Contractual
 
 
   
 
 
   Netting Arrangements
  $ 401     $ 567  
Amount of Cash Collateral Posted
    81       15  
Additional Settlement Liability if Cross Default Provision is Triggered
    213       199  

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.  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, 2010 and 2009 are summarized in the following table:

 
 
 
December 31,
 
 
 
2010 
 
2009 
 
 
 
Book Value
 
Fair Value
 
Book Value
 
Fair Value
 
 
 
(in millions)
 
Long-term Debt
 
$
 16,811 
 
$
 18,285 
 
$
 17,498 
 
$
 18,479 

 
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Fair Value Measurements of Other Temporary Investments

Other Temporary Investments include marketable securities that we intend to hold for less than one year, investments by our protected cell of EIS and funds held by trustees primarily for the payment of debt.  See “Other Temporary Investments” section of Note 1.

The following is a summary of Other Temporary Investments:

 
 
 
 
 
December 31, 2010
 
 
 
 
 
 
 
 
Gross
 
Gross
 
Estimated
 
 
 
 
 
 
 
 
 Unrealized
 
Unrealized
 
 Fair
 
Other Temporary Investments
 
Cost
 
Gains
 
Losses
 
Value
 
 
 
 
 
(in millions)
 
 
Restricted Cash (a)
 
$
 225 
 
$
 - 
 
$
 - 
 
$
 225 
 
 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mutual Funds
 
 
 69 
 
 
 - 
 
 
 - 
 
 
 69 
 
 
 
Variable Rate Demand Notes
 
 
 97 
 
 
 - 
 
 
 - 
 
 
 97 
 
 
Equity Securities - Mutual Funds
 
 
 18 
 
 
 7 
 
 
 - 
 
 
 25 
 
 
Total Other Temporary Investments
 
$
 409 
 
$
 7 
 
$
 - 
 
$
 416 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2009
 
 
 
 
 
 
 
 
Gross
 
Gross
 
Estimated
 
 
 
 
 
 
 
 
 Unrealized
 
Unrealized
 
 Fair
 
 
Other Temporary Investments
 
Cost
 
Gains
 
Losses
 
Value
 
 
 
 
 
 
(in millions)
 
 
Restricted Cash (a)
 
$
 223 
 
$
 - 
 
$
 - 
 
$
 223 
 
 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mutual Funds
 
 
 57 
 
 
 - 
 
 
 - 
 
 
 57 
 
 
 
Variable Rate Demand Notes
 
 
 45 
 
 
 - 
 
 
 - 
 
 
 45 
 
 
Equity Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
 
 1 
 
 
 15 
 
 
 - 
 
 
 16 
 
 
 
Mutual Funds
 
 
 18 
 
 
 4 
 
 
 - 
 
 
 22 
 
 
Total Other Temporary Investments
 
$
 344 
 
$
 19 
 
$
 - 
 
$
 363 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Primarily represents amounts held for the payment of debt.

The following table provides the activity for our debt and equity securities within Other Temporary Investments for the years ended December 31, 2010, 2009 and 2008:

 
Years Ended December 31,
 
 
2010
 
2009
 
2008
 
 
(in millions)
 
Proceeds From Investment Sales
  $ 455     $ 35     $ 1,185  
Purchases of Investments
    503       82       1,118  
Gross Realized Gains on Investment Sales
    16       -       -  
Gross Realized Losses on Investment Sales
    -       -       -  

At December 31, 2010 and 2009, we had no Other Temporary Investments with an unrealized loss position.  In June 2009, we recorded $9 million ($6 million, net of tax) of other-than-temporary impairments of Other Temporary Investments for equity investments of our protected cell captive insurance company.  At December 31, 2010, the fair value of fixed income securities are primarily debt based mutual funds with short and intermediate maturities and variable rate demand notes.  Mutual funds may be sold and do not contain maturity dates.

 
111
 
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 at December 31, 2010 and December 31, 2009:

 
 
 
 
 
December 31,
 
 
 
 
 
2010 
 
2009 
 
 
 
 
 
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
 
$
 20 
 
$
 - 
 
$
 - 
 
$
 14 
 
$
 - 
 
$
 - 
 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 
 461 
 
 
 23 
 
 
 (1)
 
 
 401 
 
 
 13 
 
 
 (4)
 
 
Corporate Debt
 
 
 59 
 
 
 4 
 
 
 (2)
 
 
 57 
 
 
 5 
 
 
 (2)
 
 
State and Local Government
 
 
 341 
 
 
 (1)
 
 
 - 
 
 
 369 
 
 
 8 
 
 
 1 
 
 
 
Subtotal Fixed Income Securities
 
 
 861 
 
 
 26 
 
 
 (3)
 
 
 827 
 
 
 26 
 
 
 (5)
 
Equity Securities - Domestic
 
 
 634 
 
 
 183 
 
 
 (123)
 
 
 551 
 
 
 234 
 
 
 (119)
 
Spent Nuclear Fuel and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decommissioning Trusts
 
$
 1,515 
 
$
 209 
 
$
 (126)
 
$
 1,392 
 
$
 260 
 
$
 (124)

The following table provides the securities activity within the decommissioning and SNF trusts for the years ended December 31, 2010, 2009 and 2008:

 
Years Ended December 31,
 
 
2010
 
2009
 
2008
 
 
(in millions)
 
Proceeds From Investment Sales
  $ 1,362     $ 713     $ 732  
Purchases of Investments
    1,415       771       804  
Gross Realized Gains on Investment Sales
    12       28       33  
Gross Realized Losses on Investment Sales
    2       1       7  

The adjusted cost of debt securities was $835 million and $801 million as of December 31, 2010 and 2009, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at December 31, 2010 was as follows:

 
Fair Value
 
 
of Debt
 
 
Securities
 
 
(in millions)
 
Within 1 year
  $ 22  
1 year – 5 years
    306  
5 years – 10 years
    257  
After 10 years
    276  
Total
  $ 861  

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, 2010 and 2009.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their
 
 
112
 
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 AEP’s valuation techniques.

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Assets:
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
$
 170 
 
$
 - 
 
$
 - 
 
$
 124 
 
$
 294 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Temporary Investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Restricted Cash (a)
 
 184 
 
 
 - 
 
 
 - 
 
 
 41 
 
 
 225 
 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mutual Funds
 
 69 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 69 
 
 
Variable Rate Demand Notes
 
 - 
 
 
 97 
 
 
 - 
 
 
 - 
 
 
 97 
 
Equity Securities - Mutual Funds (b)
 
 25 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 25 
 
Total Other Temporary Investments
 
 278 
 
 
 97 
 
 
 - 
 
 
 41 
 
 
 416 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (c) (f)
 
 20 
 
 
 1,432 
 
 
 112 
 
 
 (1,013)
 
 
 551 
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (c)
 
 11 
 
 
 17 
 
 
 - 
 
 
 (15)
 
 
 13 
 
 
Fair Value Hedges
 
 - 
 
 
 7 
 
 
 - 
 
 
 - 
 
 
 7 
 
 
Interest Rate/Foreign Currency Hedges
 
 - 
 
 
 25 
 
 
 - 
 
 
 - 
 
 
 25 
 
Dedesignated Risk Management Contracts (d)
 
 - 
 
 
 - 
 
 
 - 
 
 
 46 
 
 
 46 
 
Total Risk Management Assets
 
 31 
 
 
 1,481 
 
 
 112 
 
 
 (982)
 
 
 642 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (e)
 
 - 
 
 
 8 
 
 
 - 
 
 
 12 
 
 
 20 
 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 - 
 
 
 461 
 
 
 - 
 
 
 - 
 
 
 461 
 
 
Corporate Debt
 
 - 
 
 
 59 
 
 
 - 
 
 
 - 
 
 
 59 
 
 
State and Local Government
 
 - 
 
 
 341 
 
 
 - 
 
 
 - 
 
 
 341 
 
 
 
Subtotal Fixed Income Securities
 
 - 
 
 
 861 
 
 
 - 
 
 
 - 
 
 
 861 
 
Equity Securities - Domestic (b)
 
 634 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 634 
 
Total Spent Nuclear Fuel and Decommissioning Trusts
 
 634 
 
 
 869 
 
 
 - 
 
 
 12 
 
 
 1,515 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 1,113 
 
$
 2,447 
 
$
 112 
 
$
 (805)
 
$
 2,867 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (c) (f)
$
 25 
 
$
 1,325 
 
$
 27 
 
$
 (1,114)
 
$
 263 
 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (c)
 
 4 
 
 
 13 
 
 
 - 
 
 
 (15)
 
 
 2 
 
 
Fair Value Hedges
 
 - 
 
 
 1 
 
 
 - 
 
 
 - 
 
 
 1 
 
 
Interest Rate/Foreign Currency Hedges
 
 - 
 
 
 4 
 
 
 - 
 
 
 - 
 
 
 4 
 
Total Risk Management Liabilities
$
 29 
 
$
 1,343 
 
$
 27 
 
$
 (1,129)
 
$
 270 
 
 
 
113
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
$
 427 
 
$
 - 
 
$
 - 
 
$
 63 
 
$
 490 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Temporary Investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Restricted Cash (a)
 
 198 
 
 
 - 
 
 
 - 
 
 
 25 
 
 
 223 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mutual Funds
 
 57 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 57 
 
Variable Rate Demand Notes
 
 - 
 
 
 45 
 
 
 - 
 
 
 - 
 
 
 45 
Equity Securities (b):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
 16 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 16 
 
Mutual Funds
 
 22 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 22 
Total Other Temporary Investments
 
 293 
 
 
 45 
 
 
 - 
 
 
 25 
 
 
 363 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (c) (g)
 
 8 
 
 
 1,609 
 
 
 72 
 
 
 (1,119)
 
 
 570 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (c)
 
 1 
 
 
 11 
 
 
 - 
 
 
 (4)
 
 
 8 
Dedesignated Risk Management Contracts (d)
 
 - 
 
 
 - 
 
 
 - 
 
 
 25 
 
 
 25 
Total Risk Management Assets
 
 9 
 
 
 1,620 
 
 
 72 
 
 
 (1,098)
 
 
 603 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (e)
 
 - 
 
 
 3 
 
 
 - 
 
 
 11 
 
 
 14 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 - 
 
 
 401 
 
 
 - 
 
 
 - 
 
 
 401 
 
Corporate Debt
 
 - 
 
 
 57 
 
 
 - 
 
 
 - 
 
 
 57 
 
State and Local Government
 
 - 
 
 
 369 
 
 
 - 
 
 
 - 
 
 
 369 
 
 
Subtotal Fixed Income Securities
 
 - 
 
 
 827 
 
 
 - 
 
 
 - 
 
 
 827 
Equity Securities - Domestic (b)
 
 551 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 551 
Total Spent Nuclear Fuel and Decommissioning Trusts
 
 551 
 
 
 830 
 
 
 - 
 
 
 11 
 
 
 1,392 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 1,280 
 
$
 2,495 
 
$
 72 
 
$
 (999)
 
$
 2,848 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (c) (g)
$
 11 
 
$
 1,415 
 
$
 10 
 
$
 (1,205)
 
$
 231 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (c)
 
 - 
 
 
 16 
 
 
 - 
 
 
 (4)
 
 
 12 
 
Interest Rate/Foreign Currency Hedges
 
 - 
 
 
 5 
 
 
 - 
 
 
 - 
 
 
 5 
Total Risk Management Liabilities
$
 11 
 
$
 1,436 
 
$
 10 
 
$
 (1,209)
 
$
 248 

 
(a)
Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties.  Level 1 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)
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.
 
(e)
Amounts in "Other" column primarily represent accrued interest receivables from financial institutions.  Level 2 amounts primarily represent investments in money market funds.
 
(f)
The December 31, 2010 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures ($2) million in 2011, $2 million in periods 2012-2014 and ($5) million in periods 2015-2018;  Level 2 matures $13 million in 2011, $66 million in periods 2012-2014, $12 million in periods 2015-2016 and $16 million in periods 2017-2028;  Level 3 matures $18 million in 2011, $24 million in periods 2012-2014, $16 million in periods 2015-2016 and $27 million in periods 2017-2028.  Risk management commodity contracts are substantially comprised of power contracts.
 
(g)
The December 31, 2009 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures ($1) million in 2010, ($1) million in periods 2011-2013 and ($1) million in periods 2014-2015;  Level 2 matures $65 million in 2010, $84 million in periods 2011-2013, $22 million in periods 2014-2015 and $23 million in periods 2016-2028;  Level 3 matures $17 million in 2010, $16 million in periods 2011-2013, $8 million in periods 2014-2015 and $21 million in periods 2016-2028.

 
114
 
There have been no transfers between Level 1 and Level 2 during the year ended December 31, 2010.

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, 2010
 
Assets (Liabilities)
 
 
 
(in millions)
Balance as of December 31, 2009
 
$
 62 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
 
 5 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
 
 
 
 
Relating to Assets Still Held at the Reporting Date (a)
 
 
 63 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
 
 
 - 
Purchases, Issuances and Settlements (c)
 
 
 (25)
Transfers into Level 3 (d) (h)
 
 
 18 
Transfers out of Level 3 (e) (h)
 
 
 (53)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
 
 15 
Balance as of December 31, 2010
 
$
 85 

 
 
 
Net Risk Management
 Year Ended December 31, 2009
 
Assets (Liabilities)
 
 
 
(in millions)
Balance as of December 31, 2008
 
$
 49 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 
 
 (4)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
 
 
 
 
Relating to Assets Still Held at the Reporting Date (a)
 
 
 44 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income
 
 
 - 
Purchases, Issuances and Settlements (c)
 
 
 (17)
Transfers in and/or out of Level 3 (f)
 
 
 (25)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
 
 15 
Balance as of December 31, 2009
 
$
 62 

 
 
 
Net Risk
 
 
 
 
 
 
 
 
 
Management
 
Other
 
Investments
 
 
 
Assets
 
Temporary
 
in Debt
 Year Ended December 31, 2008
 
(Liabilities)
 
Investments
 
Securities
 
 
 
(in millions)
Balance as of December 31, 2007
 
$
 49 
 
$
 - 
 
$
 - 
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)
 - 
 
 
 - 
 
 
 - 
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held at the Reporting Date (a)
 
 
 12 
 
 
 - 
 
 
 - 
Realized and Unrealized Gains (Losses) Included in Other
 
 
 
 
 
 
 
 
 
 
Comprehensive Income
 
 
 - 
 
 
 - 
 
 
 - 
Purchases, Issuances and Settlements (c)
 
 
 - 
 
 
 (118)
 
 
 (17)
Transfers in and/or out of Level 3 (f)
 
 
 (36)
 
 
 118 
 
 
 17 
Changes in Fair Value Allocated to Regulated Jurisdictions (g)
 
 
 24 
 
 
 - 
 
 
 - 
Balance as of December 31, 2008
 
$
 49 
 
$
 - 
 
$
 - 

 
(a)
Included in revenues on our Consolidated 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)
Represents existing assets or liabilities that were previously categorized as Level 3.
 
(f)
Represents existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period.
 
(g)
Relates to the net gains (losses) of those contracts that are not reflected on our Consolidated Statements of Income.  These net gains (losses) are recorded as regulatory liabilities/assets.
 
(h)
Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

 
115
 
12.   INCOME TAXES

The details of our consolidated income taxes before discontinued operations and extraordinary loss as reported are as follows:

 
 
Years Ended December 31,
 
 
 
2010
   
2009
   
2008
 
 
 
(in millions)
 
Federal:
 
 
   
 
   
 
 
Current
  $ (134 )   $ (575 )   $ 164  
Deferred
    760       1,171       456  
Total Federal
    626       596       620  
 
                       
State and Local:
                       
Current
    (20 )     (76 )     (1 )
Deferred
    38       55       22  
Total State and Local
    18       (21 )     21  
 
                       
International:
                       
Current
    (1 )     -       1  
Deferred
    -       -       -  
Total International
    (1 )     -       1  
 
                       
Total Income Tax Expense Before Discontinued
                       
Operations and Extraordinary Loss
  $ 643     $ 575     $ 642  

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,
 
2010 
 
2009 
 
2008 
 
(in millions)
Net Income
$
 1,218 
 
$
 1,365 
 
$
 1,388 
Discontinued Operations, Net of Income Tax of $(10) million in 2008
 
 - 
 
 
 - 
 
 
 (12)
Extraordinary Loss, Net of Income Tax of $3 million in 2009
 
 - 
 
 
 5 
 
 
 - 
Income Before Discontinued Operations and Extraordinary Loss
 
 1,218 
 
 
 1,370 
 
 
 1,376 
Income Tax Expense Before Discontinued Operations and Extraordinary Loss
 
 643 
 
 
 575 
 
 
 642 
Pretax Income
$
 1,861 
 
$
 1,945 
 
$
 2,018 
 
 
 
 
 
 
 
 
 
Income Taxes on Pretax Income at Statutory Rate (35%)
$
 651 
 
$
 681 
 
$
 706 
Increase (Decrease) in Income Taxes resulting from the following items:
 
 
 
 
 
 
 
 
 
 
Depreciation
 
 47 
 
 
 31 
 
 
 23 
 
 
Investment Tax Credits, Net
 
 (16)
 
 
 (19)
 
 
 (19)
 
 
Energy Production Credits
 
 (20)
 
 
 (15)
 
 
 (20)
 
 
State and Local Income Taxes
 
 11 
 
 
 (14)
 
 
 13 
 
 
Removal Costs
 
 (19)
 
 
 (19)
 
 
 (21)
 
 
AFUDC
 
 (33)
 
 
 (36)
 
 
 (24)
 
 
Medicare Subsidy
 
 12 
 
 
 (11)
 
 
 (12)
 
 
Tax Reserve Adjustments
 
 (16)
 
 
 (6)
 
 
 2 
 
 
Other
 
 26 
 
 
 (17)
 
 
 (6)
Total Income Tax Expense Before Discontinued Operations and
 
 
 
 
 
 
 
 
 
Extraordinary Loss
$
 643 
 
$
 575 
 
$
 642 
 
 
 
 
 
 
 
 
 
Effective Income Tax Rate
 
 34.6 
%
 
 
 29.6 
%
 
 
 31.8 
%

 
116
 
The following table shows elements of the net deferred tax liability and significant temporary differences:

 
 
December 31,
 
 
 
2010
   
2009
 
 
 
(in millions)
 
Deferred Tax Assets
  $ 2,519     $ 2,493  
Deferred Tax Liabilities
    (10,009 )     (9,065 )
Net Deferred Tax Liabilities
  $ (7,490 )   $ (6,572 )
 
               
Property-Related Temporary Differences
  $ (5,301 )   $ (4,714 )
Amounts Due from Customers for Future Federal Income Taxes
    (250 )     (229 )
Deferred State Income Taxes
    (622 )     (523 )
Securitized Transition Assets
    (651 )     (712 )
Regulatory Assets
    (867 )     (862 )
Accrued Pensions
    218       335  
Deferred Income Taxes on Other Comprehensive Loss
    207       203  
Accrued Nuclear Decommissioning
    (395 )     (356 )
All Other, Net
    171       286  
Net Deferred Tax Liabilities
  $ (7,490 )   $ (6,572 )

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.

At December 31, 2010, we have federal general business credit carryforwards of $64 million.  If these credits are not utilized, they will expire in the years 2028 through 2030.

We are no longer subject to U.S. federal examination for years before 2001.  We have completed the exam for the years 2001 through 2006 and have issues that we are pursuing at the appeals level.  The years 2007 and 2008 are currently under examination.  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 have a material adverse effect on 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.  We believe that we have filed tax returns with 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 the ultimate resolution of these audits will not materially impact net income.  With few exceptions, we are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2000.

We sustained federal, state and local net income tax operating losses in 2009 driven primarily by bonus depreciation, a change in tax accounting method related to units of property and other book versus tax temporary differences.  As a result, we accrued current federal, state and local income tax benefits in 2009.  We realized the federal cash flow benefit in 2010 as there was sufficient capacity in prior periods to carry the net operating loss back.  Most of our state and local jurisdictions do not provide for a net operating loss carry back.  We anticipate future taxable income will be sufficient to realize the tax benefit.  As such, we determined that a valuation allowance is unnecessary.

We recognize interest accruals related to uncertain tax positions in interest income or expense, as applicable, and penalties in Other Operation in accordance with the accounting guidance for “Income Taxes.”

 
117
 
The following table shows amounts reported for interest expense, interest income and reversal of prior period interest expense:

 
Years Ended December 31,
 
 
2010
 
2009
 
2008
 
 
(in millions)
 
Interest Expense
  $ 8     $ 1     $ 10  
Interest Income
    11       5       21  
Reversal of Prior Period Interest Expense
    5       5       13  

The following table shows balances for amounts accrued for the receipt of interest and the payment of interest and penalties:

 
December 31,
 
 
2010
 
2009
 
 
(in millions)
 
Accrual for Receipt of Interest
  $ 42     $ 30  
Accrual for Payment of Interest and Penalties
    21       18  

The reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

 
 
2010
   
2009
   
2008
 
 
 
(in millions)
 
Balance at January 1,
  $ 237     $ 237     $ 222  
Increase - Tax Positions Taken During a Prior Period
    40       56       41  
Decrease - Tax Positions Taken During a Prior Period
    (43 )     (65 )     (45 )
Increase - Tax Positions Taken During the Current Year
    -       16       27  
Decrease - Tax Positions Taken During the Current Year
    (6 )     -       (5 )
Increase - Settlements with Taxing Authorities
    -       1       3  
Decrease - Settlements with Taxing Authorities
    (2 )     -       -  
Decrease - Lapse of the Applicable Statute of Limitations
    (7 )     (8 )     (6 )
Balance at December 31,
  $ 219     $ 237     $ 237  

The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $112 million, $137 million and $147 million for 2010, 2009 and 2008, 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

Under the Energy Tax Incentives Act of 2005, we filed applications with the United States Department of Energy and the IRS in 2008 for the West Virginia IGCC project and in July 2008 the IRS allocated the project $134 million in credits.  In September 2008, we entered into a memorandum of understanding with the IRS concerning the requirements of claiming the credits.  We had until July 2010 to meet certain minimum requirements under the agreement with the IRS or the credits would be forfeited.  In July 2010, we forfeited the allocated tax credits.

The Economic Stimulus Act of 2008 provided enhanced expensing provisions for certain assets placed in service in 2008 and a 50% bonus depreciation provision similar to the one in effect in 2003 through 2004 for assets placed in service in 2008.  The enacted provisions did not have a material impact on net income or financial condition, but provided a cash flow benefit of approximately $ 200 million in 2008.

The   American Recovery and Reinvestment Tax Act of 2009 provided for several new grant programs and expanded tax credits and an extension of the 50% bonus depreciation provision enacted in the Economic Stimulus Act of 2008.  The enacted provisions did not have a material impact on net income or financial condition.  However, the bonus depreciation contributed to the 2009 federal net operating tax loss that resulted in a 2010 cash flow benefit of $419 million.

 
118
 
The Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act (Health Care Acts) were enacted in March 2010.  The Health Care Acts amend tax rules so that the portion of employer health care costs that are reimbursed by the Medicare Part D prescription drug subsidy will no longer be deductible by the employer for federal income tax purposes effective for years beginning after December 31, 2012.  Because of the loss of the future tax deduction, a reduction in the deferred tax asset related to the nondeductible OPEB liabilities accrued to date was recorded in March 2010.  This reduction did not materially affect our cash flows or financial condition.  For the year ended December 31, 2010, deferred tax assets decreased $ 56 million, partially offset by recording net tax regulatory assets of $35 million in our jurisdictions with regulated operations, resulting in a decrease in net income of $21 million.

The Small Business Jobs Act (the Act) was enacted in September 2010.  Included in the Act was a one-year extension of the 50% bonus depreciation provision.  The Tax Relief, Unemployment Insurance Reauthorization and the Job Creation Act of 2010 extended the life of research and development, employment and several energy tax credits originally scheduled to expire at the end of 2010.  In addition, the Act extended the time for claiming bonus depreciation and increased the deduction to 100% for part of 2010 and 2011.  The enacted provisions will not have a material impact on net income or financial condition but had a favorable impact on cash flows of $ 318 million in 2010.

State Tax Legislation

Under Ohio House Bill 66, in 2005, the Ohio companies established a regulatory liability for $57 million pending rate-making treatment in Ohio.  For those companies in which state income taxes flow through for rate-making purposes, regulatory assets associated with the deferred state income tax liabilities were reduced by $22 million.  In November 2006, the PUCO ordered that the $57 million be amortized to income as an offset to power supply contract losses incurred by CSPCo and OPCo for sales to Ormet.  As of December 31, 2008, the $57 million regulatory liability was fully amortized.

The Ohio legislation also imposed a new commercial activity tax at a fully phased-in rate of 0.26% on all Ohio gross receipts.  The tax was phased-in over a five-year period that began July 1, 2005 at 23% of the full 0.26% rate.  As a result of this tax, expenses of approximately $13 million, $ 11 million and $9 million were recorded in 2010, 2009 and 2008, respectively, in Taxes Other Than Income Taxes.

Michigan Senate Bill 0094 (MBT Act), effective January 1, 2008, provided a comprehensive restructuring of Michigan’s principal business tax.  The law replaced the Michigan Single Business Tax.  The MBT Act is composed of a new tax which is calculated based upon two components:  (a) a business income tax (BIT) imposed at a rate of 4.95% and (b) a modified gross receipts tax (GRT) imposed at a rate of 0.80%, which will collectively be referred to as the BIT/GRT tax calculation.  The law also includes significant credits for engaging in Michigan-based activity.

In March 2008, legislation was signed providing for, among other things, a reduction in the West Virginia corporate income tax rate from 8.75% to 8.5% beginning in 2009.  The corporate income tax rate could also be reduced to 7.75% in 2012 and 7% in 2013 contingent upon the state government achieving certain minimum levels of shortfall reserve funds.  We have evaluated the impact of the law change and the application of the law change will not materially impact our net income, cash flows or financial condition.

 
119
 
13.   LEASES

Leases of property, plant and equipment are for periods up to 60 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.  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
 
2010
 
2009
 
2008
 
 
 
(in millions)
 
Net Lease Expense on Operating Leases
    $ 343     $ 354     $ 368  
Amortization of Capital Leases
      97       83       97  
Interest on Capital Leases
      26       13       16  
Total Lease Rental Costs
    $ 466     $ 450     $ 481  

The following table shows the property, plant and equipment under capital leases and related obligations recorded on our Consolidated Balance Sheets.  Capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on our Consolidated Balance Sheets.

 
 
December 31,
 
Property, Plant and Equipment Under Capital Leases
 
2010
 
2009
 
 
 
(in millions)
 
Generation
    $ 97     $ 75  
Distribution
      -       -  
Other Property, Plant and Equipment
      482       379  
Construction Work in Progress
      -       -  
Total Property, Plant and Equipment Under Capital Leases
      579       454  
Accumulated Amortization
      108       139  
Net Property, Plant and Equipment Under Capital Leases
    $ 471     $ 315  

Obligations Under Capital Leases
   
 
   
 
 
Noncurrent Liability
    $ 398     $ 244  
Liability Due Within One Year
      76       73  
Total Obligations Under Capital Leases
    $ 474     $ 317  

Future minimum lease payments consisted of the following at December 31, 2010:

 
 
 
   
Noncancelable
 
Future Minimum Lease Payments
 
Capital Leases
   
Operating Leases
 
 
 
(in millions)
 
2011 
  $ 100     $ 306  
2012 
    88       286  
2013 
    71       261  
2014 
    59       241  
2015 
    47       226  
Later Years
    286       1,349  
Total Future Minimum Lease Payments
  $ 651     $ 2,669  
Less Estimated Interest Element
    177          
Estimated Present Value of Future Minimum
               
Lease Payments
  $ 474          

 
120
 
Master Lease Agreements

We lease certain equipment under master lease agreements.  In December 2010, we signed a new master lease agreement with GE Capital Commercial Inc. (GE) for approximately $137 million to replace existing operating and capital leases with GE.  We refinanced approximately $60 million of capital leases and approximately $77 million in operating leases.  These assets were included in existing master lease agreements that were to be terminated in 2011 since GE exercised the termination provision related to these leases in 2008.  Approximately $16 million of currently leased assets were not included in the refinancing, but will be purchased or refinanced in 2011.  In addition, approximately $40 million of operating leases that were previously under lease with GE are now recorded as capital leases after the refinancing.  These obligations are included in the future minimum lease payments schedule earlier in this note.

For equipment under the GE master lease agreements, the lessor is guaranteed receipt of up to 84% of the unamortized balance of the equipment at the end of the lease term.  If the fair value of the leased equipment is below the unamortized balance at the end of the lease term, we are committed to pay the difference between the fair value and the unamortized balance, with the total guarantee not to exceed 84% of the unamortized balance.  For equipment under other master 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.  At December 31, 2010, the maximum potential loss for these lease agreements was approximately $14 million ($9 million, net of tax) assuming the fair value of the equipment is zero at the end of the lease term.  Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.

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.  Neither AEGCo, I&M nor AEP has an 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, 2010 are as follows:

Future Minimum Lease Payments
 
AEGCo
   
I&M
 
 
 
(in millions)
 
2011 
  $ 74     $ 74  
2012 
    74       74  
2013 
    74       74  
2014 
    74       74  
2015 
    74       74  
Later Years
    517       517  
Total Future Minimum Lease Payments
  $ 887     $ 887  

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
 
 
121
 
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 $17 million for I&M and $19 million for SWEPCo for the remaining railcars as of December 31, 2010.  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 84% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  I&M’s maximum potential loss related to the guarantee is approximately $ 12 million ($8 million, net of tax) and SWEPCo’s is approximately $13 million ($9 million, net of tax) 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.

Sabine Dragline Lease

During 2009, Sabine, an entity consolidated in accordance with the accounting guidance for “Variable Interest Entities,” 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.  In addition to the 2009 transactions, Sabine has one additional $53 million dragline completed in 2008 that was financed under a capital lease.  These capital lease assets are included in Other Property, Plant and Equipment on our December 31, 2010 and 2009 Consolidated 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, 2010 and 2009 Consolidated 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 December 2007, I&M entered into a sale-and-leaseback transaction with Citicorp Leasing, Inc. (CLI), an unrelated, unconsolidated, wholly-owned subsidiary of Citibank, N.A. to lease nuclear fuel for I&M’s Cook Plant.  In December 2007, I&M sold a portion of its unamortized nuclear fuel inventory to CLI at cost for $ 85 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 60 months.  The future payment obligations of $3 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, 2010 and 2009 Consolidated Balance Sheets.  The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2010 are as follows, based on estimated fuel burn:

Future Minimum Lease Payments
 
Amount
 
 
(in millions)
2011 
    $ 2
2012 
      1
Total Future Minimum Lease Payments
    $ 3

 
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14.   FINANCING ACTIVITIES

AEP Common Stock

In April 2009, we issued 69 million shares of common stock at $24.50 per share for net proceeds of $1.64 billion, which were primarily used to repay cash drawn under our credit facilities in the second quarter of 2009.

Set forth below is a reconciliation of common stock share activity for the years ended December 31, 2010, 2009 and 2008:

 
 
 
   
Held in
 
Shares of AEP Common Stock
 
Issued
   
Treasury
 
Balance, December 31, 2007
    421,926,696       21,499,992  
Issued
    4,394,552       -  
Treasury Stock Contributed to AEP Foundation
    -       (1,250,000 )
Balance, December 31, 2008
    426,321,248       20,249,992  
Issued
    72,012,017       -  
Treasury Stock Acquired
    -       28,866  
Balance, December 31, 2009
    498,333,265       20,278,858  
Issued
    2,781,616       -  
Treasury Stock Acquired
    -       28,867  
Balance, December 31, 2010
    501,114,881       20,307,725  

Preferred Stock

Information about the components of preferred stock of our subsidiaries is as follows:

 
December 31, 2010
 
Call Price
 
Shares
 
Shares
 
 
 
Per Share (a)
 
Authorized (b)
 
Outstanding (c)
 
Amount
Not Subject to Mandatory Redemption:
 
 
 
 
 
 
(in millions)
 
4.00% - 5.00%
$102-$110
 
 1,525,903 
 
 600,641 
 
$
 60 
 
 
 
 
 
 
 
 
 
December 31, 2009
 
Call Price
 
Shares
 
Shares
 
 
 
Per Share (a)
 
Authorized (b)
 
Outstanding (c)
 
Amount
Not Subject to Mandatory Redemption:
 
 
 
 
 
 
(in millions)
 
4.00% - 5.00%
$102-$110
 
 1,525,903 
 
 606,627 
 
$
 61 

(a)
At the option of the subsidiary, the shares may be redeemed at the call price plus accrued dividends.  The involuntary liquidation preference is $100 per share for all outstanding shares.  If the subsidiary defaults on preferred stock dividend payments for a period of one year or longer, preferred stock holders are entitled, voting separately as one class, to elect the number of directors necessary to constitute a majority of the full board of directors of the subsidiary.
(b)
As of December 31, 2010 and 2009, our subsidiaries had 14,494,227 and 14,488,294 shares of $100 par value preferred stock, respectively, 22,200,000 shares of $25 par value preferred stock and 7,822,535 and 7,822,482 shares of no par value preferred stock, respectively, that were authorized but unissued.  Total shares authorized but unissued include shares not subject to mandatory redemption described in the above table.
(c)
The number of preferred stock shares redeemed was 5,986 shares and 251 shares in 2010 and 2009, respectively.  There were no preferred stock shares redeemed in 2008.
 
 
 
123
 
Long-term Debt
 
 
 
Weighted
 
 
 
 
 
 
Average
 
 
 
 
 
 
 
 
 
Interest
 
 
 
 
 
 
 
 
 
 
 
 
Rate at
 
 
 
Outstanding at
 
 
December 31,
 
Interest Rate Ranges at December 31,
 
December 31,
Type of Debt and Maturity
 
2010 
 
2010 
 
2009 
 
2010 
 
2009 
 
 
 
 
 
 
 
 
(in millions)
Senior Unsecured Notes
 
 
 
 
 
 
 
 
 
 
 
 
 
2010-2015
 
4.99%
 
0.702%-6.375%
 
0.464%-6.375%
 
$
 3,318 
 
$
 4,258 
 
2016-2021
 
6.12%
 
5.00%-7.95%
 
5.00%-7.95%
 
 
 4,020 
 
 
 4,020 
 
2029-2040
 
6.41%
 
5.625%-8.13%
 
5.625%-8.13%
 
 
 4,331 
 
 
 4,138 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pollution Control Bonds (a)
 
 
 
 
 
 
 
 
 
 
 
 
 
2010-2015 (b)
 
2.95%
 
0.29%-6.25%
 
0.22%-7.125%
 
 
 1,300 
 
 
 800 
 
2017-2025
 
5.12%
 
4.45%-6.05%
 
0.23%-6.05%
 
 
 443 
 
 
 595 
 
2026-2042
 
5.19%
 
4.40%-6.30%
 
0.20%-6.30%
 
 
 520 
 
 
 764 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes Payable (c)
 
 
 
 
 
 
 
 
 
 
 
 
 
2011-2026
 
5.44%
 
2.07%-8.03%
 
4.47%-8.03%
 
 
 396 
 
 
 326 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Securitization Bonds
 
 
 
 
 
 
 
 
 
 
 
 
 
2010-2020
 
5.36%
 
4.98%-6.25%
 
4.98%-6.25%
 
 
 1,847 
 
 
 1,995 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Junior Subordinated Debentures (d)
 
 
 
 
 
 
 
 
 
 
 
 
 
2063 
 
8.75%
 
8.75%
 
8.75%
 
 
 315 
 
 
 315 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel Obligation (e)
 
 
 
 
 
 
 
 
 265 
 
 
 265 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Long-term Debt
 
 
 
 
 
 
 
 
 
 
 
 
 
2011-2059
 
1.72%
 
1.3125%-13.718%
 
1.25%-13.718%
 
 
 91 
 
 
 88 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unamortized Discount (net)
 
 
 
 
 
 
 
 
 (35)
 
 
 (66)
Total Long-term Debt Outstanding
 
 
 
 
 
 
 
 
 16,811 
 
 
 17,498 
Less Portion Due Within One Year
 
 
 
 
 
 
 
 
 1,309 
 
 
 1,741 
Long-term Portion
 
 
 
 
 
 
 
$
 15,502 
 
$
 15,757 

 
(a)
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, standby bond purchase agreements and insurance policies support certain series.
 
(b)
Certain pollution control bonds are subject to mandatory redemption earlier than the maturity date.  Consequently, these bonds have been classified for maturity and repayment purposes based on the mandatory redemption date.
 
(c)
Notes payable represent outstanding promissory notes issued under term loan agreements and revolving 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.
 
(d)
Debentures will mature on March 1, 2063, subject to extensions to no later than March 1, 2068, and are callable at par any time on or after March 1, 2013.
 
(e)
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).

At December 31, 2010, $50 million of PSO’s Senior Unsecured Notes, which are due within one year, are classified as long-term debt due to our intent and ability to refinance these notes on a long-term basis.  In January 2011, PSO issued $250 million of 4.4% Senior Unsecured Notes due in 2021, demonstrating the ability to refinance these obligations on a long-term basis.

At December 31, 2009, approximately $472 million of variable-rate, tax-exempt bonds were outstanding.  These bonds, which are short-term obligations, were classified as long-term due to our intent and ability to refinance each obligation on a long-term basis.  At December 31, 2009, our $478 million credit facility had non-cancelable terms in excess of one year, demonstrating the ability to refinance these short-term obligations on a long-term basis.

 
124
 
Long-term debt outstanding at December 31, 2010 is payable as follows:

 
 
 
 
 
 
 
 
 
 
 
After
 
 
 
2011 
 
2012 
 
2013 
 
2014 
 
2015 
 
2015 
 
Total
 
(in millions)
Principal Amount
$
 1,309 
 
$
 815 
 
$
 1,344 
 
$
 941 
 
$
 1,490 
 
$
 10,947 
 
$
 16,846 
Unamortized Discount
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (35)
Total Long-term Debt Outstanding
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$
 16,811 

In January 2011, TCC retired $92 million of its outstanding Securitization Bonds.

In February 2011, APCo issued $65 million of 2% Pollution Control Bonds due in 2041 with a 2012 mandatory put date.

As of December 31, 2010, trustees held, on our behalf, $303 million of our reacquired variable rate tax-exempt long-term debt.

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.

We have issued $315 million of Junior Subordinated Debentures.  The debentures will mature on March 1, 2063, subject to extensions to no later than March 1, 2068, and are callable at par any time on or after March 1, 2013.  We have the option to defer interest payments on the debentures for one or more periods of up to 10 consecutive years per period.  During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire our common stock.  We do not anticipate any deferral of those interest payments in the foreseeable future.

Utility Subsidiaries’ Restrictions

Various financing arrangements, charter provisions 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, most of our public utility subsidiaries have revolving credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%.  At December 31, 2010, 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 $7 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 par value of the common stock multiplied by the number of shares outstanding.  This restriction does not limit the ability of the utility subsidiaries to pay dividends out of retained earnings.

 
125
 
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, 2010, we had credit facilities totaling $3 billion to support our commercial paper program (see “Credit Facilities” section below).  The maximum amount of commercial paper outstanding during 2010 was $868 million and the weighted average interest rate of commercial paper outstanding during the year was 0.43%.  Our outstanding short-term debt was as follows:

 
 
 
December 31,
 
 
 
2010 
 
2009 
 
 
 
Outstanding
 
Interest
 
Outstanding
 
Interest
Type of Debt
Amount
Rate (a)
 
Amount
Rate (a)
 
 
(in millions)
 
 
 
 
(in millions)
 
 
 
Securitized Debt for Receivables (b)
 
$
 690 
 
 0.31 
%
 
$
 - 
 
 - 
 
Commercial Paper
 
 
 650 
 
 0.52 
%
 
 
 119 
 
 0.26 
%
Line of Credit – Sabine Mining Company (c)
 
 
 6 
 
 2.15 
%
 
 
 7 
 
 2.06 
%
Total Short-term Debt
 
$
 1,346 
 
 
 
 
$
 126 
 
 
 

(a)
Weighted average rate.
(b)
Amount of securitized debt for receivables as accounted for under the "Transfers and Servicing" accounting guidance.  See "ASU 2009-16 'Transfers and Servicing' " section of Note 2.
(c)
Sabine Mining Company is a consolidated variable interest entity.  This line of credit does not reduce available liquidity under AEP's credit facilities.

Credit Facilities

We have credit facilities totaling $3 billion to support our commercial paper program.  The facilities are structured as two $1.5 billion credit facilities, of which $750 million may be issued under the credit facility that matures in April 2012 as letters of credit.  In June 2010, we terminated one of the $1.5 billion facilities, which was scheduled to mature in March 2011, and replaced it with a new $1.5 billion credit facility which matures in June 2013 and allows for the issuance of up to $600 million as letters of credit.  As of December 31, 2010, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $124 million.

In June 2010, we reduced a $627 million credit agreement that matures in April 2011 to $478 million.  Under the facility, we may issue letters of credit.  As of December 31, 2010, $477 million of letters of credit were issued by subsidiaries under this credit agreement to support variable rate Pollution Control Bonds.

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.  Prior to January 1, 2010, this transaction constituted a sale of receivables in accordance with the accounting guidance for “Transfers and Servicing,” allowing the receivables to be removed from our Consolidated Balance Sheet.  See “ASU 2009-16 ‘Transfers and Servicing’ ” section of Note 2 for discussion of the impact of new accounting guidance effective January 1, 2010 whereby such future transactions do not constitute a sale of receivables and will be accounted for as financings.  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 July 2010, AEP Credit renewed its receivables securitization agreement.  The agreement provides a commitment of $750 million from bank conduits to finance receivables from AEP Credit.  A commitment of $375 million expires in July 2011 and the remaining commitment of $375 million expires in July 2013.

 
126
 
Accounts receivable information for AEP Credit is as follows:
 
 
 
Years Ended December 31,
 
 
 
2010
   
2009
   
2008
 
 
 
(dollars in millions)
 
Proceeds from Sale of Accounts Receivable
  $ N/A     $ 7,043     $ 7,717  
Loss on Sale of Accounts Receivable
    N/A       3       20  
Average Variable Discount Rate on Sale of
                       
Accounts Receivable
    N/A       0.57 %     3.19 %
Effective Interest Rates on Securitization of
                       
Accounts Receivable
    0.31 %     N/A       N/A  
Net Uncollectible Accounts Receivable Written Off
    22       28       23  
 
                       

 
 
December 31,
 
 
 
2010
   
2009
 
 
 
(in millions)
 
Accounts Receivable Retained Interest and Pledged as Collateral
 
 
   
 
 
Less Uncollectible Accounts
  $ 923     $ 160  
Deferred Revenue from Servicing Accounts Receivable
    N/A       1  
Retained Interest if 10% Adverse Change in Uncollectible Accounts
    N/A       158  
Retained Interest if 20% Adverse Change in Uncollectible Accounts
    N/A       156  
Total Principal Outstanding
    690       656  
Derecognized Accounts Receivable
    N/A       631  
Delinquent Securitized Accounts Receivable
    50       29  
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable
    26       20  
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable
    354       376  
 
               
N/A  Not Applicable
               

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, including stock options, 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.  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 2010, 2009 or 2008 but we do have outstanding stock options from grants in earlier periods that vested or were exercised in these years.  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 st 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.

 
127
 
The total fair value of stock options vested and the total intrinsic value of options exercised are as follows:

 
 
Years Ended December 31,
 
Stock Options
 
2010
 
2009
 
2008
 
 
 
(in thousands)
 
Fair Value of Stock Options Vested
    $ -     $ 25     $ 25  
Intrinsic Value of Options Exercised (a)
      2,058       106       655  
 
(a)
Intrinsic value is calculated as market price at exercise dates less the option exercise price.
 
A summary of AEP stock option transactions during the years ended December 31, 2010, 2009 and 2008 is as follows:

 
 
 
2010 
 
2009 
 
2008 
 
 
 
 
 
Weighted
 
 
 
Weighted
 
 
 
Weighted
 
 
 
 
 
Average
 
 
 
Average
 
 
 
Average
 
 
 
 
 
Exercise
 
 
 
Exercise
 
 
 
Exercise
 
 
 
Options
 
Price
 
Options
 
Price
 
Options
 
Price
 
 
 
(in thousands)
 
 
 
 
(in thousands)
 
 
 
 
(in thousands)
 
 
 
Outstanding at January 1,
 1,089 
 
$
 32.78 
 
 1,128 
 
$
 32.73 
 
 1,196 
 
$
 32.69 
 
 
Granted
 - 
 
 
N/A
 
 - 
 
 
N/A
 
 - 
 
 
N/A
 
 
Exercised/Converted
 (448)
 
 
 31.53 
 
 (21)
 
 
 27.20 
 
 (68)
 
 
 31.97 
 
 
Forfeited/Expired
 (90)
 
 
 38.44 
 
 (18)
 
 
 36.28 
 
 - 
 
 
N/A
Outstanding at December 31,
 551 
 
 
 32.88 
 
 1,089 
 
 
 32.78 
 
 1,128 
 
 
 32.73 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Options Exercisable at December 31,
 551 
 
$
 32.88 
 
 1,089 
 
$
 32.78 
 
 1,125 
 
$
 32.72 

The following table summarizes information about AEP stock options outstanding and exercisable at December 31, 2010:

 
 
 
Number
 
Weighted
 
 
 
 
 
 
 
of Options
 
Average
 
Weighted
 
 
2010 Range of
 
Outstanding
 
Remaining
 
Average
 
Aggregate
Exercise Prices
 
and Exercisable
 
Life
 
Exercise Price
 
Intrinsic Value
 
 
(in thousands)
 
(in years)
 
 
 
 
(in thousands)
$27.06-27.95
 
 266 
 
 2.20 
 
$
 27.44 
 
$
 2,273 
$30.76-38.65
 
 159 
 
 3.10 
 
 
 31.26 
 
 
 778 
$44.10-49.00
 
 126 
 
 0.50 
 
 
 46.40 
 
 
 - 
Total
 
 551 
 
 2.08 
 
 
 32.88 
 
 
 3,051 

We include the proceeds received from exercised stock options in common stock and paid-in capital.

Performance Units

Our performance units have a value upon vesting equal to the market value of shares of AEP common stock.  The number of performance units held is multiplied by the performance score to determine the actual number of performance units realized.  The performance score 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 and can range from 0% to 200%.  For the three-year performance and vesting period ending in 2009 and earlier performance periods, performance units are paid in cash or stock at the employee’s election unless they are needed to satisfy a participant’s stock ownership requirement.  Starting with the three-year performance and vesting period ending in 2010 and later, 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 have a value equivalent to shares of AEP common stock and are paid in cash after the participant’s termination of employment.  Amounts equivalent to cash dividends on both performance units and
 
 
128
 
AEP Career Shares accrue as additional units.  We recorded 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 our Consolidated 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, 2010, 2009 and 2008 as follows:

 
 
Years Ended December 31,
Performance Units
 
2010 
 
2009 
 
2008 
Awarded Units (in thousands)
 
 
 736 
 
 
 1,179 
 
 
 1,384 
Weighted Average Unit Fair Value at Grant Date
 
$
 35.43 
 
$
 34.32 
 
$
 30.11 
Vesting Period (in years)
 
 
 3 
 
 
 3 
 
 
 3 
 
 
 
 
 
 
 
 
 
 
 
Performance Units and AEP Career Shares
 
Years Ended December 31,
(Reinvested Dividends Portion)
 
2010 
 
2009 
 
2008 
Awarded Units (in thousands)
 
 
 211 
 
 
 224 
 
 
 149 
Weighted Average Grant Date Fair Value
 
$
 34.70 
 
$
 28.82 
 
$
 37.21 
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.

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 value of final awards, but may not increase them.  The performance scores for all open performance periods are dependent on two equally-weighted performance measures: (a) three-year total shareholder return measured relative to the utility industry segment 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.   The value of each performance unit earned equals the average closing price of AEP common stock for the last 20 business days of the performance period.

The certified performance scores and units earned for the three-year period ended December 31, 2010, 2009 and 2008 were as follows:

 
Years Ended December 31,
 
2010 
 
2009 
 
2008 
Certified Performance Score
 55.8 
%
 
 73.5 
%
 
 120.3 
%
Performance Units Earned
 489,013 
 
 593,175 
 
 1,088,302 
Performance Units Manditorily Deferred as AEP Career Shares
 33,501 
 
 26,635 
 
 42,214 
Performance Units Voluntarily Deferred into the Incentive Compensation
 
 
 
 
 
 
 Deferral Program
 6,583 
 
 27,855 
 
 66,415 
Performance Units to be Paid in Cash
 448,929 
 
 538,685 
 
 979,673 

The cash payouts for the years ended December 31, 2010, 2009 and 2008 were as follows:

 
Years Ended December 31,
 
2010
 
2009
 
2008
 
(in thousands)
Cash Payouts for Performance Units
  $ 18,683     $ 30,034     $ 52,960
Cash Payouts for AEP Career Share Distributions
    3,594       2,184       1,236

 
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Restricted Shares and Restricted Stock Units

The independent members of the AEP Board of Directors granted 300,000 restricted shares to the then Chairman, President and CEO on January 2, 2004 upon the commencement of his AEP employment.  Of these restricted shares, 50,000 vested on January 1, 2005, 50,000 vested on January 1, 2006, 66,666 vested on November 30, 2009 and 66,667 vested on November 30, 2010.  The remaining 66,667 restricted shares will vest on November 30, 2011, subject to his continued AEP employment through that date.   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 term for these restricted shares is eight years and dividends on these restricted shares are 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 on the anniversaries of the grant date.  For awards granted prior to 2009, additional RSUs granted as dividends vest on the last vesting date associated with that RSU grant.  For awards granted in 2009 and later, additional RSUs granted as dividends vest on the same date as the underlying RSUs on which the dividends were awarded.  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.  The maximum contractual term of outstanding RSUs is five years from the grant date.

In 2010, the HR Committee granted a total of 165,520 of RSUs to four CEO succession candidates to better ensure the retention of 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.

The HR Committee awarded RSUs, including units awarded for dividends, for the years ended December 31, 2010, 2009 and 2008 as follows:

 
 
 
Years Ended December 31,
Restricted Stock Units
 
2010 
 
2009 
 
2008 
Awarded Units (in thousands)
 
 
 873 
 
 
 130 
 
 
 56 
Weighted Average Grant Date Fair Value
 
$
 35.24 
 
$
 29.29 
 
$
 41.69 

The total fair value and total intrinsic value of restricted shares and restricted stock units vested during the years ended December 31, 2010, 2009 and 2008 were as follows:

 
 
 
Years Ended December 31,
Restricted Shares and Restricted Stock Units
 
2010 
 
2009 
 
2008 
 
 
(in thousands)
Fair Value of Restricted Shares and Restricted Stock Units Vested
 
$
 6,044 
 
$
 6,573 
 
$
 2,619 
Intrinsic Value of Restricted Shares and Restricted Stock Units Vested (a)
 
 
 5,993 
 
 
 5,445 
 
 
 2,534 
 
 
 
 
 
 
 
 
 
 
(a)
Intrinsic value is calculated as market price at exercise date.

A summary of the status of our nonvested restricted shares and RSUs as of December 31, 2010 and changes during the year ended December 31, 2010 are as follows:

 
 
 
 
Weighted
 
 
 
 
 
Average
 
Nonvested Restricted Shares and
 
 
 
Grant Date
 
Restricted Stock Units
 
Shares/Units
 
Fair Value
 
 
 
(in thousands)
   
 
 
Nonvested at January 1, 2010
    366     $ 34.12  
Granted
    873       35.24  
Vested
    (173 )     35.00  
Forfeited
    (40 )     35.01  
Nonvested at December 31, 2010
    1,026       34.88  

 
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The total aggregate intrinsic value of nonvested restricted shares and RSUs as of December 31, 2010 was $37 million and the weighted average remaining contractual life was 3.09 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.  Amounts equivalent to cash dividends on the stock units accrue as additional AEP stock units.  The non-employee directors vest immediately upon award of the stock units.  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 20 trading days immediately preceding the payment date.

We recorded the compensation cost for stock units when the units are awarded and adjusted the liability for changes in value based on the current 20-day average closing price of AEP common stock at the date of valuation.

We had no material cash payouts for stock unit distributions for the years ended December 31, 2010, 2009 and 2008.

The Board of Directors awarded stock units, including units awarded for dividends, for the years ended December 31, 2010, 2009 and 2008 as follows:

 
 
 
Years Ended December 31,
Stock Unit Accumulation Plan for Non-Employee Directors
 
2010 
 
2009 
 
2008 
Awarded Units (in thousands)
 
 
 54 
 
 
 56 
 
 
 43 
Weighted Average Grant Date Fair Value
 
$
 34.67 
 
$
 29.56 
 
$
 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, 2010, 2009 and 2008 were as follows:

 
 
 
Years Ended December 31,
 
Share-based Compensation Plans
 
2010 
 
2009 
 
2008 
 
 
 
(in thousands)
 
Compensation Cost for Share-based Payment Arrangements (a)
 
$
 28,116 
 
$
 31,165 
 
$
 (18,028)
(b)
Actual Tax Benefit Realized
 
 
 9,841 
 
 
 10,908 
 
 
 (6,310)
(b)
Total Compensation Cost Capitalized
 
 
 4,689 
 
 
 5,956 
 
 
 (5,026)
(b)

(a)
Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on our Consolidated Statements of Income.
(b)
In 2008, AEP’s declining total shareholder return and lower stock price significantly reduced the accruals for performance units.

During the years ended December 31, 2010, 2009 and 2008, there were no significant modifications affecting any of our share-based payment arrangements.

As of December 31, 2010, there was $81 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 1.84 years.

 
131
 
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, 2010, 2009 and 2008 were as follows:

 
 
Years Ended December 31,
Share-based Compensation Plans
 
2010 
 
2009 
 
2008 
 
 
(in thousands)
Cash Received from Stock Options Exercised
 
$
 14,134 
 
$
 567 
 
$
 2,170 
Actual Tax Benefit Realized for the Tax Deductions from Stock Options Exercised
 
 
 706 
 
 
 35 
 
 
 219 

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 could 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 AEP’s tax withholding obligation.

16.   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 as follows:

2010 
 
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
 
$
 14,147 
 
$
 6,537 
 
 1.6 
-
 3.8 
%
 
9
-
132
 
$
 10,205 
 
$
 3,788 
 
 2.2 
-
 5.1 
%
 
20
-
70
Transmission
 
 
 8,576 
 
 
 2,481 
 
 1.4 
-
 3.0 
%
 
25
-
87
 
 
 - 
 
 
 - 
 
 - 
-
 - 
%
 
 - 
-
 - 
Distribution
 
 
 14,208 
 
 
 3,607 
 
 2.4 
-
 3.9 
%
 
11
-
75
 
 
 - 
 
 
 - 
 
 - 
-
 - 
%
 
 - 
-
 - 
CWIP
 
 
 2,615 
(a)
 
 47 
 
N.M.
 
N.M.
 
 
 143 
 
 
 9 
 
N.M.
 
N.M.
Other
 
 
 2,685 
 
 
 1,268 
 
 3.0 
-
 12.5 
%
 
5
-
55
 
 
 1,161 
 
 
 329 
 
N.M.
 
N.M.
Total
 
$
 42,231 
 
$
 13,940 
 
 
 
 
 
 
 
 
 
 
$
 11,509 
 
$
 4,126 
 
 
 
 
 
 
 
 
 

2009 
 
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
 
$
 13,047 
 
$
 6,460 
 
 1.6 
-
 3.8 
%
 
9
-
132
 
$
 9,998 
 
$
 3,479 
 
 1.9 
-
 3.3 
%
 
20
-
70
Transmission
 
 
 8,315 
 
 
 2,478 
 
 1.4 
-
 2.7 
%
 
25
-
87
 
 
 - 
 
 
 - 
 
 - 
-
 - 
%
 
 - 
-
 - 
Distribution
 
 
 13,549 
 
 
 3,421 
 
 2.4 
-
 3.9 
%
 
11
-
75
 
 
 - 
 
 
 - 
 
 - 
-
 - 
%
 
 - 
-
 - 
CWIP
 
 
 2,866 
(a)
 
 (19)
 
N.M.
 
N.M.
 
 
 165 
 
 
 6 
 
N.M.
 
N.M.
Other
 
 
 2,616 
 
 
 1,130 
 
 4.2 
-
 12.8 
%
 
5
-
55
 
 
 1,128 
 
 
 385 
 
N.M.
 
N.M.
Total
 
$
 40,393 
 
$
 13,470 
 
 
 
 
 
 
 
 
 
 
$
 11,291 
 
$
 3,870 
 
 
 
 
 
 
 
 
 
 

 
 
132
 
2008 
 
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
-
3.5
%
 
9
-
132
 
2.6
-
5.1
%
 
20
-
61
Transmission
 
1.4
-
2.7
%
 
25
-
87
 
 - 
-
 - 
%
 
 - 
-
 - 
Distribution
 
2.4
-
3.9
%
 
11
-
75
 
 - 
-
 - 
%
 
 - 
-
 - 
CWIP
 
N.M.
 
N.M.
 
N.M.
 
N.M.
Other
 
4.9
-
11.3
%
 
5
-
55
 
N.M.
 
N.M.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Includes CWIP related to SWEPCo's Arkansas jurisdictional share of the Turk Plant.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
N.M.  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.

For rate-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.

As of January 1, 2010, DHLC was deconsolidated and is now reported as an equity investment on our Consolidated Balance Sheet.  Also, see the “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.

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.

 
133
 
The following is a reconciliation of the 2010 and 2009 aggregate carrying amounts of ARO:

 
 
Carrying
 
 
 
Amount
 
 
 
of ARO
 
 
 
(in millions)
 
ARO at December 31, 2008
 
$
 1,158 
 
Accretion Expense
 
 
 73 
 
Liabilities Incurred
 
 
 47 
 
Liabilities Settled
 
 
 (24)
 
Revisions in Cash Flow Estimates
 
 
 5 
 
ARO at December 31, 2009 (a)
 
 
 1,259 
 
DHLC Deconsolidation (c)
 
 
 (12)
 
Accretion Expense
 
 
 75 
 
Liabilities Incurred
 
 
 32 
 
Liabilities Settled
 
 
 (20)
 
Revisions in Cash Flow Estimates
 
 
 64 
 
ARO at December 31, 2010 (b)
 
$
 1,398 
 
 
 
 
 
 
 
 
(a)
The current portion of our ARO, totaling $5 million, is included in Other Current Liabilities on our 2009 Consolidated Balance Sheet.
 
(b)
The current portion of our ARO, totaling $4 million, is included in Other Current Liabilities on our 2010 Consolidated Balance Sheet.
 
(c)
We adopted ASU 2009-17 effective January 1, 2010 and deconsolidated DHLC.  As a result, we record only 50% of the final reclamation based on our share of the obligation instead of the previous 100%.
 

As of December 31, 2010 and 2009, our ARO liability was $1.4 billion and $1.3 billion, respectively, and included $930 million and $878 million, respectively, for nuclear decommissioning of the Cook Plant.  As of December 31, 2010 and 2009, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $1.2 billion and $1.1 billion, respectively, and are recorded in Spent Nuclear Fuel and Decommissioning Trusts on our Consolidated 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,
 
 
2010
 
2009
 
2008
 
 
(in millions)
 
Allowance for Equity Funds Used During Construction
  $ 77     $ 82     $ 45  
Allowance for Borrowed Funds Used During Construction
    53       67       75  

 
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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 in our Consolidated Statements of Income and the investments and accumulated depreciation are reflected in our Consolidated Balance Sheets under Property, Plant and Equipment as follows:

 
 
 
 
 
 
Company’s Share at December 31, 2010
 
 
 
 
 
 
 
 
Construction
 
 
 
Fuel
Percent of
Utility Plant
Work in
Accumulated
 
Type
Ownership
 in Service
Progress
Depreciation
 
 
 
 
 
 
(in millions)
W.C. Beckjord Generating Station (Unit No. 6) (a)
Coal
 
 12.5 
%
 
$
 19 
 
$
 - 
 
$
 8 
Conesville Generating Station (Unit No. 4) (b)
Coal
 
 43.5 
%
 
 
 301 
 
 
 8 
 
 
 49 
J.M. Stuart Generating Station (c)
Coal
 
 26.0 
%
 
 
 507 
 
 
 23 
 
 
 163 
Wm. H. Zimmer Generating Station (a)
Coal
 
 25.4 
%
 
 
 771 
 
 
 10 
 
 
 366 
Dolet Hills Generating Station (Unit No. 1) (f)
Lignite
 
 40.2 
%
 
 
 258 
 
 
 5 
 
 
 192 
Flint Creek Generating Station (Unit No. 1) (g)
Coal
 
 50.0 
%
 
 
 116 
 
 
 7 
 
 
 62 
Pirkey Generating Station (Unit No. 1) (g)
Lignite
 
 85.9 
%
 
 
 503 
 
 
 10 
 
 
 358 
Oklaunion Generating Station (Unit No. 1) (e)
Coal
 
 70.3 
%
 
 
 395 
 
 
 4 
 
 
 201 
Turk Generating Plant (h)
Coal
 
 73.33 
%
 
 
 - 
 
 
 971 
 
 
 - 
Transmission
N/A
 
(d)
 
 
 
 63 
 
 
 3 
 
 
 48 

 
 
 
 
 
 
Company’s Share at December 31, 2009
 
 
 
 
 
 
 
 
Construction
 
 
 
Fuel
Percent of
Utility Plant
Work in
Accumulated
 
Type
Ownership
 in Service
Progress
Depreciation
 
 
 
 
 
 
(in millions)
W.C. Beckjord Generating Station (Unit No. 6) (a)
Coal
 
 12.5 
%
 
$
 19 
 
$
 - 
 
$
 8 
Conesville Generating Station (Unit No. 4) (b)
Coal
 
 43.5 
%
 
 
 301 
 
 
 4 
 
 
 45 
J.M. Stuart Generating Station (c)
Coal
 
 26.0 
%
 
 
 499 
 
 
 15 
 
 
 153 
Wm. H. Zimmer Generating Station (a)
Coal
 
 25.4 
%
 
 
 767 
 
 
 4 
 
 
 355 
Dolet Hills Generating Station (Unit No. 1) (f)
Lignite
 
 40.2 
%
 
 
 255 
 
 
 4 
 
 
 188 
Flint Creek Generating Station (Unit No. 1) (g)
Coal
 
 50.0 
%
 
 
 116 
 
 
 5 
 
 
 61 
Pirkey Generating Station (Unit No. 1) (g)
Lignite
 
 85.9 
%
 
 
 497 
 
 
 8 
 
 
 350 
Oklaunion Generating Station (Unit No. 1) (e)
Coal
 
 70.3 
%
 
 
 390 
 
 
 6 
 
 
 195 
Turk Generating Plant (h)
Coal
 
 73.33 
%
 
 
 - 
 
 
 688 
 
 
 - 
Transmission
N/A
 
(d)
 
 
 
 70 
 
 
 1 
 
 
 47 

(a)          Operated by Duke Energy Corporation, a nonaffiliated company.
(b)          Operated by CSPCo.
(c)          Operated by The Dayton Power & Light Company, a nonaffiliated company.
(d)          Varying percentages of ownership.
(e)          Operated by PSO and also jointly-owned (54.7%) by TNC.
(f)          Operated by CLECO, a nonaffiliated company.
(g)          Operated by SWEPCo.
(h)
Turk Generating Plant is currently under construction with a projected commercial operation date of 2012.  SWEPCo jointly owns the plant with Arkansas Electric Cooperative Corporation (11.67%), East Texas Electric Cooperative (8.33%) and Oklahoma Municipal Power Authority (6.67%).  Through December 2010, construction costs totaling $279 million have been billed to the other owners.
N/A    Not Applicable

 
135
 
17.   COST REDUCTION INITIATIVES

In April 2010, we began initiatives to decrease both labor and non-labor expenses with a goal of achieving significant reductions in operation and maintenance expenses.  A total of 2,461 positions were eliminated across the AEP System as a result of process improvements, streamlined organizational designs and other efficiencies.  Most of the affected employees terminated employment May 31, 2010.  The severance program provides two weeks of base pay for every year of service along with other severance benefits.

We recorded a charge to expense in 2010 primarily related to the headcount reduction initiatives.  We do not expect additional costs to be incurred related to this initiative.

 
 
Total
 
 
 
(in millions)
 
Incurred
  $ 293  
Settled
    283  
Adjustments
    7  
Remaining Balance at December 31, 2010
  $ 17  

These costs relate primarily to severance benefits.  They are included primarily in Other Operation on the Consolidated Statements of Income and Other Current Liabilities on the Consolidated Balance Sheets.  Approximately 99% of the expense was within the Utility Operations segment.

 
136
 
18.   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 net income 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:

 
 
 
 
2010 Quarterly Periods Ended
 
 
 
 
 
March 31
 
June 30
 
September 30
 
December 31
 
 
 
 
 
(in millions - except per share amounts)
 
Total Revenues
$
 3,569 
 
$
 3,360 
 
$
 4,064 
 
$
 3,434 
 
Operating Income
 
 758 
 
 
 394 
(a)
 
 1,025 
 
 
 486 
(b)
Net Income
 
 346 
 
 
 137 
(a)
 
 557 
 
 
 178 
(b)
 
 
 
 
 
 
 
 
 
 
 
 
 
Amounts Attributable to AEP Common Shareholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income
 
 344 
 
 
 136 
(a)
 
 555 
 
 
 176 
(b)
 
 
 
 
 
 
 
 
 
 
 
 
 
Basic Earnings per Share Attributable to AEP
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Shareholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Earnings per Share (c)
 
 0.72 
 
 
 0.28 
 
 
 1.16 
 
 
 0.37 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Diluted Earnings per Share Attributable to AEP
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Shareholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Earnings per Share (c)
 
 0.72 
 
 
 0.28 
 
 
 1.16 
 
 
 0.37 
 

 
 
 
 
2009 Quarterly Periods Ended
 
 
 
 
 
March 31
 
June 30
 
September 30
 
December 31
 
 
 
 
 
(in millions - except per share amounts)
 
Total Revenues
$
 3,458 
 
$
 3,202 
 
$
 3,547 
 
$
 3,282 
 
Operating Income
 
 750 
 
 
 682 
 
 
 858 
 
 
 481 
 
Income Before Extraordinary Loss
 
 363 
 
 
 322 
 
 
 446 
 
 
 239 
 
Extraordinary Loss, Net of Tax
 
 - 
 
 
 (5)
(d)
 
 - 
 
 
 - 
 
Net Income
 
 363 
 
 
 317 
 
 
 446 
 
 
 239 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amounts Attributable to AEP Common Shareholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Before Extraordinary Loss
 
 360 
 
 
 321 
 
 
 443 
 
 
 238 
 
 
 
Extraordinary Loss, Net of Tax
 
 - 
 
 
 (5)
(d)
 
 - 
 
 
 - 
 
 
 
Net Income
 
 360 
 
 
 316 
 
 
 443 
 
 
 238 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Basic Earnings (Loss) per Share Attributable to AEP
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Shareholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Earnings per Share Before Extraordinary Loss (c)
 
 0.89 
 
 
 0.68 
 
 
 0.93 
 
 
 0.49 
 
 
 
Extraordinary Loss per Share
 
 - 
 
 
 (0.01)
 
 
 - 
 
 
 - 
 
 
 
Earnings per Share (c)
 
 0.89 
 
 
 0.67 
 
 
 0.93 
 
 
 0.49 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Diluted Earnings (Loss) per Share Attributable to AEP
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Shareholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Earnings per Share Before Extraordinary Loss (c)
 
 0.89 
 
 
 0.68 
 
 
 0.93 
 
 
 0.49 
 
 
 
Extraordinary Loss per Share
 
 - 
 
 
 (0.01)
 
 
 - 
 
 
 - 
 
 
 
Earnings per Share (c)
 
 0.89 
 
 
 0.67 
 
 
 0.93 
 
 
 0.49 
 

 
(a)
See Note 17 for discussion of expenses related to cost reduction initiatives recorded in the second quarter of 2010.
 
(b)
Includes a $43 million refund provision for the 2009 Significantly Excessive Earnings Test in addition to various other provisions for certain regulatory and legal matters.
 
(c)
Quarterly Earnings Per Share amounts are meant to be stand-alone calculations and are not always additive to full-year amount due to rounding.
 
(d)
See “SWEPCo Texas Restructuring” in “Extraordinary Item” section of Note 2 for discussion of the extraordinary loss recorded in the second quarter of 2009.

 
137
 
 

 








APPALACHIAN POWER COMPANY
AND SUBSIDIARIES

 
138
 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
SELECTED CONSOLIDATED FINANCIAL DATA
(in thousands)
 
 
 
 
 
2010 
 
2009 
 
2008 
 
2007 
 
2006 
STATEMENTS OF INCOME DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
 
$
 3,275,103 
 
$
 2,876,655 
 
$
 2,889,156 
 
$
 2,607,269 
 
$
 2,394,028 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating Income
 
$
 381,023 
 
$
 372,525 
 
$
 312,976 
 
$
 320,826 
 
$
 365,643 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Before Extraordinary Loss
 
$
 136,668 
 
$
 155,814 
 
$
 122,863 
 
$
 133,499 
 
$
 181,449 
Extraordinary Loss, Net of Tax
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (78,763)
(a)
 
 - 
Net Income
 
$
 136,668 
 
$
 155,814 
 
$
 122,863 
 
$
 54,736 
 
$
 181,449 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
BALANCE SHEETS DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and Equipment
 
$
 10,239,610 
 
$
 9,800,213 
 
$
 9,427,921 
 
$
 8,738,446 
 
$
 8,000,278 
Accumulated Depreciation and Amortization
 
 
 2,843,087 
 
 
 2,751,443 
 
 
 2,675,784 
 
 
 2,591,833 
 
 
 2,476,290 
Total Property, Plant and Equipment –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net
 
$
 7,396,523 
 
$
 7,048,770 
 
$
 6,752,137 
 
$
 6,146,613 
 
$
 5,523,988 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
 9,997,153 
 
$
 9,796,413 
 
$
 8,762,664 
 
$
 7,621,684 
 
$
 7,001,798 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Common Shareholder's Equity
 
$
 2,821,679 
 
$
 2,771,577 
 
$
 2,376,591 
 
$
 2,082,032 
 
$
 2,036,174 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cumulative Preferred Stock Not Subject to
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mandatory Redemption
 
$
 17,747 
 
$
 17,752 
 
$
 17,752 
 
$
 17,752 
 
$
 17,763 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt (b)
 
$
 3,561,141 
 
$
 3,477,306 
 
$
 3,174,512 
 
$
 2,847,299 
 
$
 2,598,664 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Obligations Under Capital Leases (b)
 
$
 32,731 
(c)
$
 7,484 
 
$
 9,313 
 
$
 11,101 
 
$
 11,859 

(a)
Reflects a change in Virginia law for the reestablishment of regulatory assets and liabilities related to generation and supply operations in accordance with the accounting guidance for “Regulated Operations.”
(b)
Includes portion due within one year.
(c)
Obligations Under Capital Leases increased primarily due to capital leases under new master lease agreements for property that was previously leased under operating leases.

 
139
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

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 957,000 retail customers in its service territory in southwestern Virginia and southern West Virginia.  APCo consolidates Cedar Coal Company, Central Appalachian Coal Company and Southern Appalachian Coal Company, its wholly-owned subsidiaries.  APCo sells power at wholesale to municipalities.

Originally approved by the FERC in 1951 and subsequently amended in 1951, 1962, 1975, 1979 (twice) and 1980, the Interconnection Agreement establishes the AEP Power Pool which permits the AEP East companies to pool their generation assets on a cost basis.  It establishes 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.  AEP Power Pool members are compensated for their costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool.  The capacity reserve relationship of the AEP Power Pool members changes as generating assets are added, retired or sold and relative peak demand changes.  The AEP Power Pool 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 determines each member’s percentage share of revenues and costs.

In December 2010, each member gave notice to AEPSC and the other AEP Power Pool members of its decision to terminate the Interconnection Agreement effective January 1, 2014 or such other date approved by the FERC, subject to state regulatory input.  It is unknown at this time whether the AEP Power Pool will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers or if each company will choose to operate independently.  This decision to terminate is subject to management’s ongoing evalution.  The AEP Power Pool members may revoke their notices of termination.  If APCo experiences decreases in revenues or increases in costs as a result of the termination of the AEP Power Pool and is unable to recover the change in revenues and costs through rates, prices or additional sales, it could have an adverse impact on future net income and cash flows.

The AEP East companies are parties to a Transmission Agreement defining how they share the costs associated with their relative ownership of transmission assets.  This sharing was based upon each company’s MLR until the FERC approved a new Transmission Agreement effective November 1, 2010.  The impacts of the new Transmission Agreement will be phased-in for retail rates, adds KGPCo and WPCo as parties to the agreement and changes the allocation method.

Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and 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.

AEPSC conducts power, gas, coal and emission allowance risk management activities on APCo’s behalf.  APCo shares in the revenues and expenses associated with these risk management activities, as described in the preceding paragraph, with the other AEP East companies, PSO and SWEPCo.  Power and gas risk management activities are allocated based on the existing power pool agreement and the SIA.  APCo shares in coal and emission 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 gas, coal and emission allowances.  The electricity, gas, coal and emission allowance 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.

 
140
 
To minimize the credit requirements and operating constraints when operating within PJM, the AEP East companies as well as KGPCo and WPCo, agreed to a netting of all payment obligations incurred by any of the AEP East companies against all balances due to the AEP East companies, and to hold PJM harmless from actions that any one or more AEP East companies may take with respect to PJM.

APCo is jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to purchase power and sale activity pursuant to the SIA.

Regulatory Activity

Virginia Regulatory Activity

In July 2010, the Virginia SCC issued an order approving a $62 million annual increase based on a 10.53% return on common equity.  The order denied recovery of the Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility, which resulted in a pretax write-off of approximately $54 million in the second quarter of 2010.  In addition, the order allowed the deferral of approximately $25 million of incremental storm expense incurred in 2009.  As a result, APCo recorded a pretax loss of $29 million in the second quarter of 2010.  See “2009 Virginia Base Rate Case” section of Note 4.

In June 2010, the Virginia SCC denied APCo’s request to include certain wind purchased power agreements (Beech Ridge and Grand Ridge) with a 20-year term in its Virginia renewable energy portfolio standard program.  As a result, APCo recorded an expense of $4 million in June 2010 to reduce the regulatory asset related to the Virginia portion of wind power costs to write off the difference between the actual Grand Ridge purchased power costs incurred from September 2009 through June 2010 and the estimated cost of non-wind power, which management believes is probable of recovery.  APCo’s future net income and cash flows will be reduced by the unrecoverable Virginia portion of the Beech Ridge and Grand Ridge costs until such time as the contracts are reassigned, renegotiated or terminated.

West Virginia Regulatory Activity

In December 2010, a settlement agreement was filed with the WVPSC to increase annual base rates by $54 million, effective March 2011.  The settlement agreement allows APCo to defer and amortize up to $18 million of previously expensed 2009 incremental storm expenses over a period of eight years.  A decision from the WVPSC is expected in March 2011.  See “2010 West Virginia Base Rate Case” section of Note 4.

In a proceeding established by the WVPSC to explore options to meet WPCo's future power supply requirements, the WVPSC, in November 2009, issued an order approving a joint stipulation among APCo, WPCo, the WVPSC staff and the Consumer Advocate Division.  The order approved the recommendation of the signatories to the stipulation that WPCo merge into APCo and be supplied from APCo's existing power resources.  Merger approvals from the WVPSC, Virginia SCC and the FERC are required.  No merger approval filings have been made.  See “WPCo Merger with APCo” section of Note 4.

Mountaineer Carbon Capture and Storage Product Validation Facility (PVF)

APCo and ALSTOM Power, Inc., an unrelated third party, jointly constructed a CO 2 capture validation facility, which was placed into service in September 2009.  APCo also constructed and owns the necessary facilities to store the CO 2 .  In APCo’s July 2009 Virginia base rate filing and May 2010 West Virginia base rate filing, APCo requested recovery of and a return on its Virginia and West Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion.  In July 2010, the Virginia SCC issued a base rate order that denied recovery of the Virginia share of the PVF costs, which resulted in a pretax write-off of approximately $54 million in the second quarter of 2010.  In December 2010, a settlement agreement was filed with the WVPSC to increase annual base rates by $60 million, effective March 2011.  A decision from the WVPSC is expected in March 2011.  As of December 31, 2010, APCo has recorded a noncurrent regulatory asset of $60 million related to the PVF.  If APCo cannot recover its remaining investments in and expenses related to the PVF, it would reduce future net income and cash flows and impact financial condition.  See “Mountaineer Carbon Capture and Storage Project” section of Note 4.

 
141
 
Carbon Capture and Sequestration Project with the Department of Energy (DOE)

During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale carbon capture and sequestration (CCS) facility under consideration at the Mountaineer Plant.  AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project.  The DOE will fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million.  A Front-End Engineering and Design (FEED) study, scheduled for completion during the third quarter of 2011, will refine the total cost estimate for the CCS facility.  Results from the FEED study will be evaluated by management before any decision is made to seek the necessary regulatory approvals to build the CCS facility.  As of December 31, 2010, APCo has incurred $14 million in total costs and has received $5 million of DOE funding resulting in a net $9 million balance included in Construction Work In Progress on the Consolidated Balance Sheets.  If APCo is unable to recover the costs of the CCS project, it would reduce future net income and cash flows.  See “Mountaineer Carbon Capture and Storage Project” section of Note 4.
 
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 state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be.  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 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 405 for additional discussion of relevant factors.

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
2010 
 
2009 
 
2008 
 
 
(in millions of KWH)
Retail:
 
 
 
 
 
 
 
 
 
Residential
 
 13,127 
 
 
 12,218 
 
 
 12,523 
 
Commercial
 
 7,208 
 
 
 6,974 
 
 
 7,057 
 
Industrial
 
 10,774 
 
 
 10,388 
 
 
 13,794 
 
Miscellaneous
 
 869 
 
 
 835 
 
 
 835 
Total Retail
 
 31,978 
 
 
 30,415 
 
 
 34,209 
 
 
 
 
 
 
 
 
 
Wholesale
 
 6,578 
 
 
 5,648 
 
 
 9,611 
 
 
 
 
 
 
 
 
 
Total KWHs
 
 38,556 
 
 
 36,063 
 
 
 43,820 

 
142
 
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,
 
 
 
2010 
 
2009 
 
2008 
 
 
 
(in degree days)
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 2,636 
 
 
 2,214 
 
 
 2,236 
 
Normal - Heating (b)
 
 2,272 
 
 
 2,288 
 
 
 2,288 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 1,530 
 
 
 1,053 
 
 
 1,116 
 
Normal - Cooling (b)
 
 1,170 
 
 
 1,176 
 
 
 1,175 
 
 
 
 
 
 
 
 
 
 
 
 
(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.

 
143
 
2010 Compared to 2009
 
 
 
 
 
Reconciliation of Year Ended December 31, 2009 to Year Ended December 31, 2010
 
Net Income
 
(in millions)
 
 
 
 
 
Year Ended December 31, 2009
  $ 156  
 
       
Changes in Gross Margin:
       
Retail Margins
    137  
Off-system Sales
    5  
Other Revenues
    15  
Total Change in Gross Margin
    157  
 
       
Total Expenses and Other:
       
Other Operation and Maintenance
    (99 )
Depreciation and Amortization
    (30 )
Taxes Other Than Income Taxes
    (19 )
Carrying Costs Income
    10  
Other Income
    (4 )
Interest Expense
    (5 )
Total Expenses and Other
    (147 )
 
       
Income Tax Expense
    (29 )
 
       
Year Ended December 31, 2010
  $ 137  

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 power were as follows:

·
Retail Margins increased $137 million primarily due to the following:
 
·
A $138 million increase in rate relief primarily due to an increase in the recovery of E&R costs in Virginia, costs related to the Transmission Rate Adjustment Clause in Virginia and construction financing costs in West Virginia.  This increase in Retail Margins had corresponding increases of $62 million related to riders/trackers recognized in other expense items.
 
·
A $49 million increase in residential usage primarily due to a 46% increase in cooling degree days.
 
These increases were partially offset by:
 
·
An $18 million decrease in industrial sales primarily due to the decreased load for APCo’s largest customer, Century Aluminum.
 
·
An $11 million decrease due to higher capacity settlement expenses under the Interconnection Agreement net of recovery in West Virginia and environmental deferrals in Virginia.
 
·
A $9 million decrease related to increased consumable and allowance expenses.
·
Margins from Off-system Sales increased $5 million primarily due to increased prices and higher physical sales volumes, partially offset by lower trading and marketing margins.
·
Other Revenues increased $15 million primarily due to increased gains on the sale of SO 2 allowances as a result of favorable market prices.

Total Expenses and Other and Income Tax Expense changed between years as follows:
 
·
Other Operation and Maintenance expenses increased $99 million primarily due to the following:
 
·
A $54 million increase due to expenses related to cost reduction initiatives.  In 2010, management conducted cost reduction initiatives to reduce both labor and non-labor expenses.
 
  · A $54 million increase due to the write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the Virginia SCC.  
 
 
144
 
 
·
A $33 million increase primarily due to the reduction of under-recovery of transmission costs resulting from the implementation of the Transmission Rate Adjustment Clause in Virginia in December 2009.  
 
·
A $7 million increase due to expenses related to the Mountaineer Carbon Capture and Storage Product Validation Facility.  
 
·
A $7 million increase in steam maintenance expenses primarily due to a planned outage at the Amos Plant.  
 
These increases were partially offset by:
 
 
·
A $49 million decrease in distribution expenses resulting from storm damage repairs in 2009.  
 
·   
A $25 million decrease due to the deferral of 2009 storm costs as allowed by the Virginia SCC in 2010.  
·
Depreciation and Amortization expenses increased $30 million primarily due to a greater depreciation base resulting from environmental upgrades at the Amos Plant and the amortization of carrying charges which are being collected through the Virginia E&R surcharges.
·
Taxes Other Than Income Taxes increased $19 million primarily due to recording a West Virginia franchise tax audit settlement, a favorable franchise tax return adjustment recorded in 2009 and additional employer payroll taxes incurred related to cost reduction initiatives.
·
Carrying Costs Income increased $10 million primarily due to environmental construction in Virginia.
·
Other Income decreased $4 million primarily due to a decrease in the equity component of AFUDC as a result of the completion of environmental projects.
·
Interest Expense increased $5 million primarily due to a decrease in the debt component of AFUDC as a result of the completion of environmental projects.
·
Income Tax Expense increased $29 million primarily due to the regulatory accounting treatment of state income taxes and other book/tax differences which are accounted for on a flow-through basis and an increase in pretax book income.
 
 
145
 
 
2009 Compared to 2008
 
 
 
 
 
Reconciliation of Year Ended December 31, 2008 to Year Ended December 31, 2009
 
Net Income
 
(in millions)
 
 
 
 
 
Year Ended December 31, 2008
  $ 123  
 
       
Changes in Gross Margin:
       
Retail Margins
    128  
Off-system Sales
    (27 )
Transmission Revenues
    2  
Other Revenues
    (2 )
Total Change in Gross Margin
    101  
 
       
Total Expenses and Other:
       
Other Operation and Maintenance
    (33 )
Depreciation and Amortization
    (17 )
Taxes Other Than Income Taxes
    9  
Carrying Costs Income
    (25 )
Other Income
    (7 )
Interest Expense
    7  
Total Expenses and Other
    (66 )
 
       
Income Tax Expense
    (2 )
 
       
Year Ended December 31, 2009
  $ 156  

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 power were as follows:

·
Retail Margins increased $128 million primarily due to the following:
 
·
A $144 million increase in rate relief primarily due to the impact of the Virginia base rate orders issued in October 2008 and December 2009 and increases in the recovery of construction financing costs in West Virginia.
 
·
A $53 million increase due to the December 2008 provision for refund of off-system sales margins as ordered by the FERC related to the SIA.
 
·
A $24 million increase due to new rates effective January 2009 for a power supply contract with KGPCo.
 
These increases were partially offset by:
 
·
A $62 million decrease due to higher capacity settlement expenses under the Interconnection Agreement net of recovery in West Virginia and environmental deferrals in Virginia.
 
·
A $25 million decrease in industrial sales primarily due to suspended operations by APCo’s largest customer, Century Aluminum.
·
Margins from Off-system Sales decreased $27 million primarily due to lower physical sales volumes and lower margins as a result of lower market prices, partially offset by higher trading and marketing margins.

Total 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 $49 million increase in distribution expenses resulting from storm damage repairs in 2009 and an increase in reliability spending.
 
·
A $15 million increase in steam maintenance expenses primarily due to a planned outage at the Amos Plant.
 
 
146
 
 
These increases were partially offset by:
 
 
·
A $26 million decrease related to the establishment of a regulatory asset in 2009 for the deferral of transmission costs.
 
·
A $7 million decrease in employee benefit expenses.
·
Depreciation and Amortization expenses increased $17 million primarily due to the following:
 
·
A $15 million increase in depreciation expense due to a greater depreciation base resulting from environmental upgrades at the Amos, Clinch River and Mountaineer Plants.
 
·
A $2 million increase in amortization of carrying charges and depreciation expense that are being collected through the Virginia E&R surcharges.
·
Taxes Other Than Income Taxes decreased $9 million primarily due to a favorable franchise tax return adjustment recorded in 2009.
·
Carrying Costs Income decreased $25 million due to completion of reliability deferrals in Virginia in December 2008 and a decrease of environmental construction deferrals in Virginia in 2009.
·
Other Income decreased $7 million primarily due to higher interest income related to a tax refund in 2008 and other tax adjustments.
·
Interest Expense decreased $7 million primarily due to a $24 million decrease in interest expense related to a refund on off-system sales margins in accordance with the FERC’s order related to the SIA in 2008.  This decrease was partially offset by a $20 million increase in interest expense due to increased long-term debt outstanding.
·
Income Tax Expense increased $2 million primarily due to an increase in pretax book income, partially offset by the regulatory accounting treatment of state income taxes and other book/tax differences which are accounted for on a flow-through basis.

FINANCIAL CONDITION

LIQUIDITY

APCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  APCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures.  See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 405 for additional discussion of liquidity.

Credit Ratings

APCo’s ultimate access to capital markets may depend on its credit ratings.  In addition, a credit rating downgrade of APCo by one of the rating agencies could increase APCo’s borrowing costs.  Failure to maintain investment grade ratings may constrain APCo’s ability to participate in the Utility Money Pool or the amount of APCo’s receivables securitized by AEP Credit.  Counterparty concerns about APCo’s credit quality could subject APCo to additional collateral demands under adequate assurance clauses under derivative and non-derivative energy contracts.

CASH FLOW

Cash flows for 2010, 2009 and 2008 were as follows:

 
 
Years Ended December 31,
 
 
 
2010
   
2009
   
2008
 
 
 
(in thousands)
 
Cash and Cash Equivalents at Beginning of Period
  $ 2,006     $ 1,996     $ 2,195  
Cash Flows from (Used for):
                       
Operating Activities
    655,564       (29,267 )     242,703  
Investing Activities
    (523,948 )     (529,958 )     (682,085 )
Financing Activities
    (132,671 )     559,235       439,183  
Net Increase (Decrease) in Cash and Cash Equivalents
    (1,055 )     10       (199 )
Cash and Cash Equivalents at End of Period
  $ 951     $ 2,006     $ 1,996  

 
147
 
Operating Activities

Net Cash Flows from Operating Activities were $656 million in 2010.  APCo produced Net Income of $137 million during the period and had noncash expense items of $304 million for Depreciation and Amortization and $144 million for Deferred Income Taxes, partially offset by $33 million in Carrying Costs Income.  APCo contributed $37 million to the qualified pension trust.  The other changes in assets and liabilities 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.  The activity in working capital relates to a number of items.  The $117 million inflow from Fuel, Materials and Supplies was primarily due to a reduction in fuel inventory and a decrease in the average cost of coal per ton.  The $77 million inflow from Accrued Taxes, Net was primarily due to the receipt of a 2010 income tax refund of $170 million related to a federal net income tax operating loss in 2009 that was carried back to 2007 and 2008.  Items contributing to the net income tax operating loss included bonus depreciation and the favorable impact of a change in tax accounting method related to units of property.  The $63 million outflow from Accounts Receivable, Net was primarily due to an increase in accrued unbilled revenues due to usual seasonal fluctuations and timing of settlements of receivables from affiliated companies.

Net Cash Flows Used for Operating Activities were $29 million in 2009.  APCo produced Net Income of $156 million during the period and had noncash expense items of $323 million for Deferred Income Taxes and $274 million for Depreciation and Amortization, partially offset by $23 million in Carrying Costs Income.  The $323 million inflow for Deferred Income Taxes was primarily due to the American Recovery and Reinvestment Act of 2009 extending bonus depreciation provisions, a change in tax accounting method and an increase in tax versus book temporary differences from operations.  The other changes in assets and liabilities 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.  The activity in working capital relates to a number of items.  The $221 million outflow from Fuel, Materials and Supplies was primarily due to an increase in coal inventory.  The $172 million outflow from Accrued Taxes, Net was primarily due to an increase in accrued tax benefits resulting from a net income tax operating loss in 2009.  The $41 million outflow from Accounts Payable was primarily due to APCo’s provision for revenue refund which was paid to the AEP West companies as part of a FERC order on the SIA.  The $194 million outflow from Fuel Over/Under-Recovery, Net was primarily due to a net under-recovery of fuel costs in both Virginia and West Virginia.

Net Cash Flows from Operating Activities were $243 million in 2008.  APCo produced Net Income of $123 million during the period and noncash expense items of $257 million for Depreciation and Amortization and $146 million for Deferred Income Taxes, partially offset by $48 million in Carrying Costs Income.  The other changes in assets and liabilities 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.  The activity in working capital relates to a number of items. The $138 million inflow from Accounts Payable included APCo’s provision for revenue refund of $77 million to be paid to the AEP West companies as part of the FERC’s recent order on the SIA.  The $190 million outflow in Fuel Over/Under-Recovery, Net resulted from a net under recovery of fuel cost in both Virginia and West Virginia.

Investing Activities

Net Cash Flows Used for Investing Activities in 2010, 2009 and 2008 primarily reflect construction expenditures of $534 million, $544 million and $697 million, respectively.  Construction expenditures were primarily for projects to improve service reliability for transmission and distribution, as well as environmental upgrades.  Environmental upgrades primarily include the installation of FGD equipment at the Amos Plant.

Financing Activities

Net Cash Flows Used for Financing Activities were $133 million in 2010.  APCo issued $300 million of Senior Unsecured Notes and $68 million of Pollution Control Bonds.  APCo retired $150 million of Senior Unsecured Notes, $100 million of Notes Payable – Affiliated and $50 million of Pollution Control Bonds.  APCo reduced short-term borrowings from the Utility Money Pool by $101 million and paid $88 million in dividends on common stock.

 
148
 
Net Cash Flows from Financing Activities were $559 million in 2009.  APCo issued $350 million of Senior Unsecured Notes and $104 million of Pollution Control Bonds.  APCo also received capital contributions from the Parent of $250 million.  These increases were partially offset by the retirement of $150 million of Senior Unsecured Notes.  In addition, APCo increased short-term borrowings from the Utility Money Pool by $35 million.

Net Cash Flows from Financing Activities were $439 million in 2008.  APCo issued $500 million of Senior Unsecured Notes and $245 million of Pollution Control Bonds.  APCo also received capital contributions from the Parent of $200 million.  These increases were partially offset by the retirement of $213 million of Pollution Control Bonds and $200 million of Senior Unsecured Notes.  In addition, APCo reduced short-term borrowings from the Utility Money Pool by $80 million.

In February 2011, APCo issued $65 million of 2% Pollution Control Bonds due in 2041 with a 2012 mandatory put date.

