SOUTHWESTERN ELECTRIC POWER CO (Form: 10-Q, Received: 07/27/2012 10:45:39)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For The Quarterly Period Ended June 30, 2012

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For The Transition Period from ____ to ____

Commission	Registrants; States of Incorporation;	I.R.S. Employer
File Number	Address and Telephone Number	Identification Nos.

1-3525	AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation)	13-4922640
1-3457	APPALACHIAN POWER COMPANY (A Virginia Corporation)	54-0124790
1-3570	INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)	35-0410455
1-6543	OHIO POWER COMPANY (An Ohio Corporation)	31-4271000
0-343	PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)	73-0410895
1-3146	SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation)	72-0323455
	1 Riverside Plaza, Columbus, Ohio 43215-2373
	Telephone (614) 716-1000

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

Indicate by check mark whether the registrants have submitted electronically and posted on their corporate websites, 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	X	No

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	X	Accelerated filer

Non-accelerated filer		Smaller reporting company

Indicate by check mark whether Appalachian Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers or smaller reporting companies. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer		Accelerated filer

Non-accelerated filer	X	Smaller reporting company

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
Yes			No	X

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

			Number of shares of common stock outstanding of the registrants at July 26, 2012

American Electric Power Company, Inc.			484,902,556
			($6.50 par value)
Appalachian Power Company			13,499,500
			(no par value)
Indiana Michigan Power Company			1,400,000
			(no par value)
Ohio Power Company			27,952,473
			(no par value)
Public Service Company of Oklahoma			9,013,000
			($15 par value)
Southwestern Electric Power Company			7,536,640
			($18 par value)

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX OF QUARTERLY REPORTS ON FORM 10-Q

June 30, 2012

			Page Number
Glossary of Terms			i

Forward-Looking Information			iv

Part I. FINANCIAL INFORMATION

		Items 1, 2 and 3 - Financial Statements, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Quantitative and Qualitative Disclosures About Market Risk:
American Electric Power Company, Inc. and Subsidiary Companies:
	Management’s Discussion and Analysis of Financial Condition and Results of Operations		1
	Condensed Consolidated Financial Statements		30
	Index of Condensed Notes to Condensed Consolidated Financial Statements		36

Appalachian Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations		80
	Condensed Consolidated Financial Statements		86
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		92

Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis of Results of Operations		94
	Condensed Consolidated Financial Statements		100
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		106

Ohio Power Company Consolidated:
	Management’s Narrative Discussion and Analysis of Results of Operations		108
	Condensed Consolidated Financial Statements		115
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		121

Public Service Company of Oklahoma:
	Management’s Narrative Discussion and Analysis of Results of Operations		123
	Condensed Financial Statements		126
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		132

Southwestern Electric Power Company Consolidated:
	Management’s Narrative Discussion and Analysis of Results of Operations		134
	Condensed Consolidated Financial Statements		139
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		145

Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries			146

Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries			201

Controls and Procedures			207

Part II. OTHER INFORMATION

	Item 1.	Legal Proceedings		208
	Item 1A.	Risk Factors		208
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		211
	Item 4.	Mine Safety Disclosures		211
	Item 5.	Other Information		211
	Item 6.	Exhibits:		211
			Exhibit 10
			Exhibit 12
			Exhibit 31(a)
			Exhibit 31(b)
			Exhibit 32(a)
			Exhibit 32(b)
			Exhibit 95
			Exhibit 101.INS
			Exhibit 101.SCH
			Exhibit 101.CAL
			Exhibit 101.DEF
			Exhibit 101.LAB
			Exhibit 101.PRE

SIGNATURE				212

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

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., a utility holding company.
AEP Consolidated		AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit		AEP Credit, Inc., a consolidated variable interest entity of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East companies		APCo, I&M, KPCo and OPCo.
AEP Energy		AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States. BlueStar began doing business as AEP Energy, Inc. in June 2012.
AEP System		American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
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.
AEPSC		American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC		Allowance for Funds Used During Construction.
AOCI		Accumulated Other Comprehensive Income.
APCo		Appalachian Power Company, an AEP electric utility subsidiary.
APSC		Arkansas Public Service Commission.
BlueStar		BlueStar Energy Holdings, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States. BlueStar began doing business as AEP Energy, Inc. in June 2012.
BOA		Bank of America Corporation.
CAA		Clean Air Act.
CLECO		Central Louisiana Electric Company, a nonaffiliated utility company.
CO 2		Carbon dioxide and other greenhouse gases.
Cook Plant		Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M.
CRES		Competitive Retail Electric Service.
CSPCo		Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.
DCC Fuel		DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC and DCC Fuel V LLC, consolidated variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DHLC		Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
E&R		Environmental compliance and transmission and distribution system reliability.
EIS		Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated variable interest entity of AEP.
ERCOT		Electric Reliability Council of Texas regional transmission organization.
ESP		Electric Security Plans, filed with the PUCO, pursuant to the Ohio Amendments.
ETT		Electric Transmission Texas, LLC, an equity interest joint venture between AEP and MidAmerican Energy Holdings Company Texas Transco, LLC formed to own and operate electric transmission facilities in ERCOT.
FAC		Fuel Adjustment Clause.
FASB		Financial Accounting Standards Board.
Federal EPA		United States Environmental Protection Agency.

Term		Meaning

FERC		Federal Energy Regulatory Commission.
FGD		Flue Gas Desulfurization or scrubbers.
FTR		Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP		Accounting Principles Generally Accepted in the United States of America.
I&M		Indiana Michigan Power Company, an AEP electric utility subsidiary.
IGCC		Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
Interconnection Agreement		An agreement by and among APCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants.
IRS		Internal Revenue Service.
IURC		Indiana Utility Regulatory Commission.
KPCo		Kentucky Power Company, an AEP electric utility subsidiary.
KPSC		Kentucky Public Service Commission.
KWH		Kilowatthour.
LPSC		Louisiana Public Service Commission.
MISO		Midwest Independent Transmission System Operator.
MMBtu		Million British Thermal Units.
MPSC		Michigan Public Service Commission.
MTM		Mark-to-Market.
MW		Megawatt.
NEIL		Nuclear Electric Insurance Limited insures domestic and international nuclear utilities for the costs associated with interruptions, damages, decontaminations and related nuclear risks.
NO x		Nitrogen oxide.
Nonutility Money Pool		Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
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.
PJM		Pennsylvania – New Jersey – Maryland regional transmission organization.
PM		Particulate Matter.
POLR		Provider of Last Resort revenues.
PSO		Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO		Public Utilities Commission of Ohio.
PUCT		Public Utility Commission of Texas.
Registrant Subsidiaries		AEP subsidiaries which are SEC registrants; APCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts		Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant		A 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, responsible for moving electricity over large interstate areas.
Sabine		Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo.
SEC		U.S. Securities and Exchange Commission.
SEET		Significantly Excessive Earnings Test.

Term		Meaning

SIA		System Integration Agreement, effective June 15, 2000, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SNF		Spent Nuclear Fuel.
SO 2		Sulfur dioxide.
SPP		Southwest Power Pool regional transmission organization.
Stall Unit		J. Lamar Stall Unit at Arsenal Hill Plant.
SWEPCo		Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC		AEP Texas Central Company, an AEP electric utility subsidiary.
TNC		AEP Texas North Company, an AEP electric utility subsidiary.
Transition Funding		AEP Texas Central Transition Funding I LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas restructuring law.
Turk Plant		John W. Turk, Jr. Plant, a 600 MW coal-fired plant under construction in Arkansas that is 73% owned by SWEPCo.
Utility Money Pool		Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIE		Variable Interest Entity.
Virginia SCC		Virginia State Corporation Commission.
WPCo		Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC		Public Service Commission of West Virginia.

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” of the 2011 Annual Report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook. These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected. Forward-looking statements in this document are presented as of the date of this document. Except to the extent required by applicable law, we undertake no obligation to update or revise any forward-looking statement. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

·	The economic climate 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 recent storms in our eastern service territory, 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 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, and transmission lines and facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are cancelled) through applicable rate cases or competitive rates.
·	New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation and cost recovery of our plants and related assets.
·	A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers.
·	Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
·	Resolution of litigation.
·	Our ability to constrain operation and maintenance costs.
·	Our ability to develop and execute a strategy based on a view regarding prices of electricity, 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 our debt.
·	Volatility and changes in markets for electricity, natural gas and other energy-related commodities.

·	Changes in utility regulation, including the implementation of ESPs and the transition to market and expected legal separation for generation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP.
·	Accounting pronouncements periodically issued by accounting standard-setting bodies.
·	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.
·	Our ability to recover through rates or market prices any remaining unrecovered investment in generating units that may be retired before the end of their previously projected useful lives.
·	Our ability to successfully manage negotiations with stakeholders and obtain regulatory approval to terminate or amend the Interconnection Agreement.
·	Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
·	Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.

The forward looking statements of AEP and its Registrant Subsidiaries speak only as of the date of this report or as of the date they are made. AEP and its Registrant Subsidiaries expressly disclaim any obligation to update any forward-looking information. For a more detailed discussion of these factors, see “Risk Factors” in the 2011 Annual Report and in Part II of this report.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Proposed June 2012 – May 2015 Ohio ESP

Intervenors and the PUCO staff filed testimony in May 2012 in opposition to many aspects of OPCo’s ESP, including the proposed RSR and the two-tiered capacity pricing structure for CRES providers. In addition, the PUCO staff’s testimony included a proposal to increase the vegetation management base used for calculating over/under recovery on incremental vegetation spend from $21 million to $39 million, which could increase future Other Operation and Maintenance expense by $18 million on an annual basis. A decision from the PUCO is expected in August 2012. See “Ohio Electric Security Plan Filing” section of Note 2.

Ohio Customer Choice

In our Ohio service territory, various CRES providers are targeting retail customers by offering alternative generation service. As a result, in comparison to the second quarter of 2011 and the first six months of 2011, we lost approximately $56 million and $99 million, respectively, of gross margin. We are recovering a portion of lost margins through collection of capacity revenues from CRES providers, off-system sales and new revenues from AEP Retail Energy Partners LLC, our CRES provider and member of our Generating and Marketing segment. We have lost 34% of our Ohio load to CRES providers. To enhance our competitive position in Ohio, AEP Retail Energy Partners LLC targets retail customers, both within and outside of our retail service territory.

Ohio Capacity Rate

In March 2012, in response to OPCo’s motion for relief, the PUCO ordered that CRES providers not qualifying for the tier one capacity billing rate of $146/MW day, which is substantially below OPCo’s current capacity cost of approximately $355/MW day, will pay a tier two capacity billing rate of $255/MW day. In July 2012, the PUCO issued an order in the capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer its incurred capacity costs not recovered from CRES providers to the extent that the total incurred capacity costs do not exceed $188.88/MW day. The RPM price is approximately $20/MW day through May 2013. The order stated that the PUCO would establish an appropriate recovery mechanism in the pending June 2012 – May 2015 ESP proceeding. The PUCO postponed implementation of the order until August 8, 2012 or until an order is issued in OPCo’s pending June 2012 – May 2015 ESP proceeding, whichever is sooner. In July 2012, OPCo requested rehearing of the PUCO order. See “Ohio Electric Security Plan Filing” section of Note 2.

Proposed Corporate Separation and Termination of the Interconnection Agreement

In March 2012, OPCo filed an application with the PUCO for approval of the corporate separation of its generation assets including the transfer of generation assets to a nonregulated AEP subsidiary at net book value. Additional filings at the FERC and other state commissions related to corporate separation are expected to be filed in the future. If all regulatory approvals are received, our results of operations related to generation in Ohio will be determined by our ability to sell power and capacity at a profit at rates determined by the prevailing market. If we are unable to sell power and capacity at a profit, it could reduce future net income and cash flows and impact financial condition. A decision is pending from the PUCO.

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC. It is unknown at this time whether the Interconnection Agreement 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. Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future. If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

Sustainable Cost Reductions

In April 2012, we initiated a process to identify employee repositioning opportunities and efficiencies that will result in sustainable cost savings. We recorded a charge to expense of $13 million in the second quarter of 2012 related to the elimination of approximately 170 positions in the first phase of this process. In May 2012, we selected one consulting firm to conduct an organizational and process optimization evaluation and a second consulting firm to evaluate our current employee benefit programs. The second phase of this process is expected to be completed by the end of 2012 with additional cost reductions.

Storm Damage

In late June 2012 and early July 2012, our eastern service territory was significantly impacted by several severe storms. In the second quarter of 2012, AEP recorded minimal incremental operation and maintenance expenses related to the June 2012 storms. AEP expects to incur an estimated $230 million in total storm restoration costs in the third quarter of 2012, including an estimated $70 million in capital spending related to these storms and an estimated $160 million in incremental operation and maintenance costs. We intend to defer the majority of the incremental operation and maintenance costs and seek future recovery. If we are not ultimately permitted to recover these storm costs, it would reduce future net income and cash flows and impact financial condition.

Significantly Excessive Earnings Test

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off of certain pretax earnings in 2010 and a subsequent refund to customers during 2011. In May 2011, the Industrial Energy Users-Ohio and the Ohio Energy Group (OEG) filed appeals with the Supreme Court of Ohio challenging the PUCO’s SEET decision. In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order. Subsequent testimony and legal briefs from intervenors recommended refunds of 2010 earnings. OPCo is required to file its 2011 SEET filing with the PUCO in 2012 on a separate CSPCo and OPCo company basis. The PUCO approved OPCo’s request to file the 2011 SEET on July 31, 2012 or one month after the PUCO issues an order on the 2010 SEET, whichever is later. Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo. See “Ohio Electric Security Plan Filing” section of Note 2.

Indiana Base Rate Case

In September 2011, I&M filed a request with the IURC for a net annual increase in Indiana base rates of $149 million based upon a return on common equity of 11.15%. The $149 million net annual increase reflects an increase in base rates of $178 million offset by proposed corresponding reductions of $13 million to the off-system sales sharing rider, $9 million to the PJM cost rider and $7 million to the clean coal technology rider rates. The request included an increase in depreciation rates that would result in a $25 million increase in annual depreciation expense.

In May 2012, the Indiana Office of Utility Consumer Counselor filed testimony that recommended an increase in base rates of $28 million, excluding reductions to certain riders, based upon a return on common equity of 9.2%. I&M filed rebuttal testimony in May 2012 which supported an increase of $170 million in base rates, excluding reductions to certain riders. Final hearings were held in June 2012. A decision from the IURC is expected in the fourth quarter of 2012. See “2011 Indiana Base Rate Case” section of Note 2.

Turk Plant

Texas Base Rate Case

In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million based upon an 11.25% return on common equity to be effective January 2013. The requested base rate increase includes a return on and of the Texas jurisdictional share of Turk Plant generation investment at December 2011 and total estimated transmission costs of the Turk Plant along with associated costs, including operations and maintenance costs. It also proposed vegetation management expenditures and includes recovery of the Stall Unit.

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 cost approximately $400 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. 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 would reduce future net income and cash flows and impact financial condition. See “Cook Plant Unit 1 Fire and Shutdown” section of Note 3.

Nuclear Regulatory Commission

As a result of the nuclear plant situation in Japan following a March 2011 earthquake, the Nuclear Regulatory Commission (NRC) initiated a review of safety procedures and requirements for nuclear generating facilities. This review could increase procedures and testing requirements, require physical modifications to the plant and increase future operating costs at the Cook Plant. The NRC is also looking into the fuel used at eleven reactors, including the units at the Cook Plant. Their concern relates to fuel temperatures if abnormal conditions are experienced. We continue to monitor this issue and respond to the NRC’s inquiry, as necessary. In addition to the review by the NRC, Congress could consider legislation tightening oversight of nuclear generating facilities. We are unable to predict the impact of potential future regulation of nuclear facilities.

Life Cycle Management Project

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the Cook Plant Life Cycle Management Project (LCM Project), which consists of a group of capital projects for Cook Plant Units 1 and 2. The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.

In Indiana, I&M requested recovery of certain project costs, including interest, through a rider effective January 2013. In Michigan, I&M requested that the MPSC approve a Certificate of Public Convenience and Necessity and authorize I&M to defer, on an interim basis, incremental depreciation and property tax costs, including interest, along with study, analysis and development costs until the applicable costs are included in I&M’s base rates. As of June 30, 2012, I&M has incurred $92 million related to the LCM Project. If I&M is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

LITIGATION

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. We assess the probability of loss for each contingency and accrue a liability for cases that have a probable likelihood of loss if the loss can be estimated. For details on our regulatory proceedings and pending litigation see Note 3 – Rate Matters, Note 5 – Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Financial Discussion and Analysis” in the 2011 Annual Report. Additionally, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies included herein. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

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, new proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.

We are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of our nuclear units. We are also engaged in the development of possible future requirements including the items discussed below and reductions of CO 2 emissions to address concerns about global climate change. We, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court. The U.S. House of Representatives passed legislation called the Transparency in Regulatory Analysis of Impacts on the Nation (the TRAIN Act) that would delay implementation of certain Federal EPA rules and facilitate a comprehensive analysis of their impacts. The Senate is considering similar legislation. We believe that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

See a complete discussion of these matters in the “Environmental Issues” section of “Management’s Financial Discussion and Analysis” in the 2011 Annual Report. We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. We should be able to recover certain of these expenditures through market prices in deregulated jurisdictions. If not, the costs of environmental compliance could reduce future net income and cash flows and impact financial condition.

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System. We continue to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of June 30, 2012, the AEP System had a total generating capacity of 37,035 MWs, of which 23,900 MWs are coal-fired. We continue to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on our coal-fired generating facilities. Based upon our estimates, investment to meet these proposed requirements ranges from approximately $6 billion to $7 billion between 2012 and 2020. These amounts include investments to convert 1,055 MWs of coal generation to natural gas capacity.