CONTRACTUAL OBLIGATION INFORMATION

APCo’s contractual cash obligations include amounts reported on APCo’s Consolidated Balance Sheets and other obligations disclosed in the footnotes.  The following table summarizes APCo’s contractual cash obligations at December 31, 2010:

 
Payments Due by Period
 
 
 
 
 
 
Less Than
 
 
 
 
 
After
 
 
 
Contractual Cash Obligations
 
1 year
 
2-3 years
 
4-5 years
 
5 years
 
Total
 
 
 
(in millions)
 
Advances from Affiliates (a)
 
$
 128.3 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 128.3 
 
Interest on Fixed Rate Portion of Long-term Debt (b)
 
 
 191.1 
 
 
 354.2 
 
 
 323.2 
 
 
 2,255.0 
 
 
 3,123.5 
 
Fixed Rate Portion of Long-term Debt (c)
 
 
 250.0 
 
 
 320.0 
 
 
 500.1 
 
 
 2,269.3 
 
 
 3,339.4 
 
Variable Rate Portion of Long-term Debt (d)
 
 
 229.7 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 229.7 
 
Capital Lease Obligations (e)
 
 
 9.5 
 
 
 14.5 
 
 
 6.5 
 
 
 6.9 
 
 
 37.4 
 
Noncancelable Operating Leases (e)
 
 
 14.3 
 
 
 21.5 
 
 
 17.6 
 
 
 58.0 
 
 
 111.4 
 
Fuel Purchase Contracts (f)
 
 
 541.7 
 
 
 790.8 
 
 
 487.5 
 
 
 419.7 
 
 
 2,239.7 
 
Energy and Capacity Purchase Contracts (g)
 
 
 16.4 
 
 
 27.3 
 
 
 27.0 
 
 
 186.4 
 
 
 257.1 
 
Construction Contracts for Capital Assets (h)
 
 
 94.7 
 
 
 197.2 
 
 
 221.0 
 
 
 289.1 
 
 
 802.0 
 
Total
 
$
 1,475.7 
 
$
 1,725.5 
 
$
 1,582.9 
 
$
 5,484.4 
 
$
 10,268.5 

(a)
Represents short-term borrowings from the Utility Money Pool.
(b)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2010 and do not reflect anticipated future refinancings, 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 0.29% and 0.37% at December 31, 2010.
(e)
See Note 13.
(f)
Represents contractual obligations to purchase coal and other consumables as fuel for electric generation along with related transportation of the fuel.
(g)
Represents contractual obligations for energy and capacity purchase contracts.
(h)
Represents only capital assets for which APCo has 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.

APCo’s $14 million liability related to uncertainty in Income Taxes is not included above because management cannot reasonably estimate the cash flows by period.

 
149
 
APCo’s pension funding requirements are not included in the above table.  As of December 31, 2010, management expects to make contributions to the pension plans totaling $14.7 million in 2011.  Estimated contributions of $24.1 million in 2012 and $21.3 million in 2013 may vary significantly based on market returns, changes in actuarial assumptions and other factors.  Based upon the benefit obligation and fair value of assets available to pay pension benefits, APCo’s pension plan obligation was 78.6% funded as of December 31, 2010.

In addition to the amounts disclosed in the contractual cash obligations table above, APCo makes additional commitments in the normal course of business.  APCo’s commitments outstanding at December 31, 2010 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)
 
$
 232.3 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 232.3 

(a)
APCo enters into standby letters of credit (LOCs) with third parties.  These LOCs cover items such as insurance programs, security deposits, debt service reserves and variable rate Pollution Control Bonds.  All of these LOCs were issued in APCo’s ordinary course of business.  There is no collateral held in relation to any guarantees in excess of APCo's ownership percentages.  In the event any LOC is drawn, there is no recourse to third parties.  The maximum future payments of these LOCs are $232.3 million with maturities ranging from March 2011 to April 2011.  See “Letters of Credit” section of Note 6.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 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 “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 for a discussion of the adoption and impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

See “Quantitative And Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 for a discussion of risk management activities.

 
150
 
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
To the Board of Directors and Shareholders of
Appalachian Power Company:
 
 
We have audited the accompanying consolidated balance sheets of Appalachian Power Company and subsidiaries (the "Company") as of December 31, 2010 and 2009, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010.  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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
 
 
/s/ Deloitte & Touche LLP
 
 
Columbus, Ohio
February 25, 2011
 

 
151
 

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, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment, APCo’s internal control over financial reporting was effective as of December 31, 2010.

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.

 
152
 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF INCOME
 
For the Years Ended December 31, 2010, 2009 and 2008
 
(in thousands)
 
 
 
 
 
2010
   
2009
   
2008
 
REVENUES
 
 
   
 
   
 
 
Electric Generation, Transmission and Distribution
  $ 2,950,183     $ 2,604,494     $ 2,542,222  
Sales to AEP Affiliates
    316,207       263,389       328,735  
Other Revenues
    8,713       8,772       18,199  
TOTAL REVENUES
    3,275,103       2,876,655       2,889,156  
 
                       
EXPENSES
                       
Fuel and Other Consumables Used for Electric Generation
    663,422       547,266       710,115  
Purchased Electricity for Resale
    257,349       246,742       215,413  
Purchased Electricity from AEP Affiliates
    917,616       803,116       785,191  
Other Operation
    429,107       266,763       297,818  
Maintenance
    211,486       274,543       209,766  
Depreciation and Amortization
    304,192       273,506       256,626  
Taxes Other Than Income Taxes
    110,908       92,194       101,251  
TOTAL EXPENSES
    2,894,080       2,504,130       2,576,180  
 
                       
OPERATING INCOME
    381,023       372,525       312,976  
 
                       
Other Income (Expense):
                       
Interest Income
    1,477       1,403       6,371  
Carrying Costs Income
    33,080       22,761       48,249  
Allowance for Equity Funds Used During Construction
    2,967       7,000       8,938  
Interest Expense
    (207,649 )     (202,426 )     (209,733 )
 
                       
INCOME BEFORE INCOME TAX EXPENSE
    210,898       201,263       166,801  
 
                       
Income Tax Expense
    74,230       45,449       43,938  
 
                       
NET INCOME
    136,668       155,814       122,863  
 
                       
Preferred Stock Dividend Requirements Including Capital Stock Expense
    900       900       942  
 
                       
EARNINGS ATTRIBUTABLE TO COMMON STOCK
  $ 135,768     $ 154,914     $ 121,921  
 
 
The common stock of APCo is wholly-owned by AEP.
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 

 
153
 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2010, 2009 and 2008
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
 
 
 
Stock
 
Capital
 
Earnings
 
Income (Loss)
 
Total
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2007
 
$
 260,458 
 
$
 1,025,149 
 
$
 831,612 
 
$
 (35,187)
 
$
 2,082,032 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Adoption of Guidance for Split-Dollar Life Insurance
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accounting, Net of Tax of $1,175
 
 
 
 
 
 
 
 
 (2,181)
 
 
 
 
 
 (2,181)
Adoption of Guidance for Fair Value Accounting,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $154
 
 
 
 
 
 
 
 
 (286)
 
 
 
 
 
 (286)
Capital Contribution from Parent
 
 
 
 
 
 200,000 
 
 
 
 
 
 
 
 
 200,000 
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (799)
 
 
 
 
 
 (799)
Capital Stock Expense
 
 
 
 
 
 143 
 
 
 (143)
 
 
 
 
 
 - 
SUBTOTAL – COMMON SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 2,278,766 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $297
 
 
 
 
 
 
 
 
 
 
 
 552 
 
 
 552 
 
 
Amortization of Pension and OPEB Deferred Costs,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $1,794
 
 
 
 
 
 
 
 
 
 
 
 3,333 
 
 
 3,333 
 
 
Pension and OPEB Funded Status, Net of Tax of $15,574
 
 
 
 
 
 
 
 
 
 
 
 (28,923)
 
 
 (28,923)
NET INCOME
 
 
 
 
 
 
 
 
 122,863 
 
 
 
 
 
 122,863 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 97,825 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2008
 
 
 260,458 
 
 
 1,225,292 
 
 
 951,066 
 
 
 (60,225)
 
 
 2,376,591 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital Contribution from Parent
 
 
 
 
 
 250,000 
 
 
 
 
 
 
 
 
 250,000 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (20,000)
 
 
 
 
 
 (20,000)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (799)
 
 
 
 
 
 (799)
Capital Stock Expense
 
 
 
 
 
 101 
 
 
 (101)
 
 
 
 
 
 - 
SUBTOTAL – COMMON SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 2,605,792 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $970
 
 
 
 
 
 
 
 
 
 
 
 (1,801)
 
 
 (1,801)
 
 
Amortization of Pension and OPEB Deferred Costs,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $2,642
 
 
 
 
 
 
 
 
 
 
 
 4,907 
 
 
 4,907 
 
 
Pension and OPEB Funded Status, Net of Tax of $3,697
 
 
 
 
 
 
 
 
 
 
 
 6,865 
 
 
 6,865 
NET INCOME
 
 
 
 
 
 
 
 
 155,814 
 
 
 
 
 
 155,814 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 165,785 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2009
 
 
 260,458 
 
 
 1,475,393 
 
 
 1,085,980 
 
 
 (50,254)
 
 
 2,771,577 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (88,000)
 
 
 
 
 
 (88,000)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (799)
 
 
 
 
 
 (799)
Capital Stock Expense
 
 
 
 
 
 103 
 
 
 (101)
 
 
 
 
 
 2 
SUBTOTAL – COMMON SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 2,682,780 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $3,843
 
 
 
 
 
 
 
 
 
 
 
 7,137 
 
 
 7,137 
 
 
Amortization of Pension and OPEB Deferred Costs,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $2,247
 
 
 
 
 
 
 
 
 
 
 
 4,172 
 
 
 4,172 
 
 
Pension and OPEB Funded Status, Net of Tax of $4,888
 
 
 
 
 
 
 
 
 
 
 
 (9,078)
 
 
 (9,078)
NET INCOME
 
 
 
 
 
 
 
 
 136,668 
 
 
 
 
 
 136,668 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 138,899 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2010
 
$
 260,458 
 
$
 1,475,496 
 
$
 1,133,748 
 
$
 (48,023)
 
$
 2,821,679 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.

 
154
 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
 
ASSETS
 
December 31, 2010 and 2009
 
(in thousands)
 
 
 
 
 
2010
   
2009
 
CURRENT ASSETS
 
 
   
 
 
Cash and Cash Equivalents
  $ 951     $ 2,006  
Accounts Receivable:
               
Customers
    166,878       150,285  
Affiliated Companies
    145,972       135,686  
Accrued Unbilled Revenues
    108,210       68,971  
Miscellaneous
    3,090       6,690  
Allowance for Uncollectible Accounts
    (6,667 )     (5,408 )
Total Accounts Receivable
    417,483       356,224  
Fuel
    230,697       343,261  
Materials and Supplies
    89,370       88,575  
Risk Management Assets
    53,242       67,956  
Accrued Tax Benefits
    104,435       180,708  
Regulatory Asset for Under-Recovered Fuel Costs
    18,300       78,685  
Prepayments and Other Current Assets
    35,811       36,293  
TOTAL CURRENT ASSETS
    950,289       1,153,708  
 
               
PROPERTY, PLANT AND EQUIPMENT
               
Electric:
               
Generation
    4,736,150       4,284,361  
Transmission
    1,852,415       1,813,777  
Distribution
    2,740,752       2,642,479  
Other Property, Plant and Equipment
    348,013       329,497  
Construction Work in Progress
    562,280       730,099  
Total Property, Plant and Equipment
    10,239,610       9,800,213  
Accumulated Depreciation and Amortization
    2,843,087       2,751,443  
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    7,396,523       7,048,770  
 
               
OTHER NONCURRENT ASSETS
               
Regulatory Assets
    1,486,625       1,433,791  
Long-term Risk Management Assets
    38,420       47,141  
Deferred Charges and Other Noncurrent Assets
    125,296       113,003  
TOTAL OTHER NONCURRENT ASSETS
    1,650,341       1,593,935  
 
               
TOTAL ASSETS
  $ 9,997,153     $ 9,796,413  
 
               
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 
 
 
155
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
December 31, 2010 and 2009
 
 
 
 
 
2010
   
2009
 
 
 
(in thousands)
 
CURRENT LIABILITIES
 
 
   
 
 
Advances from Affiliates
  $ 128,331     $ 229,546  
Accounts Payable:
               
General
    223,144       291,240  
Affiliated Companies
    166,884       157,640  
Long-term Debt Due Within One Year – Nonaffiliated
    479,672       200,019  
Long-term Debt Due Within One Year – Affiliated
    -       100,000  
Risk Management Liabilities
    27,993       25,792  
Customer Deposits
    58,451       57,578  
Deferred Income Taxes
    44,180       68,706  
Accrued Taxes
    75,619       65,241  
Accrued Interest
    57,871       58,962  
Other Current Liabilities
    93,286       95,292  
TOTAL CURRENT LIABILITIES
    1,355,431       1,350,016  
 
               
NONCURRENT LIABILITIES
               
Long-term Debt – Nonaffiliated
    3,081,469       3,177,287  
Long-term Risk Management Liabilities
    10,873       20,364  
Deferred Income Taxes
    1,642,072       1,439,884  
Regulatory Liabilities and Deferred Investment Tax Credits
    562,381       526,546  
Employee Benefits and Pension Obligations
    306,460       312,873  
Deferred Credits and Other Noncurrent Liabilities
    199,041       180,114  
TOTAL NONCURRENT LIABILITIES
    5,802,296       5,657,068  
 
               
TOTAL LIABILITIES
    7,157,727       7,007,084  
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
    17,747       17,752  
 
               
Rate Matters (Note 4)
               
Commitments and Contingencies (Note 6)
               
 
               
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
    1,475,496       1,475,393  
Retained Earnings
    1,133,748       1,085,980  
Accumulated Other Comprehensive Income (Loss)
    (48,023 )     (50,254 )
TOTAL COMMON SHAREHOLDER’S EQUITY
    2,821,679       2,771,577  
 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
  $ 9,997,153     $ 9,796,413  
 
               
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 

 
156
 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
For the Years Ended December 31, 2010, 2009 and 2008
 
(in thousands)
 
 
 
 
 
2010
   
2009
   
2008
 
OPERATING ACTIVITIES
 
 
   
 
   
 
 
Net Income
  $ 136,668     $ 155,814     $ 122,863  
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for)
                       
Operating Activities:
                       
Depreciation and Amortization
    304,192       273,506       256,626  
Deferred Income Taxes
    144,413       322,626       145,594  
Carrying Costs Income
    (33,080 )     (22,761 )     (48,249 )
Allowance for Equity Funds Used During Construction
    (2,967 )     (7,000 )     (8,938 )
Mark-to-Market of Risk Management Contracts
    29,182       (15,346 )     (20,555 )
Pension Contributions to Qualified Plan Trust
    (36,784 )     -       -  
Fuel Over/Under-Recovery, Net
    (13,356 )     (194,436 )     (189,543 )
Change in Regulatory Assets
    38,475       (84,159 )     (73,602 )
Change in Other Noncurrent Assets
    (15,668 )     (2,926 )     (12,020 )
Change in Other Noncurrent Liabilities
    1,757       3,895       (7,335 )
Changes in Certain Components of Working Capital:
                       
Accounts Receivable, Net
    (63,426 )     (14,489 )     (19,058 )
Fuel, Materials and Supplies
    116,530       (221,280 )     (43,748 )
Accounts Payable
    (16,823 )     (41,370 )     137,704  
Accrued Taxes, Net
    76,881       (172,126 )     (5,496 )
Other Current Assets
    1,287       (3,608 )     (18,984 )
Other Current Liabilities
    (11,717 )     (5,607 )     27,444  
Net Cash Flows from (Used for) Operating Activities
    655,564       (29,267 )     242,703  
 
                       
INVESTING ACTIVITIES
                       
Construction Expenditures
    (534,334 )     (543,587 )     (696,767 )
Change in Other Cash Deposits
    1,964       235       (674 )
Acquisitions of Assets
    (2,485 )     (1,116 )     (1,685 )
Proceeds from Sales of Assets
    4,738       14,510       17,041  
Other Investing Activities
    6,169       -       -  
Net Cash Flows Used for Investing Activities
    (523,948 )     (529,958 )     (682,085 )
 
                       
FINANCING ACTIVITIES
                       
Capital Contribution from Parent
    -       250,000       200,000  
Issuance of Long-term Debt – Nonaffiliated
    363,726       447,883       735,799  
Change in Advances from Affiliates, Net
    (101,215 )     34,658       (80,369 )
Retirement of Long-term Debt – Nonaffiliated
    (200,019 )     (150,017 )     (412,789 )
Retirement of Long-term Debt – Affiliated
    (100,000 )     -       -  
Retirement of Cumulative Preferred Stock
    (4 )     -       -  
Principal Payments for Capital Lease Obligations
    (7,001 )     (3,479 )     (3,922 )
Dividends Paid on Common Stock
    (88,000 )     (20,000 )     -  
Dividends Paid on Cumulative Preferred Stock
    (799 )     (799 )     (799 )
Other Financing Activities
    641       989       1,263  
Net Cash Flows from (Used for) Financing Activities
    (132,671 )     559,235       439,183  
 
                       
Net Increase (Decrease) in Cash and Cash Equivalents
    (1,055 )     10       (199 )
Cash and Cash Equivalents at Beginning of Period
    2,006       1,996       2,195  
Cash and Cash Equivalents at End of Period
  $ 951     $ 2,006     $ 1,996  
 
                       
SUPPLEMENTARY INFORMATION
                       
Cash Paid for Interest, Net of Capitalized Amounts
  $ 202,884     $ 209,806     $ 177,531  
Net Cash Paid (Received) for Income Taxes
    (153,205 )     (81,508 )     (72,973 )
Noncash Acquisitions Under Capital Leases
    22,772       2,572       3,242  
Government Grants Included in Accounts Receivable at December 31,
    1,049       -       -  
Construction Expenditures Included in Accounts Payable at December 31,
    66,048       108,077       185,469  
SIA Refund Included in Accounts Payable at December 31,
    -       -       77,139  
 
                       
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
         

 
157
 
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to APCo’s consolidated 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 246.

 
Footnote
Reference
   
Organization and Summary of Significant Accounting Policies
Note 1
New Accounting Pronouncements and Extraordinary Item
Note 2
Rate Matters
Note 4
Effects of Regulation
Note 5
Commitments, Guarantees and Contingencies
Note 6
Benefit Plans
Note 8
Business Segments
Note 9
Derivatives and Hedging
Note 10
Fair Value Measurements
Note 11
Income Taxes
Note 12
Leases
Note 13
Financing Activities
Note 14
Related Party Transactions
Note 15
Property, Plant and Equipment
Note 16
Cost Reduction Initiatives
Note 17
Unaudited Quarterly Financial Information
Note 18

 
158
 










COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES


 
159
 
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Company Overview

As a public utility, CSPCo engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 749,000 retail customers in central and southern Ohio.  CSPCo consolidates Conesville Coal Preparation Company, its wholly-owned subsidiary.  Effective May 2009, Colomet, Inc. merged into CSPCo.  Effective September 2008, Simco, Inc. merged into Conesville Coal Preparation Company.

In October 2010, CSPCo and OPCo filed with the PUCO to merge CSPCo into OPCo.  Approval of the merger will not affect CSPCo's and OPCo's rates until the PUCO approves new rates, terms and conditions for the merged company.  In January 2011, CSPCo and OPCo filed with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo effective October 2011.

Originally approved by the FERC in 1951 and subsequently amended in 1951, 1962, 1975, 1979 (twice) and 1980, the Interconnection Agreement establishes the AEP Power Pool which permits the AEP East companies to pool their generation assets on a cost basis.  It establishes 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.  AEP Power Pool members are compensated for their costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool.  The capacity reserve relationship of the AEP Power Pool members changes as generating assets are added, retired or sold and relative peak demand changes.  The AEP Power Pool 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 determines each member’s percentage share of revenues and costs.

In December 2010, each member gave notice to AEPSC and the other AEP Power Pool members of its decision to terminate the Interconnection Agreement effective January 1, 2014 or such other date approved by the FERC, subject to state regulatory input.  It is unknown at this time whether the AEP Power Pool will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers or if each company will choose to operate independently.  This decision to terminate is subject to management’s ongoing evaluation.  The AEP Power Pool members may revoke their notices of termination.  If CSPCo experiences decreases in revenues or increases in costs as a result of the termination of the AEP Power Pool and is unable to recover the change in revenues and costs through rates, prices or additional sales, it could have an adverse impact on future net income and cash flows.

The AEP East companies are parties to a Transmission Agreement defining how they share the costs associated with their relative ownership of transmission assets.  This sharing was based upon each company’s MLR until the FERC approved a new Transmission Agreement effective November 1, 2010.  The impacts of the new Transmission Agreement will be phased-in for retail rates, adds KGPCo and WPCo as parties to the agreement and changes the allocation method.

In March 2007, CSPCo 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.  CSPCo pays AEGCo for the capacity, depreciation, fuel, operation and maintenance and tax expenses.  These payments are due regardless of whether the plant operates.

Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and 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.

 
160
 
AEPSC conducts power, gas, coal and emission allowance risk management activities on CSPCo’s behalf.  CSPCo shares in the revenues and expenses associated with these risk management activities, as described in the preceding paragraph, with the other AEP East companies, PSO and SWEPCo.  Power and gas risk management activities are allocated based on the existing power pool agreement and the SIA.  CSPCo shares in coal and emission 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 gas, coal and emission allowances.  The electricity, gas, coal and emission allowance 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.

To minimize the credit requirements and operating constraints when operating within PJM, the AEP East companies as well as KGPCo and WPCo, agreed to a netting of all payment obligations incurred by any of the AEP East companies against all balances due to the AEP East companies, and to hold PJM harmless from actions that any one or more AEP East companies may take with respect to PJM.

CSPCo is jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to purchase power and sale activity pursuant to the SIA.

Ohio Customer Choice

In CSPCo’s service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service.  As of December 31, 2010, approximately 5,000 CSPCo retail customers have switched from CSPCo to alternative CRES providers.  As a result, in comparison to 2009, CSPCo lost approximately $16 million of generation related gross margin in 2010.  Management currently forecasts incremental lost margins of approximately $53 million for 2011.  Management anticipates recovery of a portion of this lost margin through off-system sales.

Regulatory Activity

2009 – 2011 ESP

During 2009, the PUCO issued an order that modified and approved CSPCo’s ESP which established rates through 2011.  The order also limited annual rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011.  The order provided a FAC for the three-year period of the ESP.  Several notices of appeal are outstanding at the Supreme Court of Ohio relating to significant issues in the determination of the approved ESP rates.  In January 2011, the PUCO issued an order that determined that relevant CSPCo 2009 earnings were significantly excessive.  As a result, the PUCO ordered CSPCo to refund $43 million of its earnings to customers, which was recorded as a revenue provision on CSPCo’s December 2010 books.  See “Ohio Electric Security Plan Filings” section of Note 4.

Proposed January 2012 – May 2014 ESP

In January 2011, CSPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  The SSO presents redesigned generation rates by customer class.  Customer class rates individually vary, but on average, customers will experience net base generation increases of 1.4% in 2012 and 2.7% for the period January 2013 through May 2014.  See “Ohio Electric Security Plan Filings” section of Note 4.

Litigation and Environmental Issues

In the ordinary course of business, CSPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be.  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 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

 
161
 
See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 405 for additional discussion of relevant factors.

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
2010 
 
2009 
 
2008 
 
 
(in millions of KWH)
Retail:
 
 
 
 
 
 
 
 
 
Residential
 
 7,804 
 
 
 7,303 
 
 
 7,551 
 
Commercial
 
 8,709 
 
 
 8,532 
 
 
 8,772 
 
Industrial
 
 4,666 
 
 
 4,784 
 
 
 5,828 
 
Miscellaneous
 
 56 
 
 
 54 
 
 
 55 
Total Retail
 
 21,235 
 
 
 20,673 
 
 
 22,206 
 
 
 
 
 
 
 
 
 
Wholesale
 
 2,950 
 
 
 2,822 
 
 
 5,463 
 
 
 
 
 
 
 
 
 
Total KWHs
 
 24,185 
 
 
 23,495 
 
 
 27,669 

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,
 
 
 
2010 
 
2009 
 
2008 
 
 
 
(in degree days)
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 3,295 
 
 
 3,040 
 
 
 3,157 
 
Normal - Heating (b)
 
 3,036 
 
 
 3,054 
 
 
 3,187 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 1,317 
 
 
 854 
 
 
 1,056 
 
Normal - Cooling (b)
 
 1,029 
 
 
 1,037 
 
 
 999 
 
 
 
 
 
 
 
 
 
 
 
 
(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.

 
162
 
2010 Compared to 2009
 
 
 
 
 
Reconciliation of Year Ended December 31, 2010 to Year Ended December 31, 2009
 
Net Income
 
(in millions)
 
 
 
 
 
Year Ended December 31, 2009
  $ 272  
 
       
Changes in Gross Margin:
       
Retail Margins
    (20 )
Off-system Sales
    22  
Other Revenues
    4  
Total Change in Gross Margin
    6  
 
       
Total Expenses and Other:
       
Other Operation and Maintenance
    (41 )
Depreciation and Amortization
    (7 )
Taxes Other Than Income Taxes
    (12 )
Other Income
    (2 )
Interest Expense
    2  
Total Expenses and Other
    (60 )
 
       
Income Tax Expense
    12  
 
       
Year Ended December 31, 2010
  $ 230  

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 power were as follows:

·
Retail Margins decreased $20 million due to:
 
·
A $43 million decrease due to a refund provision for the 2009 Significantly Excessive Earnings Test (SEET).
 
·
A $23 million decrease in capacity settlements under the Interconnection Agreement.
 
·
A $16 million decrease as a result of the expiration of the City of Westerville contract as a dedicated customer for CSPCo at the end of 2009.  A new contract was entered into with Westerville on January 1, 2010 which is partially included in Off-system Sales as margins are shared by the members of the AEP Power Pool.
 
·
A $14 million decrease as a result of the elimination of Restructuring Transition Charge (RTC) revenues with the implementation of CSPCo’s ESP.
 
These decreases were partially offset by:
 
·
A $45 million increase in residential and commercial revenue from weather-related usage primarily due to a 54% increase in cooling degree days.
 
·
A $26 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Energy Efficiency & Peak Demand Reduction (EE/PDR) Programs.  This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
 
·
A $5 million increase related to the implementation of higher rates set by the Ohio ESP.
·
Margins from Off-system Sales increased $22 million primarily due to increased prices and higher physical sales volumes, partially offset by lower trading and marketing margins.

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

·
Other Operation and Maintenance expenses increased $41 million primarily due to:
 
·
A $31 million increase due to expenses incurred related to cost reduction initiatives.  In 2010, management conducted cost reduction initiatives to reduce both labor and non-labor expenses.
 
 
 
163
 
 
·
A $26 million increase in expenses due to the implementation of PUCO approved EE/PDR programs.  This increase in Other Operation and Maintenance expenses was offset by a corresponding increase in Retail Margins as discussed above.
 
 
·
A $13 million increase in recoverable customer account expenses due to increased Universal Service Fund surcharge rates for customers who qualify for payment assistance.
 
 
These increases were partially offset by:
 
 
·
An $8 million decrease related to a 2009 obligation to contribute to the “Partnership with Ohio” fund for low income, at-risk customers ordered by the PUCO’s approval of CSPCo’s ESP.
 
 
·
A $7 million decrease in steam plant removal expenses and a $3 million decrease in maintenance of electric plant expenses primarily related to work performed at the Conesville Plant in 2009.
 
 
·
A $7 million decrease in boiler plant maintenance expenses primarily related to work performed at the Conesville and Zimmer Plants in 2009.
 
 
·
A $3 million decrease in overhead distribution line expenses primarily due to ice and wind storms in the first quarter of 2009, partially offset by increased vegetation management activities.
 
·
Depreciation and Amortization increased $7 million primarily due to environmental projects at the Conesville Plant that were completed and placed in service in November 2009.
·
Taxes Other Than Income Taxes increased $12 million primarily due to a $9 million increase in property taxes as a result of increased property values.
·
Income Tax Expense decreased $12 million primarily due to a decrease in pretax book income, changes in certain book/tax differences accounted for on a flow-through basis and a tax loss benefit from Parent, which was partially offset by federal income tax adjustments.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 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 “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 for a discussion of the adoption and impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

See “Quantitative And Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 for a discussion of risk management activities.

 
164
 
 
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
To the Board of Directors and Shareholder of
Columbus Southern Power Company:
 
 
We have audited the accompanying consolidated balance sheets of Columbus Southern Power Company and subsidiaries (the "Company") as of December 31, 2010 and 2009, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010.  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 Columbus Southern Power Company   and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
 
 
/s/ Deloitte & Touche LLP
 
 
Columbus, Ohio
February 25, 2011
 
 

 
 

 

 
165
 

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Columbus Southern Power Company and subsidiaries (CSPCo) 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. CSPCo’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 CSPCo’s internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment, CSPCo’s internal control over financial reporting was effective as of December 31, 2010.

This annual report does not include an attestation report of CSPCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit CSPCo to provide only management’s report in this annual report.

 
166
 

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF INCOME
 
For the Years Ended December 31, 2010, 2009 and 2008
 
(in thousands)
 
 
 
 
 
2010
   
2009
   
2008
 
REVENUES
 
 
   
 
   
 
 
Electric Generation, Transmission and Distribution
  $ 2,063,255     $ 1,934,338     $ 2,079,610  
Sales to AEP Affiliates
    82,994       67,213       122,949  
Other Revenues
    2,792       3,022       5,542  
TOTAL REVENUES
    2,149,041       2,004,573       2,208,101  
 
                       
EXPENSES
                       
Fuel and Other Consumables Used for Electric Generation
    399,886       298,198       360,792  
Purchased Electricity for Resale
    106,114       85,262       197,943  
Purchased Electricity from AEP Affiliates
    409,097       392,761       413,518  
Other Operation
    350,047       290,632       348,051  
Maintenance
    108,389       126,441       109,335  
Depreciation and Amortization
    151,440       144,402       186,746  
Taxes Other Than Income Taxes
    187,260       175,151       168,028  
TOTAL EXPENSES
    1,712,233       1,512,847       1,784,413  
 
                       
OPERATING INCOME
    436,808       491,726       423,688  
 
                       
Other Income (Expense):
                       
Interest Income
    919       802       5,334  
Carrying Costs Income
    8,166       7,656       6,551  
Allowance for Equity Funds Used During Construction
    2,072       3,382       3,364  
Interest Expense
    (85,893 )     (88,184 )     (92,068 )
 
                       
INCOME BEFORE INCOME TAX EXPENSE
    362,072       415,382       346,869  
 
                       
Income Tax Expense
    131,849       143,721       109,739  
 
                       
NET INCOME
    230,223       271,661       237,130  
 
                       
Capital Stock Expense
    149       157       157  
 
                       
EARNINGS ATTRIBUTABLE TO COMMON STOCK
  $ 230,074     $ 271,504     $ 236,973  
 
                       
The common stock of CSPCo is wholly-owned by AEP.
                       
 
                       
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 

 
167
 

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2010, 2009 and 2008
(in thousands)
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
 
 
 
 
Stock
 
Capital
 
Earnings
 
Income (Loss)
 
 
Total
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2007
 
$
 41,026 
 
$
 580,349 
 
$
 561,696 
 
$
 (18,794)
 
$
 1,164,277 
Adoption of Guidance for Split-Dollar Life Insurance
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accounting, Net of Tax of $589
 
 
 
 
 
 
 
 
 (1,095)
 
 
 
 
 
 (1,095)
Adoption of Guidance for Fair Value Accounting,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $170
 
 
 
 
 
 
 
 
 (316)
 
 
 
 
 
 (316)
Common Stock Dividends
 
 
 
 
 
 
 
 
 (122,500)
 
 
 
 
 
 (122,500)
Capital Stock Expense
 
 
 
 
 
 157 
 
 
 (157)
 
 
 
 
 
 - 
SUBTOTAL – COMMON SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,040,366 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $1,174
 
 
 
 
 
 
 
 
 
 
 
 2,181 
 
 
 2,181 
 
 
Amortization of Pension and OPEB Deferred
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Costs, Net of Tax of $607
 
 
 
 
 
 
 
 
 
 
 
 1,128 
 
 
 1,128 
 
 
Pension and OPEB Funded Status, Net of Tax of $19,137
 
 
 
 
 
 
 
 
 
 
 
 (35,540)
 
 
 (35,540)
NET INCOME
 
 
 
 
 
 
 
 
 237,130 
 
 
 
 
 
 237,130 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 204,899 
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2008
 
 
 41,026 
 
 
 580,506 
 
 
 674,758 
 
 
 (51,025)
 
 
 1,245,265 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (150,000)
 
 
 
 
 
 (150,000)
Capital Stock Expense
 
 
 
 
 
 157 
 
 
 (157)
 
 
 
 
 
 - 
Noncash Dividend of Property to Parent
 
 
 
 
 
 
 
 
 (8,123)
 
 
 
 
 
 (8,123)
SUBTOTAL – COMMON SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,087,142 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $1,027
 
 
 
 
 
 
 
 
 
 
 
 (1,907)
 
 
 (1,907)
 
 
Amortization of Pension and OPEB Deferred
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Costs, Net of Tax of $1,193
 
 
 
 
 
 
 
 
 
 
 
 2,215 
 
 
 2,215 
 
 
Pension and OPEB Funded Status, Net of Tax of $390
 
 
 
 
 
 
 
 
 
 
 
 724 
 
 
 724 
NET INCOME
 
 
 
 
 
 
 
 
 271,661 
 
 
 
 
 
 271,661 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 272,693 
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2009
 
 
 41,026 
 
 
 580,663 
 
 
 788,139 
 
 
 (49,993)
 
 
 1,359,835 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (102,500)
 
 
 
 
 
 (102,500)
Capital Stock Expense
 
 
 
 
 
 149 
 
 
 (149)
 
 
 
 
 
 - 
SUBTOTAL – COMMON SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,257,335 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $130
 
 
 
 
 
 
 
 
 
 
 
 242 
 
 
 242 
 
 
Amortization of Pension and OPEB Deferred
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Costs, Net of Tax of $1,333
 
 
 
 
 
 
 
 
 
 
 
 2,475 
 
 
 2,475 
 
 
Pension and OPEB Funded Status, Net of Tax of $2,186
 
 
 
 
 
 
 
 
 
 
 
 (4,060)
 
 
 (4,060)
NET INCOME
 
 
 
 
 
 
 
 
 230,223 
 
 
 
 
 
 230,223 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 228,880 
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2010
 
$
 41,026 
 
$
 580,812 
 
$
 915,713 
 
$
 (51,336)
 
$
 1,486,215 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.

 
168
 

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
 
ASSETS
 
December 31, 2010 and 2009
 
(in thousands)
 
 
 
 
 
2010
   
2009
 
CURRENT ASSETS
 
 
   
 
 
Cash and Cash Equivalents
  $ 509     $ 1,096  
Other Cash Deposits
    2,260       16,150  
Advances to Affiliates
    54,202       -  
Accounts Receivable:
               
Customers
    50,187       37,158  
Affiliated Companies
    66,788       28,555  
Accrued Unbilled Revenues
    32,821       11,845  
Miscellaneous
    14,374       4,164  
Allowance for Uncollectible Accounts
    (1,584 )     (3,481 )
Total Accounts Receivable
    162,586       78,241  
Fuel
    72,882       74,158  
Materials and Supplies
    42,033       39,652  
Emission Allowances
    28,486       26,587  
Risk Management Assets
    23,774       34,343  
Accrued Tax Benefits
    8,797       29,273  
Margin Deposits
    14,762       14,874  
Prepayments and Other Current Assets
    26,864       6,349  
TOTAL CURRENT ASSETS
    437,155       320,723  
 
               
PROPERTY, PLANT AND EQUIPMENT
               
Electric:
               
Generation
    2,686,294       2,641,860  
Transmission
    662,312       623,680  
Distribution
    1,796,023       1,745,559  
Other Property, Plant and Equipment
    203,593       189,315  
Construction Work in Progress
    172,793       155,081  
Total Property, Plant and Equipment
    5,521,015       5,355,495  
Accumulated Depreciation and Amortization
    1,927,112       1,838,840  
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    3,593,903       3,516,655  
 
               
OTHER NONCURRENT ASSETS
               
Regulatory Assets
    298,111       341,029  
Long-term Risk Management Assets
    22,089       23,882  
Deferred Charges and Other Noncurrent Assets
    152,932       147,217  
TOTAL OTHER NONCURRENT ASSETS
    473,132       512,128  
 
               
TOTAL ASSETS
  $ 4,504,190     $ 4,349,506  
 
               
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 
 
 
169
 
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
 
LIABILITIES AND SHAREHOLDER'S EQUITY
 
December 31, 2010 and 2009
 
 
 
 
 
2010
   
2009
 
 
 
(in thousands)
 
CURRENT LIABILITIES
 
 
   
 
 
Advances from Affiliates
  $ -     $ 24,202  
Accounts Payable:
               
General
    98,925       95,872  
Affiliated Companies
    78,617       81,338  
Long-term Debt Due Within One Year – Nonaffiliated
    -       150,000  
Long-term Debt Due Within One Year – Affiliated
    -       100,000  
Risk Management Liabilities
    15,967       13,052  
Customer Deposits
    29,441       27,911  
Accrued Taxes
    226,572       199,001  
Accrued Interest
    22,533       24,669  
Other Current Liabilities
    111,868       67,053  
TOTAL CURRENT LIABILITIES
    583,923       783,098  
 
               
NONCURRENT LIABILITIES
               
Long-term Debt – Nonaffiliated
    1,438,830       1,286,393  
Long-term Risk Management Liabilities
    6,223       10,313  
Deferred Income Taxes
    604,828       535,265  
Regulatory Liabilities and Deferred Investment Tax Credits
    163,888       174,671  
Employee Benefits and Pension Obligations
    136,643       133,968  
Deferred Credits and Other Noncurrent Liabilities
    83,640       65,963  
TOTAL NONCURRENT LIABILITIES
    2,434,052       2,206,573  
 
               
TOTAL LIABILITIES
    3,017,975       2,989,671  
 
               
Rate Matters (Note 4)
               
Commitments and Contingencies (Note 6)
               
 
               
COMMON SHAREHOLDER’S EQUITY
               
Common Stock – No Par Value:
               
Authorized – 24,000,000 Shares
               
Outstanding  – 16,410,426 Shares
    41,026       41,026  
Paid-in Capital
    580,812       580,663  
Retained Earnings
    915,713       788,139  
Accumulated Other Comprehensive Income (Loss)
    (51,336 )     (49,993 )
TOTAL COMMON SHAREHOLDER’S EQUITY
    1,486,215       1,359,835  
 
               
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY
  $ 4,504,190     $ 4,349,506  
 
               
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 

 
170
 

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
For the Years Ended December 31, 2010, 2009 and 2008
 
(in thousands)
 
 
 
 
 
2010
   
2009
   
2008
 
OPERATING ACTIVITIES
 
 
   
 
   
 
 
Net Income
  $ 230,223     $ 271,661     $ 237,130  
Adjustments to Reconcile Net Income to Net Cash Flows from
                       
Operating Activities:
                       
Depreciation and Amortization
    151,440       144,402       186,746  
Deferred Income Taxes
    74,585       131,407       (303 )
Carrying Costs Income
    (8,166 )     (7,656 )     (6,551 )
Allowance for Equity Funds Used During Construction
    (2,072 )     (3,382 )     (3,364 )
Mark-to-Market of Risk Management Contracts
    11,807       (4,786 )     (10,551 )
Property Taxes
    (12,463 )     (7,364 )     (2,169 )
Fuel Over/Under-Recovery, Net
    21,792       (36,028 )     -  
Provision for 2009 Significantly Excessive Earnings Test
    42,683       -       -  
Change in Other Noncurrent Assets
    596       (36,462 )     (8,984 )
Change in Other Noncurrent Liabilities
    (17,655 )     15,858       12,254  
Changes in Certain Components of Working Capital:
                       
Accounts Receivable, Net
    (75,580 )     52,088       (14,976 )
Fuel, Materials and Supplies
    880       (37,954 )     (3,381 )
Accounts Payable
    17,209       (57,666 )     67,349  
Customer Deposits
    1,530       (2,234 )     (12,950 )
Accrued Taxes, Net
    43,965       (17,319 )     5,075  
Other Current Assets
    3,251       9,439       (23,730 )
Other Current Liabilities
    5,867       (16,027 )     (8,241 )
Net Cash Flows from Operating Activities
    489,892       397,977       413,354  
 
                       
INVESTING ACTIVITIES
                       
Construction Expenditures
    (235,901 )     (302,699 )     (433,014 )
Change in Other Cash Deposits
    13,890       16,150       21,460  
Change in Advances to Affiliates, Net
    (54,202 )     -       -  
Acquisitions of Assets
    (742 )     (232 )     (807 )
Proceeds from Sales of Assets
    5,106       823       1,576  
Other Investing Activities
    12,667       -       -  
Net Cash Flows Used for Investing Activities
    (259,182 )     (285,958 )     (410,785 )
 
                       
FINANCING ACTIVITIES
                       
Issuance of Long-term Debt - Nonaffiliated
    149,443       91,160       346,397  
Change in Advances from Affiliates, Net
    (24,202 )     (50,663 )     (20,334 )
Retirement of Long-term Debt - Nonaffiliated
    (150,000 )     -       (204,245 )
Retirement of Long-term Debt - Affiliated
    (100,000 )     -       -  
Principal Payments for Capital Lease Obligations
    (4,170 )     (2,704 )     (2,936 )
Dividends Paid on Common Stock
    (102,500 )     (150,000 )     (122,500 )
Other Financing Activities
    132       221       723  
Net Cash Flows Used for Financing Activities
    (231,297 )     (111,986 )     (2,895 )
 
                       
Net Increase (Decrease) in Cash and Cash Equivalents
    (587 )     33       (326 )
Cash and Cash Equivalents at Beginning of Period
    1,096       1,063       1,389  
Cash and Cash Equivalents at End of Period
  $ 509     $ 1,096     $ 1,063  
 
                       
SUPPLEMENTARY INFORMATION
                       
Cash Paid for Interest, Net of Capitalized Amounts
  $ 85,240     $ 94,054     $ 78,539  
Net Cash Paid for Income Taxes
    36,805       46,945       113,140  
Noncash Acquisitions Under Capital Leases
    9,633       892       2,326  
Government Grants Included in Accounts Receivable at December 31,
    9,260       -       -  
Construction Expenditures Included in Accounts Payable at December 31,
    14,229       31,106       47,438  
Noncash Dividend of Property to Parent
    -       8,123       -  
SIA Refund Included in Accounts Payable at December 31,
    -       -       44,178  
 
                       
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 

 
171
 

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to CSPCo’s consolidated financial statements are combined with the notes to financial statements for other registrant subsidiaries.  Listed below are the notes that apply to CSPCo.  The footnotes begin on page 246.

 
Footnote
Reference
   
Organization and Summary of Significant Accounting Policies
Note 1
New Accounting Pronouncements and Extraordinary Item
Note 2
Rate Matters
Note 4
Effects of Regulation
Note 5
Commitments, Guarantees and Contingencies
Note 6
Benefit Plans
Note 8
Business Segments
Note 9
Derivatives and Hedging
Note 10
Fair Value Measurements
Note 11
Income Taxes
Note 12
Leases
Note 13
Financing Activities
Note 14
Related Party Transactions
Note 15
Property, Plant and Equipment
Note 16
Cost Reduction Initiatives
Note 17
Unaudited Quarterly Financial Information
Note 18

 
172
 










INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES


 
173
 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

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 582,000 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 (RTD) provides barging services to affiliates and nonaffiliated companies.  The revenues from barging represent the majority of other revenues except in 2009 when insurance proceeds related to the Cook Plant Unit 1 outage were the largest amount.

Originally approved by the FERC in 1951 and subsequently amended in 1951, 1962, 1975, 1979 (twice) and 1980, the Interconnection Agreement establishes the AEP Power Pool which permits the AEP East companies to pool their generation assets on a cost basis.  It establishes 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.  AEP Power Pool members are compensated for their costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool.  The capacity reserve relationship of the AEP Power Pool members changes as generating assets are added, retired or sold and relative peak demand changes.  The AEP Power Pool 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 determines each member’s percentage share of revenues and costs.

In December 2010, each member gave notice to AEPSC and the other AEP Power Pool members of its decision to terminate the Interconnection Agreement effective January 1, 2014 or such other date approved by the FERC, subject to state regulatory input.  It is unknown at this time whether the AEP Power Pool will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers or if each company will choose to operate independently.  This decision to terminate is subject to management’s ongoing evaluation.  The AEP Power Pool members may revoke their notices of termination.  If I&M experiences decreases in revenues or increases in costs as a result of the termination of the AEP Power Pool and is unable to recover the change in revenues and costs through rates, prices or additional sales, it could have an adverse impact on future net income and cash flows.

The AEP East companies are parties to a Transmission Agreement defining how they share the costs associated with their relative ownership of transmission assets.  This sharing was based upon each company’s MLR until the FERC approved a new Transmission Agreement effective November 1, 2010.  The new Transmission Agreement will be phased-in for retail rates over periods of up to four years, adds KGPCo and WPCo as parties to the agreement and changes the allocation method.  I&M’s recovery mechanism for transmission costs is through its base rates.  Changes in allocation under the new Transmission Agreement and state regulatory phase-in of the new agreement will limit I&M’s ability to fully recover its transmission costs.

Under unit power agreements, I&M purchases AEGCo’s 50% share of the 2,600 MW Rockport Plant capacity unless it is sold to other utilities.  AEGCo is an affiliate that is not a member of the AEP Power Pool.  An agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo’s Rockport Plant capacity to KPCo through 2022.  Therefore, 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 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.

 
174
 
AEPSC conducts power, gas, coal and emission allowance risk management activities on I&M’s behalf.  I&M shares in the revenues and expenses associated with these risk management activities, as described in the preceding paragraph, with the other AEP East companies, PSO and SWEPCo.  Power and gas risk management activities are allocated based on the existing power pool agreement and the SIA.  I&M shares in coal and emission 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 gas, coal and emission allowances.  The electricity, gas, coal and emission allowance 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.

To minimize the credit requirements and operating constraints when operating within PJM, the AEP East companies as well as KGPCo and WPCo, agreed to a netting of all payment obligations incurred by any of the AEP East companies against all balances due to the AEP East companies, and to hold PJM harmless from actions that any one or more AEP East companies may take with respect to PJM.

I&M is jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to purchase power and sale activity pursuant to the SIA.

Regulatory Activity

Michigan Regulatory Activity

In October 2010, a settlement agreement was approved by the MPSC to increase annual base rates by $36 million based on a 10.35% return on common equity, effective December 2010, plus separate recovery of approximately $7 million of customer choice implementation costs over a two year period beginning April 2011.  In addition, the approved revenue requirement includes the amortization of $6 million in previously expensed restructuring costs over five years, which I&M deferred in October 2010 and began amortizing in December 2010.  Also, the approved settlement agreement provided for sharing of off-system sales margins between customers (75%) and I&M (25%) with customers receiving a credit in future Power Supply Cost Recovery proceedings for their jurisdictional share of any off-system sales margins.  See “Michigan Base Rate Filing” section of Note 4.

Cook Plant Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in significant turbine damage and a small fire on the electric generator.  Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $395 million.  Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process.  I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power.  The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors.  As a result, the replacement of the repaired turbine rotors and other equipment is scheduled for the Unit 1 planned outage in the fall of 2011.  If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.  See “Indiana Fuel Clause Filing” and “Michigan 2009 Power Supply Cost Recovery Reconciliation” sections of Note 4 and “Cook Plant Unit 1 Fire and Shutdown” section of Note 6.

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 state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be.  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 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

 
175
 
See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 405 for additional discussion of relevant factors.

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
2010 
 
2009 
 
2008 
 
 
(in millions of KWH)
Retail:
 
 
 
 
 
 
 
 
 
Residential
 
 6,083 
 
 
 5,767 
 
 
 6,059 
 
Commercial
 
 5,121 
 
 
 5,038 
 
 
 5,272 
 
Industrial
 
 7,445 
 
 
 6,762 
 
 
 7,536 
 
Miscellaneous
 
 72 
 
 
 76 
 
 
 76 
Total Retail
 
 18,721 
 
 
 17,643 
 
 
 18,943 
 
 
 
 
 
 
 
 
 
Wholesale
 
 7,839 
 
 
 8,564 
 
 
 11,325 
 
 
 
 
 
 
 
 
 
Total KWHs
 
 26,560 
 
 
 26,207 
 
 
 30,268 

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,
 
 
 
2010 
 
2009 
 
2008 
 
 
 
(in degree days)
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 3,759 
 
 
 3,876 
 
 
 4,146 
 
Normal - Heating (b)
 
 3,774 
 
 
 3,788 
 
 
 3,789 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 1,165 
 
 
 580 
 
 
 747 
 
Normal - Cooling (b)
 
 832 
 
 
 844 
 
 
 842 
 
 
 
 
 
 
 
 
 
 
 
 
(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.

 
176
 
2010 Compared to 2009
 
 
 
 
 
Reconciliation of Year Ended December 31, 2009 to Year Ended December 31, 2010
Net Income
(in millions)
 
 
 
 
 
Year Ended December 31, 2009
 
$
 216 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
Retail Margins
 
 
 171 
 
FERC Municipals and Cooperatives
 
 
 (32)
 
Off-system Sales
 
 
 9 
 
Transmission Revenues
 
 
 2 
 
Other Revenues
 
 
 (185)
 
Total Change in Gross Margin
 
 
 (35)
 
 
 
 
 
 
Total Expenses and Other:
 
 
 
 
Other Operation and Maintenance
 
 
 (64)
 
Depreciation and Amortization
 
 
 (2)
 
Taxes Other Than Income Taxes
 
 
 (5)
 
Other Income
 
 
 1 
 
Interest Expense
 
 
 (3)
 
Total Expenses and Other
 
 
 (73)
 
 
 
 
 
 
Income Tax Expense
 
 
 18 
 
 
 
 
 
 
Year Ended December 31, 2010
 
$
 126 
 

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 power were as follows:

·
Retail Margins increased $171 million primarily due to the following:
 
·
An $87 million increase primarily due to a $78 million increase in fuel and purchased power costs recorded in 2009 related to the Cook Plant Unit 1 (Unit 1) shutdown.  This increase was offset by a corresponding decrease in Other Revenues as discussed below.
 
·
A $39 million increase in rate relief primarily due to the impact of the Michigan rate settlement approved in October 2010 and the approval of the Indiana base rate filing effective March 2009.  This increase in Retail Margins had corresponding increases of $13 million related to riders/trackers recognized in  expense items.
 
·
A $38 million increase in weather-related usage and increased price for residential and commercial customers primarily due to an increase in cooling degree days.
 
·
A $28 million increase in industrial sales margins due to higher usage in comparison to recessionary lows of 2009.
 
These increases were partially offset by:
 
·
A $15 million increase in PJM costs partially recovered through a rate rider included in the $13 million discussed above.
·
FERC Municipals and Cooperatives margins decreased $32 million primarily due to a unit power sales agreement ending in December 2009.
·
Margins from Off-system Sales increased $9 million primarily due to increased prices and higher physical sales volumes, partially offset by lower trading and marketing margins.
·
Other Revenues decreased $185 million primarily due to the following:
 
·
A $185 million decrease in the Cook Plant accidental outage insurance proceeds which ended when Unit 1 returned to service in December 2009.  I&M reduced customer bills by approximately $78 million in 2009 for the cost of replacement power resulting from the Unit 1 outage.  This decrease in insurance proceeds was offset by a corresponding increase in Retail Margins as discussed above.
 
 
177
 
 
This decrease was partially offset by:
 
·
A $9 million increase in RTD revenues from barging activities.  The increase in RTD revenue was offset by a corresponding increase in Other Operation and Maintenance expenses from barging activities as discussed below.

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

·
Other Operation and Maintenance expenses increased $64 million primarily due to the following:
 
·
A $35 million increase due to expenses related to cost reduction initiatives.  In 2010, management conducted cost reduction initiatives to reduce both labor and non-labor expenses.
 
·
A $17 million increase in transmission expense primarily due to lower credits under the Transmission Agreement.
 
·
A $9 million increase in RTD expenses from barging activities.  The increase in RTD expense was partially offset by a corresponding increase in Other Revenues from barging activities as discussed above.
·
Income Tax Expense decreased $18 million primarily due to a decrease in pretax book income partially offset by the regulatory accounting treatment of state income taxes and other book/tax differences which are accounted for on a flow-through basis.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 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 “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 for a discussion of the adoption and impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

See “Quantitative And Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 for a discussion of risk management activities.

 
178
 


 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
To the Board of Directors and Shareholders 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, 2010 and 2009, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010.  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, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
 
 
/s/ Deloitte & Touche LLP
 
 
Columbus, Ohio
February 25, 2011
 

 
179
 

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, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment, I&M’s internal control over financial reporting was effective as of December 31, 2010.

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.

 
180
 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF INCOME
 
For the Years Ended December 31, 2010, 2009 and 2008
 
(in thousands)
 
 
 
 
 
2010
   
2009
   
2008
 
REVENUES
 
 
   
 
   
 
 
Electric Generation, Transmission and Distribution
  $ 1,735,338     $ 1,685,308     $ 1,727,769  
Sales to AEP Affiliates
    330,951       196,151       302,741  
Other Revenues - Affiliated
    114,070       110,143       116,747  
Other Revenues - Nonaffiliated
    15,368       193,422       19,102  
TOTAL REVENUES
    2,195,727       2,185,024       2,166,359  
 
                       
EXPENSES
                       
Fuel and Other Consumables Used for Electric Generation
    465,482       409,845       436,078  
Purchased Electricity for Resale
    128,369       128,508       116,958  
Purchased Electricity from AEP Affiliates
    327,335       337,308       384,182  
Other Operation
    560,346       500,672       527,669  
Maintenance
    222,406       218,036       219,630  
Depreciation and Amortization
    136,443       134,690       127,406  
Taxes Other Than Income Taxes
    80,431       75,262       78,338  
TOTAL EXPENSES
    1,920,812       1,804,321       1,890,261  
 
                       
OPERATING INCOME
    274,915       380,703       276,098  
 
                       
Other Income (Expense):
                       
Interest Income
    3,389       5,776       2,921  
Allowance for Equity Funds Used During Construction
    15,678       12,013       965  
Interest Expense
    (104,465 )     (101,145 )     (89,851 )
 
                       
INCOME BEFORE INCOME TAX EXPENSE
    189,517       297,347       190,133  
 
                       
Income Tax Expense
    63,426       81,037       58,258  
 
                       
NET INCOME
    126,091       216,310       131,875  
 
                       
Preferred Stock Dividend Requirements
    339       339       339  
 
                       
EARNINGS ATTRIBUTABLE TO COMMON STOCK
  $ 125,752     $ 215,971     $ 131,536  
 
                       
The common stock of I&M is wholly-owned by AEP.
                       
 
                       
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 

 
181
 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2010, 2009 and 2008
(in thousands)
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
 
 
 
 
Stock
 
Capital
 
Earnings
 
Income (Loss)
 
 
Total
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2007
 
$
 56,584 
 
$
 861,291 
 
$
 483,499 
 
$
 (15,675)
 
$
 1,385,699 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Adoption of Guidance for Split-Dollar Life Insurance
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accounting, Net of Tax of $753
 
 
 
 
 
 
 
 
 (1,398)
 
 
 
 
 
 (1,398)
Common Stock Dividends
 
 
 
 
 
 
 
 
 (75,000)
 
 
 
 
 
 (75,000)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (339)
 
 
 
 
 
 (339)
SUBTOTAL – COMMON SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,308,962 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $1,676
 
 
 
 
 
 
 
 
 
 
 
 3,112 
 
 
 3,112 
 
 
Amortization of Pension and OPEB Deferred Costs, Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
of Tax of $237
 
 
 
 
 
 
 
 
 
 
 
 441 
 
 
 441 
 
 
Pension and OPEB Funded Status, Net of Tax of $5,154
 
 
 
 
 
 
 
 
 
 
 
 (9,572)
 
 
 (9,572)
NET INCOME
 
 
 
 
 
 
 
 
 131,875 
 
 
 
 
 
 131,875 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 125,856 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2008
 
 
 56,584 
 
 
 861,291 
 
 
 538,637 
 
 
 (21,694)
 
 
 1,434,818 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital Contribution from Parent
 
 
 
 
 
 120,000 
 
 
 
 
 
 
 
 
 120,000 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (98,000)
 
 
 
 
 
 (98,000)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (339)
 
 
 
 
 
 (339)
Gain on Reacquired Preferred Stock
 
 
 
 
 
 1 
 
 
 
 
 
 
 
 
 1 
SUBTOTAL – COMMON SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,456,480 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $462
 
 
 
 
 
 
 
 
 
 
 
 (857)
 
 
 (857)
 
 
Amortization of Pension and OPEB Deferred Costs, Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
of Tax of $445
 
 
 
 
 
 
 
 
 
 
 
 826 
 
 
 826 
 
 
Pension and OPEB Funded Status, Net of Tax of $13
 
 
 
 
 
 
 
 
 
 
 
 24 
 
 
 24 
NET INCOME
 
 
 
 
 
 
 
 
 216,310 
 
 
 
 
 
 216,310 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 216,303 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2009
 
 
 56,584 
 
 
 981,292 
 
 
 656,608 
 
 
 (21,701)
 
 
 1,672,783 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (105,000)
 
 
 
 
 
 (105,000)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (339)
 
 
 
 
 
 (339)
Gain on Reacquired Preferred Stock
 
 
 
 
 
 2 
 
 
 
 
 
 
 
 
 2 
SUBTOTAL – COMMON SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,567,446 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $652
 
 
 
 
 
 
 
 
 
 
 
 1,211 
 
 
 1,211 
 
 
Amortization of Pension and OPEB Deferred
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Costs, Net of Tax of $470
 
 
 
 
 
 
 
 
 
 
 
 873 
 
 
 873 
 
 
Pension and OPEB Funded Status, Net of Tax of $685
 
 
 
 
 
 
 
 
 
 
 
 (1,272)
 
 
 (1,272)
NET INCOME
 
 
 
 
 
 
 
 
 126,091 
 
 
 
 
 
 126,091 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 126,903 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2010
 
$
 56,584 
 
$
 981,294 
 
$
 677,360 
 
$
 (20,889)
 
$
 1,694,349 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.

 
182
 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
 
ASSETS
 
December 31, 2010 and 2009
 
(in thousands)
 
 
 
 
 
2010
   
2009
 
CURRENT ASSETS
 
 
   
 
 
Cash and Cash Equivalents
  $ 361     $ 779  
Advances to Affiliates
    -       114,012  
Accounts Receivable:
               
Customers
    76,193       71,120  
Affiliated Companies
    149,169       83,248  
Accrued Unbilled Revenues
    19,449       8,762  
Miscellaneous
    10,968       8,638  
Allowance for Uncollectible Accounts
    (1,692 )     (2,265 )
Total Accounts Receivable
    254,087       169,503  
Fuel
    87,551       79,554  
Materials and Supplies
    178,331       164,439  
Risk Management Assets
    27,526       34,438  
Accrued Tax Benefits
    71,113       144,473  
Deferred Cook Plant Fire Costs
    45,752       134,322  
Prepayments and Other Current Assets
    33,713       29,395  
TOTAL CURRENT ASSETS
    698,434       870,915  
 
               
PROPERTY, PLANT AND EQUIPMENT
               
Electric:
               
Generation
    3,774,262       3,634,215  
Transmission
    1,188,665       1,154,026  
Distribution
    1,411,095       1,360,553  
Other Property, Plant and Equipment (including nuclear fuel and coal mining)
    719,708       755,132  
Construction Work in Progress
    301,534       278,278  
Total Property, Plant and Equipment
    7,395,264       7,182,204  
Accumulated Depreciation, Depletion and Amortization
    3,124,998       3,073,695  
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    4,270,266       4,108,509  
 
               
OTHER NONCURRENT ASSETS
               
Regulatory Assets
    556,254       496,464  
Spent Nuclear Fuel and Decommissioning Trusts
    1,515,227       1,391,919  
Long-term Risk Management Assets
    31,485       29,134  
Deferred Charges and Other Noncurrent Assets
    77,229       82,047  
TOTAL OTHER NONCURRENT ASSETS
    2,180,195       1,999,564  
 
               
TOTAL ASSETS
  $ 7,148,895     $ 6,978,988  
 
               
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 
 
 
183
 
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
December 31, 2010 and 2009
 
 
 
 
 
2010
   
2009
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
  $ 42,769     $ -  
Accounts Payable:
               
General
    121,665       171,192  
Affiliated Companies
    105,221       61,315  
Long-term Debt Due Within One Year – Nonaffiliated
    154,457       37,544  
(December 31, 2010 amount includes $77,457 related to DCC Fuel)
               
Long-term Debt Due Within One Year – Affiliated
    -       25,000  
Risk Management Liabilities
    16,785       13,436  
Customer Deposits
    29,264       27,711  
Accrued Taxes
    62,637       56,814  
Accrued Interest
    27,444       27,633  
Other Current Liabilities
    140,710       151,865  
TOTAL CURRENT LIABILITIES
    700,952       572,510  
 
               
NONCURRENT LIABILITIES
               
Long-term Debt – Nonaffiliated
    1,849,769       2,015,362  
Long-term Risk Management Liabilities
    6,530       10,386  
Deferred Income Taxes
    760,105       696,163  
Regulatory Liabilities and Deferred Investment Tax Credits
    852,197       756,845  
Asset Retirement Obligations
    963,029       894,746  
Deferred Credits and Other Noncurrent Liabilities
    313,892       352,116  
TOTAL NONCURRENT LIABILITIES
    4,745,522       4,725,618  
 
               
TOTAL LIABILITIES
    5,446,474       5,298,128  
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
    8,072       8,077  
 
               
Rate Matters (Note 4)
               
Commitments and Contingencies (Note 6)
               
 
               
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
    981,294       981,292  
Retained Earnings
    677,360       656,608  
Accumulated Other Comprehensive Income (Loss)
    (20,889 )     (21,701 )
TOTAL COMMON SHAREHOLDER’S EQUITY
    1,694,349       1,672,783  
 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
  $ 7,148,895     $ 6,978,988  
 
               
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 

 
184
 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
For the Years Ended December 31, 2010, 2009 and 2008
 
(in thousands)
 
 
 
 
 
2010
   
2009
   
2008
 
OPERATING ACTIVITIES
 
 
   
 
   
 
 
Net Income
  $ 126,091     $ 216,310     $ 131,875  
Adjustments to Reconcile Net Income to Net Cash Flows from
                       
Operating Activities:
                       
Depreciation and Amortization
    136,443       134,690       127,406  
Accretion of Asset Retirement Obligations
    11,905       11,178       21,178  
Deferred Income Taxes
    63,947       271,264       57,879  
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net
    (31,939 )     3,110       8,925  
Allowance for Equity Funds Used During Construction
    (15,678 )     (12,013 )     (965 )
Mark-to-Market of Risk Management Contracts
    4,592       (10,533 )     (10,482 )
Amortization of Nuclear Fuel
    139,438       62,699       87,574  
Pension Contributions to Qualified Plan Trust
    (71,681 )     -       -  
Fuel Over/Under Recovery, Net
    (12,589 )     34,676       (35,688 )
Change in Other Noncurrent Assets
    (12,597 )     (16,555 )     (9,533 )
Change in Other Noncurrent Liabilities
    56,592       45,276       45,073  
Changes in Certain Components of Working Capital:
                       
Accounts Receivable, Net
    (85,072 )     19,338       (3,753 )
Fuel, Materials and Supplies
    (16,564 )     (20,676 )     (7,822 )
Accounts Payable
    46,579       (65,424 )     90,041  
Accrued Taxes, Net
    77,075       (132,214 )     6,283  
Received (Deferred) Cook Plant Fire Costs, Net
    87,347       (89,409 )     (23,013 )
Other Current Assets
    5,056       (5,351 )     (8,966 )
Other Current Liabilities
    4,149       (2,924 )     15,351  
Net Cash Flows from Operating Activities
    513,094       443,442       491,363  
 
                       
INVESTING ACTIVITIES
                       
Construction Expenditures
    (333,238 )     (332,775 )     (352,335 )
Change in Advances to Affiliates, Net
    114,012       (114,012 )     -  
Purchases of Investment Securities
    (1,414,473 )     (770,919 )     (803,664 )
Sales of Investment Securities
    1,361,813       712,742       732,475  
Acquisitions of Nuclear Fuel
    (90,903 )     (169,138 )     (192,299 )
Other Investing Activities
    17,105       21,004       3,642  
Net Cash Flows Used for Investing Activities
    (345,684 )     (653,098 )     (612,181 )
 
                       
FINANCING ACTIVITIES
                       
Capital Contribution from Parent
    -       120,000       -  
Issuance of Long-term Debt - Nonaffiliated
    152,464       670,060       115,269  
Issuance of Long-term Debt - Affiliated
    -       25,000       -  
Change in Advances from Affiliates, Net
    42,769       (476,036 )     430,972  
Retirement of Long-term Debt - Nonaffiliated
    (202,011 )     -       (312,000 )
Retirement of Long-term Debt - Affiliated
    (25,000 )     -       -  
Retirement of Cumulative Preferred Stock
    (3 )     (2 )     -  
Principal Payments for Capital Lease Obligations
    (31,180 )     (31,637 )     (39,427 )
Dividends Paid on Common Stock
    (105,000 )     (98,000 )     (75,000 )
Dividends Paid on Cumulative Preferred Stock
    (339 )     (339 )     (339 )
Other Financing Activities
    472       661       932  
Net Cash Flows from (Used for) Financing Activities
    (167,828 )     209,707       120,407  
 
                       
Net Increase (Decrease) in Cash and Cash Equivalents
    (418 )     51       (411 )
Cash and Cash Equivalents at Beginning of Period
    779       728       1,139  
Cash and Cash Equivalents at End of Period
  $ 361     $ 779     $ 728  
 
                       
SUPPLEMENTARY INFORMATION
                       
Cash Paid for Interest, Net of Capitalized Amounts
  $ 100,617     $ 99,079     $ 75,981  
Net Cash Paid (Received) for Income Taxes
    (71,268 )     (51,298 )     310  
Noncash Acquisitions Under Capital Leases
    10,000       2,651       4,472  
Construction Expenditures Included in Accounts Payable at December 31,
    21,757       74,251       50,507  
Acquisition of Nuclear Fuel Included in Accounts Payable at December 31,
    308       15       37,628  
SIA Refund Included in Accounts Payable at December 31,
    -       -       48,489  
 
                       
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 

 
185
 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to I&M’s consolidated 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 246.

 
Footnote
Reference
   
Organization and Summary of Significant Accounting Policies
Note 1
New Accounting Pronouncements and Extraordinary Item
Note 2
Rate Matters
Note 4
Effects of Regulation
Note 5
Commitments, Guarantees and Contingencies
Note 6
Benefit Plans
Note 8
Business Segments
Note 9
Derivatives and Hedging
Note 10
Fair Value Measurements
Note 11
Income Taxes
Note 12
Leases
Note 13
Financing Activities
Note 14
Related Party Transactions
Note 15
Property, Plant and Equipment
Note 16
Cost Reduction Initiatives
Note 17
Unaudited Quarterly Financial Information
Note 18

 
186
 










OHIO POWER COMPANY CONSOLIDATED


 
187
 

OHIO POWER COMPANY CONSOLIDATED
SELECTED CONSOLIDATED FINANCIAL DATA
(in thousands)
 
 
 
 
 
2010 
 
2009 
 
2008 
 
2007 
 
2006 
STATEMENTS OF INCOME DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
 
$
 3,223,707 
 
$
 3,011,574 
 
$
 3,096,934 
 
$
 2,814,212 
 
$
 2,724,875 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating Income
 
$
 607,802 
 
$
 613,193 
 
$
 495,050 
 
$
 526,352 
 
$
 425,291 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income
 
$
 311,393 
 
$
 308,615 
 
$
 232,455 
 
$
 271,186 
 
$
 231,434 
Less:  Net Income Attributable to
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling Interest
 
 
 - 
 
 
 2,042 
 
 
 1,332 
 
 
 2,622 
 
 
 2,791 
Net Income Attributable to OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Shareholders
 
 
 311,393 
 
 
 306,573 
 
 
 231,123 
 
 
 268,564 
 
 
 228,643 
Less:  Preferred Stock Dividend
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Requirements
 
 
 732 
 
 
 732 
 
 
 732 
 
 
 732 
 
 
 732 
Earnings Attributable to OPCo Common
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Shareholder
 
$
 310,661 
 
$
 305,841 
 
$
 230,391 
 
$
 267,832 
 
$
 227,911 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
BALANCE SHEETS DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and Equipment
 
$
 10,263,541 
 
$
 10,013,458 
 
$
 9,788,862 
 
$
 9,140,357 
 
$
 8,405,645 
Accumulated Depreciation and Amortization
 
 
 3,606,777 
 
 
 3,318,896 
 
 
 3,122,989 
 
 
 2,967,285 
 
 
 2,836,584 
Total Property, Plant and Equipment – Net
 
$
 6,656,764 
 
$
 6,694,562 
 
$
 6,665,873 
 
$
 6,173,072 
 
$
 5,569,061 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
 8,747,327 
 
$
 9,039,139 
 
$
 8,003,826 
 
$
 7,338,429 
 
$
 6,807,528 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Common Shareholder's Equity
 
$
 3,168,424 
 
$
 3,234,695 
 
$
 2,421,945 
 
$
 2,291,017 
 
$
 2,008,342 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cumulative Preferred Stock Not Subject to
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mandatory Redemption
 
$
 16,616 
 
$
 16,627 
 
$
 16,627 
 
$
 16,627 
 
$
 16,630 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling Interest
 
$
 - 
 
$
 - 
 
$
 16,799 
 
$
 15,923 
 
$
 15,825 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt (a)
 
$
 2,729,522 
 
$
 3,242,505 
 
$
 3,039,376 
 
$
 2,849,598 
 
$
 2,401,741 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Obligations Under Capital Leases (a)
 
$
 50,307 
(b)
$
 22,682 
 
$
 26,466 
 
$
 29,077 
 
$
 34,966 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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.

 
188
 
 
OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Company Overview

As a public utility, OPCo engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 706,000 retail customers in the northwestern, east central, eastern and southern sections of Ohio.  OPCo consolidated JMG Funding LP, a variable interest entity, until it was dissolved in December 2009 at which time JMG’s assets were transferred to OPCo.  This change had an immaterial impact on comparative financial statements.

In October 2010, CSPCo and OPCo filed with the PUCO to merge CSPCo into OPCo.  Approval of the merger will not affect CSPCo's and OPCo's rates until the PUCO approves new rates, terms and conditions for the merged company.  In January 2011, CSPCo and OPCo filed with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo effective October 2011.

Originally approved by the FERC in 1951 and subsequently amended in 1951, 1962, 1975, 1979 (twice) and 1980, the Interconnection Agreement establishes the AEP Power Pool which permits the AEP East companies to pool their generation assets on a cost basis.  It establishes 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.  AEP Power Pool members are compensated for their costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool.  The capacity reserve relationship of the AEP Power Pool members changes as generating assets are added, retired or sold and relative peak demand changes.  The AEP Power Pool 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 determines each member’s percentage share of revenues and costs.

In December 2010, each member gave notice to AEPSC and the other AEP Power Pool members of its decision to terminate the Interconnection Agreement effective January 1, 2014 or such other date approved by the FERC, subject to state regulatory input.  It is unknown at this time whether the AEP Power Pool will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers or if each company will choose to operate independently.  This decision to terminate is subject to management’s ongoing evaluation.  The AEP Power Pool members may revoke their notices of termination.  If OPCo experiences decreases in revenues or increases in costs as a result of the termination of the AEP Power Pool and is unable to recover the change in revenues and costs through rates, prices or additional sales, it could have an adverse impact on future net income and cash flows.

The AEP East companies are parties to a Transmission Agreement defining how they share the costs associated with their relative ownership of transmission assets.  This sharing was based upon each company’s MLR until the FERC approved a new Transmission Agreement effective November 1, 2010.  The impacts of the new Transmission Agreement will be phased-in for retail rates, adds KGPCo and WPCo as parties to the agreement and changes the allocation method.

Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and 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.

AEPSC conducts power, gas, coal and emission allowance risk management activities on OPCo’s behalf.  OPCo shares in the revenues and expenses associated with these risk management activities, as described in the preceding paragraph, with the other AEP East companies, PSO and SWEPCo.  Power and gas risk management activities are allocated based on the existing power pool agreement and the SIA.  OPCo shares in coal and emission allowance
 
189
 
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 gas, coal and emission allowances.  The electricity, gas, coal and emission allowance 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.

To minimize the credit requirements and operating constraints of operating within PJM, the AEP East companies as well as KGPCo and WPCo, agreed to a netting of all payment obligations incurred by any of the AEP East companies against all balances due to the AEP East companies, and to hold PJM harmless from actions that any one or more AEP East companies may take with respect to PJM.

OPCo is jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to purchase power and sale activity pursuant to the SIA.

Regulatory Activity

2009 – 2011 ESP

During 2009, the PUCO issued an order that modified and approved OPCo’s ESP which established rates through 2011.  The order also limited annual rate increases for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011.  The order provided a FAC for the three-year period of the ESP.  Several notices of appeal are outstanding at the Supreme Court of Ohio relating to significant issues in the determination of the approved ESP rates.  In January 2011, the PUCO issued an order that determined that OPCo’s 2009 earnings were not significantly excessive.  See “Ohio Electric Security Plan Filings” section of Note 4.

Proposed January 2012 – May 2014 ESP

In January 2011, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  The SSO presents redesigned generation rates by customer class.  Customer class rates individually vary, but on average, customers will experience net base generation increases of 1.4% in 2012 and 2.7% for the period January 2013 through May 2014.  See “Ohio Electric Security Plan Filings” section of Note 4.

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 state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be.  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 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 405 for additional discussion of relevant factors.

 
190
 
RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
2010 
 
2009 
 
2008 
 
 
(in millions of KWH)
Retail:
 
 
 
 
 
 
 
 
 
Residential
 
 7,582 
 
 
 7,339 
 
 
 7,528 
 
Commercial
 
 5,745 
 
 
 5,686 
 
 
 5,824 
 
Industrial
 
 12,800 
 
 
 11,834 
 
 
 14,441 
 
Miscellaneous
 
 73 
 
 
 77 
 
 
 79 
Total Retail
 
 26,200 
 
 
 24,936 
 
 
 27,872 
 
 
 
 
 
 
 
 
 
Wholesale
 
 5,516 
 
 
 4,136 
 
 
 7,384 
 
 
 
 
 
 
 
 
 
Total KWHs
 
 31,716 
 
 
 29,072 
 
 
 35,256 

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,
 
 
 
2010 
 
2009 
 
2008 
 
 
 
(in degree days)
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 3,714 
 
 
 3,682 
 
 
 3,845 
 
Normal - Heating (b)
 
 3,536 
 
 
 3,545 
 
 
 3,535 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 1,040 
 
 
 566 
 
 
 700 
 
Normal - Cooling (b)
 
 795 
 
 
 807 
 
 
 813 
 
 
 
 
 
 
 
 
 
 
 
 
(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.

 
191
 
2010 Compared to 2009
 
 
 
 
 
Reconciliation of Year Ended December 31, 2009 to Year Ended December 31, 2010
 
Net Income
 
(in millions)
 
 
 
 
 
Year Ended December 31, 2009
  $ 309  
 
       
Changes in Gross Margin:
       
Retail Margins
    92  
Off-system Sales
    19  
Transmission Revenues
    1  
Other Revenues
    (22 )
Total Change in Gross Margin
    90  
 
       
Total Expenses and Other:
       
Other Operation and Maintenance
    (74 )
Depreciation and Amortization
    (10 )
Taxes Other Than Income Taxes
    (12 )
Carrying Costs Income
    13  
Other Income
    1  
Interest Expense
    (3 )
Total Expenses and Other
    (85 )
 
       
Income Tax Expense
    (3 )
 
       
Year Ended December 31, 2010
  $ 311  

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 power were as follows:

·
Retail Margins increased $92 million primarily due to the following:
 
·
A $37 million increase in retail sales as a result of an increase in weather-related usage by residential and commercial customers primarily due to an 84% increase in cooling degree days and increased usage by industrial customers in comparison to recessionary lows in 2009.
 
·
A $37 million increase in capacity settlements under the Interconnection Agreement.
 
·
A $29 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Energy Efficiency & Peak Demand Reduction (EE/PDR) Programs.  This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
 
·
A $25 million FERC approved increase in demand charges received from WPCo effective January 2010.
 
These increases were partially offset by:
 
·
A $10 million decrease related to increased consumable and allowance expenses.
 
·
A $9 million decrease in fuel recovery related to coal pile survey adjustments recorded in 2009 for the 2008 consumption portion.  The 2008 portion was excluded from the deferred fuel calculation.  The PUCO’s March 2009 approval of OPCo’s ESP allowed for the recovery of fuel and related costs beginning January 1, 2009.
·
Margins from Off-system Sales increased $19 million primarily due to increased prices and higher physical sales volumes, partially offset by lower trading and marketing margins.
·
Other Revenues decreased $22 million primarily due to reduced gains on sales of emission allowances as a result of lower market prices for allowances.  Gains on sales of allowances are partially offset by sharing in the fuel clause.

 
192
 
Total Expenses and Other and Income Tax Expense changed between years as follows:

·
Other Operation and Maintenance expenses increased $74 million primarily due to:
 
·
A $54 million increase in expenses related to cost reduction initiatives.  In 2010, management conducted cost reduction initiatives to reduce both labor and non-labor expenses.
 
·
A $29 million increase in expenses due to the implementation of PUCO approved EE/PDR programs.  This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
 
·
A $10 million increase in recoverable customer account expenses due to increased Universal Service Fund surcharge rates for customers who qualify for payment assistance.
 
These increases were partially offset by:
 
·
An $11 million decrease related to a 2009 coal blending project.
 
·
A $5 million decrease related to a 2009 obligation to contribute to the “Partnership with Ohio” fund for low income, at-risk customers ordered by the PUCO’s approval of OPCo’s ESP.
·
Depreciation and Amortization increased $10 million primarily due to:
 
·
A $13 million increase from higher depreciable property balances as a result of environmental improvements placed in service and various other property additions.
 
This increase was partially offset by:
 
·
A $3 million decrease primarily due to the completion of the amortization of software in the fourth quarter of 2009.
·
Taxes Other Than Income Taxes increased $12 million primarily due to:
 
·
·
·
An $8 million increase in real and property taxes.
A $3 million increase in state excise taxes.
A $2 million increase due to the employer portion of payroll taxes incurred related to cost reduction initiatives.
·
Carrying Costs Income increased $13 million primarily due to a higher under-recovered fuel balance in 2010.
·
Income Tax Expense increased $3 million primarily due to an increase in pretax book income, the recording of federal income tax adjustments and the tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits, partially offset by the regulatory accounting treatment of state income taxes.

 
193
 
2009 Compared to 2008
 
 
 
 
 
Reconciliation of Year Ended December 31, 2008 to Year Ended December 31, 2009
 
Net Income
 
(in millions)
 
 
 
 
 
Year Ended December 31, 2008
  $ 232  
 
       
Changes in Gross Margin:
       
Retail Margins
    283  
Off-system Sales
    (119 )
Transmission Revenues
    (1 )
Other Revenues
    17  
Total Change in Gross Margin
    180  
 
       
Total Expenses and Other:
       
Other Operation and Maintenance
    18  
Depreciation and Amortization
    (78 )
Taxes Other Than Income Taxes
    (2 )
Carrying Costs Income
    (6 )
Other Income
    (5 )
Interest Expense
    21  
Total Expenses and Other
    (52 )
 
       
Income Tax Expense
    (51 )
 
       
Year Ended December 31, 2009
  $ 309  

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 power were as follows:

·
Retail Margins increased $283 million primarily due to the following:
 
·
A $148 million increase related to the implementation of higher rates set by the Ohio ESP.
 
·
A $142 million increase in fuel margins primarily due to the deferral of fuel costs in 2009.  The PUCO’s March 2009 approval of OPCo’s ESP allows for the deferral of fuel and related costs incurred during the ESP period.
 
·
A $61 million increase in capacity settlements under the Interconnection Agreement.
 
·
A $42 million increase due to the December 2008 provision for refund of off-system sales margins as ordered by the FERC related to the SIA.
 
These increases were partially offset by:
 
·
An $86 million decrease in industrial sales due to reduced operating levels and suspended operations by certain large industrial customers in OPCo’s service territory.
 
·
A $29 million decrease related to coal contract amendments recorded in 2008.
·
Margins from Off-system Sales decreased $119 million primarily due to lower physical sales volumes and lower margins as a result of lower market prices, partially offset by higher trading and marketing margins.
·
Other Revenues increased $17 million primarily due to net gains on the sale of emission allowances.

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

·
Other Operation and Maintenance expenses decreased $18 million primarily due to:
 
·
A $13 million decrease in removal and plant maintenance expenses from a reduction in planned and forced outages at various plants during 2009.  During 2008, the precipitator upgrade and boiler overhauls at Amos Plant had increased expense.
 
·
A $9 million decrease in employee benefit expenses.
 
 
194
 
 
·
A $9 million decrease in recoverable PJM expenses.
 
·
An $8 million decrease in recoverable customer account expenses due to decreased Universal Service Fund surcharge rates for customers who qualify for payment assistance.
 
·
A $5 million decrease in transmission expenses related to the AEP Transmission Equalization Agreement.
 
These decreases were partially offset by:
 
·
A $19 million increase in maintenance of overhead lines primarily due to an increase in vegetation management activities.
 
·
An $11 million increase relating to a coal blending project.
·
Depreciation and Amortization increased $78 million primarily due to:
 
·
An $82 million increase from higher depreciable property balances as a result of environmental improvements placed in service and various other property additions and higher depreciation rates related to shortened depreciable lives for certain generating facilities.
 
·
A $22 million increase due to the completion of the amortization of a regulatory liability in December 2008 related to energy sales to Ormet at below market rates.
 
These increases were partially offset by:
 
·
A $28 million decrease due to the completion of the amortization of regulatory assets in December 2008.
·
Interest Expense decreased $21 million primarily due to:
 
·
A $20 million decrease in interest expense primarily related to the December 2008 provision for refund of off-system sales margins in accordance with FERC’s order related to the SIA.
 
·
A $7 million decrease in interest expense related to the reacquisition of JMG’s bonds during the third quarter of 2009 at lower interest rates.
 
·
A $7 million decrease in interest expense primarily due to an unrealized gain on an interest rate hedge of a forecasted debt issuance.
 
These decreases were partially offset by:
 
·
A $15 million increase primarily related to a decrease in the debt component of AFUDC as a result of the Amos Plant FGD and precipitator upgrade going into service in the first quarter of 2009.
·
Income Tax Expense increased $51 million primarily due to an increase in pretax book income.

FINANCIAL CONDITION

LIQUIDITY

OPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  OPCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures.  See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 405 for additional discussion of liquidity.

Credit Ratings

OPCo’s ultimate access to capital markets may depend on its credit ratings.  In addition, a credit rating downgrade of OPCo by one of the rating agencies could increase OPCo’s borrowing costs.  Failure to maintain investment grade ratings may constrain OPCo’s ability to participate in the Utility Money Pool or the amount of OPCo’s receivables securitized by AEP Credit.  Counterparty concerns about OPCo’s credit quality could subject OPCo to additional collateral demands under adequate assurance clauses under derivative and non-derivative energy contracts.

 
195
 
CASH FLOW

Cash flows for 2010, 2009 and 2008 were as follows:

 
 
Years Ended December 31,
 
 
 
2010
   
2009
   
2008
 
 
 
(in thousands)
 
Cash and Cash Equivalents at Beginning of Period
  $ 1,984     $ 12,679     $ 6,666  
Cash Flows from (Used for):
                       
Operating Activities
    821,807       321,034       485,877  
Investing Activities
    73,112       (812,981 )     (701,789 )
Financing Activities
    (896,463 )     481,252       221,925  
Net Increase (Decrease) in Cash and Cash Equivalents
    (1,544 )     (10,695 )     6,013  
Cash and Cash Equivalents at End of Period
  $ 440     $ 1,984     $ 12,679  

Operating Activities

Net Cash Flows from Operating Activities were $822 million in 2010.  OPCo produced Net Income of $311 million during the period and noncash expense items of $362 million for Depreciation and Amortization and $218 million for Deferred Income Taxes.  The other changes in assets and liabilities 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.  The current period activity in working capital relates to a number of items.  Accrued Taxes, Net had an $87 million inflow due to a 2010 income tax refund of $138 million as a result of a federal net income tax operating loss in 2009 that was carried back to 2007 and 2008.  Fuel, Materials and Supplies had a $65 million inflow primarily due to a decrease in coal inventory to target levels as well as price decreases due to the expiration of higher priced spot market contracts.  The $154 million change in Fuel Over/Under-Recovery, Net reflects the deferral of fuel costs as a fuel clause was reactivated in 2009 under OPCo’s ESP.

Net Cash Flows from Operating Activities were $321 million in 2009.  OPCo produced Net Income of $309 million during the period and noncash expense items of $352 million for Depreciation and Amortization and $383 million for Deferred Income Taxes.  The $383 million inflow for Deferred Income Taxes was primarily due to the American Recovery and Reinvestment Act of 2009 extending bonus depreciation provisions, a change in tax accounting method and an increase in tax versus book temporary differences from operations.  The other changes in assets and liabilities 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.  The current period activity in working capital primarily relates to a number of items.  Fuel, Materials and Supplies had a $156 million outflow primarily due to an increase in coal inventory reflecting decreased customer demand for electricity.  Accounts Payable had a $121 million outflow primarily due to OPCo’s provision for revenue refund of $62 million which was paid in the first quarter of 2009 to the AEP West companies as part of the FERC’s order on the SIA.  Accrued Taxes, Net had a $119 million outflow due to an increase in accrued tax benefits resulting from a net income tax operating loss in 2009.  The $298 million change in Fuel Over/Under-Recovery, Net reflects the deferral of fuel costs as a fuel clause was reactivated in 2009 under OPCo’s ESP.

Net Cash Flows from Operating Activities were $486 million in 2008.  OPCo produced Net Income of $232 million during the period and a noncash expense item of $274 million for Depreciation and Amortization.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital and changes in the future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a number of items.  Accounts Payable had a $127 million inflow due to increases in tonnage and prices per ton related to fuel and consumable purchases and also included OPCo’s December 2008 provision for refund of $62 million which was paid in the first quarter of 2009 to the AEP West companies as part of the FERC’s order on the SIA.  Fuel, Materials and Supplies had an $89 million outflow due to price increases.

 
196
 
Investing Activities

Net Cash Flows from Investing Activities were $73 million in 2010.  Net Cash Flows Used for Investing Activities were $813 million in 2009 and $702 million in 2008.  OPCo had a net decrease of $338 million and a net increase of $438 million in loans to the Utility Money Pool during 2010 and 2009, respectively.  Construction Expenditures of $277 million, $418 million and $706 million in 2010, 2009 and 2008, respectively, were primarily related to environmental upgrades and projects to improve service reliability for transmission and distribution.  Environmental upgrades include the installation of FGD projects at the Amos and Cardinal Plants.

Financing Activities

Net Cash Flows Used for Financing Activities were $896 million in 2010.  OPCo retired $600 million of Senior Unsecured Notes and $118 million of Pollution Control Bonds.  In addition, OPCo paid $367 million of dividends on common stock.  These decreases were partially offset by the issuance of $204 million of Pollution Control Bonds.

Net Cash Flows from Financing Activities were $481 million in 2009 primarily due to a $550 million Capital Contribution from Parent as well as a $500 million issuance of Senior Unsecured Notes.  These increases were partially offset by a $218 million reaquisition of Pollution Control Bonds related to JMG and a $78 million retirement of Notes Payable – Nonaffiliated.  OPCo also had a net decrease in borrowings of $134 million from the Utility Money Pool and paid $95 million in common stock dividends to Parent.

Net Cash Flows from Financing Activities were $222 million in 2008.  OPCo issued $244 million of Pollution Control Bonds and $250 million of Senior Unsecured Notes.  These increases were partially offset by the retirement of $250 million of Pollution Control Bonds, $37 million of Senior Unsecured Notes and $18 million of Notes Payable – Nonaffiliated.

 
197
 
CONTRACTUAL OBLIGATION INFORMATION

OPCo’s contractual cash obligations include amounts reported on OPCo’s Consolidated Balance Sheets and other obligations disclosed in the footnotes.  The following table summarizes OPCo’s contractual cash obligations at December 31, 2010:

 
Payments Due by Period
 
 
 
 
 
 
Less Than
 
 
 
 
 
After
 
 
 
Contractual Cash Obligations
 
1 year
 
2-3 years
 
4-5 years
 
5 years
 
Total
 
 
 
 
(in millions)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest on Fixed Rate Portion of Long-term Debt (a)
 
$
 140.4 
 
$
 274.0 
 
$
 198.0 
 
$
 814.2 
 
$
 1,426.6 
 
Fixed Rate Portion of Long-term Debt (b)
 
 
 - 
 
 
 500.0 
 
 
 629.6 
 
 
 1,440.0 
 
 
 2,569.6 
 
Variable Rate Portion of Long-term Debt (c)
 
 
 165.0 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 165.0 
 
Capital Lease Obligations (d)
 
 
 11.7 
 
 
 18.3 
 
 
 11.4 
 
 
 22.0 
 
 
 63.4 
 
Noncancelable Operating Leases (d)
 
 
 20.7 
 
 
 38.4 
 
 
 36.1 
 
 
 71.4 
 
 
 166.6 
 
Fuel Purchase Contracts (e)
 
 
 887.8 
 
 
 1,546.7 
 
 
 1,184.4 
 
 
 2,551.6 
 
 
 6,170.5 
 
Energy and Capacity Purchase Contracts (f)
 
 
 6.5 
 
 
 8.8 
 
 
 3.4 
 
 
 21.5 
 
 
 40.2 
 
Construction Contracts for Capital Assets (g)
 
 
 43.3 
 
 
 62.4 
 
 
 65.5 
 
 
 109.0 
 
 
 280.2 
 
Total
 
$
 1,275.4 
 
$
 2,448.6 
 
$
 2,128.4 
 
$
 5,029.7 
 
$
 10,882.1 

(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2010 and do not reflect anticipated future refinancings, early redemptions or debt issuances.
(b)
See “Long-term Debt” section of Note 14.  Represents principal only excluding interest.
(c)
See “Long-term Debt” section of Note 14.  Represents principal only excluding interest.  Variable rate debt had interest rates that ranged between 0.30% and 0.48% at December 31, 2010.
(d)
See Note 13.
(e)
Represents contractual obligations to purchase coal and other consumables as fuel for electric generation along with related transportation of the fuel.
(f)
Represents contractual obligations for energy and capacity purchase contracts.
(g)
Represents only capital assets for which OPCo has 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.

OPCo’s $21 million liability related to uncertainty in Income Taxes is not included above because management cannot reasonably estimate the cash flows by period.

OPCo’s pension funding requirements are not included in the above table.  As of December 31, 2010, management expects to make contributions to the pension plans totaling $12.6 million in 2011.  Estimated contributions of $17.9 million in 2012 and $18 million in 2013 may vary significantly based on market returns, changes in actuarial assumptions and other factors.  Based upon the benefit obligation and fair value of assets available to pay pension benefits, OPCo’s pension plan obligation was 82.3% funded as of December 31, 2010.

 
198
 
In addition to the amounts disclosed in the contractual cash obligations table above, OPCo makes additional commitments in the normal course of business.  OPCo’s commitments outstanding at December 31, 2010 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)
 
$
 166.9 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 166.9 

(a)
OPCo enters into standby letters of credit (LOCs) with third parties.  These LOCs cover items such as insurance programs, security deposits, debt service reserves and variable rate Pollution Control Bonds.  All of these LOCs were issued in OPCo’s ordinary course of business.  There is no collateral held in relation to any guarantees in excess of OPCo's ownership percentages.  In the event any LOC is drawn, there is no recourse to third parties.  The maximum future payments of these LOCs are $166.9 million maturing in April 2011.  See “Letters of Credit” section of Note 6.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 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 “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 for a discussion of the adoption and impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

See “Quantitative And Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 for a discussion of risk management activities.

 
199
 


 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
To the Board of Directors and Shareholders of
Ohio Power Company:
 
 
We have audited the accompanying consolidated balance sheets of Ohio Power Company Consolidated (the "Company") as of December 31, 2010 and 2009, and the related consolidated statements of income, changes in equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010.  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   Consolidated as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
 
 
/s/ Deloitte & Touche LLP
 
 
Columbus, Ohio
February 25, 2011
 

 
200
 

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Ohio Power Company Consolidated (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, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment, OPCo’s internal control over financial reporting was effective as of December 31, 2010.

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.