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

Subject to the factors listed above and based upon our continuing evaluation, we have given notice to the applicable RTOs of our intent to retire the following plants or units of plants before or during 2016:

		Generating
Company	Plant Name and Unit	Capacity
		(in MWs)
APCo	Clinch River Plant, Unit 3		235
APCo	Glen Lyn Plant		335
APCo	Kanawha River Plant		400
APCo/OPCo	Philip Sporn Plant, Units 1-4		600
I&M	Tanners Creek Plant, Units 1-3		495
KPCo	Big Sandy Plant, Unit 1		278
OPCo	Conesville Plant, Unit 3		165
OPCo	Kammer Plant		630
OPCo	Muskingum River Plant, Units 1-4		840
OPCo	Picway Plant		100
SWEPCo	Welsh Plant, Unit 2		528
Total			4,606

Duke Energy Corporation, the operator of W. C. Beckjord Generating Station, has announced its intent to close the facility in 2015. OPCo owns 12.5% (54 MWs) of one unit at that station.

We are monitoring the potential impact that the proposed corporate separation of OPCo’s generation assets and the proposed termination of the Interconnection Agreement could have on the recoverability of OPCo’s generation assets.

In April 2012, we reached an agreement in principle with the Federal EPA, the State of Oklahoma and other parties to retire one coal-fired unit of PSO’s Northeastern Station no later than 2016, install emission controls on the second coal-fired Northeastern unit in 2016 and retire the second unit no later than 2026. These two coal-fired units have a combined generating capacity of 930 MWs. The parties are working toward a final settlement agreement.

Plans for and the timing of conversion of some of our coal units to natural gas, installing emission control equipment on other units and closure of existing units will be impacted by changes in emission requirements and demand for power. To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows.

Environmental Control Applications

Rockport Plant

I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit one unit at its Rockport Plant with environmental controls estimated to cost $1.4 billion to comply with new requirements. AEGCo and I&M jointly own Unit 1 and jointly lease Unit 2 of the Rockport Plant. I&M is also evaluating options related to the maturity of the lease for Rockport Plant Unit 2 in 2022 and continues to investigate alternative compliance technologies for these Units as part of its overall compliance strategy. As of June 30, 2012, AEGCo and I&M have incurred $10 million and $10 million, respectively, related to this project.

In July 2012, certain intervenors filed testimony which recommended costs caps ranging from $1.1 billion to $1.4 billion if the IURC approved the CPCN. In addition, the Indiana Office of Utility Consumer Counselor recommended the CPCN be denied until a more detailed and precise project plan and cost estimates are filed with the IURC. If I&M receives approval of a CPCN, I&M will file for cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism. An IURC decision is expected in the fourth quarter of 2012.

Big Sandy Unit 2 FGD System

In May 2012, KPCo filed a motion with the KPSC to withdraw its application seeking approval of a Certificate of Public Convenience and Necessity to retrofit Big Sandy Unit 2 with a dry FGD system. The motion was accepted by the KPSC in May 2012. KPCo is currently re-evaluating its needs to meet the short and long-term energy needs of its customers at the most reasonable costs. KPCo has not determined its future plan. As of June 30, 2012, KPCo has incurred $29 million related to the project. Management intends to pursue recovery of all costs related to this project. If KPCo is not ultimately permitted to recover its incurred costs, it would reduce future net income and cash flows.

Flint Creek Plant

In February 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA. The estimated cost of the project is $408 million, excluding AFUDC and company overheads. As a joint owner of the Flint Creek Plant, SWEPCo’s portion of those costs is estimated at $204 million. Through June 30, 2012, SWEPCo has incurred $9 million related to this project. In June 2012, the APSC staff and the Arkansas Attorney General’s office filed testimony that recommended additional analysis be performed in order to reach a final conclusion. The Sierra Club filed testimony that recommended the APSC deny the declaratory order. SWEPCo is currently reviewing the testimony and will file rebuttal testimony on July 30, 2012. A decision is pending from the APSC.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements.

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) to address regional haze in federal parks and other protected areas. BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants. CAVR will be implemented through individual state implementation plans (SIPs) or, if SIPs are not adequate or are not developed on schedule, through federal implementation plans (FIPs). The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas and Oklahoma. The Federal EPA finalized a FIP for Oklahoma that contains more stringent control requirements for SO 2 emissions from affected units in that state. No action has been finalized in Arkansas. In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the Cross-State Air Pollution Rule (CSAPR) trading programs to use those programs in place of source-specific BART for SO 2 and NO x emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states. As a result, depending on how the states decide to implement the CAVR, compliance with the CSAPR requirements may be sufficient to satisfy CAVR's BART requirements without the need for additional unit-specific controls.

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.

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

Cross-State Air Pollution Rule (CSAPR)

In August 2011, the Federal EPA issued CSAPR. Certain revisions to the rule were finalized in March 2012. CSAPR relies on newly-created SO 2 and NO x allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states. Interstate trading of allowances is allowed on a restricted sub-regional basis beginning in 2012. Arkansas and Louisiana are subject only to the seasonal NO x program in the rule. Texas is subject to the annual programs for SO 2 and NO x in addition to the seasonal NO x program. The annual SO 2 allowance budgets in Indiana, Ohio and West Virginia have been reduced significantly in the rule. Numerous affected entities, states and other parties filed petitions to review the CSAPR in the United States Court of Appeals for the District of Columbia Circuit. Several of the petitioners filed motions to stay the implementation of the rule pending judicial review. In December 2011, the court granted the motions for stay. Oral argument was heard in April 2012. A supplemental rule includes Oklahoma in the seasonal NO x program. The supplemental rule was finalized in December 2011 with an increased NO x emission budget for the 2012 compliance year. A separate appeal of the supplemental rule has been filed, but is being held in abeyance until the court issues a decision in the main CSAPR appeal. The Federal EPA issued a final Error Corrections Rule and further CSAPR revisions in 2012 to make corrections to state budgets and unit allocations and to remove the restrictions on interstate trading in the first phase of CSAPR. Challenges to these rules have also been filed, but are being held in abeyance pending a decision in the main appeal.

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

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In February 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants. The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal on a site-wide 30-day rolling average basis. In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans. The effective date of the final rule was April 16, 2012 and compliance is required within three years. We are participating through various organizations in the petitions for administrative reconsideration and judicial review that have been filed. In July 2012, the Federal EPA issued a letter announcing that it will grant petitions for administrative reconsideration of certain issues related to the new source standards, including measurement issues and application of variability factors that may have an impact on the level of the standards. The letter also announced a three-month stay in the effective date of the new source standards. It is uncertain whether any of the information generated during the reconsideration process will affect the standards for existing sources.

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

Regional Haze

In March 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze SIP submitted by the State of Oklahoma through the Department of Environmental Quality. The Federal EPA proposed to approve all of the NO x control measures in the SIP and disapprove the SO 2 control measures for six electric generating units, including two units owned by PSO. The Federal EPA proposed a FIP that would require these units to install technology capable of reducing SO 2 emissions to 0.06 pounds per million British thermal units within three years of the effective date of the FIP. PSO submitted comments on the proposed action demonstrating that the cost-effectiveness calculations performed by the Federal EPA were unsound, challenging the period for compliance with the final rule and showing that the visibility improvements secured by the proposed SIP were significant and cost-effective. The Federal EPA finalized the FIP in December 2011 that mirrored the proposed rule but established a five-year compliance schedule. PSO filed a petition for review of the FIP in the Tenth Circuit Court of Appeals and engaged in settlement discussions with the Federal EPA, the State of Oklahoma and other parties. In April 2012, we reached an agreement in principle that would provide for submission of a revised Regional Haze SIP requiring the retirement of one coal-fired unit of PSO’s Northeastern Station no later than 2016, installation of emission controls on the second coal-fired Northeastern unit in 2016 and retirement of the second unit no later than 2026. The parties are working toward finalizing a settlement agreement which is intended to allow PSO to meet its compliance obligations under the regional haze and HAPs rules.

CO 2 Regulation

In March 2012, the Federal EPA issued a proposal to regulate CO 2 emissions from new fossil fuel-fired electricity generating units. The proposed rule establishes a new source performance standard of 1,000 pounds of CO 2 per megawatt hour of electricity generated, a rate that most natural gas combined cycle units can meet, but that is substantially below the emission rate of a new pulverized coal generator or an integrated gas combined cycle unit that uses coal for fuel. As proposed, the rule does not apply to new gas-fired stationary combustion turbines used as peaking units, does not apply to existing, modified or reconstructed sources, and does not apply to units whose CO 2 emission rate increases as a result of the addition of pollution control equipment to control criteria pollutant emissions or HAPs. The rule is not anticipated to have a significant immediate impact on the AEP System since it does not apply to existing units or units that have already commenced construction, like our Turk Plant. The comment period closed in June 2012. New Source Performance Standards affect units that have not yet received permits, but complete the permitting process while the proposal is pending. The standards have been challenged in the United States Court of Appeals for the District of Columbia Circuit. We cannot predict the outcome of that litigation.

In June 2012, the United States Court of Appeals for the District of Columbia Circuit issued a decision upholding, in all material respects, the Federal EPA’s endangerment finding, its regulatory program for CO 2 emissions from new motor vehicles and its plan to phase in regulation of CO 2 emissions from stationary source under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs. The Federal EPA also finalized a rule in June 2012 that retains the current thresholds for permitting stationary sources under the PSD and Title V operating permit programs at 100,000 tons per year for new sources and 75,000 tons per year for modified sources. The Federal EPA also confirmed that it will re-evaluate these thresholds during its five-year review in 2016. Our generating units are large sources of CO 2 emissions and we will continue to evaluate the permitting obligations in light of these thresholds.

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 proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management. Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and initiate closure within five years of the issuance of a final rule. In October 2011, the Federal EPA issued a notice of data availability requesting comments on a number of technical reports and other data received during the comment period for the original proposal and requesting comments on potential modeling analyses to update its risk assessment. The Federal EPA has also announced its intention to complete a risk assessment of various beneficial uses of coal ash.

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

Clean Water Act Regulations

In April 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water. Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress. The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement. Compliance with this standard is required within eight years of the effective date of the final rule. The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment. The proposed entrainment standard for new units at existing facilities requires either intake flows commensurate with closed cycle cooling or achieving entrainment reductions equivalent to 90% or greater of the reductions that could be achieved with closed cycle cooling. Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority. We are evaluating the proposal and engaged in the collection of additional information regarding the feasibility of implementing this proposal at our facilities. In June 2012, the Federal EPA issued additional Notices of Data Availability and requested public comments. We submitted comments in July 2012. Issuance of a final rule is not expected until July 2013. We are preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.

Global Warming

National public policy makers and regulators in the 11 states we serve have conflicting views on 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.

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 Michigan, Ohio, Texas and Virginia. We are taking steps to comply with these requirements.

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 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 3.

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 reduce future net income and cash flows and impact financial condition.

For additional information on global warming, other environmental issues and the actions we are taking to address potential impacts, see Part I of the 2011 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters” and “Management’s Financial Discussion and Analysis.”

RESULTS OF OPERATIONS

SEGMENTS

Our primary business is the generation, transmission and distribution of electricity. 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. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

While our Utility Operations segment remains our primary business segment, the advancement of an area of our business prompted us to identify a new reportable segment. Starting in the fourth quarter of 2011, we established our new Transmission Operations segment as described below:

Utility Operations

	·	Generation of electricity for sale to U.S. retail and wholesale customers.
	·	Transmission and distribution of electricity through assets owned and operated by our ten utility operating companies.

Transmission Operations

Development, construction and operation of transmission facilities through investments in our wholly-owned transmission subsidiaries that were established in 2009 and our transmission joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.

AEP River Operations

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

Generation and Marketing

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

The table below presents our consolidated Net Income by segment for the three and six months ended June 30, 2012 and 2011. We reclassified prior year amounts to conform to the current year’s presentation.

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions)
Utility Operations	$	365		$	350		$	749		$	724
Transmission Operations		8			6			17			10
AEP River Operations		3			(1	)		12			6
Generation and Marketing		(5	)		11			(6	)		12
All Other (a)		(8	)		(13	)		(19	)		(44	)
Net Income	$	363		$	353		$	753		$	708

(a)	While not considered a reportable segment, All Other includes:
	·	Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
	·	Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005. These contracts were financial derivatives which settled and expired in the fourth quarter of 2011.
	·	Revenue sharing related to the Plaquemine Cogeneration Facility which ended in the fourth quarter of 2011.

AEP CONSOLIDATED

Second Quarter of 2012 Compared to Second Quarter of 2011

Net Income increased from $353 million in 2011 to $363 million in 2012 primarily due to:

·	A decrease in other operation and maintenance expenses as a result of reduced spending.
·	A second quarter 2012 partial reversal of a 2011 deferred fuel adjustment based on an April 2012 PUCO order related to the 2009 FAC audit.

These increases were partially offset by:

·	The loss of retail customers in Ohio to various CRES providers.
·	A net decrease in regulated revenue primarily due to the elimination of POLR charges in Ohio effective June 2011, resulting from an October 2011 PUCO remand order.
·	The increase in depreciation expenses as a result of shortened depreciable lives for certain OPCo generating plants and increases in depreciation rates for APCo and I&M in February 2012 (Virginia) and April 2012 (Michigan), respectively.

Average basic shares outstanding increased from 482 million in 2011 to 485 million in 2012. Actual shares outstanding were 485 million as of June 30, 2012.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Net Income increased from $708 million in 2011 to $753 million in 2012 primarily due to:

·	A decrease in other operation and maintenance expenses as a result of reduced spending.
·	The first quarter 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO’s February 2012 rejection of OPCo’s modified stipulation.
·	A first quarter 2011 settlement of litigation with BOA and Enron.
·	A second quarter 2012 partial reversal of a 2011 deferred fuel adjustment based on an April 2012 PUCO order related to the 2009 FAC audit.

These increases were partially offset by:

·	The loss of retail customers in Ohio to various CRES providers.
·	A decrease in weather-related usage, primarily due to a decrease in heating degree days in the first quarter of 2012.
·	A net decrease in regulated revenue primarily due to the elimination of POLR charges in Ohio effective June 2011, resulting from an October 2011 PUCO remand order.
·	The increase in depreciation expenses as a result of shortened depreciable lives for certain OPCo generating plants and increases in depreciation rates for APCo and I&M in February 2012 (Virginia) and April 2012 (Michigan), respectively.

Average basic shares outstanding increased from 482 million in 2011 to 484 million in 2012. Actual shares outstanding were 485 million as of June 30, 2012.

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 electricity. We reclassified prior year amounts to conform to the current year’s presentation.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2012			2011			2012			2011
	(in millions)
Revenues	$	3,258		$	3,388		$	6,643		$	6,912
Fuel and Purchased Electricity		1,096			1,230			2,365			2,527
Gross Margin		2,162			2,158			4,278			4,385
Other Operation and Maintenance		770			852			1,525			1,702
Depreciation and Amortization		448			398			860			791
Taxes Other Than Income Taxes		202			199			413			408
Operating Income		742			709			1,480			1,484
Interest and Investment Income		2			2			3			4
Carrying Costs Income		11			17			31			32
Allowance for Equity Funds Used During Construction		20			22			40			42
Interest Expense		(224	)		(227	)		(441	)		(459	)
Income Before Income Tax Expense and Equity
Earnings		551			523			1,113			1,103
Income Tax Expense		186			173			365			380
Equity Earnings of Unconsolidated Subsidiaries		-			-			1			1
Net Income	$	365		$	350		$	749		$	724

Summary of KWH Energy Sales for Utility Operations

	Three Months Ended			Six Months Ended
	June 30,			June 30,
	2012	2011		2012	2011
	(in millions of KWHs)
Retail:
Residential	13,155		13,503	27,954	30,452
Commercial	13,087		12,913	24,353	24,559
Industrial	15,422		15,153	30,069	29,482
Miscellaneous	779		777	1,500	1,500
Total Retail (a)	42,443		42,346	83,876	85,993

Wholesale	8,620		10,216	17,533	19,367

Total KWHs	51,063		52,562	101,409	105,360

(a) Represents energy delivered to distribution customers.

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

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2012		2011		2012		2011
		(in degree days)
Eastern Region
Actual - Heating (a)			118		134		1,379		1,989
Normal - Heating (b)			165		168		1,916		1,907

Actual - Cooling (c)			401		368		429		371
Normal - Cooling (b)			300		295		303		299

Western Region
Actual - Heating (a)			1		10		348		702
Normal - Heating (b)			20		21		601		600

Actual - Cooling (d)			961		1,035		1,094		1,144
Normal - Cooling (b)			774		762		834		820

(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.

Second Quarter of 2012 Compared to Second Quarter of 2011

Reconciliation of Second Quarter of 2011 to Second Quarter of 2012
Net Income from Utility Operations
(in millions)

Second Quarter of 2011	$	350

Changes in Gross Margin:
Retail Margins		(15	)
Off-system Sales		5
Transmission Revenues		22
Other Revenues		(8	)
Total Change in Gross Margin		4

Changes in Expenses and Other:
Other Operation and Maintenance		82
Depreciation and Amortization		(50	)
Taxes Other Than Income Taxes		(3	)
Carrying Costs Income		(6	)
Allowance for Equity Funds Used During Construction		(2	)
Interest Expense		3
Total Change in Expenses and Other		24

Income Tax Expense		(13	)

Second Quarter of 2012	$	365

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

·	Retail Margins decreased $15 million primarily due to the following:
	·	A $70 million decrease attributable to Ohio customers switching to alternative CRES providers. This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
	·	A $13 million net decrease in regulated revenue primarily due to the elimination of POLR charges in Ohio effective June 2011, resulting from an October 2011 PUCO remand order.
	These decreases were partially offset by:
	·	A $35 million increase due to OPCo’s partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
	·	A $21 million increase in revenues related to TCC’s issuance of securitization bonds in March 2012. This increase is partially offset by an increase in Depreciation and Amortization expense.
	·	A $9 million rate increase for APCo.
·	Margins from Off-system Sales increased $5 million primarily due to higher PJM capacity revenues, partially offset by lower physical sales volumes and lower trading and marketing margins.
·	Transmission Revenues increased $22 million primarily due to net increases in ERCOT and increased transmission revenues for Ohio customers who have switched to alternative CRES providers. The increase in transmission revenues related to CRES providers partially offsets lost revenues included in Retail Margins above.
·	Other Revenues decreased $8 million primarily due to a decrease in gains on other miscellaneous sales.