 
201
 

OHIO POWER COMPANY CONSOLIDATED
 
CONSOLIDATED STATEMENTS OF INCOME
 
For the Years Ended December 31, 2010, 2009 and 2008
 
(in thousands)
 
 
 
 
 
2010
   
2009
   
2008
 
REVENUES
 
 
   
 
   
 
 
Electric Generation, Transmission and Distribution
  $ 2,159,206     $ 1,941,257     $ 2,116,797  
Sales to AEP Affiliates
    1,025,923       1,034,290       940,468  
Other Revenues - Affiliated
    21,069       23,457       20,732  
Other Revenues - Nonaffiliated
    17,509       12,570       18,937  
TOTAL REVENUES
    3,223,707       3,011,574       3,096,934  
 
                       
EXPENSES
                       
Fuel and Other Consumables Used for Electric Generation
    1,088,588       988,520       1,190,939  
Purchased Electricity for Resale
    180,721       178,123       175,429  
Purchased Electricity from AEP Affiliates
    93,971       74,598       140,686  
Other Operation
    446,264       386,323       414,945  
Maintenance
    238,356       224,439       213,431  
Depreciation and Amortization
    361,728       352,068       273,720  
Taxes Other Than Income Taxes
    206,277       194,310       192,734  
TOTAL EXPENSES
    2,615,905       2,398,381       2,601,884  
 
                       
OPERATING INCOME
    607,802       613,193       495,050  
 
                       
Other Income (Expense):
                       
Interest Income
    1,648       1,436       6,515  
Carrying Costs Income
    23,630       10,698       16,309  
Allowance for Equity Funds Used During Construction
    3,877       2,712       3,073  
Interest Expense
    (156,107 )     (152,950 )     (173,870 )
 
                       
INCOME BEFORE INCOME TAX EXPENSE
    480,850       475,089       347,077  
 
                       
Income Tax Expense
    169,457       166,474       114,622  
 
                       
NET INCOME
    311,393       308,615       232,455  
 
                       
Less: Net Income Attributable to Noncontrolling Interest
    -       2,042       1,332  
 
                       
NET INCOME ATTRIBUTABLE TO OPCo SHAREHOLDERS
    311,393        306,573       231,123  
 
                       
Less: Preferred Stock Dividend Requirements
    732       732       732  
 
                       
EARNINGS ATTRIBUTABLE TO OPCo COMMON SHAREHOLDER
  $ 310,661     $ 305,841     $ 230,391  
 
                       
The common stock of OPCo is wholly-owned by AEP.
                       
 
                       
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 

 
202
 

OHIO POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CHANGES IN
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2010, 2009 and 2008
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPCo Common Shareholder
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
 
 
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
Noncontrolling
 
 
 
 
Stock
 
Capital
 
Earnings
 
Income (Loss)
 
Interest
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY – DECEMBER 31, 2007
 
$
 321,201 
 
$
 536,640 
 
$
 1,469,717 
 
$
 (36,541)
 
$
 15,923 
 
$
 2,306,940 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Adoption of Guidance for Split-Dollar Life Insurance
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accounting, Net of Tax of $1,004
 
 
 
 
 
 
 
 
 (1,864)
 
 
 
 
 
 
 
 
 (1,864)
Adoption of Guidance for Fair Value Accounting,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $152
 
 
 
 
 
 
 
 
 (282)
 
 
 
 
 
 
 
 
 (282)
Common Stock Dividends – Nonaffilated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (1,332)
 
 
 (1,332)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (732)
 
 
 
 
 
 
 
 
 (732)
Other Changes in Equity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 876 
 
 
 876 
SUBTOTAL – EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 2,303,606 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $1,343
 
 
 
 
 
 
 
 
 
 
 
 2,493 
 
 
 
 
 
 2,493 
 
 
Amortization of Pension and OPEB Deferred Costs,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $1,515
 
 
 
 
 
 
 
 
 
 
 
 2,813 
 
 
 
 
 
 2,813 
 
 
Pension and OPEB Funded Status,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $55,259
 
 
 
 
 
 
 
 
 
 
 
 (102,623)
 
 
 
 
 
 (102,623)
NET INCOME
 
 
 
 
 
 
 
 
 231,123 
 
 
 
 
 
 1,332 
 
 
 232,455 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 135,138 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY – DECEMBER 31, 2008
 
 
 321,201 
 
 
 536,640 
 
 
 1,697,962 
 
 
 (133,858)
 
 
 16,799 
 
 
 2,438,744 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital Contribution from Parent
 
 
 
 
 
 550,000 
 
 
 
 
 
 
 
 
 
 
 
 550,000 
Common Stock Dividends – Affiliated
 
 
 
 
 
 
 
 
 (95,000)
 
 
 
 
 
 
 
 
 (95,000)
Common Stock Dividends – Nonaffiliated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (2,042)
 
 
 (2,042)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (732)
 
 
 
 
 
 
 
 
 (732)
Purchase of JMG
 
 
 
 
 
 36,509 
 
 
 
 
 
 
 
 
 (17,910)
 
 
 18,599 
Other Changes in Equity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,111 
 
 
 1,111 
SUBTOTAL – EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 2,910,680 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income, Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $4,392
 
 
 
 
 
 
 
 
 
 
 
 8,156 
 
 
 
 
 
 8,156 
 
 
Amortization of Pension and OPEB Deferred Costs,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $3,421
 
 
 
 
 
 
 
 
 
 
 
 6,353 
 
 
 
 
 
 6,353 
 
 
Pension and OPEB Funded Status, Net of Tax of $480
 
 
 
 
 
 
 
 
 
 
 
 891 
 
 
 
 
 
 891 
NET INCOME
 
 
 
 
 
 
 
 
 306,573 
 
 
 
 
 
 2,042 
 
 
 308,615 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 324,015 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY – DECEMBER 31, 2009
 
 
 321,201 
 
 
 1,123,149 
 
 
 1,908,803 
 
 
 (118,458)
 
 
 - 
 
 
 3,234,695 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (366,575)
 
 
 
 
 
 
 
 
 (366,575)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (732)
 
 
 
 
 
 
 
 
 (732)
Gain on Reacquired Preferred Stock
 
 
 
 
 
 4 
 
 
 
 
 
 
 
 
 
 
 
 4 
SUBTOTAL – EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 2,867,392 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $659
 
 
 
 
 
 
 
 
 
 
 
 (1,223)
 
 
 
 
 
 (1,223)
 
 
Amortization of Pension and OPEB Deferred Costs,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $3,795
 
 
 
 
 
 
 
 
 
 
 
 7,047 
 
 
 
 
 
 7,047 
 
 
Pension and OPEB Funded Status, Net of Tax of $8,715
 
 
 
 
 
 
 
 
 
 
 
 (16,185)
 
 
 
 
 
 (16,185)
NET INCOME
 
 
 
 
 
 
 
 
 311,393 
 
 
 
 
 
 
 
 
 311,393 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 301,032 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY – DECEMBER 31, 2010
 
$
 321,201 
 
$
 1,123,153 
 
$
 1,852,889 
 
$
 (128,819)
 
$
 - 
 
$
 3,168,424 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.

 
203
 
 
OHIO POWER COMPANY CONSOLIDATED
 
CONSOLIDATED BALANCE SHEETS
 
ASSETS
 
December 31, 2010 and 2009
 
(in thousands)
 
 
 
 
 
2010
   
2009
 
CURRENT ASSETS
 
 
   
 
 
Cash and Cash Equivalents
  $ 440     $ 1,984  
Advances to Affiliates
    100,500       438,352  
Accounts Receivable:
               
Customers
    86,186       60,711  
Affiliated Companies
    198,845       200,579  
Accrued Unbilled Revenues
    27,928       15,021  
Miscellaneous
    2,368       2,701  
Allowance for Uncollectible Accounts
    (2,184 )     (2,665 )
Total Accounts Receivable
    313,143       276,347  
Fuel
    257,289       336,866  
Materials and Supplies
    134,181       115,486  
Risk Management Assets
    30,773       50,048  
Accrued Tax Benefits
    69,021       143,473  
Prepayments and Other Current Assets
    33,998       26,301  
TOTAL CURRENT ASSETS
    939,345       1,388,857  
 
               
PROPERTY, PLANT AND EQUIPMENT
               
Electric:
               
Generation
    6,890,110       6,731,469  
Transmission
    1,234,677       1,166,557  
Distribution
    1,626,390       1,567,871  
Other Property, Plant and Equipment
    359,254       348,718  
Construction Work in Progress
    153,110       198,843  
Total Property, Plant and Equipment
    10,263,541       10,013,458  
Accumulated Depreciation and Amortization
    3,606,777       3,318,896  
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    6,656,764       6,694,562  
 
               
OTHER NONCURRENT ASSETS
               
Regulatory Assets
    934,011       742,905  
Long-term Risk Management Assets
    28,012       28,003  
Deferred Charges and Other Noncurrent Assets
    189,195       184,812  
TOTAL OTHER NONCURRENT ASSETS
    1,151,218       955,720  
 
               
TOTAL ASSETS
  $ 8,747,327     $ 9,039,139  
 
               
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 
 
 
204
 
OHIO POWER COMPANY CONSOLIDATED
 
CONSOLIDATED BALANCE SHEETS
 
LIABILITIES AND EQUITY
 
December 31, 2010 and 2009
 
 
 
 
 
2010
   
2009
 
 
 
(in thousands)
 
CURRENT LIABILITIES
 
 
   
 
 
Accounts Payable:
 
 
   
 
 
General
  $ 170,240     $ 182,848  
Affiliated Companies
    136,215       92,766  
Long-term Debt Due Within One Year – Nonaffiliated
    165,000       679,450  
Risk Management Liabilities
    22,166       24,391  
Customer Deposits
    28,228       22,409  
Accrued Taxes
    229,253       203,335  
Accrued Interest
    46,184       46,431  
Other Current Liabilities
    98,687       104,889  
TOTAL CURRENT LIABILITIES
    895,973       1,356,519  
 
               
NONCURRENT LIABILITIES
               
Long-term Debt – Nonaffiliated
    2,364,522       2,363,055  
Long-term Debt – Affiliated
    200,000       200,000  
Long-term Risk Management Liabilities
    8,403       12,510  
Deferred Income Taxes
    1,531,639       1,302,939  
Regulatory Liabilities and Deferred Investment Tax Credits
    126,403       128,187  
Employee Benefits and Pension Obligations
    246,517       269,485  
Deferred Credits and Other Noncurrent Liabilities
    188,830       155,122  
TOTAL NONCURRENT LIABILITIES
    4,666,314       4,431,298  
 
               
TOTAL LIABILITIES
    5,562,287       5,787,817  
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
    16,616       16,627  
 
               
Rate Matters (Note 4)
               
Commitments and Contingencies (Note 6)
               
 
               
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
    1,123,153       1,123,149  
Retained Earnings
    1,852,889       1,908,803  
Accumulated Other Comprehensive Income (Loss)
    (128,819 )     (118,458 )
TOTAL COMMON SHAREHOLDER’S EQUITY
    3,168,424       3,234,695  
 
               
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY
  $ 8,747,327     $ 9,039,139  
 
               
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 

 
205
 

OHIO POWER COMPANY CONSOLIDATED
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
For the Years Ended December 31, 2010, 2009 and 2008
 
(in thousands)
 
 
 
 
   
 
   
 
 
 
 
2010
   
2009
   
2008
 
OPERATING ACTIVITIES
 
 
   
 
   
 
 
Net Income
  $ 311,393     $ 308,615     $ 232,455  
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
                       
Depreciation and Amortization
    361,728       352,068       273,720  
Deferred Income Taxes
    218,246       382,794       42,717  
Carrying Costs Income
    (23,630 )     (10,698 )     (16,309 )
Allowance for Equity Funds Used During Construction
    (3,877 )     (2,712 )     (3,073 )
Mark-to-Market of Risk Management Contracts
    13,444       (5,486 )     (13,839 )
Pension Contributions to Qualified Plan Trust
    (51,641 )     -       -  
Property Taxes
    (6,861 )     (7,109 )     (5,507 )
Fuel Over/Under-Recovery, Net
    (153,643 )     (297,570 )     -  
Change in Other Noncurrent Assets
    3,200       4,913       (48,653 )
Change in Other Noncurrent Liabilities
    (6,418 )     35,130       (10,445 )
Changes in Certain Components of Working Capital:
                       
Accounts Receivable, Net
    (38,066 )     (29,927 )     5,104  
Fuel, Materials and Supplies
    64,801       (155,557 )     (89,058 )
Accounts Payable
    43,060       (121,117 )     126,716  
Customer Deposits
    5,819       (1,924 )     (6,280 )
Accrued Taxes, Net
    87,476       (119,428 )     (11,210 )
Other Current Assets
    (1,310 )     2,877       (10,730 )
Other Current Liabilities
    (1,914 )     (13,835 )     20,269  
Net Cash Flows from Operating Activities
    821,807       321,034       485,877  
 
                       
INVESTING ACTIVITIES
                       
Construction Expenditures
    (276,736 )     (417,601 )     (706,315 )
Change in Advances to Affiliates, Net
    337,852       (438,352 )     -  
Acquisitions of Assets
    (5,059 )     (1,197 )     (2,033 )
Proceeds from Sales of Assets
    17,211       38,640       8,293  
Other Investing Activities
    (156 )     5,529       (1,734 )
Net Cash Flows from (Used for) Investing Activities
    73,112       (812,981 )     (701,789 )
 
                       
FINANCING ACTIVITIES
                       
Capital Contribution from Parent
    -       550,000       -  
Issuance of Long-term Debt – Nonaffiliated
    202,380       493,775       491,204  
Change in Short-term Debt, Net – Nonaffiliated
    -       -       (701 )
Change in Advances from Affiliates, Net
    -       (133,887 )     32,339  
Retirement of Long-term Debt – Nonaffiliated
    (718,580 )     (295,500 )     (305,188 )
Retirement of Cumulative Preferred Stock
    (7 )     (1 )     -  
Principal Payments for Capital Lease Obligations
    (7,447 )     (4,271 )     (5,736 )
Dividends Paid on Common Stock – Nonaffiliated
    -       (2,042 )     (1,332 )
Dividends Paid on Common Stock – Affiliated
    (366,575 )     (95,000 )     -  
Dividends Paid on Cumulative Preferred Stock
    (732 )     (732 )     (732 )
Acquisition of JMG Noncontrolling Interest
    -       (28,221 )     -  
Other Financing Activities
    (5,502 )     (2,869 )     12,071  
Net Cash Flows from (Used for) Financing Activities
    (896,463 )     481,252       221,925  
 
                       
Net Increase (Decrease) in Cash and Cash Equivalents
    (1,544 )     (10,695 )     6,013  
Cash and Cash Equivalents at Beginning of Period
    1,984       12,679       6,666  
Cash and Cash Equivalents at End of Period
  $ 440     $ 1,984     $ 12,679  
 
                       
SUPPLEMENTARY INFORMATION
                       
Cash Paid for Interest, Net of Capitalized Amounts
  $ 154,744     $ 147,573     $ 144,790  
Net Cash Paid (Received) for Income Taxes
    (115,073 )     (62,704 )     100,430  
Noncash Acquisitions Under Capital Leases
    23,736       2,383       3,910  
Noncash Acquisitions of Coal Land Rights
    -       -       41,600  
Construction Expenditures Included in Accounts Payable at December 31,
    17,710       29,929       33,177  
SIA Refund Included in Accounts Payable at December 31,
    -       -       62,045  
 
                       
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 

 
206
 

OHIO POWER COMPANY CONSOLIDATED
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 246.

 
Footnote
Reference
   
Organization and Summary of Significant Accounting Policies
Note 1
New Accounting Pronouncements and Extraordinary Item
Note 2
Rate Matters
Note 4
Effects of Regulation
Note 5
Commitments, Guarantees and Contingencies
Note 6
Benefit Plans
Note 8
Business Segments
Note 9
Derivatives and Hedging
Note 10
Fair Value Measurements
Note 11
Income Taxes
Note 12
Leases
Note 13
Financing Activities
Note 14
Related Party Transactions
Note 15
Property, Plant and Equipment
Note 16
Cost Reduction Initiatives
Note 17
Unaudited Quarterly Financial Information
Note 18

 
207
 













PUBLIC SERVICE COMPANY OF OKLAHOMA


 
208
 

PUBLIC SERVICE COMPANY OF OKLAHOMA
SELECTED FINANCIAL DATA
(in thousands)
 
 
 
 
 
2010 
 
2009 
 
2008 
 
2007 
 
2006 
STATEMENTS OF OPERATIONS DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
 
$
 1,273,662 
 
$
 1,124,750 
 
$
 1,655,945 
(a)
$
 1,395,550 
 
$
 1,441,784 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating Income (Loss)
 
$
 181,992 
 
$
 170,308 
 
$
 160,463 
(a)(b)
$
 (4,835)
(c)
$
 90,993 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss)
 
$
 72,787 
 
$
 75,602 
 
$
 78,484 
(a)(b)
$
 (24,124)
(c)
$
 36,860 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
BALANCE SHEETS DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and Equipment
 
$
 3,975,329 
 
$
 3,809,558 
 
$
 3,692,011 
 
$
 3,459,181 
 
$
 3,186,294 
Accumulated Depreciation and Amortization
 
 
 1,255,064 
 
 
 1,220,177 
 
 
 1,192,130 
 
 
 1,182,171 
 
 
 1,187,107 
Total Property, Plant and Equipment – Net
 
$
 2,720,265 
 
$
 2,589,381 
 
$
 2,499,881 
 
$
 2,277,010 
 
$
 1,999,187 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
 3,284,071 
 
$
 3,169,207 
 
$
 3,100,798 
 
$
 2,843,871 
 
$
 2,565,579 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Common Shareholder's Equity
 
$
 842,472 
 
$
 811,742 
 
$
 748,246 
 
$
 640,898 
 
$
 585,438 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cumulative Preferred Stock Not Subject to
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mandatory Redemption
 
$
 4,882 
 
$
 5,258 
 
$
 5,262 
 
$
 5,262 
 
$
 5,262 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt (d)
 
$
 971,186 
 
$
 968,121 
 
$
 884,859 
 
$
 918,316 
 
$
 669,998 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Obligations Under Capital Leases (d)
 
$
 18,389 
(e)
$
 5,470 
 
$
 3,478 
 
$
 4,028 
 
$
 4,816 

(a)
Includes the net favorable effect of the recognition of off-system sales margins as ordered by the FERC in November 2008.  See “Allocation of Off-system Sales Margins” section of Note 4.
(b)
Includes the favorable effect of the 2008 deferral of Oklahoma ice storm expenses incurred in 2007.
(c)
Includes expenses incurred from ice storms in January and December 2007.
(d)
Includes portion due within one year.
(e)
Obligations Under Capital Leases increased primarily due to capital leases under new master lease agreements for property that was previously leased under operating leases.

 
209
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

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 532,000 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 member of the CSW 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.

Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and 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.

AEPSC conducts power, gas, coal and emission allowance 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 gas risk management activities are allocated based on the CSW Operating Agreement and the SIA.  PSO shares in coal and emission 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 gas, coal and emission allowances.  The electricity, gas, coal and emission allowance 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.

PSO is jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to purchase power and sale activity pursuant to the SIA.

Regulatory Activity

In July 2010, PSO filed a request with the OCC to increase annual base rates by $82 million, including $30 million that is currently being recovered through a rider.  The requested net annual increase to ratepayers would be $52 million.  The requested increase included a $24 million increase in depreciation and an 11.5% return on common equity.  In January 2011, the OCC approved a settlement agreement which did not change annual revenue or depreciation rates, but transferred $30 million into base rates that was previously being recovered through a capital investment rider.  The order provided a 10.15% return on common equity and new rates were effective in February 2011.  See “2010 Oklahoma Base Rate Case” section of Note 4.

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 state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be.  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 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

 
210
 
See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 405 for additional discussion of relevant factors.

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
2010 
 
2009 
 
2008 
 
 
(in millions of KWH)
Retail:
 
 
 
 
 
 
 
 
 
Residential
 
 6,595 
 
 
 6,004 
 
 
 5,997 
 
Commercial
 
 5,136 
 
 
 4,974 
 
 
 4,890 
 
Industrial
 
 4,921 
 
 
 4,742 
 
 
 5,551 
 
Miscellaneous
 
 1,265 
 
 
 1,236 
 
 
 1,315 
Total Retail
 
 17,917 
 
 
 16,956 
 
 
 17,753 
 
 
 
 
 
 
 
 
 
Wholesale
 
 1,190 
 
 
 982 
 
 
 949 
 
 
 
 
 
 
 
 
 
Total KWHs
 
 19,107 
 
 
 17,938 
 
 
 18,702 

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,
 
 
 
2010 
 
2009 
 
2008 
 
 
 
(in degree days)
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 1,993 
 
 
 1,840 
 
 
 1,864 
 
Normal - Heating (b)
 
 1,784 
 
 
 1,789 
 
 
 1,809 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 2,380 
 
 
 1,861 
 
 
 2,003 
 
Normal - Cooling (b)
 
 2,095 
 
 
 2,126 
 
 
 2,130 
 
 
 
 
 
 
 
 
 
 
 
 
(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.

 
211
 
2010 Compared to 2009
 
 
 
 
 
Reconciliation of Year Ended December 31, 2009 to Year Ended December 31, 2010
 
Net Income
 
(in millions)
 
 
 
 
 
Year Ended December 31, 2009
  $ 76  
 
       
Changes in Gross Margin:
       
Retail Margins (a)
    52  
Transmission Revenues
    1  
Other Revenues
    (1 )
Total Change in Gross Margin
    52  
 
       
Total Expenses and Other:
       
Other Operation and Maintenance
    (45 )
Depreciation and Amortization
    5  
Taxes Other Than Income Taxes
    (1 )
Other Income
    (4 )
Interest Expense
    (4 )
Total Expenses and Other
    (49 )
 
       
Income Tax Expense
    (6 )
 
       
Year Ended December 31, 2010
  $ 73  
 
(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 power were as follows:

·
Retail Margins increased $52 million primarily due to the following:
 
·
A $37 million increase primarily due to rate increases.
 
·
A $27 million increase in weather-related usage primarily due to a 28% increase in cooling degree days and an 8% increase in heating degree days.
 
These increases were partially offset by:
 
·
A $10 million decrease primarily due to lower wholesale municipal customer revenues and increased capacity and fuel costs.

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

·
Other Operation and Maintenance expenses increased $45 million primarily due to the following:
 
·
A $24 million increase primarily due to expenses related to cost reduction initiatives.  In 2010, management conducted cost reduction initiatives to reduce both labor and non-labor expenses.
 
·
A $9 million increase in demand side management programs.
 
·
A $7 million increase in plant maintenance expense resulting primarily from the 2009 deferral of generation maintenance expenses as a result of PSO’s 2008 base rate case.
 
·
A $5 million increase in employee-related expenses.
·
Depreciation and Amortization expenses decreased $5 million primarily due to a decrease in amortization of regulatory assets related to Generation Cost Recovery (GCR) and the Lawton Settlement which were fully recovered in August 2009 and August 2010, respectively.  The decrease was partially offset by an increase in depreciation on higher levels of depreciable plant and by the amortization of storm-related regulatory assets.
 
 
212
 
·
Other Income decreased $4 million primarily due to the following:
 
·
A $2 million decrease in interest income primarily due to the Lawton Settlement regulatory asset.
 
·
A $1 million decrease in carrying charges for GCR and storm-related regulatory assets.
·
Interest Expense increased $4 million primarily due to increased long-term debt outstanding.
·
Income Tax Expense increased $6 million due to the recording of state income tax adjustments and to an increase in pretax book income.

 
213
 
2009 Compared to 2008
 
 
 
 
 
Reconciliation of Year Ended December 31, 2008 to Year Ended December 31, 2009
 
Net Income
 
(in millions)
 
 
 
 
 
Year Ended December 31, 2008
  $ 78  
 
       
Changes in Gross Margin:
       
Retail Margins (a)
    75  
Off-system Sales
    (3 )
Transmission Revenues
    2  
Other Revenues
    (11 )
Total Change in Gross Margin
    63  
 
       
Total Expenses and Other:
       
Other Operation and Maintenance
    29  
Deferral of Ice Storm Costs
    (74 )
Depreciation and Amortization
    (5 )
Taxes Other Than Income Taxes
    (3 )
Other Income
    (23 )
Carrying Costs Income
    (5 )
Interest Expense
    18  
Total Expenses and Other
    (63 )
 
       
Income Tax Expense
    (2 )
 
       
Year Ended December 31, 2009
  $ 76  
 
(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 power were as follows:

·
Retail Margin s increased $75 million primarily due to the following:
 
·
An $86 million increase primarily resulting from base rate increases during the year, including revenue increases from rate riders of $22 million.  This increase in rider revenue was offset by a corresponding $14 million increase in Other Operation and Maintenance expenses and a $4 million increase in Depreciation and Amortization expenses discussed below.
 
This increase was partially offset by:
 
·
A $14 million decrease due to the net favorable effect of the recognition of off-system sales margins as ordered by the FERC in November 2008.
·
Other Revenues decreased $11 million primarily due to the recognition of the sale of SO 2 allowances in 2008, partially offset by a corresponding $9 million decrease in Other Operation and Maintenance expenses discussed below.

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

·
Other Operation and Maintenance expenses decreased $29 million primarily due to the following:
 
·
The write-off in 2008 of $10 million of unrecoverable pre-construction costs related to the cancelled Red Rock Generating Facility.
 
·
An $8 million decrease in plant maintenance expense primarily due to the deferral of generation maintenance expenses as a result of PSO’s 2008 base rate case.
 
·
A $5 million decrease in contributions.
 
·
A $4 million decrease primarily resulting from the reduced sale of receivable expense due to decreased revenues.
 
 
214
 
 
·
A $3 million decrease in expense related to maintenance of overhead transmission lines and miscellaneous transmission maintenance expenses.
 
These decreases were partially offset by:
 
·
A $5 million net increase due to increased amortization of regulatory assets and liabilities related to the 2007 ice storm, demand side management and distribution vegetation management, offset by a corresponding increase in rider revenue discussed above.
·
Deferral of Ice Storm Costs in 2008 of $74 million results from an OCC order approving recovery of ice storm costs incurred in January and December 2007.
·
Depreciation and Amortization expenses increased $5 million primarily due to a $4 million increase in amortization of regulatory assets, the largest of which was related to the GCR regulatory asset.  This increase was offset by a corresponding increase in rider revenue discussed above.
·
Other Income decreased $23 million primarily due to interest income in 2008 from the AEP East companies for the refund of off-system sales margins in accordance with the FERC’s order related to the SIA.
·
Carrying Costs Income decreased $5 million due to the declining balance of unrecovered GCR regulatory assets being collected from customers, which were fully recovered in August 2009.
·
Interest Expense decreased $18 million primarily due to interest expense to customers in 2008 for off-system sales margins in accordance with the FERC’s order related to the SIA.
·
Income Tax Expense increased $2 million primarily due to an increase in state income tax expense, partially offset by a decrease in pretax book income.

FINANCIAL CONDITION

LIQUIDITY

PSO participates in the Utility Money Pool, which provides access to AEP’s liquidity.  PSO relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures.  See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 405 for additional discussion of liquidity.

Credit Ratings

PSO’s ultimate access to capital markets may depend on its credit ratings.  In addition, a credit rating downgrade of PSO by one of the rating agencies could increase PSO’s borrowing costs.  Failure to maintain investment grade ratings may constrain PSO’s ability to participate in the Utility Money Pool or the amount of PSO’s receivables securitized by AEP Credit.  Counterparty concerns about PSO’s credit quality could subject PSO to additional collateral demands under adequate assurance clauses under derivative and non-derivative energy contracts.

CASH FLOW

Cash flows for 2010, 2009 and 2008 were as follows:

 
 
Years Ended December 31,
 
 
 
2010
   
2009
   
2008
 
 
 
(in thousands)
 
Cash and Cash Equivalents at Beginning of Period
  $ 796     $ 1,345     $ 1,370  
Cash Flows from (Used for):
                       
Operating Activities
    93,946       239,653       167,956  
Investing Activities
    (132,569 )     (237,975 )     (233,464 )
Financing Activities
    38,297       (2,227 )     65,483  
Net Decrease in Cash and Cash Equivalents
    (326 )     (549 )     (25 )
Cash and Cash Equivalents at End of Period
  $ 470     $ 796     $ 1,345  

 
215
 
Operating Activities

Net Cash Flows from Operating Activities were $94 million in 2010.  PSO produced Net Income of $73 million during the period and had noncash expense items of $105 million for Depreciation and Amortization and $93 million for Deferred Income Taxes.  The $19 million outflow in Change in Other Noncurrent Assets was primarily the result of the deferral of January 2010 ice storm costs.  The other changes in assets and liabilities 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.  The activity in working capital relates to a number of items.  The $24 million outflow from Accrued Taxes, Net was primarily due to an increase in accrued tax benefits as a result of PSO’s 2010 federal net income tax operating loss.  Items contributing to the net income tax operating loss included bonus depreciation and the favorable impact of a change in tax accounting method related to units of property.  The $21 million outflow from Accounts Payable was primarily due to a decrease in affiliated payables.  The $10 million outflow in Accounts Receivable, Net was primarily due to the refund anticipated from Parent as a result of PSO’s 2010 federal net income tax operating loss.  The $88 million outflow from Fuel Over/Under-Recovery, Net was the result of returning previously over-recovered fuel costs to customers and higher fuel costs in relation to commission-approved fuel recovery rates.

Net Cash Flows from Operating Activities were $240 million in 2009.  PSO produced Net Income of $76 million during the period and had noncash expense items of $110 million for Depreciation and Amortization and $56 million for Deferred Income Taxes.  The other changes in assets and liabilities 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.  The activity in working capital relates to a number of items.  The $81 million inflow from Accounts Receivable, Net was primarily due to receiving the SIA refund from the AEP East companies.  The $16 million outflow from Accounts Payable was primarily due to decreases in customer accounts factored and purchased power payables. The $10 million outflow from Accrued Taxes, Net was due to an increase in accrued tax benefits resulting from a net income tax operating loss in 2009.  The $59 million outflow from Fuel Over/Under-Recovery, Net was primarily due to refunding customers previously over-recovered fuel costs, including those associated with the SIA refund.

Net Cash Flows from Operating Activities were $168 million in 2008.  PSO produced Net Income of $78 million during the period and had noncash expense items of $105 million for Depreciation and Amortization and $68 million for Deferred Income Taxes.  PSO established a $74 million regulatory asset for an OCC order approving recovery of ice storm costs related to storms in January and December 2007.  PSO recorded a Provision for SIA Refund of $52 million to its customers for off-system sales margins to be received from the AEP East companies as ordered by the FERC related to the SIA.  The other changes in assets and liabilities 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.  The activity in working capital relates to a number of items.  The $89 million outflow from Accounts Payable was primarily due to a decrease in accounts payable accruals and purchased power payables.  The $41 million change in Accounts Receivable, Net was primarily the result of the refund to be received from the AEP East companies related to the SIA.  The $29 million inflow from Accrued Taxes, Net was the result of a refund for the 2007 overpayment of federal income taxes and increased accruals related to property and income taxes.  The $47 million inflow from Fuel Over/Under-Recovery, Net resulted from revenues exceeding recoverable fuel costs.

Investing Activities

Net Cash Flows Used for Investing Activities in 2010, 2009 and 2008 were $133 million, $238 million and $233 million, respectively.  Construction Expenditures of $195 million, $175 million and $286 million in 2010, 2009 and 2008, respectively, were primarily related to projects for improved generation, transmission and distribution service reliability, customer service work and storm restoration.  In 2010 and 2009, PSO had a net decrease and increase, respectively, of $63 million in loans to the Utility Money Pool.  In 2008, PSO had a net decrease of $51 million in loans to the Utility Money Pool.

Financing Activities

Net Cash Flows from Financing Activities were $38 million in 2010.  PSO had a net increase of $91 million in borrowings from the Utility Money Pool.  This inflow was partially offset by $51 million paid in dividends on common stock.

 
216
 
Net Cash Flows Used for Financing Activities were $2 million in 2009.  PSO issued $250 million of Senior Unsecured Notes and $34 million of Pollution Control Bonds, partially offset by the retirement of $200 million of Senior Unsecured Notes.  PSO had a net decrease of $70 million in borrowings from the Utility Money Pool.  In addition, PSO paid $32 million in common stock dividends and received capital contributions from the Parent of $20 million.
 
 
Net Cash Flows from Financing Activities were $65 million in 2008.  PSO had a net increase of $70 million in borrowings from the Utility Money Pool and received capital contributions from the Parent of $30 million.  These inflows were partially offset by PSO’s repurchasing of $34 million of Pollution Control Bonds in May 2008.

In January 2011, PSO issued $250 million of 4.4% Senior Unsecured Notes due in 2021.

In January 2011, PSO gave notice to retire $200 million of 6% Senior Unsecured Notes due in 2032 on February 28, 2011.

CONTRACTUAL OBLIGATION INFORMATION

PSO’s contractual cash obligations include amounts reported on PSO’s Balance Sheets and other obligations disclosed in the footnotes.  The following table summarizes PSO’s contractual cash obligations at December 31, 2010:

 
Payments Due by Period
 
 
 
 
 
 
Less Than
 
 
 
 
 
After
 
 
 
Contractual Cash Obligations
 
1 year
 
2-3 years
 
4-5 years
 
5 years
 
Total
 
 
 
(in millions)
 
Advances from Affiliates
 
$
 91.4 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 91.4 
 
Interest on Fixed Rate Portion of Long-term Debt (a)
 
 
 54.8 
 
 
 106.0 
 
 
 103.3 
 
 
 631.6 
 
 
 895.7 
 
Fixed Rate Portion of Long-term Debt (b)
 
 
 25.0 
 
 
 0.3 
 
 
 34.0 
 
 
 914.3 
 
 
 973.6 
 
Capital Lease Obligations (c)
 
 
 5.4 
 
 
 7.8 
 
 
 4.2 
 
 
 4.1 
 
 
 21.5 
 
Noncancelable Operating Leases (c)
 
 
 2.3 
 
 
 3.5 
 
 
 1.5 
 
 
 1.0 
 
 
 8.3 
 
Fuel Purchase Contracts (d)
 
 
 256.6 
 
 
 113.8 
 
 
 30.1 
 
 
 - 
 
 
 400.5 
 
Energy and Capacity Purchase Contracts (e)
 
 
 18.0 
 
 
 114.8 
 
 
 131.5 
 
 
 590.7 
 
 
 855.0 
 
Construction Contracts for Capital Assets (f)
 
 
 36.0 
 
 
 53.9 
 
 
 44.8 
 
 
 118.9 
 
 
 253.6 
 
Total
 
$
 489.5 
 
$
 400.1 
 
$
 349.4 
 
$
 2,260.6 
 
$
 3,499.6 

(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2010 and do not reflect anticipated future refinancings, early redemptions or debt issuances.
(b)
See “Long-term Debt” section of Note 14.  Represents principal only excluding interest.
(c)
See Note 13.
(d)
Represents contractual obligations to purchase coal, natural gas and other consumables as fuel for electric generation along with related transportation of the fuel.
(e)
Represents contractual obligations for energy and capacity purchase contracts.
(f)
Represents only capital assets for which PSO has 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.

PSO’s $9 million liability related to uncertainty in Income Taxes is not included above because management cannot reasonably estimate the cash flows by period.

PSO’s pension funding requirements are not included in the above table.  As of December 31, 2010, management expects to make contributions to the pension plans totaling $5.4 million in 2011.  Estimated contributions of $18 million in 2012 and $14.5 million in 2013 may vary significantly based on market returns, changes in actuarial assumptions and other factors.  Based upon the benefit obligation and fair value of assets available to pay pension benefits, PSO’s pension plan obligation was 79.6% funded as of December 31, 2010.

 
217
 
As of December 31, 2010, PSO had no outstanding standby letters of credit or guarantees of performance.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 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 “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 for a discussion of the adoption and impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

See “Quantitative And Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 for a discussion of risk management activities.

 
218
 


 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
To the Board of Directors and Shareholders 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, 2010 and 2009, and the related statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010.  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, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
 
 
/s/ Deloitte & Touche LLP
 
 
Columbus, Ohio
February 25, 2011
 

 
219
 

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, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment, PSO’s internal control over financial reporting was effective as of December 31, 2010.

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.

 
220
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
 
STATEMENTS OF INCOME
 
For the Years Ended December 31, 2010, 2009 and 2008
 
(in thousands)
 
 
 
 
   
 
   
 
 
 
 
2010
   
2009
   
2008
 
REVENUES
 
 
   
 
   
 
 
Electric Generation, Transmission and Distribution
  $ 1,246,916     $ 1,075,014     $ 1,549,490  
Sales to AEP Affiliates
    23,528       45,756       101,602  
Other Revenues
    3,218       3,980       4,853  
TOTAL REVENUES
    1,273,662       1,124,750       1,655,945  
 
                       
EXPENSES
                       
Fuel and Other Consumables Used for Electric Generation
    373,317       310,168       774,089  
Purchased Electricity for Resale
    187,106       180,055       270,536  
Purchased Electricity from AEP Affiliates
    46,013       19,331       59,344  
Other Operation
    222,396       185,575       208,930  
Maintenance
    115,788       108,020       113,305  
Deferral of Ice Storm Costs
    -       -       (74,217 )
Depreciation and Amortization
    104,929       110,149       105,249  
Taxes Other Than Income Taxes
    42,121       41,144       38,246  
TOTAL EXPENSES
    1,091,670       954,442       1,495,482  
 
                       
OPERATING INCOME
    181,992       170,308       160,463  
 
                       
Other Income (Expense):
                       
Interest Income
    308       1,879       25,248  
Carrying Costs Income
    3,145       4,642       10,138  
Allowance for Equity Funds Used During Construction
    804       1,787       1,822  
Interest Expense
    (63,362 )     (59,093 )     (76,910 )
 
                       
INCOME BEFORE INCOME TAX EXPENSE
    122,887       119,523       120,761  
 
                       
Income Tax Expense
    50,100       43,921       42,277  
 
                       
NET INCOME
    72,787       75,602       78,484  
 
                       
Preferred Stock Dividend Requirements
    200       212       212  
 
                       
EARNINGS ATTRIBUTABLE TO COMMON STOCK
  $ 72,587     $ 75,390     $ 78,272  
 
                       
The common stock of PSO is wholly-owned by AEP.
                       
 
                       
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 

 
221
 

 
PUBLIC SERVICE COMPANY OF OKLAHOMA
STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2010, 2009 and 2008
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
 
 
 
Stock
 
Capital
 
Earnings
 
Income (Loss)
 
Total
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2007
 
$
 157,230 
 
$
 310,016 
 
$
 174,539 
 
$
 (887)
 
$
 640,898 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Adoption of Guidance for Split-Dollar Life Insurance
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accounting, Net of Tax of $596
 
 
 
 
 
 
 
 
 (1,107)
 
 
 
 
 
 (1,107)
Capital Contribution from Parent
 
 
 
 
 
 30,000 
 
 
 
 
 
 
 
 
 30,000 
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (212)
 
 
 
 
 
 (212)
SUBTOTAL – COMMON SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 669,579 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income, Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $99
 
 
 
 
 
 
 
 
 
 
 
 183 
 
 
 183 
NET INCOME
 
 
 
 
 
 
 
 
 78,484 
 
 
 
 
 
 78,484 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 78,667 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2008
 
 
 157,230 
 
 
 340,016 
 
 
 251,704 
 
 
 (704)
 
 
 748,246 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital Contribution from Parent
 
 
 
 
 
 20,000 
 
 
 
 
 
 
 
 
 20,000 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (32,000)
 
 
 
 
 
 (32,000)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (212)
 
 
 
 
 
 (212)
Gain on Reacquired Preferred Stock
 
 
 
 
 
 1 
 
 
 
 
 
 
 
 
 1 
Other Changes in Common Shareholder's Equity
 
 
 
 
 
 4,214 
 
 
 (4,214)
 
 
 
 
 
 - 
SUBTOTAL – COMMON SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 736,035 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income, Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $57
 
 
 
 
 
 
 
 
 
 
 
 105 
 
 
 105 
NET INCOME
 
 
 
 
 
 
 
 
 75,602 
 
 
 
 
 
 75,602 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 75,707 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2009
 
 
 157,230 
 
 
 364,231 
 
 
 290,880 
 
 
 (599)
 
 
 811,742 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends
 
 
 
 
 
 
 
 
 (51,026)
 
 
 
 
 
 (51,026)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (200)
 
 
 
 
 
 (200)
Gain on Reacquired Preferred Stock
 
 
 
 
 
 76 
 
 
 
 
 
 
 
 
 76 
SUBTOTAL – COMMON SHAREHOLDER'S EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 760,592 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income, Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $4,896
 
 
 
 
 
 
 
 
 
 
 
 9,093 
 
 
 9,093 
NET INCOME
 
 
 
 
 
 
 
 
 72,787 
 
 
 
 
 
 72,787 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 81,880 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL COMMON SHAREHOLDER'S EQUITY –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
DECEMBER 31, 2010
 
$
 157,230 
 
$
 364,307 
 
$
 312,441 
 
$
 8,494 
 
$
 842,472 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.

 
222
 

PUBLIC SERVICE COMPANY OF OKLAHOMA
 
BALANCE SHEETS
 
ASSETS
 
December 31, 2010 and 2009
 
(in thousands)
 
 
 
 
 
2010
   
2009
 
CURRENT ASSETS
 
 
   
 
 
Cash and Cash Equivalents
  $ 470     $ 796  
Advances to Affiliates
    -       62,695  
Accounts Receivable:
               
Customers
    43,049       38,239  
Affiliated Companies
    65,070       59,096  
Miscellaneous
    5,497       7,242  
Allowance for Uncollectible Accounts
    (971 )     (304 )
Total Accounts Receivable
    112,645       104,273  
Fuel
    20,176       20,892  
Materials and Supplies
    46,247       44,914  
Risk Management Assets
    14,225       2,376  
Deferred Income Tax Benefits
    -       26,335  
Accrued Tax Benefits
    38,589       15,291  
Regulatory Asset for Under-Recovered Fuel Costs
    37,262       -  
Prepayments and Other Current Assets
    9,416       9,139  
TOTAL CURRENT ASSETS
    279,030       286,711  
 
               
PROPERTY, PLANT AND EQUIPMENT
               
Electric:
               
Generation
    1,330,368       1,300,069  
Transmission
    663,994       617,291  
Distribution
    1,686,470       1,596,355  
Other Property, Plant and Equipment
    235,406       228,705  
Construction Work in Progress
    59,091       67,138  
Total Property, Plant and Equipment
    3,975,329       3,809,558  
Accumulated Depreciation and Amortization
    1,255,064       1,220,177  
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    2,720,265       2,589,381  
 
               
OTHER NONCURRENT ASSETS
               
Regulatory Assets
    263,545       279,185  
Long-term Risk Management Assets
    252       50  
Deferred Charges and Other Noncurrent Assets
    20,979       13,880  
TOTAL OTHER NONCURRENT ASSETS
    284,776       293,115  
 
               
TOTAL ASSETS
  $ 3,284,071     $ 3,169,207  
 
               
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 
 
 
223
 
PUBLIC SERVICE COMPANY OF OKLAHOMA
 
BALANCE SHEETS
 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
December 31, 2010 and 2009
 
 
 
 
   
 
 
 
 
2010
   
2009
 
 
 
(in thousands)
 
CURRENT LIABILITIES
 
 
   
 
 
Advances from Affiliates
  $ 91,382     $ -  
Accounts Payable:
               
General
    69,155       76,895  
Affiliated Companies
    53,179       71,099  
Long-term Debt Due Within One Year – Nonaffiliated
    25,000       -  
Risk Management Liabilities
    922       2,579  
Customer Deposits
    41,217       42,002  
Accrued Taxes
    25,390       19,471  
Regulatory Liability for Over-Recovered Fuel Costs
    -       51,087  
Other Current Liabilities
    47,333       60,905  
TOTAL CURRENT LIABILITIES
    353,578       324,038  
 
               
NONCURRENT LIABILITIES
               
Long-term Debt – Nonaffiliated
    946,186       968,121  
Long-term Risk Management Liabilities
    197       144  
Deferred Income Taxes
    660,783       588,768  
Regulatory Liabilities and Deferred Investment Tax Credits
    336,961       326,931  
Employee Benefits and Pension Obligations
    98,107       107,748  
Deferred Credits and Other Noncurrent Liabilities
    40,905       36,457  
TOTAL NONCURRENT LIABILITIES
    2,083,139       2,028,169  
 
               
TOTAL LIABILITIES
    2,436,717       2,352,207  
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
    4,882       5,258  
 
               
Rate Matters (Note 4)
               
Commitments and Contingencies (Note 6)
               
 
               
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
    364,307       364,231  
Retained Earnings
    312,441       290,880  
Accumulated Other Comprehensive Income (Loss)
    8,494       (599 )
TOTAL COMMON SHAREHOLDER’S EQUITY
    842,472       811,742  
 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
  $ 3,284,071     $ 3,169,207  
 
               
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 

 
224
 

PUBLIC SERVICE COMPANY OF OKLAHOMA
 
STATEMENTS OF CASH FLOWS
 
For the Years Ended December 31, 2010, 2009 and 2008
 
(in thousands)
 
 
 
 
 
2010
   
2009
   
2008
 
OPERATING ACTIVITIES
 
 
   
 
   
 
 
Net Income
  $ 72,787     $ 75,602     $ 78,484  
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
                       
Depreciation and Amortization
    104,929       110,149       105,249  
Deferred Income Taxes
    92,695       56,029       67,874  
Provision for SIA Refund
    -       -       52,100  
Carrying Costs Income
    (3,145 )     (4,642 )     (10,138 )
Deferral of Ice Storm Costs
    -       -       (74,217 )
Allowance for Equity Funds Used During Construction
    (804 )     (1,787 )     (1,822 )
Mark-to-Market of Risk Management Contracts
    160       1,791       5,151  
Fuel Over/Under-Recovery, Net
    (88,349 )     (59,462 )     46,553  
Unrealized Forward Commitments, Net
    46       (1,928 )     (5,263 )
Change in Other Noncurrent Assets
    (19,325 )     7,713       6,117  
Change in Other Noncurrent Liabilities
    3,764       625       (6,774 )
Changes in Certain Components of Working Capital:
                       
Accounts Receivable, Net
    (10,094 )     81,446       (40,725 )
Fuel, Materials and Supplies
    (617 )     5,301       (4,022 )
Margin Deposits
    217       499       8,093  
Accounts Payable
    (20,601 )     (16,431 )     (89,413 )
Accrued Taxes, Net
    (23,605 )     (10,230 )     28,506  
Other Current Assets
    4,229       (6,426 )     491  
Other Current Liabilities
    (18,341 )     1,404       1,712  
Net Cash Flows from Operating Activities
    93,946       239,653       167,956  
 
                       
INVESTING ACTIVITIES
                       
Construction Expenditures
    (194,896 )     (175,122 )     (285,826 )
Change in Other Temporary Investments, Net
    3       -       5  
Change in Advances to Affiliates, Net
    62,695       (62,695 )     51,202  
Acquisitions of Assets
    (2,819 )     (2,646 )     (1,409 )
Proceeds from Sales of Assets
    2,448       2,488       2,564  
Net Cash Flows Used for Investing Activities
    (132,569 )     (237,975 )     (233,464 )
 
                       
FINANCING ACTIVITIES
                       
Capital Contribution from Parent
    -       20,000       30,000  
Issuance of Long-term Debt – Nonaffiliated
    2,240       280,732       -  
Change in Advances from Affiliates, Net
    91,382       (70,308 )     70,308  
Retirement of Long-term Debt – Nonaffiliated
    -       (200,000 )     (33,700 )
Retirement of Cumulative Preferred Stock
    (300 )     (2 )     -  
Principal Payments for Capital Lease Obligations
    (3,991 )     (1,485 )     (1,551 )
Dividends Paid on Common Stock
    (51,026 )     (32,000 )     -  
Dividends Paid on Cumulative Preferred Stock
    (200 )     (212 )     (212 )
Other Financing Activities
    192       1,048       638  
Net Cash Flows from (Used For) Financing Activities
    38,297       (2,227 )     65,483  
 
                       
Net Decrease in Cash and Cash Equivalents
    (326 )     (549 )     (25 )
Cash and Cash Equivalents at Beginning of Period
    796       1,345       1,370  
Cash and Cash Equivalents at End of Period
  $ 470     $ 796     $ 1,345  
 
                       
SUPPLEMENTARY INFORMATION
                       
Cash Paid for Interest, Net of Capitalized Amounts
  $ 57,970     $ 71,135     $ 53,132  
Net Cash Paid (Received) for Income Taxes
    (16,770 )     1,040       (50,022 )
Noncash Acquisitions Under Capital Leases
    13,794       3,478       1,008  
Construction Expenditures Included in Accounts Payable at December 31,
    6,842       11,901       18,004  
SIA Refund Included in Accounts Receivable at December 31,
    -       -       72,311  
 
                       
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 

 
225
 

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 246.

 
Footnote
Reference
   
Organization and Summary of Significant Accounting Policies
Note 1
New Accounting Pronouncements and Extraordinary Item
Note 2
Rate Matters
Note 4
Effects of Regulation
Note 5
Commitments, Guarantees and Contingencies
Note 6
Benefit Plans
Note 8
Business Segments
Note 9
Derivatives and Hedging
Note 10
Fair Value Measurements
Note 11
Income Taxes
Note 12
Leases
Note 13
Financing Activities
Note 14
Related Party Transactions
Note 15
Property, Plant and Equipment
Note 16
Cost Reduction Initiatives
Note 17
Unaudited Quarterly Financial Information
Note 18

 
226
 









SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

 
227
 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
 
SELECTED CONSOLIDATED FINANCIAL DATA
 
(in thousands)
 
 
 
 
 
 
2010 (a)
 
2009 
 
2008 
 
2007 
 
2006 
 
STATEMENTS OF INCOME DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 1,523,534 
 
$
 1,389,302 
 
$
 1,554,762 
 
$
 1,483,462 
 
$
 1,431,839 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating Income
$
 248,797 
 
$
 162,512 
 
$
 172,645 
 
$
 134,702 
 
$
 189,618 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Before Extraordinary Loss
$
 146,684 
 
$
 122,528 
 
$
 96,445 
 
$
 69,771 
 
$
 94,591 
 
Extraordinary Loss, Net of Tax
 
 - 
 
 
 (5,325)
(b)
 
 - 
 
 
 - 
 
 
 - 
 
Net Income
 
 146,684 
 
 
 117,203 
 
 
 96,445 
 
 
 69,771 
 
 
 94,591 
 
Less:  Net Income Attributable to
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling Interest
 
 4,093 
 
 
 3,130 
 
 
 3,691 
 
 
 3,507 
 
 
 2,868 
 
Net Income Attributable to SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Shareholders
 
 142,591 
 
 
 114,073 
 
 
 92,754 
 
 
 66,264 
 
 
 91,723 
 
Less:  Preferred Stock Dividend
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Requirements
 
 229 
 
 
 229 
 
 
 229 
 
 
 229 
 
 
 229 
 
Earnings Attributable to SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Shareholder
$
 142,362 
 
$
 113,844 
 
$
 92,525 
 
$
 66,035 
 
$
 91,494 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
BALANCE SHEETS DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and Equipment
$
 6,556,077 
 
$
 6,064,895 
 
$
 5,576,528 
 
$
 4,876,912 
 
$
 4,328,247 
 
Accumulated Depreciation and Amortization
 
 2,130,351 
 
 
 2,086,333 
 
 
 2,014,154 
 
 
 1,939,044 
 
 
 1,834,145 
 
Total Property, Plant and Equipment –
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net
$
 4,425,726 
 
$
 3,978,562 
 
$
 3,562,374 
 
$
 2,937,868 
 
$
 2,494,102 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 5,243,567 
 
$
 4,640,033 
 
$
 4,253,085 
 
$
 3,488,386 
 
$
 3,175,071 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Common Shareholder's Equity
$
 1,666,988 
 
$
 1,524,126 
 
$
 1,248,653 
 
$
 972,955 
 
$
 821,202 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cumulative Preferred Stock Not Subject to
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mandatory Redemption
$
 4,696 
 
$
 4,697 
 
$
 4,697 
 
$
 4,697 
 
$
 4,697 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling Interest
$
 361 
 
$
 31 
 
$
 276 
 
$
 1,687 
 
$
 1,815 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt (c)
$
 1,769,520 
(d)
$
 1,474,153 
 
$
 1,478,149 
(d)
$
 1,197,217 
(d)
$
 729,006 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Obligations Under Capital Leases (c)
$
 128,664 
 
$
 148,661 
(e)
$
 112,725 
(e)
$
 100,320 
(e)
$
 84,715 
 

(a)
Prospectively adopted the “Consolidation” accounting guidance effective January 1, 2010 and began accounting for DHLC under the equity method of accounting.
(b)
Reflects the re-application of the generation portion of Texas’ retail jurisdiction in accordance with the accounting guidance for “Regulated Operations.”  See “SWEPCo Texas Restructuring” in “Extraordinary Item” section of Note 2.
(c)
Includes portion due within one year.
(d)
Increased primarily due to the construction of new generation.
(e)
Increased primarily due to new leases for coal handling equipment.

 
228
 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

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 520,000 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.  See Note 2 for a discussion of the deconsolidation of DHLC effective January 1, 2010.  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 member of the CSW 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.

Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and 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.

AEPSC conducts power, gas, coal and emission allowance 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 gas risk management activities are allocated based on the CSW Operating Agreement and the SIA.  SWEPCo shares in coal and emission 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 gas, coal and emission allowances.  The electricity, gas, coal and emission allowance 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.

SWEPCo is jointly and severally liable for activity conducted by AEPSC on the behalf of the AEP East companies, PSO and SWEPCo related to purchase power and sale activity pursuant to the SIA.

Regulatory Activity

Texas Regulatory Activity

In April 2010, a settlement agreement was approved by the PUCT to increase SWEPCo’s base rates by approximately $15 million annually, effective May 2010, including a return on equity of 10.33%.  In addition, the settlement agreement will decrease annual depreciation expense by $17 million and allows SWEPCo a $10 million one-year surcharge rider to recover additional vegetation management costs that SWEPCo must spend within two years.  See “2009 Texas Base Rate Filing” section of Note 4.

 
229
 
Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW coal generating unit in Arkansas, which is expected to be in service in 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  SWEPCo’s share of construction costs is currently estimated to cost $1.3 billion, excluding AFUDC, plus an additional $125 million for transmission, excluding AFUDC.  The APSC, LPSC and PUCT approved SWEPCo’s original application to build the Turk Plant.  Various proceedings are pending that challenge the Turk Plant’s construction, its approved wetlands and air permits and its transmission line certificate of environmental compatibility and public need.  See “Turk Plant” section of Note 4.

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 state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be.  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 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 405 for additional discussion of relevant factors.

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
2010 
 
2009 
 
2008 
 
 
(in millions of KWH)
Retail:
 
 
 
 
 
 
 
 
 
Residential
 
 6,361 
 
 
 5,587 
 
 
 5,694 
 
Commercial
 
 6,117 
 
 
 5,957 
 
 
 5,994 
 
Industrial
 
 5,254 
 
 
 4,460 
 
 
 5,402 
 
Miscellaneous
 
 81 
 
 
 82 
 
 
 82 
Total Retail
 
 17,813 
 
 
 16,086 
 
 
 17,172 
 
 
 
 
 
 
 
 
 
Wholesale
 
 7,333 
 
 
 6,527 
 
 
 6,395 
 
 
 
 
 
 
 
 
 
Total KWHs
 
 25,146 
 
 
 22,613 
 
 
 23,567 

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,
 
 
 
2010 
 
2009 
 
2008 
 
 
 
(in degree days)
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 1,543 
 
 
 1,270 
 
 
 1,325 
 
Normal - Heating (b)
 
 1,253 
 
 
 1,263 
 
 
 1,281 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 2,592 
 
 
 1,956 
 
 
 2,031 
 
Normal - Cooling (b)
 
 2,213 
 
 
 2,231 
 
 
 2,221 
 
 
 
 
 
 
 
 
 
 
 
 
(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.

 
230
 
2010 Compared to 2009
 
 
 
 
 
Reconciliation of Year Ended December 31, 2009 to Year Ended December 31, 2010
 
Income Before Extraordinary Loss
 
(in millions)
 
 
 
 
 
Year Ended December 31, 2009
  $ 123  
 
       
Changes in Gross Margin:
       
Retail Margins (a)
    104  
Off-system Sales
    1  
Transmission Revenues
    1  
Other Revenues
    (42 )
Total Change in Gross Margin
    64  
 
       
Total Expenses and Other:
       
Other Operation and Maintenance
    7  
Depreciation and Amortization
    18  
Taxes Other Than Income Taxes
    (3 )
Other Income
    (1 )
Interest Expense
    (16 )
Equity Earnings of Unconsolidated Subsidiaries
    2  
Total Expenses and Other
    7  
 
       
Income Tax Expense
    (47 )
 
       
Year Ended December 31, 2010
  $ 147  
 
(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 power were as follows:

·
Retail Margins increased $104 million primarily due to:
 
·
A $42 million increase in base rates in Arkansas and Texas.  This increase in Retail Margins had corresponding increases of $9 million related to riders/trackers recognized in other expense items.
 
·
A $25 million increase in weather-related usage primarily due to a 33% increase in cooling degree days and a 21% increase in heating degree days.
 
·
A $16 million increase in fuel recovery primarily due to lower capacity costs and increased wholesale fuel recovery.
 
·
A $14 million increase in industrial sales compared to the recessionary lows of 2009.
·
Other Revenues decreased $42 million primarily resulting from the deconsolidation of SWEPCo’s mining subsidiary, DHLC.  Prior to the deconsolidation, SWEPCo recorded revenues from coal deliveries from DHLC to CLECO.  SWEPCo prospectively adopted the “Consolidation” accounting guidance effective January 1, 2010 and began accounting for DHLC under the equity method of accounting.  The decreased revenue from coal deliveries was partially offset by a corresponding decrease in Other Operation and Maintenance expenses from mining operations discussed below.

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

·
Other Operation and Maintenance expenses decreased $7 million primarily due to:
 
·
A $34 million decrease in expenses for coal deliveries from SWEPCo’s mining subsidiary, DHLC.  The decreased expenses for coal deliveries were partially offset by a corresponding decrease in Other Revenues discussed above.
 
 
231
 
 
This decrease was partially offset by:
 
·
A $30 million increase due to expenses related to cost reduction initiatives.  In 2010, management conducted cost reduction initiatives to reduce both labor and non-labor expenses.
·
Depreciation and Amortization expenses decreased $18 million primarily due to lower Arkansas and Texas depreciation resulting from the Arkansas and Texas base rate orders and the deconsolidation of DHLC, partially offset by the addition of the Stall Unit.
·
Interest Expense increased $16 million primarily due to increased long-term debt outstanding.
·
Income Tax Expense increased $47 million primarily due to an increase in pretax book income and the recording of federal income tax adjustments.
 
 
232
 
2009 Compared to 2008
 
 
 
 
 
Reconciliation of Year Ended December 31, 2008 to Year Ended December 31, 2009
 
Income Before Extraordinary Loss
 
(in millions)
 
 
 
 
 
Year Ended December 31, 2008
  $ 96  
 
       
Changes in Gross Margin:
       
Retail Margins (a)
    (32 )
Off-system Sales
    1  
Transmission Revenues
    7  
Other Revenues
    (1 )
Total Change in Gross Margin
    (25 )
 
       
Total Expenses and Other:
       
Other Operation and Maintenance
    16  
Taxes Other Than Income Taxes
    (1 )
Other Income
    (2 )
Interest Expense
    23  
Total Expenses and Other
    36  
 
       
Income Tax Expense
    16  
 
       
Year Ended December 31, 2009
  $ 123  
 
(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 power were as follows:

·
Retail Margins decreased $32 million primarily due to the following:
 
·
A $22 million decrease due to the net favorable effect of the recognition of off-system sales margins as ordered by the FERC in November 2008.
 
·
A $12 million decrease in wholesale fuel recovery.
 
·
A $12 million decrease in industrial sales due to reduced operating levels and suspended operations by certain large industrial customers in SWEPCo’s service territory.
 
·
A $5 million net impairment of a fuel regulatory asset related to deferred mining costs in Arkansas.
 
These decreases were partially offset by:
 
·
A $13 million increase in wholesale and municipal revenue primarily due to higher prices and the annual true-up for formula rate customers.
 
·
An $8 million increase in rate relief related to the Louisiana Formula Rate Plan.
·
Transmission Revenues increased $7 million primarily due to higher rates in the SPP region.

Total Expenses and Other and Income Tax Expense changed between years as indicated:

·
Other Operation and Maintenance expenses decreased $16 million primarily due to the following:
 
·
An $11 million decrease in distribution expenses associated with the 2008 storm restoration expenses from Hurricanes Ike and Gustav.
 
·
A $2 million decrease in expenses for coal deliveries from SWEPCo’s mining subsidiary, DHLC.
 
·
A $2 million decrease resulting from reduced sale of receivable expense due to decreased revenues.
·
Other Income decreased $2 million primarily due to the following:
 
·
A $26 million decrease in interest income from the AEP East companies for the refund in 2008 of off-system sales margins in accordance with the FERC’s order related to SIA.
 
·
An $8 million decrease in interest income primarily resulting from fuel recovery and decreased lending to affiliated companies.
 
 
233
 
 
These decreases were partially offset by:
 
·
A $32 million increase in the equity component of AFUDC primarily as a result of construction at the Turk Plant and Stall Unit and the reapplication of “Regulated Operations” accounting guidance for the generation portion of Texas’ retail jurisdiction effective April 2009.
·
Interest Expense decreased $23 million primarily due to the following:
 
·
Interest expense of $16 million to customers for off-system sales margins in accordance with the FERC’s 2008 order related to the SIA.
 
·
A $10 million increase in the debt component of AFUDC due to new generation projects at the Turk Plant and Stall Unit.
 
·
A $2 million decrease in interest expense due to a decrease in short-term debt outstanding.
 
These decreases were partially offset by:
 
·
A $5 million increase in interest expense due to an increase in long-term debt outstanding during the first six months of 2009.
·
Income Tax Expense decreased $16 million primarily due to the regulatory accounting treatment of state income taxes and other book/tax differences which are accounted for on a flow-through basis and a tax loss benefit from Parent.

FINANCIAL CONDITION

LIQUIDITY

SWEPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  SWEPCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures.  See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 405 for additional discussion of liquidity.

Credit Ratings

SWEPCo’s ultimate access to capital markets may depend on its credit ratings.  In addition, a credit rating downgrade of SWEPCo by one of the rating agencies could increase SWEPCo’s borrowing costs.  Failure to maintain investment grade ratings may constrain SWEPCo’s ability to participate in the Utility Money Pool or the amount of SWEPCo’s receivables securitized by AEP Credit.  Counterparty concerns about SWEPCo’s credit quality could subject SWEPCo to additional collateral demands under adequate assurance clauses under derivative and non-derivative energy contracts.

CASH FLOW

Cash flows for 2010, 2009 and 2008 were as follows:

 
 
Years Ended December 31,
 
 
 
2010
   
2009
   
2008
 
 
 
(in thousands)
 
Cash and Cash Equivalents at Beginning of Period
  $ 1,661     $ 1,910     $ 1,742  
Cash Flows from (Used for):
                       
Operating Activities
    272,951       410,820       224,210  
Investing Activities
    (553,170 )     (556,487 )     (692,345 )
Financing Activities
    280,072       145,418       468,303  
Net Increase (Decrease) in Cash and Cash Equivalents
    (147 )     (249 )     168  
Cash and Cash Equivalents at End of Period
  $ 1,514     $ 1,661     $ 1,910  

 
234
 
Operating Activities

Net Cash Flows from Operating Activities were $273 million in 2010.  SWEPCo produced Net Income of $147 million during the period and had noncash items of $127 million for Depreciation and Amortization and $82 million for Deferred Income Taxes, partially offset by $46 million in Allowance for Equity Funds Used During Construction.  SWEPCo contributed $29 million to the qualified pension trust.  The other changes in assets and liabilities 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.  The activity in working capital relates to a number of items.  The $23 million outflow from Accounts Payable was primarily due to a decrease in fuel costs and purchased power payables.  The $22 million outflow from Accounts Receivable, Net was primarily due to the refund anticipated from Parent as a result of SWEPCo’s 2010 federal net income tax operating loss.  Items contributing to the net income tax operating loss included bonus depreciation and the favorable impact of a change in tax accounting method related to units of property.  The $21 million inflow from Fuel, Materials and Supplies was primarily due to lower coal inventories at the Flint Creek and Welsh Plants.  The $19 million outflow from Accrued Taxes, Net was primarily due to an increase in accrued tax benefits as a result of SWEPCo’s 2010 federal net income tax operating loss.

Net Cash Flows from Operating Activities were $411 million in 2009.  SWEPCo produced Net Income of $117 million during the period and had noncash expense items of $145 million for Depreciation and Amortization and $28 million for Deferred Income Taxes, partially offset by $47 million in Allowance for Equity Funds Used During Construction.  The other changes in assets and liabilities 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.  The activity in working capital relates to a number of items.  The $113 million inflow from Accounts Receivable, Net was a result of receiving the SIA refund from the AEP East companies and billed sale of receivables.  The $41 million inflow from Accounts Payable was due to a new gas transportation contract, fuel received but not billed and unbilled sale of receivables.  The $26 million outflow from Fuel, Materials and Supplies was due to higher coal inventories at Sabine Mining Company.  The $25 million outflow from Accrued Taxes, Net was the result of tax payments for prior year liabilities and decreased accruals related to property and income taxes.  The $68 million inflow from Fuel Over/Under-Recovery, Net was due to higher fuel cost recovery in Arkansas and Texas.

Net Cash Flows from Operating Activities were $224 million in 2008.  SWEPCo produced Net Income of $96 million during the period and had noncash expense items of $145 million for Depreciation and Amortization and $62 million for Deferred Income Taxes.  SWEPCo recorded a Provision for SIA Refund of $54 million to its customers for off-system sales margins to be received from the AEP East companies as ordered by the FERC related to the SIA.  The other changes in assets and liabilities 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.  The activity in working capital relates to a number of items.  The $52 million outflow from Accounts Receivable, Net was primarily the result of the anticipated refund from the AEP East companies related to the SIA.  The $36 million outflow from Accounts Payable was primarily due to a decrease in purchased power payables.  The $25 million outflow from Fuel, Materials and Supplies was primarily due to higher coal and fuel-related costs.  The $87 million outflow from Fuel Over/Under-Recovery, Net was the result of higher fuel costs.

Investing Activities

Net Cash Flows Used for Investing Activities in 2010, 2009 and 2008 were $553 million, $556 million and $692 million, respectively.  Construction Expenditures of $420 million, $597 million and $692 million in 2010, 2009 and 2008, respectively, were primarily related to new generation projects at the Turk Plant and Stall Unit.  In 2010, SWEPCo acquired the Valley Electric Membership Corporation for $102 million and increased loans to the Utility Money Pool by $34 million.  In 2009, SWEPCo increased loans to the Utility Money Pool by $35 million, acquired the Red River Mining Company for $16 million and purchased 50% of the Oxbow Lignite Mining Company, LLC membership interest for $13 million.  These outflows in 2009 were partially offset by $106 million in proceeds from sales of assets primarily relating to the sale of a portion of Turk Plant to joint owners.

 
235
 
Financing Activities

Net Cash Flows from Financing Activities were $280 million in 2010.  SWEPCo issued $350 million of Senior Unsecured Notes and $54 million of Pollution Control Bonds.  These increases were partially offset by the retirement of $54 million of Pollution Control Bonds and $50 million of Notes Payable – Affiliated.

Net Cash Flows from Financing Activities were $145 million in 2009.  During the year, SWEPCo received capital contributions from the Parent of $143 million.

Net Cash Flows from Financing Activities were $468 million in 2008.  SWEPCo issued $400 million of Senior Unsecured Notes and received capital contributions from the Parent of $200 million.  These increases were partially offset by the retirement of $160 million of Long-term Debt – Nonaffiliated.

CONTRACTUAL OBLIGATION INFORMATION

SWEPCo’s contractual cash obligations include amounts reported on SWEPCo’s Consolidated Balance Sheets and other obligations disclosed in the footnotes.  The following table summarizes SWEPCo’s contractual cash obligations at December 31, 2010:

 
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)
 
$
 6.2 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 6.2 
 
Interest on Fixed Rate Portion of Long-term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt (b)
 
 
 102.4 
 
 
 198.4 
 
 
 194.6 
 
 
 711.0 
 
 
 1,206.4 
 
Fixed Rate Portion of Long-term Debt (c)
 
 
 41.1 
 
 
 20.0 
 
 
 303.5 
 
 
 1,406.7 
 
 
 1,771.3 
 
Capital Lease Obligations (d)
 
 
 22.3 
 
 
 42.3 
 
 
 36.1 
 
 
 78.5 
 
 
 179.2 
 
Noncancelable Operating Leases (d)
 
 
 6.0 
 
 
 9.1 
 
 
 5.7 
 
 
 12.5 
 
 
 33.3 
 
Fuel Purchase Contracts (e)
 
 
 257.1 
 
 
 321.2 
 
 
 76.6 
 
 
 80.2 
 
 
 735.1 
 
Energy and Capacity Purchase Contracts (f)
 
 
 19.0 
 
 
 39.1 
 
 
 39.2 
 
 
 284.9 
 
 
 382.2 
 
Construction Contracts for Capital Assets (g)
 
 
 172.0 
 
 
 201.2 
 
 
 105.3 
 
 
 110.7 
 
 
 589.2 
 
Total
 
$
 626.1 
 
$
 831.3 
 
$
 761.0 
 
$
 2,684.5 
 
$
 4,902.9 

(a)
Represents principal only excluding interest.
(b)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2010 and do not reflect anticipated future refinancings, early redemptions or debt issuances.
(c)
See “Long-term Debt” section of Note 14.  Represents principal only excluding interest.
(d)
See Note 13.
(e)
Represents contractual obligations to purchase coal, natural gas and other consumables as fuel for electric generation along with related transportation of the fuel.
(f)
Represents contractual obligations for energy and capacity purchase contracts.
(g)
Represents only capital assets for which SWEPCo has 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.

SWEPCo’s $14 million liability related to uncertainty in Income Taxes is not included above because management cannot reasonably estimate the cash flows by period.

SWEPCo’s pension funding requirements are not included in the above table.  As of December 31, 2010, management expects to make contributions to the pension plans totaling $7.3 million in 2011.  Estimated contributions of $16.3 million in 2012 and $13.2 million in 2013 may vary significantly based on market returns, changes in actuarial assumptions and other factors.  Based upon the benefit obligation and fair value of assets available to pay pension benefits, SWEPCo’s pension plan obligation was 84.1% funded as of December 31, 2010.

 
236
 
In addition to the amounts disclosed in the contractual cash obligations table above, SWEPCo makes additional commitments in the normal course of business.  SWEPCo’s commitments outstanding at December 31, 2010 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)
 
$
 4.4 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 4.4 
 
Guarantees of the Performance of Outside Parties (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 65.0 
 
 
 65.0 
 
Total
 
$
 4.4 
 
$
 - 
 
$
 - 
 
$
 65.0 
 
$
 69.4 

(a)
SWEPCo enters into standby letters of credit (LOCs) with third parties.  These LOCs cover items such as insurance programs, security deposits, debt service reserves and variable rate Pollution Control Bonds.  All of these LOCs were issued in SWEPCo’s ordinary course of business.  There is no collateral held in relation to any guarantees in excess of SWEPCo’s ownership percentages.  In the event any LOC is drawn, there is no recourse to third parties.  The maximum future payments of these LOCs are $4.4 million maturing in June 2011.  See “Letters of Credit” section of Note 6.
(b)
See "Guarantees of Third-Party Obligations" section of Note 6.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 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 “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 for a discussion of the adoption and impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

See “Quantitative And Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 for a discussion of risk management activities.

 
237
 


 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
To the Board of Directors and Shareholders 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, 2010 and 2009, and the related consolidated statements of income, changes in equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010.  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, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
 
 
As discussed in Note 2 to the consolidated financial statements, the Company adopted FASB Accounting Standards Update No. 2009-17, Consolidations (Topic 810): Improvements to Financial Reporting  by Enterprises Involved with Variable Interest Entities, effective January 1, 2010.
 
 
/s/ Deloitte & Touche LLP
 
 
Columbus, Ohio
February 25, 2011
 

 
238
 

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, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment, SWEPCo’s internal control over financial reporting was effective as of December 31, 2010.

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.

 
239
 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
 
CONSOLIDATED STATEMENTS OF INCOME
 
For the Years Ended December 31, 2010, 2009 and 2008
 
(in thousands)
 
 
 
 
 
2010
   
2009
   
2008
 
REVENUES
 
 
   
 
   
 
 
Electric Generation, Transmission and Distribution
  $ 1,469,514     $ 1,315,056     $ 1,458,027  
Sales to AEP Affiliates
    51,870       29,318       50,842  
Lignite Revenues – Nonaffiliated
    -       43,239       44,366  
Other Revenues
    2,150       1,689       1,527  
TOTAL REVENUES
    1,523,534       1,389,302       1,554,762  
 
                       
EXPENSES
                       
Fuel and Other Consumables Used for Electric Generation
    587,058       495,928       523,361  
Purchased Electricity for Resale
    125,064       127,170       164,466  
Purchased Electricity from AEP Affiliates
    23,707       42,712       118,773  
Other Operation
    245,504       249,792       260,186  
Maintenance
    103,352       105,602       111,273  
Depreciation and Amortization
    126,901       145,144       145,011  
Taxes Other Than Income Taxes
    63,151       60,442       59,047  
TOTAL EXPENSES
    1,274,737       1,226,790       1,382,117  
 
                       
OPERATING INCOME
    248,797       162,512       172,645  
 
                       
Other Income (Expense):
                       
Interest Income
    579       1,286       35,086  
Allowance for Equity Funds Used During Construction
    45,646       46,737       14,908  
Interest Expense
    (86,538 )     (70,500 )     (93,150 )
 
                       
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY
                       
EARNINGS (LOSS)
    208,484       140,035       129,489  
 
                       
Income Tax Expense
    64,214       17,511       33,041  
Equity Earnings (Loss) of Unconsolidated Subsidiaries
    2,414       4       (3 )
 
                       
INCOME BEFORE EXTRAORDINARY LOSS
    146,684       122,528       96,445  
 
                       
EXTRAORDINARY LOSS, NET OF TAX
    -       (5,325 )     -  
 
                       
NET INCOME
    146,684       117,203       96,445  
 
                       
Less: Net Income Attributable to Noncontrolling Interest
    4,093       3,130       3,691  
 
                       
NET INCOME ATTRIBUTABLE TO SWEPCo SHAREHOLDERS
    142,591       114,073       92,754  
 
                       
Less: Preferred Stock Dividend Requirements
    229       229       229  
 
                       
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER
  $ 142,362     $ 113,844     $ 92,525  
 
                       
The common stock of SWEPCo is wholly-owned by AEP.
                       
 
                       
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 

 
240
 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONSOLIDATED STATEMENTS OF CHANGES IN
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2010, 2009 and 2008
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SWEPCo Common Shareholder
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other
 
 
 
 
 
 
 
Common
 
Paid-in
 
Retained
 
Comprehensive
 
Noncontrolling
 
 
 
 
Stock
 
Capital
 
Earnings
 
Income (Loss)
 
Interest
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY – DECEMBER 31, 2007
 
$
 135,660 
 
$
 330,003 
 
$
 523,731 
 
$
 (16,439)
 
$
 1,687 
 
$
 974,642 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Adoption of Guidance for Split-Dollar Life Insurance
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accounting, Net of Tax of $622
 
 
 
 
 
 
 
 
 (1,156)
 
 
 
 
 
 
 
 
 (1,156)
Adoption of Guidance for Fair Value Accounting, Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
of Tax of $6
 
 
 
 
 
 
 
 
 10 
 
 
 
 
 
 
 
 
 10 
Capital Contribution from Parent
 
 
 
 
 
 200,000 
 
 
 
 
 
 
 
 
 
 
 
 200,000 
Common Stock Dividends – Nonaffilated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (5,109)
 
 
 (5,109)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (229)
 
 
 
 
 
 
 
 
 (229)
SUBTOTAL – EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,168,158 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $56
 
 
 
 
 
 
 
 
 
 
 
 97 
 
 
 7 
 
 
 104 
 
 
Amortization of Pension and OPEB Deferred Costs,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $507
 
 
 
 
 
 
 
 
 
 
 
 941 
 
 
 
 
 
 941 
 
 
Pension and OPEB Funded Status, Net of Tax of $9,003
 
 
 
 
 
 
 
 
 
 
 
 (16,719)
 
 
 
 
 
 (16,719)
NET INCOME
 
 
 
 
 
 
 
 
 92,754 
 
 
 
 
 
 3,691 
 
 
 96,445 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 80,771 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY – DECEMBER 31, 2008
 
 
 135,660 
 
 
 530,003 
 
 
 615,110 
 
 
 (32,120)
 
 
 276 
 
 
 1,248,929 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital Contribution from Parent
 
 
 
 
 
 142,500 
 
 
 
 
 
 
 
 
 
 
 
 142,500 
Common Stock Dividends – Nonaffiliated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (3,375)
 
 
 (3,375)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (229)
 
 
 
 
 
 
 
 
 (229)
Other Changes in Equity
 
 
 
 
 
 2,476 
 
 
 (2,476)
 
 
 
 
 
 
 
 
 - 
SUBTOTAL – EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,387,825 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income, Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $533
 
 
 
 
 
 
 
 
 
 
 
 989 
 
 
 
 
 
 989 
 
 
Reapplication of Regulated Operations Accounting
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Guidance for Pensions, Net of Tax of $8,223
 
 
 
 
 
 
 
 
 
 
 
 15,271 
 
 
 
 
 
 15,271 
 
 
Amortization of Pension and OPEB Deferred Costs,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $928
 
 
 
 
 
 
 
 
 
 
 
 1,724 
 
 
 
 
 
 1,724 
 
 
Pension and OPEB Funded Status, Net of Tax of $617
 
 
 
 
 
 
 
 
 
 
 
 1,145 
 
 
 
 
 
 1,145 
NET INCOME
 
 
 
 
 
 
 
 
 114,073 
 
 
 
 
 
 3,130 
 
 
 117,203 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 136,332 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY – DECEMBER 31, 2009
 
 
 135,660 
 
 
 674,979 
 
 
 726,478 
 
 
 (12,991)
 
 
 31 
 
 
 1,524,157 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Dividends – Nonaffiliated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 (3,763)
 
 
 (3,763)
Preferred Stock Dividends
 
 
 
 
 
 
 
 
 (229)
 
 
 
 
 
 
 
 
 (229)
SUBTOTAL – EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 1,520,165 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Comprehensive Income (Loss), Net of Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Flow Hedges, Net of Tax of $401
 
 
 
 
 
 
 
 
 
 
 
 745 
 
 
 
 
 
 745 
 
 
Amortization of Pension and OPEB Deferred Costs,
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net of Tax of $505
 
 
 
 
 
 
 
 
 
 
 
 937 
 
 
 
 
 
 937 
 
 
Pension and OPEB Funded Status, Net of Tax of $636
 
 
 
 
 
 
 
 
 
 
 
 (1,182)
 
 
 
 
 
 (1,182)
NET INCOME
 
 
 
 
 
 
 
 
 142,591 
 
 
 
 
 
 4,093 
 
 
 146,684 
TOTAL COMPREHENSIVE INCOME
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 147,184 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
TOTAL EQUITY – DECEMBER 31, 2010
 
$
 135,660 
 
$
 674,979 
 
$
 868,840 
 
$
 (12,491)
 
$
 361 
 
$
 1,667,349 
 
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.

 
241
 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
 
CONSOLIDATED BALANCE SHEETS
 
ASSETS
 
December 31, 2010 and 2009
 
(in thousands)
 
 
 
 
 
2010
   
2009
 
CURRENT ASSETS
 
 
   
 
 
Cash and Cash Equivalents
  $ 1,514     $ 1,661  
Advances to Affiliates
    86,222       34,883  
Accounts Receivable:
               
Customers
    34,434       46,657  
Affiliated Companies
    43,219       19,542  
Miscellaneous
    17,739       9,952  
Allowance for Uncollectible Accounts
    (588 )     (64 )
Total Accounts Receivable
    94,804       76,087  
Fuel
               
(December 31, 2010 amount includes $35,055 related to Sabine)
    91,777       121,453  
Materials and Supplies
    50,395       54,484  
Risk Management Assets
    1,209       3,049  
Deferred Income Tax Benefits
    15,529       13,820  
Accrued Tax Benefits
    37,900       16,164  
Regulatory Asset for Under-Recovered Fuel Costs
    758       1,639  
Prepayments and Other Current Assets
    24,270       20,503  
TOTAL CURRENT ASSETS
    404,378       343,743  
 
               
PROPERTY, PLANT AND EQUIPMENT
               
Electric:
               
Generation
    2,297,463       1,837,318  
Transmission
    943,724       870,069  
Distribution
    1,611,129       1,447,559  
Other Property, Plant and Equipment
               
(December 31, 2010 amount includes $224,857 related to Sabine)
    632,158       733,310  
Construction Work in Progress
    1,071,603       1,176,639  
Total Property, Plant and Equipment
    6,556,077       6,064,895  
Accumulated Depreciation and Amortization
               
(December 31, 2010 amount includes $91,840 related to Sabine)
    2,130,351       2,086,333  
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    4,425,726       3,978,562  
 
               
OTHER NONCURRENT ASSETS
               
Regulatory Assets
    332,698       268,165  
Long-term Risk Management Assets
    438       84  
Deferred Charges and Other Noncurrent Assets
    80,327       49,479  
TOTAL OTHER NONCURRENT ASSETS
    413,463       317,728  
 
               
TOTAL ASSETS
  $ 5,243,567     $ 4,640,033  
 
               
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 
 
 
242
 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
 
CONSOLIDATED BALANCE SHEETS
 
LIABILITIES AND EQUITY
 
December 31, 2010 and 2009
 
 
 
 
 
2010
   
2009
 
 
 
(in thousands)
 
CURRENT LIABILITIES
 
 
   
 
 
Accounts Payable:
 
 
   
 
 
General
  $ 162,271     $ 160,870  
Affiliated Companies
    64,474       59,818  
Short-term Debt – Nonaffiliated
    6,217       6,890  
Long-term Debt Due Within One Year – Nonaffiliated
    41,135       4,406  
Long-term Debt Due Within One Year – Affiliated
    -       50,000  
Risk Management Liabilities
    4,067       844  
Customer Deposits
    48,245       41,269  
Accrued Taxes
    30,516       24,720  
Accrued Interest
    39,856       33,179  
Obligations Under Capital Leases
    13,265       14,617  
Regulatory Liability for Over-Recovered Fuel Costs
    16,432       13,762  
Provision for SIA Refund
    7,698       19,307  
Other Current Liabilities
    59,420       71,781  
TOTAL CURRENT LIABILITIES
    493,596       501,463  
 
               
NONCURRENT LIABILITIES
               
Long-term Debt – Nonaffiliated
    1,728,385       1,419,747  
Long-term Risk Management Liabilities
    338       221  
Deferred Income Taxes
    624,333       485,936  
Regulatory Liabilities and Deferred Investment Tax Credits
    393,673       333,935  
Asset Retirement Obligations
    56,632       60,562  
Employee Benefits and Pension Obligations
    96,314       125,956  
Obligations Under Capital Leases
    115,399       134,044  
Deferred Credits and Other Noncurrent Liabilities
    62,852       49,315  
TOTAL NONCURRENT LIABILITIES
    3,077,926       2,609,716  
 
               
TOTAL LIABILITIES
    3,571,522       3,111,179  
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
    4,696       4,697  
 
               
Rate Matters (Note 4)
               
Commitments and Contingencies (Note 6)
               
 
               
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
    674,979       674,979  
Retained Earnings
    868,840       726,478  
Accumulated Other Comprehensive Income (Loss)
    (12,491 )     (12,991 )
TOTAL COMMON SHAREHOLDER’S EQUITY
    1,666,988       1,524,126  
 
               
Noncontrolling Interest
    361       31  
 
               
TOTAL EQUITY
    1,667,349       1,524,157  
 
               
TOTAL LIABILITIES AND EQUITY
  $ 5,243,567     $ 4,640,033  
 
               
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 

 
243
 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
For the Years Ended December 31, 2010, 2009 and 2008
 
(in thousands)
 
 
   
 
 
 
 
2010
   
2009
   
2008
 
OPERATING ACTIVITIES
 
 
   
 
   
 
 
Net Income
  $ 146,684     $ 117,203     $ 96,445  
Adjustments to Reconcile Net Income to Net Cash Flows from
                       
Operating Activities:
                       
Depreciation and Amortization
    126,901       145,144       145,011  
Deferred Income Taxes
    81,764       28,016       62,060  
Provision for SIA Refund
    -       -       54,100  
Extraordinary Loss, Net of Tax
    -       5,325       -  
Allowance for Equity Funds Used During Construction
    (45,646 )     (46,737 )     (14,908 )
Mark-to-Market of Risk Management Contracts
    4,826       650       5,294  
Pension Contributions to Qualified Plan Trust
    (29,065 )     -       -  
Fuel Over/Under-Recovery, Net
    (6,089 )     68,024       (86,864 )
Change in Regulatory Liabilities
    26,671       (2,310 )     598  
Change in Other Noncurrent Assets
    (15,207 )     20,333       27,121  
Change in Other Noncurrent Liabilities
    21,958       9,111       (8,287 )
Changes in Certain Components of Working Capital:
                       
Accounts Receivable, Net
    (21,507 )     113,134       (52,375 )
Fuel, Materials and Supplies
    21,498       (26,190 )     (25,427 )
Accounts Payable
    (23,004 )     40,981       (36,422 )
Accrued Taxes, Net
    (18,788 )     (25,252 )     8,015  
Accrued Interest
    6,570       (3,468 )     19,612  
Other Current Assets
    (3,182 )     700       7,928  
Other Current Liabilities
    (1,433 )     (33,844 )     22,309  
Net Cash Flows from Operating Activities
    272,951       410,820       224,210  
 
                       
INVESTING ACTIVITIES
                       
Construction Expenditures
    (420,485 )     (596,581 )     (692,162 )
Change in Advances to Affiliates, Net
    (34,405 )     (34,883 )     -  
Equity Investment in Oxbow Lignite Company
    -       (12,873 )     -  
Acquisition of Red River Mining Company
    -       (15,650 )     -  
Acquisition of Valley Electric Membership Corporation
    (101,841 )     -       -  
Proceeds from Sales of Assets
    5,356       105,999       1,107  
Other Investing Activities
    (1,795 )     (2,499 )     (1,290 )
Net Cash Flows Used for Investing Activities
    (553,170 )     (556,487 )     (692,345 )
 
                       
FINANCING ACTIVITIES
                       
Capital Contribution from Parent
    -       142,500       200,000  
Issuance of Long-term Debt – Nonaffiliated
    399,394       -       437,042  
Credit Facility Borrowings
    99,688       126,903       86,095  
Change in Advances from Affiliates, Net
    -       (2,526 )     961  
Retirement of Long-term Debt – Nonaffiliated
    (53,500 )     (4,406 )     (160,444 )
Retirement of Long-term Debt – Affiliated
    (50,000 )     -       -  
Retirement of Cumulative Preferred Stock
    (1 )     -       -  
Credit Facility Repayments
    (100,361 )     (127,185 )     (79,208 )
Proceeds from Dragline Sale/Leaseback
    -       22,831       -  
Principal Payments for Capital Lease Obligations
    (12,183 )     (10,952 )     (11,511 )
Dividends Paid on Common Stock – Nonaffiliated
    (3,763 )     (3,375 )     (5,109 )
Dividends Paid on Cumulative Preferred Stock
    (229 )     (229 )     (229 )
Other Financing Activities
    1,027       1,857       706  
Net Cash Flows from Financing Activities
    280,072       145,418       468,303  
 
                       
Net Increase (Decrease) in Cash and Cash Equivalents
    (147 )     (249 )     168  
Cash and Cash Equivalents at Beginning of Period
    1,661       1,910       1,742  
Cash and Cash Equivalents at End of Period
  $ 1,514     $ 1,661     $ 1,910  
 
                       
SUPPLEMENTARY INFORMATION
                       
Cash Paid for Interest, Net of Capitalized Amounts
  $ 70,729     $ 80,671     $ 47,029  
Net Cash Paid (Received) for Income Taxes
    8,350       19,615       (33,275 )
Noncash Acquisitions Under Capital Leases
    1,593       51,217       25,398  
Construction Expenditures Included in Accounts Payable at December 31,
    94,836       71,431       76,826  
Noncash Assumption of Liabilities Related to Acquisition of Valley
                       
Electric Membership Corporation
    8,400       -       -  
SIA Refund Included in Accounts Receivable at December 31,
    -       -       85,248  
 
                       
See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246.
 

 
244
 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to SWEPCo’s consolidated 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 246.

 
Footnote
Reference
   
Organization and Summary of Significant Accounting Policies
Note 1
New Accounting Pronouncements and Extraordinary Item
Note 2
Goodwill and Other Intangible Assets
Note 3
Rate Matters
Note 4
Effects of Regulation
Note 5
Commitments, Guarantees and Contingencies
Note 6
Acquisitions
Note 7
Benefit Plans
Note 8
Business Segments
Note 9
Derivatives and Hedging
Note 10
Fair Value Measurements
Note 11
Income Taxes
Note 12
Leases
Note 13
Financing Activities
Note 14
Related Party Transactions
Note 15
Property, Plant and Equipment
Note 16
Cost Reduction Initiatives
Note 17
Unaudited Quarterly Financial Information
Note 18
 
 
245
 
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:
     
1.
Organization and Summary of Significant Accounting Policies
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
2.
New Accounting Pronouncements and Extraordinary Item
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
3.
Goodwill and Other Intangible Assets
SWEPCo
4.
Rate Matters
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
5.
Effects of Regulation
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
6.
Commitments, Guarantees and Contingencies
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
7.
Acquisitions
SWEPCo
8.
Benefit Plans
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
9.
Business Segments
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
10.
Derivatives and Hedging
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
11.
Fair Value Measurements
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
12.
Income Taxes
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
13.
Leases
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
14.
Financing Activities
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
15.
Related Party Transactions
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
16.
Property, Plant and Equipment
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
17.
Cost Reduction Initiatives
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
18.
Unaudited Quarterly Financial Information
APCo, CSPCo, I&M, OPCo, PSO, SWEPCo

 
246
 

1.   ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

The principal business conducted by AEP’s 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 engage in wholesale electricity marketing and risk management activities in the United States.  In addition, I&M provides barging services to both affiliated and nonaffiliated companies and SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities.

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 that a nonregulated affiliate can bill an affiliated public utility company 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.  They 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 cost-based due to PSO and SWEPCo having market power in the SPP region.

The state regulatory commissions regulate all of the distribution operations and rates of the Registrant Subsidiaries retail public utilities on a cost basis.  They also regulate the retail generation/power supply operations and rates except in Ohio.  The ESP rates in Ohio continue the process of aligning generation/power supply rates over time with market rates.  SWEPCo operates in the SPP area which includes a portion of Texas.  In 2009, the Texas legislature amended its restructuring legislation for the generation portion of SWEPCo’s Texas retail jurisdiction to delay indefinitely restructuring requirements.  As a result, SWEPCo reapplied accounting guidance for “Regulated Operations” to its Texas generation operations.

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.  CSPCo’s and 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.  CSPCo’s and OPCo’s retail transmission rates in Ohio and APCo’s retail transmission rates in Virginia are based on the FERC’s Open Access Transmission Tariff (OATT) rates that are cost-based.  Although I&M’s retail transmission rates in Michigan are unbundled, retail transmission rates are regulated, on a cost basis, by the Michigan Public Service Commission.  Bundled retail transmission rates are regulated, on a cost basis, by the state commissions.

In addition, the FERC regulates the SIA, the Interconnection Agreement, the CSW Operating Agreement, the System Transmission Integration Agreement, the Transmission Agreement, the Transmission Coordination Agreement and the AEP System Interim Allowance Agreement, all of which allocate shared system costs and revenues to the Registrant Subsidiaries that are parties to each agreement.