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

·	Other Operation and Maintenance expenses decreased $82 million primarily due to the following:
	·	A $46 million decrease in plant outage and other plant operating and maintenance expenses.
	·	A $30 million decrease in employee-related expenses and other reduced spending.
	·	A $19 million decrease in storm expenses.
	These decreases were partially offset by:
	·	A $13 million increase due to expenses related to the 2012 sustainable cost reductions.
·	Depreciation and Amortization expenses increased $50 million primarily due to the following:
	·	An $18 million increase due to TCC’s issuance of securitization bonds in March 2012. The increase in TCC’s securitization related amortizations are offset within Gross Margin.
	·	An $18 million increase due to shortened depreciable lives for certain OPCo generating plants effective December 2011.
	·	A $14 million combined increase in depreciation for APCo and I&M primarily due to increases in depreciation rates effective February 2012 (Virginia) and April 2012 (Michigan), respectively.
	·	A $5 million increase in amortization primarily as a result of the Virginia E&R surcharge and the Virginia Environmental Rate Adjustment Clause, both effective February 2012.
	·	Overall higher depreciable property balances.
	These increases were partially offset by:
	·	A $10 million decrease due to an amortization adjustment approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.
	·	A $5 million decrease in OPCo’s depreciation due to the third quarter 2011 plant impairment of Sporn Unit 5.
·	Carrying Costs Income decreased $6 million primarily due to OPCo’s reduction in debt carrying charges associated with the 2008 coal contract settlement for the period January 2009 through March 2012 as ordered by the PUCO in April 2012 related to the 2009 FAC audit.
·	Income Tax Expense increased $13 million primarily due to an increase in pre-tax book income.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Reconciliation of Six Months Ended June 30, 2011 to Six Months Ended June 30, 2012
Net Income from Utility Operations
(in millions)

Six Months Ended June 30, 2011	$	724

Changes in Gross Margin:
Retail Margins		(113)
Off-system Sales		2
Transmission Revenues		34
Other Revenues		(30)
Total Change in Gross Margin		(107)

Changes in Expenses and Other:
Other Operation and Maintenance		177
Depreciation and Amortization		(69)
Taxes Other Than Income Taxes		(5)
Interest and Investment Income		(1)
Carrying Costs Income		(1)
Allowance for Equity Funds Used During Construction		(2)
Interest Expense		18
Total Change in Expenses and Other		117

Income Tax Expense		15

Six Months Ended June 30, 2012	$	749

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

·	Retail Margins decreased $113 million primarily due to the following:
	·	A $124 million decrease attributable to Ohio customers switching to alternative CRES providers. This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
	·	An $89 million decrease in weather-related usage in our eastern and western regions primarily due to decreases of 31% and 50%, respectively, in heating degree days.
	·	A $17 million net decrease in regulated revenue primarily due to the elimination of POLR charges in Ohio effective June 2011, resulting from an October 2011 PUCO remand order.
	These decreases were partially offset by:
	·	Successful rate proceedings in our service territories which include:
		·	A $31 million rate increase for APCo.
		·	A $14 million rate increase for I&M.
		·	A $9 million rate increase for PSO.
			For the rate increases described above, $46 million of these increases relate to riders/trackers which have corresponding increases in other expense items below.
	·	A $35 million increase due to OPCo’s second quarter 2012 partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
	·	A $24 million increase in revenues related to TCC’s issuance of securitization bonds in March 2012. This increase is partially offset by an increase in Depreciation and Amortization expense.
·	Margins from Off-system Sales increased $2 million primarily due to higher PJM capacity revenues, partially offset by lower physical sales volumes and lower trading and marketing margins.
·	Transmission Revenues increased $34 million primarily due to net increases in ERCOT and increased transmission revenues for Ohio customers who have switched to alternative CRES providers. The increase in transmission revenues related to CRES providers offsets lost revenues included in Retail Margins above.
·	Other Revenues decreased $30 million primarily due to an unfavorable regulatory order in Ohio and a decrease in gains on other miscellaneous sales.

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

·	Other Operation and Maintenance expenses decreased $177 million primarily due to the following:
	·	A $75 million decrease in plant outage and other plant operating and maintenance expenses.
	·	A $75 million decrease in employee-related expenses and other reduced spending.
	·	A $41 million decrease due to the first quarter 2011 write-off of a portion of the West Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC.
	·	A $35 million decrease due to the first quarter 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO’s February 2012 rejection of OPCo’s modified stipulation.
	·	A $16 million decrease in other storm expenses.
	These decreases were partially offset by:
	·	A $33 million increase due to the first quarter 2011 deferral of 2009 storm costs and the 2010 cost reduction initiatives as allowed by the WVPSC in 2011.
	·	A $13 million increase due to expenses related to the 2012 sustainable cost reductions.
	·	An $8 million increase in energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
·	Depreciation and Amortization expenses increased $69 million primarily due to the following:
	·	A $32 million increase due to shortened depreciable lives for certain OPCo generating plants effective December 2011.
	·	A $23 million increase due to TCC’s issuance of securitization bonds in March 2012. The increase in TCC’s securitization related amortizations are offset within Gross Margin.
	·	A $21 million combined increase in depreciation for APCo and I&M primarily due to increases in depreciation rates effective February 2012 (Virginia) and April 2012 (Michigan), respectively.
	·	A $9 million increase in amortization primarily as a result of the Virginia E&R surcharge and the Virginia Environmental Rate Adjustment Clause, both effective February 2012.
	·	Overall higher depreciable property balances.
	These increases were partially offset by:
	·	A $19 million decrease due to an amortization adjustment approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.
	·	A $10 million decrease in OPCo’s depreciation due to the third quarter 2011 plant impairment of Sporn Unit 5.
·	Carrying Costs Income decreased $1 million primarily due to the following:
	·	A $6 million decrease due to OPCo’s collection of carrying costs in the first quarter 2012 on phase-in FAC deferrals and line extension carrying charges recorded in 2011.
	·	A $5 million decrease for OPCo due to a reduction in debt carrying charges associated with the 2008 coal contract settlement for the period January 2009 through March 2012 as ordered by the PUCO in April 2012 related to the 2009 FAC audit.
	These decreases were offset by:
	·	An $8 million increase due to the recording of debt carrying costs prior to TCC’s issuance of securitization bonds in March 2012.
	·	A $3 million increase from carrying charges on APCo’s Dresden Plant resulting from the Virginia Generation Rate Adjustment Clause and the West Virginia Expanded Net Energy Charge.
·	Interest Expense decreased $18 million primarily due to lower outstanding long-term debt balances and lower long-term interest rates.
·	Income Tax Expense decreased $15 million primarily due to audit settlements for previous years and federal income tax adjustments recorded in 2011 related to prior year tax returns, partially offset by an increase in pre-tax book income.

TRANSMISSION OPERATIONS

Second Quarter of 2012 Compared to Second Quarter of 2011

Net Income from our Transmission Operations segment increased from $6 million in 2011 to $8 million in 2012 primarily due to an increase in investments by ETT and our wholly-owned transmission subsidiaries.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Net Income from our Transmission Operations segment increased from $10 million in 2011 to $17 million in 2012 primarily due to an increase in investments by ETT and our wholly-owned transmission subsidiaries.

AEP RIVER OPERATIONS

Second Quarter of 2012 Compared to Second Quarter of 2011

Net Income from our AEP River Operations segment increased from a loss of $1 million in 2011 to a gain of $3 million in 2012 primarily due to flood-related expenses incurred in the second quarter of 2011 and reduced spending in 2012.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Net Income from our AEP River Operations segment increased from $6 million in 2011 to $12 million in 2012 primarily due to flood-related expenses incurred in the second quarter of 2011 and reduced spending in 2012.

GENERATION AND MARKETING

Second Quarter of 2012 Compared to Second Quarter of 2011

Net Income from our Generation and Marketing segment decreased from a gain of $11 million in 2011 to a loss of $5 million in 2012 primarily due to the expiration of wind-related production tax credits in 2011, lower trading margins and reduced inception gains from ERCOT marketing activities.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Net Income from our Generation and Marketing segment decreased from a gain of $12 million in 2011 to a loss of $6 million in 2012 primarily due to the expiration of wind-related production tax credits in 2011 and lower trading margins.

ALL OTHER

Second Quarter of 2012 Compared to Second Quarter of 2011

Net Income from All Other increased from a loss of $13 million in 2011 to a loss of $8 million in 2012 primarily due to a decrease in various parent related expenses.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Net Income from All Other increased from a loss of $44 million in 2011 to a loss of $19 million in 2012 due to a loss incurred in the first quarter of 2011 related to the settlement of litigation with BOA and Enron.

AEP SYSTEM INCOME TAXES

Second Quarter of 2012 Compared to Second Quarter of 2011

Income Tax Expense increased $16 million primarily due to an increase in pretax book income and the expiration of wind production tax credits in 2011.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Income Tax Expense decreased $73 million primarily due to the unrealized capital loss valuation allowance related to a deferred tax asset associated with the settlement of litigation with BOA and Enron, audit settlements for previous years and a decrease in pretax book income.

FINANCIAL CONDITION

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

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

	June 30, 2012				December 31, 2011
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	17,302	51.6	%	$	16,516	50.3	%
Short-term Debt		1,208	3.6			1,650	5.0
Total Debt		18,510	55.2			18,166	55.3
AEP Common Equity		15,007	44.8			14,664	44.7
Noncontrolling Interests		1	-			1	-

Total Debt and Equity Capitalization	$	33,518	100.0	%	$	32,831	100.0	%

Our ratio of debt-to-total capital decreased from 55.3% at December 31, 2011 to 55.2% at June 30, 2012. Long-term debt outstanding increased due to the March 2012 issuance of $800 million of securitization bonds.

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability. We believe we have adequate liquidity under our existing credit facilities. At June 30, 2012, we had $3.25 billion in aggregate credit facility commitments to support our operations. Additional liquidity is available from cash from operations and a receivables securitization agreement. We are committed to maintaining adequate liquidity. We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged. Sources of long-term funding include issuance of long-term debt, sale-and-leaseback or leasing agreements or common stock.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments. At June 30, 2012, our available liquidity was approximately $2.8 billion as illustrated in the table below:

		Amount		Maturity
		(in millions)
Commercial Paper Backup:
	Revolving Credit Facility	$	1,500	June 2015
	Revolving Credit Facility		1,750	July 2016
Total			3,250
Cash and Cash Equivalents			297
Total Liquidity Sources			3,547
Less:	AEP Commercial Paper Outstanding		550
	Letters of Credit Issued		167

Net Available Liquidity		$	2,830

We have credit facilities totaling $3.25 billion to support our commercial paper program. The credit facilities allow us to issue letters of credit in an amount up to $1.35 billion.

We use our commercial paper program to meet the short-term borrowing needs of our subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. The maximum amount of commercial paper outstanding during the first six months of 2012 was $1.2 billion. The weighted-average interest rate for our commercial paper during 2012 was 0.46%.

Securitized Accounts Receivables

In June 2012, we renewed our receivables securitization agreement. The agreement provides a commitment of $700 million from bank conduits to purchase receivables. A commitment of $385 million expires in June 2013 and the remaining commitment of $315 million expires in June 2015.

Securitization of Regulatory Assets

In March 2012, West Virginia passed securitization legislation, which allows the WVPSC to establish a regulatory framework to securitize certain deferred Expanded Net Energy Charge (ENEC) balances and other ENEC related assets. APCo and WPCo anticipate filing, in the third quarter of 2012, a request for a financing order with the WVPSC pursuant to the securitization legislation to securitize approximately $400 million. See “APCo’s and WPCo’s Expanded Net Energy Charge (ENEC) Filing” section of Note 2.

OPCo plans to file, in the third quarter of 2012, an application with the PUCO requesting securitization of the Distribution Asset Recovery Rider (DARR) balance. As of June 30, 2012, OPCo’s DARR balance was $309 million, including $145 million of unrecognized equity carrying costs. Currently, the DARR is being recovered through 2018.

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. Debt as defined in the revolving credit agreements excludes junior subordinated debentures, securitization bonds and debt of AEP Credit. At June 30, 2012, this contractually-defined percentage was 50%. Nonperformance under these covenants could result in an event of default under these credit agreements. At June 30, 2012, 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 June 30, 2012, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.47 per share in July 2012. Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Our income derives from our common stock equity in the earnings of our utility subsidiaries. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.

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 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.

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.

	Six Months Ended
	June 30,
	2012				2011
	(in millions)
Cash and Cash Equivalents at Beginning of Period		$	221			$	294
Net Cash Flows from Operating Activities			1,713				1,732
Net Cash Flows Used for Investing Activities			(1,530	)			(1,280	)
Net Cash Flows Used for Financing Activities			(107	)			(329	)
Net Increase in Cash and Cash Equivalents			76				123
Cash and Cash Equivalents at End of Period		$	297			$	417

Cash from operations and short-term borrowings provides working capital and allows us to meet other short-term cash needs.

Operating Activities

	Six Months Ended
	June 30,
	2012			2011
	(in millions)
Net Income		$	753		$	708
Depreciation and Amortization			883			813
Other			77			211
Net Cash Flows from Operating Activities		$	1,713		$	1,732

Net Cash Flows from Operating Activities were $1.7 billion in 2012 consisting primarily of Net Income of $753 million and $883 million 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. A significant change in other items includes the favorable impact of a decrease in accounts receivable and the unfavorable impact of an increase in fuel inventory due to the mild winter weather. Cash was also used to pay real and personal property taxes and to reduce accounts payable. Deferred Income Taxes increased primarily due to provisions in the Small Business Jobs Act and the Tax Relief, Unemployment Insurance Reauthorization and Jobs Creation Act and an increase in tax versus book temporary differences from operations.

Net Cash Flows from Operating Activities were $1.7 billion in 2011 consisting primarily of Net Income of $708 million and $813 million 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. Significant changes in other items include the favorable impact of a decrease in fuel inventory and the unfavorable impact of reducing accounts payable and adjusting accrued taxes for a net operating loss and tax credit carryforward. Deferred Income Taxes increased primarily due to provisions in the Small Business Jobs Act and the Tax Relief, Unemployment Insurance Reauthorization and Jobs Creation Act, the settlement with BOA and Enron and an increase in tax versus book temporary differences from operations. In February 2011, we paid $425 million to BOA of which $211 million was used to settle litigation with BOA and Enron. The remaining $214 million was used to acquire cushion gas as discussed in Investing Activities below.

Investing Activities

	Six Months Ended
	June 30,
	2012				2011
	(in millions)
Construction Expenditures		$	(1,371	)		$	(1,113	)
Acquisitions of Nuclear Fuel			(11	)			(93	)
Acquisitions of Assets/Businesses			(88	)			(10	)
Acquisition of Cushion Gas from BOA			-				(214	)
Proceeds from Sales of Assets			8				94
Other			(68	)			56
Net Cash Flows Used for Investing Activities		$	(1,530	)		$	(1,280	)

Net Cash Flows Used for Investing Activities were $1.5 billion in 2012 primarily due to Construction Expenditures for new generation, environmental, distribution and transmission investments. Acquisitions of Assets/Businesses include our March 2012 purchase of BlueStar for $70 million.

Net Cash Flows Used for Investing Activities were $1.3 billion in 2011 primarily due to Construction Expenditures for new generation, environmental, distribution and transmission investments. We paid $214 million to BOA for cushion gas as part of a litigation settlement.

Financing Activities

	Six Months Ended
	June 30,
	2012				2011
	(in millions)
Issuance of Common Stock, Net		$	50			$	49
Issuance of Debt, Net			332				104
Dividends Paid on Common Stock			(458	)			(446	)
Other			(31	)			(36	)
Net Cash Flows Used for Financing Activities		$	(107	)		$	(329	)

Net Cash Flows Used for Financing Activities in 2012 were $107 million. Our net debt issuances were $332 million. The net issuances included issuances of $800 million of securitization bonds, $275 million of senior unsecured notes and $197 million of notes payable and other debt offset by retirements of $234 million of senior unsecured and other debt notes, $155 million of pollution control bonds, $98 million of securitization bonds and a decrease in short-term borrowing of $442 million. We paid common stock dividends of $458 million. See Note 10 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows Used for Financing Activities in 2011 were $329 million. Our net debt issuances were $104 million. The net issuances included issuances of $600 million of senior unsecured notes, $481 million of pollution control bonds and an increase in short-term borrowing of $293 million offset by retirements of $578 million of senior unsecured and debt notes, $591 million of pollution control bonds and $92 million of securitization bonds. We paid common stock dividends of $446 million.

In July 2012, I&M retired $9 million of Notes Payable related to DCC Fuel.

In July 2012, TCC retired $73 million of Securitization Bonds.