 
247
 
Principles of Consolidation

The consolidated financial statements for APCo and CSPCo include the Registrant Subsidiary and its wholly-owned subsidiaries.  The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled variable interest entities (VIEs)).  The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiaries excluding DHLC (as of January 1, 2010, SWEPCo is no longer the primary beneficiary of DHLC and is no longer required to consolidate DHLC, in accordance with “ASU 2009-17 ‘Consolidations’ ”) and Sabine (a substantially-controlled VIE).  The consolidated financial statements for OPCo include the Registrant Subsidiary and JMG (a substantially-controlled VIE that was dissolved in December 2009).  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.  CSPCo, 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 “Variable Interest Entities” section of Note 15.

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 (future revenue reductions or refunds) to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues and income with its passage to customers through the reduction of regulated revenues.  Due to the passage of legislation requiring restructuring and a transition to customer choice and market-based rates, CSPCo and OPCo discontinued the application of “Regulated Operations” accounting treatment for the generation portion of their business.  In 2009, the Texas legislature amended its restructuring legislation for the generation portion of SWEPCo’s Texas retail jurisdiction to delay indefinitely restructuring requirements.  As a result, SWEPCo reapplied accounting guidance for “Regulated Operations” to its Texas generation operations.

Accounting guidance for “Discontinuation of Rate-Regulated Operations” requires the recognition of an impairment of stranded net regulatory assets and stranded plant costs if they are not recoverable in regulated rates.  In addition, an enterprise is required to eliminate from its balance sheet the effects of any actions of regulators that had been recognized as regulatory assets and regulatory liabilities.  Such impairments and adjustments are classified as an extraordinary item.  Consistent with accounting guidance for “Discontinuation of Rate-Regulated Operations,” SWEPCo recorded an extraordinary reduction in earnings and shareholder’s equity from the reapplication of “Regulated Operations” accounting guidance in 2009.

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.

 
248
 
Other Cash Deposits

Other Cash Deposits include funds held by trustees primarily for environmental construction expenditures.

Inventory

Fossil fuel inventories are generally 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, 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, through purchase agreements with CSPCo, 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.  See “Sale of Receivables – AEP Credit” section of Note 14 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, 2010.

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 provision for credit loss has been made in the accompanying Registrant Subsidiary financial statements.

Emission Allowances

The Registrant Subsidiaries record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. They follow the inventory model for these allowances.  Allowances expected to be consumed within one year are reported in Materials and Supplies for all of the Registrant Subsidiaries except CSPCo who reflects allowances in Emission Allowances.  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.  Allowances held for speculation are included in Prepayments and Other Current Assets for all the Registrant Subsidiaries except CSPCo, who reflects allowances held for speculation in Emission Allowances.  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
 
 
249
 
transactions and in Sales to AEP Affiliates Revenues 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 purchase cost. Additions, major replacements and betterments are added to the plant accounts.  Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation under the group composite method of 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.  Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in the original cost, less salvage, being charged to accumulated depreciation.  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.

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.”  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

The generation operations of CSPCo and OPCo generally follow the policies of cost-based rate-regulated operations listed above but with the following exceptions.  Property, plant and equipment 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

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.  For nonregulated operations, including generating assets in Ohio, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”  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.

Valuation of Nonderivative Financial Instruments

The book values of Cash and Cash Equivalents, Other Cash Deposits, Accounts Receivable, Short-term Debt and Accounts Payable 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.

 
250
 
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.

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 non-binding 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 and 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.  Long-dated and illiquid complex or structured transactions and FTRs can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.

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 investment managers perform their 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 plans.

Assets in the benefits and nuclear trusts and Other Cash Deposits 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.  Fixed income securities do not trade on an exchange and do not have an official closing price.  Pricing vendors calculate bond valuations using financial models and matrices.  Fixed income securities are typically classified as Level 2 holdings because their valuation inputs are based on observable market data.  Observable inputs used for valuing fixed income securities are benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, bids, offers, reference data and economic events.  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 real estate and private equity investments that are valued using methods requiring judgment including appraisals.

 
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Items classified as Level 2 are primarily investments in individual fixed income securities.  These fixed income securities are valued using models with input data as follows:

   
Type of Fixed Income Security
   
United States
     
State and Local
Type of Input
 
Government
 
Corporate Debt
 
Government
             
Benchmark Yields
 
X
 
X
 
X
Broker Quotes
 
X
 
X
 
X
Discount Margins
 
X
 
X
   
Treasury Market Update
 
X
       
Base Spread
 
X
 
X
 
X
Corporate Actions
     
X
   
Ratings Agency Updates
     
X
 
X
Prepayment Schedule and History
         
X
Yield Adjustments
 
X
       

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.  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 fuel cost disallowance becomes probable, the Registrant Subsidiaries adjust their FAC deferrals and record provisions for estimated refunds to recognize these probable outcomes.  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.

Changes in fuel costs, including purchased power in Indiana and Michigan for I&M, in Texas, Louisiana and Arkansas for SWEPCo, in Oklahoma for PSO and in Virginia and West Virginia (prior to 2009) for APCo are reflected in rates in a timely manner through the FAC.  Beginning in 2009, changes in fuel costs, including purchased power in Ohio for CSPCo and OPCo and in West Virginia for APCo are reflected in rates through FAC phase-in plans.  All of the profits from off-system sales are given to customers through the FAC in West Virginia for APCo.  A portion of profits from off-system sales are shared with customers through the FAC and other rate mechanisms in Oklahoma for PSO, Texas, Louisiana and Arkansas for SWEPCo, Virginia for APCo and in Indiana and Michigan (all areas of Michigan beginning in December 2010) for I&M.  Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent (prior to 2009 for CSPCo and OPCo in Ohio), changes in fuel costs or sharing of off-system sales impacted 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.

 
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When regulatory assets are probable of recovery through regulated rates, the Registrant Subsidiaries record them as assets on the balance sheet.  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.

Traditional 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 in the financial statements 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 RTO operating in the east service territory.  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 in 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 operate 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 upon receipt of purchased electricity 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, such as in Ohio for CSPCo and OPCo and until April 2009 in Texas for SWEPCo.  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

AEPSC, on behalf of the Registrant Subsidiaries, engages in wholesale electricity, coal, natural gas and emission allowances marketing and risk management activities focused on wholesale markets where the AEP System owns assets and on adjacent markets.  These activities include the purchase and sale of energy under forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options, as well as over-the-counter options and swaps.  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 on their income statements.  For CSPCo and OPCo, the 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 on the income statements.  For APCo, I&M, PSO and SWEPCo, who are subject to cost-based regulation, the 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
 
 
253
 
hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their income statements.  For CSPCo and OPCo, the ineffective portion of the gain or loss is recognized in revenues or expense in 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 10.

Levelization of Nuclear Refueling Outage Costs

In order to match costs with nuclear refueling cycles, 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.  PSO defers distribution tree trimming costs above the level included in base rates and amortizes those deferrals commensurate with recovery through a rate rider in Oklahoma.  PSO also amortizes deferred ice storm costs commensurate with their recovery through a rate rider.

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.

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.

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.

Government Grants

In 2010, APCo received final approval for a federal stimulus grant for a commercial scale Carbon Capture and Sequestration facility under consideration at the Mountaineer Plant.  Also in 2010, CSPCo received final approval for a federal stimulus grant for the gridSMART ® demonstration program.  For each project, APCo and CSPCo are reimbursed for allowable costs incurred during the billing period.  These reimbursements result in the reduction of Other Operation and Maintenance expenses on the Consolidated Statements of Income or a reduction in Construction Work in Progress on the Consolidated Balance Sheets.

 
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Debt and Preferred Stock

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.  Some jurisdictions require that these costs be expensed upon reacquisition.  The Registrant Subsidiaries report gains and losses on the reacquisition of debt for operations that are not subject to cost-based rate regulation in Interest Expense.

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.

Where reflected in rates, redemption premiums paid to reacquire preferred stock of Registrant Subsidiaries are included in paid-in capital and amortized to retained earnings commensurate with their recovery in rates.  The excess of par value over costs of preferred stock reacquired is credited to paid-in capital and reclassified to retained earnings upon the redemption of the entire preferred stock series.

Goodwill and Intangible Assets

SWEPCo is the only Registrant Subsidiary with an intangible asset with a finite life.  SWEPCo amortizes the asset over its estimated life to its residual value (see Note 3 – Goodwill and Other Intangible Assets).  The Registrant Subsidiaries have no recorded goodwill or intangible assets with indefinite lives as of December 31, 2010 and 2009.

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 allocation and periodically rebalance the investments to targeted allocation 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 optimizing net returns.  Strategies used include:

·  
Maintaining a long-term investment horizon.
·  
Diversifying assets to help control volatility of returns at acceptable level.
·  
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 target asset allocation and allocation ranges are as follows:

Pension Plan Assets
 
Minimum
 
Target
 
Maximum
Domestic Equity
 
 30.0 
%
 
 35.0 
%
 
 40.0 
%
International and Global Equity
 
 10.0 
%
 
 15.0 
%
 
 20.0 
%
Fixed Income
 
 35.0 
%
 
 39.0 
%
 
 45.0 
%
Real Estate
 
 4.0 
%
 
 5.0 
%
 
 6.0 
%
Other Investments
 
 1.0 
%
 
 5.0 
%
 
 7.0 
%
Cash
 
 0.5 
%
 
 1.0 
%
 
 3.0 
%
 
 
 
 
 
 
 
OPEB Plans Assets
 
Minimum
 
Target
 
Maximum
Equity
 
 61.0 
%
 
 66.0 
%
 
 71.0 
%
Fixed Income
 
 29.0 
%
 
 32.0 
%
 
 37.0 
%
Cash
 
 1.0 
%
 
 2.0 
%
 
 4.0 
%

The investment policy for each benefit plan contains various investment limitations.  The investment policies establish concentration limits for securities.  Investment policies prohibit the benefit trust funds from purchasing 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.
·  
Individual stock must be less 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 one issuer
·  
20% in non-US dollar denominated
·  
5% private placements
·  
5% 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 classified as Level 1.

 
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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 six 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 (V EBA) 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 Consolidated Balance Sheet.  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 equity and debt 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 gains or losses due to the adjusted cost of investment.  I&M records unrealized gains and other-than-temporary impairments
 
 
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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, the 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).

Components of Accumulated Other Comprehensive Income (Loss) (AOCI)

AOCI is included on the balance sheets in the equity section.  Components of AOCI for the Registrant Subsidiaries as of December 31, 2010 and 2009 is shown in the following table:

 
 
December 31,
 
 
2010 
 
2009 
 
 
(in thousands)
Cash Flow Hedges, Net of Tax
 
 
 
 
 
 
APCo
 
$
 (56)
 
$
 (7,193)
CSPCo
 
 
 (134)
 
 
 (376)
I&M
 
 
 (8,685)
 
 
 (9,896)
OPCo
 
 
 10,583 
 
 
 11,806 
PSO
 
 
 8,494 
 
 
 (599)
SWEPCo
 
 
 (4,190)
 
 
 (4,935)
 
 
 
 
 
 
 
Amortization of Pension and OPEB Deferred Costs, Net of Tax
 
 
 
 
 
 
APCo
 
$
 12,412 
 
$
 8,240 
CSPCo
 
 
 5,818 
 
 
 3,343 
I&M
 
 
 2,140 
 
 
 1,267 
OPCo
 
 
 16,213 
 
 
 9,166 
SWEPCo
 
 
 3,602 
 
 
 2,665 
 
 
 
 
 
 
 
Pension and OPEB Funded Status, Net of Tax
 
 
 
 
 
 
APCo
 
$
 (60,379)
 
$
 (51,301)
CSPCo
 
 
 (57,020)
 
 
 (52,960)
I&M
 
 
 (14,344)
 
 
 (13,072)
OPCo
 
 
 (155,615)
 
 
 (139,430)
SWEPCo
 
 
 (11,903)
 
 
 (10,721)

Earnings Per Share (EPS)

APCo, CSPCo, I&M, OPCo, PSO and SWEPCo are wholly-owned subsidiaries of AEP.  Therefore, none are required to report EPS.

 
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CSPCo and OPCo Revised Depreciation Rates

Effective January 1, 2009, CSPCo and OPCo revised book depreciation rates for generating plants consistent with a completed depreciation study.  OPCo’s overall higher depreciation rates primarily related to shortened depreciable lives for certain OPCo generating facilities.  In comparing 2009 and 2008, the change in depreciation rates resulted in a net increase (decrease) in depreciation expense of:

 
 
Depreciation
 
 
Expense Variance
 
 
Years Ended
 
 
December 31,
 
 
2009/2008
 
 
(in thousands)
CSPCo
 
$
 (17,815)
OPCo
 
 
 71,056 

Adjustments to Sale of Receivables Disclosure

In the “Sale of Receivables – AEP Credit” section of Note 14, the disclosure was expanded for the Registrant Subsidiaries to reflect certain prior period amounts related to the sale of receivables that were not previously disclosed.  These omissions were not material to the financial statements and had no impact on the Registrant Subsidiaries’ previously reported net income, changes in shareholders’ equity, financial position or cash flows.

Adjustments to Benefit Plans Footnote

In Note 8 – Benefit Plans, the disclosure was expanded to reflect disclosure requirements for each of the individual Registrant Subsidiaries based on their participation in the AEP System.  These omissions were not material to the financial statements and had no impact on the Registrant Subsidiaries’ previously reported net income, changes in shareholder’s equity, financial position or cash flows.

2.   NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM

NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business.  The following represents a summary of final pronouncements that impact the Registrant Subsidiaries’ financial statements.

Pronouncements Adopted in 2010

The following standard was effective during 2010.  Consequently, the financial statements reflect its impact.

ASU 2009-17 “Consolidations” (ASU 2009-17)

In 2009, the FASB issued ASU 2009-17 amending the analysis an entity must perform to determine if it has a controlling financial interest in a VIE.  In addition to presentation and disclosure guidance, ASU 2009-17 provides that the primary beneficiary of a VIE must have both:
  
        •  The power to direct the activities of the VIE that most significantly impact the VIE’s economic performance.
      •   The obligation to absorb the losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant
  to the VIE.
       
The Registrant Subsidiaries adopted the prospective provisions of ASU 2009-17 effective January 1, 2010.  This standard required separate presentation of material consolidated VIEs’ assets and liabilities on the balance sheets.  Upon adoption, SWEPCo deconsolidated DHLC.  DHLC was deconsolidated due to the shared control between SWEPCo and CLECO.  After January 1, 2010, SWEPCo reports DHLC using the equity method of accounting.

 
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EXTRAORDINARY ITEM

SWEPCo Texas Restructuring

In August 2006, the PUCT adopted a rule extending the delay in implementation of customer choice in SWEPCo’s SPP area of Texas until no sooner than January 1, 2011.  In May 2009, the governor of Texas signed a bill related to SWEPCo’s SPP area of Texas that requires continued cost of service regulation until certain stages have been completed and approved by the PUCT such that fair competition is available to all Texas retail customer classes.  Based upon the signing of the bill, SWEPCo re-applied “Regulated Operations” accounting guidance for the generation portion of SWEPCo’s Texas retail jurisdiction effective second quarter of 2009.  Management believes that a switch to competition in the SPP area of Texas will not occur.  The reapplication of “Regulated Operations” accounting guidance resulted in an $8 million ($5 million, net of tax) extraordinary loss.

3.   GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

There is no goodwill carried by any of the Registrant Subsidiaries.

Other Intangible Assets

SWEPCo’s acquired intangible asset subject to amortization was $7.7 million at December 31, 2009, net of accumulated amortization and was included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s Consolidated Balance Sheet.  The amortization life, gross carrying amount and accumulated amortization are:

 
 
 
December 31,
 
 
 
2010 
 
2009 
 
 
 
Gross
 
 
 
Gross
 
 
 
Amortization
 
Carrying
 
Accumulated
 
Carrying
 
Accumulated
 
Life
 
Amount
 
Amortization
 
Amount
 
Amortization
 
(in years)
 
(in millions)
Advanced Royalties
15 
 
$
 - 
 
$
 - 
 
$
 29.4 
 
$
 21.7 

Amortization of the intangible asset was $1 million and $1 million for 2009 and 2008, respectively.

The Advanced Royalties asset class relates to the lignite mine of DHLC, a wholly-owned subsidiary of SWEPCo.  As of January 1, 2010, SWEPCo no longer consolidates DHLC, but rather it is reported as an equity investment resulting in the elimination of a review of this asset by SWEPCo.  Also, see “ASU 2009-17 ‘Consolidations’” section of Note 2 for discussion of impact of new accounting guidance effective January 1, 2010.

Starting in 2010, the Registrant Subsidiaries have no intangible assets.

4.   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.

CSPCo and OPCo Rate Matters
 

Ohio Electric Security Plan Filings

2009 – 2011 ESPs

The PUCO issued an order in March 2009 that modified and approved CSPCo’s and OPCo’s ESPs which established rates at the start of the April 2009 billing cycle.  The ESPs are in effect through 2011.  The order also limited annual rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011.  Some rate components and increases are exempt from these limitations.  CSPCo and OPCo collected the 2009 annualized revenue increase over the last nine months of 2009.

 
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The order provided a FAC for the three-year period of the ESP.  The FAC was phased in to avoid having the resultant rate increases exceed the ordered annual caps described above.  The FAC is subject to quarterly true-ups, annual accounting audits and prudency reviews.  See the “2009 Fuel Adjustment Clause Audit” section below.  The order allowed CSPCo and OPCo to defer any unrecovered FAC costs resulting from the annual caps and accrued associated carrying charges at CSPCo’s and OPCo’s weighted average cost of capital.  Any deferred FAC regulatory asset balance at the end of the three-year ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018.  That recovery will include deferrals associated with the Ormet interim arrangement and is subject to the PUCO’s ultimate decision regarding the Ormet interim arrangement deferrals plus related carrying charges.  See the “Ormet Interim Arrangement” section below.  The FAC deferral as of December 31, 2010 was $ 476 million for OPCo excluding $30 million of unrecognized equity carrying costs.

Discussed below are the significant outstanding uncertainties related to the ESP order:

The Ohio Consumers’ Counsel filed a notice of appeal with the Supreme Court of Ohio raising several issues including alleged retroactive ratemaking, recovery of carrying charges on certain environmental investments, Provider of Last Resort (POLR) charges and the decision not to offset rates by off-system sales margins.  A decision from the Supreme Court of Ohio is pending.
 
In November 2009, the Industrial Energy Users-Ohio filed a notice of appeal with the Supreme Court of Ohio challenging components of the ESP order including the POLR charge, the distribution riders for gridSMART ® and enhanced reliability, the PUCO’s conclusion and supporting evaluation that the modified ESPs are more favorable than the expected results of a market rate offer, the unbundling of the fuel and non-fuel generation rate components, the scope and design of the fuel adjustment clause and the approval of the plan after the 150-day statutory deadline.  A decision from the Supreme Court of Ohio is pending.

In April 2010, the Industrial Energy Users-Ohio filed an additional notice of appeal with the Supreme Court of Ohio challenging alleged retroactive ratemaking, CSPCo's and OPCo's abilities to collect through the FAC amounts deferred under the Ormet interim arrangement and the approval of the plan after the 150-day statutory deadline.  A decision from the Supreme Court of Ohio is pending.
 
  Ohio law requires that the PUCO determine, following the end of each year of the ESP, if rate adjustments included in the ESP resulted in significantly excessive earnings under the Significantly Excessive Earnings Test (SEET).  If the rate adjustments, in the aggregate, result in significantly excessive earnings, the excess amount could be returned to customers.  In September 2010, CSPCo and OPCo filed their 2009 SEET filings with the PUCO.  CSPCo’s and OPCo’s returns on common equity were 20.84% and 10.81%, respectively, including off-system sales margins.  In January 2011, the PUCO issued an order that determined a return on common equity for 2009 in excess of 17.6% would be significantly excessive.  The PUCO determined that OPCo’s 2009 earnings were not significantly excessive but determined relevant CSPCo earnings, excluding off-system sales margins, to be 19.73%, which exceeded the PUCO determined threshold by 2.13%.  As a result, the PUCO ordered CSPCo to refund $43 million ($ 28 million net of tax) of its earnings to customers, which was recorded as a revenue provision on CSPCo’s December 2010 books.  The PUCO ordered that the significantly excessive earnings be applied first to CSPCo’s FAC deferral, including unrecognized equity carrying costs, as of the date of the order, with any remaining balance to be credited to CSPCo’s customers on a per kilowatt basis which began with the first billing cycle in February 2011 through December 2011.  Several parties, including CSPCo and OPCo, have filed requests for rehearing with the PUCO, which remain pending.  CSPCo and OPCo are required to file their 2010 SEET filing with the PUCO in 2011.  Based upon the approach in the PUCO 2009 order, management does not currently believe that there are significantly excessive earnings in 2010.

Management is unable to predict the outcome of the various ongoing ESP proceedings and litigation discussed above.  If these proceedings, including future SEET filings, result in adverse rulings, it could reduce future net income and cash flows and impact financial condition.

 
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Proposed January 2012 – May 2014 ESP

In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing on a combined company basis for generation effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  The ESP also includes alternative energy resource requirements and addresses provisions regarding distribution service, energy efficiency requirements, economic development, job retention in Ohio and other matters.  The SSO presents redesigned generation rates by customer class.  Customer class rates individually vary, but on average, customers will experience net base generation increases of 1.4% in 2012 and 2.7% for the period January 2013 through May 2014.

Proposed CSPCo and OPCo Merger

In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo.  Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company.  In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo.  CSPCo and OPCo requested the reorganization transaction be effective in October 2011.  Decisions are pending from the PUCO and the FERC.

Requested Sporn Unit 5 Shutdown and Proposed Distribution Rider

In October 2010, OPCo filed an application with the PUCO for the approval of a December 2010 closure of Sporn Unit 5 and the simultaneous establishment of a new non-bypassable distribution rider, outside the rate caps established in the 2009 – 2011 ESP proceeding.  The proposed rider would recover the net book value of the unit as well as related materials and supplies as of December 2010, which is estimated to be $ 59 million, as well as future closure costs incurred after December 2010.  OPCo also requested authority to record the future closure costs as a regulatory asset or regulatory liability with a weighted average cost of capital carrying charge to be included in the proposed non-bypassable distribution rider after they are incurred.  Also in October 2010, OPCo filed a retirement notification with PJM pending PUCO approval of OPCo’s application to close Sporn Unit 5, which was granted by PJM.  Pending PUCO approval, Sporn Unit 5 continues to operate.  Management is unable to predict the outcome of this proceeding.

2009 Fuel Adjustment Clause Audit

As required under the ESP orders, the PUCO selected an outside consultant to conduct the audit of the FAC for the period of January 2009 through December 2009.  In May 2010, the outside consultant provided their confidential audit report to the PUCO.  The audit report included a recommendation that the PUCO should review whether any proceeds from a 2008 coal contract settlement agreement which totaled $ 72 million should reduce OPCo’s FAC under-recovery balance.  Of the total proceeds, approximately $58 million was recognized as a reduction to fuel expense prior to 2009 and $ 14 million reduced fuel expense in 2009 and 2010.  Hearings were held in August 2010.  If the PUCO orders any portion of the $58 million previously recognized or potential other future adjustments be used to reduce the current year FAC deferral, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

CSPCo, OPCo and Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet.  This interim arrangement was approved by the PUCO and was effective from January 2009 through September 2009.  In March 2009, the PUCO approved a FAC in the ESP filings.  The approval of the FAC, together with the PUCO approval of the interim arrangement, provided the basis to record regulatory assets for the difference between the approved market price and the rate paid by Ormet.  The Industrial Energy Users-Ohio, CSPCo and OPCo filed Notices of Appeal regarding aspects of this decision with the Supreme Court of Ohio.  A hearing at the Supreme Court of Ohio was held in February 2011.  Through September 2009, the last month of the interim arrangement, CSPCo and OPCo had $ 30 million and $34 million, respectively, of deferred FAC related to the interim arrangement including recognized carrying charges.  These amounts exclude $ 1 million and $1 million, respectively, of unrecognized equity carrying costs.  In November 2009, CSPCo and OPCo requested that the PUCO approve recovery of the deferrals under the interim agreement plus a weighted average cost of capital carrying charge.  The interim arrangement deferrals are included in CSPCo’s and OPCo’s FAC phase-in deferral balances.  See “Ohio Electric Security Plan Filings” section above.  In the ESP proceeding, intervenors requested that CSPCo and OPCo be
 
 
262
 
required to refund the Ormet-related regulatory assets and requested that the PUCO prevent CSPCo and OPCo from collecting the Ormet-related revenues in the future.  The PUCO did not take any action on this request in the ESP proceeding.  The intervenors raised the issue again in response to CSPCo’s and OPCo’s November 2009 filing to approve recovery of the deferrals under the interim agreement.  If CSPCo and OPCo are not ultimately permitted to fully recover their requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

Economic Development Rider

In April 2010, the Industrial Energy Users-Ohio filed a notice of appeal of the 2009 PUCO-approved Economic Development Rider (EDR) with the Supreme Court of Ohio.  The EDR collects from ratepayers the difference between the standard tariff and lower contract billings to qualifying industrial customers, subject to PUCO approval.  The Industrial Energy Users-Ohio raised several issues including claims that (a) the PUCO lost jurisdiction over CSPCo’s and OPCo’s ESP proceedings and related proceedings when the PUCO failed to issue ESP orders within the 150-day statutory deadline, (b) the EDR should not be exempt from the ESP annual rate limitations and (c) CSPCo and OPCo should not be allowed to apply a weighted average long-term debt carrying cost on deferred EDR regulatory assets.

In June 2010, Industrial Energy Users-Ohio filed a notice of appeal of the 2010 PUCO-approved EDR with the Supreme Court of Ohio.  The Industrial Energy Users-Ohio raised the same issues as noted in the 2009 EDR appeal plus a claim that CSPCo and OPCo should not be able to take the benefits of the higher ESP rates while simultaneously challenging the ESP orders.

As of December 31, 2010, CSPCo and OPCo have incurred $ 38 million and $30 million, respectively, in EDR costs including carrying costs.  Of these costs, CSPCo and OPCo have collected $ 35 million and $26 million, respectively, through the EDR, which CSPCo and OPCo began collecting in January 2010.  The remaining $ 3 million and $4 million for CSPCo and OPCo, respectively, are recorded as EDR regulatory assets.  If CSPCo and OPCo are not ultimately permitted to recover their deferrals or are required to refund revenue collected, it would reduce future net income and cash flows and impact financial condition.

Environmental Investment Carrying Cost Rider

In February 2010, CSPCo and OPCo filed an application with the PUCO to establish an Environmental Investment Carrying Cost Rider to recover carrying costs for 2009 through 2011 related to environmental investments made in 2009.  The carrying costs include both a return of and on the environmental investments as well as related administrative and general expenses and taxes.  In August 2010, the PUCO issued an order approving a rider of approximately $26 million and $34 million for CSPCo and OPCo, respectively, effective September 2010.  The implementation of the rider will likely not impact cash flows since this rider is subject to the rate increase caps authorized by the PUCO in the ESP proceedings, but will increase the ESP phase-in plan deferrals associated with the FAC.

Ohio IGCC Plant

In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant.  Through December 31, 2010, CSPCo and OPCo have each collected $12 million in pre-construction costs authorized in a June 2006 PUCO order and each incurred $11 million in pre-construction costs.  As a result, CSPCo and OPCo each established a net regulatory liability of approximately $ 1 million.  The order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant before June 2011, all pre-construction costs that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest.  Intervenors have filed motions with the PUCO requesting all pre-construction costs be refunded to Ohio ratepayers with interest.

CSPCo and OPCo will not start construction of an IGCC plant until existing statutory barriers are addressed and sufficient assurance of regulatory cost recovery exists.   Management cannot predict the outcome of any cost recovery litigation concerning the Ohio IGCC plant or what effect, if any, such litigation would have on future net income and cash flows.  However, if CSPCo and OPCo were required to refund all or some of the pre-construction costs collected and the costs incurred were not recoverable in another jurisdiction, it would reduce future net income and cash flows and impact financial condition.

 
263
 
SWEPCo Rate Matters

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in service in 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, plus an additional $ 125 million for transmission, excluding AFUDC.  SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $ 125 million for transmission, excluding AFUDC.  As of December 31, 2010, excluding costs attributable to its joint owners, SWEPCo has capitalized approximately $1 billion of expenditures (including AFUDC and capitalized interest of $ 137 million and related transmission costs of $66 million).  As of December 31, 2010, the joint owners and SWEPCo have contractual construction commitments of approximately $321 million (including related transmission costs of $3 million).  SWEPCo’s share of the contractual construction commitments is $235 million.  If the plant is cancelled, the joint owners and SWEPCo would incur contractual construction cancellation fees, based on construction status as of December 31, 2010, of approximately $121   million (including related transmission cancellation fees of $ 1 million).  SWEPCo’s share of the contractual construction cancellation fees would be approximately $89 million.

Discussed below are the significant outstanding uncertainties related to the Turk Plant:

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the 88 MW SWEPCo Arkansas jurisdictional share of the Turk Plant.  Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN.  The Arkansas Supreme Court ultimately concluded that the APSC erred in determining the need for additional power supply resources in a proceeding separate from the proceeding in which the APSC granted the CECPN.  However, the Arkansas Supreme Court approved the APSC’s procedure of granting CECPNs for transmission facilities in dockets separate from the Turk Plant CECPN proceeding.  SWEPCo filed a notice with the APSC of its intent to proceed with construction of the Turk Plant but that SWEPCo no longer intends to pursue a CECPN to seek recovery of the originally approved 88 MW portion of Turk Plant costs in Arkansas retail rates.  In June 2010, the APSC issued an order which reversed and set aside the previously granted CECPN.

The PUCT issued an order approving 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 construction cost, excluding AFUDC and 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.  SWEPCo appealed the PUCT’s order contending the two cost cap restrictions are unlawful.  The Texas Industrial Energy Consumers filed an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant was unnecessary to serve retail customers.  In February 2010, the Texas District Court affirmed the PUCT’s order in all respects.  In March 2010, SWEPCo and the Texas Industrial Energy Consumers appealed this decision to the Texas Court of Appeals.

The LPSC approved SWEPCo’s application to construct the Turk Plant.  The Sierra Club filed a complaint with the LPSC to begin an investigation into the construction of the Turk Plant.  In November 2010, the LPSC dismissed the complaint.

In November 2008, SWEPCo received its required air permit approval from the Arkansas Department of Environmental Quality and commenced construction at the site.  The Arkansas Pollution Control and Ecology Commission (APCEC) upheld the air permit.  The parties who unsuccessfully appealed the air permit to the APCEC filed a notice of appeal with the Circuit Court of Hempstead County, Arkansas.   In December 2010, the Circuit Court affirmed the APCEC.  In January 2011, the same parties asked the Arkansas Court of Appeals to overturn the Circuit Court’s December 2010 decision.  A decision from the Arkansas Court of Appeals is pending.

A wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009.  In 2010, the Sierra Club, the Audubon Society and others filed a complaint in the Federal District Court for the Western District of Arkansas against the U.S. Army Corps of Engineers challenging the process used and the terms of the permit issued to
 
 
264
 
SWEPCo authorizing certain wetland and stream impacts, and sought a preliminary injunction to halt construction and for a temporary restraining order.  In July 2010, the Hempstead County Hunting Club also filed a complaint with the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of the Interior and the U.S. Fish and Wildlife Service seeking a temporary restraining order and preliminary injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws.  The plaintiffs’ federal law claims challenge the process used and terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts.  The plaintiffs’ state law claims challenge SWEPCo's ability to construct the Turk Plant without obtaining a certificate from the APSC.  In 2010, the motions for preliminary injunction were partially granted and upheld on appeal pending a hearing.  According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop.  Mitigation measures required by the permit are authorized and may be completed.  The preliminary injunction affects portions of the water intake and associated piping and portions of the transmission lines.  A hearing on SWEPCo’s appeal is scheduled for March 2011.  In October 2010, the Federal District Court certified issues relating to the state law claims to the Arkansas Supreme Court, including whether those claims are within the primary jurisdiction of the APSC.  The Arkansas Supreme Court accepted the request.

In January 2009, SWEPCo was granted CECPNs by the APSC to build three transmission lines and facilities authorized by the SPP and needed to transmit power from the Turk Plant.  Intervenors appealed the CECPN decisions in April 2009 to the Arkansas Court of Appeals.  In July 2010, the Hempstead County Hunting Club and other appellants filed with the Arkansas Court of Appeals emergency motions to stay the transmission CECPNs to prohibit SWEPCo from taking ownership of private property and undertaking construction of the transmission lines.  The Arkansas Court of Appeals issued a decision in July 2010 remanding all transmission line CECPN appeals to the APSC.  As a result, a stay was not ordered and construction continues on the affected transmission lines.  In January 2011, the appellants filed requests to withdraw their appeals at the Court of Appeals and the APSC postponed a scheduled hearing pending a ruling on those requests.  In February 2011, the Court of Appeals dismissed the appeals, and the APSC subsequently closed the remand docket, finding the CECPN decisions final and non-appealable.  As previously discussed, the preliminary injunction issued by the Federal District Court related to the wetlands permit also impacts the uncompleted construction on portions of the transmission lines.

Management expects that SWEPCo will ultimately be able to complete construction of the Turk Plant and related transmission facilities and place those facilities in service.  However, if SWEPCo is unable to complete the Turk Plant construction, including the related transmission facilities, and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.

Stall Unit

SWEPCo constructed the Stall Unit, an intermediate load 500 MW natural gas-fired combustion turbine combined cycle generating unit, at its existing Arsenal Hill Plant located in Shreveport, Louisiana.  The LPSC and the APSC issued orders capping SWEPCo’s Stall Unit construction costs at $ 445 million including AFUDC and excluding related transmission costs.  The Stall Unit was placed in service in June 2010.  As of December 31, 2010, the Stall Unit cost applicable to the cap was $426 million, including $ 49 million of AFUDC.  Management does not expect the final costs of the Stall Unit to exceed the ordered cap.  In July 2010, the Stall Unit was placed into Arkansas rates.  SWEPCo received CWIP treatment for a portion of the Stall Unit in the 2009 Texas Base Rate Filing.  See “2009 Texas Base Rate Filing” section below.  The Stall Unit will be phased into Louisiana rates between October 2010 and October 2011.

Louisiana Fuel Adjustment Clause Audit

Consultants for the LPSC issued their audit report of SWEPCo’s Louisiana retail FAC.  The audit report included a significant recommendation that might result in a financial impact that could be material for SWEPCo.  The audit report recommended that the LPSC discontinue SWEPCo’s tiered sharing mechanism related to off-system sales margins on a prospective basis and that SWEPCo included inappropriate costs in the FAC.  In September 2010, the LPSC consultants filed testimony supporting their audit report findings but did not quantify their recommendations.  Management is unable to predict how the LPSC will rule on the recommendations in the audit report and its financial statement impact on net income, cash flows and financial condition.

 
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2009 Texas Base Rate Filing

In August 2009, SWEPCo filed a rate case with the PUCT to increase its base rates by approximately $ 75 million annually including a return on common equity of 11.5%.  The filing included requests for financing cost riders of $ 32 million related to construction of the Stall Unit and Turk Plant, a vegetation management rider of $16 million and other requested increases of $ 27 million.  In April 2010, a settlement agreement was approved by the PUCT to increase SWEPCo’s base rates by approximately $15 million annually, effective May 2010, including a return on common equity of 10.33%, which consists of $5 million related to construction of the Stall Unit and $ 10 million in other increases.  In addition, the settlement agreement decreased annual depreciation expense by $17 million and allowed SWEPCo a $ 10 million one-year surcharge rider to recover additional vegetation management costs that SWEPCo must spend within two years.

Texas Fuel Reconciliation

In May 2010, various intervenors, including the PUCT staff, filed testimony recommending disallowances ranging from $ 3 million to $30 million in SWEPCo’s $ 755 million fuel and purchased power costs reconciliation for the period January 2006 through March 2009.  In July 2010, Cities Advocating Reasonable Deregulation filed testimony regarding the 2007 transfer of ERCOT trading contracts to AEPEP.  The testimony included unquantified refund recommendations relating to re-pricing of contract transactions.

In September 2010, the Administrative Law Judges issued a Proposal for Decision (PFD) that recommended a disallowance of a significant portion of the charges under a ten-year gas transportation agreement that began in 2009 for the Mattison Plant located in northwest Arkansas.  In January 2011, the PUCT issued an order which overturned a portion of the PFD that recommended a finding of imprudence on the Mattison gas contract.  The impact of this order had an immaterial impact on SWEPCo’s financial statements.

Louisiana 2008 Formula Rate Filing

In April 2008, SWEPCo filed its first formula rate filing under an approved three-year formula rate plan (FRP).  SWEPCo requested an increase in its annual Louisiana retail rates of $11 million to be effective in August 2008 in order to earn the approved formula return on common equity of 10.565%.  In August 2008, as provided by the FRP, SWEPCo implemented the FRP rates, subject to refund.  During 2009, SWEPCo recorded a provision for refund of approximately $1 million after reaching a settlement in principle with intervenors.  A settlement stipulation was reached by the parties and is pending LPSC approval.  SWEPCo began refunding customers in August 2010.

Louisiana 2009 Formula Rate Filing

In April 2009, SWEPCo filed the second FRP which would increase its annual Louisiana retail rates by an additional $4 million effective in August 2009.  SWEPCo implemented the FRP rate increase as filed in August 2009, subject to refund.  In October 2009, consultants for the LPSC objected to certain components of SWEPCo’s FRP calculation.  In February 2011, a settlement stipulation was reached by the parties and is pending LPSC approval.  The settlement stipulation agreed to a $2 million refund, which was recorded in 2010 as a provision in Other Current Liabilities on SWEPCo's Consolidated Balance Sheets.  If a refund is required, it could reduce future net income and cash flows.

Louisiana 2010 Formula Rate Filing

In April 2010, SWEPCo filed the third FRP which would decrease its annual Louisiana retail rates by $3 million effective in August 2010 pursuant to the approved FRP, subject to refund.  In October 2010, consultants for the LPSC objected to certain components of SWEPCo’s FRP calculations.  SWEPCo believes the rates as filed are in compliance with the FRP methodology previously approved by the LPSC.  If the LPSC disagrees with SWEPCo, it could result in refunds which could reduce future net income and cash flows.

 
266
 
APCo Rate Matters

2009 Virginia Base Rate Case

In July 2009, APCo filed a generation and distribution base rate increase with the Virginia SCC of $ 154 million annually based on a 13.35% return on common equity.  Interim rates, subject to refund, became effective in December 2009 but were discontinued in February 2010 when newly enacted Virginia legislation suspended the collection of interim rates.  In July 2010, the Virginia SCC issued an order approving a $ 62 million increase based on a 10.53% return on common equity.  The order denied recovery of the Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility, which resulted in a pretax write-off of $ 54 million in Other Operation.  See “Mountaineer Carbon Capture and Storage Project” section below.  In addition, the order allowed the deferral of approximately $25 million of incremental storm expense incurred in 2009.  Approximately $ 3 million, including interest, was refunded to customers in September 2010 related to the collection of interim rates.

2010 West Virginia Base Rate Case

In May 2010, APCo filed a request with the WVPSC to increase annual base rates by $140 million based on an 11.75% return on common equity to be effective March 2011.  The filing also included a request for recovery of and a return on the West Virginia jurisdictional share of the Mountaineer Carbon Capture and Storage Product Validation Facility.  In December 2010, a settlement agreement was filed with the WVPSC to increase annual base rates by $54 million, effective March 2011.  In addition, the settlement agreement allows APCo to defer and amortize up to $18 million of previously expensed 2009 incremental storm expenses over a period of eight years.  A decision from the WVPSC is expected in March 2011.

Mountaineer Carbon Capture and Storage Project

Product Validation Facility (PVF)

APCo and ALSTOM Power, Inc., an unrelated third party, jointly constructed a CO 2 capture validation facility, which was placed into service in September 2009.  APCo also constructed and owns the necessary facilities to store the CO 2 .  In October 2009, APCo started injecting CO 2 into the underground storage facilities.  The injection of CO 2 required the recording of an asset retirement obligation and an offsetting regulatory asset.  As of December 31, 2010, APCo has recorded a noncurrent regulatory asset of $60 million related to the PVF.

In APCo’s July 2009 Virginia base rate filing, APCo requested recovery of and a return on its Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion.  In July 2010, the Virginia SCC issued a base rate order that denied recovery of the Virginia share of the PVF costs.  See “2009 Virginia Base Rate Case” section above.

In APCo’s May 2010 West Virginia base rate filing, APCo requested recovery of and a return on its West Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion.  In December 2010, a settlement agreement was filed with the WVPSC to increase annual base rates by $54 million, effective March 2011.  A decision from the WVPSC is expected in March 2011.  If APCo cannot recover its remaining investment in and expenses related to the PVF, it would reduce future net income and cash flows and impact financial condition.

Carbon Capture and Sequestration Project with the Department of Energy (DOE)

During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale carbon capture and sequestration (CCS) facility under consideration at the Mountaineer Plant.  AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project.  The DOE will fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million.  A Front-End Engineering and Design (FEED) study, scheduled for completion during the third quarter of 2011, will refine the total cost estimate for the CCS facility.  Results from the FEED study will be evaluated by management before any decision is made to seek the necessary regulatory approvals to build the CCS facility.  As of December 31, 2010, APCo has incurred $14 million in
 
 
267
 
total costs and has received $5 million of DOE funding resulting in a net $9 million balance included in Construction Work In Progress on the Consolidated Balance Sheets.  If APCo is unable to recover the costs of the CCS project, it would reduce future net income and cash flows.

APCo’s Filings for an IGCC Plant

In 2008, the Virginia SCC issued an order denying APCo’s request for a surcharge rate mechanism to provide for the timely recovery of pre-construction costs and the ongoing financing costs of the project during the construction period, as well as the capital costs, operating costs and a return on common equity once the facility is placed into commercial operation. The order was based upon the Virginia SCC's finding that the estimated cost of the plant was uncertain and may escalate.  The Virginia SCC also expressed concerns that the estimated costs did not include a retrofitting of carbon capture and sequestration facilities.  During 2009, based on the order received in Virginia, the WVPSC removed the IGCC case as an active case from its docket and indicated that the conditional CPCN granted in 2008 must be reconsidered if and when APCo proceeds with the IGCC plant.

Through December 31, 2010, 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 $ 9 million applicable to its Virginia jurisdiction.

APCo will not start construction of the IGCC plant until sufficient assurance of full cost recovery exists in Virginia and West Virginia.  If the plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs which, if not recoverable, would reduce future net income and cash flows and impact financial condition.

APCo’s 2009 Expanded Net Energy Charge (ENEC) Filing

In September 2009, the WVPSC issued an order approving APCo’s March 2009 ENEC request.  The approved order provided for recovery of an under-recovered balance plus a projected increase in ENEC costs over a four-year phase-in period with an overall increase of $320 million and a first-year increase of $112 million, effective October 2009.  The WVPSC also approved a fixed annual carrying cost rate of 4%, effective October 2009, to be applied to the incremental deferred regulatory asset balance that will result from the phase-in plan and lowered annual coal cost projections by $27 million.

In June 2010, the WVPSC approved a settlement agreement for $86 million, including $9 million of construction surcharges related to APCo’s second year ENEC increase.  The settlement agreement provided for recovery of the amounts related to the renegotiated coal contracts and allows APCo to accrue weighted average cost of capital carrying costs on the excess under-recovery balance due to the ENEC phase-in as adjusted for the impacts of Accumulated Deferred Income Taxes.  As of December 31, 2010, APCo’s ENEC under-recovery balance was $361 million, excluding $3 million of unrecognized equity carrying costs, which is included in noncurrent regulatory assets.  The new rates became effective in July 2010.

WPCo Merger with APCo

In a proceeding established by the WVPSC to explore options to meet WPCo's future power supply requirements, the WVPSC, in November 2009, issued an order approving a joint stipulation among APCo, WPCo, the WVPSC staff and the Consumer Advocate Division.  The order approved the recommendation of the signatories to the stipulation that WPCo merge into APCo and be supplied from APCo's existing power resources.  Merger approvals from the WVPSC, Virginia SCC and the FERC are required.  No merger approval filings have been made.

 
268
 
PSO Rate Matters

PSO Fuel and Purchased Power

2006 and Prior Fuel and Purchased Power

The OCC filed a complaint with the FERC related to the allocation of off-system sales margins (OSS) among the AEP operating companies in accordance with a FERC-approved allocation agreement.  The FERC issued an adverse ruling in 2008.  As a result, PSO recorded a regulatory liability in 2008 to return reallocated OSS to customers.  Starting in March 2009, PSO refunded the additional reallocated OSS to its customers through February 2010.

A reallocation of purchased power costs among AEP West companies for periods prior to 2002 resulted in an under-recovery of $ 42 million of PSO fuel costs.  PSO recovered the $42 million by offsetting it against an existing fuel over-recovery during the period June 2007 through May 2008.  The Oklahoma Industrial Energy Consumers (OIEC) contended that PSO should not have collected the $ 42 million without specific OCC approval.  In December 2010, the OCC issued orders which approved PSO’s 2006 and prior fuel and purchased power costs without any adjustments.

2008 Fuel and Purchased Power

In July 2009, the OCC initiated a proceeding to review PSO’s fuel and purchased power adjustment clause for the calendar year 2008 and also initiated a prudence review of the related costs.  In March 2010, the Oklahoma Attorney General and the OIEC recommended the fuel clause adjustment rider be amended so that the shareholder’s portion of off-system sales margins decrease from 25% to 10%.  The OIEC also recommended that the OCC conduct a comprehensive review of all affiliate transactions during 2007 and 2008.  In July 2010, additional testimony regarding the 2007 transfer of ERCOT trading contracts to AEPEP was filed.  The testimony included unquantified refund recommendations relating to re-pricing of contract transactions.  Hearings are currently scheduled for March 2011.  If the OCC were to issue an unfavorable decision, it could reduce future net income and cash flows and impact financial condition.

2008 Oklahoma Base Rate Appeal

In January 2009, the OCC issued a final order approving an $ 81 million increase in PSO’s non-fuel base revenues based on a 10.5% return on common equity.  The new rates reflecting the final order were implemented with the first billing cycle of February 2009.  PSO and intervenors appealed various issues but the Court of Civil Appeals affirmed the OCC's decision.  No parties sought rehearing or appeal and, as a result, this case has concluded.

2010 Oklahoma Base Rate Case

In July 2010, PSO filed a request with the OCC to increase annual base rates by $ 82 million, including $30 million that is currently being recovered through a rider.  The requested net annual increase to ratepayers would be $52 million.  The requested increase included a $24 million increase in depreciation and an 11.5% return on common equity.  In January 2011, the OCC approved a settlement agreement which did not change annual revenue or depreciation rates, but transferred $30 million into base rates that was previously being recovered through a capital investment rider.  The order provided a 10.15% return on common equity and new rates were effective in February 2011.

I&M Rate Matters

Indiana Fuel Clause Filing (Cook Plant Unit 1 Fire and Shutdown)

I&M filed applications with the IURC to increase its fuel adjustment charge by approximately $ 53 million for the period of April 2009 through September 2009.  The filings sought increases for previously under-recovered fuel clause expenses.

As fully discussed in the “Cook Plant Unit 1 Fire and Shutdown” section of Note 6, Cook Plant Unit 1 (Unit 1) was shut down in September 2008 due to significant turbine damage and a small fire on the electric generator.  Unit 1 was placed back into service in December 2009 at slightly reduced power.  The unit outage resulted in increased replacement power fuel costs.  The filing only requested the cost of replacement power through mid-December 2008, the date when I&M began receiving accidental outage insurance proceeds.  I&M committed to absorb the remaining costs of replacement power through the date the unit returned to service, which occurred in December 2009.

 
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I&M reached an agreement with intervenors, which was approved by the IURC in March 2009, to collect its existing prior period under-recovery regulatory asset deferral balance over twelve months instead of over six months as initially proposed.  Under the agreement, the fuel factors were placed into effect, subject to refund, and a subdocket was established to consider issues relating to the Unit 1 shutdown including the treatment of the accidental outage insurance proceeds.  I&M maintains a separate accidental outage policy with NEIL.  In 2009, I&M recorded $185 million in revenue under the policy and reduced the cost of replacement power in customers’ bills by $78 million.

In October 2010, the Indiana/Michigan Industrial Group and the Indiana Office of Utility Consumer Counselor filed testimony which recommended I&M pay to customers a portion of the accidental outage insurance proceeds up to the extent not previously paid to customers through the fuel adjustment clause or needed to cover costs not covered by I&M’s property damage insurance policy.  In January 2011, a settlement agreement was filed with the IURC.  The settlement stated (a) that I&M will credit an additional $14 million to customers through the fuel adjustment clause, (b) that the parties to the settlement will not oppose the need to replace the existing low-pressure turbine at Cook Unit 1, and (c) that the parties to the settlement agree that the cost of the replacement should not be offset by the accidental outage insurance proceeds received by I&M.  In February 2011, the IURC approved the settlement agreement as filed.

Michigan 2009 Power Supply Cost Recovery (PSCR) Reconciliation (Cook Plant Unit 1 Fire and Shutdown)

In March 2010, I&M filed its 2009 PSCR reconciliation with the MPSC.  The filing included an adjustment to exclude from the PSCR the incremental fuel cost of replacement power due to the Unit 1 outage from mid-December 2008 through December 2009, the period during which I&M received and recognized the accidental outage insurance proceeds.  Management believes that I&M is entitled to retain the accidental outage insurance proceeds since it made customers whole regarding the replacement power costs.  In October 2010, a settlement agreement was filed with the MPSC which included deferring the Unit 1 outage issue to the 2010 PSCR reconciliation, which will be filed in March 2011.  If any fuel clause revenues or accidental outage insurance proceeds have to be paid to customers, it would reduce future net income and cash flows and impact financial condition.  See the “Cook Plant Unit 1 Fire and Shutdown” section of Note 6.

Michigan Base Rate Filing

In January 2010, I&M filed with the MPSC a request for a $63 million increase in annual base rates based on an 11.75% return on common equity.  Starting with the August 2010 billing cycle, I&M, with MPSC authorization, implemented a $ 44 million interim rate increase.  The interim increase excluded new trackers and regulatory assets for which I&M was not currently incurring expenses.  In October 2010, a settlement agreement was approved by the MPSC to increase annual base rates by $36 million based on a 10.35% return on common equity, effective December 2010, plus separate recovery of approximately $7 million of customer choice implementation costs over a two year period beginning April 2011.  In addition, the approved revenue requirement includes the amortization of $6 million in previously expensed restructuring costs over five years, which I&M deferred in October 2010 and began amortizing in December 2010.  Also, the approved settlement agreement provided for sharing of off-system sales margins between customers (75%) and I&M ( 25%) with customers receiving a credit in future Power Supply Cost Recovery proceedings for their jurisdictional share of any off-system sales margins.  Through December 2010, I&M recorded a provision for refund of $3 million, including interest, related to interim rates that were in effect through November 2010.  In January 2011, I&M filed an application with the MPSC requesting the MPSC find that $3 million, including interest, is the total amount to be refunded to customers.  I&M is proposing to refund this amount to customers during April 2011.  A decision from the MPSC is pending.

 
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FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund

In 2004, AEP eliminated transaction-based through-and-out transmission service (T&O) charges in accordance with FERC orders and collected, at the FERC’s direction, load-based charges, referred to as RTO SECA, to partially mitigate the loss of T&O revenues on a temporary basis through March 2006.  Intervenors objected to the temporary SECA rates.  The FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund.  The AEP East companies recognized gross SECA revenues of $220 million from 2004 through 2006 when the SECA rates terminated.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of recognized gross SECA revenues are as follows:

Company
 
(in millions)
APCo
 
$
70.2 
CSPCo
   
38.8 
I&M
   
41.3 
OPCo
   
53.3 

In 2006, a FERC Administrative Law Judge (ALJ) issued an initial decision finding that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made.  The ALJ also found that any unpaid SECA rates must be paid in the recommended reduced amount.

AEP filed briefs jointly with other affected companies asking the FERC to reverse the decision.  In May 2010, the FERC issued an order that generally supports AEP’s position and requires a compliance filing to be filed with the FERC by August 2010.  In June 2010, AEP and other affected companies filed a joint request for rehearing with the FERC.

The AEP East companies provided reserves for net refunds for SECA settlements totaling $44 million applicable to the $220 million of SECA revenues collected.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the provision are as follows:

Company
 
(in millions)
APCo
 
$
14.1 
CSPCo
   
7.8 
I&M
   
8.3 
OPCo
   
10.7 

Settlements approved by the FERC consumed $10 million of the reserve for refunds applicable to $112 million of SECA revenue.  In December 2010, the FERC issued an order approving a settlement agreement resulting in the collection of $2 million of previously deemed uncollectible SECA revenue.  Therefore, the AEP East companies reduced their reserves for net refunds for SECA settlements by $2 million.  The balance in the reserve for future settlements as of December 31, 2010 was $32 million.  APCo’s, CSPCo’s, I&M’s and OPCo’s reserve balances at December 31, 2010 were:

Company
 
December 31, 2010
   
(in millions)
APCo
 
$
10.0 
CSPCo
   
5.6 
I&M
   
5.9 
OPCo
   
7.6 

 
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In August 2010, the affected companies, including the AEP East companies, filed a compliance filing with the FERC.  If the compliance filing is accepted, the AEP East companies would have to pay refunds of approximately $20 million including estimated interest of $5 million.  The AEP East companies could also potentially receive payments up to approximately $10 million including estimated interest of $3 million.  A decision is pending from the FERC.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of potential refund payments and potential payments to be received are as follows:

Company
 
Potential Refund Payments
 
Potential Payments to be Received
   
(in millions)
APCo
 
$
6.4
 
$
3.2
CSPCo
   
3.5
   
1.8
I&M
   
3.7
   
1.9
OPCo
   
4.8
   
2.4

Based on the AEP East companies’ analysis of the May 2010 order and the compliance filing, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the May 2010 order or the compliance filing be made final.  Management cannot predict the ultimate outcome of this proceeding at the FERC which could impact future net income and cash flows.


Allocation of Off-system Sales Margins – Affecting PSO and SWEPCo

The OCC filed a complaint at the FERC alleging that AEP inappropriately allocated off-system sales margins between the AEP East companies and the AEP West companies and did not properly allocate off-system sales margins within the AEP West companies.

In 2009, AEP made a compliance filing with the FERC and the AEP East companies refunded approximately $250 million to the AEP West companies.  Following authorized regulatory treatment, the AEP West companies shared a portion of SIA margins with their customers during the period June 2000 to March 2006.  In 2008, the AEP West companies recorded a provision for refund reflecting the sharing.  Refunds have been or are currently being returned to PSO, SWEPCo and FERC customers.  Management believes the AEP West companies’ provision for refund is adequate.

Modification of the Transmission Agreement (TA) – Affecting APCo, CSPCo, I&M and OPCo

The AEP East companies are parties to the TA that provides for a sharing of the cost of transmission lines operated at 138-kV and above and transmission stations containing extra-high voltage facilities.  In June 2009, AEPSC, on behalf of the parties to the TA, filed with the FERC a request to modify the TA.  Under the proposed amendments, KGPCo and WPCo will be added as parties to the TA.  In addition, the amendments would provide for the allocation of PJM transmission costs generally on the basis of the TA parties’ 12-month coincident peak and reimburse transmission revenues based on individual cost of service instead of the MLR method used in the present TA.  In October 2010, the FERC approved a settlement agreement for the new TA effective November 1, 2010.  The impacts of the settlement agreement will be phased-in for retail rate making purposes in certain jurisdictions over periods of up to four years.

PJM Transmission Formula Rate Filing – Affecting APCo, CSPCo, I&M and OPCo

AEP filed an application with the FERC in July 2008 to increase its open access transmission tariff (OATT) rates for wholesale transmission service within PJM.  The filing sought to implement a formula rate allowing annual adjustments reflecting future changes in the AEP East companies' cost of service.  The FERC issued an order conditionally accepting AEP’s proposed formula rate and delayed the requested October 2008 effective date for five months.  AEP began settlement discussions with the intervenors and the FERC staff which resulted in a settlement that was filed with the FERC in April 2010.

 
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In October 2010, a settlement agreement was approved by the FERC which resulted in a $51 million annual increase beginning in April 2009 for service as of March 2009, of which approximately $7 million is being collected from nonaffiliated customers within PJM.  Prior to November 2010, the remaining $44 million was billed to the AEP East companies and was generally offset by compensation from PJM for use of the AEP East companies’ transmission facilities so that net income was not directly affected.  Beginning in November 2010, AEP East companies, KGPCo and WPCo, which are parties to the modified TA, allocate revenue and expenses on different methodologies and will affect net income.  See “Modification of the Transmission Agreement” above.

The settlement also results in an additional $30 million increase for the first annual update of the formula rate, beginning in August 2009 for service as of July 2009.  Approximately $4 million of the increase will be collected from nonaffiliated customers within PJM with the remaining $26 million being billed to the AEP East companies.

Under the formula, an annual update will be filed to be effective July 2010 and each year thereafter.  Also, beginning with the July 2010 update, the rates each year will include an adjustment to true-up the prior year's collections to the actual costs for the prior year.  In May 2010, the second annual update was filed with the FERC to decrease the revenue requirement by $58 million for service as of July 2010.  Approximately $8 million of the decrease will be refunded to nonaffiliated customers within PJM.


Transmission Agreement (TA) – Affecting APCo, CSPCo, I&M and OPCo

Certain transmission facilities placed in service in 1998 were inadvertently excluded from the AEP East companies’ TA calculation prior to January 2009.  The excluded equipment was KPCo’s Inez Station which had been determined as eligible equipment for inclusion in the TA in 1995 by the AEP TA transmission committee.  The amount involved was $7 million annually.  In June 2010, the KPSC approved a settlement agreement in KPCo’s base rate filing which set new base rates effective July 2010 but excluded consideration of this issue.

PJM/MISO Market Flow Calculation Settlement Adjustments - Affecting APCo, CSPCo, I&M and OPCo

During 2009, an analysis conducted by MISO and PJM discovered several instances of unaccounted for power flows on numerous coordinated flowgates.  These flows affected the settlement data for congestion revenues and expenses and dated back to the start of the MISO market in 2005.  In January 2011, PJM and MISO reached a settlement agreement where the parties agreed to net various issues to zero.  This settlement was filed with the FERC in January 2011.  PJM and MISO are currently awaiting final approval from the FERC.

 
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5.   EFFECTS OF REGULATION

Regulatory assets and liabilities are comprised of the following items:

 
 
 
 
 
 
 
APCo
 
I&M
 
 
 
 
 
 
 
 
 
Remaining
 
 
 
Remaining
 
 
 
 
 
 
 
December 31,
 
Recovery
 
December 31,
 
Recovery
Regulatory Assets:
 
2010 
 
2009 
 
Period
 
2010 
 
2009 
 
Period
 
 
(in thousands)
 
 
 
(in thousands)
 
 
Current Regulatory Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Under-recovered Fuel Costs - earns a return
 
$
 18,300 
 
$
 78,685 
 
1 year
 
$
 - 
 
$
 4,826 
 
 
Under-recovered Fuel Costs - does not earn a return
 
 
 - 
 
 
 - 
 
 
 
 
 8,467 
 
 
 - 
 
1 year
Total Current Regulatory Assets
 
$
 18,300 
 
$
 78,685 
 
 
 
$
 8,467 
 
$
 4,826 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Customer Choice Implementation Costs
 
$
 - 
 
$
 - 
 
 
 
$
 - 
(b)
$
 6,311 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mountaineer Carbon Capture and Storage
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Product Validation Facility
 
 
 59,866 
 
 
 110,665 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Virginia Environmental Rate Adjustment Clause
 
 
 55,724 
 
 
 25,311 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Deferred Wind Power Costs
 
 
 28,584 
 
 
 5,372 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Storm Related Costs
 
 
 25,225 
 
 
 - 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Special Rate Mechanism for Century Aluminum
 
 
 12,628 
 
 
 12,422 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Virginia Transmission Rate Adjustment Clause
 
 
 - 
(a)
 
 26,184 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Deferred PJM Fees
 
 
 - 
 
 
 - 
 
 
 
 
 - 
(b)
 
 6,254 
 
 
 
 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 604 
 
 
 315 
 
 
 
 
 - 
 
 
 - 
 
 
Total Regulatory Assets Not Yet Being Recovered
 
 
 182,631 
 
 
 180,269 
 
 
 
 
 - 
 
 
 12,565 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory assets being recovered:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expanded Net Energy Charge
 
 
 361,314 
(c)
 
 - 
 
3 years
 
 
 - 
 
 
 - 
 
 
 
 
 
Unamortized Loss on Reacquired Debt
 
 
 12,679 
 
 
 13,456 
 
26 years
 
 
 18,507 
 
 
 16,326 
 
22 years
 
 
 
RTO Formation/Integration Costs
 
 
 5,952 
 
 
 6,647 
 
9 years
 
 
 4,437 
 
 
 4,967 
 
9 years
 
 
 
Customer Choice Implementation Costs
 
 
 - 
 
 
 - 
 
 
 
 
 6,767 
(b)
 
 - 
 
3 years
 
 
 
Other Regulatory Assets Being Recovered
 
 
 - 
 
 
 - 
 
 
 
 
 1,103 
 
 
 1,674 
 
various
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Taxes, Net
 
 
 523,009 
 
 
 490,356 
 
29 years
 
 
 159,453 
 
 
 152,722 
 
37 years
 
 
 
Pension and OPEB Funded Status
 
 
 335,105 
 
 
 331,631 
 
13 years
 
 
 268,080 
 
 
 252,011 
 
13 years
 
 
 
Postemployment Benefits
 
 
 25,484 
 
 
 26,045 
 
4 years
 
 
 8,968 
 
 
 8,398 
 
4 years
 
 
 
Virginia Transmission Rate Adjustment Clause
 
 
 19,271 
(a)
 
 - 
 
2 years
 
 
 - 
 
 
 - 
 
 
 
 
 
Asset Retirement Obligation
 
 
 12,560 
 
 
 14,595 
 
7 years
 
 
 2,700 
 
 
 2,120 
 
10 years
 
 
 
Virginia Environmental and Reliability Costs
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recovery
 
 
 4,421 
 
 
 76,057 
 
3 years
 
 
 - 
 
 
 - 
 
 
 
 
 
West Virginia Reliability Expense
 
 
 3,158 
 
 
 7,956 
 
1 year
 
 
 - 
 
 
 - 
 
 
 
 
 
Postretirement Benefits
 
 
 26 
 
 
 38 
 
3 years
 
 
 1,857 
 
 
 3,373 
 
2 years
 
 
 
Cook Nuclear Plant Refueling Outage Levelization
 
 
 - 
 
 
 - 
 
 
 
 
 53,795 
 
 
 21,856 
 
3 years
 
 
 
Off-system Sales Margin Sharing
 
 
 - 
 
 
 - 
 
 
 
 
 13,091 
 
 
 17,583 
 
1 year
 
 
 
Deferred PJM Fees
 
 
 - 
 
 
 - 
 
 
 
 
 7,078 
(b)
 
 - 
 
2 years
 
 
 
Deferred Severance Costs
 
 
 - 
 
 
 - 
 
 
 
 
 6,217 
 
 
 - 
 
5 years
 
 
 
Expanded Net Energy Charge
 
 
 - 
(c)
 
 281,818 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Virginia Restructuring Transition Costs
 
 
 - 
 
 
 4,245 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Other Regulatory Assets Being Recovered
 
 
 1,015 
 
 
 678 
 
various
 
 
 4,201 
 
 
 2,869 
 
various
Total Regulatory Assets Being Recovered
 
 
 1,303,994 
 
 
 1,253,522 
 
 
 
 
 556,254 
 
 
 483,899 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Noncurrent Regulatory Assets
 
$
 1,486,625 
 
$
 1,433,791 
 
 
 
$
 556,254 
 
$
 496,464 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a) Recovery of regulatory asset through the transmission rate adjustment clause.
(b) Recovery of regulatory asset was granted during 2010.
(c) The majority of the balance results from the ENEC phase-in plan and earns a weighted average cost of capital carrying charge.

 
274
 
 
 
 
 
 
 
 
APCo
 
I&M
 
 
 
 
 
 
 
 
 
Remaining
 
 
 
Remaining
 
 
 
 
 
 
 
December 31,
 
Refund
 
December 31,
 
Refund
Regulatory Liabilities:
 
2010 
 
2009 
 
Period
 
2010 
 
2009 
 
Period
 
 
(in thousands)
 
 
 
(in thousands)
 
 
Current Regulatory Liability
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Over-recovered Fuel Costs - pays a return
 
$
 - 
 
$
 - 
 
 
 
$
 1 
 
$
 - 
 
1 year
Over-recovered Fuel Costs - does not pay a return
 
 
 - 
 
 
 - 
 
 
 
 
 - 
 
 
 8,949 
 
 
Total Current Regulatory Liability
 
$
 - 
 
$
 - 
 
 
 
$
 1 
 
$
 8,949 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
 
$
 - 
 
$
 - 
 
 
 
$
 147 
 
$
 158 
 
 
Total Regulatory Liabilities Not Yet Being Paid
 
 
 - 
 
 
 - 
 
 
 
 
 147 
 
 
 158 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory liabilities being paid:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Liabilities Currently Paying a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Asset Removal Costs
 
 
 500,667 
 
 
 451,170 
 
(a)
 
 
 357,493 
 
 
 327,593 
 
(a)
 
 
 
Deferred Investment Tax Credits
 
 
 5,097 
 
 
 8,997 
 
10 years
 
 
 - 
 
 
 - 
 
 
 
Regulatory Liabilities Currently Not Paying a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred State Income Tax Coal Credits
 
 
 28,900 
 
 
 27,842 
 
9 years
 
 
 - 
 
 
 - 
 
 
 
 
 
Deferred Investment Tax Credits
 
 
 1,918 
 
 
 1,985 
 
10 years
 
 
 55,416 
 
 
 57,732 
 
76 years
 
 
 
Unrealized Gain on Forward Commitments
 
 
 25,799 
 
 
 36,552 
 
5 years
 
 
 28,045 
 
 
 27,359 
 
5 years
 
 
 
Excess Asset Retirement Obligations for Nuclear
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decommissioning Liability
 
 
 - 
 
 
 - 
 
 
 
 
 353,689 
 
 
 280,705 
 
(b)
 
 
 
Spent Nuclear Fuel Liability
 
 
 - 
 
 
 - 
 
 
 
 
 41,932 
 
 
 41,517 
 
(b)
 
 
 
Over-recovery of PJM Expenses
 
 
 - 
 
 
 - 
 
 
 
 
 11,671 
 
 
 17,827 
 
1 year
 
 
 
Indiana Clean Coal Technology Rider Liability
 
 
 - 
 
 
 - 
 
 
 
 
 2,494 
 
 
 2,416 
 
1 year
 
 
 
Other Regulatory Liabilities Being Paid
 
 
 - 
 
 
 - 
 
 
 
 
 1,310 
 
 
 1,538 
 
various
Total Regulatory Liabilities Being Paid
 
 
 562,381 
 
 
 526,546 
 
 
 
 
 852,050 
 
 
 756,687 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Noncurrent Regulatory Liabilities and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred Investment Tax Credits
 
$
 562,381 
 
$
 526,546 
 
 
 
$
 852,197 
 
$
 756,845 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
 
Relieved as removal costs are incurred.
(b)
 
Relieved when plant is decommissioned.

 
275
 
 
 
 
 
 
 
 
CSPCo
 
OPCo
 
 
 
 
 
 
 
 
 
Remaining
 
 
 
Remaining
 
 
 
 
 
 
 
December 31,
 
Recovery
 
December 31,
 
Recovery
 
 
 
 
 
 
 
2010 
 
2009 
 
Period
 
2010 
 
2009 
 
Period
Regulatory Assets:
 
(in thousands)
 
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Line Extension Carrying Costs
 
$
 33,709 
 
$
 26,590 
 
 
 
$
 21,246 
 
$
 16,278 
 
 
 
 
 
Customer Choice Deferrals
 
 
 29,716 
 
 
 28,781 
 
 
 
 
 29,141 
 
 
 28,330 
 
 
 
 
 
Storm Related Costs
 
 
 19,122 
 
 
 17,014 
 
 
 
 
 11,021 
 
 
 9,794 
 
 
 
 
 
Acquisition of Monongahela Power
 
 
 7,929 
 
 
 10,282 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Economic Development Rider
 
 
 3,057 
 
 
 - 
 
 
 
 
 3,057 
 
 
 - 
 
 
 
 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 287 
 
 
 1,421 
 
 
 
 
 391 
 
 
 1,058 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Acquisition of Monongahela Power
 
 
 4,052 
 
 
 - 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Energy Efficiency/Peak Demand Reduction
 
 
 - 
(a)
 
 4,071 
 
 
 
 
 - 
 
 
 4,007 
 
 
 
 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 43 
 
 
 17 
 
 
 
 
 58 
 
 
 22 
 
 
Total Regulatory Assets Not Yet Being Recovered
 
 
 97,915 
 
 
 88,176 
 
 
 
 
 64,914 
 
 
 59,489 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory assets being recovered:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unamortized Loss on Reacquired Debt
 
 
 8,613 
 
 
 9,357 
 
14 years
 
 
 7,276 
 
 
 7,871 
 
28 years
 
 
 
RTO Formation/Integration Costs
 
 
 2,420 
 
 
 2,692 
 
9 years
 
 
 6,547 
 
 
 7,302 
 
9 years
 
 
 
Economic Development Rider
 
 
 710 
 
 
 10,209 
 
1 year
 
 
 696 
 
 
 1,633 
 
1 year
 
 
 
Acquisition of Monongahela Power
 
 
 504 
 
 
 2,861 
 
1 year
 
 
 - 
 
 
 - 
 
 
 
 
 
Fuel Adjustment Clause
 
 
 - 
 
 
 36,982 
 
 
 
 
 475,835 
 
 
 303,550 
 
2 to 8 years
 
 
 
Other Regulatory Assets Being Recovered
 
 
 383 
 
 
 - 
 
various
 
 
 - 
 
 
 - 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension and OPEB Funded Status
 
 
 173,755 
 
 
 175,024 
 
13 years
 
 
 190,076 
 
 
 188,149 
 
13 years
 
 
 
Income Taxes, Net
 
 
 3,100 
 
 
 10,631 
 
25 years
 
 
 179,186 
 
 
 168,849 
 
19 years
 
 
 
Enhanced Service Reliability Plan
 
 
 2,990 
 
 
 2,061 
 
2 years
 
 
 387 
 
 
 - 
 
2 years
 
 
 
Postemployment Benefits
 
 
 2,909 
 
 
 3,036 
 
4 years
 
 
 5,897 
 
 
 6,062 
 
4 years
 
 
 
Unrealized Loss on Forward Commitments
 
 
 2,591 
 
 
 - 
 
1 year
 
 
 3,197 
 
 
 - 
 
1 year
 
 
 
Energy Efficiency/Peak Demand Reduction
 
 
 2,221 
(a)
 
 - 
 
2 years
 
 
 - 
 
 
 - 
 
 
Total Regulatory Assets Being Recovered
 
 
 200,196 
 
 
 252,853 
 
 
 
 
 869,097 
 
 
 683,416 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Noncurrent Regulatory Assets
 
$
 298,111 
 
$
 341,029 
 
 
 
$
 934,011 
 
$
 742,905 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
 
Recovery of regulatory asset was granted during 2010.

 
276
 
 
 
 
 
 
 
 
CSPCo
 
OPCo
 
 
 
 
 
 
 
 
 
Remaining
 
 
 
Remaining
 
 
 
 
 
 
 
December 31,
 
Refund
 
December 31,
 
Refund
 
 
2010 
 
2009 
 
Period
 
2010 
 
2009 
 
Period
Regulatory Liabilities:
 
(in thousands)
 
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncurrent Regulatory Liabilities and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred Investment Tax Credits
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory liabilities not yet being paid:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Liabilities Currently Not Paying a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Over-recovery of Costs Related to gridSMART®
 
$
 6,182 
 
$
 7,477 
 
 
 
$
 - 
 
$
 - 
 
 
 
 
 
Low Income Customers/Economic Recovery
 
 
 2,260 
 
 
 2,351 
 
 
 
 
 1,160 
 
 
 1,110 
 
 
 
 
 
Other Regulatory Liabilities Not Yet Being Paid
 
 
 1,817 
 
 
 1,823 
 
 
 
 
 1,349 
 
 
 2,476 
 
 
Total Regulatory Liabilities Not Yet Being Paid
 
 
 10,259 
 
 
 11,651 
 
 
 
 
 2,509 
 
 
 3,586 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory liabilities being paid:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Liabilities Currently Paying a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Asset Removal Costs
 
 
 137,720 
 
 
 130,999 
 
(a)
 
 
 118,826 
 
 
 112,453 
 
(a)
 
 
 
Transmission Cost Recovery Rider
 
 
 786 
 
 
 14,811 
 
1 year
 
 
 1,633 
 
 
 10,003 
 
1 year
 
 
 
Deferred Investment Tax Credits
 
 
 - 
 
 
 - 
 
 
 
 
 1,085 
 
 
 1,967 
 
9 years
 
 
 
Other Regulatory Liabilities Being Paid
 
 
 336 
 
 
 377 
 
various
 
 
 - 
 
 
 178 
 
 
 
Regulatory Liabilities Currently Not Paying a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred Investment Tax Credits
 
 
 14,787 
 
 
 16,833 
 
14 years
 
 
 - 
 
 
 - 
 
 
 
 
 
Energy Efficiency/Peak Demand Reduction
 
 
 - 
 
 
 - 
 
 
 
 
 2,245 
 
 
 - 
 
2 years
 
 
 
Unrealized Gain on Forward Commitments
 
 
 - 
 
 
 - 
 
 
 
 
 105 
 
 
 - 
 
1 year
Total Regulatory Liabilities Being Paid
 
 
 153,629 
 
 
 163,020 
 
 
 
 
 123,894 
 
 
 124,601 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Noncurrent Regulatory Liabilities and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred Investment Tax Credits
 
$
 163,888 
 
$
 174,671 
 
 
 
$
 126,403 
 
$
 128,187 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
 
Relieved as removal costs are incurred.

 
277
 
 
 
 
 
 
 
 
PSO
 
SWEPCo
 
 
 
 
 
 
 
 
 
Remaining
 
 
 
Remaining
 
 
 
 
 
 
 
December 31,
 
Recovery
 
December 31,
 
Recovery
 
 
 
 
 
 
 
2010 
 
2009 
 
Period
 
2010 
 
2009 
 
Period
Regulatory Assets:
 
(in thousands)
 
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Regulatory Asset
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Under-recovered Fuel Costs - earns a return
 
$
 37,262 
 
$
 - 
 
1 year
 
$
 758 
 
$
 1,639 
 
1 year
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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
 
$
 17,256 
 
$
 - 
 
 
 
$
 1,239 
 
$
 - 
 
 
 
 
 
Other Regulatory Assets Not Yet Being Recovered
 
 
 574 
 
 
 850 
 
 
 
 
 613 
 
 
 471 
 
 
Total Regulatory Assets Not Yet Being Recovered
 
 
 17,830 
 
 
 850 
 
 
 
 
 1,852 
 
 
 471 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory assets being recovered:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets Currently Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Storm Related Costs
 
 
 38,499 
 
 
 53,366 
 
3 years
 
 
 - 
 
 
 3,043 
 
 
 
 
 
Red Rock Generating Facility
 
 
 10,406 
 
 
 10,631 
 
46 years
 
 
 - 
 
 
 - 
 
 
 
 
 
Unamortized Loss on Reacquired Debt
 
 
 8,277 
 
 
 10,175 
 
9 years
 
 
 12,422 
 
 
 13,118 
 
33 years
 
 
 
Acquisition of Valley Electric Membership
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Corporation (VEMCO)
 
 
 - 
 
 
 - 
 
 
 
 
 6,500 
 
 
 - 
 
5 years
 
 
 
Lawton Settlement
 
 
 - 
 
 
 9,396 
 
 
 
 
 - 
 
 
 - 
 
 
 
Regulatory Assets Currently Not Earning a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension and OPEB Funded Status
 
 
 166,333 
 
 
 172,420 
 
13 years
 
 
 163,870 
 
 
 174,974 
 
13 years
 
 
 
Vegetation Management
 
 
 13,303 
 
 
 16,014 
 
1 year
 
 
 - 
 
 
 - 
 
 
 
 
 
Deferral of Major Generation Overhauls
 
 
 4,083 
 
 
 5,083 
 
4 years
 
 
 - 
 
 
 - 
 
 
 
 
 
Energy Efficiency/Peak Demand Reduction
 
 
 3,705 
 
 
 88 
 
1 year
 
 
 495 
 
 
 1 
 
1 year
 
 
 
Income Taxes, Net
 
 
 691 
 
 
 - 
 
34 years
 
 
 132,118 
 
 
 72,174 
 
29 years
 
 
 
Unrealized Loss on Forward Commitments
 
 
 285 
 
 
 331 
 
3 years
 
 
 2,975 
 
 
 73 
 
3 years
 
 
 
Storm Related Costs
 
 
 - 
 
 
 - 
 
 
 
 
 4,800 
 
 
 - 
 
3 years
 
 
 
Rate Case Expense
 
 
 - 
 
 
 - 
 
 
 
 
 4,606 
 
 
 - 
 
3 years
 
 
 
Dolet Hills Deferred Fuel
 
 
 - 
 
 
 - 
 
 
 
 
 2,725 
 
 
 3,353 
 
4 years
 
 
 
Other Regulatory Assets Being Recovered
 
 
 133 
 
 
 831 
 
various
 
 
 335 
 
 
 958 
 
various
Total Regulatory Assets Being Recovered
 
 
 245,715 
 
 
 278,335 
 
 
 
 
 330,846 
 
 
 267,694 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Noncurrent Regulatory Assets
 
$
 263,545 
 
$
 279,185 
 
 
 
$
 332,698 
 
$
 268,165 
 
 

 
278
 
 
 
 
 
 
 
 
PSO
 
SWEPCo
 
 
 
 
 
 
 
 
 
Remaining
 
 
 
Remaining
 
 
 
 
 
 
 
December 31,
 
Refund
 
December 31,
 
Refund
 
 
 
 
 
 
 
2010 
 
2009 
 
Period
 
2010 
 
2009 
 
Period
Regulatory Liabilities:
 
(in thousands)
 
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Regulatory Liability
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Over-recovered Fuel Costs - pays a return
 
$
 - 
 
$
 51,087 
 
 
 
$
 16,432 
 
$
 13,762 
 
1 year
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncurrent Regulatory Liabilities and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred Investment Tax Credits
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory liabilities not yet being paid:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Liabilities Currently Paying a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Refundable Construction Financing Costs
 
$
 - 
 
$
 - 
 
 
 
$
 20,139 
 
$
 - 
 
 
 
Regulatory Liabilities Currently Not Paying a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Over-recovery of Costs Related to gridSMART®
 
 
 3,806 
 
 
 1,833 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Over-recovery of Storm Related Costs
 
 
 3,493 
 
 
 - 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Excess Earnings
 
 
 - 
 
 
 - 
 
 
 
 
 - 
(a)
 
 3,167 
 
 
 
 
 
Other Regulatory Liabilities Not Yet Being Paid
 
 
 - 
 
 
 1,171 
 
 
 
 
 806 
 
 
 1,006 
 
 
Total Regulatory Liabilities Not Yet Being Paid
 
 
 7,299 
 
 
 3,004 
 
 
 
 
 20,945 
 
 
 4,173 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory liabilities being paid:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Liabilities Currently Paying a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Asset Removal Costs
 
 
 284,230 
 
 
 283,683 
 
(b)
 
 
 346,402 
 
 
 308,590 
 
(b)
 
 
 
Excess Earnings
 
 
 - 
 
 
 - 
 
 
 
 
 3,119 
(a)
 
 - 
 
43 years
 
 
 
Other Regulatory Liabilities Being Paid
 
 
 - 
 
 
 - 
 
 
 
 
 1,667 
 
 
 2,054 
 
various
 
Regulatory Liabilities Currently Not Paying a Return
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred Investment Tax Credits
 
 
 41,166 
 
 
 31,541 
 
38 years
 
 
 13,868 
 
 
 15,352 
 
28 years
 
 
 
Energy Efficiency/Peak Demand Reduction
 
 
 4,266 
 
 
 1,120 
 
1 year
 
 
 - 
 
 
 64 
 
 
 
 
 
Vegetation Management
 
 
 - 
 
 
 - 
 
 
 
 
 5,672 
 
 
 - 
 
2 years
 
 
 
Income Taxes, Net
 
 
 - 
 
 
 5,431 
 
 
 
 
 - 
 
 
 - 
 
 
 
 
 
Other Regulatory Liabilities Being Paid
 
 
 - 
 
 
 2,152 
 
 
 
 
 2,000 
 
 
 3,702 
 
various
Total Regulatory Liabilities Being Paid
 
 
 329,662 
 
 
 323,927 
 
 
 
 
 372,728 
 
 
 329,762 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Noncurrent Regulatory Liabilities and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred Investment Tax Credits
 
$
 336,961 
 
$
 326,931 
 
 
 
$
 393,673 
 
$
 333,935 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
 
Payment of regulatory liability was granted during 2010.
(b)
 
Relieved as removal costs are incurred.

 
279
 
6.   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 adverse effect on the financial statements.

COMMITMENTS

Construction and Commitments – Affecting APCo, CSPCo, 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 following table shows the forecasted construction expenditures excluding AFUDC and capitalized interest by Registrant Subsidiary for 2011:

 
 
Forecasted
 
 
 
Construction
 
Company
 
Expenditures
 
 
 
(in millions)
 
APCo
 
$
 450 
 
CSPCo
 
 
 187 
 
I&M
 
 
 305 
 
OPCo
 
 
 264 
 
PSO
 
 
 169 
 
SWEPCo
 
 
 442 
 

The Registrant 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 tables summarize the Registrant Subsidiaries’ actual contractual commitments at December 31, 2010:

 
 
 
Less Than 1
 
 
 
 
 
After
 
 
 
Contractual Commitments - APCo
 
year
 
2-3 years
 
4-5 years
 
5 years
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(in millions)
 
Fuel Purchase Contracts (a)
 
$
 541.7 
 
$
 790.8 
 
$
 487.5 
 
$
 419.7 
 
$
 2,239.7 
 
Energy and Capacity Purchase Contracts (b)
 
 
 16.4 
 
 
 27.3 
 
 
 27.0 
 
 
 186.4 
 
 
 257.1 
 
Total
 
$
 558.1 
 
$
 818.1 
 
$
 514.5 
 
$
 606.1 
 
$
 2,496.8 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Less Than 1
 
 
 
 
 
After
 
 
 
Contractual Commitments - CSPCo
 
year
 
2-3 years
 
4-5 years
 
5 years
 
Total
 
 
 
(in millions)
 
Fuel Purchase Contracts (a)
 
$
 254.1 
 
$
 426.9 
 
$
 323.2 
 
$
 497.5 
 
$
 1,501.7 
 
Energy and Capacity Purchase Contracts (b)
 
 
 5.3 
 
 
 7.1 
 
 
 2.7 
 
 
 16.9 
 
 
 32.0 
 
Total
 
$
 259.4 
 
$
 434.0 
 
$
 325.9 
 
$
 514.4 
 
$
 1,533.7 
 
 
280
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Less Than 1
 
 
 
 
 
After
 
 
 
Contractual Commitments - I&M
 
year
 
2-3 years
 
4-5 years
 
5 years
 
Total
 
 
 
(in millions)
 
Fuel Purchase Contracts (a)
 
$
 429.6 
 
$
 585.3 
 
$
 441.6 
 
$
 169.1 
 
$
 1,625.6 
 
Energy and Capacity Purchase Contracts (b)
 
 
 2.5 
 
 
 1.2 
 
 
 0.4 
 
 
 - 
 
 
 4.1 
 
Total
 
$
 432.1 
 
$
 586.5 
 
$
 442.0 
 
$
 169.1 
 
$
 1,629.7 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Less Than 1
 
 
 
 
 
After
 
 
 
Contractual Commitments - OPCo
 
year
 
2-3 years
 
4-5 years
 
5 years
 
Total
 
 
 
(in millions)
 
Fuel Purchase Contracts (a)
 
$
 887.8 
 
$
 1,546.7 
 
$
 1,184.4 
 
$
 2,551.6 
 
$
 6,170.5 
 
Energy and Capacity Purchase Contracts (b)
 
 
 6.5 
 
 
 8.8 
 
 
 3.4 
 
 
 21.5 
 
 
 40.2 
 
Total
 
$
 894.3 
 
$
 1,555.5 
 
$
 1,187.8 
 
$
 2,573.1 
 
$
 6,210.7 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Less Than 1
 
 
 
 
 
After
 
 
 
Contractual Commitments - PSO
 
year
 
2-3 years
 
4-5 years
 
5 years
 
Total
 
 
 
(in millions)
 
Fuel Purchase Contracts (a)
 
$
 256.6 
 
$
 113.8 
 
$
 30.1 
 
$
 - 
 
$
 400.5 
 
Energy and Capacity Purchase Contracts (b)
 
 
 18.0 
 
 
 114.8 
 
 
 131.5 
 
 
 590.7 
 
 
 855.0 
 
Total
 
$
 274.6 
 
$
 228.6 
 
$
 161.6 
 
$
 590.7 
 
$
 1,255.5 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Less Than 1
 
 
 
 
 
After
 
 
 
Contractual Commitments - SWEPCo
 
year
 
2-3 years
 
4-5 years
 
5 years
 
Total
 
 
 
(in millions)
 
Fuel Purchase Contracts (a)
 
$
 257.1 
 
$
 321.2 
 
$
 76.6 
 
$
 80.2 
 
$
 735.1 
 
Energy and Capacity Purchase Contracts (b)
 
 
 19.0 
 
 
 39.1 
 
 
 39.2 
 
 
 284.9 
 
 
 382.2 
 
Total
 
$
 276.1 
 
$
 360.3 
 
$
 115.8 
 
$
 365.1 
 
$
 1,117.3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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 contractual commitments for energy and capacity purchase contracts.

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 $1.5 billion credit facilities, of which $750 million may be issued under one credit facility as letters of credit.  In June 2010, AEP terminated one of the $1.5 billion facilities that was scheduled to mature in March 2011 and replaced it with a new $1.5 billion credit facility which matures in 2013 and allows for the issuance of up to $600 million as letters of credit.

In June 2010, the Registrant Subsidiaries and certain other companies in the AEP System reduced a $627 million credit agreement to $478 million.  As of December 31, 2010, $477 million of letters of credit were issued by Registrant Subsidiaries under the agreement to support variable rate Pollution Control Bonds.

 
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At December 31, 2010, the maximum future payments of the letters of credit were as follows:

 
 
 
 
 
 
 
 
 
Borrower
 
Company
 
Amount
 
Maturity
 
Sublimit
 
 
 
 
(in thousands)
 
 
 
(in thousands)
 
$1.35 billion letters of credit:
 
 
 
 
 
 
 
 
 
 
I&M
 
$
 150 
 
March 2011
 
 
N/A
 
 
SWEPCo
 
 
 4,448 
 
June 2011
 
 
N/A
 
 
 
 
 
 
 
 
 
 
 
 
$478 million letter of credit:
 
 
 
 
 
 
 
 
 
 
APCo
 
$
 232,292 
 
March 2011 to April 2011
 
$
 300,000 
 
 
I&M
 
 
 77,886 
 
April 2011
 
 
 230,000 
 
 
OPCo
 
 
 166,899 
 
April 2011
 
 
 400,000 

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 approximately $65 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 Mining Company (Sabine), a consolidated variable interest entity.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  As of December 31, 2010, SWEPCo has collected approximately $49 million through a rider for final mine closure and reclamation costs, of which $2 million is recorded in Other Current Liabilities, $25 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $22 million is recorded in Asset Retirement Obligations on SWEPCo’s Consolidated 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 – Affecting APCo, CSPCo, 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.  There are no material liabilities recorded for any indemnifications.

The AEP East companies, PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to power purchase and sale activity conducted 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 13 for disclosure of lease residual value guarantees.

ENVIRONMENTAL CONTINGENCIES

Federal EPA Complaint and Notice of Violation – Affecting CSPCo

The Federal EPA, certain special interest groups and a number of states alleged that APCo, CSPCo, I&M and OPCo modified certain units at their coal-fired generating plants in violation of the NSR requirements of the CAA.  Cases with similar allegations against CSPCo, Dayton Power and Light Company and Duke Energy Ohio, Inc. were also filed related to their jointly-owned units.  The cases were settled with the exception of a case involving a jointly-owned Beckjord unit which had a liability trial.  Following two liability trials, the jury found no liability at the jointly-owned Beckjord unit.  The defendants and the plaintiffs appealed to the Seventh Circuit Court of Appeals.  In October 2010, the Seventh Circuit dismissed all remaining claims in these cases.  Beckjord is operated by Duke Energy Ohio, Inc.

 
282
 
Citizen Suit  and  Notice of Violation – Affecting SWEPCo

In 2005, two special interest groups, Sierra Club and Public Citizen, filed a complaint alleging violations of the CAA at SWEPCo’s Welsh Plant.  In 2008, a consent decree resolved all claims in the case and in the pending appeal of an altered permit for the Welsh Plant.  The consent decree required SWEPCo to install continuous particulate emission monitors at the Welsh Plant, secure 65 MW of renewable energy capacity, fund $2 million in emission reduction, energy efficiency or environmental mitigation projects and pay a portion of plaintiffs’ attorneys’ fees and costs.

The Federal EPA issued a Notice of Violation (NOV) based on alleged violations of a percent sulfur in fuel limitation and the heat input values listed in a previous state permit similar to the claims made in the citizen suit.  The NOV also alleges that a permit alteration issued by the Texas Commission on Environmental Quality in 2007 was improper.  In March 2008, SWEPCo met with the Federal EPA to discuss the alleged violations.  The Federal EPA did not object to the settlement of the citizen suit and has taken no further action.  Management is unable to predict the timing of any future action by the Federal EPA.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.

Carbon Dioxide Public Nuisance Claims – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

In 2004, eight states and the City of New York filed an action in Federal District Court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority.  The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants.  The actions allege that CO 2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming and sought injunctive relief in the form of specific emission reduction commitments from the defendants.  The trial court dismissed the lawsuits.

In September 2009, the Second Circuit Court of Appeals issued a ruling on appeal remanding the cases to the Federal District Court for the Southern District of New York.  The Second Circuit held that the issues of climate change and global warming do not raise political questions and that Congress’ refusal to regulate CO 2 emissions does not mean that plaintiffs must wait for an initial policy determination by Congress or the President’s administration to secure the relief sought in their complaints.  The court stated that Congress could enact comprehensive legislation to regulate CO 2 emissions or that the Federal EPA could regulate CO 2 emissions under existing CAA authorities and that either of these actions could override any decision made by the district court under federal common law.  The Second Circuit did not rule on whether the plaintiffs could proceed with their state common law nuisance claims.  In December 2010, the defendants’ petition for review by the U.S. Supreme Court was granted.  Briefing is underway and the case will be heard in April 2011.  Management believes the actions are without merit and intends to continue to defend against the 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.

Management is unable to determine a range of potential losses that are reasonably possible of occurring.

Alaskan Villages’ Claims – Affecting APCo, CSPCo, 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
 
 
283
 
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.  The plaintiffs appealed the decision.  Briefing is complete and no date has been set for oral argument.  The defendants requested that the court defer setting this case for oral argument until after the Supreme Court issues its decision in the CO 2 public nuisance case discussed above.  Management believes the action is without merit and intends to defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.
 
The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting APCo, CSPCo, 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 generating 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.  At December 31, 2010, APCo and CSPCo are each named as a Potentially Responsible Party (PRP) for one site and OPCo is named a PRP for two sites by the Federal EPA.  There are seven additional sites for which APCo, CSPCo, I&M, OPCo, and SWEPCo have received information requests which could lead to PRP designation.  I&M and SWEPCo have also been named potentially liable at two sites each under state law including the I&M site discussed in the next paragraph.  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 and recorded a provision of approximately $11 million.  As the remediation work is completed, I&M’s cost may continue to increase 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.

Amos Plant – State and Federal Enforcement Proceedings – Affecting APCo and OPCo

In March 2010, APCo and OPCo received a letter from the West Virginia Department of Environmental Protection, Division of Air Quality (DAQ), alleging that at various times in 2007 through 2009 the units at Amos Plant reported periods of excess opacity (indicator of compliance with particulate matter emission limits) that lasted for more than thirty consecutive minutes in a 24-hour period and that certain required notifications were not made.  Management met with representatives of DAQ to discuss these occurrences and the steps taken to prevent a recurrence.  DAQ indicated that additional enforcement action may be taken, including imposition of a civil penalty of approximately $240 thousand.  APCo and OPCo denied that violations of the reporting requirements occurred and maintain that the proper reporting was done.  Management continues to discuss the resolution of these issues with DAQ, but cannot predict the outcome of these discussions or the amount of any penalty that may be assessed.

 
284
 
In March 2010, APCo and OPCo received a request to show cause from the Federal EPA alleging that certain reporting requirements under Superfund and the Emergency Planning and Community Right-to-Know Act had been violated and inviting APCo and OPCo to engage in settlement negotiations.  The request includes a proposed civil penalty of approximately $300 thousand.  Management indicated a willingness to engage in good faith negotiations and met with representatives of the Federal EPA.  APCo and OPCo have not admitted that any violations occurred or that the amount of the proposed penalty is reasonable.

Defective Environmental Equipment – Affecting CSPCo and OPCo

As part of the AEP System’s continuing environmental investment program, management chose to retrofit wet flue gas desulfurization systems on units utilizing the jet bubbling reactor (JBR) technology.  The retrofits on two of the Cardinal Plant units and a Conesville Plant unit are operational.  Due to unexpected operating results, management completed an extensive review in 2009 of the design and manufacture of the JBR internal components.  The review concluded that there were fundamental design deficiencies and that inferior and/or inappropriate materials were selected for the internal fiberglass components.  Management initiated discussions with Black & Veatch, the original equipment manufacturer, to develop a repair or replacement corrective action plan.  In 2010, management settled with Black & Veatch and resolved the issues involving the internal components and JBR vessel corrosion.  These settlements resulted in an immaterial increase in the capitalized costs of the projects for modification of the scope of the contracts.

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 2009.  According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste ranges from $831 million to $1.5 billion in 2009 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 amount recovered in rates was $14 million in 2010, $16 million in 2009 and $ 27 million in 2008.  Reduced annual decommissioning cost recovery amounts reflect the units’ longer estimated life and operating licenses granted by the NRC.  Decommissioning costs recovered from customers are deposited in external trusts.

At December 31, 2010 and 2009, the total decommissioning trust fund balance was $1.2 billion and $ 1.1 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, cash flows and possibly financial condition would be adversely affected 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.  At December 31, 2010 and 2009, 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 $307 million and $306 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.

 
285
 
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 property damage, decommissioning and decontamination at the Cook Plant in the amount of $1.8 billion.  I&M purchases $1 billion of excess coverage for property damage, decommissioning and decontamination.  Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage.  I&M utilizes an industry mutual insurer for the placement of this insurance coverage.  Participation in this mutual insurance requires a contingent financial obligation of up to $41 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 $12.6 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 $117.5 million on each licensed reactor in the U.S. payable in annual installments of $17.5 million.  As a result, I&M could be assessed $235 million per nuclear incident payable in annual installments of $35 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 $12.2 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, net income, cash flows and financial condition could be adversely affected.

Cook Plant Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in significant turbine damage and a small fire on the electric generator.  This equipment, located in the turbine building, is separate and isolated from the nuclear reactor.  The turbine rotors that caused the vibration were installed in 2006 and are within the vendor’s warranty period.  The warranty provides for the repair or replacement of the turbine rotors if the damage was caused by a defect in materials or workmanship.  Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $395 million.  Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process.  I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power.  The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors.  As a result, the replacement of the repaired turbine rotors and other equipment is scheduled for the Unit 1 planned outage in the fall of 2011.

I&M maintains property insurance through NEIL with a $1 million deductible.  As of December 31, 2010, I&M recorded $46 million on its Consolidated Balance Sheet representing estimated recoverable amounts under the property insurance policy.  Through December 31, 2010, I&M received partial payments of $203 million from NEIL for the cost incurred to date to repair the property damage.

I&M also maintains a separate accidental outage policy with NEIL.  In 2009, I&M recorded $185 million in revenue under the policy and reduced the cost of replacement power in customers’ bills by $78 million.

NEIL is reviewing claims made under the insurance policies to ensure that claims associated with the outage are covered by the policies.  The review by NEIL includes the timing of the unit’s return to service and whether the return should have occurred earlier reducing the amount received under the accidental outage policy.  The treatment of the remaining accidental outage policy revenues through fuel clauses is discussed in “I&M Rate Matters” section of Note 4.  The treatment of property damage costs, replacement power costs and insurance proceeds will be the subject of future regulatory proceedings in Indiana and Michigan.  If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.

 
286
 
OPERATIONAL CONTINGENCIES

Insurance and Potential Losses – Affecting APCo, CSPCo, 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 have a material adverse effect on net income, cash flows and financial condition.

Fort Wayne Lease – Affecting I&M

Since 1975, I&M has leased certain energy delivery assets from the City of Fort Wayne, Indiana under a long-term lease that expired on February 28, 2010.  I&M negotiated with Fort Wayne to purchase the assets at the end of the lease, but no agreement was reached prior to the end of the lease.

I&M and Fort Wayne reached a settlement agreement.  The agreement, signed in October 2010, is subject to approval by the IURC.  I&M filed a petition with the IURC seeking approval.  If the agreement is approved, I&M will purchase the remaining leased property and settle claims Fort Wayne asserted.  The agreement provides that I&M will pay Fort Wayne a total of $39 million, inclusive of interest, over 15 years and Fort Wayne will recognize that I&M is the exclusive electricity supplier in the Fort Wayne area.   I&M will seek recovery in rates of the payments made to Fort Wayne.  If the agreement is not approved by the IURC, the parties have the right to terminate the agreement and pursue other relief.

Coal Transportation Rate Dispute – Affecting PSO

In 1985, the Burlington Northern Railroad Co. (now BNSF) entered into a coal transportation agreement with PSO.  The agreement contained a base rate subject to adjustment, a rate floor, a reopener provision and an arbitration provision.  In 1992, PSO reopened the pricing provision.  The parties failed to reach an agreement and the matter was arbitrated, with the arbitration panel establishing a lowered rate as of July 1, 1992 (the 1992 Rate) and modifying the rate adjustment formula.  The decision did not mention the rate floor.  From April 1996 through the contract termination in December 2001, the 1992 Rate exceeded the adjusted rate determined according to the decision.  PSO paid the adjusted rate and contended that the panel eliminated the rate floor.  BNSF invoiced at the 1992 Rate and contended that the 1992 Rate was the new rate floor.  PSO terminated the contract by paying a termination fee, as required by the agreement.  BNSF contends that the termination fee should have been calculated on the 1992 Rate, not the adjusted rate, resulting in an underpayment of approximately $9.5 million, including interest.

This matter was submitted to an arbitration board.  In April 2006, the arbitration board filed its decision, denying BNSF’s underpayments claim.  PSO filed a request for an order confirming the arbitration award and a request for entry of judgment on the award with the U.S. District Court for the Northern District of Oklahoma.  On July 14, 2006, the U.S. District Court issued an order confirming the arbitration award.  On July 24, 2006, BNSF filed a Motion to Reconsider the July 14, 2006 Arbitration Confirmation Order and Final Judgment and its Motion to Vacate and Correct the Arbitration Award with the U.S. District Court.  In February 2007, the U.S. District Court granted BNSF’s Motion to Reconsider.  In August 2009, the U.S. District Court upheld the arbitration board’s decision.  BNSF appealed the U.S. District Court’s decision to the U.S. Court of Appeals.  In December 2010, the Tenth Circuit Court of Appeals affirmed the U.S. District Court’s order confirming the arbitration award, denying BNSF’s underpayments claim.  In January 2011, the appellate
 
 
287
 
court issued a mandate to send the case back to the U.S. District Court to address the remaining attorney fee issues to determine the award amount to PSO for attorney’s fees and expenses related to the proceedings at both the district court and appellate court levels.

7.   ACQUISITIONS

2010

Valley Electric Membership Corporation – Affecting SWEPCo

In November 2009, SWEPCo signed a letter of intent to purchase certain transmission and distribution assets of Valley Electric Membership Corporation (VEMCO).  In October 2010, SWEPCo finalized the purchase for approximately $102 million and began serving VEMCO’s 30,000 customers in Louisiana.

2009

Oxbow Lignite Company and Red River Mining Company – Affecting SWEPCo

On December 29, 2009, SWEPCo   purchased 50% of the Oxbow Lignite Company, LLC (OLC) membership interest for $13 million.  CLECO acquired the remaining 50% membership interest in the OLC for $13 million.  The Oxbow Mine is located near Coushatta, Louisiana and will be used as one of the fuel sources for SWEPCo’s and CLECO’s jointly-owned Dolet Hills Generating Station.  SWEPCo will account for OLC as an equity investment.  Also, on December 29, 2009, DHLC purchased mining equipment and assets for $16 million from the Red River Mining Company.

2008

None

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.

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 medical 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.

 
288
 
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
 
2010 
 
2009 
 
 
2010 
 
2009 
Discount Rate
 
 5.05 
%
 
 5.60 
%
 
 
 5.25 
%
 
 5.85 
%

 
 
Pension Plans
Assumption - Rate of Compensation Increase (a)
 
2010 
 
2009 
APCo
 
 4.70 
%
 
 4.35 
%
CSPCo
 
 5.30 
%
 
 4.95 
%
I&M
 
 4.90 
%
 
 4.55 
%
OPCo
 
 4.90 
%
 
 4.55 
%
PSO
 
 4.95 
%
 
 4.60 
%
SWEPCo
 
 4.80 
%
 
 4.45 
%

   (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 similar to those included in the Moody’s Aa bond index is constructed with a duration 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 2010, 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
 
2010 
 
2009 
 
2008 
 
2010 
 
2009 
 
2008 
Discount Rate
 
 5.60 
%
 
 6.00 
%
 
 6.00 
%
 
 5.85 
%
 
 6.10 
%
 
 6.20 
%
Expected Return on Plan Assets
 
 8.00 
%
 
 8.00 
%
 
 8.00 
%
 
 8.00 
%
 
 7.75 
%
 
 8.00 
%

 
 
 
 
 
Pension Plans
Assumption - Rate of Compensation Increase
 
2010 
 
2009 
 
2008 
APCo
 
 4.35 
%
 
 5.65 
%
 
 5.65 
%
CSP
 
 4.95 
%
 
 6.25 
%
 
 6.25 
%
I&M
 
 4.55 
%
 
 5.85 
%
 
 5.85 
%
OPCo
 
 4.55 
%
 
 5.85 
%
 
 5.85 
%
PSO
 
 4.60 
%
 
 5.90 
%
 
 5.90 
%
SWEPCo
 
 4.45 
%
 
 5.75 
%
 
 5.75 
%

The expected return on plan assets for 2010 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.

 
289
 
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
 
2010 
 
2009 
Initial
 
 8.00 
%
 
 6.50 
%
Ultimate
 
 5.00 
%
 
 5.00 
%
Year Ultimate Reached  
                      20 16
                        20 12

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
 
CSPCo
 
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
 
$
 3,689 
 
$
 1,619 
 
$
 2,908 
 
$
 3,278 
 
$
 1,273 
 
$
 1,394 
 
   1% Decrease
 
 
 (2,965)
 
 
 (1,302)
 
 
 (2,343)
 
 
 (2,636)
 
 
 (1,026)
 
 
 (1,123)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effect on the Health Care Component of the
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated Postretirement Benefit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Obligation:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
   1% Increase
 
$
 47,231 
 
$
 20,182 
 
$
 31,596 
 
$
 41,472 
 
$
 13,770 
 
$
 15,276 
 
   1% Decrease
 
 
 (38,564)
 
 
 (16,501)
 
 
 (25,905)
 
 
 (33,902)
 
 
 (11,297)
 
 
 (12,533)

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.  At December 31, 2010, 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.

 
290
 
Benefit Plan Obligations, Plan Assets and Funded Status as of December 31, 2010 and 2009

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
 
 
2010 
 
2009 
 
2010 
 
2009 
Change in Benefit Obligation
 
(in thousands)
Benefit Obligation at January 1
 
$
 632,832 
 
$
 585,806 
 
$
 348,787 
 
$
 333,140 
Service Cost
 
 
 12,908 
 
 
 12,689 
 
 
 5,722 
 
 
 5,142 
Interest Cost
 
 
 33,956 
 
 
 34,050 
 
 
 20,300 
 
 
 19,710 
Actuarial Loss
 
 
 28,909 
 
 
 34,389 
 
 
 33,656 
 
 
 8,892 
Plan Amendment Prior Service Credit
 
 
 - 
 
 
 - 
 
 
 (4,257)
 
 
 - 
Benefit Payments
 
 
 (56,386)
 
 
 (34,102)
 
 
 (27,677)
 
 
 (24,188)
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 4,782 
 
 
 4,243 
Medicare Subsidy
 
 
 - 
 
 
 - 
 
 
 1,839 
 
 
 1,848 
Benefit Obligation at December 31
 
$
 652,219 
 
$
 632,832 
 
$
 383,152 
 
$
 348,787 
 
 
 
 
 
 
 
 
 
 
 
 
 
Change in Fair Value of Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Plan Assets at January 1
 
$
 474,657 
 
$
 440,386 
 
$
 217,160 
 
$
 169,462 
Actual Gain on Plan Assets
 
 
 57,745 
 
 
 68,337 
 
 
 29,112 
 
 
 42,378 
Company Contributions
 
 
 36,820 
 
 
 36 
 
 
 20,394 
 
 
 25,265 
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 4,782 
 
 
 4,243 
Benefit Payments
 
 
 (56,386)
 
 
 (34,102)
 
 
 (27,677)
 
 
 (24,188)
Fair Value of Plan Assets at December 31
 
$
 512,836 
 
$
 474,657 
 
$
 243,771 
 
$
 217,160 
 
 
 
 
 
 
 
 
 
 
 
 
 
Underfunded Status at December 31
 
$
 (139,383)
 
$
 (158,175)
 
$
 (139,381)
 
$
 (131,627)

CSPCo
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
2010 
 
2009 
 
2010 
 
2009 
Change in Benefit Obligation
 
(in thousands)
Benefit Obligation at January 1
 
$
 364,891 
 
$
 344,638 
 
$
 151,161 
 
$
 150,885 
Service Cost
 
 
 5,873 
 
 
 5,504 
 
 
 2,761 
 
 
 2,470 
Interest Cost
 
 
 19,156 
 
 
 19,529 
 
 
 8,713 
 
 
 8,493 
Actuarial (Gain) Loss
 
 
 7,931 
 
 
 15,910 
 
 
 14,171 
 
 
 (2,915)
Plan Amendment Prior Service Credit
 
 
 - 
 
 
 - 
 
 
 (2,164)
 
 
 - 
Benefit Payments
 
 
 (43,698)
 
 
 (20,690)
 
 
 (11,988)
 
 
 (10,677)
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 2,488 
 
 
 2,143 
Medicare Subsidy
 
 
 - 
 
 
 - 
 
 
 765 
 
 
 762 
Benefit Obligation at December 31
 
$
 354,153 
 
$
 364,891 
 
$
 165,907 
 
$
 151,161 
 
 
 
 
 
 
 
 
 
 
 
 
 
Change in Fair Value of Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Plan Assets at January 1
 
$
 288,468 
 
$
 271,342 
 
$
 98,754 
 
$
 81,350 
Actual Gain on Plan Assets
 
 
 28,825 
 
 
 37,816 
 
 
 12,208 
 
 
 14,808 
Company Contributions
 
 
 6,998 
 
 
 - 
 
 
 8,072 
 
 
 11,130 
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 2,488 
 
 
 2,143 
Benefit Payments
 
 
 (43,698)
 
 
 (20,690)
 
 
 (11,988)
 
 
 (10,677)
Fair Value of Plan Assets at December 31
 
$
 280,593 
 
$
 288,468 
 
$
 109,534 
 
$
 98,754 
 
 
 
 
 
 
 
 
 
 
 
 
 
Underfunded Status at December 31
 
$
 (73,560)
 
$
 (76,423)
 
$
 (56,373)
 
$
 (52,407)

 
291
 
I&M
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
2010 
 
2009 
 
2010 
 
2009 
Change in Benefit Obligation
 
(in thousands)
Benefit Obligation at January 1
 
$
 526,363 
 
$
 480,447 
 
$
 241,847 
 
$
 227,979 
Service Cost
 
 
 15,284 
 
 
 14,002 
 
 
 6,750 
 
 
 5,990 
Interest Cost
 
 
 29,085 
 
 
 28,520 
 
 
 14,164 
 
 
 13,675 
Actuarial Loss
 
 
 40,694 
 
 
 29,079 
 
 
 20,980 
 
 
 4,443 
Plan Amendment Prior Service Credit
 
 
 - 
 
 
 - 
 
 
 (4,273)
 
 
 - 
Benefit Payments
 
 
 (50,444)
 
 
 (25,685)
 
 
 (17,439)
 
 
 (14,337)
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 3,526 
 
 
 2,908 
Medicare Subsidy
 
 
 - 
 
 
 - 
 
 
 1,187 
 
 
 1,189 
Benefit Obligation at December 31
 
$
 560,982 
 
$
 526,363 
 
$
 266,742 
 
$
 241,847 
 
 
 
 
 
 
 
 
 
 
 
 
 
Change in Fair Value of Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Plan Assets at January 1
 
$
 379,562 
 
$
 353,624 
 
$
 166,682 
 
$
 128,878 
Actual Gain on Plan Assets
 
 
 50,811 
 
 
 51,612 
 
 
 20,983 
 
 
 30,576 
Company Contributions
 
 
 71,759 
 
 
 11 
 
 
 14,938 
 
 
 18,657 
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 3,526 
 
 
 2,908 
Benefit Payments
 
 
 (50,444)
 
 
 (25,685)
 
 
 (17,439)
 
 
 (14,337)
Fair Value of Plan Assets at December 31
 
$
 451,688 
 
$
 379,562 
 
$
 188,690 
 
$
 166,682 
 
 
 
 
 
 
 
 
 
 
 
 
 
Underfunded Status at December 31
 
$
 (109,294)
 
$
 (146,801)
 
$
 (78,052)
 
$
 (75,165)

OPCo
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
2010 
 
2009 
 
2010 
 
2009 
Change in Benefit Obligation
 
(in thousands)
Benefit Obligation at January 1
 
$
 616,590 
 
$
 573,613 
 
$
 306,711 
 
$
 291,601 
Service Cost
 
 
 11,381 
 
 
 11,034 
 
 
 5,426 
 
 
 4,877 
Interest Cost
 
 
 32,744 
 
 
 33,100 
 
 
 17,785 
 
 
 17,325 
Actuarial Loss
 
 
 23,478 
 
 
 32,454 
 
 
 31,462 
 
 
 9,284 
Plan Amendment Prior Service Credit
 
 
 - 
 
 
 - 
 
 
 (3,875)
 
 
 - 
Benefit Payments
 
 
 (54,257)
 
 
 (33,611)
 
 
 (23,685)
 
 
 (22,385)
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 4,765 
 
 
 4,234 
Medicare Subsidy
 
 
 - 
 
 
 - 
 
 
 1,759 
 
 
 1,775 
Benefit Obligation at December 31
 
$
 629,936 
 
$
 616,590 
 
$
 340,348 
 
$
 306,711 
 
 
 
 
 
 
 
 
 
 
 
 
 
Change in Fair Value of Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Plan Assets at January 1
 
$
 468,300 
 
$
 435,694 
 
$
 200,797 
 
$
 157,255 
Actual Gain on Plan Assets
 
 
 52,940 
 
 
 66,153 
 
 
 26,258 
 
 
 39,214 
Company Contributions
 
 
 51,705 
 
 
 64 
 
 
 15,529 
 
 
 22,479 
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 4,765 
 
 
 4,234 
Benefit Payments
 
 
 (54,257)
 
 
 (33,611)
 
 
 (23,685)
 
 
 (22,385)
Fair Value of Plan Assets at December 31
 
$
 518,688 
 
$
 468,300 
 
$
 223,664 
 
$
 200,797 
 
 
 
 
 
 
 
 
 
 
 
 
 
Underfunded Status at December 31
 
$
 (111,248)
 
$
 (148,290)
 
$
 (116,684)
 
$
 (105,914)

 
292
 
PSO
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
2010 
 
2009 
 
2010 
 
2009 
Change in Benefit Obligation
 
(in thousands)
Benefit Obligation at January 1
 
$
 285,592 
 
$
 260,936 
 
$
 108,220 
 
$
 101,446 
Service Cost
 
 
 6,052 
 
 
 5,744 
 
 
 2,815 
 
 
 2,522 
Interest Cost
 
 
 14,888 
 
 
 15,369 
 
 
 6,360 
 
 
 6,154 
Actuarial (Gain) Loss
 
 
 (1,047)
 
 
 18,364 
 
 
 7,540 
 
 
 2,434 
Plan Amendment Prior Service Credit
 
 
 - 
 
 
 - 
 
 
 (2,408)
 
 
 - 
Benefit Payments
 
 
 (37,305)
 
 
 (14,821)
 
 
 (8,049)
 
 
 (6,510)
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 1,763 
 
 
 1,472 
Medicare Subsidy
 
 
 - 
 
 
 - 
 
 
 694 
 
 
 702 
Benefit Obligation at December 31
 
$
 268,180 
 
$
 285,592 
 
$
 116,935 
 
$
 108,220 
 
 
 
 
 
 
 
 
 
 
 
 
 
Change in Fair Value of Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Plan Assets at January 1
 
$
 216,966 
 
$
 202,447 
 
$
 75,700 
 
$
 58,195 
Actual Gain on Plan Assets
 
 
 21,040 
 
 
 29,316 
 
 
 6,357 
 
 
 12,637 
Company Contributions
 
 
 12,875 
 
 
 24 
 
 
 8,146 
 
 
 9,906 
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 1,763 
 
 
 1,472 
Benefit Payments
 
 
 (37,305)
 
 
 (14,821)
 
 
 (8,049)
 
 
 (6,510)
Fair Value of Plan Assets at December 31
 
$
 213,576 
 
$
 216,966 
 
$
 83,917 
 
$
 75,700 
 
 
 
 
 
 
 
 
 
 
 
 
 
Underfunded Status at December 31
 
$
 (54,604)
 
$
 (68,626)
 
$
 (33,018)
 
$
 (32,520)

SWEPCo
 
 
 
Other Postretirement
 
 
Pension Plans
 
Benefit Plans
 
 
2010 
 
2009 
 
2010 
 
2009 
Change in Benefit Obligation
 
(in thousands)
Benefit Obligation at January 1
 
$
 288,081 
 
$
 257,749 
 
$
 118,571 
 
$
 110,689 
Service Cost
 
 
 7,046 
 
 
 6,757 
 
 
 3,108 
 
 
 2,817 
Interest Cost
 
 
 15,093 
 
 
 15,557 
 
 
 6,940 
 
 
 6,735 
Actuarial (Gain) Loss
 
 
 (2,014)
 
 
 23,126 
 
 
 9,084 
 
 
 2,453 
Plan Amendment Prior Service Credit
 
 
 - 
 
 
 - 
 
 
 (2,399)
 
 
 - 
Benefit Payments
 
 
 (41,000)
 
 
 (15,108)
 
 
 (8,125)
 
 
 (6,347)
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 1,907 
 
 
 1,579 
Medicare Subsidy
 
 
 - 
 
 
 - 
 
 
 640 
 
 
 645 
Benefit Obligation at December 31
 
$
 267,206 
 
$
 288,081 
 
$
 129,726 
 
$
 118,571 
 
 
 
 
 
 
 
 
 
 
 
 
 
Change in Fair Value of Plan Assets
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Plan Assets at January 1
 
$
 212,626 
 
$
 194,816 
 
$
 82,940 
 
$
 63,498 
Actual Gain on Plan Assets
 
 
 23,854 
 
 
 32,840 
 
 
 8,150 
 
 
 14,035 
Company Contributions
 
 
 29,138 
 
 
 78 
 
 
 8,225 
 
 
 10,175 
Participant Contributions
 
 
 - 
 
 
 - 
 
 
 1,907 
 
 
 1,579 
Benefit Payments
 
 
 (41,000)
 
 
 (15,108)
 
 
 (8,125)
 
 
 (6,347)
Fair Value of Plan Assets at December 31
 
$
 224,618 
 
$
 212,626 
 
$
 93,097 
 
$
 82,940 
 
 
 
 
 
 
 
 
 
 
 
 
 
Underfunded Status at December 31
 
$
 (42,588)
 
$
 (75,455)
 
$
 (36,629)
 
$
 (35,631)

 
293
 
Amounts Recognized on the Registrant Subsidiaries' Balance Sheets as of December 31, 2010 and 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement
 
 
 
 
Pension Plans
 
Benefit Plans
 
 
 
 
December 31,
 
APCo
 
2010 
 
2009 
 
2010 
 
2009 
 
 
 
 
(in thousands)
 
Other Current Liabilities - Accrued Short-term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Benefit Liability
 
$
 (34)
 
$
 (35)
 
$
 (2,854)
 
$
 (2,705)
 
Employee Benefits and Pension Obligations -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Long-term Benefit Liability
 
 
 (139,349)
 
 
 (158,140)
 
 
 (136,527)
 
 
 (128,922)
 
Underfunded Status
 
$
 (139,383)
 
$
 (158,175)
 
$
 (139,381)
 
$
 (131,627)

 
 
 
 
 
 
Other Postretirement
 
 
 
 
Pension Plans
 
Benefit Plans
 
 
 
 
December 31,
 
CSPCo
 
2010 
 
2009 
 
2010 
 
2009 
 
 
 
 
(in thousands)
 
Other Current Liabilities - Accrued Short-term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Benefit Liability
 
$
 - 
 
$
 - 
 
$
 (363)
 
$
 (338)
 
Employee Benefits and Pension Obligations -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Long-term Benefit Liability
 
 
 (73,560)
 
 
 (76,423)
 
 
 (56,010)
 
 
 (52,069)
 
Underfunded Status
 
$
 (73,560)
 
$
 (76,423)
 
$
 (56,373)
 
$
 (52,407)

 
 
 
 
 
 
Other Postretirement
 
 
 
 
Pension Plans
 
Benefit Plans
 
 
 
 
December 31,
 
I&M
 
2010 
 
2009 
 
2010 
 
2009 
 
 
 
 
(in thousands)
 
Other Current Liabilities - Accrued Short-term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Benefit Liability
 
$
 (57)
 
$
 (87)
 
$
 (313)
 
$
 (327)
 
Deferred Credits and Other Noncurrent Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Long-term Benefit Liability
 
 
 (109,237)
 
 
 (146,714)
 
 
 (77,739)
 
 
 (74,838)
 
Underfunded Status
 
$
 (109,294)
 
$
 (146,801)
 
$
 (78,052)
 
$
 (75,165)

 
 
 
 
 
 
Other Postretirement
 
 
 
 
Pension Plans
 
Benefit Plans
 
 
 
 
December 31,
 
OPCo
 
2010 
 
2009 
 
2010 
 
2009 
 
 
 
 
(in thousands)
 
Other Current Liabilities - Accrued Short-term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Benefit Liability
 
$
 (59)
 
$
 (64)
 
$
 (304)
 
$
 (240)
 
Employee Benefits and Pension Obligations -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Long-term Benefit Liability
 
 
 (111,189)
 
 
 (148,226)
 
 
 (116,380)
 
 
 (105,674)
 
Underfunded Status
 
$
 (111,248)
 
$
 (148,290)
 
$
 (116,684)
 
$
 (105,914)

 
294
 
 
 
 
 
 
 
Other Postretirement
 
 
 
 
Pension Plans
 
Benefit Plans
 
 
 
 
December 31,
 
PSO
 
2010 
 
2009 
 
2010 
 
2009 
 
 
 
 
(in thousands)
 
Other Current Liabilities - Accrued Short-term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Benefit Liability
 
$
 (68)
 
$
 (97)
 
$
 - 
 
$
 - 
 
Employee Benefits and Pension Obligations -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Long-term Benefit Liability
 
 
 (54,536)
 
 
 (68,529)
 
 
 (33,018)
 
 
 (32,520)
 
Underfunded Status
 
$
 (54,604)
 
$
 (68,626)
 
$
 (33,018)
 
$
 (32,520)

 
 
 
 
 
 
Other Postretirement
 
 
 
 
Pension Plans
 
Benefit Plans
 
 
 
 
December 31,
 
SWEPCo
 
2010 
 
2009 
 
2010 
 
2009 
 
 
 
 
(in thousands)
 
Other Current Liabilities - Accrued Short-term
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Benefit Liability
 
$
 (73)
 
$
 (75)
 
$
 - 
 
$
 - 
 
Employee Benefits and Pension Obligations -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Long-term Benefit Liability
 
 
 (42,515)
 
 
 (75,380)
 
 
 (36,629)
 
 
 (35,631)
 
Underfunded Status
 
$
 (42,588)
 
$
 (75,455)
 
$
 (36,629)
 
$
 (35,631)

Amounts Included in AOCI and Regulatory Assets as of December 31, 2010 and 2009
 
 
 
 
 
 
 
Other Postretirement
APCo
 
Pension Plans
 
Benefit Plans
 
 
 
December 31,
 
 
 
2010 
 
2009 
 
2010 
 
2009 
Components
 
(in thousands)
Net Actuarial Loss
 
$
 290,798 
 
$
 287,871 
 
$
 115,350 
 
$
 96,884 
Prior Service Cost (Credit)
 
 
 2,310 
 
 
 3,227 
 
 
 (2,086)
 
 
 - 
Transition Obligation
 
 
 - 
 
 
 - 
 
 
 1,947 
 
 
 9,362 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recorded as
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets
 
$
 289,214 
 
$
 286,995 
 
$
 45,891 
 
$
 44,636 
Deferred Income Taxes
 
 
 1,366 
 
 
 1,439 
 
 
 23,881 
 
 
 21,213 
Net of Tax AOCI
 
 
 2,528 
 
 
 2,664 
 
 
 45,439 
 
 
 40,397 

 
 
 
 
 
Other Postretirement
CSPCo
 
Pension Plans
 
Benefit Plans
 
 
 
December 31,
 
 
 
2010 
 
2009 
 
2010 
 
2009 
Components
 
(in thousands)
Net Actuarial Loss
 
$
 200,755 
 
$
 202,025 
 
$
 51,305 
 
$
 43,708 
Prior Service Cost (Credit)
 
 
 1,292 
 
 
 1,856 
 
 
 (898)
 
 
 - 
Transition Obligation
 
 
 - 
 
 
 - 
 
 
 74 
 
 
 3,771 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recorded as
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets
 
$
 144,607 
 
$
 146,082 
 
$
 29,148 
 
$
 28,942 
Deferred Income Taxes
 
 
 20,104 
 
 
 20,230 
 
 
 7,467 
 
 
 6,489 
Net of Tax AOCI
 
 
 37,336 
 
 
 37,569 
 
 
 13,866 
 
 
 12,048 

 
295
 
 
 
 
 
 
Other Postretirement
I&M
 
Pension Plans
 
Benefit Plans
 
 
 
December 31,
 
 
 
2010 
 
2009 
 
2010 
 
2009 
Components
 
(in thousands)
Net Actuarial Loss
 
$
 208,879 
 
$
 194,212 
 
$
 78,483 
 
$
 68,637 
Prior Service Cost (Credit)
 
 
 2,051 
 
 
 2,795 
 
 
 (2,882)
 
 
 - 
Transition Obligation
 
 
 - 
 
 
 - 
 
 
 320 
 
 
 4,525 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recorded as
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets
 
$
 199,982 
 
$
 186,367 
 
$
 68,098 
 
$
 65,644 
Deferred Income Taxes
 
 
 3,830 
 
 
 3,723 
 
 
 2,737 
 
 
 2,630 
Net of Tax AOCI
 
 
 7,118 
 
 
 6,917 
 
 
 5,086 
 
 
 4,888 

 
 
 
 
 
Other Postretirement
OPCo
 
Pension Plans
 
Benefit Plans
 
 
 
December 31,
 
 
 
2010 
 
2009 
 
2010 
 
2009 
Components
 
(in thousands)
Net Actuarial Loss
 
$
 296,277 
 
$
 286,851 
 
$
 107,571 
 
$
 90,839 
Prior Service Cost (Credit)
 
 
 2,207 
 
 
 3,115 
 
 
 (1,699)
 
 
 - 
Transition Obligation
 
 
 - 
 
 
 - 
 
 
 180 
 
 
 6,566 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recorded as
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets
 
$
 148,095 
 
$
 146,818 
 
$
 41,981 
 
$
 41,331 
Deferred Income Taxes
 
 
 52,637 
 
 
 49,332 
 
 
 22,421 
 
 
 19,626 
Net of Tax AOCI
 
 
 97,752 
 
 
 93,816 
 
 
 41,650 
 
 
 36,448 

 
 
 
 
 
Other Postretirement
PSO
 
Pension Plans
 
Benefit Plans
 
 
 
December 31,
 
 
 
2010 
 
2009 
 
2010 
 
2009 
Components
 
(in thousands)
Net Actuarial Loss
 
$
 134,101 
 
$
 141,636 
 
$
 33,922 
 
$
 28,212 
Prior Service Credit
 
 
 (769)
 
 
 (1,720)
 
 
 (921)
 
 
 - 
Transition Obligation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 4,292 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recorded as
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets
 
$
 133,332 
 
$
 139,916 
 
$
 33,001 
 
$
 32,504 

 
 
 
 
 
Other Postretirement
SWEPCo
 
Pension Plans
 
Benefit Plans
 
 
 
December 31,
 
 
 
2010 
 
2009 
 
2010 
 
2009 
Components
 
(in thousands)
Net Actuarial Loss
 
$
 131,343 
 
$
 142,964 
 
$
 37,707 
 
$
 31,848 
Prior Service Credit
 
 
 (235)
 
 
 (1,031)
 
 
 (1,095)
 
 
 - 
Transition Obligation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 3,765 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recorded as
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Assets
 
$
 131,108 
 
$
 141,933 
 
$
 23,842 
 
$
 23,221 
Deferred Income Taxes
 
 
 - 
 
 
 - 
 
 
 4,469 
 
 
 4,336 
Net of Tax AOCI
 
 
 - 
 
 
 - 
 
 
 8,301 
 
 
 8,056 

 
296
 
Components of the change in amounts included in AOCI and Regulatory Assets by Registrant Subsidiary during the years ended December 31, 2010 and 2009 are as follows:

Pension Plans - Components
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Actuarial Loss (Gain) During the Year
 
$
 14,769 
 
$
 5,439 
 
$
 24,732 
 
$
 20,869 
 
$
 (2,346)
 
$
 (6,379)
Amortization of Actuarial Loss
 
 
 (11,842)
 
 
 (6,708)
 
 
 (10,065)
 
 
 (11,442)
 
 
 (5,188)
 
 
 (5,242)
Amortization of Prior Service Cost (Credit)
 
 
 (917)
 
 
 (565)
 
 
 (744)
 
 
 (909)
 
 
 950 
 
 
 796 
Change for the Year Ended
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 December 31, 2010
$
 2,010 
 
$
 (1,834)
 
$
 13,923 
 
$
 8,518 
 
$
 (6,584)
 
$
 (10,825)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension Plans - Components
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Actuarial Loss During the Year
 
$
 10,937 
 
$
 5,372 
 
$
 13,200 
 
$
 10,579 
 
$
 9,484 
 
$
 10,367 
Amortization of Actuarial Loss
 
 
 (7,688)
 
 
 (4,431)
 
 
 (6,406)
 
 
 (7,500)
 
 
 (3,487)
 
 
 (3,516)
Amortization of Prior Service Cost (Credit)
 
 
 (917)
 
 
 (565)
 
 
 (744)
 
 
 (910)
 
 
 1,082 
 
 
 916 
Change for the Year Ended
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2009
$
 2,332 
 
$
 376 
 
$
 6,050 
 
$
 2,169 
 
$
 7,079 
 
$
 7,767 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement Benefit Plans - Components
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Actuarial Loss During the Year
 
$
 23,876 
 
$
 9,858 
 
$
 13,372 
 
$
 21,349 
 
$
 7,283 
 
$
 7,570 
Amortization of Actuarial Loss
 
 
 (5,410)
 
 
 (2,261)
 
 
 (3,526)
 
 
 (4,616)
 
 
 (1,573)
 
 
 (1,711)
Prior Service Credit
 
 (4,257)
 
 
 (2,164)
 
 
 (4,273)
 
 
 (3,875)
 
 
 (2,408)
 
 
 (2,399)
Amortization of Transition Obligation
 
 
 (5,244)
 
 
 (2,431)
 
 
 (2,814)
 
 
 (4,211)
 
 
 (2,805)
 
 
 (2,461)
Change for the Year Ended
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2010
$
 8,965 
 
$
 3,002 
 
$
 2,759 
 
$
 8,647 
 
$
 497 
 
$
 999 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement Benefit Plans - Components
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Actuarial Gain During the Year
 
$
 (21,375)
 
$
 (11,976)
 
$
 (16,408)
 
$
 (18,761)
 
$
 (5,577)
 
$
 (6,540)
Amortization of Actuarial Loss
 
 
 (7,666)
 
 
 (3,285)
 
 
 (5,213)
 
 
 (6,703)
 
 
 (2,348)
 
 
 (2,560)
Amortization of Transition Obligation
 
 
 (5,244)
 
 
 (2,432)
 
 
 (2,814)
 
 
 (4,211)
 
 
 (2,805)
 
 
 (2,461)
Change for the Year Ended
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2009
$
 (34,285)
 
$
 (17,693)
 
$
 (24,435)
 
$
 (29,675)
 
$
 (10,730)
 
$
 (11,561)

 
297
 
Pension and Other Postretirement Plans’ Assets

The following tables present the classification of pension plan assets within the fair value hierarchy by Registrant Subsidiary at December 31, 2010:

 
APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 179,421 
 
$
 366 
 
$
 - 
 
$
 - 
 
$
 179,787 
 
 35.1 
%
 
 
International
 
 
 53,559 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 53,559 
 
 10.4 
%
 
 
Real Estate Investment Trusts
 
 
 14,932 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 14,932 
 
 2.9 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 21,619 
 
 
 - 
 
 
 - 
 
 
 21,619 
 
 4.2 
%
 
Subtotal - Equities
 
 
 247,912 
 
 
 21,985 
 
 
 - 
 
 
 - 
 
 
 269,897 
 
 52.6 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 84,280 
 
 
 - 
 
 
 - 
 
 
 84,280 
 
 16.4 
%
 
 
Corporate Debt
 
 
 - 
 
 
 89,296 
 
 
 - 
 
 
 - 
 
 
 89,296 
 
 17.4 
%
 
 
Foreign Debt
 
 
 - 
 
 
 16,900 
 
 
 - 
 
 
 - 
 
 
 16,900 
 
 3.3 
%
 
 
State and Local Government
 
 
 - 
 
 
 3,021 
 
 
 - 
 
 
 - 
 
 
 3,021 
 
 0.6 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 6,798 
 
 
 - 
 
 
 - 
 
 
 6,798 
 
 1.3 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 200,295 
 
 
 - 
 
 
 - 
 
 
 200,295 
 
 39.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 11,060 
 
 
 - 
 
 
 11,060 
 
 2.2 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 17,281 
 
 
 - 
 
 
 17,281 
 
 3.4 
%
 
Securities Lending
 
 
 - 
 
 
 33,804 
 
 
 - 
 
 
 - 
 
 
 33,804 
 
 6.6 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (36,664)
 
 
 (36,664)
 
 (7.1)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (b)
 
 
 - 
 
 
 16,870 
 
 
 - 
 
 
 212 
 
 
 17,082 
 
 3.3 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (c)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 81 
 
 
 81 
 
 - 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 247,912 
 
$
 272,954 
 
$
 28,341 
 
$
 (36,371)
 
$
 512,836 
 
 100.0 
%

 
298
 
 
CSPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 98,168 
 
$
 200 
 
$
 - 
 
$
 - 
 
$
 98,368 
 
 35.1 
%
 
 
International
 
 
 29,304 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 29,304 
 
 10.4 
%
 
 
Real Estate Investment Trusts
 
 
 8,170 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 8,170 
 
 2.9 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 11,829 
 
 
 - 
 
 
 - 
 
 
 11,829 
 
 4.2 
%
 
Subtotal - Equities
 
 
 135,642 
 
 
 12,029 
 
 
 - 
 
 
 - 
 
 
 147,671 
 
 52.6 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 46,113 
 
 
 - 
 
 
 - 
 
 
 46,113 
 
 16.4 
%
 
 
Corporate Debt
 
 
 - 
 
 
 48,857 
 
 
 - 
 
 
 - 
 
 
 48,857 
 
 17.4 
%
 
 
Foreign Debt
 
 
 - 
 
 
 9,247 
 
 
 - 
 
 
 - 
 
 
 9,247 
 
 3.3 
%
 
 
State and Local Government
 
 
 - 
 
 
 1,653 
 
 
 - 
 
 
 - 
 
 
 1,653 
 
 0.6 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 3,719 
 
 
 - 
 
 
 - 
 
 
 3,719 
 
 1.3 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 109,589 
 
 
 - 
 
 
 - 
 
 
 109,589 
 
 39.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 6,052 
 
 
 - 
 
 
 6,052 
 
 2.2 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 9,455 
 
 
 - 
 
 
 9,455 
 
 3.4 
%
 
Securities Lending
 
 
 - 
 
 
 18,496 
 
 
 - 
 
 
 - 
 
 
 18,496 
 
 6.6 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (20,060)
 
 
 (20,060)
 
 (7.1)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (b)
 
 
 - 
 
 
 9,230 
 
 
 - 
 
 
 116 
 
 
 9,346 
 
 3.3 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (c)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 44 
 
 
 44 
 
 - 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 135,642 
 
$
 149,344 
 
$
 15,507 
 
$
 (19,900)
 
$
 280,593 
 
 100.0 
%

 
299
 
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 158,027 
 
$
 323 
 
$
 - 
 
$
 - 
 
$
 158,350 
 
 35.1 
%
 
 
International
 
 
 47,173 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 47,173 
 
 10.4 
%
 
 
Real Estate Investment Trusts
 
 
 13,152 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 13,152 
 
 2.9 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 19,041 
 
 
 - 
 
 
 - 
 
 
 19,041 
 
 4.2 
%
 
Subtotal - Equities
 
 
 218,352 
 
 
 19,364 
 
 
 - 
 
 
 - 
 
 
 237,716 
 
 52.6 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 74,231 
 
 
 - 
 
 
 - 
 
 
 74,231 
 
 16.4 
%
 
 
Corporate Debt
 
 
 - 
 
 
 78,649 
 
 
 - 
 
 
 - 
 
 
 78,649 
 
 17.4 
%
 
 
Foreign Debt
 
 
 - 
 
 
 14,885 
 
 
 - 
 
 
 - 
 
 
 14,885 
 
 3.3 
%
 
 
State and Local Government
 
 
 - 
 
 
 2,661 
 
 
 - 
 
 
 - 
 
 
 2,661 
 
 0.6 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 5,987 
 
 
 - 
 
 
 - 
 
 
 5,987 
 
 1.3 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 176,413 
 
 
 - 
 
 
 - 
 
 
 176,413 
 
 39.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 9,742 
 
 
 - 
 
 
 9,742 
 
 2.2 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 15,220 
 
 
 - 
 
 
 15,220 
 
 3.4 
%
 
Securities Lending
 
 
 - 
 
 
 29,773 
 
 
 - 
 
 
 - 
 
 
 29,773 
 
 6.6 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (32,292)
 
 
 (32,292)
 
 (7.1)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (b)
 
 
 - 
 
 
 14,859 
 
 
 - 
 
 
 186 
 
 
 15,045 
 
 3.3 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (c)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 71 
 
 
 71 
 
 - 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 218,352 
 
$
 240,409 
 
$
 24,962 
 
$
 (32,035)
 
$
 451,688 
 
 100.0 
%

 
300
 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 181,467 
 
$
 371 
 
$
 - 
 
$
 - 
 
$
 181,838 
 
 35.1 
%
 
 
International
 
 
 54,169 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 54,169 
 
 10.4 
%
 
 
Real Estate Investment Trusts
 
 
 15,103 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 15,103 
 
 2.9 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 21,866 
 
 
 - 
 
 
 - 
 
 
 21,866 
 
 4.2 
%
 
Subtotal - Equities
 
 
 250,739 
 
 
 22,237 
 
 
 - 
 
 
 - 
 
 
 272,976 
 
 52.6 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 85,242 
 
 
 - 
 
 
 - 
 
 
 85,242 
 
 16.4 
%
 
 
Corporate Debt
 
 
 - 
 
 
 90,315 
 
 
 - 
 
 
 - 
 
 
 90,315 
 
 17.4 
%
 
 
Foreign Debt
 
 
 - 
 
 
 17,093 
 
 
 - 
 
 
 - 
 
 
 17,093 
 
 3.3 
%
 
 
State and Local Government
 
 
 - 
 
 
 3,055 
 
 
 - 
 
 
 - 
 
 
 3,055 
 
 0.6 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 6,875 
 
 
 - 
 
 
 - 
 
 
 6,875 
 
 1.3 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 202,580 
 
 
 - 
 
 
 - 
 
 
 202,580 
 
 39.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 11,187 
 
 
 - 
 
 
 11,187 
 
 2.2 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 17,478 
 
 
 - 
 
 
 17,478 
 
 3.4 
%
 
Securities Lending
 
 
 - 
 
 
 34,190 
 
 
 - 
 
 
 - 
 
 
 34,190 
 
 6.6 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (37,082)
 
 
 (37,082)
 
 (7.1)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (b)
 
 
 - 
 
 
 17,063 
 
 
 - 
 
 
 214 
 
 
 17,277 
 
 3.3 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (c)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 82 
 
 
 82 
 
 - 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 250,739 
 
$
 276,070 
 
$
 28,665 
 
$
 (36,786)
 
$
 518,688 
 
 100.0 
%

 
301
 
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 74,721 
 
$
 153 
 
$
 - 
 
$
 - 
 
$
 74,874 
 
 35.1 
%
 
 
International
 
 
 22,305 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 22,305 
 
 10.4 
%
 
 
Real Estate Investment Trusts
 
 
 6,219 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 6,219 
 
 2.9 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 9,004 
 
 
 - 
 
 
 - 
 
 
 9,004 
 
 4.2 
%
 
Subtotal - Equities
 
 
 103,245 
 
 
 9,157 
 
 
 - 
 
 
 - 
 
 
 112,402 
 
 52.6 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 35,099 
 
 
 - 
 
 
 - 
 
 
 35,099 
 
 16.4 
%
 
 
Corporate Debt
 
 
 - 
 
 
 37,188 
 
 
 - 
 
 
 - 
 
 
 37,188 
 
 17.4 
%
 
 
Foreign Debt
 
 
 - 
 
 
 7,038 
 
 
 - 
 
 
 - 
 
 
 7,038 
 
 3.3 
%
 
 
State and Local Government
 
 
 - 
 
 
 1,258 
 
 
 - 
 
 
 - 
 
 
 1,258 
 
 0.6 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 2,831 
 
 
 - 
 
 
 - 
 
 
 2,831 
 
 1.3 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 83,414 
 
 
 - 
 
 
 - 
 
 
 83,414 
 
 39.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 4,606 
 
 
 - 
 
 
 4,606 
 
 2.2 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 7,197 
 
 
 - 
 
 
 7,197 
 
 3.4 
%
 
Securities Lending
 
 
 - 
 
 
 14,078 
 
 
 - 
 
 
 - 
 
 
 14,078 
 
 6.6 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (15,269)
 
 
 (15,269)
 
 (7.1)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (b)
 
 
 - 
 
 
 7,026 
 
 
 - 
 
 
 88 
 
 
 7,114 
 
 3.3 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (c)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 34 
 
 
 34 
 
 - 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 103,245 
 
$
 113,675 
 
$
 11,803 
 
$
 (15,147)
 
$
 213,576 
 
 100.0 
%

 
302
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 78,585 
 
$
 160 
 
$
 - 
 
$
 - 
 
$
 78,745 
 
 35.1 
%
 
 
International
 
 
 23,458 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 23,458 
 
 10.4 
%
 
 
Real Estate Investment Trusts
 
 
 6,540 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 6,540 
 
 2.9 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 9,469 
 
 
 - 
 
 
 - 
 
 
 9,469 
 
 4.2 
%
 
Subtotal - Equities
 
 
 108,583 
 
 
 9,629 
 
 
 - 
 
 
 - 
 
 
 118,212 
 
 52.6 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 36,914 
 
 
 - 
 
 
 - 
 
 
 36,914 
 
 16.4 
%
 
 
Corporate Debt
 
 
 - 
 
 
 39,111 
 
 
 - 
 
 
 - 
 
 
 39,111 
 
 17.4 
%
 
 
Foreign Debt
 
 
 - 
 
 
 7,402 
 
 
 - 
 
 
 - 
 
 
 7,402 
 
 3.3 
%
 
 
State and Local Government
 
 
 - 
 
 
 1,323 
 
 
 - 
 
 
 - 
 
 
 1,323 
 
 0.6 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 2,977 
 
 
 - 
 
 
 - 
 
 
 2,977 
 
 1.3 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 87,727 
 
 
 - 
 
 
 - 
 
 
 87,727 
 
 39.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 4,844 
 
 
 - 
 
 
 4,844 
 
 2.2 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 7,569 
 
 
 - 
 
 
 7,569 
 
 3.4 
%
 
Securities Lending
 
 
 - 
 
 
 14,806 
 
 
 - 
 
 
 - 
 
 
 14,806 
 
 6.6 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (16,058)
 
 
 (16,058)
 
 (7.1)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (b)
 
 
 - 
 
 
 7,389 
 
 
 - 
 
 
 93 
 
 
 7,482 
 
 3.3 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (c)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 36 
 
 
 36 
 
 - 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 108,583 
 
$
 119,551 
 
$
 12,413 
 
$
 (15,929)
 
$
 224,618 
 
 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 foreign currency holdings.
 
(c)
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 real estate and alternative investments classified as Level 3 in the fair value hierarchy by Registrant Subsidiary for pension assets:

 
 
 
 
 
 
Alternative
 
Total
 
APCo
 
Real Estate
 
Investments
 
Level 3
 
 
 
 
(in thousands)
 
Balance as of January 1, 2010
 
$
 12,623 
 
$
 14,739 
 
$
 27,362 
 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 (1,563)
 
 
 412 
 
 
 (1,151)
 
 
Relating to Assets Sold During the Period
 
 
 - 
 
 
 134 
 
 
 134 
 
Purchases and Sales
 
 
 - 
 
 
 1,996 
 
 
 1,996 
 
Transfers into Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
Transfers out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
Balance as of December 31, 2010
 
$
 11,060 
 
$
 17,281 
 
$
 28,341 

 
303
 
 
 
 
 
 
 
Alternative
 
Total
 
CSPCo
 
Real Estate
 
Investments
 
Level 3
 
 
 
 
(in thousands)
 
Balance as of  January 1, 2010
 
$
 7,671 
 
$
 8,957 
 
$
 16,628 
 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 (1,619)
 
 
 81 
 
 
 (1,538)
 
 
Relating to Assets Sold During the Period
 
 
 - 
 
 
 26 
 
 
 26 
 
Purchases and Sales
 
 
 - 
 
 
 391 
 
 
 391 
 
Transfers into Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
Transfers out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
Balance as of December 31, 2010
 
$
 6,052 
 
$
 9,455 
 
$
 15,507 

 
 
 
 
 
 
Alternative
 
Total
 
I&M
 
Real Estate
 
Investments
 
Level 3
 
 
 
 
(in thousands)
 
Balance as of January 1, 2010
 
$
 10,094 
 
$
 11,786 
 
$
 21,880 
 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 (352)
 
 
 556 
 
 
 204 
 
 
Relating to Assets Sold During the Period
 
 
 - 
 
 
 181 
 
 
 181 
 
Purchases and Sales
 
 
 - 
 
 
 2,697 
 
 
 2,697 
 
Transfers into Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
Transfers out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
Balance as of December 31, 2010
 
$
 9,742 
 
$
 15,220 
 
$
 24,962 

 
 
 
 
 
 
Alternative
 
Total
 
OPCo
 
Real Estate
 
Investments
 
Level 3
 
 
 
 
(in thousands)
 
Balance as of January 1, 2010
 
$
 12,454 
 
$
 14,541 
 
$
 26,995 
 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 (1,267)
 
 
 476 
 
 
 (791)
 
 
Relating to Assets Sold During the Period
 
 
 - 
 
 
 155 
 
 
 155 
 
Purchases and Sales
 
 
 - 
 
 
 2,306 
 
 
 2,306 
 
Transfers into Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
Transfers out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
Balance as of December 31, 2010
 
$
 11,187 
 
$
 17,478 
 
$
 28,665 

 
 
 
 
 
 
Alternative
 
Total
 
PSO
 
Real Estate
 
Investments
 
Level 3
 
 
 
 
(in thousands)
 
Balance as of January 1, 2010
 
$
 5,770 
 
$
 6,737 
 
$
 12,507 
 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 (1,164)
 
 
 75 
 
 
 (1,089)
 
 
Relating to Assets Sold During the Period
 
 
 - 
 
 
 24 
 
 
 24 
 
Purchases and Sales
 
 
 - 
 
 
 361 
 
 
 361 
 
Transfers into Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
Transfers out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
Balance as of December 31, 2010
 
$
 4,606 
 
$
 7,197 
 
$
 11,803 

 
 
 
 
 
 
Alternative
 
Total
 
SWEPCo
 
Real Estate
 
Investments
 
Level 3
 
 
 
 
(in thousands)
 
Balance as of January 1, 2010
 
$
 5,654 
 
$
 6,602 
 
$
 12,256 
 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 (810)
 
 
 156 
 
 
 (654)
 
 
Relating to Assets Sold During the Period
 
 
 - 
 
 
 51 
 
 
 51 
 
Purchases and Sales
 
 
 - 
 
 
 760 
 
 
 760 
 
Transfers into Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
Transfers out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
Balance as of December 31, 2010
 
$
 4,844 
 
$
 7,569 
 
$
 12,413 

 
304
 
The following tables present the classification of OPEB plan assets within the fair value hierarchy by Registrant Subsidiary at December 31, 2010:

 
APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 97,469 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 97,469 
 
 40.0 
%
 
 
International
 
 
 36,792 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 36,792 
 
 15.1 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Global
 
 
 - 
 
 
 19,153 
 
 
 - 
 
 
 - 
 
 
 19,153 
 
 7.9 
%
 
Subtotal - Equities
 
 
 134,261 
 
 
 19,153 
 
 
 - 
 
 
 - 
 
 
 153,414 
 
 63.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 7,966 
 
 
 - 
 
 
 - 
 
 
 7,966 
 
 3.3 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 15,636 
 
 
 - 
 
 
 - 
 
 
 15,636 
 
 6.4 
%
 
 
Corporate Debt
 
 
 - 
 
 
 18,365 
 
 
 - 
 
 
 - 
 
 
 18,365 
 
 7.5 
%
 
 
Foreign Debt
 
 
 - 
 
 
 4,140 
 
 
 - 
 
 
 - 
 
 
 4,140 
 
 1.7 
%
 
 
State and Local Government
 
 
 - 
 
 
 583 
 
 
 - 
 
 
 - 
 
 
 583 
 
 0.2 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 158 
 
 
 - 
 
 
 - 
 
 
 158 
 
 0.1 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 46,848 
 
 
 - 
 
 
 - 
 
 
 46,848 
 
 19.2 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 8,189 
 
 
 - 
 
 
 - 
 
 
 8,189 
 
 3.3 
%
 
 
United States Bonds
 
 
 - 
 
 
 27,130 
 
 
 - 
 
 
 - 
 
 
 27,130 
 
 11.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
 
 3,422 
 
 
 4,179 
 
 
 - 
 
 
 143 
 
 
 7,744 
 
 3.2 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 446 
 
 
 446 
 
 0.2 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 137,683 
 
$
 105,499 
 
$
 - 
 
$
 589 
 
$
 243,771 
 
 100.0 
%

 
305
 
 
CSPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 43,795 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 43,795 
 
 40.0 
%
 
 
International
 
 
 16,532 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 16,532 
 
 15.1 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Global
 
 
 - 
 
 
 8,606 
 
 
 - 
 
 
 - 
 
 
 8,606 
 
 7.9 
%
 
Subtotal - Equities
 
 
 60,327 
 
 
 8,606 
 
 
 - 
 
 
 - 
 
 
 68,933 
 
 63.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 3,580 
 
 
 - 
 
 
 - 
 
 
 3,580 
 
 3.3 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 7,026 
 
 
 - 
 
 
 - 
 
 
 7,026 
 
 6.4 
%
 
 
Corporate Debt
 
 
 - 
 
 
 8,252 
 
 
 - 
 
 
 - 
 
 
 8,252 
 
 7.5 
%
 
 
Foreign Debt
 
 
 - 
 
 
 1,860 
 
 
 - 
 
 
 - 
 
 
 1,860 
 
 1.7 
%
 
 
State and Local Government
 
 
 - 
 
 
 262 
 
 
 - 
 
 
 - 
 
 
 262 
 
 0.2 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 71 
 
 
 - 
 
 
 - 
 
 
 71 
 
 0.1 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 21,051 
 
 
 - 
 
 
 - 
 
 
 21,051 
 
 19.2 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 3,679 
 
 
 - 
 
 
 - 
 
 
 3,679 
 
 3.3 
%
 
 
United States Bonds
 
 
 - 
 
 
 12,190 
 
 
 - 
 
 
 - 
 
 
 12,190 
 
 11.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
 
 1,538 
 
 
 1,878 
 
 
 - 
 
 
 64 
 
 
 3,480 
 
 3.2 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 201 
 
 
 201 
 
 0.2 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 61,865 
 
$
 47,404 
 
$
 - 
 
$
 265 
 
$
 109,534 
 
 100.0 
%

 
306
 
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 75,446 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 75,446 
 
 40.0 
%
 
 
International
 
 
 28,479 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 28,479 
 
 15.1 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Global
 
 
 - 
 
 
 14,825 
 
 
 - 
 
 
 - 
 
 
 14,825 
 
 7.9 
%
 
Subtotal - Equities
 
 
 103,925 
 
 
 14,825 
 
 
 - 
 
 
 - 
 
 
 118,750 
 
 63.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 6,166 
 
 
 - 
 
 
 - 
 
 
 6,166 
 
 3.3 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 12,103 
 
 
 - 
 
 
 - 
 
 
 12,103 
 
 6.4 
%
 
 
Corporate Debt
 
 
 - 
 
 
 14,215 
 
 
 - 
 
 
 - 
 
 
 14,215 
 
 7.5 
%
 
 
Foreign Debt
 
 
 - 
 
 
 3,204 
 
 
 - 
 
 
 - 
 
 
 3,204 
 
 1.7 
%
 
 
State and Local Government
 
 
 - 
 
 
 452 
 
 
 - 
 
 
 - 
 
 
 452 
 
 0.2 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 122 
 
 
 - 
 
 
 - 
 
 
 122 
 
 0.1 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 36,262 
 
 
 - 
 
 
 - 
 
 
 36,262 
 
 19.2 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 6,338 
 
 
 - 
 
 
 - 
 
 
 6,338 
 
 3.3 
%
 
 
United States Bonds
 
 
 - 
 
 
 21,000 
 
 
 - 
 
 
 - 
 
 
 21,000 
 
 11.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
 
 2,649 
 
 
 3,234 
 
 
 - 
 
 
 111 
 
 
 5,994 
 
 3.2 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 346 
 
 
 346 
 
 0.2 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 106,574 
 
$
 81,659 
 
$
 - 
 
$
 457 
 
$
 188,690 
 
 100.0 
%

 
307
 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 89,430 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 89,430 
 
 40.0 
%
 
 
International
 
 
 33,758 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 33,758 
 
 15.1 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Global
 
 
 - 
 
 
 17,573 
 
 
 - 
 
 
 - 
 
 
 17,573 
 
 7.9 
%
 
 
 
 
Subtotal Equities
 
 
 123,188 
 
 
 17,573 
 
 
 - 
 
 
 - 
 
 
 140,761 
 
 63.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 7,309 
 
 
 - 
 
 
 - 
 
 
 7,309 
 
 3.3 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 14,346 
 
 
 - 
 
 
 - 
 
 
 14,346 
 
 6.4 
%
 
 
Corporate Debt
 
 
 - 
 
 
 16,850 
 
 
 - 
 
 
 - 
 
 
 16,850 
 
 7.5 
%
 
 
Foreign Debt
 
 
 - 
 
 
 3,798 
 
 
 - 
 
 
 - 
 
 
 3,798 
 
 1.7 
%
 
 
State and Local Government
 
 
 - 
 
 
 535 
 
 
 - 
 
 
 - 
 
 
 535 
 
 0.2 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 145 
 
 
 - 
 
 
 - 
 
 
 145 
 
 0.1 
%
 
 
 
 
Subtotal Fixed Income
 
 
 - 
 
 
 42,983 
 
 
 - 
 
 
 - 
 
 
 42,983 
 
 19.2 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 7,513 
 
 
 - 
 
 
 - 
 
 
 7,513 
 
 3.3 
%
 
 
United States Bonds
 
 
 - 
 
 
 24,892 
 
 
 - 
 
 
 - 
 
 
 24,892 
 
 11.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
 
 3,140 
 
 
 3,834 
 
 
 - 
 
 
 131 
 
 
 7,105 
 
 3.2 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 410 
 
 
 410 
 
 0.2 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 126,328 
 
$
 96,795 
 
$
 - 
 
$
 541 
 
$
 223,664 
 
 100.0 
%

 
308
 
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 33,555 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 33,555 
 
 40.0 
%
 
 
International
 
 
 12,666 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 12,666 
 
 15.1 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Global
 
 
 - 
 
 
 6,593 
 
 
 - 
 
 
 - 
 
 
 6,593 
 
 7.9 
%
 
Subtotal - Equities
 
 
 46,221 
 
 
 6,593 
 
 
 - 
 
 
 - 
 
 
 52,814 
 
 63.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 2,742 
 
 
 - 
 
 
 - 
 
 
 2,742 
 
 3.3 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 5,382 
 
 
 - 
 
 
 - 
 
 
 5,382 
 
 6.4 
%
 
 
Corporate Debt
 
 
 - 
 
 
 6,322 
 
 
 - 
 
 
 - 
 
 
 6,322 
 
 7.5 
%
 
 
Foreign Debt
 
 
 - 
 
 
 1,425 
 
 
 - 
 
 
 - 
 
 
 1,425 
 
 1.7 
%
 
 
State and Local Government
 
 
 - 
 
 
 201 
 
 
 - 
 
 
 - 
 
 
 201 
 
 0.2 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 54 
 
 
 - 
 
 
 - 
 
 
 54 
 
 0.1 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 16,126 
 
 
 - 
 
 
 - 
 
 
 16,126 
 
 19.2 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 2,819 
 
 
 - 
 
 
 - 
 
 
 2,819 
 
 3.3 
%
 
 
United States Bonds
 
 
 - 
 
 
 9,339 
 
 
 - 
 
 
 - 
 
 
 9,339 
 
 11.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
 
 1,178 
 
 
 1,438 
 
 
 - 
 
 
 49 
 
 
 2,665 
 
 3.2 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 154 
 
 
 154 
 
 0.2 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 47,399 
 
$
 36,315 
 
$
 - 
 
$
 203 
 
$
 83,917 
 
 100.0 
%

 
309
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 37,225 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 37,225 
 
 40.0 
%
 
 
International
 
 
 14,051 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 14,051 
 
 15.1 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Global
 
 
 - 
 
 
 7,314 
 
 
 - 
 
 
 - 
 
 
 7,314 
 
 7.9 
%
 
Subtotal - Equities
 
 
 51,276 
 
 
 7,314 
 
 
 - 
 
 
 - 
 
 
 58,590 
 
 63.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 3,042 
 
 
 - 
 
 
 - 
 
 
 3,042 
 
 3.3 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 5,971 
 
 
 - 
 
 
 - 
 
 
 5,971 
 
 6.4 
%
 
 
Corporate Debt
 
 
 - 
 
 
 7,014 
 
 
 - 
 
 
 - 
 
 
 7,014 
 
 7.5 
%
 
 
Foreign Debt
 
 
 - 
 
 
 1,581 
 
 
 - 
 
 
 - 
 
 
 1,581 
 
 1.7 
%
 
 
State and Local Government
 
 
 - 
 
 
 223 
 
 
 - 
 
 
 - 
 
 
 223 
 
 0.2 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 60 
 
 
 - 
 
 
 - 
 
 
 60 
 
 0.1 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 17,891 
 
 
 - 
 
 
 - 
 
 
 17,891 
 
 19.2 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 3,127 
 
 
 - 
 
 
 - 
 
 
 3,127 
 
 3.3 
%
 
 
United States Bonds
 
 
 - 
 
 
 10,361 
 
 
 - 
 
 
 - 
 
 
 10,361 
 
 11.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
 
 1,307 
 
 
 1,596 
 
 
 - 
 
 
 55 
 
 
 2,958 
 
 3.2 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 170 
 
 
 170 
 
 0.2 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 52,583 
 
$
 40,289 
 
$
 - 
 
$
 225 
 
$
 93,097 
 
 100.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Amounts in "Other" column primarily represent foreign currency holdings.
 
(b)
Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending
 
 
 
 
settlement.

 
310
 
The following tables present the classification of pension plan assets within the fair value hierarchy by Registrant Subsidiary at December 31, 2009:

 
APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 170,104 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 170,104 
 
 35.8 
%
 
 
International
 
 
 44,620 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 44,620 
 
 9.4 
%
 
 
Real Estate Investment Trusts
 
 
 12,089 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 12,089 
 
 2.6 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 22,468 
 
 
 - 
 
 
 - 
 
 
 22,468 
 
 4.7 
%
 
Subtotal - Equities
 
 
 226,813 
 
 
 22,468 
 
 
 - 
 
 
 - 
 
 
 249,281 
 
 52.5 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 32,473 
 
 
 - 
 
 
 - 
 
 
 32,473 
 
 6.9 
%
 
 
Corporate Debt
 
 
 - 
 
 
 115,879 
 
 
 - 
 
 
 - 
 
 
 115,879 
 
 24.4 
%
 
 
Foreign Debt
 
 
 - 
 
 
 23,838 
 
 
 - 
 
 
 - 
 
 
 23,838 
 
 5.0 
%
 
 
State and Local Government
 
 
 - 
 
 
 4,800 
 
 
 - 
 
 
 - 
 
 
 4,800 
 
 1.0 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 3,822 
 
 
 - 
 
 
 - 
 
 
 3,822 
 
 0.8 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 180,812 
 
 
 - 
 
 
 - 
 
 
 180,812 
 
 38.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 12,623 
 
 
 - 
 
 
 12,623 
 
 2.7 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 14,739 
 
 
 - 
 
 
 14,739 
 
 3.1 
%
 
Securities Lending
 
 
 - 
 
 
 24,179 
 
 
 - 
 
 
 - 
 
 
 24,179 
 
 5.1 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (27,313)
 
 
 (27,313)
 
 (5.8)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (b)
 
 
 - 
 
 
 16,126 
 
 
 - 
 
 
 562 
 
 
 16,688 
 
 3.5 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (c)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 3,648 
 
 
 3,648 
 
 0.8 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 226,813 
 
$
 243,585 
 
$
 27,362 
 
$
 (23,103)
 
$
 474,657 
 
 100.0 
%

 
311
 
 
CSPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 103,381 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 103,381 
 
 35.8 
%
 
 
International
 
 
 27,117 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 27,117 
 
 9.4 
%
 
 
Real Estate Investment Trusts
 
 
 7,347 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 7,347 
 
 2.6 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 13,655 
 
 
 - 
 
 
 - 
 
 
 13,655 
 
 4.7 
%
 
Subtotal - Equities
 
 
 137,845 
 
 
 13,655 
 
 
 - 
 
 
 - 
 
 
 151,500 
 
 52.5 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 19,735 
 
 
 - 
 
 
 - 
 
 
 19,735 
 
 6.9 
%
 
 
Corporate Debt
 
 
 - 
 
 
 70,425 
 
 
 - 
 
 
 - 
 
 
 70,425 
 
 24.4 
%
 
 
Foreign Debt
 
 
 - 
 
 
 14,487 
 
 
 - 
 
 
 - 
 
 
 14,487 
 
 5.0 
%
 
 
State and Local Government
 
 
 - 
 
 
 2,917 
 
 
 - 
 
 
 - 
 
 
 2,917 
 
 1.0 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 2,323 
 
 
 - 
 
 
 - 
 
 
 2,323 
 
 0.8 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 109,887 
 
 
 - 
 
 
 - 
 
 
 109,887 
 
 38.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 7,671 
 
 
 - 
 
 
 7,671 
 
 2.7 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 8,957 
 
 
 - 
 
 
 8,957 
 
 3.1 
%
 
Securities Lending
 
 
 - 
 
 
 14,694 
 
 
 - 
 
 
 - 
 
 
 14,694 
 
 5.1 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (16,599)
 
 
 (16,599)
 
 (5.8)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (b)
 
 
 - 
 
 
 9,800 
 
 
 - 
 
 
 341 
 
 
 10,141 
 
 3.5 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (c)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 2,217 
 
 
 2,217 
 
 0.8 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 137,845 
 
$
 148,036 
 
$
 16,628 
 
$
 (14,041)
 
$
 288,468 
 
 100.0 
%

 
312
 
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 136,025 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 136,025 
 
 35.8 
%
 
 
International
 
 
 35,680 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 35,680 
 
 9.4 
%
 
 
Real Estate Investment Trusts
 
 
 9,667 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 9,667 
 
 2.6 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 17,967 
 
 
 - 
 
 
 - 
 
 
 17,967 
 
 4.7 
%
 
Subtotal - Equities
 
 
 181,372 
 
 
 17,967 
 
 
 - 
 
 
 - 
 
 
 199,339 
 
 52.5 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 25,967 
 
 
 - 
 
 
 - 
 
 
 25,967 
 
 6.9 
%
 
 
Corporate Debt
 
 
 - 
 
 
 92,664 
 
 
 - 
 
 
 - 
 
 
 92,664 
 
 24.4 
%
 
 
Foreign Debt
 
 
 - 
 
 
 19,062 
 
 
 - 
 
 
 - 
 
 
 19,062 
 
 5.0 
%
 
 
State and Local Government
 
 
 - 
 
 
 3,839 
 
 
 - 
 
 
 - 
 
 
 3,839 
 
 1.0 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 3,056 
 
 
 - 
 
 
 - 
 
 
 3,056 
 
 0.8 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 144,588 
 
 
 - 
 
 
 - 
 
 
 144,588 
 
 38.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 10,094 
 
 
 - 
 
 
 10,094 
 
 2.7 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 11,786 
 
 
 - 
 
 
 11,786 
 
 3.1 
%
 
Securities Lending
 
 
 - 
 
 
 19,335 
 
 
 - 
 
 
 - 
 
 
 19,335 
 
 5.1 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (21,841)
 
 
 (21,841)
 
 (5.8)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (b)
 
 
 - 
 
 
 12,895 
 
 
 - 
 
 
 449 
 
 
 13,344 
 
 3.5 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (c)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 2,917 
 
 
 2,917 
 
 0.8 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 181,372 
 
$
 194,785 
 
$
 21,880 
 
$
 (18,475)
 
$
 379,562 
 
 100.0 
%

 
313
 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 167,827 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 167,827 
 
 35.8 
%
 
 
International
 
 
 44,022 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 44,022 
 
 9.4 
%
 
 
Real Estate Investment Trusts
 
 
 11,927 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 11,927 
 
 2.6 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 22,167 
 
 
 - 
 
 
 - 
 
 
 22,167 
 
 4.7 
%
 
Subtotal - Equities
 
 
 223,776 
 
 
 22,167 
 
 
 - 
 
 
 - 
 
 
 245,943 
 
 52.5 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 32,038 
 
 
 - 
 
 
 - 
 
 
 32,038 
 
 6.9 
%
 
 
Corporate Debt
 
 
 - 
 
 
 114,327 
 
 
 - 
 
 
 - 
 
 
 114,327 
 
 24.4 
%
 
 
Foreign Debt
 
 
 - 
 
 
 23,519 
 
 
 - 
 
 
 - 
 
 
 23,519 
 
 5.0 
%
 
 
State and Local Government
 
 
 - 
 
 
 4,736 
 
 
 - 
 
 
 - 
 
 
 4,736 
 
 1.0 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 3,771 
 
 
 - 
 
 
 - 
 
 
 3,771 
 
 0.8 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 178,391 
 
 
 - 
 
 
 - 
 
 
 178,391 
 
 38.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 12,454 
 
 
 - 
 
 
 12,454 
 
 2.7 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 14,541 
 
 
 - 
 
 
 14,541 
 
 3.1 
%
 
Securities Lending
 
 
 - 
 
 
 23,855 
 
 
 - 
 
 
 - 
 
 
 23,855 
 
 5.1 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (26,947)
 
 
 (26,947)
 
 (5.8)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (b)
 
 
 - 
 
 
 15,910 
 
 
 - 
 
 
 554 
 
 
 16,464 
 
 3.5 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (c)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 3,599 
 
 
 3,599 
 
 0.8 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 223,776 
 
$
 240,323 
 
$
 26,995 
 
$
 (22,794)
 
$
 468,300 
 
 100.0 
%

 
314
 
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 77,756 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 77,756 
 
 35.8 
%
 
 
International
 
 
 20,396 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 20,396 
 
 9.4 
%
 
 
Real Estate Investment Trusts
 
 
 5,526 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 5,526 
 
 2.6 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 10,270 
 
 
 - 
 
 
 - 
 
 
 10,270 
 
 4.7 
%
 
Subtotal - Equities
 
 
 103,678 
 
 
 10,270 
 
 
 - 
 
 
 - 
 
 
 113,948 
 
 52.5 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 14,843 
 
 
 - 
 
 
 - 
 
 
 14,843 
 
 6.9 
%
 
 
Corporate Debt
 
 
 - 
 
 
 52,968 
 
 
 - 
 
 
 - 
 
 
 52,968 
 
 24.4 
%
 
 
Foreign Debt
 
 
 - 
 
 
 10,896 
 
 
 - 
 
 
 - 
 
 
 10,896 
 
 5.0 
%
 
 
State and Local Government
 
 
 - 
 
 
 2,194 
 
 
 - 
 
 
 - 
 
 
 2,194 
 
 1.0 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 1,747 
 
 
 - 
 
 
 - 
 
 
 1,747 
 
 0.8 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 82,648 
 
 
 - 
 
 
 - 
 
 
 82,648 
 
 38.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 5,770 
 
 
 - 
 
 
 5,770 
 
 2.7 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 6,737 
 
 
 - 
 
 
 6,737 
 
 3.1 
%
 
Securities Lending
 
 
 - 
 
 
 11,052 
 
 
 - 
 
 
 - 
 
 
 11,052 
 
 5.1 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (12,485)
 
 
 (12,485)
 
 (5.8)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (b)
 
 
 - 
 
 
 7,371 
 
 
 - 
 
 
 257 
 
 
 7,628 
 
 3.5 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (c)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,668 
 
 
 1,668 
 
 0.8 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 103,678 
 
$
 111,341 
 
$
 12,507 
 
$
 (10,560)
 
$
 216,966 
 
 100.0 
%

 
315
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 76,200 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 76,200 
 
 35.8 
%
 
 
International
 
 
 19,988 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 19,988 
 
 9.4 
%
 
 
Real Estate Investment Trusts
 
 
 5,415 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 5,415 
 
 2.6 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International
 
 
 - 
 
 
 10,065 
 
 
 - 
 
 
 - 
 
 
 10,065 
 
 4.7 
%
 
Subtotal - Equities
 
 
 101,603 
 
 
 10,065 
 
 
 - 
 
 
 - 
 
 
 111,668 
 
 52.5 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 14,547 
 
 
 - 
 
 
 - 
 
 
 14,547 
 
 6.9 
%
 
 
Corporate Debt
 
 
 - 
 
 
 51,909 
 
 
 - 
 
 
 - 
 
 
 51,909 
 
 24.4 
%
 
 
Foreign Debt
 
 
 - 
 
 
 10,678 
 
 
 - 
 
 
 - 
 
 
 10,678 
 
 5.0 
%
 
 
State and Local Government
 
 
 - 
 
 
 2,150 
 
 
 - 
 
 
 - 
 
 
 2,150 
 
 1.0 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 1,712 
 
 
 - 
 
 
 - 
 
 
 1,712 
 
 0.8 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 80,996 
 
 
 - 
 
 
 - 
 
 
 80,996 
 
 38.1 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real Estate
 
 
 - 
 
 
 - 
 
 
 5,654 
 
 
 - 
 
 
 5,654 
 
 2.7 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alternative Investments
 
 
 - 
 
 
 - 
 
 
 6,602 
 
 
 - 
 
 
 6,602 
 
 3.1 
%
 
Securities Lending
 
 
 - 
 
 
 10,831 
 
 
 - 
 
 
 - 
 
 
 10,831 
 
 5.1 
%
 
Securities Lending Collateral (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (12,235)
 
 
 (12,235)
 
 (5.8)
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (b)
 
 
 - 
 
 
 7,224 
 
 
 - 
 
 
 252 
 
 
 7,476 
 
 3.5 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (c)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,634 
 
 
 1,634 
 
 0.8 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 101,603 
 
$
 109,116 
 
$
 12,256 
 
$
 (10,349)
 
$
 212,626 
 
 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 foreign currency holdings.
 
(c)
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 real estate and alternative investments classified as Level 3 in the fair value hierarchy for pension assets by Registrant Subsidiary:

 
 
 
 
 
 
Alternative
 
Total
 
APCo
 
Real Estate
 
Investments
 
Level 3
 
 
 
 
(in thousands)
 
Balance as of January 1, 2009
 
$
 19,157 
 
$
 14,853 
 
$
 34,010 
 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 (6,534)
 
 
 (1,933)
 
 
 (8,467)
 
 
Relating to Assets Sold During the Period
 
 
 - 
 
 
 58 
 
 
 58 
 
Purchases and Sales
 
 
 - 
 
 
 1,761 
 
 
 1,761 
 
Transfers in and/or out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
Balance as of December 31, 2009
 
$
 12,623 
 
$
 14,739 
 
$
 27,362 

 
316
 
 
 
 
 
 
 
Alternative
 
Total
 
CSPCo
 
Real Estate
 
Investments
 
Level 3
 
 
 
 
(in thousands)
 
Balance as of January 1, 2009
 
$
 11,642 
 
$
 9,026 
 
$
 20,668 
 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 (3,971)
 
 
 (1,175)
 
 
 (5,146)
 
 
Relating to Assets Sold During the Period
 
 
 - 
 
 
 35 
 
 
 35 
 
Purchases and Sales
 
 
 - 
 
 
 1,071 
 
 
 1,071 
 
Transfers in and/or out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
Balance as of December 31, 2009
 
$
 7,671 
 
$
 8,957 
 
$
 16,628 

 
 
 
 
 
 
Alternative
 
Total
 
I&M
 
Real Estate
 
Investments
 
Level 3
 
 
 
 
(in thousands)
 
Balance as of January 1, 2009
 
$
 15,319 
 
$
 11,877 
 
$
 27,196 
 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 (5,225)
 
 
 (1,546)
 
 
 (6,771)
 
 
Relating to Assets Sold During the Period
 
 
 - 
 
 
 46 
 
 
 46 
 
Purchases and Sales
 
 
 - 
 
 
 1,409 
 
 
 1,409 
 
Transfers in and/or out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
Balance as of December 31, 2009
 
$
 10,094 
 
$
 11,786 
 
$
 21,880 

 
 
 
 
 
 
Alternative
 
Total
 
OPCo
 
Real Estate
 
Investments
 
Level 3
 
 
 
 
(in thousands)
 
Balance as of January 1, 2009
 
$
 18,900 
 
$
 14,653 
 
$
 33,553 
 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 (6,446)
 
 
 (1,907)
 
 
 (8,353)
 
 
Relating to Assets Sold During the Period
 
 
 - 
 
 
 57 
 
 
 57 
 
Purchases and Sales
 
 
 - 
 
 
 1,738 
 
 
 1,738 
 
Transfers in and/or out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
Balance as of December 31, 2009
 
$
 12,454 
 
$
 14,541 
 
$
 26,995 

 
 
 
 
 
 
Alternative
 
Total
 
PSO
 
Real Estate
 
Investments
 
Level 3
 
 
 
 
(in thousands)
 
Balance as of January 1, 2009
 
$
 8,757 
 
$
 6,790 
 
$
 15,547 
 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 (2,987)
 
 
 (884)
 
 
 (3,871)
 
 
Relating to Assets Sold During the Period
 
 
 - 
 
 
 26 
 
 
 26 
 
Purchases and Sales
 
 
 - 
 
 
 805 
 
 
 805 
 
Transfers in and/or out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
Balance as of December 31, 2009
 
$
 5,770 
 
$
 6,737 
 
$
 12,507 

 
 
 
 
 
 
Alternative
 
Total
 
SWEPCo
 
Real Estate
 
Investments
 
Level 3
 
 
 
 
(in thousands)
 
Balance as of January 1, 2009
 
$
 8,581 
 
$
 6,653 
 
$
 15,234 
 
Actual Return on Plan Assets
 
 
 
 
 
 
 
 
 
 
 
Relating to Assets Still Held as of the Reporting Date
 
 
 (2,927)
 
 
 (866)
 
 
 (3,793)
 
 
Relating to Assets Sold During the Period
 
 
 - 
 
 
 26 
 
 
 26 
 
Purchases and Sales
 
 
 - 
 
 
 789 
 
 
 789 
 
Transfers in and/or out of Level 3
 
 
 - 
 
 
 - 
 
 
 - 
 
Balance as of December 31, 2009
 
$
 5,654 
 
$
 6,602 
 
$
 12,256 

 
317
 
The following tables present the classification of OPEB plan assets within the fair value hierarchy by Registrant Subsidiary at December 31, 2009:

 
APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 57,049 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 57,049 
 
 26.2 
%
 
 
International
 
 
 62,241 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 62,241 
 
 28.7 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Global
 
 
 - 
 
 
 15,468 
 
 
 - 
 
 
 - 
 
 
 15,468 
 
 7.1 
%
 
Subtotal - Equities
 
 
 119,290 
 
 
 15,468 
 
 
 - 
 
 
 - 
 
 
 134,758 
 
 62.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 6,302 
 
 
 - 
 
 
 - 
 
 
 6,302 
 
 2.9 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 6,955 
 
 
 - 
 
 
 - 
 
 
 6,955 
 
 3.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 23,498 
 
 
 - 
 
 
 - 
 
 
 23,498 
 
 10.8 
%
 
 
Foreign Debt
 
 
 - 
 
 
 5,334 
 
 
 - 
 
 
 - 
 
 
 5,334 
 
 2.4 
%
 
 
State and Local Government
 
 
 - 
 
 
 996 
 
 
 - 
 
 
 - 
 
 
 996 
 
 0.5 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 232 
 
 
 - 
 
 
 - 
 
 
 232 
 
 0.2 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 43,317 
 
 
 - 
 
 
 - 
 
 
 43,317 
 
 20.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 12,369 
 
 
 - 
 
 
 - 
 
 
 12,369 
 
 5.7 
%
 
 
United States Bonds
 
 
 - 
 
 
 21,759 
 
 
 - 
 
 
 - 
 
 
 21,759 
 
 10.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
 
 1,092 
 
 
 2,389 
 
 
 - 
 
 
 165 
 
 
 3,646 
 
 1.7 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,311 
 
 
 1,311 
 
 0.6 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 120,382 
 
$
 95,302 
 
$
 - 
 
$
 1,476 
 
$
 217,160 
 
 100.0 
%

 
318
 
 
CSPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 25,942 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 25,942 
 
 26.2 
%
 
 
International
 
 
 28,304 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 28,304 
 
 28.7 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Global
 
 
 - 
 
 
 7,034 
 
 
 - 
 
 
 - 
 
 
 7,034 
 
 7.1 
%
 
Subtotal - Equities
 
 
 54,246 
 
 
 7,034 
 
 
 - 
 
 
 - 
 
 
 61,280 
 
 62.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 2,866 
 
 
 - 
 
 
 - 
 
 
 2,866 
 
 2.9 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 3,163 
 
 
 - 
 
 
 - 
 
 
 3,163 
 
 3.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 10,686 
 
 
 - 
 
 
 - 
 
 
 10,686 
 
 10.8 
%
 
 
Foreign Debt
 
 
 - 
 
 
 2,426 
 
 
 - 
 
 
 - 
 
 
 2,426 
 
 2.4 
%
 
 
State and Local Government
 
 
 - 
 
 
 453 
 
 
 - 
 
 
 - 
 
 
 453 
 
 0.5 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 106 
 
 
 - 
 
 
 - 
 
 
 106 
 
 0.2 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 19,700 
 
 
 - 
 
 
 - 
 
 
 19,700 
 
 20.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 5,625 
 
 
 - 
 
 
 - 
 
 
 5,625 
 
 5.7 
%
 
 
United States Bonds
 
 
 - 
 
 
 9,895 
 
 
 - 
 
 
 - 
 
 
 9,895 
 
 10.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
 
 497 
 
 
 1,086 
 
 
 - 
 
 
 75 
 
 
 1,658 
 
 1.7 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 596 
 
 
 596 
 
 0.6 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 54,743 
 
$
 43,340 
 
$
 - 
 
$
 671 
 
$
 98,754 
 
 100.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
319
 
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 43,790 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 43,790 
 
 26.2 
%
 
 
International
 
 
 47,773 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 47,773 
 
 28.7 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Global
 
 
 - 
 
 
 11,873 
 
 
 - 
 
 
 - 
 
 
 11,873 
 
 7.1 
%
 
Subtotal - Equities
 
 
 91,563 
 
 
 11,873 
 
 
 - 
 
 
 - 
 
 
 103,436 
 
 62.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 4,837 
 
 
 - 
 
 
 - 
 
 
 4,837 
 
 2.9 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 5,338 
 
 
 - 
 
 
 - 
 
 
 5,338 
 
 3.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 18,036 
 
 
 - 
 
 
 - 
 
 
 18,036 
 
 10.8 
%
 
 
Foreign Debt
 
 
 - 
 
 
 4,094 
 
 
 - 
 
 
 - 
 
 
 4,094 
 
 2.4 
%
 
 
State and Local Government
 
 
 - 
 
 
 764 
 
 
 - 
 
 
 - 
 
 
 764 
 
 0.5 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 178 
 
 
 - 
 
 
 - 
 
 
 178 
 
 0.2 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 33,247 
 
 
 - 
 
 
 - 
 
 
 33,247 
 
 20.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 9,494 
 
 
 - 
 
 
 - 
 
 
 9,494 
 
 5.7 
%
 
 
United States Bonds
 
 
 - 
 
 
 16,701 
 
 
 - 
 
 
 - 
 
 
 16,701 
 
 10.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
 
 838 
 
 
 1,834 
 
 
 - 
 
 
 126 
 
 
 2,798 
 
 1.7 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,006 
 
 
 1,006 
 
 0.6 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 92,401 
 
$
 73,149 
 
$
 - 
 
$
 1,132 
 
$
 166,682 
 
 100.0 
%

 
320
 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 52,752 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 52,752 
 
 26.2 
%
 
 
International
 
 
 57,551 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 57,551 
 
 28.7 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Global
 
 
 - 
 
 
 14,302 
 
 
 - 
 
 
 - 
 
 
 14,302 
 
 7.1 
%
 
Subtotal - Equities
 
 
 110,303 
 
 
 14,302 
 
 
 - 
 
 
 - 
 
 
 124,605 
 
 62.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 5,827 
 
 
 - 
 
 
 - 
 
 
 5,827 
 
 2.9 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 6,431 
 
 
 - 
 
 
 - 
 
 
 6,431 
 
 3.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 21,727 
 
 
 - 
 
 
 - 
 
 
 21,727 
 
 10.8 
%
 
 
Foreign Debt
 
 
 - 
 
 
 4,932 
 
 
 - 
 
 
 - 
 
 
 4,932 
 
 2.4 
%
 
 
State and Local Government
 
 
 - 
 
 
 921 
 
 
 - 
 
 
 - 
 
 
 921 
 
 0.5 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 215 
 
 
 - 
 
 
 - 
 
 
 215 
 
 0.2 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 40,053 
 
 
 - 
 
 
 - 
 
 
 40,053 
 
 20.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 11,437 
 
 
 - 
 
 
 - 
 
 
 11,437 
 
 5.7 
%
 
 
United States Bonds
 
 
 - 
 
 
 20,119 
 
 
 - 
 
 
 - 
 
 
 20,119 
 
 10.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
 
 1,010 
 
 
 2,209 
 
 
 - 
 
 
 152 
 
 
 3,371 
 
 1.7 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,212 
 
 
 1,212 
 
 0.6 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 111,313 
 
$
 88,120 
 
$
 - 
 
$
 1,364 
 
$
 200,797 
 
 100.0 
%

 
321
 
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 19,887 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 19,887 
 
 26.2 
%
 
 
International
 
 
 21,697 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 21,697 
 
 28.7 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Global
 
 
 - 
 
 
 5,392 
 
 
 - 
 
 
 - 
 
 
 5,392 
 
 7.1 
%
 
Subtotal - Equities
 
 
 41,584 
 
 
 5,392 
 
 
 - 
 
 
 - 
 
 
 46,976 
 
 62.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 2,197 
 
 
 - 
 
 
 - 
 
 
 2,197 
 
 2.9 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 2,424 
 
 
 - 
 
 
 - 
 
 
 2,424 
 
 3.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 8,191 
 
 
 - 
 
 
 - 
 
 
 8,191 
 
 10.8 
%
 
 
Foreign Debt
 
 
 - 
 
 
 1,859 
 
 
 - 
 
 
 - 
 
 
 1,859 
 
 2.4 
%
 
 
State and Local Government
 
 
 - 
 
 
 347 
 
 
 - 
 
 
 - 
 
 
 347 
 
 0.5 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 81 
 
 
 - 
 
 
 - 
 
 
 81 
 
 0.2 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 15,099 
 
 
 - 
 
 
 - 
 
 
 15,099 
 
 20.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 4,312 
 
 
 - 
 
 
 - 
 
 
 4,312 
 
 5.7 
%
 
 
United States Bonds
 
 
 - 
 
 
 7,585 
 
 
 - 
 
 
 - 
 
 
 7,585 
 
 10.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
 
 381 
 
 
 833 
 
 
 - 
 
 
 57 
 
 
 1,271 
 
 1.7 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 457 
 
 
 457 
 
 0.6 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 41,965 
 
$
 33,221 
 
$
 - 
 
$
 514 
 
$
 75,700 
 
 100.0 
%

 
322
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year End
 
Asset Class
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
 
Allocation
 
 
 
(in thousands)
 
Equities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Domestic
 
$
 21,790 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 21,790 
 
 26.2 
%
 
 
International
 
 
 23,772 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 23,772 
 
 28.7 
%
 
 
Common Collective Trust -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Global
 
 
 - 
 
 
 5,908 
 
 
 - 
 
 
 - 
 
 
 5,908 
 
 7.1 
%
 
Subtotal - Equities
 
 
 45,562 
 
 
 5,908 
 
 
 - 
 
 
 - 
 
 
 51,470 
 
 62.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fixed Income:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Collective Trust - Debt
 
 
 - 
 
 
 2,407 
 
 
 - 
 
 
 - 
 
 
 2,407 
 
 2.9 
%
 
 
United States Government and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Agency Securities
 
 
 - 
 
 
 2,656 
 
 
 - 
 
 
 - 
 
 
 2,656 
 
 3.2 
%
 
 
Corporate Debt
 
 
 - 
 
 
 8,974 
 
 
 - 
 
 
 - 
 
 
 8,974 
 
 10.8 
%
 
 
Foreign Debt
 
 
 - 
 
 
 2,037 
 
 
 - 
 
 
 - 
 
 
 2,037 
 
 2.4 
%
 
 
State and Local Government
 
 
 - 
 
 
 380 
 
 
 - 
 
 
 - 
 
 
 380 
 
 0.5 
%
 
 
Other - Asset Backed
 
 
 - 
 
 
 89 
 
 
 - 
 
 
 - 
 
 
 89 
 
 0.2 
%
 
Subtotal - Fixed Income
 
 
 - 
 
 
 16,543 
 
 
 - 
 
 
 - 
 
 
 16,543 
 
 20.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Trust Owned Life Insurance:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
International Equities
 
 
 - 
 
 
 4,724 
 
 
 - 
 
 
 - 
 
 
 4,724 
 
 5.7 
%
 
 
United States Bonds
 
 
 - 
 
 
 8,310 
 
 
 - 
 
 
 - 
 
 
 8,310 
 
 10.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (a)
 
 
 417 
 
 
 912 
 
 
 - 
 
 
 63 
 
 
 1,392 
 
 1.7 
%
 
Other - Pending Transactions and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrued Income (b)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 501 
 
 
 501 
 
 0.6 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total
 
$
 45,979 
 
$
 36,397 
 
$
 - 
 
$
 564 
 
$
 82,940 
 
 100.0 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Amounts in "Other" column primarily represent foreign currency holdings.
 