OFF-BALANCE SHEET ARRANGEMENTS

In prior periods, under a limited set of circumstances, we entered into off-balance sheet arrangements for various reasons including 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 that we enter in the normal course of business. The following identifies significant off-balance sheet arrangements:

	June 30,			December 31,
	2012			2011
	(in millions)
Rockport Plant Unit 2 Future Minimum Lease Payments		$	1,552		$	1,626
Railcars Maximum Potential Loss From Lease Agreement			25			25

For complete information on each of these off-balance sheet arrangements see the “Off-balance Sheet Arrangements” section of “Management’s Financial Discussion and Analysis” in the 2011 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

A summary of our contractual obligations is included in our 2011 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Financial Discussion and Analysis” in the 2011 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.

ACCOUNTING PRONOUNCEMENTS

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, we cannot determine the impact on the reporting of our operations and financial position that may result from any such future changes. The FASB is currently working on several projects including revenue recognition, financial instruments, leases, insurance, hedge accounting and consolidation policy. 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 future net income and financial position.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

Our Utility Operations segment is exposed to certain market risks as a major power producer and through its transactions 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 as we occasionally procure various services and materials used in our energy business from foreign suppliers. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

Our Generation and Marketing segment conducts marketing, risk management and retail activities in ERCOT, PJM and MISO. This segment is exposed to certain market risks as a marketer of wholesale and retail electricity. These risks include commodity price risk, interest rate risk and credit risk. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

We employ risk management contracts including physical forward purchase and sale contracts and financial forward purchase and sale contracts. We engage in risk management of power, coal and natural gas and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with our energy business. As a result, we are subject to price risk. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors. Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The CORC consists of our Chief Operating Officer, 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.

The following table summarizes the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2011:

MTM Risk Management Contract Net Assets (Liabilities)
Six Months Ended June 30, 2012

			Generation
	Utility		and
	Operations		Marketing			Total
	(in millions)
Total MTM Risk Management Contract Net Assets
at December 31, 2011	$	59	$	132		$	191
(Gain) Loss from Contracts Realized/Settled During the Period and
Entered in a Prior Period		14		(14	)		-
Fair Value of New Contracts at Inception When Entered During the
Period (a)		5		9			14
Changes in Fair Value Due to Market Fluctuations During the
Period (b)		5		(1	)		4
Changes in Fair Value Allocated to Regulated Jurisdictions (c)		4		-			4
Total MTM Risk Management Contract Net Assets
at June 30, 2012	$	87	$	126			213

Commodity Cash Flow Hedge Contracts							(22	)
Interest Rate and Foreign Currency Cash Flow Hedge Contracts							(35	)
Fair Value Hedge Contracts							2
Collateral Deposits							76
Total MTM Derivative Contract Net Assets at June 30, 2012						$	234

(a)	Reflects fair value on primarily long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged.
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)	Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets.

See Note 7 – Derivatives and Hedging and Note 8 – 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.

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 June 30, 2012, our credit exposure net of collateral to sub investment grade counterparties was approximately 6%, 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 June 30, 2012, 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		$	739	$	2	$	737		2	$	313
Split Rating			-		-		-		-		-
Noninvestment Grade			12		2		10		1		10
No External Ratings:
	Internal Investment Grade		168		-		168		1		42
	Internal Noninvestment Grade		58		10		48		1		35
Total as of June 30, 2012		$	977	$	14	$	963		5	$	400

Total as of December 31, 2011		$	960	$	19	$	941		5	$	348

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 June 30, 2012, 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

Six Months Ended								Twelve Months Ended
June 30, 2012								December 31, 2011
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	-	$	1	$	-	$	-	$	-	$	2	$	-	$	-

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.

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 June 30, 2012 and December 31, 2011, the estimated EaR on our debt portfolio for the following twelve months was $37 million and $29 million, respectively.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2012 and 2011
(in millions, except per-share and share amounts)
(Unaudited)

	Three Months Ended						Six Months Ended
	2012			2011			2012			2011
REVENUES
Utility Operations	$	3,235		$	3,360		$	6,598		$	6,857
Other Revenues		316			249			578			482
TOTAL REVENUES		3,551			3,609			7,176			7,339
EXPENSES
Fuel and Other Consumables Used for Electric Generation		904			980			1,957			2,036
Purchased Electricity for Resale		268			287			528			562
Other Operation		719			697			1,375			1,383
Maintenance		252			316			514			581
Depreciation and Amortization		460			410			883			813
Taxes Other Than Income Taxes		207			202			424			415
TOTAL EXPENSES		2,810			2,892			5,681			5,790

OPERATING INCOME		741			717			1,495			1,549

Other Income (Expense):
Interest and Investment Income		2			3			4			5
Carrying Costs Income		11			17			31			32
Allowance for Equity Funds Used During Construction		24			23			47			43
Interest Expense		(235	)		(239	)		(464	)		(481	)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		543			521			1,113			1,148

Income Tax Expense		190			174			379			452
Equity Earnings of Unconsolidated Subsidiaries		10			6			19			12

NET INCOME		363			353			753			708

Net Income Attributable to Noncontrolling Interests		1			1			2			2

NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS		362			352			751			706

Preferred Stock Dividend Requirements of Subsidiaries		-			-			-			1

EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	362		$	352		$	751		$	705

WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING		484,500,029			481,928,494			484,164,065			481,538,549

TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
SHAREHOLDERS	$	0.75		$	0.73		$	1.55		$	1.46

WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING		484,860,690			482,203,255			484,554,779			481,786,698

TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
SHAREHOLDERS	$	0.75		$	0.73		$	1.55		$	1.46

CASH DIVIDENDS DECLARED PER SHARE	$	0.47		$	0.46		$	0.94		$	0.92

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 36.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2012 and 2011
(in millions)
(Unaudited)

	Three Months Ended					Six Months Ended
	2012			2011		2012			2011
Net Income	$	363		$	353	$	753		$	708

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $5 and $2 for the Three Months Ended
June 30, 2012 and 2011, Respectively, and $11 and $3 for the Six
Months Ended June 30, 2012 and 2011, Respectively		(10	)		5		(21	)		6
Securities Available for Sale, Net of Tax of $- and $- for the Three Months
Ended June 30, 2012 and 2011, Respectively, and $1 and $- for the
Six Months Ended June 30, 2012 and 2011, Respectively		(1	)		-		1			1
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $4
and $3 for the Three Months Ended June 30, 2012 and 2011,
Respectively, and $8 and $6 for the Six Months Ended June 30,
2012 and 2011, Respectively		8			6		15			12

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(3	)		11		(5	)		19

TOTAL COMPREHENSIVE INCOME		360			364		748			727

Total Comprehensive Income Attributable to Noncontrolling Interests		1			1		2			2

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
SHAREHOLDERS		359			363		746			725

Preferred Stock Dividend Requirements of Subsidiaries		-			-		-			1

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO AEP
COMMON SHAREHOLDERS	$	359		$	363	$	746		$	724

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 36.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Six Months Ended June 30, 2012 and 2011
(in millions)
(Unaudited)

		AEP Common Shareholders
		Common Stock								Accumulated
										Other
						Paid-in		Retained		Comprehensive		Noncontrolling
		Shares		Amount		Capital		Earnings		Income (Loss)		Interests		Total
TOTAL EQUITY – DECEMBER 31, 2010			501	$	3,257	$	5,904	$	4,842	$	(381)	$	-	$	13,622

Issuance of Common Stock			1		9		40								49
Common Stock Dividends									(444)				(2)		(446)
Preferred Stock Dividend Requirements of
	Subsidiaries								(1)						(1)
Other Changes in Equity							(12)								(12)
Subtotal – Equity															13,212

Net Income									706				2		708
Other Comprehensive Income											19				19
TOTAL EQUITY – JUNE 30, 2011			502	$	3,266	$	5,932	$	5,103	$	(362)	$	-	$	13,939

TOTAL EQUITY – DECEMBER 31, 2011			504	$	3,274	$	5,970	$	5,890	$	(470)	$	1	$	14,665

Issuance of Common Stock			1		10		40								50
Common Stock Dividends									(456)				(2)		(458)
Other Changes in Equity							3								3
Subtotal – Equity															14,260

Net Income									751				2		753
Other Comprehensive Loss											(5)				(5)
TOTAL EQUITY – JUNE 30, 2012			505	$	3,284	$	6,013	$	6,185	$	(475)	$	1	$	15,008

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 36.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2012 and December 31, 2011
(in millions)
(Unaudited)

			2012		2011
CURRENT ASSETS
Cash and Cash Equivalents			$	297	$	221
Other Temporary Investments
	(June 30, 2012 and December 31, 2011 Amounts Include $279 and $281, Respectively, Related to Transition Funding and EIS)			297		294
Accounts Receivable:
	Customers			674		690
	Accrued Unbilled Revenues			129		106
	Pledged Accounts Receivable – AEP Credit			910		920
	Miscellaneous			84		150
	Allowance for Uncollectible Accounts			(35)		(32)
		Total Accounts Receivable		1,762		1,834
Fuel				837		657
Materials and Supplies				657		635
Risk Management Assets				219		193
Accrued Tax Benefits				46		51
Regulatory Asset for Under-Recovered Fuel Costs				126		65
Margin Deposits				63		67
Prepayments and Other Current Assets				179		165
TOTAL CURRENT ASSETS				4,483		4,182