(b)
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 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.

Accumulated Benefit Obligation
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Qualified Pension Plan
 
$
 646,513 
 
$
 350,150 
 
$
 551,702 
 
$
 623,652 
 
$
 261,535 
 
$
 260,838 
Nonqualified Pension Plans
 
 
 221 
 
 
 6 
 
 
 994 
 
 
 793 
 
 
 1,326 
 
 
 1,133 
Total as of December 31, 2010
 
$
 646,734 
 
$
 350,156 
 
$
 552,696 
 
$
 624,445 
 
$
 262,861 
 
$
 261,971 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated Benefit Obligation
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Qualified Pension Plan
 
$
 626,533 
 
$
 362,037 
 
$
 515,338 
 
$
 611,120 
 
$
 281,452 
 
$
 284,143 
Nonqualified Pension Plans
 
 
 259 
 
 
 1 
 
 
 803 
 
 
 833 
 
 
 1,176 
 
 
 1,081 
Total as of December 31, 2009
 
$
 626,792 
 
$
 362,038 
 
$
 516,141 
 
$
 611,953 
 
$
 282,628 
 
$
 285,224 

 
323
 
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 at December 31, 2010 and 2009 were as follows:

 
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Projected Benefit Obligation
$
 652,219 
 
$
 354,153 
 
$
 560,982 
 
$
 629,936 
 
$
 268,180 
 
$
 267,206 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated Benefit Obligation
 
$
 646,734 
 
$
 350,156 
 
$
 552,696 
 
$
 624,445 
 
$
 262,861 
 
$
 261,971 
Fair Value of Plan Assets
 
 
 512,836 
 
 
 280,593 
 
 
 451,688 
 
 
 518,688 
 
 
 213,576 
 
 
 224,618 
Underfunded Accumulated Benefit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Obligation as of December 31, 2010
 
$
 (133,898)
 
$
 (69,563)
 
$
 (101,008)
 
$
 (105,757)
 
$
 (49,285)
 
$
 (37,353)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Projected Benefit Obligation
$
 632,832 
 
$
 364,891 
 
$
 526,363 
 
$
 616,590 
 
$
 285,592 
 
$
 288,081 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Accumulated Benefit Obligation
 
$
 626,792 
 
$
 362,038 
 
$
 516,141 
 
$
 611,953 
 
$
 282,628 
 
$
 285,224 
Fair Value of Plan Assets
 
 
 474,657 
 
 
 288,468 
 
 
 379,562 
 
 
 468,300 
 
 
 216,966 
 
 
 212,626 
Underfunded Accumulated Benefit
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Obligation as of December 31, 2009
 
$
 (152,135)
 
$
 (73,570)
 
$
 (136,579)
 
$
 (143,653)
 
$
 (65,662)
 
$
 (72,598)

Estimated Future Benefit Payments and Contributions

The estimated pension benefit payments for the unfunded plan and contributions to the trust are at least the minimum amount required by ERISA plus payment of unfunded nonqualified benefits.  For the qualified pension plan, additional discretionary contributions may be made to the trust to maintain the funded status of the plan.  The contributions to the OPEB plans are generally based on the amount of the OPEB plans’ periodic benefit costs for accounting purposes as provided in agreements with state regulatory authorities, plus the additional discretionary contribution of the Medicare subsidy receipts.  The following table provides the estimated contributions and payments by Registrant Subsidiary for 2011:

 
 
 
 
Other Postretirement
Company
 
Pension Plans
 
Benefit Plans
 
 
(in thousands)
APCo
 
$
 14,735 
 
$
 15,032 
CSPCo
 
 
 4,958 
 
 
 5,544 
I&M
 
 
 21,087 
 
 
 11,756 
OPCo
 
 
 12,578 
 
 
 11,184 
PSO
 
 
 5,376 
 
 
 5,196 
SWEPCo
 
 
 7,287 
 
 
 5,539 

 
324
 
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.  Medicare subsidy receipts are shown in the year of the corresponding benefit payments, even though actual cash receipts are expected early in the following year.  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
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
2011 
 
$
 43,369 
 
$
 27,274 
 
$
 33,768 
 
$
 43,315 
 
$
 19,313 
 
$
 19,103 
2012 
 
 
 43,847 
 
 
 27,316 
 
 
 34,466 
 
 
 43,244 
 
 
 20,198 
 
 
 19,550 
2013 
 
 
 44,073 
 
 
 27,164 
 
 
 35,638 
 
 
 43,140 
 
 
 20,601 
 
 
 20,207 
2014 
 
 
 45,098 
 
 
 27,572 
 
 
 35,763 
 
 
 44,263 
 
 
 21,167 
 
 
 20,871 
2015 
 
 
 45,333 
 
 
 27,496 
 
 
 37,269 
 
 
 44,398 
 
 
 21,585 
 
 
 22,063 
Years 2016 to 2020, in Total
 
 
 241,638 
 
 
 136,426 
 
 
 206,098 
 
 
 233,038 
 
 
 111,796 
 
 
 114,363 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement Benefit Plans:  Benefit Payments
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
2011 
 
$
 27,094 
 
$
 12,259 
 
$
 17,682 
 
$
 23,622 
 
$
 8,136 
 
$
 8,321 
2012 
 
 
 27,634 
 
 
 12,674 
 
 
 18,514 
 
 
 24,116 
 
 
 8,532 
 
 
 8,781 
2013 
 
 
 28,353 
 
 
 13,095 
 
 
 19,297 
 
 
 24,493 
 
 
 9,016 
 
 
 9,274 
2014 
 
 
 29,439 
 
 
 13,548 
 
 
 20,216 
 
 
 25,110 
 
 
 9,295 
 
 
 9,838 
2015 
 
 
 30,306 
 
 
 13,751 
 
 
 21,129 
 
 
 26,036 
 
 
 9,774 
 
 
 10,300 
Years 2016 to 2020, in Total
 
 
 164,970 
 
 
 72,606 
 
 
 120,771 
 
 
 143,818 
 
 
 55,120 
 
 
 59,052 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement Benefit Plans:  Medicare Subsidy Receipts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
2011 
 
$
 (2,086)
 
$
 (836)
 
$
 (1,322)
 
$
 (1,862)
 
$
 (754)
 
$
 (704)
2012 
 
 
 (2,312)
 
 
 (948)
 
 
 (1,455)
 
 
 (2,077)
 
 
 (807)
 
 
 (769)
2013 
 
 
 (2,508)
 
 
 (1,057)
 
 
 (1,592)
 
 
 (2,273)
 
 
 (863)
 
 
 (830)
2014 
 
 
 (2,684)
 
 
 (1,163)
 
 
 (1,719)
 
 
 (2,454)
 
 
 (924)
 
 
 (889)
2015 
 
 
 (2,865)
 
 
 (1,284)
 
 
 (1,846)
 
 
 (2,616)
 
 
 (973)
 
 
 (956)
Years 2016 to 2020, in Total
 
 
 (17,053)
 
 
 (8,000)
 
 
 (11,283)
 
 
 (15,409)
 
 
 (5,661)
 
 
 (5,791)

Components of Net Periodic Benefit Cost (Credit)

The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the years ended December 31, 2010, 2009 and 2008:

 
 
 
 
 
 
Other Postretirement
 
APCo
 
Pension Plans
 
Benefit Plans
 
 
 
 
Years Ended December 31,
 
 
 
 
2010 
 
2009 
 
2008 
 
2010 
 
2009 
 
2008 
 
 
 
 
(in thousands)
 
Service Cost
 
$
 12,908 
 
$
 12,689 
 
$
 12,407 
 
$
 5,722 
 
$
 5,142 
 
$
 5,228 
 
Interest Cost
 
 
 33,956 
 
 
 34,050 
 
 
 33,852 
 
 
 20,300 
 
 
 19,710 
 
 
 20,578 
 
Expected Return on Plan Assets
 
 
 (43,805)
 
 
 (44,885)
 
 
 (46,855)
 
 
 (17,628)
 
 
 (13,531)
 
 
 (18,793)
 
Amortization of Transition Obligation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 5,244 
 
 
 5,244 
 
 
 5,244 
 
Amortization of Prior Service Cost
 
 
 917 
 
 
 917 
 
 
 917 
 
 
 - 
 
 
 - 
 
 
 - 
 
Amortization of Net Actuarial Loss
 
 
 11,842 
 
 
 7,688 
 
 
 3,016 
 
 
 5,410 
 
 
 7,666 
 
 
 2,639 
 
Net Periodic Benefit Cost
 
 
 15,818 
 
 
 10,459 
 
 
 3,337 
 
 
 19,048 
 
 
 24,231 
 
 
 14,896 
 
Capitalized Portion
 
 
 (6,058)
 
 
 (3,661)
 
 
 (1,258)
 
 
 (7,295)
 
 
 (8,481)
 
 
 (5,616)
 
Net Periodic Benefit Cost Recognized as
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
$
 9,760 
 
$
 6,798 
 
$
 2,079 
 
$
 11,753 
 
$
 15,750 
 
$
 9,280 

 
325
 
 
 
 
 
 
 
Other Postretirement
 
CSPCo
 
Pension Plans
 
Benefit Plans
 
 
 
 
Years Ended December 31,
 
 
 
 
2010 
 
2009 
 
2008 
 
2010 
 
2009 
 
2008 
 
 
 
 
(in thousands)
 
Service Cost
 
$
 5,873 
 
$
 5,504 
 
$
 5,367 
 
$
 2,761 
 
$
 2,470 
 
$
 2,435 
 
Interest Cost
 
 
 19,156 
 
 
 19,529 
 
 
 19,804 
 
 
 8,713 
 
 
 8,493 
 
 
 9,327 
 
Expected Return on Plan Assets
 
 
 (26,357)
 
 
 (27,277)
 
 
 (28,905)
 
 
 (7,916)
 
 
 (6,126)
 
 
 (9,080)
 
Amortization of Transition Obligation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 2,431 
 
 
 2,432 
 
 
 2,431 
 
Amortization of Prior Service Cost
 
 
 565 
 
 
 565 
 
 
 565 
 
 
 - 
 
 
 - 
 
 
 - 
 
Amortization of Net Actuarial Loss
 
 
 6,708 
 
 
 4,431 
 
 
 1,771 
 
 
 2,261 
 
 
 3,285 
 
 
 928 
 
Net Periodic Benefit Cost (Credit)
 
 
 5,945 
 
 
 2,752 
 
 
 (1,398)
 
 
 8,250 
 
 
 10,554 
 
 
 6,041 
 
Capitalized Portion
 
 
 (1,891)
 
 
 (900)
 
 
 509 
 
 
 (2,624)
 
 
 (3,451)
 
 
 (2,199)
 
Net Periodic Benefit Cost (Credit)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Recognized as Expense
 
$
 4,054 
 
$
 1,852 
 
$
 (889)
 
$
 5,626 
 
$
 7,103 
 
$
 3,842 

 
 
 
 
 
 
Other Postretirement
 
I&M
 
Pension Plans
 
Benefit Plans
 
 
 
 
Years Ended December 31,
 
 
 
 
2010 
 
2009 
 
2008 
 
2010 
 
2009 
 
2008 
 
 
 
 
(in thousands)
 
Service Cost
 
$
 15,284 
 
$
 14,002 
 
$
 13,573 
 
$
 6,750 
 
$
 5,990 
 
$
 5,944 
 
Interest Cost
 
 
 29,085 
 
 
 28,520 
 
 
 27,959 
 
 
 14,164 
 
 
 13,675 
 
 
 14,006 
 
Expected Return on Plan Assets
 
 
 (35,040)
 
 
 (35,733)
 
 
 (37,466)
 
 
 (13,397)
 
 
 (10,259)
 
 
 (14,067)
 
Amortization of Transition Obligation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 2,814 
 
 
 2,814 
 
 
 2,814 
 
Amortization of Prior Service Cost
 
 
 744 
 
 
 744 
 
 
 745 
 
 
 - 
 
 
 - 
 
 
 - 
 
Amortization of Net Actuarial Loss
 
 
 10,065 
 
 
 6,406 
 
 
 2,472 
 
 
 3,526 
 
 
 5,213 
 
 
 1,068 
 
Net Periodic Benefit Cost
 
 
 20,138 
 
 
 13,939 
 
 
 7,283 
 
 
 13,857 
 
 
 17,433 
 
 
 9,765 
 
Capitalized Portion
 
 
 (4,028)
 
 
 (2,732)
 
 
 (1,646)
 
 
 (2,771)
 
 
 (3,417)
 
 
 (2,207)
 
Net Periodic Benefit Cost Recognized as
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
$
 16,110 
 
$
 11,207 
 
$
 5,637 
 
$
 11,086 
 
$
 14,016 
 
$
 7,558 

 
 
 
 
 
 
Other Postretirement
 
OPCo
 
Pension Plans
 
Benefit Plans
 
 
 
 
Years Ended December 31,
 
 
 
 
2010 
 
2009 
 
2008 
 
2010 
 
2009 
 
2008 
 
 
 
 
(in thousands)
 
Service Cost
 
$
 11,381 
 
$
 11,034 
 
$
 10,715 
 
$
 5,426 
 
$
 4,877 
 
$
 4,893 
 
Interest Cost
 
 
 32,744 
 
 
 33,100 
 
 
 33,065 
 
 
 17,785 
 
 
 17,325 
 
 
 17,977 
 
Expected Return on Plan Assets
 
 
 (42,720)
 
 
 (44,277)
 
 
 (46,365)
 
 
 (16,176)
 
 
 (12,559)
 
 
 (17,493)
 
Amortization of Transition Obligation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 4,211 
 
 
 4,211 
 
 
 4,211 
 
Amortization of Prior Service Cost
 
 
 909 
 
 
 910 
 
 
 913 
 
 
 - 
 
 
 - 
 
 
 - 
 
Amortization of Net Actuarial Loss
 
 
 11,442 
 
 
 7,500 
 
 
 2,949 
 
 
 4,616 
 
 
 6,703 
 
 
 1,769 
 
Net Periodic Benefit Cost
 
 
 13,756 
 
 
 8,267 
 
 
 1,277 
 
 
 15,862 
 
 
 20,557 
 
 
 11,357 
 
Capitalized Portion
 
 
 (4,952)
 
 
 (3,001)
 
 
 (476)
 
 
 (5,710)
 
 
 (7,462)
 
 
 (4,236)
 
Net Periodic Benefit Cost Recognized as
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
$
 8,804 
 
$
 5,266 
 
$
 801 
 
$
 10,152 
 
$
 13,095 
 
$
 7,121 

 
326
 
 
 
 
 
 
 
Other Postretirement
 
PSO
 
Pension Plans
 
Benefit Plans
 
 
 
 
Years Ended December 31,
 
 
 
 
2010 
 
2009 
 
2008 
 
2010 
 
2009 
 
2008 
 
 
 
 
(in thousands)
 
Service Cost
 
$
 6,052 
 
$
 5,744 
 
$
 5,340 
 
$
 2,815 
 
$
 2,522 
 
$
 2,489 
 
Interest Cost
 
 
 14,888 
 
 
 15,369 
 
 
 15,087 
 
 
 6,360 
 
 
 6,154 
 
 
 6,137 
 
Expected Return on Plan Assets
 
 
 (19,739)
 
 
 (20,438)
 
 
 (21,546)
 
 
 (6,110)
 
 
 (4,695)
 
 
 (6,271)
 
Amortization of Transition Obligation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 2,805 
 
 
 2,805 
 
 
 2,805 
 
Amortization of Prior Service Credit
 
 
 (950)
 
 
 (1,082)
 
 
 (1,081)
 
 
 - 
 
 
 - 
 
 
 - 
 
Amortization of Net Actuarial Loss
 
 
 5,188 
 
 
 3,487 
 
 
 4,233 
 
 
 1,573 
 
 
 2,348 
 
 
 421 
 
Net Periodic Benefit Cost
 
 
 5,439 
 
 
 3,080 
 
 
 2,033 
 
 
 7,443 
 
 
 9,134 
 
 
 5,581 
 
Capitalized Portion
 
 
 (1,806)
 
 
 (1,087)
 
 
 (777)
 
 
 (2,471)
 
 
 (3,224)
 
 
 (2,132)
 
Net Periodic Benefit Cost Recognized as
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
$
 3,633 
 
$
 1,993 
 
$
 1,256 
 
$
 4,972 
 
$
 5,910 
 
$
 3,449 

 
 
 
 
 
 
Other Postretirement
 
SWEPCo
 
Pension Plans
 
Benefit Plans
 
 
 
 
Years Ended December 31,
 
 
 
 
2010 
 
2009 
 
2008 
 
2010 
 
2009 
 
2008 
 
 
 
 
(in thousands)
 
Service Cost
 
$
 7,046 
 
$
 6,757 
 
$
 6,284 
 
$
 3,108 
 
$
 2,817 
 
$
 2,745 
 
Interest Cost
 
 
 15,093 
 
 
 15,557 
 
 
 14,961 
 
 
 6,940 
 
 
 6,735 
 
 
 6,694 
 
Expected Return on Plan Assets
 
 
 (19,489)
 
 
 (20,083)
 
 
 (20,751)
 
 
 (6,646)
 
 
 (5,120)
 
 
 (6,819)
 
Amortization of Transition Obligation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 2,461 
 
 
 2,461 
 
 
 2,461 
 
Amortization of Prior Service Credit
 
 
 (796)
 
 
 (916)
 
 
 (917)
 
 
 - 
 
 
 - 
 
 
 - 
 
Amortization of Net Actuarial Loss
 
 
 5,242 
 
 
 3,516 
 
 
 4,165 
 
 
 1,711 
 
 
 2,560 
 
 
 458 
 
Net Periodic Benefit Cost
 
 
 7,096 
 
 
 4,831 
 
 
 3,742 
 
 
 7,574 
 
 
 9,453 
 
 
 5,539 
 
Capitalized Portion
 
 
 (2,406)
 
 
 (1,546)
 
 
 (1,362)
 
 
 (2,568)
 
 
 (3,025)
 
 
 (2,016)
 
Net Periodic Benefit Cost Recognized as
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
$
 4,690 
 
$
 3,285 
 
$
 2,380 
 
$
 5,006 
 
$
 6,428 
 
$
 3,523 

 
327
 
Estimated amounts expected to be amortized to net periodic benefit costs and the impact on each Registrant Subsidiary’s balance sheet during 2011 are shown in the following tables:

 
 
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
Pension Plan - Components
 
(in thousands)
Net Actuarial Loss
 
$
 16,342 
 
$
 8,873 
 
$
 14,061 
 
$
 15,787 
 
$
 6,727 
 
$
 6,701 
Prior Service Cost (Credit)
 
 
 917 
 
 
 565 
 
 
 744 
 
 
 909 
 
 
 (950)
 
 
 (795)
Total Estimated 2011 Amortization
$
 17,259 
 
$
 9,438 
 
$
 14,805 
 
$
 16,696 
 
$
 5,777 
 
$
 5,906 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension Plans -
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expected to be Recorded as
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Asset
 
$
 17,168 
 
$
 6,470 
 
$
 13,917 
 
$
 7,614 
 
$
 5,777 
 
$
 5,906 
Deferred Income Taxes
 
 
 32 
 
 
 1,039 
 
 
 311 
 
 
 3,179 
 
 
 - 
 
 
 - 
Net of Tax AOCI
 
 
 59 
 
 
 1,929 
 
 
 577 
 
 
 5,903 
 
 
 - 
 
 
 - 
Total
$
 17,259 
 
$
 9,438 
 
$
 14,805 
 
$
 16,696 
 
$
 5,777 
 
$
 5,906 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
Other Postretirement Benefit Plans -
(in thousands)
 
Components
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Actuarial Loss
 
$
 6,423 
 
$
 2,700 
 
$
 4,085 
 
$
 5,560 
 
$
 1,766 
 
$
 1,960 
Prior Service Credit
 
 
 (171)
 
 
 (74)
 
 
 (236)
 
 
 (139)
 
 
 (75)
 
 
 (90)
Transition Obligation
 
 
 1,146 
 
 
 44 
 
 
 188 
 
 
 106 
 
 
 - 
 
 
 - 
Total Estimated 2011 Amortization
$
 7,398 
 
$
 2,670 
 
$
 4,037 
 
$
 5,527 
 
$
 1,691 
 
$
 1,870 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement Benefit Plans - Expected to be Recorded as
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory Asset
 
$
 2,419 
 
$
 1,523 
 
$
 3,419 
 
$
 2,190 
 
$
 1,691 
 
$
 1,215 
Deferred Income Taxes
 
 
 1,743 
 
 
 402 
 
 
 216 
 
 
 1,168 
 
 
 - 
 
 
 229 
Net of Tax AOCI
 
 
 3,236 
 
 
 745 
 
 
 402 
 
 
 2,169 
 
 
 - 
 
 
 426 
Total
$
 7,398 
 
$
 2,670 
 
$
 4,037 
 
$
 5,527 
 
$
 1,691 
 
$
 1,870 

American Electric Power System Retirement Savings Plans

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 were 75% of the first 6% of eligible compensation contributed by the employee in 2008.  Effective January 1, 2009, the match is 100% of the first 1% of eligible employee contributions and 70% of the next 5% of contributions.

The 2009 and 2008 contributions below for SWEPCo include a legacy savings plan of an acquired subsidiary.

The following table provides the cost for contributions to the retirement savings plans by Registrant Subsidiary for the years ended December 31, 2010, 2009 and 2008:

 
 
 
Years Ended December 31,
Company
 
2010 
 
2009 
 
2008 
 
 
 
(in thousands)
APCo
 
$
 7,284 
 
$
 8,673 
 
$
 8,226 
CSPCo
 
 
 3,267 
 
 
 4,008 
 
 
 3,678 
I&M
 
 
 8,969 
 
 
 10,315 
 
 
 9,501 
OPCo
 
 
 6,439 
 
 
 7,632 
 
 
 7,246 
PSO
 
 
 3,505 
 
 
 4,083 
 
 
 3,933 
SWEPCo
 
 
 3,866 
 
 
 5,269 
 
 
 4,943 

 
328
 
UMWA Benefits

APCo, CSPCo, I&M and OPCo 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, CSPCo, I&M and OPCo administer the health and welfare benefits and pay them from their general assets.  Contributions and benefits paid were not material in 2010, 2009 and 2008.

9.   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.

10.   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, 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

Trading Strategies

The strategy surrounding the use of derivative instruments for trading purposes focuses 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.

Risk Management Strategies

The strategy surrounding the use of derivative instruments focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies.  To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical forward purchase and sale contracts, financial forward purchase and sale contracts and financial swap instruments.  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 degree, heating oil and gasoline, emission allowance 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, 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.

 
329
 
The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of December 31, 2010 and 2009:

 
Notional Volume of Derivative Instruments
 
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Primary Risk
 
Unit of
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exposure
 
Measure
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
 
(in thousands)
Commodity:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Power
 
MWHs
 
 
 194,217 
 
 
 111,959 
 
 
 117,862 
 
 
 136,657 
 
 
 21 
 
 
 34 
 
Coal
 
Tons
 
 
 11,195 
 
 
 5,550 
 
 
 6,571 
 
 
 23,033 
 
 
 4,936 
 
 
 8,777 
 
Natural Gas
 
MMBtus
 
 
 2,166 
 
 
 1,248 
 
 
 1,302 
 
 
 1,524 
 
 
 15 
 
 
 19 
 
Heating Oil and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline
 
Gallons
 
 
 1,054 
 
 
 467 
 
 
 521 
 
 
 776 
 
 
 616 
 
 
 564 
 
Interest Rate
 
USD
 
$
 9,541 
 
$
 5,471 
 
$
 5,732 
 
$
 7,185 
 
$
 609 
 
$
 793 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Foreign Currency
 
USD
 
$
 200,000 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 200,000 
 
$
 189 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notional Volume of Derivative Instruments
 
December 31, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Primary Risk
 
Unit of
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exposure
 
Measure
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
 
(in thousands)
Commodity:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Power
 
MWHs
 
 
 191,121 
 
 
 96,828 
 
 
 99,265 
 
 
 112,745 
 
 
 10 
 
 
 12 
 
Coal
 
Tons
 
 
 11,347 
 
 
 5,615 
 
 
 5,150 
 
 
 23,631 
 
 
 5,936 
 
 
 6,790 
 
Natural Gas
 
MMBtus
 
 
 17,867 
 
 
 9,051 
 
 
 9,129 
 
 
 10,539 
 
 
 - 
 
 
 - 
 
Heating Oil and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gasoline
 
Gallons
 
 
 1,164 
 
 
 474 
 
 
 552 
 
 
 838 
 
 
 668 
 
 
 628 
 
Interest Rate
 
USD
 
$
 21,054 
 
$
 10,658 
 
$
 10,716 
 
$
 13,487 
 
$
 1,137 
 
$
 1,457 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Foreign Currency
 
USD
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 3,798 

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.

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 activity as “Commodity.” The Registrant Subsidiaries do not hedge all fuel price risk.

 
330
 
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 anticipated borrowings of fixed-rate debt.  The anticipated 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 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.

 
331
 
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, 2010 and 2009 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,
 
 
 
2010 
 
2009 
 
 
 
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
 
$
 1,809 
 
$
 16,229 
 
$
 3,789 
 
$
 31,806 
CSPCo
 
 
 1,042 
 
 
 9,347 
 
 
 1,920 
 
 
 16,108 
I&M
 
 
 1,087 
 
 
 9,757 
 
 
 1,936 
 
 
 16,222 
OPCo
 
 
 1,272 
 
 
 11,561 
 
 
 2,235 
 
 
 19,512 
PSO
 
 
 - 
 
 
 44 
 
 
 - 
 
 
 194 
SWEPCo
 
 
 - 
 
 
 72 
 
 
 - 
 
 
 305 
 
 
332
 
The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the Balance Sheets as of December 31, 2010 and 2009:

Fair Value of Derivative Instruments
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
267,702 
 
$
1,956 
 
$
11,888 
 
$
(228,304)
 
$
53,242 
Long-term Risk Management Assets
 
 
79,560 
 
 
714 
 
 
- 
 
 
(41,854)
 
 
38,420 
Total Assets
 
 
347,262 
 
 
2,670 
 
 
11,888 
 
 
(270,158)
 
 
91,662 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
262,027 
 
 
2,363 
 
 
- 
 
 
(236,397)
 
 
27,993 
Long-term Risk Management Liabilities
 
 
61,724 
 
 
701 
 
 
- 
 
 
(51,552)
 
 
10,873 
Total Liabilities
 
 
323,751 
 
 
3,064 
 
 
- 
 
 
(287,949)
 
 
38,866 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
23,511 
 
$
(394)
 
$
11,888 
 
$
17,791 
 
$
52,796 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
332,764 
 
$
3,621 
 
$
- 
 
$
(268,429)
 
$
67,956 
Long-term Risk Management Assets
 
 
132,044 
 
 
- 
 
 
- 
 
 
(84,903)
 
 
47,141 
Total Assets
 
 
464,808 
 
 
3,621 
 
 
- 
 
 
(353,332)
 
 
115,097 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
309,639 
 
 
5,084 
 
 
- 
 
 
(288,931)
 
 
25,792 
Long-term Risk Management Liabilities
 
 
118,702 
 
 
80 
 
 
- 
 
 
(98,418)
 
 
20,364 
Total Liabilities
 
 
428,341 
 
 
5,164 
 
 
- 
 
 
(387,349)
 
 
46,156 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
36,467 
 
$
(1,543)
 
$
- 
 
$
34,017 
 
$
68,941 

 
333
 
Fair Value of Derivative Instruments
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CSPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
149,886 
 
$
1,164 
 
$
- 
 
$
(127,276)
 
$
23,774 
Long-term Risk Management Assets
 
 
45,413 
 
 
412 
 
 
- 
 
 
(23,736)
 
 
22,089 
Total Assets
 
 
195,299 
 
 
1,576 
 
 
- 
 
 
(151,012)
 
 
45,863 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
146,540 
 
 
1,362 
 
 
- 
 
 
(131,935)
 
 
15,967 
Long-term Risk Management Liabilities
 
 
35,144 
 
 
404 
 
 
- 
 
 
(29,325)
 
 
6,223 
Total Liabilities
 
 
181,684 
 
 
1,766 
 
 
- 
 
 
(161,260)
 
 
22,190 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
13,615 
 
$
(190)
 
$
- 
 
$
10,248 
 
$
23,673 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CSPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
168,137 
 
$
1,805 
 
$
- 
 
$
(135,599)
 
$
34,343 
Long-term Risk Management Assets
 
 
66,816 
 
 
- 
 
 
- 
 
 
(42,934)
 
 
23,882 
Total Assets
 
 
234,953 
 
 
1,805 
 
 
- 
 
 
(178,533)
 
 
58,225 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
156,463 
 
 
2,574 
 
 
- 
 
 
(145,985)
 
 
13,052 
Long-term Risk Management Liabilities
 
 
60,048 
 
 
41 
 
 
- 
 
 
(49,776)
 
 
10,313 
Total Liabilities
 
 
216,511 
 
 
2,615 
 
 
- 
 
 
(195,761)
 
 
23,365 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
18,442 
 
$
(810)
 
$
- 
 
$
17,228 
 
$
34,860 

 
334
 
Fair Value of Derivative Instruments
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
162,896 
 
$
1,151 
 
$
- 
 
$
(136,521)
 
$
27,526 
Long-term Risk Management Assets
 
 
56,154 
 
 
429 
 
 
- 
 
 
(25,098)
 
 
31,485 
Total Assets
 
 
219,050 
 
 
1,580 
 
 
- 
 
 
(161,619)
 
 
59,011 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
156,750 
 
 
1,421 
 
 
- 
 
 
(141,386)
 
 
16,785 
Long-term Risk Management Liabilities
 
 
37,039 
 
 
421 
 
 
- 
 
 
(30,930)
 
 
6,530 
Total Liabilities
 
 
193,789 
 
 
1,842 
 
 
- 
 
 
(172,316)
 
 
23,315 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
25,261 
 
$
(262)
 
$
- 
 
$
10,697 
 
$
35,696 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
167,847 
 
$
1,839 
 
$
- 
 
$
(135,248)
 
$
34,438 
Long-term Risk Management Assets
 
 
72,127 
 
 
- 
 
 
- 
 
 
(42,993)
 
 
29,134 
Total Assets
 
 
239,974 
 
 
1,839 
 
 
- 
 
 
(178,241)
 
 
63,572 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
156,561 
 
 
2,596 
 
 
- 
 
 
(145,721)
 
 
13,436 
Long-term Risk Management Liabilities
 
 
60,217 
 
 
41 
 
 
- 
 
 
(49,872)
 
 
10,386 
Total Liabilities
 
 
216,778 
 
 
2,637 
 
 
- 
 
 
(195,593)
 
 
23,822 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
23,196 
 
$
(798)
 
$
- 
 
$
17,352 
 
$
39,750 

 
335
 
Fair Value of Derivative Instruments
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
262,751 
 
$
1,316 
 
$
- 
 
$
(233,294)
 
$
30,773 
Long-term Risk Management Assets
 
 
63,533 
 
 
503 
 
 
- 
 
 
(36,024)
 
 
28,012 
Total Assets
 
 
326,284 
 
 
1,819 
 
 
- 
 
 
(269,318)
 
 
58,785 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
259,635 
 
 
1,663 
 
 
- 
 
 
(239,132)
 
 
22,166 
Long-term Risk Management Liabilities
 
 
50,757 
 
 
493 
 
 
- 
 
 
(42,847)
 
 
8,403 
Total Liabilities
 
 
310,392 
 
 
2,156 
 
 
- 
 
 
(281,979)
 
 
30,569 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
15,892 
 
$
(337)
 
$
- 
 
$
12,661 
 
$
28,216 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
255,179 
 
$
2,199 
 
$
- 
 
$
(207,330)
 
$
50,048 
Long-term Risk Management Assets
 
 
88,064 
 
 
- 
 
 
- 
 
 
(60,061)
 
 
28,003 
Total Assets
 
 
343,243 
 
 
2,199 
 
 
- 
 
 
(267,391)
 
 
78,051 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
240,877 
 
 
2,998 
 
 
- 
 
 
(219,484)
 
 
24,391 
Long-term Risk Management Liabilities
 
 
81,186 
 
 
47 
 
 
- 
 
 
(68,723)
 
 
12,510 
Total Liabilities
 
 
322,063 
 
 
3,045 
 
 
- 
 
 
(288,207)
 
 
36,901 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
21,180 
 
$
(846)
 
$
- 
 
$
20,816 
 
$
41,150 

 
336
 
Fair Value of Derivative Instruments
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
19,174 
 
$
134 
 
$
13,558 
 
$
(18,641)
 
$
14,225 
Long-term Risk Management Assets
 
 
1,944 
 
 
- 
 
 
- 
 
 
(1,692)
 
 
252 
Total Assets
 
 
21,118 
 
 
134 
 
 
13,558 
 
 
(20,333)
 
 
14,477 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
19,607 
 
 
- 
 
 
- 
 
 
(18,685)
 
 
922 
Long-term Risk Management Liabilities
 
 
1,889 
 
 
- 
 
 
- 
 
 
(1,692)
 
 
197 
Total Liabilities
 
 
21,496 
 
 
- 
 
 
- 
 
 
(20,377)
 
 
1,119 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
(378)
 
$
134 
 
$
13,558 
 
$
44 
 
$
13,358 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
14,885 
 
$
179 
 
$
- 
 
$
(12,688)
 
$
2,376 
Long-term Risk Management Assets
 
 
2,640 
 
 
- 
 
 
- 
 
 
(2,590)
 
 
50 
Total Assets
 
 
17,525 
 
 
179 
 
 
- 
 
 
(15,278)
 
 
2,426 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
14,981 
 
 
301 
 
 
- 
 
 
(12,703)
 
 
2,579 
Long-term Risk Management Liabilities
 
 
2,913 
 
 
- 
 
 
- 
 
 
(2,769)
 
 
144 
Total Liabilities
 
 
17,894 
 
 
301 
 
 
- 
 
 
(15,472)
 
 
2,723 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
(369)
 
$
(122)
 
$
- 
 
$
194 
 
$
(297)

 
337
 
Fair Value of Derivative Instruments
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
33,284 
 
$
123 
 
$
- 
 
$
(32,198)
 
$
1,209 
Long-term Risk Management Assets
 
 
3,346 
 
 
- 
 
 
5 
 
 
(2,913)
 
 
438 
Total Assets
 
 
36,630 
 
 
123 
 
 
5 
 
 
(35,111)
 
 
1,647 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
36,338 
 
 
- 
 
 
- 
 
 
(32,271)
 
 
4,067 
Long-term Risk Management Liabilities
 
 
3,250 
 
 
- 
 
 
- 
 
 
(2,912)
 
 
338 
Total Liabilities
 
 
39,588 
 
 
- 
 
 
- 
 
 
(35,183)
 
 
4,405 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
(2,958)
 
$
123 
 
$
5 
 
$
72 
 
$
(2,758)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value of Derivative Instruments
December 31, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk
 
 
 
 
 
 
 
 
 
 
 
Management
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
Hedging Contracts
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
 
 
 
 
 
and Foreign
 
 
 
 
Balance Sheet Location
 
Commodity (a)
 
Commodity (a)
 
Currency (a)
 
Other (a) (b)
 
Total
 
 
 
(in thousands)
Current Risk Management Assets
 
$
22,847 
 
$
169 
 
$
42 
 
$
(20,009)
 
$
3,049 
Long-term Risk Management Assets
 
 
4,145 
 
 
- 
 
 
5 
 
 
(4,066)
 
 
84 
Total Assets
 
 
26,992 
 
 
169 
 
 
47 
 
 
(24,075)
 
 
3,133 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current Risk Management Liabilities
 
 
20,788 
 
 
- 
 
 
89 
 
 
(20,033)
 
 
844 
Long-term Risk Management Liabilities
 
 
4,568 
 
 
- 
 
 
- 
 
 
(4,347)
 
 
221 
Total Liabilities
 
 
25,356 
 
 
- 
 
 
89 
 
 
(24,380)
 
 
1,065 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total MTM Derivative Contract Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets (Liabilities)
 
$
1,636 
 
$
169 
 
$
(42)
 
$
305 
 
$
2,068 

  (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 represent counterparty netting of risk management and hedging contracts, associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging” and dedesignated risk management contracts.

 
338
 
The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the years ended December 31, 2010 and 2009:

 
Amount of Gain (Loss) Recognized on
 
Risk Management Contracts
 
 Year Ended December 31, 2010
 
 
 
Location of Gain (Loss)
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
(in thousands)
 
Electric Generation, Transmission and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
$
 5,057 
 
$
 22,429 
 
$
 21,834 
 
$
 18,464 
 
$
 3,156 
 
$
 3,880 
 
Sales to AEP Affiliates
 
 
 (2,379)
 
 
 (2,630)
 
 
 (2,471)
 
 
 7,673 
 
 
 (794)
 
 
 (1,523)
 
Regulatory Assets (a)
 
 
 (372)
 
 
 (2,591)
 
 
 (186)
 
 
 (3,197)
 
 
 46 
 
 
 (2,902)
 
Regulatory Liabilities (a)
 
 
 27,790 
 
 
 1,498 
 
 
 8,217 
 
 
 1,953 
 
 
 878 
 
 
 351 
 
Total Gain (Loss) on Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
$
 30,096 
 
$
 18,706 
 
$
 27,394 
 
$
 24,893 
 
$
 3,286 
 
$
 (194)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Amount of Gain (Loss) Recognized on
 
Risk Management Contracts
 
 Year Ended December 31, 2009
 
 
 
Location of Gain (Loss)
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
(in thousands)
 
Electric Generation, Transmission and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
$
 16,213 
 
$
 28,738 
 
$
 39,188 
 
$
 30,575 
 
$
 (94)
 
$
 44 
 
Sales to AEP Affiliates
 
 
 (8,978)
 
 
 (5,650)
 
 
 (5,450)
 
 
 (1,120)
 
 
 912 
 
 
 750 
 
Regulatory Assets (a)
 
 
 - 
 
 
 (10,281)
 
 
 (5,837)
 
 
 (11,784)
 
 
 (331)
 
 
 (73)
 
Regulatory Liabilities (a)
 
 
 6,908 
 
 
 (3,486)
 
 
 (2,394)
 
 
 (4,319)
 
 
 (1,280)
 
 
 190 
 
Total Gain (Loss) on Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
$
 14,143 
 
$
 9,321 
 
$
 25,507 
 
$
 13,352 
 
$
 (793)
 
$
 911 

(a)  Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or non-current on the balance sheet.

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.

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, the non-Texas portion of SWEPCo generation and beginning in the second quarter of 2009 the Texas portion of SWEPCo generation) 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.”  SWEPCo re-applied the accounting guidance for “Regulated Operations” for the generation portion of SWEPCo’s Texas retail jurisdiction effective the second quarter of 2009.

 
339
 
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 December 31, 2010 and 2009, the Registrant Subsidiaries did not employ any fair value hedging strategies.  During 2008, APCo employed fair value hedging strategies and recognized an immaterial loss and no hedge ineffectiveness.

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, natural gas and heating oil and gasoline 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 2010, 2009 and 2008, APCo, CSPCo, I&M and OPCo designated commodity derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on financial fuel 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 2010 and 2009, 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) into Interest Expense in those periods in which hedged interest payments occur.  During 2010, APCo and PSO designated interest rate derivatives as cash flow hedges.  During 2009, OPCo designated interest rate derivatives as cash flow hedges.  During 2008, APCo and OPCo 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 that were designated as the hedged items in qualifying foreign currency hedging relationships.  During 2010 and 2009, SWEPCo designated foreign currency derivatives as cash flow hedges.  During 2008, APCo, OPCo and SWEPCo designated foreign currency derivatives as cash flow hedges.

During 2009, OPCo recognized a $6 million gain in Interest Expense related to hedge ineffectiveness on interest rate derivatives designated in cash flow hedge strategies.  During 2010, 2009 and 2008, hedge ineffectiveness was immaterial or nonexistent for all of the other hedge strategies disclosed above.

 
340
 
The following tables provide details on designated, effective cash flow hedges included in AOCI on the Balance Sheets and the reasons for changes in cash flow hedges for the years ended December 31, 2010 and 2009.  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, 2010
 
 
 
Commodity Contracts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
 
Balance in AOCI as of December 31, 2009
 
$
 (743)
 
$
 (376)
 
$
 (382)
 
$
 (366)
 
$
 (78)
 
$
 112 
 
Changes in Fair Value Recognized in AOCI
 
 
 (1,450)
 
 
 (852)
 
 
 (901)
 
 
 (1,106)
 
 
 77 
 
 
 69 
 
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Income Statement/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission, and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
 
 51 
 
 
 112 
 
 
 87 
 
 
 117 
 
 
 - 
 
 
 - 
 
 
 
Fuel and Other Consumables Used for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (13)
 
 
 197 
 
 
 - 
 
 
 
Purchased Electricity for Resale
 
 
 393 
 
 
 1,068 
 
 
 895 
 
 
 1,270 
 
 
 - 
 
 
 - 
 
 
 
Other Operation Expense
 
 
 (43)
 
 
 (33)
 
 
 (31)
 
 
 (39)
 
 
 (39)
 
 
 (44)
 
 
 
Maintenance Expense
 
 
 (70)
 
 
 (21)
 
 
 (28)
 
 
 (33)
 
 
 (24)
 
 
 (23)
 
 
 
Property, Plant and Equipment
 
 
 (71)
 
 
 (32)
 
 
 (36)
 
 
 (55)
 
 
 (45)
 
 
 (32)
 
 
 
Regulatory Assets (a)
 
 
 1,660 
 
 
 - 
 
 
 218 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
Regulatory Liabilities (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (5)
 
 
 - 
 
 
 - 
 
Balance in AOCI as of December 31, 2010
 
$
 (273)
 
$
 (134)
 
$
 (178)
 
$
 (230)
 
$
 88 
 
$
 82 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and Foreign Currency
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
 
(in thousands)
 
Balance in AOCI as of December 31, 2009
 
$
 (6,450)
 
$
 - 
 
$
 (9,514)
 
$
 12,172 
 
$
 (521)
 
$
 (5,047)
 
Changes in Fair Value Recognized in AOCI
 
 
 5,042 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 8,813 
 
 
 (74)
 
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Income Statement/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 4 
 
 
 - 
 
 
 - 
 
 
 
Other Operation Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 21 
 
 
 
Interest Expense
 
 
 1,625 
 
 
 - 
 
 
 1,007 
 
 
 (1,363)
 
 
 114 
 
 
 828 
 
Balance in AOCI as of December 31, 2010
 
$
 217 
 
$
 - 
 
$
 (8,507)
 
$
 10,813 
 
$
 8,406 
 
$
 (4,272)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Contracts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
 
(in thousands)
 
Balance in AOCI as of December 31, 2009
 
$
 (7,193)
 
$
 (376)
 
$
 (9,896)
 
$
 11,806 
 
$
 (599)
 
$
 (4,935)
 
Changes in Fair Value Recognized in AOCI
 
 
 3,592 
 
 
 (852)
 
 
 (901)
 
 
 (1,106)
 
 
 8,890 
 
 
 (5)
 
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Income Statement/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission, and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
 
 51 
 
 
 112 
 
 
 87 
 
 
 117 
 
 
 - 
 
 
 - 
 
 
 
Fuel and Other Consumables Used for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (13)
 
 
 197 
 
 
 - 
 
 
 
Purchased Electricity for Resale
 
 
 393 
 
 
 1,068 
 
 
 895 
 
 
 1,270 
 
 
 - 
 
 
 - 
 
 
 
Other Operation Expense
 
 
 (43)
 
 
 (33)
 
 
 (31)
 
 
 (39)
 
 
 (39)
 
 
 (23)
 
 
 
Maintenance Expense
 
 
 (70)
 
 
 (21)
 
 
 (28)
 
 
 (33)
 
 
 (24)
 
 
 (23)
 
 
 
Depreciation and Amortization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 4 
 
 
 - 
 
 
 - 
 
 
 
Interest Expense
 
 
 1,625 
 
 
 - 
 
 
 1,007 
 
 
 (1,363)
 
 
 114 
 
 
 828 
 
 
 
Property, Plant and Equipment
 
 
 (71)
 
 
 (32)
 
 
 (36)
 
 
 (55)
 
 
 (45)
 
 
 (32)
 
 
 
Regulatory Assets (a)
 
 
 1,660 
 
 
 - 
 
 
 218 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
Regulatory Liabilities (a)
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (5)
 
 
 - 
 
 
 - 
 
Balance in AOCI as of December 31, 2010
 
$
 (56)
 
$
 (134)
 
$
 (8,685)
 
$
 10,583 
 
$
 8,494 
 
$
 (4,190)

 
341
 
 
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
 
 Year Ended December 31, 2009
 
 
 
Commodity Contracts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
 
Balance in AOCI as of December 31, 2008
 
$
 2,726 
 
$
 1,531 
 
$
 1,482 
 
$
 1,898 
 
$
 - 
 
$
 - 
 
Changes in Fair Value Recognized in AOCI
 
 
 (669)
 
 
 (462)
 
 
 (435)
 
 
 (522)
 
 
 5 
 
 
 190 
 
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Income Statement/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission, and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
 
 (1,646)
 
 
 (4,088)
 
 
 (3,189)
 
 
 (4,903)
 
 
 - 
 
 
 - 
 
 
 
Fuel and Other Consumables Used for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation
 
 
 (95)
 
 
 (41)
 
 
 (50)
 
 
 (67)
 
 
 (49)
 
 
 (54)
 
 
 
Purchased Electricity for Resale
 
 
 1,093 
 
 
 2,708 
 
 
 2,142 
 
 
 3,274 
 
 
 - 
 
 
 - 
 
 
 
Other Operation Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
Maintenance Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
Property, Plant and Equipment
 
 
 (58)
 
 
 (24)
 
 
 (29)
 
 
 (46)
 
 
 (34)
 
 
 (24)
 
 
 
Regulatory Assets (a)
 
 
 4,003 
 
 
 - 
 
 
 481 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
Regulatory Liabilities (a)
 
 
 (6,097)
 
 
 - 
 
 
 (784)
 
 
 - 
 
 
 - 
 
 
 - 
 
Balance in AOCI as of December 31, 2009
 
$
 (743)
 
$
 (376)
 
$
 (382)
 
$
 (366)
 
$
 (78)
 
$
 112 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest Rate and Foreign Currency
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Contracts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
 
(in thousands)
 
Balance in AOCI as of December 31, 2008
 
$
 (8,118)
 
$
 - 
 
$
 (10,521)
 
$
 1,752 
 
$
 (704)
 
$
 (5,924)
 
Changes in Fair Value Recognized in AOCI
 
 
 (1)
 
 
 - 
 
 
 - 
 
 
 10,915 
 
 
 - 
 
 
 49 
 
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Income Statement/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Depreciation and Amortization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
 
 - 
 
 
 - 
 
 
 (4)
 
 
 4 
 
 
 - 
 
 
 - 
 
 
 
Interest Expense
 
 
 1,669 
 
 
 - 
 
 
 1,011 
 
 
 (499)
 
 
 183 
 
 
 828 
 
Balance in AOCI as of December 31, 2009
 
$
 (6,450)
 
$
 - 
 
$
 (9,514)
 
$
 12,172 
 
$
 (521)
 
$
 (5,047)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Contracts
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
 
(in thousands)
 
Balance in AOCI as of December 31, 2008
 
$
 (5,392)
 
$
 1,531 
 
$
 (9,039)
 
$
 3,650 
 
$
 (704)
 
$
 (5,924)
 
Changes in Fair Value Recognized in AOCI
 
 
 (670)
 
 
 (462)
 
 
 (435)
 
 
 10,393 
 
 
 5 
 
 
 239 
 
Amount of (Gain) or Loss Reclassified
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
from AOCI to Income Statement/within
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance Sheet:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation, Transmission, and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Distribution Revenues
 
 
 (1,646)
 
 
 (4,088)
 
 
 (3,189)
 
 
 (4,903)
 
 
 - 
 
 
 - 
 
 
 
Fuel and Other Consumables Used for
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Electric Generation
 
 
 (95)
 
 
 (41)
 
 
 (50)
 
 
 (67)
 
 
 (49)
 
 
 (54)
 
 
 
Purchased Electricity for Resale
 
 
 1,093 
 
 
 2,708 
 
 
 2,142 
 
 
 3,274 
 
 
 - 
 
 
 - 
 
 
 
Other Operation Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
Maintenance Expense
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
Depreciation and Amortization
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expense
 
 
 - 
 
 
 - 
 
 
 (4)
 
 
 4 
 
 
 - 
 
 
 - 
 
 
 
Interest Expense
 
 
 1,669 
 
 
 - 
 
 
 1,011 
 
 
 (499)
 
 
 183 
 
 
 828 
 
 
 
Property, Plant and Equipment
 
 
 (58)
 
 
 (24)
 
 
 (29)
 
 
 (46)
 
 
 (34)
 
 
 (24)
 
 
 
Regulatory Assets (a)
 
 
 4,003 
 
 
 - 
 
 
 481 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
Regulatory Liabilities (a)
 
 
 (6,097)
 
 
 - 
 
 
 (784)
 
 
 - 
 
 
 - 
 
 
 - 
 
Balance in AOCI as of December 31, 2009
 
$
 (7,193)
 
$
 (376)
 
$
 (9,896)
 
$
 11,806 
 
$
 (599)
 
$
 (4,935)
 
    (a)  Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or non-current on the Balance Sheets.

 
342
 
The following table represents amounts of income reclassified from AOCI to net income:

Year
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
2008 
 
$
 975 
 
$
 736 
 
$
 1,713 
 
$
 1,528 
 
$
 183 
 
$
 284 

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the Balance Sheets at December 31, 2010 and 2009 were:

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Balance Sheets
December 31, 2010
 
 
 
 
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
 
$
 333 
 
$
 11,888 
 
$
 (727)
 
$
 - 
 
$
 (273)
 
$
 217 
CSPCo
 
 
 229 
 
 
 - 
 
 
 (419)
 
 
 - 
 
 
 (134)
 
 
 - 
I&M
 
 
 175 
 
 
 - 
 
 
 (437)
 
 
 - 
 
 
 (178)
 
 
 (8,507)
OPCo
 
 
 174 
 
 
 - 
 
 
 (511)
 
 
 - 
 
 
 (230)
 
 
 10,813 
PSO
 
 
 134 
 
 
 13,558 
 
 
 - 
 
 
 - 
 
 
 88 
 
 
 8,406 
SWEPCo
 
 
 123 
 
 
 5 
 
 
 - 
 
 
 - 
 
 
 82 
 
 
 (4,272)

 
 
 
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
 
$
 (280)
 
$
 (1,173)
 
 
 41 
CSPCo
 
 
 (137)
 
 
 - 
 
 
 41 
I&M
 
 
 (184)
 
 
 (955)
 
 
 41 
OPCo
 
 
 (236)
 
 
 1,359 
 
 
 41 
PSO
 
 
 88 
 
 
 735 
 
 
 12 
SWEPCo
 
 
 82 
 
 
 (829)
 
 
 23 

 
343
 
Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Balance Sheets
December 31, 2009
 
 
 
 
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
 
$
 1,999 
 
$
 - 
 
$
 (3,542)
 
$
 - 
 
$
 (743)
 
$
 (6,450)
CSPCo
 
 
 984 
 
 
 - 
 
 
 (1,794)
 
 
 - 
 
 
 (376)
 
 
 - 
I&M
 
 
 1,011 
 
 
 - 
 
 
 (1,809)
 
 
 - 
 
 
 (382)
 
 
 (9,514)
OPCo
 
 
 1,242 
 
 
 - 
 
 
 (2,088)
 
 
 - 
 
 
 (366)
 
 
 12,172 
PSO
 
 
 178 
 
 
 - 
 
 
 (300)
 
 
 - 
 
 
 (78)
 
 
 (521)
SWEPCo
 
 
 168 
 
 
 5 
 
 
 - 
 
 
 (46)
 
 
 112 
 
 
 (5,047)

 
 
 
Expected to be Reclassified to
 
 
 
 
Net Income During the Next
 
 
 
 
Twelve Months
 
 
 
 
 
 
Interest Rate
 
 
 
 
 
 
and Foreign
 
Company
 
Commodity
 
Currency
 
 
 
 
(in thousands)
 
APCo
 
$
 (691)
 
$
 (1,301)
 
CSPCo
 
 
 (349)
 
 
 - 
 
I&M
 
 
 (358)
 
 
 (1,007)
 
OPCo
 
 
 (335)
 
 
 1,359 
 
PSO
 
 
 (79)
 
 
 (114)
 
SWEPCo
 
 
 111 
 
 
 (829)
 

(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.

AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements which 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.

 
344
 
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.  Management does not anticipate a downgrade below investment grade.  The following tables represent: (a) the Registrant Subsidiaries’ aggregate 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, 2010 and  2009:

 
 
 
December 31, 2010
 
 
 
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
 
$
 6,594 
 
$
 12,607 
 
$
 12,574 
CSPCo
 
 
 3,801 
 
 
 7,267 
 
 
 7,248 
I&M
 
 
 3,965 
 
 
 7,581 
 
 
 7,561 
OPCo
 
 
 4,640 
 
 
 8,871 
 
 
 8,847 
PSO
 
 
 16 
 
 
 1,785 
 
 
 1,385 
SWEPCo
 
 
 19 
 
 
 2,139 
 
 
 1,659 

 
 
 
December 31, 2009
 
 
 
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
 
$
 2,229 
 
$
 8,433 
 
$
 7,947 
CSPCo
 
 
 1,129 
 
 
 4,272 
 
 
 4,026 
I&M
 
 
 1,139 
 
 
 4,309 
 
 
 4,060 
OPCo
 
 
 1,315 
 
 
 4,975 
 
 
 4,688 
PSO
 
 
 689 
 
 
 2,772 
 
 
 2,083 
SWEPCo
 
 
 819 
 
 
 3,297 
 
 
 2,477 

As of December 31, 2010 and 2009, the Registrant Subsidiaries were not required to post any collateral.

 
345
 
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 under outstanding debt 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.  Management does not anticipate a non-performance event under these provisions.  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, 2010 and 2009:

 
 
 
December 31, 2010
 
 
 
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
 
$
 76,810 
 
$
 6,637 
 
$
 23,748 
CSPCo
 
 
 44,277 
 
 
 3,826 
 
 
 13,689 
I&M
 
 
 46,188 
 
 
 3,991 
 
 
 14,280 
OPCo
 
 
 54,066 
 
 
 4,670 
 
 
 16,731 
PSO
 
 
 60 
 
 
 - 
 
 
 28 
SWEPCo
 
 
 75 
 
 
 - 
 
 
 37 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2009
 
 
 
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
 
$
 154,924 
 
$
 3,115 
 
$
 33,186 
CSPCo
 
 
 78,489 
 
 
 1,578 
 
 
 16,813 
I&M
 
 
 79,158 
 
 
 1,592 
 
 
 16,955 
OPCo
 
 
 91,430 
 
 
 1,838 
 
 
 19,615 
PSO
 
 
 40 
 
 
 - 
 
 
 40 
SWEPCo
 
 
 139 
 
 
 - 
 
 
 93 

 
346
 
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.  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, 2010 and 2009 are summarized in the following table:

 
 
December 31,
 
 
2010 
 
2009 
Company
 
Book Value
 
Fair Value
 
Book Value
 
Fair Value
 
 
(in thousands)
APCo
 
$
 3,561,141 
 
$
 3,878,557 
 
$
 3,477,306 
 
$
 3,699,373 
CSPCo
 
 
 1,438,830 
 
 
 1,571,219 
 
 
 1,536,393 
 
 
 1,616,857 
I&M
 
 
 2,004,226 
 
 
 2,169,520 
 
 
 2,077,906 
 
 
 2,192,854 
OPCo
 
 
 2,729,522 
 
 
 2,945,280 
 
 
 3,242,505 
 
 
 3,380,084 
PSO
 
 
 971,186 
 
 
 1,040,656 
 
 
 968,121 
 
 
 1,007,183 
SWEPCo
 
 
 1,769,520 
 
 
 1,931,516 
 
 
 1,474,153 
 
 
 1,554,165 

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 at December 31, 2010 and 2009:

 
 
 
December 31,
 
 
 
2010 
 
2009 
 
 
 
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
 
$
 20,039 
 
$
 - 
 
$
 - 
 
$
 14,412 
 
$
 - 
 
$
 - 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 
 461,084 
 
 
 22,582 
 
 
 (1,489)
 
 
 400,565 
 
 
 12,708 
 
 
 (3,472)
 
Corporate Debt
 
 
 59,463 
 
 
 3,716 
 
 
 (1,905)
 
 
 57,291 
 
 
 4,636 
 
 
 (2,177)
 
State and Local Government
 
 
 340,786 
 
 
 (975)
 
 
 (340)
 
 
 368,930 
 
 
 7,924 
 
 
 991 
 
  Subtotal Fixed Income Securities
 
 861,333 
 
 
 25,323 
 
 
 (3,734)
 
 
 826,786 
 
 
 25,268 
 
 
 (4,658)
Equity Securities - Domestic
 
 
 633,855 
 
 
 183,447 
 
 
 (122,889)
 
 
 550,721 
 
 
 234,437 
 
 
 (119,379)
Spent Nuclear Fuel and
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decommissioning Trusts
 
$
 1,515,227 
 
$
 208,770 
 
$
 (126,623)
 
$
 1,391,919 
 
$
 259,705 
 
$
 (124,037)

The following table provides the securities activity within the decommissioning and SNF trusts for the years ended December 31, 2010, 2009 and 2008:

 
Years Ended December 31,
 
2010 
 
2009 
 
2008 
 
(in thousands)
Proceeds From Investment Sales
$
 1,361,813 
 
$
 712,742 
 
$
 732,475 
Purchases of Investments
 
 1,414,473 
 
 
 770,919 
 
 
 803,664 
Gross Realized Gains on Investment Sales
 
 11,570 
 
 
 28,218 
 
 
 32,634 
Gross Realized Losses on Investment Sales
 
 2,087 
 
 
 1,241 
 
 
 7,223 

 
347
 
The adjusted cost of debt securities was $835 million and $801 million as of December 31, 2010 and 2009, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at December 31, 2010 was as follows:

 
Fair Value
 
 
of Debt
 
 
Securities
 
 
 
 
 
 
(in thousands)
 
Within 1 year
  $ 22,424  
1 year – 5 years
    305,846  
5 years – 10 years
    257,096  
After 10 years
    275,967  
Total
  $ 861,333  

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, 2010 and 2009.  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.

 
348
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2010
APCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (g)
$
 1,686 
 
$
 330,605 
 
$
 13,791 
 
$
 (270,012)
 
$
 76,070 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 2,591 
 
 
 - 
 
 
 (2,258)
 
 
 333 
 
Interest Rate/Foreign Currency Hedges
 
 - 
 
 
 11,888 
 
 
 - 
 
 
 - 
 
 
 11,888 
Dedesignated Risk Management Contracts (b)
 
 - 
 
 
 - 
 
 
 - 
 
 
 3,371 
 
 
 3,371 
Total Risk Management Assets
$
 1,686 
 
$
 345,084 
 
$
 13,791 
 
$
 (268,899)
 
$
 91,662 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (g)
$
 1,653 
 
$
 312,258 
 
$
 8,660 
 
$
 (284,432)
 
$
 38,139 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 2,985 
 
 
 - 
 
 
 (2,258)
 
 
 727 
Total Risk Management Liabilities
$
 1,653 
 
$
 315,243 
 
$
 8,660 
 
$
 (286,690)
 
$
 38,866 

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2009
APCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Cash Deposits (d)
$
 421 
 
$
 - 
 
$
 - 
 
$
 51 
 
$
 472 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a)
 
 2,344 
 
 
 449,406 
 
 
 12,866 
 
 
 (360,248)
 
 
 104,368 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 3,620 
 
 
 - 
 
 
 (1,621)
 
 
 1,999 
Dedesignated Risk Management Contracts (b)
 
 - 
 
 
 - 
 
 
 - 
 
 
 8,730 
 
 
 8,730 
Total Risk Management Assets
 
 2,344 
 
 
 453,026 
 
 
 12,866 
 
 
 (353,139)
 
 
 115,097 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 2,765 
 
$
 453,026 
 
$
 12,866 
 
$
 (353,088)
 
$
 115,569 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a)
$
 2,648 
 
$
 422,063 
 
$
 3,438 
 
$
 (388,265)
 
$
 39,884 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 5,163 
 
 
 - 
 
 
 (1,621)
 
 
 3,542 
DETM Assignment (c)
 
 - 
 
 
 - 
 
 
 - 
 
 
 2,730 
 
 
 2,730 
Total Risk Management Liabilities
$
 2,648 
 
$
 427,226 
 
$
 3,438 
 
$
 (387,156)
 
$
 46,156 

 
349
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2010
CSPCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (g)
$
 972 
 
$
 185,699 
 
$
 7,950 
 
$
 (150,930)
 
$
 43,691 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 1,531 
 
 
 - 
 
 
 (1,302)
 
 
 229 
Dedesignated Risk Management Contracts (b)
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,943 
 
 
 1,943 
Total Risk Management Assets
$
 972 
 
$
 187,230 
 
$
 7,950 
 
$
 (150,289)
 
$
 45,863 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (g)
$
 953 
 
$
 175,078 
 
$
 4,975 
 
$
 (159,235)
 
$
 21,771 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 1,721 
 
 
 - 
 
 
 (1,302)
 
 
 419 
Total Risk Management Liabilities
$
 953 
 
$
 176,799 
 
$
 4,975 
 
$
 (160,537)
 
$
 22,190 

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2009
CSPCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Cash Deposits (d)
$
 16,129 
 
$
 - 
 
$
 - 
 
$
 21 
 
$
 16,150 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a)
 
 1,188 
 
 
 227,150 
 
 
 6,518 
 
 
 (182,038)
 
 
 52,818 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 1,805 
 
 
 - 
 
 
 (821)
 
 
 984 
Dedesignated Risk Management Contracts (b)
 
 - 
 
 
 - 
 
 
 - 
 
 
 4,423 
 
 
 4,423 
Total Risk Management Assets
 
 1,188 
 
 
 228,955 
 
 
 6,518 
 
 
 (178,436)
 
 
 58,225 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 17,317 
 
$
 228,955 
 
$
 6,518 
 
$
 (178,415)
 
$
 74,375 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a)
$
 1,342 
 
$
 213,330 
 
$
 1,742 
 
$
 (196,226)
 
$
 20,188 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 2,615 
 
 
 - 
 
 
 (821)
 
 
 1,794 
DETM Assignment (c)
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,383 
 
 
 1,383 
Total Risk Management Liabilities
$
 1,342 
 
$
 215,945 
 
$
 1,742 
 
$
 (195,664)
 
$
 23,365 

 
350
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2010
I&M
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (g)
$
 1,014 
 
$
 209,031 
 
$
 8,295 
 
$
 (161,531)
 
$
 56,809 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 1,533 
 
 
 - 
 
 
 (1,358)
 
 
 175 
Dedesignated Risk Management Contracts (b)
 
 - 
 
 
 - 
 
 
 - 
 
 
 2,027 
 
 
 2,027 
Total Risk Management Assets
 
 1,014 
 
 
 210,564 
 
 
 8,295 
 
 
 (160,862)
 
 
 59,011 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (e)
 
 - 
 
 
 7,898 
 
 
 - 
 
 
 12,141 
 
 
 20,039 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 - 
 
 
 461,084 
 
 
 - 
 
 
 - 
 
 
 461,084 
 
Corporate Debt
 
 - 
 
 
 59,463 
 
 
 - 
 
 
 - 
 
 
 59,463 
 
State and Local Government
 
 - 
 
 
 340,786 
 
 
 - 
 
 
 - 
 
 
 340,786 
 
 
Subtotal Fixed Income Securities
 
 - 
 
 
 861,333 
 
 
 - 
 
 
 - 
 
 
 861,333 
Equity Securities - Domestic (f)
 
 633,855 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 633,855 
Total Spent Nuclear Fuel and Decommissioning Trusts
 
 633,855 
 
 
 869,231 
 
 
 - 
 
 
 12,141 
 
 
 1,515,227 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 634,869 
 
$
 1,079,795 
 
$
 8,295 
 
$
 (148,721)
 
$
 1,574,238 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (g)
$
 994 
 
$
 186,898 
 
$
 5,187 
 
$
 (170,201)
 
$
 22,878 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 1,795 
 
 
 - 
 
 
 (1,358)
 
 
 437 
Total Risk Management Liabilities
$
 994 
 
$
 188,693 
 
$
 5,187 
 
$
 (171,559)
 
$
 23,315 

 
351
 
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
 
December 31, 2009
I&M
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a)
$
 1,198 
 
$
 231,777 
 
$
 6,571 
 
$
 (181,446)
 
$
 58,100 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 1,839 
 
 
 - 
 
 
 (828)
 
 
 1,011 
Dedesignated Risk Management Contracts (b)
 
 - 
 
 
 - 
 
 
 - 
 
 
 4,461 
 
 
 4,461 
Total Risk Management Assets
 
 1,198 
 
 
 233,616 
 
 
 6,571 
 
 
 (177,813)
 
 
 63,572 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel and Decommissioning Trusts
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and Cash Equivalents (e)
 
 - 
 
 
 3,562 
 
 
 - 
 
 
 10,850 
 
 
 14,412 
Fixed Income Securities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States Government
 
 - 
 
 
 400,565 
 
 
 - 
 
 
 - 
 
 
 400,565 
 
Corporate Debt
 
 - 
 
 
 57,291 
 
 
 - 
 
 
 - 
 
 
 57,291 
 
State and Local Government
 
 - 
 
 
 368,930 
 
 
 - 
 
 
 - 
 
 
 368,930 
 
 
Subtotal Fixed Income Securities
 
 - 
 
 
 826,786 
 
 
 - 
 
 
 - 
 
 
 826,786 
Equity Securities - Domestic (f)
 
 550,721 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 550,721 
Total Spent Nuclear Fuel and Decommissioning Trusts
 
 550,721 
 
 
 830,348 
 
 
 - 
 
 
 10,850 
 
 
 1,391,919 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 551,919 
 
$
 1,063,964 
 
$
 6,571 
 
$
 (166,963)
 
$
 1,455,491 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a)
$
 1,353 
 
$
 213,242 
 
$
 1,755 
 
$
 (195,732)
 
$
 20,618 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 2,637 
 
 
 - 
 
 
 (828)
 
 
 1,809 
DETM Assignment (c)
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,395 
 
 
 1,395 
Total Risk Management Liabilities
$
 1,353 
 
$
 215,879 
 
$
 1,755 
 
$
 (195,165)
 
$
 23,822 

 
352
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2010
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Cash Deposits (d)
$
26 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 26 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (g)
 
 1,186 
 
 
 314,560 
 
 
 9,709 
 
 
 (269,216)
 
 
 56,239 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 1,764 
 
 
 - 
 
 
 (1,590)
 
 
 174 
Dedesignated Risk Management Contracts (b)
 
 - 
 
 
 - 
 
 
 - 
 
 
 2,372 
 
 
 2,372 
Total Risk Management Assets
 
 1,186 
 
 
 316,324 
 
 
 9,709 
 
 
 (268,434)
 
 
 58,785 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 1,212 
 
$
 316,324 
 
$
 9,709 
 
$
 (268,434)
 
$
 58,811 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (g)
$
 1,163 
 
$
 302,299 
 
$
 6,101 
 
$
 (279,505)
 
$
 30,058 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 2,101 
 
 
 - 
 
 
 (1,590)
 
 
 511 
Total Risk Management Liabilities
$
 1,163 
 
$
 304,400 
 
$
 6,101 
 
$
 (281,095)
 
$
 30,569 

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2009
OPCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Cash Deposits (d)
$
 1,075 
 
$
 - 
 
$
 - 
 
$
 24 
 
$
 1,099 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a)
 
 1,383 
 
 
 332,904 
 
 
 7,644 
 
 
 (270,272)
 
 
 71,659 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 2,199 
 
 
 - 
 
 
 (957)
 
 
 1,242 
Dedesignated Risk Management Contracts (b)
 
 - 
 
 
 - 
 
 
 - 
 
 
 5,150 
 
 
 5,150 
Total Risk Management Assets
 
 1,383 
 
 
 335,103 
 
 
 7,644 
 
 
 (266,079)
 
 
 78,051 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 2,458 
 
$
 335,103 
 
$
 7,644 
 
$
 (266,055)
 
$
 79,150 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a)
$
 1,562 
 
$
 317,114 
 
$
 2,075 
 
$
 (287,549)
 
$
 33,202 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 3,045 
 
 
 - 
 
 
 (957)
 
 
 2,088 
DETM Assignment (c)
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,611 
 
 
 1,611 
Total Risk Management Liabilities
$
 1,562 
 
$
 320,159 
 
$
 2,075 
 
$
 (286,895)
 
$
 36,901 

 
353
 
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2010
PSO
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (g)
$
 - 
 
$
 21,119 
 
$
 1 
 
$
 (20,335)
 
$
 785 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges
 
 - 
 
 
 134 
 
 
 - 
 
 
 - 
 
 
 134 
 
Interest Rate/Foreign Currency Hedges
 
 - 
 
 
 13,558 
 
 
 - 
 
 
 - 
 
 
 13,558 
Total Risk Management Assets
$
 - 
 
$
 34,811 
 
$
 1 
 
$
 (20,335)
 
$
 14,477 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (g)
$
 - 
 
$
 21,498 
 
$
 - 
 
$
 (20,379)
 
$
 1,119 

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2009
PSO
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a)
$
 - 
 
$
 17,494 
 
$
 14 
 
$
 (15,260)
 
$
 2,248 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 179 
 
 
 - 
 
 
 (1)
 
 
 178 
Total Risk Management Assets
$
 - 
 
$
 17,673 
 
$
 14 
 
$
 (15,261)
 
$
 2,426 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a)
$
 - 
 
$
 17,865 
 
$
 12 
 
$
 (15,454)
 
$
 2,423 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 301 
 
 
 - 
 
 
 (1)
 
 
 300 
Total Risk Management Liabilities
$
 - 
 
$
 18,166 
 
$
 12 
 
$
 (15,455)
 
$
 2,723 

 
354
 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2010
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (g)
$
 - 
 
$
 36,632 
 
$
 2 
 
$
 (35,115)
 
$
 1,519 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges
 
 - 
 
 
 123 
 
 
 - 
 
 
 - 
 
 
 123 
 
Interest Rate/Foreign Currency Hedges
 
 - 
 
 
 5 
 
 
 - 
 
 
 - 
 
 
 5 
Total Risk Management Assets
$
 - 
 
$
 36,760 
 
$
 2 
 
$
 (35,115)
 
$
 1,647 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a) (g)
$
 - 
 
$
 39,592 
 
$
 - 
 
$
 (35,187)
 
$
 4,405 

 
Assets and Liabilities Measured at Fair Value on a Recurring Basis
 
December 31, 2009
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
Level 1
 
Level 2
 
Level 3
 
Other
 
Total
Assets:
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a)
$
 - 
 
$
 26,945 
 
$
 22 
 
$
 (24,007)
 
$
 2,960 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 216 
 
 
 - 
 
 
 (43)
 
 
 173 
Total Risk Management Assets
$
 - 
 
$
 27,161 
 
$
 22 
 
$
 (24,050)
 
$
 3,133 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Risk Management Commodity Contracts (a)
$
 - 
 
$
 25,312 
 
$
 19 
 
$
 (24,312)
 
$
 1,019 
Cash Flow Hedges:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity Hedges (a)
 
 - 
 
 
 89 
 
 
 - 
 
 
 (43)
 
 
 46 
Total Risk Management Liabilities
$
 - 
 
$
 25,401 
 
$
 19 
 
$
 (24,355)
 
$
 1,065 

(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)
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.
(c)
See “Natural Gas Contracts with DETM” section of Note 15.
(d)
Amounts in “Other” column primarily represent cash deposits with third parties.  Level 1 amounts primarily represent investments in money market funds.
(e)
Amounts in “Other” column primarily represent accrued interest receivables from financial institutions.  Level 2 amounts primarily represent investments in money market funds.
(f)
Amounts represent publicly traded equity securities and equity-based mutual funds.
(g)
Substantially comprised of power contracts for APCo, CSPCo, I&M and OPCo and coal contracts for PSO and SWEPCo.

There have been no transfers between Level 1 and Level 2 during the year ended December 31, 2010.

 
355
 
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, 2010
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance as of December 31, 2009
 
$
 9,428 
 
$
 4,776 
 
$
 4,816 
 
$
 5,569 
 
$
 2 
 
$
 3 
Realized Gain (Loss) Included in Net Income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(or Changes in Net Assets) (a) (b)
 
 
 1,670 
 
 
 946 
 
 
 963 
 
 
 1,107 
 
 
 2 
 
 
 2 
Unrealized Gain (Loss) Included in Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income (or Changes in Net Assets) Relating
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
to Assets Still Held at the Reporting Date (a)
 
 
 - 
 
 
 9,601 
 
 
 - 
 
 
 11,713 
 
 
 - 
 
 
 - 
Realized and Unrealized Gains (Losses)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Included in Other Comprehensive Income
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Purchases, Issuances and Settlements (c)
 
 
 (7,163)
 
 
 (4,039)
 
 
 (4,121)
 
 
 (4,761)
 
 
 (1)
 
 
 (1)
Transfers into Level 3 (d) (h)
 
 
 1,133 
 
 
 614 
 
 
 616 
 
 
 719 
 
 
 - 
 
 
 - 
Transfers out of Level 3 (e) (h)
 
 
 (10,999)
 
 
 (6,332)
 
 
 (6,558)
 
 
 (7,646)
 
 
 - 
 
 
 - 
Changes in Fair Value Allocated to Regulated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jurisdictions (g)
 
 
 11,062 
 
 
 (2,591)
 
 
 7,392 
 
 
 (3,093)
 
 
 (2)
 
 
 (2)
Balance as of December 31, 2010
 
$
 5,131 
 
$
 2,975 
 
$
 3,108 
 
$
 3,608 
 
$
 1 
 
$
 2 

Year Ended December 31, 2009
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance as of December 31, 2008
 
$
 8,009 
 
$
 4,497 
 
$
 4,352 
 
$
 5,563 
 
$
 (2)
 
$
 (3)
Realized Gain (Loss) Included in Net Income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(or Changes in Net Assets) (a) (b)
 
 
 (1,324)
 
 
 (743)
 
 
 (719)
 
 
 (921)
 
 
 - 
 
 
 - 
Unrealized Gain (Loss) Included in Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income (or Changes in Net Assets) Relating
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
to Assets Still Held at the Reporting Date (a)
 
 
 - 
 
 
 4,234 
 
 
 - 
 
 
 4,947 
 
 
 - 
 
 
 - 
Realized and Unrealized Gains (Losses)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Included in Other Comprehensive Income
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Purchases, Issuances and Settlements (c)
 
 
 (5,464)
 
 
 (2,940)
 
 
 (2,847)
 
 
 (3,683)
 
 
 - 
 
 
 - 
Transfers in and/or out of Level 3 (f)
 
 
 (500)
 
 
 (272)
 
 
 (263)
 
 
 (337)
 
 
 - 
 
 
 - 
Changes in Fair Value Allocated to Regulated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jurisdictions (g)
 
 
 8,707 
 
 
 - 
 
 
 4,293 
 
 
 - 
 
 
 4 
 
 
 6 
Balance as of December 31, 2009
 
$
 9,428 
 
$
 4,776 
 
$
 4,816 
 
$
 5,569 
 
$
 2 
 
$
 3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2008
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Balance as of December 31, 2007
 
$
 (697)
 
$
 (263)
 
$
 (280)
 
$
 (1,607)
 
$
 (243)
 
$
 (408)
Realized (Gain) Loss Included in Net Income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(or Changes in Net Assets) (a)
 
 
 393 
 
 
 86 
 
 
 110 
 
 
 1,406 
 
 
 244 
 
 
 410 
Unrealized Gain (Loss) Included in Net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income (or Changes in Net Assets) Relating
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
to Assets Still Held at the Reporting Date (a)
 
 
 - 
 
 
 1,724 
 
 
 - 
 
 
 2,082 
 
 
 - 
 
 
 (1)
Realized and Unrealized Gains (Losses)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Included in Other Comprehensive Income
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Purchases, Issuances and Settlements
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Transfers in and/or out of Level 3 (f)
 
 
 (931)
 
 
 (537)
 
 
 (516)
 
 
 (637)
 
 
 (1)
 
 
 (2)
Changes in Fair Value Allocated to Regulated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jurisdictions (g)
 
 
 9,244 
 
 
 3,487 
 
 
 5,038 
 
 
 4,319 
 
 
 (2)
 
 
 (2)
Balance as of December 31, 2008
 
$
 8,009 
 
$
 4,497 
 
$
 4,352 
 
$
 5,563 
 
$
 (2)
 
$
 (3)

 
356
 
(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)
Represents existing assets or liabilities that were previously categorized as Level 3.
(f)
Represents existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period.
(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.
(h)
Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

12.   INCOME TAXES

The details of the Registrant Subsidiaries’ income taxes before extraordinary loss as reported are as follows:

Year Ended December 31, 2010
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Income Tax Expense (Credit):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current
 
$
 (66,216)
 
$
 59,310 
 
$
 1,795 
 
$
 (47,907)
 
$
 (46,528)
 
$
 (16,066)
 
Deferred
 
 
 144,413 
 
 
 74,585 
 
 
 63,947 
 
 
 218,246 
 
 
 92,695 
 
 
 81,764 
 
Deferred Investment Tax Credits
 
 
 (3,967)
 
 
 (2,046)
 
 
 (2,316)
 
 
 (882)
 
 
 3,933 
 
 
 (1,484)
Total Income Taxes
 
$
 74,230 
 
$
 131,849 
 
$
 63,426 
 
$
 169,457 
 
$
 50,100 
 
$
 64,214 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2009
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Income Tax Expense (Credit):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current
 
$
 (273,084)
 
$
 14,294 
 
$
 (187,911)
 
$
 (215,371)
 
$
 (11,338)
 
$
 (6,963)
 
Deferred
 
 
 322,626 
 
 
 131,407 
 
 
 271,264 
 
 
 382,794 
 
 
 56,029 
 
 
 28,016 
 
Deferred Investment Tax Credits
 
 
 (4,093)
 
 
 (1,980)
 
 
 (2,316)
 
 
 (949)
 
 
 (770)
 
 
 (3,542)
Total Income Taxes
 
$
 45,449 
 
$
 143,721 
 
$
 81,037 
 
$
 166,474 
 
$
 43,921 
 
$
 17,511 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2008
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Income Tax Expense (Credit):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current
 
$
 (97,447)
 
$
 111,996 
 
$
 2,575 
 
$
 72,847 
 
$
 (24,763)
 
$
 (25,055)
 
Deferred
 
 
 145,594 
 
 
 (303)
 
 
 57,879 
 
 
 42,717 
 
 
 67,874 
 
 
 62,060 
 
Deferred Investment Tax Credits
 
 
 (4,209)
 
 
 (1,954)
 
 
 (2,196)
 
 
 (942)
 
 
 (834)
 
 
 (3,964)
Total Income Taxes
 
$
 43,938 
 
$
 109,739 
 
$
 58,258 
 
$
 114,622 
 
$
 42,277 
 
$
 33,041 

 
357
 
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 rate and the amount of income taxes reported.

APCo
Years Ended December 31,
 
2010 
 
2009 
 
2008 
 
(in thousands)
Net Income
$
 136,668 
 
$
 155,814 
 
$
 122,863 
Income Taxes
 
 74,230 
 
 
 45,449 
 
 
 43,938 
Pretax Income
$
 210,898 
 
$
 201,263 
 
$
 166,801 
 
 
 
 
 
 
 
 
 
Income Taxes on Pretax Income at Statutory Rate (35%)
$
 73,814 
 
$
 70,442 
 
$
 58,380 
Increase (Decrease) in Income Taxes resulting from the following items:
 
 
 
 
 
 
 
 
 
 
Depreciation
 
 18,134 
 
 
 11,357 
 
 
 9,117 
 
 
AFUDC
 
 (1,860)
 
 
 (4,469)
 
 
 (6,159)
 
 
Removal Costs
 
 (6,709)
 
 
 (6,424)
 
 
 (6,596)
 
 
Investment Tax Credits, Net
 
 (3,967)
 
 
 (4,093)
 
 
 (4,209)
 
 
State and Local Income Taxes
 
 (7,189)
 
 
 (15,821)
 
 
 (7,583)
 
 
Conservation Easement
 
 - 
 
 
 (5,250)
 
 
 - 
 
 
Other
 
 2,007 
 
 
 (293)
 
 
 988 
Total Income Taxes
$
 74,230 
 
$
 45,449 
 
$
 43,938 
 
 
 
 
 
 
 
 
 
Effective Income Tax Rate
 
 35.2 
%
 
 
 22.6 
%
 
 
 26.3 
%

CSPCo
Years Ended December 31,
 
2010 
 
2009 
 
2008 
 
(in thousands)
Net Income
$
 230,223 
 
$
 271,661 
 
$
 237,130 
Income Taxes
 
 131,849 
 
 
 143,721 
 
 
 109,739 
Pretax Income
$
 362,072 
 
$
 415,382 
 
$
 346,869 
 
 
 
 
 
 
 
 
 
Income Taxes on Pretax Income at Statutory Rate (35%)
$
 126,725 
 
$
 145,384 
 
$
 121,404 
Increase (Decrease) in Income Taxes resulting from the following items:
 
 
 
 
 
 
 
 
 
 
Depreciation
 
 5,641 
 
 
 3,775 
 
 
 3,659 
 
 
Investment Tax Credits, Net
 
 (2,046)
 
 
 (1,980)
 
 
 (1,954)
 
 
State and Local Income Taxes
 
 2,759 
 
 
 2,880 
 
 
 964 
 
 
Parent Company Loss Benefit
 
 (7,136)
 
 
 (2,986)
 
 
 (6,663)
 
 
Other
 
 5,906 
 
 
 (3,352)
 
 
 (7,671)
Total Income Taxes
$
 131,849 
 
$
 143,721 
 
$
 109,739 
 
 
 
 
 
 
 
 
 
Effective Income Tax Rate
 
 36.4 
%
 
 
 34.6 
%
 
 
 31.6 
%

 
358
 
I&M
Years Ended December 31,
 
2010 
 
2009 
 
2008 
 
(in thousands)
Net Income
$
 126,091 
 
$
 216,310 
 
$
 131,875 
Income Taxes
 
 63,426 
 
 
 81,037 
 
 
 58,258 
Pretax Income
$
 189,517 
 
$
 297,347 
 
$
 190,133 
 
 
 
 
 
 
 
 
 
Income Taxes on Pretax Income at Statutory Rate (35%)
$
 66,331 
 
$
 104,071 
 
$
 66,547 
Increase (Decrease) in Income Taxes resulting from the following items:
 
 
 
 
 
 
 
 
 
 
Depreciation
 
 11,419 
 
 
 9,550 
 
 
 4,971 
 
 
Nuclear Fuel Disposal Costs
 
 (1,655)
 
 
 (3,249)
 
 
 (4,381)
 
 
AFUDC
 
 (9,032)
 
 
 (7,413)
 
 
 (3,362)
 
 
Removal Costs
 
 (3,663)
 
 
 (5,960)
 
 
 (3,839)
 
 
Investment Tax Credits, Net
 
 (2,316)
 
 
 (2,316)
 
 
 (2,196)
 
 
State and Local Income Taxes
 
 3,966 
 
 
 (15,059)
 
 
 3,077 
 
 
Other
 
 (1,624)
 
 
 1,413 
 
 
 (2,559)
Total Income Taxes
$
 63,426 
 
$
 81,037 
 
$
 58,258 
 
 
 
 
 
 
 
 
 
Effective Income Tax Rate
 
 33.5 
%
 
 
 27.3 
%
 
 
 30.6 
%

OPCo
Years Ended December 31,
 
2010 
 
2009 
 
2008 
 
(in thousands)
Net Income
$
 311,393 
 
$
 308,615 
 
$
 232,455 
Income Taxes
 
 169,457 
 
 
 166,474 
 
 
 114,622 
Pretax Income
$
 480,850 
 
$
 475,089 
 
$
 347,077 
 
 
 
 
 
 
 
 
 
Income Taxes on Pretax Income at Statutory Rate (35%)
$
 168,298 
 
$
 166,281 
 
$
 121,477 
Increase (Decrease) in Income Taxes resulting from the following items:
 
 
 
 
 
 
 
 
 
 
Depreciation
 
 5,802 
 
 
 5,371 
 
 
 4,389 
 
 
Investment Tax Credits, Net
 
 (882)
 
 
 (949)
 
 
 (942)
 
 
State and Local Income Taxes
 
 (1,853)
 
 
 4,766 
 
 
 2,102 
 
 
Other
 
 (1,908)
 
 
 (8,995)
 
 
 (12,404)
Total Income Taxes
$
 169,457 
 
$
 166,474 
 
$
 114,622 
 
 
 
 
 
 
 
 
 
Effective Income Tax Rate
 
 35.2 
%
 
 
 35.0 
%
 
 
 33.0 
%

PSO
Years Ended December 31,
 
2010 
 
2009 
 
2008 
 
(in thousands)
Net Income
$
 72,787 
 
$
 75,602 
 
$
 78,484 
Income Taxes
 
 50,100 
 
 
 43,921 
 
 
 42,277 
Pretax Income
$
 122,887 
 
$
 119,523 
 
$
 120,761 
 
 
 
 
 
 
 
 
 
Income Taxes on Pretax Income at Statutory Rate (35%)
$
 43,010 
 
$
 41,833 
 
$
 42,266 
Increase (Decrease) in Income Taxes resulting from the following items:
 
 
 
 
 
 
 
 
 
 
Depreciation
 
 (166)
 
 
 (174)
 
 
 (502)
 
 
Investment Tax Credits, Net
 
 (781)
 
 
 (770)
 
 
 (834)
 
 
State and Local Income Taxes
 
 10,307 
 
 
 6,025 
 
 
 3,845 
 
 
Other
 
 (2,270)
 
 
 (2,993)
 
 
 (2,498)
Total Income Taxes
$
 50,100 
 
$
 43,921 
 
$
 42,277 
 
 
 
 
 
 
 
 
 
Effective Income Tax Rate
 
 40.8 
%
 
 
 36.7 
%
 
 
 35.0 
%

 
359
 
SWEPCo
Years Ended December 31,
 
2010 
 
2009 
 
2008 
 
(in thousands)
Net Income
$
 146,684 
 
$
 117,203 
 
$
 96,445 
Extraordinary Loss
 
 - 
 
 
 5,325 
 
 
 - 
Income Taxes
 
 64,214 
 
 
 17,511 
 
 
 33,041 
Pretax Income
$
 210,898 
 
$
 140,039 
 
$
 129,486 
 
 
 
 
 
 
 
 
 
Income Taxes on Pretax Income at Statutory Rate (35%)
$
 73,814 
 
$
 49,014 
 
$
 45,320 
Increase (Decrease) in Income Taxes resulting from the following items:
 
 
 
 
 
 
 
 
 
 
Depreciation
 
 1,223 
 
 
 1,506 
 
 
 502 
 
 
Depletion
 
 (1,506)
 
 
 (3,150)
 
 
 (3,158)
 
 
AFUDC
 
 (15,856)
 
 
 (16,243)
 
 
 (5,114)
 
 
Investment Tax Credits, Net
 
 (1,484)
 
 
 (3,542)
 
 
 (3,964)
 
 
State and Local Income Taxes
 
 (637)
 
 
 647 
 
 
 4,121 
 
 
Parent Company Loss Benefit
 
 - 
 
 
 (4,232)
 
 
 - 
 
 
Other
 
 8,660 
 
 
 (6,489)
 
 
 (4,666)
Total Income Taxes
$
 64,214 
 
$
 17,511 
 
$
 33,041 
 
 
 
 
 
 
 
 
 
Effective Income Tax Rate
 
 30.4 
%
 
 
 12.5 
%
 
 
 25.5 
%

The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant Subsidiary.

APCo
 
December 31,
 
 
2010 
 
2009 
 
 
(in thousands)
Deferred Tax Assets
 
$
 417,393 
 
$
 404,253 
Deferred Tax Liabilities
 
 
 (2,103,645)
 
 
 (1,912,843)
Net Deferred Tax Liabilities
 
$
 (1,686,252)
 
$
 (1,508,590)
 
 
 
 
 
 
 
Property Related Temporary Differences
 
$
 (1,151,667)
 
$
 (1,027,656)
Amounts Due from Customers for Future Federal Income Taxes
 
 
 (104,995)
 
 
 (106,519)
Deferred State Income Taxes
 
 
 (242,579)
 
 
 (202,987)
Deferred Income Taxes on Other Comprehensive Loss
 
 
 25,859 
 
 
 27,060 
Deferred Fuel and Purchased Power
 
 
 (129,671)
 
 
 (126,230)
Accrued Pensions
 
 
 52,406 
 
 
 58,779 
Regulatory Assets
 
 
 (179,686)
 
 
 (185,880)
All Other, Net
 
 
 44,081 
 
 
 54,843 
Net Deferred Tax Liabilities
 
$
 (1,686,252)
 
$
 (1,508,590)

CSPCo
 
December 31,
 
 
2010 
 
2009 
 
 
(in thousands)
Deferred Tax Assets
 
$
 143,453 
 
$
 124,087 
Deferred Tax Liabilities
 
 
 (761,834)
 
 
 (682,624)
Net Deferred Tax Liabilities
 
$
 (618,381)
 
$
 (558,537)
 
 
 
 
 
 
 
Property Related Temporary Differences
 
$
 (576,649)
 
$
 (493,879)
Amounts Due from Customers for Future Federal Income Taxes
 
 
 (1,013)
 
 
 (3,182)
Deferred State Income Taxes
 
 
 (7,251)
 
 
 (9,161)
Deferred Income Taxes on Other Comprehensive Loss
 
 
 27,642 
 
 
 26,920 
Accrued Pensions
 
 
 6,927 
 
 
 8,140 
Regulatory Assets
 
 
 (78,623)
 
 
 (74,298)
All Other, Net
 
 
 10,586 
 
 
 (13,077)
Net Deferred Tax Liabilities
 
$
 (618,381)
 
$
 (558,537)

 
360
 
I&M
 
December 31,
 
 
2010 
 
2009 
 
 
(in thousands)
Deferred Tax Assets
 
$
 751,455 
 
$
 722,974 
Deferred Tax Liabilities
 
 
 (1,530,993)
 
 
 (1,428,710)
Net Deferred Tax Liabilities
 
$
 (779,538)
 
$
 (705,736)
 
 
 
 
 
 
 
Property Related Temporary Differences
 
$
 (246,395)
 
$
 (224,113)
Amounts Due from Customers for Future Federal Income Taxes
 
 
 (27,932)
 
 
 (25,573)
Deferred State Income Taxes
 
 
 (79,522)
 
 
 (80,345)
Deferred Income Taxes on Other Comprehensive Loss
 
 
 11,248 
 
 
 11,685 
Accrued Nuclear Decommissioning Expense
 
 
 (394,441)
 
 
 (354,534)
Post Retirement Benefits
 
 
 41,727 
 
 
 34,236 
Accrued Pensions
 
 
 36,564 
 
 
 49,086 
Regulatory Assets
 
 
 (108,842)
 
 
 (102,247)
All Other, Net
 
 
 (11,945)
 
 
 (13,931)
Net Deferred Tax Liabilities
 
$
 (779,538)
 
$
 (705,736)

OPCo
 
December 31,
 
 
2010 
 
2009 
 
 
(in thousands)
Deferred Tax Assets
 
$
 290,613 
 
$
 270,381 
Deferred Tax Liabilities
 
 
 (1,841,019)
 
 
 (1,601,472)
Net Deferred Tax Liabilities
 
$
 (1,550,406)
 
$
 (1,331,091)
 
 
 
 
 
 
 
Property Related Temporary Differences
 
$
 (1,263,137)
 
$
 (1,127,166)
Amounts Due from Customers for Future Federal Income Taxes
 
 
 (56,506)
 
 
 (53,651)
Deferred State Income Taxes
 
 
 (99,508)
 
 
 (88,489)
Deferred Income Taxes on Other Comprehensive Loss
 
 
 69,364 
 
 
 63,785 
Deferred Fuel and Purchased Power
 
 
 (177,057)
 
 
 (109,204)
Accrued Pensions
 
 
 (8,852)
 
 
 3,602 
Regulatory Assets
 
 
 (71,219)
 
 
 (74,769)
All Other, Net
 
 
 56,509 
 
 
 54,801 
Net Deferred Tax Liabilities
 
$
 (1,550,406)
 
$
 (1,331,091)

PSO
 
December 31,
 
 
2010 
 
2009 
 
 
(in thousands)
Deferred Tax Assets
 
$
 90,750 
 
$
 101,346 
Deferred Tax Liabilities
 
 
 (751,592)
 
 
 (663,779)
Net Deferred Tax Liabilities
 
$
 (660,842)
 
$
 (562,433)
 
 
 
 
 
 
 
Property Related Temporary Differences
 
$
 (561,364)
 
$
 (500,832)
Amounts Due from Customers for Future Federal Income Taxes
 
 
 (242)
 
 
 1,901 
Deferred State Income Taxes
 
 
 (76,254)
 
 
 (60,408)
Deferred Income Taxes on Other Comprehensive Loss
 
 
 (4,574)
 
 
 322 
Accrued Pensions
 
 
 18,389 
 
 
 23,382 
Regulatory Assets
 
 
 (74,404)
 
 
 (75,101)
All Other, Net
 
 
 37,607 
 
 
 48,303 
Net Deferred Tax Liabilities
 
$
 (660,842)
 
$
 (562,433)

 
361
 
SWEPCo
 
December 31,
 
 
2010 
 
2009 
 
 
(in thousands)
Deferred Tax Assets
 
$
 104,444 
 
$
 89,938 
Deferred Tax Liabilities
 
 
 (713,248)
 
 
 (562,054)
Net Deferred Tax Liabilities
 
$
 (608,804)
 
$
 (472,116)
 
 
 
 
 
 
 
Property Related Temporary Differences
 
$
 (521,210)
 
$
 (422,726)
Amounts Due from Customers for Future Federal Income Taxes
 
 
 (25,800)
 
 
 (13,927)
Deferred State Income Taxes
 
 
 (56,315)
 
 
 (32,260)
Deferred Income Taxes on Other Comprehensive Loss
 
 
 6,726 
 
 
 6,995 
Accrued Pensions
 
 
 9,821 
 
 
 20,581 
Regulatory Assets
 
 
 (41,956)
 
 
 (52,894)
All Other, Net
 
 
 19,930 
 
 
 22,115 
Net Deferred Tax Liabilities
 
$
 (608,804)
 
$
 (472,116)

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.

The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2001.  The Registrant Subsidiaries have completed the exam for the years 2001 through 2006 and have issues that are being pursued at the appeals level.  The years 2007 and 2008 are currently under examination.  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 have a material adverse effect on 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.  Management believes that previously filed tax returns have positions that may be challenged by these tax authorities.  However, 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.  With few exceptions, the Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2000.

APCo, I&M, OPCo and PSO sustained federal, state and local net income tax operating losses in 2009 driven primarily by bonus depreciation, a change in tax accounting method related to units of property and other book versus tax temporary differences.  As a result, these registrant subsidiaries accrued current federal, state and local income tax benefits in 2009.  These registrant subsidiaries realized the federal cash flow benefit in 2010 as there was sufficient capacity in prior periods to carry the consolidated federal net operating loss back.  Most of the registrant subsidiaries’ state and local jurisdictions do not provide for a net operating loss carry back.  It is anticipated that future taxable income will be sufficient to realize the tax benefit.  As such, management has determined that a valuation allowance is unnecessary.

The Registrant Subsidiaries recognize interest accruals related to uncertain tax positions in interest income or expense as applicable and penalties in Other Operation in accordance with the accounting guidance for “Income Taxes.”

 
362
 
The following tables show amounts reported for interest expense, interest income and reversal of prior period interest expense:

 
 
 
Years Ended December 31,
 
 
 
2010 
 
2009 
 
 
 
 
 
 
 
Reversal of
 
 
 
 
 
Reversal of
 
 
 
 
 
 
 
Prior Period
 
 
 
 
 
Prior Period
 
 
 
Interest
 
Interest
 
Interest
 
Interest
 
Interest
 
Interest
Company
 
Expense
 
Income
 
Expense
 
Expense
 
Income
 
Expense
 
 
(in thousands)
 
APCo
 
$
 2,330 
 
$
 - 
 
$
 1,146 
 
$
 593 
 
$
 - 
 
$
 1,803 
 
CSPCo
 
 
 1,549 
 
 
 - 
 
 
 39 
 
 
 1,091 
 
 
 - 
 
 
 200 
 
I&M
 
 
 - 
 
 
 209 
 
 
 159 
 
 
 - 
 
 
 4,090 
 
 
 119 
 
OPCo
 
 
 2,399 
 
 
 - 
 
 
 1,614 
 
 
 2,221 
 
 
 - 
 
 
 1,495 
 
PSO
 
 
 455 
 
 
 - 
 
 
 871 
 
 
 - 
 
 
 721 
 
 
 382 
 
SWEPCo
 
 
 749 
 
 
 - 
 
 
 320 
 
 
 12 
 
 
 424 
 
 
 428 

 
 
Year Ended December 31, 2008
 
 
 
 
 
 
Reversal of
 
 
 
 
 
 
 
 
Prior Period
 
 
Interest
 
Interest
 
Interest
Company
 
Expense
 
Income
 
Expense
 
 
(in thousands)
APCo
 
$
 2,365 
 
$
 5,367 
 
$
 2,635 
CSPCo
 
 
 153 
 
 
 3,304 
 
 
 3,411 
I&M
 
 
 179 
 
 
 1,371 
 
 
 5,650 
OPCo
 
 
 4,093 
 
 
 5,755 
 
 
 295 
PSO
 
 
 2,008 
 
 
 - 
 
 
 - 
SWEPCo
 
 
 1,340 
 
 
 1,585 
 
 
 - 

The following table shows balances for amounts accrued for the receipt of interest:

 
 
December 31,
Company
 
2010 
 
2009 
 
 
(in thousands)
APCo
 
$
 934 
 
$
 2,187 
CSPCo
 
 
 2,784 
 
 
 2,281 
I&M
 
 
7,642 
 
 
 5,764 
OPCo
 
 
6 
 
 
 1,339 
PSO
 
 
- 
 
 
 1,735 
SWEPCo
 
 
957 
 
 
 1,262 

The following table shows balances for amounts accrued for the payment of interest and penalties:

 
 
December 31,
Company
 
2010 
 
2009 
 
 
(in thousands)
APCo
 
$
 1,274 
 
$
 1,733 
CSPCo
 
 
 2,219 
 
 
 206 
I&M
 
 
 1,823 
 
 
 439 
OPCo
 
 
 3,858 
 
 
 4,411 
PSO
 
 
 877 
 
 
 3,028 
SWEPCo
 
 
 1,107 
 
 
 983 

 
363
 
The reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
(in thousands)
Balance at January 1, 2010
$
 17,292 
 
$
 16,738 
 
$
 20,007 
 
$
 48,813 
 
$
 12,216 
 
$
 10,163 
Increase - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 a Prior Period
 
 4,177 
 
 
 10,110 
 
 
 4,964 
 
 
 9,104 
 
 
 151 
 
 
 6,128 
Decrease - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 a Prior Period
 
 (6,376)
 
 
 (1,496)
 
 
 (5,287)
 
 
 (7,341)
 
 
 (1,200)
 
 
 (376)
Decrease - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 the Current Year
 
 (1,015)
 
 
 (597)
 
 
 (1,487)
 
 
 (1,152)
 
 
 (517)
 
 
 (691)
Decrease - Settlements with Taxing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Authorities
 
 (811)
 
 
 - 
 
 
 (236)
 
 
 (70)
 
 
 (265)
 
 
 (4)
Decrease - Lapse of the Applicable
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Statute of Limitations
 
 - 
 
 
 - 
 
 
 (90)
 
 
 (5,454)
 
 
 (540)
 
 
 (810)
Balance at December 31, 2010
$
 13,267 
 
$
 24,755 
 
$
 17,871 
 
$
 43,900 
 
$
 9,845 
 
$
 14,410 

 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
(in thousands)
Balance at January 1, 2009
$
 20,573 
 
$
 21,179 
 
$
 11,815 
 
$
 52,338 
 
$
 13,310 
 
$
 10,252 
Increase - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 a Prior Period
 
 5,339 
 
 
 6,068 
 
 
 8,336 
 
 
 11,970 
 
 
 2,304 
 
 
 4,102 
Decrease - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 a Prior Period
 
 (8,263)
 
 
 (9,994)
 
 
 (14,921)
 
 
 (14,030)
 
 
 (2,322)
 
 
 (3,065)
Increase - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 the Current Year
 
 2,471 
 
 
 - 
 
 
 14,398 
 
 
 890 
 
 
 - 
 
 
 - 
Decrease - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 the Current Year
 
 - 
 
 
 (195)
 
 
 - 
 
 
 - 
 
 
 (533)
 
 
 (357)
Increase - Settlements with Taxing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Authorities
 
 - 
 
 
 - 
 
 
 645 
 
 
 - 
 
 
 - 
 
 
 - 
Decrease - Lapse of the Applicable
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Statute of Limitations
 
 (2,828)
 
 
 (320)
 
 
 (266)
 
 
 (2,355)
 
 
 (543)
 
 
 (769)
Balance at December 31, 2009
$
 17,292 
 
$
 16,738 
 
$
 20,007 
 
$
 48,813 
 
$
 12,216 
 
$
 10,163 

 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
(in thousands)
Balance at January 1, 2008
$
 19,741 
 
$
 19,753 
 
$
 11,317 
 
$
 51,982 
 
$
 14,105 
 
$
 6,610 
Increase - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 a Prior Period
 
 1,617 
 
 
 1,198 
 
 
 100 
 
 
 3,133 
 
 
 1,322 
 
 
 2,233 
Decrease - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 a Prior Period
 
 (486)
 
 
 (1,207)
 
 
 (2,976)
 
 
 (2,692)
 
 
 (6,383)
 
 
 (2,271)
Increase - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 the Current Year
 
 2,891 
 
 
 1,575 
 
 
 3,335 
 
 
 2,446 
 
 
 4,806 
 
 
 4,193 
Decrease - Tax Positions Taken During
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 the Current Year
 
 (1,931)
 
 
 (311)
 
 
 (436)
 
 
 (835)
 
 
 (540)
 
 
 (395)
Increase - Settlements with Taxing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Authorities
 
 906 
 
 
 171 
 
 
 745 
 
 
 192 
 
 
 - 
 
 
 - 
Decrease - Settlements with Taxing
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Authorities
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (28)
Decrease - Lapse of the Applicable
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 Statute of Limitations
 
 (2,165)
 
 
 - 
 
 
 (270)
 
 
 (1,888)
 
 
 - 
 
 
 (90)
Balance at December 31, 2008
$
 20,573 
 
$
 21,179 
 
$
 11,815 
 
$
 52,338 
 
$
 13,310 
 
$
 10,252 

 
364
 
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
 
2010 
 
2009 
 
2008 
 
 
(in thousands)
APCo
 
$
 1,109 
 
$
 3,777 
 
$
 5,738 
CSPCo
 
 
 10,626 
 
 
 9,709 
 
 
 11,954 
I&M
 
 
 1,664 
 
 
 1,271 
 
 
 6,283 
OPCo
 
 
 18,123 
 
 
 23,795 
 
 
 27,307 
PSO
 
 
 1,977 
 
 
 2,985 
 
 
 2,974 
SWEPCo
 
 
 2,481 
 
 
 2,278 
 
 
 2,205 

Federal Tax Legislation – Affecting APCo

Under the Energy Tax Incentives Act of 2005, AEP filed applications with the United States Department of Energy and the IRS in 2008 for the West Virginia IGCC project and in July 2008 the IRS allocated the project $134 million in credits.  In September 2008, AEP entered into a memorandum of understanding with the IRS concerning the requirements of claiming the credits.  AEP had until July 2010 to meet certain minimum requirements under the agreement with the IRS or the credits would be forfeited.  In July 2010, AEP forfeited the allocated tax credits.

Federal Tax Legislation – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

The Economic Stimulus Act of 2008 provided enhanced expensing provisions for certain assets placed in service in 2008 and a 50% bonus depreciation provision similar to the one in effect in 2003 through 2004 for assets placed in service in 2008.  The enacted provisions did not have a material impact on net income or financial condition, but provided a material favorable cash flow benefit for each Registrant Subsidiary as follows:

Company
 
(in thousands)
 
 
 
 
APCo
 
$
 37,831 
CSPCo
 
 
 16,776 
I&M
 
 
 21,830 
OPCo
 
 
 37,696 
PSO
 
 
 6,838 
SWEPCo
 
 
 25,872 

The American Recovery and Reinvestment Act of 2009 provided for several new grant programs and expanded tax credits and an extension of the 50% bonus depreciation provision enacted in the Economic Stimulus Act of 2008.  The enacted provisions did not have a material impact on net income or financial condition.  However, the bonus depreciation contributed to AEP’s 2009 federal net operating tax loss that resulted in a 2010 cash flow benefit to the Registrant Subsidiaries as follows:

Company
 
(in thousands)
 
 
 
 
APCo
 
$
 170,466 
CSPCo
 
 
 3,192 
I&M
 
 
 78,456 
OPCo
 
 
 137,919 
PSO
 
 
 10,741 
SWEPCo
 
 
 - 

The Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act (Health Care Acts) were enacted in March 2010.  The Health Care Acts amend tax rules so that the portion of employer health care costs that are reimbursed by the Medicare Part D prescription drug subsidy will no longer be deductible by the employer for federal income tax purposes effective for years beginning after December 31, 2012.  Because of the loss of the future tax deduction, a reduction in the deferred tax asset related to the nondeductible OPEB liabilities accrued to date
 
 
365
 
was recorded by the Registrant Subsidiaries in March 2010.  This reduction did not materially affect the Registrant Subsidiaries' cash flows or financial condition.  For the year ended December 31, 2010, the Registrant Subsidiaries reflected a decrease in deferred tax assets, which was partially offset by recording net tax regulatory assets in jurisdictions with regulated operations, resulting in a decrease in net income as follows:

 
 
Net Reduction
 
Tax
 
 
 
 
to Deferred
 
Regulatory
 
Decrease in
Company
 
Tax Assets
 
Assets, Net
 
Net Income
 
 
(in thousands)
APCo
 
$
 9,397 
 
$
8,831 
 
$
 566 
CSPCo
 
 
 4,386 
 
 
2,970 
 
 
 1,416 
I&M
 
 
 7,212 
 
 
6,528 
 
 
 684 
OPCo
 
 
 8,385 
 
 
4,020 
 
 
 4,365 
PSO
 
 
 3,172 
 
 
3,172 
 
 
 - 
SWEPCo
 
 
 3,412 
 
 
3,412 
 
 
 - 

The Small Business Jobs Act (the Act) was enacted in September 2010.  Included in the Act was a one-year extension of the 50% bonus depreciation provision.  The Tax Relief, Unemployment Insurance Reauthorization and the Job Creation Act of 2010 extended the life of research and development, employment and several energy tax credits originally scheduled to expire at the end of 2010.  In addition, the Act extended the time for claiming bonus depreciation and increased the deduction to 100% for part of 2010 and 2011.  The enacted provisions will not have a material impact on the Registrant Subsidiaries’ net income or financial condition but had a favorable impact on cash flows in 2010 as follows:

Company
 
(in thousands)
APCo
 
$
 43,379 
CSPCo
 
 
 85,180 
I&M
 
 
 49,740 
OPCo
 
 
 39,457 
PSO
 
 
 - 
SWEPCo
 
 
 30,269 

State Tax Legislation – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

Under Ohio House Bill 66, in 2005, AEP reversed deferred state income tax liabilities that are not expected to reverse during the phase-out as follows:

 
 
Other
 
 
 
 
 
 
Deferred State
 
 
Regulatory
 
Regulatory
 
State Income
 
Income Tax
Company
 
Liabilities (a)
 
Asset, Net (b)
 
Tax Expense (c)
 
Liabilities (d)
 
 
(in thousands)
APCo
 
$
 - 
 
$
 10,945 
 
$
 2,769 
 
$
 13,714 
CSPCo
 
 
 15,104 
 
 
 - 
 
 
 - 
 
 
 15,104 
I&M
 
 
 - 
 
 
 5,195 
 
 
 - 
 
 
 5,195 
OPCo
 
 
 41,864 
 
 
 - 
 
 
 - 
 
 
 41,864 
PSO
 
 
 - 
 
 
 - 
 
 
 706 
 
 
 706 
SWEPCo
 
 
 - 
 
 
 582 
 
 
 119 
 
 
 701 

(a)  
The reversal of deferred state income taxes for CSPCo and OPCo was recorded as a regulatory liability pending rate-making treatment in Ohio.
(b)  
Deferred state income tax adjustments related to those companies in which state income taxes flow through for rate-making purposes reduced the regulatory asset associated with the deferred state income tax liabilities.
(c)  
These amounts were recorded as a reduction to Income Tax Expense.
(d)  
Total deferred state income tax liabilities that reversed during 2005 related to Ohio law change.

 
366
 
In November 2006, the PUCO ordered OPCo and CSPCo to amortize $42 million and $15 million, respectively, to income as an offset to power supply contract losses incurred by OPCo and CSPCo for sales to Ormet and as of December 31, 2008, both regulatory liabilities were fully amortized.

The Ohio legislation also imposed a new commercial activity tax at a fully phased-in rate of 0.26% on all Ohio gross receipts.  The tax was phased-in over a five-year period that began July 1, 2005 at 23% of the full 0.26% rate.  As a result of this tax, expenses of approximately $6 million, $5 million and $4 million each for CSPCo and OPCo were recorded in 2010, 2009 and 2008, respectively, in Taxes Other Than Income Taxes.

State Tax Legislation – Affecting APCo, CSPCo, I&M and OPCo

Michigan Senate Bill 0094 (MBT Act), effective January 1, 2008, provided a comprehensive restructuring of Michigan’s principal business tax.  The law replaced the Michigan Single Business Tax.  The MBT Act is composed of a new tax which will be calculated based upon two components:  (a) a business income tax (BIT) imposed at a rate of 4.95% and (b) a modified gross receipts tax (GRT) imposed at a rate of 0.80%, which will collectively be referred to as the BIT/GRT tax calculation.  The law also includes significant credits for engaging in Michigan-based activity.

In September 2007, House Bill 5198 amended the MBT Act to provide for a new deduction on the BIT and GRT tax returns equal to the book-tax basis difference triggered as a result of the enactment of the MBT Act.  This state-only temporary difference will be deducted over a 15 year period on the MBT Act tax returns starting in 2015.  Management has evaluated the impact of the MBT Act and the application of the MBT Act will not materially affect net income, cash flows or financial condition.

In March 2008, legislation was signed providing for, among other things, a reduction in the West Virginia corporate income tax rate from 8.75% to 8.5% beginning in 2009.  The corporate income tax rate could also be reduced to 7.75% in 2012 and 7% in 2013 contingent upon the state government achieving certain minimum levels of shortfall reserve funds.  Management has evaluated the impact of the law change and the application of the law change will not materially impact net income, cash flows or financial condition.

13.   LEASES

Leases of property, plant and equipment are for periods up to 60 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.  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, 2010
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Net Lease Expense on Operating Leases
 
$
 18,034 
 
$
 40,011 
 
$
 91,973 
 
$
 22,876 
 
$
 2,649 
 
$
 5,877 
Amortization of Capital Leases
 
 
 7,002 
 
 
 4,204 
 
 
 31,178 
 
 
 7,865 
 
 
 3,992 
 
 
 11,742 
Interest on Capital Leases
 
 
 1,598 
 
 
 639 
 
 
 2,298 
 
 
 2,493 
 
 
 1,057 
 
 
 9,892 
Total Lease Rental Costs
 
$
 26,634 
 
$
 44,854 
 
$
 125,449 
 
$
 33,234 
 
$
 7,698 
 
$
 27,511 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2009
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Net Lease Expense on Operating Leases
 
$
 21,001 
 
$
 45,124 
 
$
 94,409 
 
$
 28,334 
 
$
 5,807 
 
$
 8,052 
Amortization of Capital Leases
 
 
 3,480 
 
 
 2,715 
 
 
 31,612 
 
 
 4,688 
 
 
 1,485 
 
 
 10,739 
Interest on Capital Leases
 
 
 206 
 
 
 140 
 
 
 1,937 
 
 
 1,284 
 
 
 85 
 
 
 6,372 
Total Lease Rental Costs
 
$
 24,687 
 
$
 47,979 
 
$
 127,958 
 
$
 34,306 
 
$
 7,377 
 
$
 25,163 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year Ended December 31, 2008
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Net Lease Expense on Operating Leases
 
$
 18,840 
 
$
 42,330 
 
$
 96,595 
 
$
 25,876 
 
$
 6,995 
 
$
 8,519 
Amortization of Capital Leases
 
 
 4,820 
 
 
 3,329 
 
 
 39,697 
 
 
 6,369 
 
 
 1,550 
 
 
 6,926 
Interest on Capital Leases
 
 
 525 
 
 
 482 
 
 
 5,311 
 
 
 1,606 
 
 
 140 
 
 
 3,855 
Total Lease Rental Costs
 
$
 24,185 
 
$
 46,141 
 
$
 141,603 
 
$
 33,851 
 
$
 8,685 
 
$
 19,300 

 
367
 
The following table shows the property, plant and equipment under capital leases and related obligations recorded on the Registrant Subsidiaries’ balance sheets.  For I&M, current capital lease obligations are included in Obligations Under Capital Leases on I&M’s Consolidated Balance Sheets.  For all other Registrant Subsidiaries, current capital lease obligations are included in Other Current Liabilities.  For all Registrant Subsidiaries, long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrant Subsidiaries’ balance sheets.

December 31, 2010
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Property, Plant and Equipment Under
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital Leases:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Generation
 
$
 10,255 
 
$
 1,696 
 
$
 19,147 
 
$
 32,524 
 
$
 3,471 
 
$
 15,528 
Distribution
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Other Property, Plant and Equipment
 
 
 29,154 
 
 
 14,144 
 
 
 26,922 
 
 
 29,965 
 
 
 19,256 
 
 
 142,210 
Construction Work in Progress
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Total Property, Plant and Equipment
 
 
 39,409 
 
 
 15,840 
 
 
 46,069 
 
 
 62,489 
 
 
 22,727 
 
 
 157,738 
Accumulated Amortization
 
 
 6,678 
 
 
 3,953 
 
 
 10,366 
 
 
 15,010 
 
 
 4,338 
 
 
 29,370 
Net Property, Plant and Equipment
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Under Capital Leases
 
$
 32,731 
 
$
 11,887 
 
$
 35,703 
 
$
 47,479 
 
$
 18,389 
 
$
 128,368 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Obligations Under Capital Leases:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncurrent Liability
 
$
 24,617 
 
$
 7,965 
 
$
 26,858 
 
$
 38,237 
 
$
 13,838 
 
$
 115,399 
Liability Due Within One Year
 
 
 8,114 
 
 
 3,990 
 
 
 8,845 
 
 
 12,070 
 
 
 4,551 
 
 
 13,265 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Obligations Under Capital Leases
 
$
 32,731 
 
$
 11,955 
 
$
 35,703 
 
$
 50,307 
 
$
 18,389 
 
$
 128,664 

December 31, 2009
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Property, Plant and Equipment Under
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital Leases:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Generation
 
$
 90 
 
$
 6,989 
 
$
 16,363 
 
$
 23,018 
 
$
 2,041 
 
$
 13,869 
Distribution
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Other Property, Plant and Equipment
 
 
 15,401 
 
 
 8,477 
 
 
 50,587 
 
 
 13,344 
 
 
 6,973 
 
 
 164,632 
Construction Work in Progress
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
Total Property, Plant and Equipment
 
 
 15,491 
 
 
 15,466 
 
 
 66,950 
 
 
 36,362 
 
 
 9,014 
 
 
 178,501 
Accumulated Amortization
 
 
 8,007 
 
 
 10,769 
 
 
 14,400 
 
 
 16,066 
 
 
 3,544 
 
 
 30,858 
Net Property, Plant and Equipment
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Under Capital Leases
 
$
 7,484 
 
$
 4,697 
 
$
 52,550 
 
$
 20,296 
 
$
 5,470 
 
$
 147,643 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Obligations Under Capital Leases:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncurrent Liability
 
$
 4,539 
 
$
 2,452 
 
$
 27,485 
 
$
 16,926 
 
$
 3,722 
 
$
 134,044 
Liability Due Within One Year
 
 
 2,945 
 
 
 2,274 
 
 
 25,065 
 
 
 5,756 
 
 
 1,748 
 
 
 14,617 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Obligations Under Capital Leases
 
$
 7,484 
 
$
 4,726 
 
$
 52,550 
 
$
 22,682 
 
$
 5,470 
 
$
 148,661 

 
368
 
Future minimum lease payments consisted of the following at December 31, 2010:

Capital Leases
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
2011 
 
$
 9,529 
 
$
 4,472 
 
$
 10,345 
 
$
 11,702 
 
$
 5,448 
 
$
 22,306 
2012 
 
 
 8,571 
 
 
 2,769 
 
 
 9,144 
 
 
 9,377 
 
 
 4,208 
 
 
 21,722 
2013 
 
 
 5,901 
 
 
 2,379 
 
 
 4,702 
 
 
 8,902 
 
 
 3,610 
 
 
 20,540 
2014 
 
 
 3,616 
 
 
 1,820 
 
 
 3,779 
 
 
 6,665 
 
 
 2,689 
 
 
 19,079 
2015 
 
 
 2,885 
 
 
 695 
 
 
 2,742 
 
 
 4,773 
 
 
 1,475 
 
 
 17,053 
Later Years
 
 
 6,897 
 
 
 1,284 
 
 
 15,933 
 
 
 21,952 
 
 
 4,082 
 
 
 78,506 
Total Future Minimum Lease
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Payments
 
 
 37,399 
 
 
 13,419 
 
 
 46,645 
 
 
 63,371 
 
 
 21,512 
 
 
 179,206 
Less Estimated Interest Element
 
 
 4,668 
 
 
 1,464 
 
 
 10,942 
 
 
 13,064 
 
 
 3,123 
 
 
 50,542 
Estimated Present Value of Future
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Minimum Lease Payments
 
$
 32,731 
 
$
 11,955 
 
$
 35,703 
 
$
 50,307 
 
$
 18,389 
 
$
 128,664 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncancelable Operating Leases
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
2011 
 
$
 14,339 
 
$
 38,904 
 
$
 97,750 
 
$
 20,708 
 
$
 2,281 
 
$
 6,015 
2012 
 
 
 11,505 
 
 
 36,479 
 
 
 95,170 
 
 
 19,379 
 
 
 2,031 
 
 
 4,861 
2013 
 
 
 9,939 
 
 
 34,911 
 
 
 94,612 
 
 
 18,978 
 
 
 1,464 
 
 
 4,199 
2014 
 
 
 9,311 
 
 
 33,456 
 
 
 93,880 
 
 
 18,687 
 
 
 949 
 
 
 3,140 
2015 
 
 
 8,332 
 
 
 31,920 
 
 
 90,786 
 
 
 17,408 
 
 
 626 
 
 
 2,599 
Later Years
 
 
 57,971 
 
 
 60,936 
 
 
 561,803 
 
 
 71,457 
 
 
 974 
 
 
 12,518 
Total Future Minimum Lease
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Payments
 
$
 111,397 
 
$
 236,606 
 
$
 1,034,001 
 
$
 166,617 
 
$
 8,325 
 
$
 33,332 

Master Lease Agreements

The Registrant Subsidiaries lease certain equipment under master lease agreements.  In December 2010, management signed a new master lease agreement with GE Capital Commercial Inc. (GE) to replace existing operating and capital leases with GE.  These assets were included in existing master lease agreements that were to be terminated in 2011 since GE exercised the termination provision related to these leases in 2008.  Certain assets were not included in the refinancing, but the assets will be purchased or refinanced in 2011.  In addition, certain operating leases that were previously under lease with GE are now recorded as capital leases after the refinancing.    The amounts refinanced for the Registrant Subsidiaries are as follows:

Leases Refinanced with GE
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
(in thousands)
Operating Lease to Operating Lease
 
$
 6,815 
 
$
 8,382 
 
$
 12,245 
 
$
 7,443 
 
$
 2,458 
 
$
 13,091 
Capital Lease to Capital Lease
 
 
 1,602 
 
 
 965 
 
 
 6,749 
 
 
 1,491 
 
 
 522 
 
 
 652 
Operating Lease to Capital Lease
 
 
 11,252 
 
 
 1,906 
 
 
 4,984 
 
 
 10,087 
 
 
 3,205 
 
 
 4,574 

These obligations are included in the future minimum lease payments schedule earlier in this note.

 
369
 
For equipment under the GE master lease agreements, the lessor is guaranteed receipt of up to 84% of the unamortized balance of the equipment at the end of the lease term.  If the fair value of the leased equipment is below the unamortized balance at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the fair value and the unamortized balance, with the total guarantee not to exceed 84% of the unamortized balance.  For equipment under other master 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.  At December 31, 2010, 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
 
Maximum
   
Potential
 
Potential Loss
Company
 
Loss
 
Net of Tax
   
(in thousands)
APCo
 
$
1,197 
 
$
778
CSPCo
   
888 
   
577
I&M
   
1,768 
   
1,149
OPCo
   
1,216 
   
790
PSO
   
616 
   
400
SWEPCo
   
2,572 
   
1,672

Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.

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.  Neither AEGCo, I&M nor AEP has an 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, 2010 are as follows:

Future Minimum Lease Payments
 
I&M
 
 
 
(in millions)
2011 
 
$
 74 
2012 
 
 
 74 
2013 
 
 
 74 
2014 
 
 
 74 
2015 
 
 
 74 
Later Years
 
 
 517 
Total Future Minimum Lease Payments
 
$
 887 

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
 
 
370
 
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 $17 million for I&M and $19 million for SWEPCo for the remaining railcars as of December 31, 2010.  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 84% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  I&M’s maximum potential loss related to the guarantee is approximately $12 million ($8 million, net of tax) and SWEPCo’s is approximately $13 million ($ 9 million, net of tax) 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, an entity consolidated in accordance with the accounting guidance for “Variable Interest Entities,” 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.  In addition to the 2009 transactions, Sabine has one additional $53 million dragline completed in 2008 that was financed under a capital lease.  These capital lease assets are included in Other Property, Plant and Equipment on SWEPCo’s December 31, 2010 and 2009 Consolidated 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 SWEPCo’s December 31, 2010 and 2009 Consolidated 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 December 2007, I&M entered into a sale-and-leaseback transaction with Citicorp Leasing, Inc. (CLI), an unrelated, unconsolidated, wholly-owned subsidiary of Citibank, N.A. to lease nuclear fuel for I&M’s Cook Plant.  In December 2007, I&M sold a portion of its unamortized nuclear fuel inventory to CLI at cost for $85 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 60 months.  The future payment obligations of $3 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 Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities, respectively, on I&M’s December 31, 2010 and 2009 Consolidated Balance Sheets.  The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2010 are as follows, based on estimated fuel burn:

Future Minimum Lease Payments
 
Amount
 
 
(in millions)
2011 
 
$
 2 
2012 
 
 
 1 
Total Future Minimum Lease Payments
 
$
 3 

 
371
 
14.   FINANCING ACTIVITIES

Preferred Stock

 
 
 
 
 
 
 
Shares
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding at
 
Call Price at
 
 
 
 
 
 
 
 
 
 
 
 
 
Par
 
Authorized
 
December 31,
 
December 31,
 
 
 
 
 
 
 
December 31,
Company
 
Value
 
Shares
 
2010 
 
2010 (a)
 
Series
 
Redemption
 
2010 
 
2009 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands)
APCo
 
$
- 
(b)
8,000,000 
 
177,465 
 
$
 110.00 
 
4.50 
%
 
Any time
 
$
 17,747 
 
$
 17,752 
CSPCo
 
 
25 
 
7,000,000 
 
 - 
 
 
 - 
 
 - 
 
 
-
 
 
 - 
 
 
 - 
CSPCo
 
 
100 
 
2,500,000 
 
 - 
 
 
 - 
 
 - 
 
 
-
 
 
 - 
 
 
 - 
I&M
 
 
25 
 
11,200,000 
 
 - 
 
 
 - 
 
 - 
 
 
-
 
 
 - 
 
 
 - 
I&M
 
 
100 
 
(c)
 
55,257 
 
 
 106.13 
 
4.125 
%
 
Any time
 
 
 5,525 
 
 
 5,530 
I&M
 
 
100 
 
(c)
 
14,412 
 
 
 102.00 
 
4.56 
%
 
Any time
 
 
 1,441 
 
 
 1,441 
I&M
 
 
100 
 
(c)
 
11,055 
 
 
 102.73 
 
4.12 
%
 
Any time
 
 
 1,106 
 
 
 1,106 
OPCo
 
 
25 
 
4,000,000 
 
 - 
 
 
 - 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
OPCo
 
 
100 
 
(d)
 
14,495 
 
 
 103.00 
 
4.08 
%
 
Any time
 
 
 1,450 
 
 
 1,460 
OPCo
 
 
100 
 
(d)
 
22,824 
 
 
 103.20 
 
4.20 
%
 
Any time
 
 
 2,282 
 
 
 2,282 
OPCo
 
 
100 
 
(d)
 
31,482 
 
 
 104.00 
 
4.40 
%
 
Any time
 
 
 3,148 
 
 
 3,148 
OPCo
 
 
100 
 
(d)
 
97,357 
 
 
 110.00 
 
4.50 
%
 
Any time
 
 
 9,736 
 
 
 9,737 
PSO
 
 
100 
 
(e)
 
44,508 
 
 
 105.75 
 
4.00 
%
 
Any time
 
 
 4,451 
 
 
 4,451 
PSO
 
 
100 
 
(e)
 
4,310 
 
 
 103.19 
 
4.24 
%
 
Any time
 
 
 431 
 
 
 807 
SWEPCo
 
 
100 
 
(f)
 
7,386 
 
 
 103.90 
 
4.28 
%
 
Any time
 
 
 739 
 
 
 740 
SWEPCo
 
 
100 
 
(f)
 
1,907 
 
 
 102.75 
 
4.65 
%
 
Any time
 
 
 190 
 
 
 190 
SWEPCo
 
 
100 
 
(f)
 
37,665 
 
 
 109.00 
 
5.00 
%
 
Any time
 
 
 3,767 
 
 
 3,767 

 
(a)
The cumulative preferred stock is callable at the price indicated plus accrued dividends.  If the Registrant Subsidiary defaults on preferred stock dividend payments for a period of one year or longer, preferred stock holders are entitled, voting separately as one class, to elect the number of directors necessary to constitute a majority of the Registrant Subsidiary’s full board of directors.
 
(b)
Stated value is $100 per share.
 
(c)
I&M has 2,250,000 authorized $100 par value per share shares in total.
 
(d)
OPCo has 3,762,403 authorized $100 par value per share shares in total.
 
(e)
PSO has 700,000 authorized shares in total.
 
(f)
SWEPCo has 1,860,000 authorized shares in total.

 
 
 
 
 
 
Number of Shares Redeemed for the
 
 
 
 
 
 
Years Ended December 31,
Company
 
Series
 
2010 
 
2009 
 
2008 
APCo
 
4.50 
%
 
 53 
 
 2 
 
 - 
I&M
 
4.125 
%
 
 44 
 
 34 
 
 - 
OPCo
 
4.08 
%
 
 100 
 
 - 
 
 - 
OPCo
 
4.50 
%
 
 6 
 
 10 
 
 - 
PSO
 
4.00 
%
 
 - 
 
 40 
 
 - 
PSO
 
4.24 
%
 
 3,759 
 
 - 
 
 - 
SWEPCo
 
5.00 
%
 
 8 
 
 - 
 
 - 

 
372
 
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, 2010 and 2009:

 
 
 
 
Weighted
 
 
 
 
 
 
 
 
Average
 
 
 
 
 
 
 
 
Interest
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rate at
 
 
 
Outstanding at
 
 
 
 
December 31,
 
Interest Rate Ranges at December 31,
 
December 31,
Company
 
Maturity
 
2010 
 
2010 
 
2009 
 
2010 
 
2009 
Senior Unsecured Notes
 
 
 
 
 
 
 
 
 
(in thousands)
APCo
 
2010-2038
 
5.98%
 
3.40%-7.95%
 
4.40%-7.95%
 
$
 3,042,060 
 
$
 2,875,885 
CSPCo
 
2010-2035
 
5.37%
 
0.702%-6.60%
 
4.40%-6.60%
 
 
 1,246,085 
 
 
 1,243,648 
I&M
 
2012-2037
 
6.25%
 
5.05%-7.00%
 
5.05%-7.00%
 
 
 1,270,116 
 
 
 1,419,633 
OPCo
 
2010-2033
 
5.74%
 
4.85%-6.60%
 
0.4644%-6.60%
 
 
 2,044,942 
 
 
 2,643,925 
PSO
 
2011-2037
 
5.86%
 
4.70%-6.625%
 
4.70%-6.625%
 
 
 922,576 
 
 
 921,761 
SWEPCo
 
2015-2040
 
5.92%
 
4.90%-6.45%
 
4.90%-6.45%
 
 
 1,548,185 
 
 
 1,196,944 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pollution Control Bonds (a)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo
 
2010-2042 (b)
3.09%
 
0.29%-6.05%
 
0.20%-7.125%
 
 
 516,650 
 
 
 498,972 
CSPCo
 
2012-2038 (b)
4.78%
 
3.875%-5.80%
 
3.875%-5.80%
 
 
 192,745 
 
 
 192,745 
I&M
 
2011-2025 (b)
4.09%
 
0.33%-6.25%
 
0.23%-6.25%
 
 
 266,456 
 
 
 266,418 
OPCo
 
2010-2037 (b)
2.62%
 
0.30%-5.15%
 
0.22%-7.125%
 
 
 484,580 
 
 
 398,580 
PSO
 
2014-2020
 
5.03%
 
4.45%-5.25%
 
4.45%-5.25%
 
 
 46,360 
 
 
 46,360 
SWEPCo
 
2011-2019 (b)
4.33%
 
3.25%-4.95%
 
0.82%-4.95%
 
 
 176,335 
 
 
 176,335 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes Payable - Affiliated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo
 
2010 
 
-
 
-
 
4.708%
 
 
 - 
 
 
 100,000 
CSPCo
 
2010 
 
-
 
-
 
4.64%
 
 
 - 
 
 
 100,000 
I&M
 
2010 
 
-
 
-
 
5.375%
 
 
 - 
 
 
 25,000 
OPCo
 
2015 
 
5.25%
 
5.25%
 
5.25%
 
 
 200,000 
 
 
 200,000 
SWEPCo
 
2010 
 
-
 
-
 
4.45%
 
 
 - 
 
 
 50,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notes Payable - Nonaffiliated
 
 
 
 
 
 
 
 
 
 
 
 
 
 
I&M
 
2013-2015
 
3.81%
 
2.07%-5.44%
 
5.44%
 
 
 202,753 
 
 
 102,300 
SWEPCo
 
2012-2024
 
6.66%
 
6.37%-7.03%
 
4.47%-7.03%
 
 
 45,000 
 
 
 50,874 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Spent Nuclear Fuel Liability (c)
 
 
 
 
 
 
 
 
 
 
 
 
 
I&M
 
 
 
 
 
 
 
 
 
 
 264,901 
 
 
 264,555 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Long-term Debt
 
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo
 
2026 
 
13.718%
 
13.718%
 
13.718%
 
 
 2,431 
 
 
 2,449 
PSO
 
2026 
 
3.00%
 
3.00%
 
-
 
 
 2,250 
 
 
 - 

(a)  
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, standby bond purchase agreements and insurance policies support certain series .
(b)  
Certain pollution control bonds are subject to mandatory redemption earlier than the maturity date.  Consequently, these bonds have been classified for maturity and repayment purposes based on the mandatory redemption date.
(c)  
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).

At December 31, 2010, $50 million of PSO’s Senior Unsecured Notes, which are due within one year, are classified as long-term debt due to management’s intent and ability to refinance these notes on a long-term basis.  In January 2011, PSO issued $250 million of 4.4% Senior Unsecured Notes due in 2021, demonstrating the ability to refinance these obligations on a long-term basis.

 
373
 
At December 31, 2009, approximately $230 million, $77 million and $165 million of variable-rate, tax-exempt bonds were outstanding for APCo, I&M and OPCo, respectively.  These bonds, which are short-term obligations, were classified as long-term debt due to management’s intent and ability to refinance each obligation on a long-term basis.  At December 31, 2009, the $478 million credit facility had non-cancelable terms in excess of one year, demonstrating the ability to refinance these short-term obligations on a long-term basis.

Long-term debt outstanding at December 31, 2010 is payable as follows:

 
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
2011 
$
 479,672 
 
$
 - 
 
$
 154,457 
 
$
 165,000 
 
$
 25,000 
 
$
 41,135 
2012 
 
 250,025 
 
 
 194,500 
 
 
 161,389 
 
 
 - 
 
 
 150 
 
 
 20,000 
2013 
 
 70,029 
 
 
 306,000 
 
 
 43,937 
 
 
 500,000 
 
 
 150 
 
 
 - 
2014 
 
 33 
 
 
 60,000 
 
 
 290,943 
 
 
 343,580 
 
 
 33,850 
 
 
 - 
2015 
 
 500,038 
 
 
 - 
 
 
 129,027 
 
 
 286,000 
 
 
 150 
 
 
 303,500 
After 2015
 
 2,269,284 
 
 
 882,245 
 
 
 1,229,901 
 
 
 1,440,000 
 
 
 914,310 
 
 
 1,406,700 
Total Principal Amount
 
 3,569,081 
 
 
 1,442,745 
 
 
 2,009,654 
 
 
 2,734,580 
 
 
 973,610 
 
 
 1,771,335 
Unamortized Discount
 
 (7,940)
 
 
 (3,915)
 
 
 (5,428)
 
 
 (5,058)
 
 
 (2,424)
 
 
 (1,815)
Total Long-term Debt
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Outstanding
$
 3,561,141 
 
$
 1,438,830 
 
$
 2,004,226 
 
$
 2,729,522 
 
$
 971,186 
 
$
 1,769,520 

In February 2011, APCo issued $65 million of 2% Pollution Control Bonds due in 2041 with a 2012 mandatory put date.

On behalf of OPCo, trustees held $303 million of reacquired variable rate tax-exempt long-term debt as of December 31, 2010.

Dividend Restrictions

The Registrant Subsidiaries pay dividends to Parent provided funds are legally available.  Various financing arrangements, charter provisions 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.  As applicable, the Registrant Subsidiaries understand “capital account” to mean the par value of the common stock multiplied by the number of shares outstanding.

Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generating plants.  Because of their respective ownership of such plants, this reserve applies to APCo, I&M and OPCo.

None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.

Charter and Leverage Restrictions

Provisions within the articles or certificates of incorporation of the Registrant Subsidiaries relating to preferred stock or shares restrict the payment of cash dividends on common and preferred stock or shares.  Pursuant to the credit agreement leverage restrictions, the Registrant Subsidiaries must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%.

At December 31, 2010, approximately $150 million of the retained earnings of APCo, $77 million of the retained earnings of CSPCo, $101 million of the retained earnings of SWEPCo and none of the retained earnings of I&M, OPCo and PSO have restrictions related to the payment of dividends to Parent.

 
374
 
Utility Money Pool – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of its subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries.  The AEP System Utility Money Pool operates in accordance with the terms and conditions approved in a regulatory order.  The amount of outstanding loans (borrowings) to/from the Utility Money Pool as of December 31, 2010 and 2009 is included in Advances to/from Affiliates 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, 2010 and 2009 are described in the following tables:

Year Ended December 31, 2010:

 
 
 
 
 
 
 
 
 
 
 
Loans
 
 
 
 
Maximum
 
Maximum
 
Average
 
Average
 
(Borrowings)
 
Authorized
 
 
Borrowings
 
Loans
 
Borrowings
 
Loans
 
to/from Utility
 
Short-term
 
 
from Utility
 
to Utility
 
from Utility
 
to Utility
 
Money Pool as of
 
Borrowing
Company
 
Money Pool
 
Money Pool
 
Money Pool
 
Money Pool
 
December 31, 2010
 
Limit
 
 
(in thousands)
APCo
 
$
 438,039 
 
$
 - 
 
$
 227,002 
 
$
 - 
 
$
 (128,331)
 
$
 600,000 
CSPCo
 
 
 134,592 
 
 
 229,758 
 
 
 32,368 
 
 
 96,009 
 
 
 54,202 
 
 
 350,000 
I&M
 
 
 42,769 
 
 
 223,111 
 
 
 17,972 
 
 
 107,123 
 
 
 (42,769)
 
 
 500,000 
OPCo
 
 
 - 
 
 
 618,559 
 
 
 - 
 
 
 231,600 
 
 
 100,500 
 
 
 600,000 
PSO
 
 
 107,320 
 
 
 74,751 
 
 
 45,287 
 
 
 31,211 
 
 
 (91,382)
 
 
 300,000 
SWEPCo
 
 
 78,616 
 
 
 274,958 
 
 
 39,458 
 
 
 184,126 
 
 
 86,222 
 
 
 350,000 

Year Ended December 31, 2009:

 
 
 
 
 
 
 
 
 
 
 
Loans
 
 
 
 
Maximum
 
Maximum
 
Average
 
Average
 
(Borrowings)
 
Authorized
 
 
Borrowings
 
Loans
 
Borrowings
 
Loans
 
to/from Utility
 
Short-term
 
 
from Utility
 
to Utility
 
from Utility
 
to Utility
 
Money Pool as of
 
Borrowing
Company
 
Money Pool
 
Money Pool
 
Money Pool
 
Money Pool
 
December 31, 2009
 
Limit
 
 
(in thousands)
APCo
 
$
 420,925 
 
$
 - 
 
$
 207,121 
 
$
 - 
 
$
 (229,546)
 
$
 600,000 
CSPCo
 
 
 203,306 
 
 
 9,029 
 
 
 101,965 
 
 
 5,666 
 
 
 (24,202)
 
 
 350,000 
I&M
 
 
 491,107 
 
 
 210,813 
 
 
 109,469 
 
 
 110,454 
 
 
 114,012 
 
 
 500,000 
OPCo
 
 
 522,934 
 
 
 451,832 
 
 
 255,870 
 
 
 302,420 
 
 
 438,352 
 
 
 600,000 
PSO
 
 
 77,976 
 
 
 284,647 
 
 
 56,378 
 
 
 61,328 
 
 
 62,695 
 
 
 300,000 
SWEPCo
 
 
 62,871 
 
 
 158,843 
 
 
 18,530 
 
 
 61,828 
 
 
 34,883 
 
 
 350,000 

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,
   
2010
 
2009
 
2008
Maximum Interest Rate
 
0.55%
 
2.28%
 
5.47%
Minimum Interest Rate
 
0.09%
 
0.15%
 
2.28%

 
375
 
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the years ended December 31, 2010, 2009 and 2008 are summarized for all Registrant Subsidiaries in the following table:

 
 
Average Interest Rate
 
Average Interest Rate
 
 
 for Funds Borrowed
 
 for Funds Loaned
 
 
from Utility Money Pool for
 
to Utility Money Pool for
 
 
Years Ended December 31,
 
Years Ended December 31,
Company
 
2010 
 
2009 
 
2008 
 
2010 
 
2009 
 
2008 
APCo
 
 0.26 
%
 
0.89 
%
 
 3.66 
%
 
 - 
%
 
 - 
%
 
 3.25 
%
CSPCo
 
 0.18 
%
 
1.05 
%
 
 3.59 
%
 
 0.26 
%
 
0.57 
%
 
 3.29 
%
I&M
 
 0.43 
%
 
1.46 
%
 
 3.35 
%
 
 0.24 
%
 
0.26 
%
 
 - 
%
OPCo
 
 - 
%
 
1.21 
%
 
 3.24 
%
 
 0.21 
%
 
0.22 
%
 
 3.82 
%
PSO
 
 0.31 
%
 
2.01 
%
 
 3.32 
%
 
 0.17 
%
 
0.56 
%
 
 4.53 
%
SWEPCo
 
 0.19 
%
 
1.66 
%
 
 3.38 
%
 
 0.27 
%
 
0.52 
%
 
 3.12 
%

Interest expense related to the Utility Money Pool is included in Interest Expense on each of the Registrant Subsidiaries’ Financial Statements.  The Registrant Subsidiaries incurred interest expense for amounts borrowed from the Utility Money Pool as follows:

 
 
Years Ended December 31,
Company
 
2010 
 
2009 
 
2008 
 
 
 
 
 
(in thousands)
 
 
 
APCo
 
$
611 
 
$
1,887 
 
$
6,076 
CSPCo
 
 
11 
 
 
1,081 
 
 
2,287 
I&M
 
 
17 
 
 
924 
 
 
7,903 
OPCo
 
 
5 
 
 
2,075 
 
 
4,912 
PSO
 
 
102 
 
 
86 
 
 
1,856 
SWEPCo
 
 
11 
 
 
68 
 
 
1,480 

Interest income related to the Utility Money Pool is included in Interest Income on each of the Registrant Subsidiaries’ Financial Statements.  The Registrant Subsidiaries earned interest income for amounts advanced to the Utility Money Pool as follows:

 
 
 
Years Ended December 31,
 
Company
 
2010 
 
2009 
 
2008 
 
 
 
 
 
 
(in thousands)
 
 
 
 
APCo
 
$
 9 
 
$
 - 
 
$
 872 
 
CSPCo
 
 
 208 
 
 
 - 
 
 
 880 
 
I&M
 
 
 219 
 
 
 129 
 
 
 - 
 
OPCo
 
 
 500 
 
 
 228 
 
 
 79 
 
PSO
 
 
 19 
 
 
 322 
 
 
 293 
 
SWEPCo
 
 
 438 
 
 
 278 
 
 
 2,540 

Short-term Debt
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
The Registrant Subsidiaries’ outstanding short-term debt was as follows:
 
 
 
 
December 31,
 
 
 
 
 
2010 
2009 
 
 
 
 
Outstanding
Interest
Outstanding
Interest
 
Company
Type of Debt
Amount
Rate (b)
Amount
Rate (b)
 
 
 
 
(in thousands)
 
 
(in thousands)
 
 
 
SWEPCo
Line of Credit – Sabine (a)
$
 6,217 
 2.15 
%
$
 6,890 
 2.06 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Sabine Mining Company is a consolidated variable interest entity.
 
(b)
Weighted average rate.

 
376
 
Credit Facilities

AEP has credit facilities totaling $3 billion to support the commercial paper program.  The facilities are structured as two $1.5 billion credit facilities, of which $750 million may be issued under the credit facility that matures in April 2012 as letters of credit.  In June 2010, AEP terminated one of the $1.5 billion facilities, which was scheduled to mature in March 2011, and replaced it with a new $1.5 billion credit facility which matures in June 2013 and allows for the issuance of up to $600 million as letters of credit.  As of December 31, 2010, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $150 thousand for I&M and $4 million for SWEPCo.

In June 2010, the Registrant Subsidiaries and certain other companies in the AEP System reduced a $627 million credit agreement that matures in April 2011 to $478 million.  Under the facility, letters of credit may be issued.  As of December 31, 2010, $477 million of letters of credit were issued to support variable rate Pollution Control Bonds as follows:

Company
 
Amount
   
(in thousands)
APCo
 
$
232,292 
I&M
   
77,886 
OPCo
   
166,899 

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 Subsidiaries’ 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 on the Registrant Subsidiaries’ income statements.  The Registrant Subsidiaries manage and service their customer accounts receivable sold.

In July 2010, AEP Credit renewed its receivables securitization agreement.  The agreement provides a commitment of $750 million from bank conduits to purchase receivables.  A commitment of $375 million expires in July 2011 and the remaining commitment of $375 million expires in July 2013.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of December 31, 2010 and 2009 was as follows:

 
 
 
December 31,
Company
 
2010 
 
2009 
 
 
 
(in thousands)
APCo
 
$
 145,515 
 
$
 143,938 
CSPCo
 
 
 175,997 
 
 
 169,095 
I&M
 
 
 123,366 
 
 
 130,193 
OPCo
 
 
 168,701 
 
 
 160,977 
PSO
 
 
 121,679 
 
 
 73,518 
SWEPCo
 
 
 135,092 
 
 
 117,297 

The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:

 
 
 
Years Ended December 31,
Company
 
2010 
 
2009 
 
2008 
 
 
 
(in thousands)
APCo
 
$
 9,194 
 
$
 5,132 
 
$
 6,140 
CSPCo
 
 
 11,412 
 
 
 11,225 
 
 
 12,744 
I&M
 
 
 6,770 
 
 
 6,191 
 
 
 7,213 
OPCo
 
 
 9,218 
 
 
 8,769 
 
 
 10,003 
PSO
 
 
 5,406 
 
 
 6,954 
 
 
 10,936 
SWEPCo
 
 
 5,688 
 
 
 6,171 
 
 
 7,992 

 
377
 
The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:

 
 
 
Years Ended December 31,
Company
 
2010 
 
2009 
 
2008 
 
 
 
(in thousands)
APCo
 
$
 1,418,487 
 
$
 1,258,860 
 
$
 1,029,779 
CSPCo
 
 
 1,750,902 
 
 
 1,627,444 
 
 
 1,640,598 
I&M
 
 
 1,283,955 
 
 
 1,228,502 
 
 
 1,178,473 
OPCo
 
 
 1,744,707 
 
 
 1,574,323 
 
 
 1,630,446 
PSO
 
 
 1,196,586 
 
 
 1,028,770 
 
 
 1,484,556 
SWEPCo
 
 
 1,402,525 
 
 
 1,300,393 
 
 
 1,347,899 

15.   RELATED PARTY TRANSACTIONS

For other related party transactions, also see “Utility Money Pool – AEP System” and “Sale of Receivables – AEP Credit” sections of Note 14.

AEP Power Pool

APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended, defining how they share the costs and benefits associated with their generating plants.  This sharing is based upon each company’s MLR, which is calculated monthly on the basis of each company’s maximum peak demand in relation to the sum of the maximum peak demands of all five companies during the preceding 12 months.  In December 2010, each AEP Power Pool member gave notice to AEPSC and the other AEP Power Pool members of its decision to terminate the Interconnection Agreement effective January 2014 or such other date approved by the FERC.  It is unknown at this time what will replace the Interconnection Agreement.  In addition, since 1995, APCo, CSPCo, I&M, KPCo and OPCo have been parties to the AEP System Interim Allowance Agreement, which provides, among other things, for the transfer of SO 2 allowances associated with the transactions under the Interconnection Agreement.

Power, gas and risk management activities are conducted by AEPSC and profits and losses are allocated under the SIA to AEP Power Pool members, PSO and SWEPCo.  Risk management activities involve the purchase and sale of electricity and gas under physical forward contracts at fixed and variable prices.  In addition, the risk management of electricity, and to a lesser extent gas contracts, includes exchange traded futures and options and OTC options and swaps.  The majority of these transactions represent physical forward contracts in the AEP System’s traditional marketing area and are typically settled by entering into offsetting contracts.  In addition, AEPSC enters into transactions for the purchase and sale of electricity and gas options, futures and swaps, and for the forward purchase and sale of electricity outside of the AEP System’s traditional marketing area.

CSW Operating Agreement

PSO, SWEPCo and AEPSC are parties to a Restated and Amended Operating Agreement originally dated as of January 1, 1997 (CSW Operating Agreement), which was approved by the FERC.  The CSW 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 the use of 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.

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 and the CSW Operating Agreement, each of which controls the distribution of costs and benefits within a zone.

 
378
 
Power generated, allocated or provided under the Interconnection Agreement or CSW 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 CSW 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 to the pools, direct sales to affiliates, natural gas contracts with AEPES and other revenues for the years ended December 31, 2010, 2009 and 2008:

Related Party Revenues
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Year Ended December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sales to AEP Power Pool
 
$
 158,873 
 
$
 64,467 
 
$
 327,992 
 
$
 891,424 
 
$
 - 
 
$
 - 
 
Direct Sales to East Affiliates
 
 
 123,832 
 
 
 - 
 
 
 - 
 
 
 115,406 
 
 
 1,210 
 
 
 1,248 
 
Direct Sales to West Affiliates
 
 
 3,471 
 
 
 1,900 
 
 
 1,931 
 
 
 2,225 
 
 
 19,629 
 
 
 39,851 
 
Direct Sales to AEPEP
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (286)
 
Direct Sales to Transmission Companies
 
 
 44 
 
 
 113 
 
 
 1,848 
 
 
 123 
 
 
 30 
 
 
 1 
 
Natural Gas Contracts with AEPES
 
 
 (2,171)
 
 
 (1,072)
 
 
 (1,087)
 
 
 (1,258)
 
 
 2 
 
 
 3 
 
Other Revenues
 
 
 32,158 
 
 
 17,586 
 
 
 267 
 
 
 18,003 
 
 
 2,657 
 
 
 11,053 
 
Total Affiliated Revenues
 
$
 316,207 
 
$
 82,994 
 
$
 330,951 
 
$
 1,025,923 
 
$
 23,528 
 
$
 51,870 

Related Party Revenues
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Year Ended December 31, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sales to AEP Power Pool
 
$
 130,331 
 
$
 57,373 
 
$
 198,579 
 
$
 935,563 
 
$
 - 
 
$
 - 
 
Direct Sales to East Affiliates
 
 
 123,549 
 
 
 - 
 
 
 - 
 
 
 84,078 
 
 
 3,136 
 
 
 1,220 
 
Direct Sales to West Affiliates
 
 
 2,255 
 
 
 1,169 
 
 
 1,154 
 
 
 1,384 
 
 
 39,197 
 
 
 16,434 
 
Direct Sales to AEPEP
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (659)
 
Natural Gas Contracts with AEPES
 
 
 (8,340)
 
 
 (4,866)
 
 
 (4,637)
 
 
 (6,142)
 
 
 (328)
 
 
 (387)
 
Other Revenues
 
 
 15,594 
 
 
 13,537 
 
 
 1,055 
 
 
 19,407 
 
 
 3,751 
 
 
 12,710 
 
Total Affiliated Revenues
 
$
 263,389 
 
$
 67,213 
 
$
 196,151 
 
$
 1,034,290 
 
$
 45,756 
 
$
 29,318 

Related Party Revenues
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Year Ended December 31, 2008
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sales to AEP Power Pool
 
$
 219,305 
 
$
 101,743 
 
$
 292,183 
 
$
 849,574 
 
$
 - 
 
$
 - 
 
Direct Sales to East Affiliates
 
 
 92,225 
 
 
 - 
 
 
 - 
 
 
 74,465 
 
 
 4,246 
 
 
 3,438 
 
Direct Sales to West Affiliates
 
 
 16,558 
 
 
 9,849 
 
 
 9,483 
 
 
 11,505 
 
 
 90,545 
 
 
 33,493 
 
Natural Gas Contracts with AEPES
 
 
 (2,029)
 
 
 (1,203)
 
 
 (1,085)
 
 
 (689)
 
 
 (467)
 
 
 (552)
 
Other Revenues
 
 
 2,676 
 
 
 12,560 
 
 
 2,160 
 
 
 5,613 
 
 
 7,278 
 
 
 14,463 
 
Total Affiliated Revenues
 
$
 328,735 
 
$
 122,949 
 
$
 302,741 
 
$
 940,468 
 
$
 101,602 
 
$
 50,842 

The following tables show the purchased power expense incurred for purchases from the pools and affiliates for the years ended December 31, 2010, 2009 and 2008:

Related Party Purchases
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Year Ended December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Purchases from AEP Power Pool
 
$
 916,791 
 
$
 294,838 
 
$
 91,129 
 
$
 90,576 
 
$
 - 
 
$
 - 
 
Direct Purchases from East Affiliates
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 6,162 
 
 
 4,078 
 
Direct Purchases from West Affiliates
 
 
 825 
 
 
 458 
 
 
 466 
 
 
 538 
 
 
 39,851 
 
 
 19,629 
 
Purchases from AEGCo
 
 
 - 
 
 
 113,801 
 
 
 235,740 
 
 
 - 
 
 
 - 
 
 
 - 
 
Gas Purchases from AEPES
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 2,857 
 
 
 - 
 
 
 - 
 
Total Purchases
 
$
 917,616 
 
$
 409,097 
 
$
 327,335 
 
$
 93,971 
 
$
 46,013 
 
$
 23,707 

 
379
 
Related Party Purchases
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Year Ended December 31, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Purchases from AEP Power Pool
 
$
 801,624 
 
$
 316,490 
 
$
 99,159 
 
$
 72,360 
 
$
 - 
 
$
 - 
 
Direct Purchases from East Affiliates
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 2,896 
 
 
 3,515 
 
Direct Purchases from West Affiliates
 
 
 1,492 
 
 
 802 
 
 
 777 
 
 
 987 
 
 
 16,435 
 
 
 39,197 
 
Direct Purchases from AEGCo
 
 
 - 
 
 
 75,469 
 
 
 237,372 
 
 
 - 
 
 
 - 
 
 
 - 
 
Gas Purchases from AEPES
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1,251 
 
 
 - 
 
 
 - 
 
Total Purchases
 
$
 803,116 
 
$
 392,761 
 
$
 337,308 
 
$
 74,598 
 
$
 19,331 
 
$
 42,712 

Related Party Purchases
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
Year Ended December 31, 2008
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Purchases from AEP Power Pool
 
$
 783,048 
 
$
 334,983 
 
$
 135,056 
 
$
 135,514 
 
$
 - 
 
$
 - 
 
Purchases from West System Pool
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 2,867 
 
Purchases from AEPEP
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 28 
 
Direct Purchases from East Affiliates
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 25,851 
 
 
 25,333 
 
Direct Purchases from West Affiliates
 
 
 2,143 
 
 
 1,239 
 
 
 1,195 
 
 
 1,483 
 
 
 33,493 
 
 
 90,545 
 
Direct Purchases from AEGCo
 
 
 - 
 
 
 77,296 
 
 
 247,931 
 
 
 - 
 
 
 - 
 
 
 - 
 
Gas Purchases from AEPES
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 3,689 
 
 
 - 
 
 
 - 
 
Total Purchases
 
$
 785,191 
 
$
 413,518 
 
$
 384,182 
 
$
 140,686 
 
$
 59,344 
 
$
 118,773 

The above summarized related party revenues and expenses are reported as Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates on the income statements of each Registrant Subsidiary.  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 and
·  
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, CSPCo, I&M, KPCo and OPCo are parties to the TA, dated April 1, 1984, as amended, defining how they share the costs associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345 kV and above) and certain facilities operated at lower voltages (138 kV and above).  Like the Interconnection Agreement, this sharing is based upon each company’s MLR.  The FERC approved a new TA effective November 2010.  The impacts of the new TA will be phased-in for retail rates, adds KGPCo and WPCo as parties to the agreement and changes the allocation method.

The following table shows the net charges (credits) allocated among the Registrant Subsidiaries, party to the TA, during the years ended December 31, 2010, 2009 and 2008:

 
 
 
Years Ended December 31,
Company
 
2010 
 
2009 
 
2008 
 
 
(in thousands)
APCo
 
$
 (16,079)
 
$
 (12,535)
 
$
 (29,146)
CSPCo
 
 
 42,516 
 
 
 51,309 
 
 
 55,273 
I&M
 
 
 (25,188)
 
 
 (38,400)
 
 
 (37,398)
OPCo
 
 
 6,765 
 
 
 8,461 
 
 
 13,294 

The net charges (credits) shown above are recorded in Other Operation expense on the income statements.

 
380
 
PSO, SWEPCo, TNC and AEPSC are parties to the TCA, originally dated January 1, 1997, as amended.  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, including 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 Open Access Transmission Tariff (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 (with respect to PSO, TNC and SWEPCo).

The following table shows the net charges (credits) allocated among parties to the TCA pursuant to the SPP OATT protocols as described above during the years ended December 31, 2010, 2009 and 2008:

 
 
 
Years Ended December 31,
Company
 
2010 
 
2009 
 
2008 
 
 
(in thousands)
PSO
 
$
 10,600 
 
$
 11,100 
 
$
 8,200 
SWEPCo
 
 
 (10,500)
 
 
 (11,100)
 
 
 (8,200)

The net charges (credits) shown above are recorded in the Other Operation expense on PSO’s and SWEPCo’s income statements.

Assignment from SWEPCo to AEPEP

On March 1, 2008, SWEPCo assigned its portion of a 20-year Purchase Power Agreement (PPA) to AEPEP.  In addition to the PPA assignment, an intercompany agreement was executed between AEPEP and SWEPCo to provide SWEPCo with future margins related to its share.  SWEPCo also retained the rights to the Renewable Energy Credit Offsets from the PPA.  The PPA and intercompany agreements are effective through 2019.  SWEPCo recorded losses of $286 thousand and $659 thousand and revenue of $903 thousand from AEPEP in Sales to AEP Affiliates on its 2010, 2009 and 2008 Consolidated Statements of Income, respectively.

ERCOT Contracts Transferred to AEPEP

Effective January 1, 2007, PSO and SWEPCo transferred certain existing ERCOT energy marketing contracts to AEPEP and entered into intercompany financial and physical purchase and sale agreements with AEPEP.  This was done to lock in PSO and SWEPCo’s margins on ERCOT trading and marketing contracts and to transfer the future associated commodity price and credit risk to AEPEP.  The contracts ended in December 2009.

PSO and SWEPCo have historically presented third party ERCOT trading and marketing activity on a net basis in Revenues - Electric Generation, Transmission and Distribution.  The applicable ERCOT third party trading and marketing contracts that were not transferred to AEPEP will remain until maturity on PSO’s and SWEPCo’s balance sheets and will be presented on a net basis in Sales to AEP Affiliates on PSO’s and SWEPCo’s income statements.

 
381
 
The following tables indicate the sales to AEPEP and the amounts reclassified from third party to affiliates:

 
 
 
 
Year Ended December 31, 2009
 
 
 
 
 
Third Party Amounts
 
Net Amount
 
 
 
Net Settlement
 
Reclassified to
 
Included in Sales
Company
 
with AEPEP
 
Affiliate
 
to AEP Affiliates
 
 
(in thousands)
PSO
 
$
 (3,871)
 
$
 4,318 
 
$
 447 
SWEPCo
 
 
 (4,569)
 
 
 5,098 
 
 
 529 
 
 
 
 
Year Ended December 31, 2008
 
 
 
 
 
Third Party Amounts
 
Net Amount
 
 
 
Net Settlement
 
Reclassified to
 
Included in Sales
Company
 
with AEPEP
 
Affiliate
 
to AEP Affiliates
 
 
(in thousands)
PSO
 
$
 79,445 
 
$
 (76,000)
 
$
 3,445 
SWEPCo
 
 
 84,095 
 
 
 (80,032)
 
 
 4,063 

CSPCo Transfer of Property

In May 2009, CSPCo transferred a parking garage to AEP through a dividend.  AEP then transferred the property to AEPSC through a capital contribution.  The transfers were effective May 2009 and were recorded at net book value of $8 million.

Natural Gas Contracts with DETM

In 2003, AEPES assigned to AEPSC, as agent for the AEP East companies, approximately $97 million (negative value) associated with its natural gas contracts with DETM.  The assignment was executed in order to consolidate DETM positions within AEP.  Beginning in 2007, PSO and SWEPCo were allocated a portion of the DETM assignment based on the SIA methodology of sharing trading and marketing margins between the AEP East companies, PSO and SWEPCo.  Concurrently, in order to ensure that there would be no financial impact to the AEP East companies, PSO or SWEPCo as a result of the assignment, AEPES and AEPSC entered into agreements requiring AEPES to reimburse AEPSC for any related cash settlements and all income related to the assigned contracts.  The agreement between AEPSC and AEPES ended December 31, 2010, coinciding with the settlement of the remaining DETM contracts.  The following table represents the Registrant Subsidiaries’ risk management liabilities related to DETM at December 31, 2009:

 
 
 
December 31,
Company
 
2009 
 
 
(in thousands)
APCo
 
$
 2,730 
CSPCo
 
 
 1,383 
I&M
 
 
 1,395 
OPCo
 
 
 1,611 

 
382
 
Fuel Agreement between OPCo and AEPES

OPCo and National Power Cooperative, Inc (NPC) have an agreement whereby OPCo operates a 500 MW gas plant owned by NPC (Mone Plant).  AEPES entered into a fuel management agreement with OPCo and NPC to manage and procure fuel for the Mone Plant.  The gas purchased by AEPES and used in generation is first sold to OPCo then allocated to the AEP East companies, who have an agreement to purchase 100% of the available generating capacity from the plant through May 2012.  The related purchases of gas managed by AEPES were as follows:

 
 
 
Years Ended December 31,
Company
 
2010 
 
2009 
 
2008 
 
 
(in thousands)
APCo
 
$
 940 
 
$
 431 
 
$
 1,204 
CSPCo
 
 
 535 
 
 
 229 
 
 
 707 
I&M
 
 
 547 
 
 
 224 
 
 
 681 
OPCo
 
 
 640 
 
 
 279 
 
 
 840 

These purchases are reflected in Purchased Electricity for Resale on the income statements.

Unit Power Agreements (UPA)

Lawrenceburg UPA between CSPCo and AEGCo

In March 2007, CSPCo 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 2-year period.  I&M operates the plant under an agreement with AEGCo.  Under the UPA, CSPCo 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.

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.  I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to 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

Cook Coal Terminal, a division of OPCo, performs coal transloading services at cost for APCo and I&M.  OPCo included revenues for these services in Other Revenues – Affiliated and expenses in Other Operation expense on its Consolidated Statements of Income.  The coal transloading revenues in 2010, 2009 and 2008 were as follows:

 
 
 
Years Ended December 31,
Company
 
2010 
 
2009 
 
2008 
 
 
(in thousands)
APCo
 
$
 - 
 
$
 916 
 
$
 1,000 
I&M
 
 
 17,208 
 
 
 18,908 
 
 
 15,368 

APCo and I&M recorded the cost of transloading services in Fuel on their balance sheets.

 
383
 
In addition, Cook Coal Terminal provided coal transloading services for OVEC in 2008.  Cook Coal Terminal did not provide coal transloading services for OVEC in 2009 or 2010.  OPCo recorded revenue as Other Revenues – Nonaffiliated on its Consolidated Statements of Income in the amount of $59 thousand in 2008.  OVEC is 43.47% owned by AEP (includes CSPCo’s 4.3% ownership of OVEC).

In 2010, 2009 and 2008, Cook Coal Terminal also performed railcar maintenance services at cost for APCo, I&M, PSO and SWEPCo.  OPCo included revenues for these services in Sales to AEP Affiliates and expenses in Other Operation expense on its Consolidated Statements of Income.  The railcar maintenance revenues were as follows:

 
 
 
Years Ended December 31,
Company
 
2010 
 
2009 
 
2008 
 
 
(in thousands)
APCo
 
$
 7 
 
$
 98 
 
$
 39 
I&M
 
 
 1,870 
 
 
 2,045 
 
 
 2,720 
PSO
 
 
 522 
 
 
 510 
 
 
 1,160 
SWEPCo
 
 
 1,044 
 
 
 914 
 
 
 434 

APCo, I&M, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on their balance sheets.

In addition, Cook Coal Terminal provides railcar maintenance services for OVEC.  OPCo recorded revenue as Other Revenues – Nonaffiliated on its Consolidated Statements of Income in the amount of $1 million, for each year in 2010, 2009 and 2008.

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 $1.8 million and $2.2 million for railcar services provided in 2010 and 2009, respectively, and billed PSO $655 thousand and $425 thousand in 2010 and 2009, 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 as Other Revenues – Affiliated on its Consolidated Statements of Income.  The affiliated companies recorded these costs paid to I&M as fuel expense or other operation expense.  The amount of affiliated revenues and affiliated expenses were:

 
 
 
Years Ended December 31,
Company
 
2010 
 
2009 
 
2008 
 
 
(in thousands)
I&M – Revenues
 
$
 105,811 
 
$
 94,921 
 
$
 103,436 
AEGCo – Expense
 
 
 12,548 
 
 
 13,167 
 
 
 17,038 
APCo – Expense
 
 
 28,241 
 
 
 29,442 
 
 
 27,058 
KPCo – Expense
 
 
 133 
 
 
 112 
 
 
 9 
OPCo – Expense
 
 
 44,160 
 
 
 38,039 
 
 
 40,950 
AEP River Operations LLC – Expense (Nonutility
 
 
 
 
 
 
 
 
 
 
Subsidiary of AEP)
 
 
 20,729 
 
 
 14,161 
 
 
 18,381 

In addition, I&M provided transloading services to OVEC.  I&M recorded revenues of $112 thousand, $135 thousand and $3 thousand for 2010, 2009 and 2008, respectively, in Other Revenues – Nonaffiliated on its Consolidated Statements of Income.

 
384
 
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 expense.  For the years ended December 31, 2010, 2009 and 2008, I&M recorded expenses of $28 million, $24 million and $37 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 on its balance sheet the cost of performing the services, then transfers the cost to the affiliate for reimbursement.  The AEP subsidiaries recorded these billings as capital or maintenance expense 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
 
2010 
 
2009 
 
2008 
 
 
(in thousands)
AEGCo
 
$
 180 
 
$
 31 
 
$
 138 
CSPCo
 
 
 397 
 
 
 1,306 
 
 
 682 
I&M
 
 
 2,112 
 
 
 2,818 
 
 
 2,714 
KGPCo
 
 
 - 
 
 
 5 
 
 
 - 
KPCo
 
 
 368 
 
 
 358 
 
 
 1,183 
OPCo
 
 
 3,268 
 
 
 2,831 
 
 
 1,944 
PSO
 
 
 412 
 
 
 848 
 
 
 1,225 
SWEPCo
 
 
 560 
 
 
 966 
 
 
 288 

In addition, APCo billed OVEC and IKEC a total of $541 thousand, $202 thousand and $303 thousand for the years ended December 31, 2010, 2009 and 2008, respectively.

Affiliate Coal Purchases

In 2008, OPCo entered into contracts to sell excess coal purchases to certain AEP subsidiaries through 2010.  These sales (purchases) are reflected in Sales to AEP Affiliates on the income statements.  The following table shows the realized and unrealized amounts recorded for the years ended December 31, 2010, 2009 and 2008:

 
 
Years Ended December 31,
Company
 
2010 
 
2009 
 
2008 
 
 
(in thousands)
APCo
 
$
 (2,830)
 
$
 (1,573)
 
$
 (187)
CSPCo
 
 
 (1,558)
 
 
 (783)
 
 
 (90)
I&M
 
 
 (1,383)
 
 
 (813)
 
 
 (92)
KPCo
 
 
 (837)
 
 
 (340)
 
 
 (36)
OPCo
 
 
 8,930 
 
 
 5,022 
 
 
 534 
PSO
 
 
 (796)
 
 
 (585)
 
 
 (48)
SWEPCo
 
 
 (1,526)
 
 
 (928)
 
 
 (81)

 
385
 
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 their balance sheets and such costs are recoverable from customers.  The following tables show the net effect of the railcar agreement on the balance sheets:

Year Ended December 31, 2010
Billing Company
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Billed Company
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
Total
 
 
(in thousands)
APCo
 
$
 - 
 
$
 - 
 
$
 1,195 
 
$
 1 
 
$
 (1)
 
$
 1,195 
CSPCo
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 9 
 
 
 9 
I&M
 
 
 142 
 
 
 - 
 
 
 1,536 
 
 
 123 
 
 
 502 
 
 
 2,303 
KPCo
 
 
 399 
 
 
 - 
 
 
 245 
 
 
 - 
 
 
 - 
 
 
 644 
OPCo
 
 
 919 
 
 
 418 
 
 
 - 
 
 
 21 
 
 
 97 
 
 
 1,455 
PSO
 
 
 177 
 
 
 921 
 
 
 191 
 
 
 - 
 
 
 493 
 
 
 1,782 
SWEPCo
 
 
 328 
 
 
 2,162 
 
 
 594 
 
 
 110 
 
 
 - 
 
 
 3,194 
Total
 
$
 1,965 
 
$
 3,501 
 
$
 3,761 
 
$
 255 
 
$
 1,100 
 
$
 10,582 

Year Ended December 31, 2009
Billing Company
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Billed Company
 
APCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
Total
 
 
(in thousands)
APCo
 
$
 - 
 
$
 143 
 
$
 1,632 
 
$
 15 
 
$
 44 
 
$
 1,834 
CSPCo
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 11 
 
 
 11 
I&M
 
 
 162 
 
 
 - 
 
 
 1,185 
 
 
 195 
 
 
 895 
 
 
 2,437 
KPCo
 
 
 669 
 
 
 - 
 
 
 13 
 
 
 - 
 
 
 - 
 
 
 682 
OPCo
 
 
 969 
 
 
 708 
 
 
 - 
 
 
 37 
 
 
 179 
 
 
 1,893 
PSO
 
 
 277 
 
 
 953 
 
 
 181 
 
 
 - 
 
 
 562 
 
 
 1,973 
SWEPCo
 
 
 79 
 
 
 1,896 
 
 
 1,312 
 
 
 136 
 
 
 - 
 
 
 3,423 
Total
 
$
 2,156 
 
$
 3,700 
 
$
 4,323 
 
$
 383 
 
$
 1,691 
 
$
 12,253 

Purchased Power from OVEC

The amounts of power purchased by the Registrant Subsidiaries from OVEC for the years ended December 31, 2010, 2009 and 2008 were:

 
 
 
Years Ended December 31,
Company
 
2010 
 
2009 
 
2008 
 
 
(in thousands)
APCo
 
$
 105,307 
 
$
 103,369 
 
$
 94,874 
CSPCo
 
 
 29,809 
 
 
 29,261 
 
 
 26,853 
I&M
 
 
 52,687 
 
 
 51,710 
 
 
 47,465 
OPCo
 
 
 103,967 
 
 
 102,057 
 
 
 93,661 

The amounts shown above are recoverable from customers and are included in Purchased Electricity for Resale on the income statements.

 
386
 
AEP Power Pool Purchases from OVEC

Beginning in 2006, the AEP Power Pool began purchasing power from OVEC as part of wholesale marketing and risk management activity.  These purchases are reflected in Electric Generation, Transmission and Distribution revenues on the income statements.  The agreement ended in December 2008.  The following table shows the amounts recorded for the year ended December 31, 2008:

 
 
 
Year Ended
Company
 
December 31, 2008
 
 
(in thousands)
APCo
 
$
 17,795 
CSPCo
 
 
 10,381 
I&M
 
 
 9,999 
OPCo
 
 
 12,359 

In January 2010, the AEP Power Pool began purchasing power from OVEC to serve off-system sales and retail sales through June 2010.  Purchases serving off-system sales are reported net as a reduction in Electric Generation, Transmission and Distribution revenues and purchases serving retail sales are reported in Purchased Electricity for Resale expenses on the income statements.  The following table shows the amounts recorded for the year ended December 31, 2010:

 
 
 
Year Ended December 31, 2010
 
 
 
Reported in
 
Reported in
Company
 
Revenues
 
Expenses
 
 
(in thousands)
APCo
 
$
 6,631 
 
$
 3,635 
CSPCo
 
 
 3,689 
 
 
 1,963 
I&M
 
 
 3,721 
 
 
 1,980 
OPCo
 
 
 4,248 
 
 
 2,268 

SWEPCo Lignite Purchases from DHLC

Effective January 1, 2010, SWEPCo deconsolidated DHLC due to the adoption of new accounting guidance.  See “ASU 2009-17 ‘Consolidations’ ” section of Note 2.  DHLC sells 50% of its lignite mining output to SWEPCo and the other 50% to CLECO.  SWEPCo purchased $56 million of lignite from DHLC and recorded these costs in Fuel on its Consolidated Balance Sheet at December 31, 2010.

SWEPCo Transactions with Oxbow Lignite Company

Oxbow Lignite Company, LLC (OLC) is jointly-owned by SWEPCo and CLECO, each owning 50%.  As joint-owners, SWEPCo and CLECO have equal representation in OLC regarding ownership, liability, profit and distributions.  OLC has surface lease and lignite and coal lease agreements which provide equal rights to each owner to mine the reserves and equal liability for the depletion costs.  DHLC is the exclusive miner of OLC’s reserves and 100% of the lignite mined is sold to SWEPCo and CLECO.  SWEPCo paid OLC $465 thousand for land leases, lignite leases and administrative services in 2010.  SWEPCo recorded these costs in Fuel on its Consolidated Balance Sheet at December 31, 2010.  See “Oxbow Lignite Company and Red River Mining Company” section of Note 7 for additional information regarding the purchase of OLC.

Sales and Purchases of Property – Transmission Companies

In 2009, AEP Transmission Company, LLC (AEP Transco) formed seven wholly-owned transmission companies.  AEP Transco is the holding company for the seven new transmission companies.  These seven companies consist of:  AEP Appalachian Transmission Company, Inc., AEP Indiana Michigan Transmission Company, Inc., AEP Kentucky Transmission Company, Inc., AEP Ohio Transmission Company, Inc., AEP West Virginia Transmission Company, Inc., AEP Oklahoma Transmission Company, Inc. (OKTCo) and AEP Soutwestern Transmission Company, Inc.

 
387
 
PSO began selling transmission property to OKTCo during 2010 for $1.5 million, which was recorded at net book value.  There were no gains or losses recorded on the transactions.

Sales and Purchases of Property

Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more for the years ended December 31, 2010, 2009 and 2008 as shown in the following tables:

 
 
 
Year Ended
Companies
 
December 31, 2010
 
 
(in thousands)
AEGCo to APCo
 
$
 332 
AEGCo to OPCo
 
 
 190 
APCo to I&M
 
 
 1,090 
APCo to KPCo
 
 
 209 
CSPCo to I&M
 
 
 1,459 
CSPCo to KPCo
 
 
 433 
I&M to APCo
 
 
 444 
I&M to OPCo
 
 
 485 
I&M to SWEPCo
 
 
 218 
OPCo to APCo
 
 
 3,011 
OPCo to CSPCo
 
 
 686 
OPCo to I&M
 
 
 976 
OPCo to KPCo
 
 
 527 
SWEPCo to PSO
 
 
 3,680 
TCC to SWEPCo
 
 
 360 

 
 
 
Year Ended
Companies
 
December 31, 2009
 
 
(in thousands)
APCo to I&M
 
$
 155 
I&M to APCo
 
 
 4,004 
I&M to OPCo
 
 
 6,378 
OPCo to APCo
 
 
 908 
OPCo to CSPCo
 
 
 344 
OPCo to I&M
 
 
 6,026 
OPCo to TCC
 
 
 526 
PSO to SWEPCo
 
 
 118 
TCC to APCo
 
 
 426 
TCC to SWEPCo
 
 
 684 

 
 
 
Year Ended
Companies
 
December 31, 2008
 
 
(in thousands)
APCo to CSPCo
 
$
 858 
APCo to I&M
 
 
 2,720 
APCo to OPCo
 
 
 615 
CSPCo to PSO
 
 
 180 
I&M to APCo
 
 
 653 
I&M to KPCo
 
 
 444 
I&M to OPCo
 
 
 1,992 
I&M to PSO
 
 
 666 
OPCo to I&M
 
 
 1,800 
OPCo to PSO
 
 
 259 
PSO to I&M
 
 
 646 
TCC to APCo
 
 
 220 

 
388
 
In addition, certain AEP subsidiaries had aggregate affiliated sales and purchases of meters and transformers for the years ended December 31, 2010, 2009 and 2008 as shown in the following tables:

Year Ended December 31, 2010
 
 
Purchaser
Seller
 
APCo
 
CSPCo
 
I&M
 
KGPCo
 
KPCo
 
OPCo
 
PSO
 
SWEPCo
 
TCC
 
TNC
 
WPCo
 
Total
 
 
(in thousands)
APCo
 
$
 - 
 
$
 17 
 
$
 112 
 
$
 225 
 
$
 139 
 
$
 120 
 
$
 61 
 
$
 31 
 
$
 - 
 
$
 - 
 
$
 - 
 
$
 705 
CSPCo
 
 
 65 
 
 
 - 
 
 
 3 
 
 
 - 
 
 
 - 
 
 
 1,164 
 
 
 74 
 
 
 908 
 
 
 157 
 
 
 - 
 
 
 6 
 
 
 2,377 
I&M
 
 
 138 
 
 
 46 
 
 
 - 
 
 
 - 
 
 
 7 
 
 
 310 
 
 
 116 
 
 
 1 
 
 
 - 
 
 
 63 
 
 
 14 
 
 
 695 
KGPCo
 
 
 154 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 154 
KPCo
 
 
 364 
 
 
 9 
 
 
 6 
 
 
 23 
 
 
 - 
 
 
 83 
 
 
 - 
 
 
 2 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 487 
OPCo
 
 
 146 
 
 
 6,085 
 
 
 429 
 
 
 1 
 
 
 139 
 
 
 - 
 
 
 5 
 
 
 196 
 
 
 8 
 
 
 10 
 
 
 366 
 
 
 7,385 
PSO
 
 
 - 
 
 
 42 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 2 
 
 
 - 
 
 
 560 
 
 
 6 
 
 
 3 
 
 
 - 
 
 
 613 
SWEPCo
 
 
 48 
 
 
 2 
 
 
 4 
 
 
 - 
 
 
 3 
 
 
 212 
 
 
 1,203 
 
 
 - 
 
 
 70 
 
 
 11 
 
 
 - 
 
 
 1,553 
TCC
 
 
 22 
 
 
 - 
 
 
 38 
 
 
 - 
 
 
 - 
 
 
 23 
 
 
 6 
 
 
 266 
 
 
 - 
 
 
 966 
 
 
 - 
 
 
 1,321 
TNC
 
 
 8 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1 
 
 
 70 
 
 
 642 
 
 
 - 
 
 
 4 
 
 
 725 
WPCo
 
 
 - 
 
 
 1 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 110 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 111 
Total
 
$
 945 
 
$
 6,202 
 
$
 592 
 
$
 249 
 
$
 288 
 
$
 2,024 
 
$
 1,466 
 
$
 2,034 
 
$
 883 
 
$
 1,053 
 
$
 390 
 
$
 16,126 

Year Ended December 31, 2009
 
 
Purchaser
Seller
 
APCo
 
CSPCo
 
I&M
 
KGPCo
 
KPCo
 
OPCo
 
PSO
 
SWEPCo
 
TCC
 
TNC
 
WPCo
 
Total
 
 
(in thousands)
APCo
 
$
 - 
 
$
 32 
 
$
 87 
 
$
 305 
 
$
 161 
 
$
 115 
 
$
 - 
 
$
 19 
 
$
 44 
 
$
 - 
 
$
 - 
 
$
 763 
CSPCo
 
 
 30 
 
 
 - 
 
 
 26 
 
 
 - 
 
 
 - 
 
 
 664 
 
 
 93 
 
 
 6 
 
 
 - 
 
 
 - 
 
 
 3 
 
 
 822 
I&M
 
 
 39 
 
 
 88 
 
 
 - 
 
 
 - 
 
 
 50 
 
 
 315 
 
 
 119 
 
 
 65 
 
 
 37 
 
 
 75 
 
 
 17 
 
 
 805 
KGPCo
 
 
 213 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 213 
KPCo
 
 
 505 
 
 
 23 
 
 
 64 
 
 
 7 
 
 
 - 
 
 
 133 
 
 
 3 
 
 
 8 
 
 
 - 
 
 
 - 
 
 
 1 
 
 
 744 
OPCo
 
 
 372 
 
 
 2,748 
 
 
 297 
 
 
 - 
 
 
 87 
 
 
 - 
 
 
 6 
 
 
 85 
 
 
 1 
 
 
 44 
 
 
 464 
 
 
 4,104 
PSO
 
 
 23 
 
 
 42 
 
 
 7 
 
 
 - 
 
 
 - 
 
 
 1 
 
 
 - 
 
 
 607 
 
 
 26 
 
 
 1 
 
 
 - 
 
 
 707 
SWEPCo
 
 
 38 
 
 
 27 
 
 
 21 
 
 
 - 
 
 
 26 
 
 
 58 
 
 
 1,360 
 
 
 - 
 
 
 162 
 
 
 28 
 
 
 - 
 
 
 1,720 
TCC
 
 
 13 
 
 
 - 
 
 
 72 
 
 
 - 
 
 
 - 
 
 
 19 
 
 
 2 
 
 
 87 
 
 
 - 
 
 
 873 
 
 
 - 
 
 
 1,066 
TNC
 
 
 8 
 
 
 - 
 
 
 10 
 
 
 - 
 
 
 - 
 
 
 17 
 
 
 18 
 
 
 25 
 
 
 750 
 
 
 - 
 
 
 - 
 
 
 828 
WPCo
 
 
 - 
 
 
 6 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 170 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 176 
Total
 
$
 1,241 
 
$
 2,966 
 
$
 584 
 
$
 312 
 
$
 324 
 
$
 1,492 
 
$
 1,601 
 
$
 902 
 
$
 1,020 
 
$
 1,021 
 
$
 485 
 
$
 11,948 

Year Ended December 31, 2008
 
 
Purchaser
Seller
 
APCo
 
CSPCo
 
I&M
 
KGPCo
 
KPCo
 
OPCo
 
PSO
 
SWEPCo
 
TCC
 
TNC
 
WPCo
 
Total
 
 
(in thousands)
APCo
 
$
 - 
 
$
 27 
 
$
 24 
 
$
 386 
 
$
 112 
 
$
 206 
 
$
 9 
 
$
 164 
 
$
 73 
 
$
 - 
 
$
 - 
 
$
 1,001 
CSPCo
 
 
 18 
 
 
 - 
 
 
 15 
 
 
 - 
 
 
 - 
 
 
 580 
 
 
 2 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 5 
 
 
 620 
I&M
 
 
 2 
 
 
 86 
 
 
 - 
 
 
 - 
 
 
 15 
 
 
 270 
 
 
 25 
 
 
 2 
 
 
 5 
 
 
 - 
 
 
 22 
 
 
 427 
KGPCo
 
 
 253 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 253 
KPCo
 
 
 354 
 
 
 11 
 
 
 16 
 
 
 6 
 
 
 - 
 
 
 121 
 
 
 - 
 
 
 2 
 
 
 33 
 
 
 - 
 
 
 - 
 
 
 543 
OPCo
 
 
 249 
 
 
 3,446 
 
 
 613 
 
 
 - 
 
 
 95 
 
 
 - 
 
 
 2 
 
 
 16 
 
 
 14 
 
 
 11 
 
 
 562 
 
 
 5,008 
PSO
 
 
 1 
 
 
 98 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 4 
 
 
 - 
 
 
 124 
 
 
 - 
 
 
 25 
 
 
 - 
 
 
 252 
SWEPCo
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 3 
 
 
 655 
 
 
 - 
 
 
 13 
 
 
 9 
 
 
 - 
 
 
 680 
TCC
 
 
 1 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 1 
 
 
 9 
 
 
 535 
 
 
 - 
 
 
 494 
 
 
 - 
 
 
 1,040 
TNC
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 9 
 
 
 28 
 
 
 26 
 
 
 334 
 
 
 - 
 
 
 - 
 
 
 397 
WPCo
 
 
 - 
 
 
 6 
 
 
 1 
 
 
 - 
 
 
 - 
 
 
 152 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 159 
Total
 
$
 878 
 
$
 3,674 
 
$
 669 
 
$
 392 
 
$
 222 
 
$
 1,346 
 
$
 730 
 
$
 869 
 
$
 472 
 
$
 539 
 
$
 589 
 
$
 10,380 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
The amounts above are recorded in Property, Plant and Equipment.  Transfers are recorded at cost.

 
389
 
Global Borrowing Notes

AEP has intercompany notes in place with the Registrant Subsidiaries.  The debt is reflected in Long-term Debt – Affiliated on the Registrant Subsidiaries’ balance sheets.  The Registrant Subsidiaries accrue interest for their share of the global borrowing and remit the interest to AEP.  The accrued interest is reflected in either Accrued Interest or Other Current Liabilities on the Registrant Subsidiaries’ balance sheets.  APCo, CSPCo, I&M, OPCo, PSO and SWEPCo participate in the global borrowing arrangement.

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 bases 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.  Billings between affiliated subsidiaries are capitalized or expensed depending on the nature of the services rendered.

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 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.  Also, see the “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.

SWEPCo is the primary beneficiary of Sabine.  As of January 1, 2010, SWEPCo is no longer the primary beneficiary of DHLC as defined by new accounting guidance for “Variable Interest Entities.”  I&M is the primary beneficiary of DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC.  APCo, CSPCo, I&M, OPCo, PSO and SWEPCo each hold a significant variable interest in AEPSC.  I&M and CSPCo each hold a significant variable interest in AEGCo.  SWEPCo holds a significant variable interest in DHLC.

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, 2010, 2009 and 2008 were $133 million, $99 million and $110 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on SWEPCo’s Consolidated Balance Sheets.

DHLC is a mining operator who sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  SWEPCo and CLECO share the executive board seats and its voting rights equally.  Each entity guarantees a 50% share 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.  Based on the shared control of DHLC’s operations, management concluded as of January 1, 2010 that SWEPCo is no longer the primary beneficiary and is no longer required to consolidate DHLC.  SWEPCo’s total billings from DHLC for the years ended December 31, 2010, 2009 and 2008 were $56 million, $43 million and $44 million, respectively.  See the
 
 
390
 
tables below for the classification of DHLC’s assets and liabilities on SWEPCo’s Consolidated Balance Sheet at December 31, 2009 as well as SWEPCo’s investment and maximum exposure as of December 31, 2010.  As of December 31, 2010, DHLC is reported as an equity investment in Deferred Charges and Other Noncurrent Assets on SWEPCo’s Consolidated Balance Sheet.  Also, see the “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.

The balances below represent the assets and liabilities of the VIEs that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
December 31, 2010
(in millions)
 
 
Sabine
 
ASSETS
 
 
 
 
Current Assets
 
$
 50 
 
Net Property, Plant and Equipment
 
 
 139 
 
Other Noncurrent Assets
 
 
 34 
 
Total Assets
 
$
 223 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
Current Liabilities
 
$
 33 
 
Noncurrent Liabilities
 
 
 190 
 
Equity
 
 
 - 
 
Total Liabilities and Equity
 
$
 223 
 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
December 31, 2009
(in millions)
 
 
Sabine
 
DHLC
ASSETS
 
 
 
 
 
 
Current Assets
 
$
 51 
 
$
 8 
Net Property, Plant and Equipment
 
 
 149 
 
 
 44 
Other Noncurrent Assets
 
 
 35 
 
 
 11 
Total Assets
 
$
 235 
 
$
 63 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
Current Liabilities
 
$
 36 
 
$
 17 
Noncurrent Liabilities
 
 
 199 
 
 
 38 
Equity
 
 
 - 
 
 
 8 
Total Liabilities and Equity
 
$
 235 
 
$
 63 
 
SWEPCo's investment in DHLC was:
 
 
 
   
 
 
 
December 31, 2010
 
 
As Reported on
   
 
 
 
the Consolidated
 
Maximum
 
 
Balance Sheets
 
Exposure
 
 
(in millions)
 
Capital Contribution from SWEPCo
  $ 6     $ 6  
Retained Earnings
    2       2  
SWEPCo's Guarantee of Debt
    -       48  
 
               
Total Investment in DHLC
  $ 8     $ 56  

In September 2009, I&M entered into a nuclear fuel sale and leaseback transaction with DCC Fuel LLC.  In April 2010, I&M entered into a nuclear fuel sale and leaseback transaction with DCC Fuel II LLC.  In December 2010, I&M entered into a nuclear fuel sale and leaseback transaction with DCC Fuel III LLC.  DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC (collectively DCC Fuel) were formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.  
 
 
391
 
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.  DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC are separate legal entities from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on the DCC Fuel LLC and DCC Fuel II LLC leases are made semi-annually and began in April 2010 and October 2010, respectively.  Payments on the DCC Fuel III LLC lease are made monthly and began in January 2011.  Payments on the leases for the year ended December 31, 2010 were $59 million.  No payments were made to DCC Fuel in 2009.  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 48, 54 and 54 month lease term, respectively.  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.  See the tables below for the classification of DCC Fuel’s assets and liabilities on I&M’s Consolidated Balance Sheets.

The balances below represent the assets and liabilities of the VIE that are consolidated.  These balances include intercompany transactions that would be eliminated upon consolidation.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
December 31, 2010 and 2009
(in millions)
 
 
DCC Fuel
ASSETS
 
2010 
 
2009 
Current Assets
 
$
 92 
 
$
 47 
Net Property, Plant and Equipment
 
 
 173 
 
 
 89 
Other Noncurrent Assets
 
 
 112 
 
 
 57 
Total Assets
 
$
 377 
 
$
 193 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
Current Liabilities
 
$
 79 
 
$
 39 
Noncurrent Liabilities
 
 
 298 
 
 
 154 
Equity
 
 
 - 
 
 
 - 
Total Liabilities and Equity
 
$
 377 
 
$
 193 

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.  No AEP subsidiary has 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’s subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations.  All Registrant Subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure.  However, no Registrant Subsidiary has 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
 
2010 
 
2009 
 
2008 
 
 
(in thousands)
APCo
 
$
 238,367 
 
$
 200,828 
 
$
 249,897 
CSPCo
 
 
 136,160 
 
 
 124,055 
 
 
 135,586 
I&M
 
 
 139,920 
 
 
 128,372 
 
 
 147,851 
OPCo
 
 
 196,271 
 
 
 175,193 
 
 
 207,773 
PSO
 
 
 102,116 
 
 
 86,375 
 
 
 116,576 
SWEPCo
 
 
 147,928 
 
 
 129,887 
 
 
 138,753 
 
 
392
 
The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31,
 
 
2010 
 
2009 
 
 
As Reported on the
 
Maximum
 
As Reported on the
 
Maximum
Company
 
Balance Sheet
 
Exposure
 
Balance Sheet
 
Exposure
 
 
(in thousands)
APCo
 
$
 23,230 
 
$
 23,230 
 
$
 22,693 
 
$
 22,693 
CSPCo
 
 
 12,676 
 
 
 12,676 
 
 
 13,348 
 
 
 13,348 
I&M
 
 
 12,980 
 
 
 12,980 
 
 
 13,119 
 
 
 13,119 
OPCo
 
 
 16,927 
 
 
 16,927 
 
 
 17,647 
 
 
 17,647 
PSO
 
 
 9,384 
 
 
 9,384 
 
 
 8,521 
 
 
 8,521 
SWEPCo
 
 
 14,465 
 
 
 14,465 
 
 
 13,752 
 
 
 13,752 

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 leases the Lawrenceburg Generating Station to CSPCo.  AEP guarantees all the debt obligations of AEGCo.  I&M and CSPCo are considered to have a significant interest in AEGCo due to these transactions.  I&M and CSPCo are exposed to losses to the extent they cannot recover the costs of AEGCo through their normal business operations.  In the event AEGCo would require financing or other support outside the billings to I&M, CSPCo and KPCo, this financing would be provided by AEP.  For additional information regarding AEGCo’s lease, see “Rockport Lease” section of Note 13.
 
Total billings from AEGCo were as follows:
 
   
 
   
 
   
 
 
 
 
Years Ended December 31,
 
Company
 
2010
 
2009
 
2008
 
 
 
(in thousands)
   
 
 
CSPCo
    $ 113,801     $ 75,469     $ 113,875  
I&M
      235,741       237,372       247,932  
 
 
The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows:
 
 
 
December 31,
 
 
2010 
 
2009 
 
 
As Reported on
 
 
 
 
As Reported on
 
 
 
 
 
the Consolidated
 
Maximum
 
the Consolidated
 
Maximum
Company
 
Balance Sheet
 
Exposure
 
Balance Sheet
 
Exposure
 
 
(in thousands)
CSPCo
 
$
 18,165 
 
$
 18,165 
 
$
 5,690 
 
$
 5,690 
I&M
 
 
 27,899 
 
 
 27,899 
 
 
 22,506 
 
 
 22,506 

 
393
 
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 table provides the annual composite depreciation rates by functional class generally used by the Registrant Subsidiaries:

APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2010 
 
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
 
$
 4,736,150 
 
$
 1,701,839 
 
2.4%
 
40-121
 
$
 - 
 
$
 - 
 
-
 
-
Transmission
 
 
 1,852,415 
 
 
 445,671 
 
1.6%
 
25-87
 
 
 - 
 
 
 - 
 
-
 
-
Distribution
 
 
 2,740,752 
 
 
 562,139 
 
3.2%
 
11-52
 
 
 - 
 
 
 - 
 
-
 
-
CWIP
 
 
 562,280 
 
 
 (18,470)
 
N.M.
 
N.M.
 
 
 - 
 
 
 - 
 
-
 
-
Other
 
 
 314,301 
 
 
 139,167 
 
7.8%
 
24-55
 
 
 33,712 
 
 
 12,741 
 
N.M.
 
N.M.
Total
 
$
 10,205,898 
 
$
 2,830,346 
 
 
 
 
 
$
 33,712 
 
$
 12,741 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2009 
 
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
 
$
 4,284,361 
 
$
 1,648,292 
 
2.3%
 
40-121
 
$
 - 
 
$
 - 
 
-
 
-
Transmission
 
 
 1,813,777 
 
 
 436,320 
 
1.6%
 
25-87
 
 
 - 
 
 
 - 
 
-
 
-
Distribution
 
 
 2,642,479 
 
 
 557,963 
 
3.2%
 
11-52
 
 
 - 
 
 
 - 
 
-
 
-
CWIP
 
 
 730,099 
 
 
 (27,062)
 
N.M.
 
N.M.
 
 
 - 
 
 
 - 
 
-
 
-
Other
 
 
 296,149 
 
 
 123,419 
 
8.9%
 
24-55
 
 
 33,348 
 
 
 12,511 
 
N.M.
 
N.M.
Total
 
$
 9,766,865 
 
$
 2,738,932 
 
 
 
 
 
$
 33,348 
 
$
 12,511 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

2008 
 
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
 
2.3%
 
40-121
 
-
 
-
Transmission
 
1.6%
 
25-87
 
-
 
-
Distribution
 
3.2%
 
11-52
 
-
 
-
CWIP
 
N.M.
 
N.M.
 
-
 
-
Other
 
7.5%
 
24-55
 
N.M.
 
N.M.
 
 
 
 
 
 
 
 
 
N.M.  Not Meaningful

 
394
 
CSPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2010 
 
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
 
$
 - 
 
$
 - 
 
-
 
-
 
$
 2,686,294 
 
$
 967,882 
 
2.2%
 
50 - 60
Transmission
 
 
 662,312 
 
 
 241,393 
 
2.3%
 
33-50
 
 
 - 
 
 
 - 
 
-
 
-
Distribution
 
 
 1,796,023 
 
 
 617,407 
 
3.5%
 
12-56
 
 
 - 
 
 
 - 
 
-
 
-
CWIP
 
 
 94,845 
 
 
 (2,156)
 
N.M.
 
N.M.
 
 
 77,948 
 
 
 527 
 
N.M.
 
N.M.
Other
 
 
 179,276 
 
 
 98,801 
 
8.4%
 
N.M.
 
 
 24,317 
 
 
 3,258 
 
N.M.
 
N.M.
Total
 
$
 2,732,456 
 
$
 955,445 
 
 
 
 
 
$
 2,788,559 
 
$
 971,667 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2009 
 
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
 
$
 - 
 
$
 - 
 
-
 
-
 
$
 2,641,860 
 
$
 924,842 
 
2.0%
 
50-60
Transmission
 
 
 623,680 
 
 
 231,428 
 
2.2%
 
33-50
 
 
 - 
 
 
 - 
 
-
 
-
Distribution
 
 
 1,745,559 
 
 
 593,541 
 
3.4%
 
12-56
 
 
 - 
 
 
 - 
 
-
 
-
CWIP
 
 
 112,426 
 
 
 (4,006)
 
N.M.
 
N.M.
 
 
 42,655 
 
 
 10 
 
N.M.
 
N.M.
Other
 
 
 164,998 
 
 
 89,968 
 
10.2%
 
N.M.
 
 
 24,317 
 
 
 3,057 
 
N.M.
 
N.M.
Total
 
$
 2,646,663 
 
$
 910,931 
 
 
 
 
 
$
 2,708,832 
 
$
 927,909 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

2008 
 
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
 
-
 
-
 
2.7%
 
40-59
Transmission
 
2.3%
 
33-50
 
-
 
-
Distribution
 
3.5%
 
12-56
 
-
 
-
CWIP
 
N.M.
 
N.M.
 
N.M.
 
N.M.
Other
 
8.7%
 
N.M.
 
N.M.
 
N.M.
 
 
 
 
 
 
 
 
 
N.M.  Not Meaningful

 
395
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2010 
 
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
 
$
 - 
 
$
 - 
 
-
 
-
 
$
 6,890,110 
 
$
 2,526,808 
 
3.7%
 
35-70
Transmission
 
 
 1,234,677 
 
 
 491,798 
 
2.3%
 
27-70
 
 
 - 
 
 
 - 
 
-
 
-
Distribution
 
 
 1,626,390 
 
 
 449,390 
 
3.9%
 
12-55
 
 
 - 
 
 
 - 
 
-
 
-
CWIP
 
 
 98,532 
 
 
 616 
 
N.M.
 
N.M.
 
 
 54,578 
 
 
 8,624 
 
N.M.
 
N.M.
Other
 
 
 241,238 
 
 
 118,485 
 
9.9%
 
N.M.
 
 
 118,016 
 
 
 11,056 
 
N.M.
 
N.M.
Total
 
$
 3,200,837 
 
$
 1,060,289 
 
 
 
 
 
$
 7,062,704 
 
$
 2,546,488 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2009 
 
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
 
$
 - 
 
$
 - 
 
-
 
-
 
$
 6,731,469 
 
$
 2,283,322 
 
3.3%
 
35-70
Transmission
 
 
 1,166,557 
 
 
 473,342 
 
2.3%
 
27-70
 
 
 - 
 
 
 - 
 
-
 
-
Distribution
 
 
 1,567,871 
 
 
 422,521 
 
3.9%
 
12-55
 
 
 - 
 
 
 - 
 
-
 
-
CWIP
 
 
 95,726 
 
 
 (2,623)
 
N.M.
 
N.M.
 
 
 103,117 
 
 
 6,467 
 
N.M.
 
N.M.
Other
 
 
 231,416 
 
 
 124,217 
 
11.5%
 
N.M.
 
 
 117,302 
 
 
 11,650 
 
N.M.
 
N.M.
Total
 
$
 3,061,570 
 
$
 1,017,457 
 
 
 
 
 
$
 6,951,888 
 
$
 2,301,439 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

2008 
 
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
 
-
 
-
 
2.7%
 
35-61
Transmission
 
2.3%
 
27-70
 
-
 
-
Distribution
 
3.9%
 
12-55
 
-
 
-
CWIP
 
N.M.
 
N.M.
 
N.M.
 
N.M.
Other
 
8.5%
 
N.M.
 
N.M.
 
N.M.
 
 
 
 
 
 
 
 
 
N.M.  Not Meaningful

 
396
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2010 
 
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
 
$
 2,297,463 
 
$
 1,026,467 
 
1.9%
 
35-68
 
$
 - 
 
$
 - 
 
-
 
-
Transmission
 
 
 943,724 
 
 
 272,619 
 
2.4%
 
50-70
 
 
 - 
 
 
 - 
 
-
 
-
Distribution
 
 
 1,611,129 
 
 
 513,472 
 
2.7%
 
25-65
 
 
 - 
 
 
 - 
 
-
 
-
CWIP
 
 
 1,065,949 
(a)
 
 700 
 
N.M.
 
N.M.
 
 
 5,654 
 
 
 - 
 
N.M.
 
N.M.
Other
 
 
 403,881 
 
 
 248,544 
 
7.7%
 
7-47
 
 
 228,277 
 
 
 68,549 
 
N.M.
 
N.M.
Total
 
$
 6,322,146 
 
$
 2,061,802 
 
 
 
 
 
$
 233,931 
 
$
 68,549 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2009 
 
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
 
$
 1,837,318 
 
$
 1,089,516 
 
2.7%
 
22-68
 
$
 - 
 
$
 - 
 
-
 
-
Transmission
 
 
 870,069 
 
 
 266,524 
 
2.6%
 
40-72
 
 
 - 
 
 
 - 
 
-
 
-
Distribution
 
 
 1,447,559 
 
 
 397,445 
 
3.6%
 
18-67
 
 
 - 
 
 
 - 
 
-
 
-
CWIP
 
 
 1,170,823 
(a)
 
 (5,920)
 
N.M.
 
N.M.
 
 
 5,816 
 
 
 - 
 
N.M.
 
N.M.
Other
 
 
 396,080 
 
 
 192,006 
 
7.6%
 
7-48
 
 
 337,230 
 
 
 146,762 
 
N.M.
 
N.M.
Total
 
$
 5,721,849 
 
$
 1,939,571 
 
 
 
 
 
$
 343,046 
 
$
 146,762 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

2008 
 
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
 
2.9%
 
19-68
 
2.9%
 
30-37
Transmission
 
2.7%
 
44-65
 
-
 
-
Distribution
 
3.5%
 
19-56
 
-
 
-
CWIP
 
N.M.
 
N.M.
 
N.M.
 
N.M.
Other
 
7.1%
 
7-45
 
N.M.
 
N.M.
 
 
 
 
 
 
 
 
 
(a) Includes CWIP related to SWEPCo's Arkansas jurisdictional share of the Turk Plant.
 
 
 
 
 
 
 
 
 
N.M.  Not Meaningful

 
397
 
 
 
I&M
 
PSO
2010 
 
Regulated
 
Regulated
 
 
 
 
 
 
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
 
$
 3,774,262 
 
$
 2,085,746 
 
1.6%
 
59-132
 
$
 1,330,368 
 
$
 648,205 
 
1.8%
 
9-70
Transmission
 
 
 1,188,665 
 
 
 408,832 
 
1.4%
 
46-75
 
 
 663,994 
 
 
 161,835 
 
1.9%
 
40-75
Distribution
 
 
 1,411,095 
 
 
 361,259 
 
2.5%
 
14-70
 
 
 1,686,470 
 
 
 311,005 
 
2.4%
 
27-65
CWIP
 
 
 301,534 
 
 
 33,046 
 
N.M.
 
N.M.
 
 
 59,091 
 
 
 (1,958)
 
N.M.
 
N.M.
Other
 
 
 572,328 
 
 
 129,703 
 
11.7%
 
N.M.
 
 
 230,286 
 
 
 135,977 
 
8.3%
 
5-35
Total
 
$
 7,247,884 
 
$
 3,018,586 
 
 
 
 
 
$
 3,970,209 
 
$
 1,255,064 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
I&M
 
PSO
 
 
Nonregulated
 
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)
Other
 
$
 147,380 
 
$
 106,412 
 
N.M.
 
N.M.
 
$
 5,120 
 
$
 - 
 
N.M.
 
N.M.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
I&M
 
PSO
2009 
 
Regulated
 
Regulated
 
 
 
 
 
 
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
 
$
 3,634,215 
 
$
 2,056,271 
 
1.6%
 
59-132
 
$
 1,300,069 
 
$
 637,317 
 
1.8%
 
9-70
Transmission
 
 
 1,154,026 
 
 
 403,760 
 
1.4%
 
46-75
 
 
 617,291 
 
 
 157,999 
 
2.0%
 
40-75
Distribution
 
 
 1,360,553 
 
 
 358,231 
 
2.4%
 
14-70
 
 
 1,596,355 
 
 
 311,352 
 
2.4%
 
27-65
CWIP
 
 
 278,278 
 
 
 29,931 
 
N.M.
 
N.M.
 
 
 67,138 
 
 
 (1,422)
 
N.M.
 
N.M.
Other
 
 
 605,288 
 
 
 118,433 
 
12.8%
 
N.M.
 
 
 223,585 
 
 
 114,931 
 
8.3%
 
5-35
Total
 
$
 7,032,360 
 
$
 2,966,626 
 
 
 
 
 
$
 3,804,438 
 
$
 1,220,177 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
I&M
 
PSO
 
 
Nonregulated
 
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)
Other
 
$
 149,844 
 
$
 107,069 
 
N.M.
 
N.M.
 
$
 5,120 
 
$
 - 
 
N.M.
 
N.M.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
398
 
 
 
I&M
 
PSO
2008 
 
Regulated
 
Regulated
 
 
 
 
 
 
 
 
 
 
 
Annual Composite
 
Depreciable
 
Annual Composite
 
Depreciable
Functional Class of Property
 
Depreciation Rate
 
Life Ranges
 
Depreciation Rate
 
Life Ranges
 
 
 
 
(in years)
 
 
 
(in years)
Generation
 
1.6%
 
59-132
 
1.7%
 
9-70
Transmission
 
1.4%
 
46-75
 
1.9%
 
40-75
Distribution
 
2.4%
 
14-70
 
2.9%
 
27-65
CWIP
 
N.M.
 
N.M.
 
N.M.
 
N.M.
Other
 
11.3%
 
N.M.
 
6.8%
 
5-35
 
 
 
 
 
 
 
 
 
 
 
I&M
 
PSO
 
 
Nonregulated
 
Nonregulated
 
 
 
 
 
 
 
 
 
 
 
Annual Composite
 
Depreciable
 
Annual Composite
 
Depreciable
Functional Class of Property
 
Depreciation Rate
 
Life Ranges
 
Depreciation Rate
 
Life Ranges
 
 
 
 
(in years)
 
 
 
(in years)
Other
 
N.M.
 
N.M.
 
N.M.
 
N.M.
 
 
 
 
 
 
 
 
 
N.M.  Not Meaningful

The Registrant Subsidiaries 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.  The Registrant Subsidiaries 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.  The Registrant Subsidiaries include these costs in the cost of coal charged to fuel expense.

For cost-based rate-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.

As of January 1, 2010, DHLC was deconsolidated and is now reported as an equity investment on SWEPCo’s Consolidated Balance Sheet.  Also, see the “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.

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, 2010 and 2009, I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $930 million and $878 million, respectively.  These liabilities are reflected in Asset Retirement Obligations on I&M’s Consolidated Balance Sheets.  As of December 31, 2010 and 2009, the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.2 billion and $1.1 billion, respectively.  These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s Consolidated Balance Sheets.

 
399
 
The following is a reconciliation of the 2010 and 2009 aggregate carrying amounts of ARO by Registrant Subsidiary:

 
 
 
ARO at
 
 
 
 
 
 
 
Revisions in
 
ARO at
 
 
 
December 31,
 
Accretion
 
Liabilities
 
Liabilities
 
Cash Flow
 
December 31,
Company
 
2009 
 
Expense
 
Incurred
 
Settled
 
Estimates
 
2010 
 
 
(in thousands)
APCo (a)(d)
 
$
 125,289 
 
$
 8,541 
 
$
 5,341 
 
$
 (4,064)
 
$
 6,817 
 
$
 141,924 
CSPCo (a)(d)
 
 
 40,522 
 
 
 2,869 
 
 
 1,452 
 
 
 (1,711)
 
 
 11,643 
 
 
 54,775 
I&M (a)(b)(d)
 
 
 894,746 
 
 
 47,844 
 
 
 7,216 
 
 
 (1,694)
 
 
 14,917 
 
 
 963,029 
OPCo (a)(d)
 
 
 94,221 
 
 
 8,565 
 
 
 3,579 
 
 
 (2,497)
 
 
 30,628 
 
 
 134,496 
PSO (a)(d)
 
 
 15,652 
 
 
 1,332 
 
 
 4,746 
 
 
 (173)
 
 
 - 
 
 
 21,557 
SWEPCo (a)(c)(d)(e)
 
 
 51,684 
(f)
 
 4,290 
 
 
 9,056 
 
 
 (7,709)
 
 
 2,061 
 
 
 59,382 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ARO at
 
 
 
 
 
 
 
Revisions in
 
ARO at
 
 
 
December 31,
 
Accretion
 
Liabilities
 
Liabilities
 
Cash Flow
 
December 31,
Company
 
2008 
 
Expense
 
Incurred
 
Settled
 
Estimates
 
2009 
 
 
(in thousands)
APCo (a)(d)
 
$
 51,879 
 
$
 4,969 
 
$
 38,654 
 
$
 (2,656)
 
$
 32,443 
 
$
 125,289 
CSPCo (a)(d)
 
 
 17,428 
 
 
 1,458 
 
 
 - 
 
 
 (2,858)
 
 
 24,494 
 
 
 40,522 
I&M (a)(b)(d)
 
 
 902,920 
 
 
 48,662 
 
 
 2,396 
 
 
 (1,480)
 
 
 (57,752)
 
 
 894,746 
OPCo (a)(d)
 
 
 89,316 
 
 
 7,935 
 
 
 - 
 
 
 (3,946)
 
 
 916 
 
 
 94,221 
PSO (a)(d)
 
 
 14,826 
 
 
 1,250 
 
 
 - 
 
 
 (390)
 
 
 (34)
 
 
 15,652 
SWEPCo (a)(c)(d)(e)
 
 
 55,086 
 
 
 7,384 
 
 
 6,039 
 
 
 (11,081)
 
 
 6,673 
 
 
 64,101 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Includes ARO related to ash disposal facilities.
(b)
Includes ARO related to nuclear decommissioning costs for the Cook Plant ($930 million and $878 million at
 
December 31, 2010 and 2009, respectively).
(c)
Includes ARO related to Sabine and DHLC.
(d)
Includes ARO related to asbestos removal.
(e)
The current portion of SWEPCo’s ARO, totaling $2.6 million and $3.5 million, at December 31, 2010 and
 
and 2009 respectively, is included in Other Current Liabilities on SWEPCo’s Consolidated Balance Sheets.
(f)
SWEPCo adopted ASU 2009-17 effective January 1, 2010 and deconsolidated DHLC.  As a result, SWEPCo
 
recorded only 50% ($12 million) of the final reclamation based on its share of the obligation instead of the
 
previous 100%.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization

The amounts of AFUDC included in Allowance for Equity Funds Used During Construction on the Registrant Subsidiaries’ income statements for 2010, 2009 and 2008 were as follows:

 
 
Years Ended December 31,
Company
 
2010 
 
2009 
 
2008 
 
 
(in thousands)
APCo
 
$
 2,967 
 
$
 7,000 
 
$
 8,938 
CSPCo
 
 
 2,072 
 
 
 3,382 
 
 
 3,364 
I&M
 
 
 15,678 
 
 
 12,013 
 
 
 965 
OPCo
 
 
 3,877 
 
 
 2,712 
 
 
 3,073 
PSO
 
 
 804 
 
 
 1,787 
 
 
 1,822 
SWEPCo
 
 
 45,646 
 
 
 46,737 
 
 
 14,908 

 
400
 
The amounts of allowance for borrowed funds used during construction or interest capitalized included in Interest Expense on the Registrant Subsidiaries’ income statements for 2010, 2009 and 2008 were as follows:

 
 
Years Ended December 31,
Company
 
2010 
 
2009 
 
2008 
 
 
(in thousands)
APCo
 
$
 2,251 
 
$
 6,014 
 
$
 9,040 
CSPCo
 
 
 2,311 
 
 
 5,968 
 
 
 2,677 
I&M
 
 
 8,500 
 
 
 8,348 
 
 
 4,609 
OPCo
 
 
 1,475 
 
 
 10,538 
 
 
 25,269 
PSO
 
 
 572 
 
 
 1,142 
 
 
 2,174 
SWEPCo
 
 
 33,668 
 
 
 29,546 
 
 
 19,800 

Jointly-owned Electric Facilities

APCo, CSPCo, I&M, OPCo, PSO and SWEPCo 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 operations and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows:

 
 
 
 
 
 
 
 
Company’s Share at December 31, 2010
 
 
 
 
 
 
 
 
 
 
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 No. 3) (a)
 
Coal
 
 33.33 
%
 
$
 472,244 
 
$
 5,638 
 
$
 77,786 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CSPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
W.C. Beckjord Generating Station
 
Coal
 
 12.5 
%
 
$
 19,079 
 
$
 248 
 
$
 8,003 
 
(Unit No. 6) (b)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Conesville Generating Station (Unit No. 4) (c)
 
Coal
 
 43.5 
%
 
 
 300,618 
 
 
 8,259 
 
 
 49,121 
J.M. Stuart Generating Station (d)
 
Coal
 
 26.0 
%
 
 
 506,756 
 
 
 22,435 
 
 
 162,869 
Wm. H. Zimmer Generating Station (b)
 
Coal
 
 25.4 
%
 
 
 771,236 
 
 
 9,636 
 
 
 365,989 
Transmission
 
N/A
 
(f)
 
 
 
 62,952 
 
 
 3,008 
 
 
 47,957 
Total
 
 
 
 
 
 
$
 1,660,641 
 
$
 43,586 
 
$
 633,939 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
I&M
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Rockport Generating Plant (Unit No. 1) (e)
 
Coal
 
 50.0 
%
 
$
 742,538 
 
$
 25,304 
 
$
 437,371 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
John E. Amos Generating Station (Unit No. 3) (a)
 
Coal
 
 66.67 
%
 
$
 988,870 
 
$
 6,354 
 
$
 168,933 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oklaunion Generating Station (Unit No. 1) (g)
 
Coal
 
 15.6 
%
 
$
 91,275 
 
$
 1,124 
 
$
 56,160 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dolet Hills Generating Station (Unit No. 1) (h)
 
Lignite
 
 40.2 
%
 
$
 258,261 
 
$
 4,648 
 
$
 191,486 
Flint Creek Generating Station (Unit No. 1) (i)
 
Coal
 
 50.0 
%
 
 
 115,742 
 
 
 6,725 
 
 
 61,750 
Pirkey Generating Station (Unit No. 1) (i)
 
Lignite
 
 85.9 
%
 
 
 502,520 
 
 
 10,317 
 
 
 358,241 
Turk Generating Plant (j)
 
Coal
 
 73.33 
%
 
 
 - 
 
 
 971,131 
 
 
 - 
Total
 
 
 
 
 
 
$
 876,523 
 
$
 992,821 
 
$
 611,477 

 
401
 
 
 
 
 
 
 
 
 
Company’s Share at December 31, 2009
 
 
 
 
 
 
 
 
 
 
Construction
 
 
 
 
Fuel
Percent of
Utility Plant
Work in
Accumulated
Company
Type
Ownership
 in Service
Progress
Depreciation
 
 
 
 
 
 
 
 
(in thousands)
CSPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
W.C. Beckjord Generating Station
 
Coal
 
 12.5 
%
 
$
 19,400 
 
$
 120 
 
$
 8,097 
 
(Unit No. 6) (b)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Conesville Generating Station (Unit No. 4) (c)
 
Coal
 
 43.5 
%
 
 
 300,646 
 
 
 3,829 
 
 
 44,832 
J.M. Stuart Generating Station (d)
 
Coal
 
 26.0 
%
 
 
 498,851 
 
 
 15,442 
 
 
 152,601 
Wm. H. Zimmer Generating Station (b)
 
Coal
 
 25.4 
%
 
 
 767,654 
 
 
 4,082 
 
 
 355,457 
Transmission
 
N/A
 
(f)
 
 
 
 69,868 
 
 
 355 
 
 
 46,815 
Total
 
 
 
 
 
 
$
 1,656,419 
 
$
 23,828 
 
$
 607,802 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PSO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oklaunion Generating Station (Unit No. 1) (g)
 
Coal
 
 15.6 
%
 
$
 89,823 
 
$
 1,688 
 
$
 55,772 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dolet Hills Generating Station (Unit No. 1) (h)
 
Lignite
 
 40.2 
%
 
$
 255,274 
 
$
 4,212 
 
$
 188,475 
Flint Creek Generating Station (Unit No. 1) (i)
 
Coal
 
 50.0 
%
 
 
 115,839 
 
 
 4,627 
 
 
 60,772 
Pirkey Generating Station (Unit No. 1) (i)
 
Lignite
 
 85.9 
%
 
 
 496,786 
 
 
 7,724 
 
 
 350,079 
Turk Generating Plant (j)
 
Coal
 
 73.33 
%
 
 
 - 
 
 
 688,167 
 
 
 - 
Total
 
 
 
 
 
 
$
 867,899 
 
$
 704,730 
 
$
 599,326 

(a)
Operated by APCo.
(b)
Operated by Duke Energy Corporation, a nonaffiliated company.
(c)
Operated by CSPCo.
(d)
Operated by The Dayton Power & Light Company, a nonaffiliated company.
(e)
Operated by I&M.
(f)
Varying percentages of ownership.
(g)
Operated by PSO and also jointly-owned (54.7%) by TNC.
(h)
Operated by Cleco Corporation, a nonaffiliated company.
(i)
Operated by SWEPCo.
(j)
Turk Generating Plant is currently under construction with a projected commercial operation date of 2012.  SWEPCo jointly owns the plant with Arkansas Electric Cooperative Corporation (11.67%), East Texas Electric Cooperative (8.33%) and Oklahoma Municipal Power Authority (6.67%).  Through December 2010, construction costs totaling $279 million have been billed to the other owners.
N/A
   Not Applicable

 
402
 
17.   COST REDUCTION INITIATIVES

In April 2010, management began initiatives to decrease both labor and non-labor expenses with a goal of achieving significant reductions in operation and maintenance expenses.  A total of 2,461 positions were eliminated across the AEP System as a result of process improvements, streamlined organizational designs and other efficiencies.  Most of the affected employees terminated employment May 31, 2010.  The severance program provides two weeks of base pay for every year of service along with other severance benefits.

Management recorded a charge to expense in 2010 primarily related to the headcount reduction initiatives.  Management does not expect additional costs to be incurred related to this initiative.

 
 
Expense
 
Incurred for
 
 
 
 
 
 
Remaining
 
 
Allocation from
 
Registrant
 
 
 
 
 
 
Balance at
 
 
AEPSC
 
Subsidiaries
 
Settled
 
Adjustments
 
December 31, 2010
 
 
(in thousands)
APCo
 
$
 20,526 
 
$
 36,399 
 
$
 51,826 
 
$
 (1,373)
 
$
 3,726 
CSPCo
 
 
 11,048 
 
 
 21,244 
 
 
 30,948 
 
 
 110 
 
 
 1,454 
I&M
 
 
 12,051 
 
 
 32,985 
 
 
 41,503 
 
 
 (1,335)
 
 
 2,198 
OPCo
 
 
 19,427 
 
 
 33,681 
 
 
 53,691 
 
 
 3,502 
 
 
 2,919 
PSO
 
 
 10,681 
 
 
 13,324 
 
 
 22,970 
 
 
 491 
 
 
 1,526 
SWEPCo
 
 
 12,588 
 
 
 17,074 
 
 
 28,874 
 
 
 965 
 
 
 1,753 

These costs relate primarily to severance benefits.  They are included primarily in Other Operation on the Consolidated Statements of Income and Other Current Liabilities on the Consolidated Balance Sheets.

 
403
 
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
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
 
March 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 926,623 
 
$
 517,439 
 
$
 553,056 
 
$
 861,273 
 
$
 237,755 
 
$
 342,804 
 
Operating Income
 
 157,938 
 
 
 98,401 
 
 
 87,870 
 
 
 181,343 
 
 
 22,622 
 
 
 43,468 
 
Net Income
 
 70,282 
 
 
 51,650 
 
 
 45,058 
 
 
 91,903 
 
 
 4,139 
 
 
 31,083 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
June 30, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 703,274 
 
$
 524,104 
 
$
 509,915 
 
$
 721,964 
 
$
 327,686 
 
$
 361,467 
 
Operating Income (a)
 
 9,033 
(b)
 
 97,150 
 
 
 42,140 
 
 
 89,623 
 
 
 39,265 
 
 
 43,518 
 
Net Income (Loss) (a)
 
 (19,619)
(b)
 
 52,116 
 
 
 14,602 
 
 
 37,548 
 
 
 15,489 
 
 
 26,705 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
September 30, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 840,622 
 
$
 648,394 
 
$
 608,250 
 
$
 855,859 
 
$
 426,569 
 
$
 480,982 
 
Operating Income
 
 112,060 
 
 
 186,844 
 
 
 115,904 
 
 
 190,063 
 
 
 104,654 
 
 
 128,428 
 
Net Income
 
 50,071 
 
 
 107,057 
 
 
 62,300 
 
 
 100,865 
 
 
 55,432 
 
 
 81,685 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 804,584 
 
$
 459,104 
 
$
 524,506 
 
$
 784,611 
 
$
 281,652 
 
$
 338,281 
 
Operating Income
 
 101,992 
 
 
 54,413 
(c)
 
 29,001 
(d)
 
 146,773 
 
 
 15,451 
 
 
 33,383 
 
Net Income (Loss)
 
 35,934 
 
 
 19,400 
(c)
 
 4,131 
(d)
 
 81,077 
 
 
 (2,273)
 
 
 7,211 
 

Quarterly Periods Ended:
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
 
 
 
(in thousands)
 
March 31, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 786,029 
 
$
 471,736 
 
$
 567,044 
 
$
 762,715 
 
$
 295,287 
 
$
 321,802 
 
Operating Income
 
 153,898 
 
 
 90,533 
 
 
 136,570 
 
 
 145,077 
 
 
 21,872 
 
 
 24,993 
 
Net Income
 
 74,407 
 
 
 48,858 
 
 
 80,952 
 
 
 72,609 
 
 
 6,038 
 
 
 11,700 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
June 30, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 636,112 
 
$
 507,876 
 
$
 530,416 
 
$
 678,013 
 
$
 277,141 
 
$
 340,782 
 
Operating Income
 
 85,567 
 
 
 150,966 
 
 
 91,874 
 
 
 133,839 
 
 
 50,891 
 
 
 48,870 
 
Income Before Extraordinary Loss
 
 29,170 
 
 
 84,178 
 
 
 48,509 
 
 
 63,912 
 
 
 24,122 
 
 
 35,778 
 
Extraordinary Loss, Net of Tax
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 (5,325)
(e)
Net Income
 
 29,170 
 
 
 84,178 
 
 
 48,509 
 
 
 63,912 
 
 
 24,122 
 
 
 30,453 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
September 30, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 695,673 
 
$
 556,143 
 
$
 552,267 
 
$
 765,971 
 
$
 318,555 
 
$
 414,974 
 
Operating Income
 
 83,698 
 
 
 167,412 
 
 
 100,143 
 
 
 186,121 
 
 
 81,352 
 
 
 83,023 
 
Net Income
 
 27,370 
 
 
 97,593 
 
 
 54,859 
 
 
 96,575 
 
 
 43,577 
 
 
 65,058 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 758,841 
 
$
 468,818 
 
$
 535,297 
 
$
 804,875 
 
$
 233,767 
 
$
 311,744 
 
Operating Income
 
 49,362 
(f)
 
 82,815 
 
 
 52,116 
 
 
 148,156 
 
 
 16,193 
 
 
 5,626 
 
Net Income
 
 24,867 
(f)
 
 41,032 
 
 
 31,990 
 
 
 75,519 
 
 
 1,865 
 
 
 9,992 
 

(a)
See Note 17 for discussion of expenses related to cost reduction initiatives recorded in the second quarter of 2010.
(b)
Includes a $54 million write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility.
(c)
Includes a $43 million refund provision for the 2009 Significantly Excessive Earnings Test.
(d)
Includes provisions for certain regulatory and legal matters.
(e)
See “SWEPCo Texas Restructuring” in “Extraordinary Item” section of Note 2 for discussion of the extraordinary loss recorded in the second quarter of 2009.
(f)
Includes a $68 million increase in storm, plant maintenance and other maintenance expenses.

 
404
 

COMBINED MANAGEMENT’S 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 Financial Discussion and Analysis, (b) financial statements, (c) footnotes and (d) the schedules of each individual registrant.

EXECUTIVE OVERVIEW

Economic Conditions

The Registrant Subsidiaries’ retail margins increased primarily due to successful rate proceedings in Indiana, Ohio, Oklahoma, Michigan and Virginia and higher residential and commercial demand for electricity as a result of favorable weather.

In comparison to the recessionary lows of 2009, industrial sales increased 5% in 2010 for the AEP System.  During 2009, the Registrant Subsidiaries’ operations were impacted by difficult economic conditions especially their industrial sales reflecting customers’ curtailments or closures of facilities.  In 2009, CSPCo’s and OPCo’s largest customer, Ormet, a major industrial customer, operated at a reduced load of approximately 330 MW and continued operations at this reduced level during 2010.  In February 2009, Century Aluminum, a major industrial customer (325 MW load) of APCo, announced the curtailment of operations at its Ravenswood, WV facility.

Management forecasts slight improvement in economic conditions in 2011 for all operating companies.  Industrial sales are expected to increase 4% for CSPCo and OPCo due to Ormet’s announcement of increased production in 2011.  Residential growth for the Registrant Subsidiaries is expected to see slow improvement, similar to 2010.

Cost Reduction Initiatives

Due to the continued slow recovery in the U.S. economy and a corresponding negative impact on energy consumption, the AEP System implemented cost reduction initiatives in the second quarter of 2010 to reduce its workforce by 11.5% and reduce other operation and maintenance spending.  Achieving these goals involved identifying process improvements, streamlining organizational designs and developing other efficiencies that will deliver additional savings.  In 2010, pretax expense of $293 million was recorded related to these cost reduction initiatives.  Starting with the third quarter of 2010, the Registrant Subsidiaries realized cost savings in Other Operation and Maintenance expenses on their statements of income.  Management anticipates continued savings to help offset future inflationary impacts.

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 have a material adverse effect on net income, cash flows and 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 from fossil fuel-fired power plants and new proposals governing the beneficial use and disposal of coal combustion products.

 
405
 
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.  Management is also engaged in the development of possible future requirements to reduce CO 2 emissions to address concerns about global climate change.

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.  Notable developments in CAA regulatory requirements affecting the Registrant Subsidiaries’ operations are discussed briefly below.

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 D.C. Circuit Court of Appeals issued a decision remanding CAIR to the Federal EPA.  CAIR remains in effect while a new rulemaking is conducted.  Nearly all of the states in which the AEP System’s power plants are located are covered by CAIR.  In July 2010, the Federal EPA issued a proposed rule (Transport Rule) to replace CAIR that would impose new and more stringent requirements to control SO 2 and NO x emissions from fossil fuel-fired electric generating units in 31 states and the District of Columbia.  Each state covered by the Transport Rule is assigned an allowance budget for SO 2 and/or NO x .  Limited interstate trading is allowed on a sub-regional basis and intrastate trading is allowed among generating units.  Texas, Arkansas and Oklahoma would be subject to only the seasonal NO x program, with new limits that are proposed to take effect in 2012.  The remainder of the states in which the Registrant Subsidiaries operate would be subject to seasonal and annual NO x programs and an annual SO 2 emissions reduction program that takes effect in two phases.  The first phase becomes effective in 2012 and requires approximately one million tons per year more SO 2 emission reductions across the region than would have been required under CAIR.  The second phase takes effect in 2014 and reduces SO 2 emissions by an additional 800,000 tons per year.  The SO 2 and NO x programs rely on newly-created allowances rather than relying on the CAIR NO x allowances or the Title IV Acid Rain Program allowances used in the CAIR rule.  The time frames for and stringency of the additional 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, as these features could accelerate unit retirements, increase capital requirements, constrain operations, decrease reliability and unfavorably impact financial condition if the increased costs are not recovered in rates or market prices.  The Federal EPA requested comments on a scheme based exclusively on intrastate trading of allowances or a scheme that establishes unit-by-unit emission rates.  Either of these options would provide less flexibility and exacerbate the negative impact of the rule.  The proposal indicates that the requirements are expected to be finalized in June 2011 and be effective January 1, 2012.

The Federal EPA issued a Clean Air Mercury Rule (CAMR) setting mercury standards for new coal-fired power plants and requiring all states to issue new state implementation plans (SIPs) including mercury requirements for existing coal-fired power plants.  The CAMR was vacated and remanded to the Federal EPA by the D.C. Circuit Court of Appeals in 2008.

Under the terms of a consent decree, the Federal EPA is required to issue final maximum achievable control technology (MACT) standards for coal and oil-fired power plants by November 2011.  The Federal EPA has substantial discretion in determining how to structure the MACT standards.  Management will urge the Federal EPA to carefully consider all of the options available so that costly and inefficient control requirements are not imposed regardless of unit size, age or other operating characteristics.  However, the AEP System has approximately 5,000 MW of older coal units, including 2,000 MW of older coal-fired capacity already subject to control requirements under the NSR consent decree, for which it may be economically inefficient to install scrubbers or other environmental controls.  The timing and ultimate disposition of those units will be affected by: (a) the MACT standards and other environmental regulations, (b) the economics of maintaining the units, (c) demand for electricity, (d) availability and cost of replacement power and (e) regulatory decisions about cost recovery of the remaining investment in those units.

The Federal EPA issued a 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.  CAVR will be implemented through individual SIPs or, if SIPs are not adequate or are not developed on schedule, through federal implementation plans (FIPs).  The Federal
 
 
406
 
EPA has proposed disapproval of SIPs in a few states, and proposed more stringent control requirements for affected units in those states.  If the Federal EPA takes such action in the states where the AEP System’s facilities are located, it could increase the costs of compliance, accelerate the installation of required controls, and/or force the premature retirement of existing units.

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 and final rules limiting CO 2 emissions from new motor vehicles in May 2010.  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 is reconsidering whether to include CO 2 emissions in a number of stationary source standards, including standards that apply to new and modified electric utility units and announced a settlement agreement to issue proposed new source performance standards for utility boilers.  It is not possible at this time to estimate the costs of compliance with these new standards, but they may be material.

The Federal EPA has also issued new, more stringent national ambient air quality standards (NAAQS) for SO 2 , NO 2 and lead, and is currently reviewing the NAAQS for ozone and PM.  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.

Estimated Air Quality Environmental Investments

The CAIR, CAVR and the consent decree signed to settle the NSR litigation require significant additional investments, some of which are estimable.  Management’s estimates are subject to significant uncertainties and will be affected by any changes in the outcome of several interrelated variables and assumptions, including: (a) the timing of implementation, (b) required levels of reductions, (c) methods for allocation of allowances and (d) selected compliance alternatives and their costs.  These obligations may also be affected or altered by the development of new regulations described above.  In short, management cannot estimate compliance costs with certainty and the actual costs to comply could differ significantly from the estimates discussed below.

The CAIR, CAVR and commitments in the consent decree will require installation of additional controls on the Registrant Subsidiaries’ power plants through 2020.  The Registrant Subsidiaries plan to install additional scrubbers on 5,970 MW for SO 2 control.  This amount includes the installation of scrubbers on the Rockport Plant (50% I&M and 50% AEGCo).  From 2011 to 2020, the following table shows the total estimated costs for environmental investment to meet these requirements including investment in scrubbers and other SO 2 equipment by Registrant Subsidiary:

 
 
Required
 
 
Total
Company
Environmental
 
 
(in millions)
APCo
 
$
 857 
CSPCo
 
 
 500 
I&M
 
 
 1,556 
OPCo
 
 
 1,551 
PSO
 
 
 1,186 
SWEPCo
 
 
 2,458 

These estimates are highly uncertain due to the variability associated with: (a) the states’ implementation of these regulatory programs, including the potential for SIPs or FIPS that impose standards more stringent than CAIR or CAVR, (b) additional rulemaking activities in response to the court decisions remanding the CAIR and CAMR, (c) the actual performance of the pollution control technologies installed on each units, (d) changes in costs for new pollution controls, (e) new generating technology developments and (f) other factors.  Associated operational and maintenance expenses will also increase during those years.  Management cannot estimate these additional operational and maintenance costs due to the uncertainties described above, but they are expected to be significant.

 
407
 
The Registrant Subsidiaries will seek recovery of expenditures for pollution control technologies, replacement or additional generation and associated operating costs from customers through regulated rates.  The Registrant Subsidiaries should be able to recover these expenditures through market prices in deregulated jurisdictions.  If not, those costs could adversely affect future net income, cash flows and possibly financial condition.

Coal Combustion Residual Rule

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.  The rule contains two alternative proposals, one that would impose federal hazardous waste disposal and management standards on these materials and one that 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.

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.  Management estimates that the potential compliance costs associated with the proposed solid waste management alternative could be as high as $3.9 billion for units across the AEP System.  Regulation of these materials as hazardous wastes would significantly increase these costs.  The Registrant Subsidiaries will seek recovery of expenditures for pollution control technologies and associated costs from customers through regulated rates or market prices for electricity.  If these costs are not recovered, it will have a material adverse impact on net income, cash flows and financial condition.

Global Warming

National public policy makers and regulators in the 10 states the Registrant Subsidiaries serve have conflicting views on global warming.  Management is focused on taking, in the short term, actions that are seen as prudent, 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.

Management believes that this is a global issue and that the United States should assume a leadership role in developing a new international approach that will address growing emissions of CO 2 and other greenhouse gases (generally referred to as CO 2 in this discussion) from all nations, including developing countries.  Management supports a reasonable approach to CO 2 emission reductions that recognizes a reliable and affordable electric supply is vital to economic stability and that allows sufficient time for technology development.  Management proposed to national policy makers that national and international policy for reasonable CO 2 controls should involve the following principles:

·
Comprehensiveness
·
Cost-effectiveness
·
Realistic emission reduction objectives
·
Reliable monitoring and verification mechanisms
·
Incentives to develop and deploy CO 2 reduction technologies
·
Removal of regulatory or economic barriers to CO 2 emission reductions
·
Recognition for early actions/investments in CO 2 reduction/mitigation
·
Inclusion of adjustment provisions if largest emitters in developing world do not take action

For additional information on climate change see Part I of the Annual Report under the headings entitled “Business – General – Environmental and Other Matters – Global Warming.”

 
408
 
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 discussed above.

The Registrant Subsidiaries’ fossil fuel-fired generating units are very 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 impact the ultimate retirement of older, less-efficient, coal-fired units.  To the extent the Registrant Subsidiaries install additional controls on their generating plants to limit CO 2 emissions and receive regulatory approvals to increase rates, cost recovery could have a positive effect on future earnings.  Prudently incurred capital investments made by the Registrant 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.  Management would expect these principles to apply to investments made to address new environmental requirements.  However, requests for rate increases reflecting these costs can affect the Registrant Subsidiaries adversely because the regulators could limit the amount or timing of increased costs that would be recoverable through higher rates.  In addition, to the extent the Registrant Subsidiaries’ costs are relatively higher than their competitors’ costs, such as operators of nuclear and natural gas based generation, it could reduce off-system sales or cause the Registrant Subsidiaries to lose customers in jurisdictions that permit customers to choose their supplier of generation service.

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 the Registrant Subsidiaries have generating facilities.  Certain states, including Ohio, Michigan, Texas and Virginia, 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 by an additional 2,000 MW from 2007 levels by 2011.  By the end of 2010, the Registrant Subsidiaries secured, through power purchase agreements, an additional 1,111 MW of wind power.  To the extent demand for renewable energy from wind power increases, it could have a positive effect on future earnings from transmission activities.

The AEP System has taken measurable, voluntary actions to reduce and offset CO 2 emissions.  The AEP System participates in a number of voluntary programs to monitor, mitigate and reduce CO 2 emissions, but many of these programs have been discontinued due to anticipated legislative or regulatory actions.  Through the end of 2009, the AEP System reduced emissions by a cumulative 94 million metric tons from adjusted baseline levels in 1998 through 2001 as a result of these voluntary actions.  The AEP System’s total CO 2 emissions in 2009 were 136 million metric tons.  Management estimates that 2010 emissions were approximately 140 million metric tons.

Certain groups have filed lawsuits alleging that emissions of CO 2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others.  The Registrant Subsidiaries have been named in pending lawsuits, which management is vigorously defending.  It is not possible to predict the outcome of these lawsuits or their impact on operations or financial condition.  See “Carbon Dioxide Public Nuisance Claims” and “Alaskan Villages’ Claims” sections of Note 6.

Future federal and state legislation or regulations that mandate limits on the emission of CO 2 would 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.  As a result, mandatory limits could have a material adverse impact on net income, cash flows and financial condition.

Global warming creates the potential for physical and financial risk.  The materiality of the risks depends on whether any physical changes occur quickly or over several decades and the extent and nature of those changes.  Physical risks from climate change could include changes in weather conditions.  Customers' energy needs currently vary with weather conditions, primarily temperature and humidity.  For residential customers, heating and cooling today represent their largest energy use.  To the extent weather patterns change significantly, customers' energy use could increase or decrease depending on the duration and magnitude of the changes.  Increased energy use due to weather changes could require the Registrant Subsidiaries to invest in more generating assets, transmission and other infrastructure to serve increased load, driving the cost of electricity higher.  Decreased energy use due to weather changes could affect financial condition through lower sales and decreased revenues.  Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions and increased storm restoration
 
 
409
 
costs.  The Registrant Subsidiaries may not recover all costs related to mitigating these physical and financial risks.  Weather conditions outside of the AEP System’s service territory could also have an impact on revenues, either directly through changes in the patterns of off-system power purchases and sales or indirectly through demographic changes as people adapt to changing weather.  The Registrant Subsidiaries buy and sell electricity depending upon system needs and market opportunities.  Extreme weather conditions that create high energy demand could raise electricity prices, which would increase the cost of energy the Registrant Subsidiaries provide to customers and could provide opportunity for increased wholesale sales.

To the extent climate change impacts a region's economic health, it could also impact 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

LIQUIDITY AND CAPITAL RESOURCES

Sources of Funding

Short-term funding for the Registrant Subsidiaries comes from AEP’s commercial paper program and revolving credit facilities through the Utility Money Pool.  AEP and its Registrant Subsidiaries operate a money pool to minimize the AEP System’s external short-term funding requirements and sell accounts receivable to provide liquidity.  Under credit facilities, $1.35 billion may be issued as letters of credit (LOC).  The Registrant Subsidiaries generally use short-term funding sources (the Utility Money Pool or receivables sales) to provide for interim financing of capital expenditures that exceed internally generated funds and periodically reduce their outstanding short-term debt through issuances of long-term debt, sale-leasebacks, leasing arrangements and additional capital contributions from Parent.

The Registrant Subsidiaries and certain other companies in the AEP System entered into a 3-year credit agreement which matures in April 2011.  In June 2010, the credit facility was reduced from $627 million to $478 million.  The Registrant Subsidiaries may issue LOCs under the credit facility.  Each subsidiary has a borrowing/LOC limit under the credit facility.  This facility is fully utilized for letters of credit providing liquidity support for Pollution Control Bonds.  Management intends to replace the revolving credit facility with bilateral letters of credit or refinance the bonds.  Management may redeem some portion of the Pollution Control Bonds supported by the facility.  As of December 31, 2010, a total of $477 million of LOCs were issued under the credit agreement.  The following table shows each Registrant Subsidiaries’ borrowing/LOC limit under the credit facility and the outstanding amount of LOCs.

           
LOC Amount
           
Outstanding
     
Credit Facility
   
Against the
     
Borrowing/LOC
   
Agreement at
  Company    
Limit
   
December 31, 2010
     
(in millions)
APCo
 
$
300 
 
$
232 
CSPCo
   
230 
   
- 
I&M
   
230 
   
78 
OPCo
   
400 
   
167 
PSO
   
65 
   
- 
SWEPCo
   
230 
   
- 

 
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Dividend Restrictions

Under the Federal Power Act, the Registrant Subsidiaries are restricted from paying dividends out of stated capital.  Various financing arrangements, charter provisions and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

Sales of Receivables

In 2010, AEP Credit renewed its receivables securitization agreement.  The agreement provides a commitment of $750 million from bank conduits to purchase receivables.  A commitment of $375 million expires in July 2011 and the remaining commitment of $375 million expires in July 2013. AEP Credit purchases accounts receivable from the Registrant Subsidiaries.  Management intends to extend or replace AEP Credit’s agreement expiring in July 2011 on or before its maturity.

BUDGETED CONSTRUCTION EXPENDITURES

The 2011 estimated construction expenditures by Registrant Subsidiary include generation, transmission and distribution related investments, as well as expenditures for compliance with environmental regulations as follows:

 
 
 
 
 
Budgeted Construction Expenditures
 
Company
 
Environmental
 
Generation
 
Transmission
 
Distribution
 
Other
 
Total
 
 
 
 
(in millions)
 
APCo
 
$
 112 
 
$
 62 
 
$
 103 
 
$
 161 
 
$
 12 
 
$
 450 
 
CSPCo
 
 
 21 
 
 
 50 
 
 
 25 
 
 
 84 
 
 
 7 
 
 
 187 
 
I&M
 
 
 1 
 
 
 185 
 
 
 29 
 
 
 82 
 
 
 8 
 
 
 305 
 
OPCo
 
 
 50 
 
 
 82 
 
 
 37 
 
 
 85 
 
 
 10 
 
 
 264 
 
PSO
 
 
 7 
 
 
 24 
 
 
 32 
 
 
 99 
 
 
 7 
 
 
 169 
 
SWEPCo
 
 
 10 
 
 
 266 
 
 
 85 
 
 
 71 
 
 
 10 
 
 
 442 

For 2012 through 2014, management forecasts annual construction expenditures for the AEP System to average between $2.6 billion and $3.1 billion.  The projected increases are generally the result of required environmental investment to comply with Federal EPA rules and additional transmission spending.  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.  The budgeted amounts exclude AFUDC and capitalized interest.  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.  SWEPCo’s budgeted construction expenditures include an amount for scheduled completion of the Turk Plant in 2012.

SIGNIFICANT TAX LEGISLATION

The   American Recovery and Reinvestment Tax Act of 2009 provided for several new grant programs, expanded tax credits and extended the 50% bonus depreciation provision enacted in the Economic Stimulus Act of 2008.  The Small Business Jobs Act, enacted in September 2010, included a one-year extension of the 50% bonus depreciation provision.  The Tax Relief, Unemployment Insurance Reauthorization and the Job Creation Act of 2010 extended the life of research and development, employment and several energy tax credits originally scheduled to expire at the end of 2010.  In addition, this act extended the time for claiming bonus depreciation and increased the deduction to 100% starting in September 2010 through 2011 and decreasing the deduction to 50% for 2012.

These enacted provisions will have no material impact on the Registrant Subsidiaries’ net income or financial condition but will have a favorable impact on their cash flows in 2011.  The provisions are expected to result in material future cash flow benefits.

 
411
 
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 DHLC, CSPCo, through its ownership of Conesville Coal Preparation Company (CCPC), and OPCo, through its use of the Conner 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, CCPC and Conner Run received the following notices of violation and proposed assessments under the Mine Act for the quarter ended December 31, 2010:

 
 
 
DHLC
 
CCPC
 
Conner Run
Number of Citations for Violations of Mandatory Health or
 
 
 
 
 
 
 
 
 
 
Safety Standards under 104 *
 
 
 1 
 
 
 - 
 
 
 - 
Number of Orders Issued under 104(b) *
 
 
 - 
 
 
 - 
 
 
 - 
Number of Citations and Orders for Unwarrantable Failure
 
 
 
 
 
 
 
 
 
 
to Comply with Mandatory Health or Safety Standards under
 
 
 
 
 
 
 
 
 
 
104(d) *
 
 
 - 
 
 
 - 
 
 
 - 
Number of Flagrant Violations under 110(b)(2) *
 
 
 - 
 
 
 - 
 
 
 - 
Number of Imminent Danger Orders Issued under 107(a) *
 
 
 - 
 
 
 - 
 
 
 - 
Total Dollar Value of Proposed Assessments
 
$
 1,026 
 
$
 - 
 
$
 - 
Number of Mining-related Fatalities
 
 
 - 
 
 
 - 
 
 
 - 
 
 
 
 
 
 
 
 
 
 
* References to sections under the Mine Act
 
 
 
 
 
 
 
 
 

DHLC currently has two legal actions pending before the Mine Safety and Health Administration (MSHA) challenging four violations issued by MSHA following an employee fatality in March 2009.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW 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 disclosure 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.

 
412
 
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 CSPCo and 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.

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 recognition with the recovery of such expense in regulated revenues.  Likewise, they match income with the regulated revenues from their customers in the same accounting period.  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.  Examples of new events 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, 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 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 5 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 included in Revenue for the years ended December 31, 2010, 2009 and 2008 were as follows:

 
 
Years Ended December 31,
Company
 
2010 
 
2009 
 
2008 
 
 
(in thousands)
APCo
 
$
 30,337 
 
$
 25,378 
 
$
 32,815 
CSPCo
 
 
 11,272 
 
 
 7,030 
 
 
 7,614 
I&M
 
 
 2,194 
 
 
 2,695 
 
 
 12,934 
OPCo
 
 
 (1,408)
 
 
 5,845 
 
 
 4,048 
PSO
 
 
 (4,159)
 
 
 4,415 
 
 
 (211)
SWEPCo
 
 
 (1,175)
 
 
 (282)
 
 
 5,008 

 
413
 
Assumptions and Approach Used

For each Registrant Subsidiary, the monthly estimate for unbilled revenues is computed as net generation 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.

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 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 10 and 11.  See “Fair Value Measurements of Assets and Liabilities” section of Note 1 for fair value calculation policy.

 
414
 
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 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 as approved by their regulators.  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 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.  For assets held for sale, an impairment is recognized if the expected net sales price is less than its book value.  For regulated assets, 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, the Registrant Subsidiaries 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.  The Registrant Subsidiaries perform depreciation studies to determine composite depreciation rates and related lives which are subject to periodic review by state regulatory commissions.  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 past 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 to be paid to participants in the Qualified Plans (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 medical and life insurance benefits for retired employees (Postretirement Plans).  The Pension Plans and Postretirement Plans are collectively the Plans.

The Registrant Subsidiaries participate in the Plans.  The Plans cover all employees who meet eligibility requirements.

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.

 
415
 
The following table shows the net periodic cost (credit) for the years ended December 31, 2010, 2009 and 2008 by Registrant Subsidiary for the Plans:

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension Plans
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
2010 
 
$
 15,818 
 
$
 5,945 
 
$
 20,138 
 
$
 13,756 
 
$
 5,439 
 
$
 7,096 
2009 
 
 
 10,459 
 
 
 2,752 
 
 
 13,939 
 
 
 8,267 
 
 
 3,080 
 
 
 4,831 
2008 
 
 
 3,337 
 
 
 (1,398)
 
 
 7,283 
 
 
 1,277 
 
 
 2,033 
 
 
 3,742 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement Benefit Plans
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
2010 
 
$
 19,048 
 
$
 8,250 
 
$
 13,857 
 
$
 15,862 
 
$
 7,443 
 
$
 7,574 
2009 
 
 
 24,231 
 
 
 10,554 
 
 
 17,433 
 
 
 20,557 
 
 
 9,134 
 
 
 9,453 
2008 
 
 
 14,896 
 
 
 6,041 
 
 
 9,765 
 
 
 11,357 
 
 
 5,581 
 
 
 5,539 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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 2011, 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.  Management anticipates that the investment managers employed for the Plans will invest the assets to generate future returns averaging 7.75% for the Qualified Plan and 7.5% 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/
 
2011 
 
Expected
 
2011 
 
Expected
 
Target
 
Long-Term
 
Target
 
Long-Term
 
Asset
 
Rate of
 
Asset
 
Rate of
 
Allocation
 
Return
 
Allocation
 
Return
Equity
 50 
%
 
 9.00 
%
 
 66 
%
 
 9.00 
%
Real Estate
 5 
%
 
 7.60 
%
 
-
%
 
 - 
%
Debt Securities
 39 
%
 
 5.75 
%
 
 32 
%
 
 5.75 
%
Other Investments
 5 
%
 
 10.50 
%
 
-
%
 
 - 
%
Cash and Cash Equivalents
 1 
%
 
 3.00 
%
 
 2 
%
 
 3.00 
%
Total
 100 
%
 
 
 
 
 100 
%
 
 
 

Management regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation.  Management believes that 7.75% for the Pension Plan and 7.5% for the Postretirement Plans are reasonable long-term rates of return on the Plans’ assets despite the recent market volatility.  The Pension Plan’s assets had an actual gain of 13.4% and 17.1% for the years ended December 31, 2010 and 2009, respectively.  The Postretirement Plans’ assets had an actual gain of 11.3% and 23.7% for the years ended December 31, 2010 and 2009, 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.

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, 2010, AEP had cumulative losses of approximately $285 million that remain to be recognized in the calculation of the market-related value of assets.  These unrecognized net actuarial losses will result in increases in the future pension costs depending on several factors,
 
 
416
 
including whether such losses at each measurement date exceed the corridor in accordance with “Compensation – Retirement Benefits” accounting guidance.  See the table below for the amount of cumulative losses by Registrant Subsidiary.

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 similar to those included in the Moody’s Aa bond index is constructed with a duration 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 at December 31, 2010 under this method was 5.05% for the Qualified Plan, 4.95% for the Nonqualified Plans and 5.25% for the Postretirement Plans.  Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on the Pension Plans’ assets of 7.75%, a discount rate of 5.05% and 4.95% 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 7.5%, a discount rate of 5.25% and various other assumptions, management estimates Postretirement Plan costs by Registrant Subsidiary will approximate the amounts in the following tables:

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cumulative Losses
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
Deferred Asset Loss
 
$
 37,859 
 
$
 20,714 
 
$
 33,345 
 
$
 38,291 
 
$
 15,767 
 
$
 16,582 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension Plans
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
2011 
 
$
 17,433 
 
$
 8,659 
 
$
 17,412 
 
$
 14,295 
 
$
 9,811 
 
$
 10,175 
2012 
 
 
 20,219 
 
 
 11,656 
 
 
 18,984 
 
 
 17,177 
 
 
 12,681 
 
 
 13,166 
2013 
 
 
 24,887 
 
 
 13,516 
 
 
 24,207 
 
 
 21,549 
 
 
 11,755 
 
 
 11,949 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Postretirement Benefit Plans
 
APCo
 
CSPCo
 
I&M
 
OPCo
 
PSO
 
SWEPCo
 
 
(in thousands)
2011 
 
$
 14,762 
 
$
 5,791 
 
$
 11,635 
 
$
 12,251 
 
$
 4,445 
 
$
 4,845 
2012 
 
 
 13,561 
 
 
 5,475 
 
 
 10,186 
 
 
 11,679 
 
 
 4,270 
 
 
 4,654 
2013 
 
 
 12,012 
 
 
 5,193 
 
 
 9,731 
 
 
 11,172 
 
 
 4,124 
 
 
 4,492 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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.

The value of AEP’s Pension Plans’ assets increased to $3.9 billion at December 31, 2010 from $3.4 billion at December 31, 2009 primarily due to a $500 million contribution.  During 2010, the Qualified Plan paid $465 million in benefits to plan participants and the nonqualified plans paid $15 million in benefits.  The value of AEP’s Postretirement Plans’ assets increased to $1.5 billion at December 31, 2010 from $1.3 billion at December 31, 2009 primarily due to investment gains and contributions.  The Postretirement Plans paid $142 million in benefits to plan participants during 2010.  See Note 8 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.

 
417
 
Assumptions and Approach Used

The critical assumptions used in developing the required estimates include the following key factors:

·  
Discount rate
·  
Rate of compensation increase
·  
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, 2010 Benefit Obligations
 
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
$
 (32,159)
 
$
 35,286 
 
$
 (22,728)
 
$
 25,268 
 
Compensation Increase Rate
 
 
 1,166 
 
 
 (1,086)
 
 
 3 
 
 
 (3)
 
Cash Balance Crediting Rate
 
 
 4,904 
 
 
 (4,116)
 
 
N/A
 
 
N/A
 
Health Care Cost Trend Rate
 
 
N/A
 
 
N/A
 
 
 19,401 
 
 
 (17,875)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effect on 2010 Periodic Cost
 
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
 
 (2,751)
 
 
 3,006 
 
 
 (2,366)
 
 
 2,655 
 
Compensation Increase Rate
 
 
 479 
 
 
 (439)
 
 
 113 
 
 
 (106)
 
Cash Balance Crediting Rate
 
 
 1,412 
 
 
 (1,259)
 
 
N/A
 
 
N/A
 
Health Care Cost Trend Rate
 
 
N/A
 
 
N/A
 
 
 3,257 
 
 
 (2,910)
 
Expected Return on Plan Assets
 
 
 (2,697)
 
 
 2,697 
 
 
 (1,050)
 
 
 1,054 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
CSPCo
 
 
 
Other Postretirement
 
 
 
Pension Plans
 
Benefit Plans
 
 
 
+0.5%
 
-0.5%
 
+0.5%
 
-0.5%
 
 
 
(in thousands)
 
Effect on December 31, 2010 Benefit Obligations
 
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
$
 (15,931)
 
$
 17,396 
 
$
 (9,880)
 
$
 11,002 
 
Compensation Increase Rate
 
 
 624 
 
 
 (577)
 
 
 2 
 
 
 (2)
 
Cash Balance Crediting Rate
 
 
 1,746 
 
 
 (1,507)
 
 
N/A
 
 
N/A
 
Health Care Cost Trend Rate
 
 
N/A
 
 
N/A
 
 
 8,300 
 
 
 (7,630)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effect on 2010 Periodic Cost
 
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
 
 (1,494)
 
 
 1,632 
 
 
 (991)
 
 
 1,110 
 
Compensation Increase Rate
 
 
 260 
 
 
 (239)
 
 
 51 
 
 
 (48)
 
Cash Balance Crediting Rate
 
 
 767 
 
 
 (684)
 
 
N/A
 
 
N/A
 
Health Care Cost Trend Rate
 
 
N/A
 
 
N/A
 
 
 1,413 
 
 
 (1,259)
 
Expected Return on Plan Assets
 
 
 (1,465)
 
 
 1,465 
 
 
 (472)
 
 
 474 
 
 
418
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
I&M
 
 
 
Other Postretirement
 
 
 
Pension Plans
 
Benefit Plans
 
 
 
+0.5%
 
-0.5%
 
+0.5%
 
-0.5%
 
 
 
(in thousands)
 
Effect on December 31, 2010 Benefit Obligations
 
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
$
 (29,382)
 
$
 32,383 
 
$
 (16,618)
 
$
 18,564 
 
Compensation Increase Rate
 
 
 1,499 
 
 
 (1,388)
 
 
 3 
 
 
 (3)
 
Cash Balance Crediting Rate
 
 
 5,229 
 
 
 (4,475)
 
 
N/A
 
 
N/A
 
Health Care Cost Trend Rate
 
 
N/A
 
 
N/A
 
 
 14,170 
 
 
 (12,858)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effect on 2010 Periodic Cost
 
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
 
 (2,365)
 
 
 2,584 
 
 
 (1,482)
 
 
 1,651 
 
Compensation Increase Rate
 
 
 412 
 
 
 (378)
 
 
 88 
 
 
 (82)
 
Cash Balance Crediting Rate
 
 
 1,213 
 
 
 (1,082)
 
 
N/A
 
 
N/A
 
Health Care Cost Trend Rate
 
 
N/A
 
 
N/A
 
 
 2,275 
 
 
 (2,014)
 
Expected Return on Plan Assets
 
 
 (2,316)
 
 
 2,316 
 
 
 (812)
 
 
 815 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPCo
 
 
 
Other Postretirement
 
 
 
Pension Plans
 
Benefit Plans
 
 
 
+0.5%
 
-0.5%
 
+0.5%
 
-0.5%
 
 
 
(in thousands)
 
Effect on December 31, 2010 Benefit Obligations
 
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
$
 (30,215)
 
$
 33,096 
 
$
 (21,157)
 
$
 23,654 
 
Compensation Increase Rate
 
 
 1,050 
 
 
 (968)
 
 
 2 
 
 
 (2)
 
Cash Balance Crediting Rate
 
 
 4,262 
 
 
 (3,562)
 
 
N/A
 
 
N/A
 
Health Care Cost Trend Rate
 
 
N/A
 
 
N/A
 
 
 18,318 
 
 
 (16,812)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effect on 2010 Periodic Cost
 
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
 
 (2,656)
 
 
 2,902 
 
 
 (2,041)
 
 
 2,287 
 
Compensation Increase Rate
 
 
 462 
 
 
 (424)
 
 
 104 
 
 
 (98)
 
Cash Balance Crediting Rate
 
 
 1,363 
 
 
 (1,215)
 
 
N/A
 
 
N/A
 
Health Care Cost Trend Rate
 
 
N/A
 
 
N/A
 
 
 2,899 
 
 
 (2,583)
 
Expected Return on Plan Assets
 
 
 (2,602)
 
 
 2,602 
 
 
 (964)
 
 
 968 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PSO
 
 
 
Other Postretirement
 
 
 
Pension Plans
 
Benefit Plans
 
 
 
+0.5%
 
-0.5%
 
+0.5%
 
-0.5%
 
 
 
(in thousands)
 
Effect on December 31, 2010 Benefit Obligations
 
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
$
 (11,647)
 
$
 12,698 
 
$
 (7,330)
 
$
 8,191 
 
Compensation Increase Rate
 
 
 673 
 
 
 (608)
 
 
 3 
 
 
 (3)
 
Cash Balance Crediting Rate
 
 
 3,529 
 
 
 (3,303)
 
 
N/A
 
 
N/A
 
Health Care Cost Trend Rate
 
 
N/A
 
 
N/A
 
 
 6,518 
 
 
 (5,434)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effect on 2010 Periodic Cost
 
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
 
 (1,129)
 
 
 1,234 
 
 
 (639)
 
 
 712 
 
Compensation Increase Rate
 
 
 197 
 
 
 (180)
 
 
 39 
 
 
 (37)
 
Cash Balance Crediting Rate
 
 
 578 
 
 
 (516)
 
 
N/A
 
 
N/A
 
Health Care Cost Trend Rate
 
 
N/A
 
 
N/A
 
 
 998 
 
 
 (883)
 
Expected Return on Plan Assets
 
 
 (1,104)
 
 
 1,104 
 
 
 (361)
 
 
 363 
 
 
419
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
SWEPCo
 
 
 
Other Postretirement
 
 
 
Pension Plans
 
Benefit Plans
 
 
 
+0.5%
 
-0.5%
 
+0.5%
 
-0.5%
 
 
 
(in thousands)
 
Effect on December 31, 2010 Benefit Obligations
 
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
$
 (11,515)
 
$
 12,552 
 
$
 (8,411)
 
$
 9,411 
 
Compensation Increase Rate
 
 
 666 
 
 
 (598)
 
 
 4 
 
 
 (4)
 
Cash Balance Crediting Rate
 
 
 4,295 
 
 
 (4,035)
 
 
N/A
 
 
N/A
 
Health Care Cost Trend Rate
 
 
N/A
 
 
N/A
 
 
 7,541 
 
 
 (6,338)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Effect on 2010 Periodic Cost
 
 
 
 
 
 
 
 
 
 
 
 
 
Discount Rate
 
 
 (1,126)
 
 
 1,230 
 
 
 (708)
 
 
 789 
 
Compensation Increase Rate
 
 
 196 
 
 
 (180)
 
 
 43 
 
 
 (40)
 
Cash Balance Crediting Rate
 
 
 577 
 
 
 (514)
 
 
N/A
 
 
N/A
 
Health Care Cost Trend Rate
 
 
N/A
 
 
N/A
 
 
 1,106 
 
 
 (978)
 
Expected Return on Plan Assets
 
 
 (1,100)
 
 
 1,100 
 
 
 (400)
 
 
 402 

N/A   Not Applicable

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.

I&M maintains trust funds for each regulatory jurisdiction.  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 as Spent Nuclear Fuel and Decommissioning Trusts on its Consolidated Balance Sheets.  I&M records these securities at fair value.  Management utilizes the trustee’s external pricing service to estimate the fair value of the underlying investments held in these trusts.  I&M’s investment managers review and validate the prices utilized by the trustee to determine fair value.  Management performs valuation testing to verify the fair values of the securities.  Management receives audit reports of the trustee’s operating controls and valuation processes.  See “Investments Held in Trust for Future Liabilities” section of Note 1 and “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11.

NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Pronouncement Adopted During  2010

The Registrant Subsidiaries prospectively adopted ASU 2009-17 “Consolidation” effective January 1, 2010.  SWEPCo no longer consolidates DHLC effective with the adoption of this standard.

See Note 2 for further discussion of 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, contingencies, financial instruments, emission allowances, fair value measurements, leases, insurance, hedge accounting, consolidation policy and discontinued operations.  Management also expects to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP.  The ultimate pronouncements resulting from these and future projects could have an impact on future net income and financial position.

 
420
 
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

The Registrant Subsidiaries’ risk management assets and liabilities are managed by AEPSC as agent.  The related risk management policies and procedures are instituted and administered by AEPSC.  See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section.  Also, see Note 10 – Derivatives and Hedging and Note 11 – Fair Value Measurements for additional information related to the Registrant Subsidiaries’ risk management contracts.

The following tables summarize the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2009:

 
MTM Risk Management Contract Net Assets (Liabilities)
 
Year Ended December 31, 2010
 
(in thousands)
 
 
 
APCo
 
 
 
 
 
Total MTM Risk Management Contract Net Assets at December 31, 2009
$
 45,197 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
 
 (28,148)
Fair Value of New Contracts at Inception When Entered During the Period (a)
 
 - 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
 
 
 
During the Period
 
 (217)
Changes in Fair Value Due to Market Fluctuations During the Period (c)
 
 65 
Changes in Fair Value Allocated to Regulated Jurisdictions (d)
 
 9,985 
Total MTM Risk Management Contract Net Assets
 
 26,882 
Cash Flow Hedge Contracts
 
 11,494 
Collateral Deposits
 
 14,420 
Total MTM Derivative Contract Net Assets at December 31, 2010
$
 52,796 
 
 
 
 
OPCo
 
 
 
 
 
Total MTM Risk Management Contract Net Assets at December 31, 2009
$
 26,330 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
 
 (17,265)
Fair Value of New Contracts at Inception When Entered During the Period (a)
 
 9,434 
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b)
 
 (715)
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
 
 
 
During the Period
 
 (441)
Changes in Fair Value Due to Market Fluctuations During the Period (c)
 
 4,013 
Changes in Fair Value Allocated to Regulated Jurisdictions (d)
 
 (3,092)
Total MTM Risk Management Contract Net Assets
 
 18,264 
Cash Flow Hedge Contracts
 
 (337)
Collateral Deposits
 
 10,289 
Total MTM Derivative Contract Net Assets at December 31, 2010
$
 28,216 
 
 
421
 
 
 
 
 
PSO
 
 
 
 
 
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2009
$
 (369)
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
 
 96 
Fair Value of New Contracts at Inception When Entered During the Period (a)
 
 - 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
 
 
 
During the Period
 
 (74)
Changes in Fair Value Due to Market Fluctuations During the Period (c)
 
 (19)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)
 
 (12)
Total MTM Risk Management Contract Net Assets
 
 (378)
Cash Flow Hedge Contracts
 
 13,692 
Collateral Deposits
 
 44 
Total MTM Derivative Contract Net Assets at December 31, 2010
$
 13,358 
 
 
 
 
SWEPCo
 
 
 
 
 
Total MTM Risk Management Contract Net Assets at December 31, 2009
$
 1,636 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
 
 (2,059)
Fair Value of New Contracts at Inception When Entered During the Period (a)
 
 - 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
 
 
 
During the Period
 
 (128)
Changes in Fair Value Due to Market Fluctuations During the Period (c)
 
 (25)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)
 
 (2,382)
Total MTM Risk Management Contract Net Assets
 
 (2,958)
Cash Flow Hedge Contracts
 
 128 
Collateral Deposits
 
 72 
Total MTM Derivative Contract Net Assets at December 31, 2010
$
 (2,758)

(a)
Reflects fair value on primarily long-term 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)
Reflects changes in methodology in calculating the credit and discounting liability fair value adjustments.
(c)
Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(d)
Relates to the net gains (losses) of those contracts that are not reflected on the Consolidated Statements of Income.  These net gains (losses) are recorded as regulatory liabilities/assets.

 
422
 
The following tables present the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate or (require) cash:

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets (Liabilities)
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
APCo
 
 
 
 
 
 
 
 
 
 
 
 
 
2011 
 
2012-2014
 
2015+
 
Total
 
 
(in thousands)
Level 1 (a)
$
 33 
 
$
 - 
 
$
 - 
 
$
 33 
Level 2 (b)
 
 3,588 
 
 
 14,518 
 
 
 241 
 
 
 18,347 
Level 3 (c)
 
 2,053 
 
 
 1,909 
 
 
 1,169 
 
 
 5,131 
Total
 
 5,674 
 
 
 16,427 
 
 
 1,410 
 
 
 23,511 
Dedesignated Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
Contracts (d)
 
 1,779 
 
 
 1,592 
 
 
 - 
 
 
 3,371 
Total MTM Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
Contract Net Assets
$
 7,453 
 
$
 18,019 
 
$
 1,410 
 
$
 26,882 
 
 
 
 
 
 
 
 
 
 
 
 
 
OPCo
 
 
 
 
 
 
 
 
 
 
 
 
 
2011 
 
2012-2014
 
2015+
 
Total
 
 
(in thousands)
Level 1 (a)
$
 23 
 
$
 - 
 
$
 - 
 
$
 23 
Level 2 (b)
 
 1,637 
 
 
 10,454 
 
 
 170 
 
 
 12,261 
Level 3 (c)
 
 1,455 
 
 
 1,330 
 
 
 823 
 
 
 3,608 
Total
 
 3,115 
 
 
 11,784 
 
 
 993 
 
 
 15,892 
Dedesignated Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
Contracts (d)
 
 1,252 
 
 
 1,120 
 
 
 - 
 
 
 2,372 
Total MTM Risk Management
 
 
 
 
 
 
 
 
 
 
 
 
Contract Net Assets
$
 4,367 
 
$
 12,904 
 
$
 993 
 
$
 18,264 

 
423
 
PSO
 
 
 
 
 
 
 
 
 
 
2011 
 
2012-2014
 
Total
 
 
(in thousands)
Level 1 (a)
$
 - 
 
$
 - 
 
$
 - 
Level 2 (b)
 
 (432)
 
 
 53 
 
 
 (379)
Level 3 (c)
 
 (1)
 
 
 2 
 
 
 1 
Total MTM Risk Management
 
 
 
 
 
 
 
 
 
Contract Net Assets
$
 (433)
 
$
 55 
 
$
 (378)
 
 
 
 
 
 
 
 
 
 
SWEPCo
 
 
 
 
 
 
 
 
 
 
2011 
 
2012-2014
 
Total
 
 
(in thousands)
Level 1 (a)
$
 - 
 
$
 - 
 
$
 - 
Level 2 (b)
 
 (3,055)
 
 
 95 
 
 
 (2,960)
Level 3 (c)
 
 2 
 
 
 - 
 
 
 2 
Total MTM Risk Management
 
 
 
 
 
 
 
 
 
Contract Net Assets
$
 (3,053)
 
$
 95 
 
$
 (2,958)

(a)
Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.  Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.
(b)
Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.  If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1 and OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market.
(c)
Level 3 inputs are unobservable inputs for the asset or liability.  Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.
(d)
Dedesignated Risk Management Contracts are 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 will be amortized into Revenues over the remaining life of the contracts.

Credit Risk

Counterparty credit quality and exposure of the Registrant Subsidiaries is generally consistent with that of AEP.

Value at Risk (VaR) Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates VaR to measure 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, at December 31, 2010, a near term typical change in commodity prices is not expected to have a material effect on net income, cash flows or financial condition.

 
424
 
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 December 31,
 
2010
 
2009
Company
 
End
 
High
 
Average
 
Low
 
End
 
High
 
Average
 
Low
 
(in thousands)
APCo
 
$
124
 
$
659
 
$
193
 
$
71
 
$
275
 
$
699
 
$
333
 
$
151
OPCo
   
100
   
545
   
161
   
54
   
201
   
530
   
244
   
113
PSO
   
3
   
70
   
15
   
1
   
10
   
34
   
12
   
4
SWEPCo
   
6
   
93
   
21
   
2
   
16
   
49
   
18
   
6

Management back-tests its 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.

As the VaR calculations capture recent price movements, management also performs regular stress testing of the portfolio to understand the exposure to extreme price movements.  Management employs a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last four years in order to ascertain which historical price movements translated into the largest potential MTM loss.  Management then researches the underlying positions, price movements and market events that created the most significant exposure and report the findings to the Risk Executive Committee or the Commercial Operations Risk Committee as appropriate.

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which 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 the Registrant Subsidiaries’ outstanding debt as of December 31, 2010 and 2009, the estimated EaR on the Registrant Subsidiaries’ debt portfolio was as follows:

   
December 31,
Company
 
2010
 
2009
   
(in thousands)
APCo
 
$
1,165 
 
$
1,837 
CSPCo
   
178 
   
216 
I&M
   
274 
   
227 
OPCo
   
926 
   
1,373 
PSO
   
658 
   
119 
SWEPCo
   
1,027 
   
305 
 
 
 
 
 
 
 
425
 
 
 
EXHIBIT 21
Subsidiaries of
American Electric Power Company, Inc.
As of December 31, 2010
The voting stock of each company shown indented is owned by 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
 
Percentage of
Voting Securities
Owned by
Immediate Parent
American Electric Power Company, Inc.
New York
       
American Electric Power Service Corporation
New York
    100.0    
AEP C&I Company, LLC
Delaware
    100.0    
AEP Coal, Inc.
Nevada
    100.0    
AEP Credit, Inc.
Delaware
    100.0    
AEP Fiber Venture, LLC
Virginia
    100.0    
AEP Generating Company
Ohio
    100.0    
AEP Investments, Inc.
Ohio
    100.0    
AEP Nonutility Funding LLC
Delaware
    100.0    
AEP Pro Serv, Inc.
Ohio
    100.0    
AEP Resources, Inc.
Ohio
    100.0    
AEP T&D Services, LLC
Delaware
    100.0    
AEP Transmission Holding Company, LLC
Delaware
    100.0    
AEP Utilities, Inc.
Delaware
    100.0    
AEP Texas Central Company
Texas
    100.0    
AEP Texas Central Transition Funding LLC
Delaware
    100.0    
AEP Texas Central Transition Funding II LLC
Delaware
    100.0    
AEP Texas North Company
Texas
    100.0    
AEP Texas North Generation Company LLC
Delaware
    100.0    
CSW Energy, Inc.
Texas
    100.0    
CSW Energy Services, Inc.
Delaware
    100.0    
Electric Transmission Texas, LLC
Delaware
    50.0  
(a)
AEP Utility Funding LLC
Delaware
    100.0    
Appalachian Power Company
Virginia
    98.7  
(b)
Cedar Coal Co.
West Virginia
    100.0    
Central Appalachian Coal Company
West Virginia
    100.0    
Central Coal Company
West Virginia
    50.0  
(c)
Southern Appalachian Coal Company
West Virginia
    100.0    
Columbus Southern Power Company
Ohio
    100.0    
Conesville Coal Preparation Company
Ohio
    100.0    
Ohio Valley Electric Corporation
Ohio
    4.3  
(d)
Indiana-Kentucky Electric Corporation
Indiana
    100.0    
Franklin Real Estate Company
Pennsylvania
    100.0    
Indiana Michigan Power Company
Indiana
    100.0    
Blackhawk Coal Company
Utah
    100.0    
Price River Coal Company
Indiana
    100.0    
Kentucky Power Company
Kentucky
    100.0    
Kingsport Power Company
Virginia
    100.0    
Ohio Power Company
Ohio
    99.4  
(e)
Cardinal Operating Company
Ohio
    50.0  
(f)
Central Coal Company
West Virginia
    50.0  
(c)
OP Gavin, LLC
Delaware
    100.0    
Ohio Valley Electric Corporation
Ohio
    39.2  
(d)
Indiana-Kentucky Electric Corporation
Indiana
    100.0    
Power Tree Carbon Company, LLC
Delaware
    9.2  
(g)
Public Service Company of Oklahoma
Oklahoma
    99.5  
(h)
Southwestern Electric Power Company
Delaware
    99.4  
(i)
Dolet Hills Lignite Company, LLC
Delaware
    100.0    
Oxbow Lignite Company, LLC
Delaware
    50.0  
(j)
Southwestern Arkansas Utilities Corporation
Arkansas
    100.0    
SWEPCo Capital Trust I
Delaware
    100.0    
The Arklahoma Corporation
Arkansas
    47.6  
(k)
Wheeling Power Company
West Virginia
    100.0    


NOTES:

(a)
Owned 50% by AEP Utilities, Inc; the other 50% is owned by a nonaffiliated company.
(b)
13,499,500 shares of Common Stock, all owned by parent, have one vote each and 177,465 shares of Preferred Stock, all owned by the public, have one vote each.
(c)
Owned 50% by Appalachian Power Company and 50% by Ohio Power Company.
(d)
American Electric Power Company, Inc. and Columbus Southern Power Company own 39.2% and 4.3% of the stock, respectively, and the remaining 56.5% is owned by nonaffiliated companies.
(e)
27,952,473 shares of Common Stock, all owned by parent, have one vote each and 166,158 shares of Preferred Stock, all owned by the public, have one vote each.
(f)
Ohio Power Company owns 50% of the Common Stock; the other 50% is owned by a nonaffiliated company.
(g)
The remaining 90.8% is owned by nonaffiliated companies.
(h)
9,013,000 shares of Common Stock, all owned by parent, have one vote each and 48,818 shares of Preferred Stock, all owned by the public, have one vote each.
(i)
7,536,640 shares of Common Stock, all owned by parent, have one vote each and 46,958 shares of Preferred Stock all owned by the public, have one vote each.
(j)
Southwestern Electric Power Company owns 50% of the Common Stock; the other 50% is owned by a nonaffiliated company.
(k)
 
Southwestern Electric Power Company owns 47.6% of the Common Stock; the other 52.4% is owned by nonaffiliated companies.

Exhibit 23


 
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 
We consent to the incorporation by reference in Registration Statements No. 333-46360, 333-128273, 333-66048, 333-62278 and 333-128043 on Form S-8 and Registration Statements No. 333-155646 and 333-156387 on Form S-3 of our reports dated February 25, 2011 relating to the consolidated financial statements (which report on the consolidated financial statements expresses an unqualified opinion and includes an explanatory paragraph relating to the adoption of a new accounting pronouncement in 2010) 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, 2010.
 
 

 
 

 
/s/ Deloitte & Touche LLP
 
Columbus, Ohio
February 25, 2011
 

Exhibit 24

POWER OF ATTORNEY
 
AMERICAN ELECTRIC POWER COMPANY, INC.
Annual Report on Form 10-K for the Fiscal Year Ended
December 31, 2010


The undersigned directors of AMERICAN ELECTRIC POWER COMPANY, INC., a New York corporation (the "Company"), do hereby constitute and appoint MICHAEL G. MORRIS, CHARLES E. ZEBULA 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, 2010, 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 25th day of January, 2011.


/s/ E. R. Brooks
/s/ Lester A. Hudson, Jr.
E. R. Brooks
Lester A. Hudson, Jr.
   
/s/ Donald M. Carlton
/s/ Michael G. Morris
Donald M. Carlton
Michael G. Morris
   
/s/ James F. Cordes
/s/ Lionel L. Nowell, III
James F. Cordes
Lionel L. Nowell, III
   
/s/ Ralph D. Crosby, Jr.
/s/ Richard L. Sandor
Ralph D. Crosby, Jr.
Richard L. Sandor
   
/s/ Linda A. Goodspeed
/s/ Kathryn D. Sullivan
Linda A. Goodspeed
Kathryn D. Sullivan
   
/s/ Thomas E. Hoaglin
/s/ Sara Martinez Tucker
Thomas E. Hoaglin
Sara Martinez Tucker
   
 
/s/ John F. Turner
 
John F. Turner
   
   

EXHIBIT 31(a)
CERTIFICATION PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002

I, Michael G. Morris, 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 which 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 24, 2011    
By:           
 
/s/ Michael G. Morris
Michael G. Morris
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 which 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 24, 2011    
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, 2010 as filed with the Securities and Exchange Commission on the date hereof, I, Michael G. Morris, 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/ Michael G. Morris
Michael G. Morris
Chief Executive Officer


February 24, 2011


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 American Electric Power Company, Inc. (the “Company”) on Form 10-K (the “Report”) for the year ended December 31, 2010 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 24, 2011


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.