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			25,382		24,938
	Transmission			9,372		9,048
	Distribution			15,148		14,783
Other Property, Plant and Equipment (Including Nuclear Fuel and Coal Mining)				3,862		3,780
Construction Work in Progress				3,020		3,121
Total Property, Plant and Equipment				56,784		55,670
Accumulated Depreciation and Amortization				18,956		18,699
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				37,828		36,971

OTHER NONCURRENT ASSETS
Regulatory Assets				5,277		6,026
Securitized Transition Assets				2,241		1,627
Spent Nuclear Fuel and Decommissioning Trusts				1,658		1,592
Goodwill				90		76
Long-term Risk Management Assets				439		403
Deferred Charges and Other Noncurrent Assets				1,405		1,346
TOTAL OTHER NONCURRENT ASSETS				11,110		11,070

TOTAL ASSETS			$	53,421	$	52,223

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 36.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2012 and December 31, 2011
(dollars in millions)
(Unaudited)

					2012		2011
CURRENT LIABILITIES
Accounts Payable					$	906	$	1,095
Short-term Debt:
	Securitized Debt for Receivables - AEP Credit					658		666
	Other Short-term Debt					550		984
		Total Short-term Debt				1,208		1,650
Long-term Debt Due Within One Year
	(June 30, 2012 and December 31, 2011 Amounts Include $368 and $293, Respectively, Related to Transition Funding, DCC Fuel and Sabine)					1,983		1,433
Risk Management Liabilities						165		150
Customer Deposits						293		289
Accrued Taxes						617		717
Accrued Interest						281		279
Regulatory Liability for Over-Recovered Fuel Costs						84		8
Other Current Liabilities						870		990
TOTAL CURRENT LIABILITIES						6,407		6,611

NONCURRENT LIABILITIES
Long-term Debt
	(June 30, 2012 and December 31, 2011 Amounts Include $2,400 and $1,674, Respectively, Related to Transition Funding, DCC Fuel and Sabine)					15,319		15,083
Long-term Risk Management Liabilities						259		195
Deferred Income Taxes						8,627		8,227
Regulatory Liabilities and Deferred Investment Tax Credits						3,615		3,195
Asset Retirement Obligations						1,523		1,472
Employee Benefits and Pension Obligations						1,729		1,801
Deferred Credits and Other Noncurrent Liabilities						934		974
TOTAL NONCURRENT LIABILITIES						32,006		30,947

TOTAL LIABILITIES						38,413		37,558

Rate Matters (Note 2)
Commitments and Contingencies (Note 3)

EQUITY
Common Stock – Par Value – $6.50 Per Share:
			2012	2011
	Shares Authorized		600,000,000	600,000,000
	Shares Issued		505,165,281	503,759,460
(20,336,592 Shares were Held in Treasury at June 30, 2012 and December 31, 2011)						3,284		3,274
Paid-in Capital						6,013		5,970
Retained Earnings						6,185		5,890
Accumulated Other Comprehensive Income (Loss)						(475)		(470)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY						15,007		14,664

Noncontrolling Interests						1		1

TOTAL EQUITY						15,008		14,665

TOTAL LIABILITIES AND EQUITY					$	53,421	$	52,223

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 36.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2012 and 2011
(in millions)
(Unaudited)

			2012		2011
OPERATING ACTIVITIES
Net Income			$	753	$	708
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			883		813
	Deferred Income Taxes			417		525
	Gain on Settlement with BOA and Enron			-		(51)
	Settlement of Litigation with BOA and Enron			-		(211)
	Carrying Costs Income			(31)		(32)
	Allowance for Equity Funds Used During Construction			(47)		(43)
	Mark-to-Market of Risk Management Contracts			8		61
	Amortization of Nuclear Fuel			64		72
	Property Taxes			68		62
	Fuel Over/Under-Recovery, Net			91		(93)
	Change in Other Noncurrent Assets			(80)		(11)
	Change in Other Noncurrent Liabilities			31		83
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		93		53
		Fuel, Materials and Supplies		(199)		146
		Accounts Payable		(100)		(87)
		Accrued Taxes, Net		(92)		(198)
		Other Current Assets		(7)		(9)
		Other Current Liabilities		(139)		(56)
Net Cash Flows from Operating Activities				1,713		1,732

INVESTING ACTIVITIES
Construction Expenditures				(1,371)		(1,113)
Change in Other Temporary Investments, Net				(1)		11
Purchases of Investment Securities				(546)		(645)
Sales of Investment Securities				517		712
Acquisitions of Nuclear Fuel				(11)		(93)
Acquisitions of Assets/Businesses				(88)		(10)
Acquisition of Cushion Gas from BOA				-		(214)
Proceeds from Sales of Assets				8		94
Other Investing Activities				(38)		(22)
Net Cash Flows Used for Investing Activities				(1,530)		(1,280)

FINANCING ACTIVITIES
Issuance of Common Stock, Net				50		49
Issuance of Long-term Debt				1,261		1,074
Commercial Paper and Credit Facility Borrowings				21		357
Change in Short-term Debt, Net				(425)		566
Retirement of Long-term Debt				(487)		(1,263)
Commercial Paper and Credit Facility Repayments				(38)		(630)
Principal Payments for Capital Lease Obligations				(36)		(35)
Dividends Paid on Common Stock				(458)		(446)
Dividends Paid on Cumulative Preferred Stock				-		(1)
Other Financing Activities				5		-
Net Cash Flows Used for Financing Activities				(107)		(329)

Net Increase in Cash and Cash Equivalents				76		123
Cash and Cash Equivalents at Beginning of Period				221		294
Cash and Cash Equivalents at End of Period			$	297	$	417

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	444	$	442
Net Cash Paid (Received) for Income Taxes				(42)		15
Noncash Acquisitions Under Capital Leases				33		28
Construction Expenditures Included in Current Liabilities at June 30,				255		292
Noncash Assumption of Liabilities Related to Acquisitions				56		-

See Condensed Notes to Condensed Consolidated Financial Statements beginning on page 36.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX OF CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1.	Significant Accounting Matters
2.	Rate Matters
3.	Commitments, Guarantees and Contingencies
4.	Acquisition
5.	Benefit Plans
6.	Business Segments
7.	Derivatives and Hedging
8.	Fair Value Measurements
9.	Income Taxes
10.	Financing Activities
11.	Sustainable Cost Reductions

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. SIGNIFICANT ACCOUNTING MATTERS

General

The unaudited condensed consolidated financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our net income, financial position and cash flows for the interim periods. Net income for the three and six months ended June 30, 2012 is not necessarily indicative of results that may be expected for the year ending December 31, 2012. The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2011 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 28, 2012.

Variable Interest Entities

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether we are the primary beneficiary of a VIE, we consider factors such as equity at risk, the amount of the VIE’s variability we absorb, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. We believe that significant assumptions and judgments were applied consistently.

We are the primary beneficiary of Sabine, DCC Fuel, AEP Credit, Transition Funding and a protected cell of EIS. In addition, we have not provided material financial or other support to Sabine, DCC Fuel, Transition Funding, our protected cell of EIS and AEP Credit that was not previously contractually required. We hold a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series).

Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the three months ended June 30, 2012 and 2011 were $36 million and $30 million, respectively, and for the six months ended June 30, 2012 and 2011 were $91 million and $64 million, respectively. See the tables below for the classification of Sabine’s assets and liabilities on our condensed balance sheets.

Our subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. Our subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on our control and the structure of the protected cell and EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate its assets and liabilities. Our insurance premium payments to the protected cell for the three months ended June 30, 2012 and 2011 was $0 and $80 thousand, respectively, and for the six months ended June 30, 2012 and 2011 was $15 million and $30 million, respectively. See the tables below for the classification of the protected cell’s assets and liabilities on our condensed balance sheets. The amount reported as equity is the protected cell’s policy holders’ surplus.

I&M has nuclear fuel lease agreements with DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC and DCC Fuel V LLC (collectively DCC Fuel). DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended June 30, 2012 and 2011 were $42 million and $38 million, respectively, and for the six months ended June 30, 2012 and 2011 were $59 million and $43 million, respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on our control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the tables below for the classification of DCC Fuel’s assets and liabilities on our condensed balance sheets.

AEP Credit is a wholly-owned subsidiary of AEP. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings. Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing. Based on our control of AEP Credit, management 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 condensed balance sheets. See “Securitized Accounts Receivable – AEP Credit” section of Note 10.

Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant. Therefore, TCC is required to consolidate Transition Funding. The securitized bonds totaled $2.4 billion and $1.7 billion at June 30, 2012 and December 31, 2011, respectively, and are included in current and long-term debt on the condensed balance sheets. Transition Funding has securitized transition assets of $2.2 billion and $1.6 billion at June 30, 2012 and December 31, 2011, respectively, which are presented separately on the face of the condensed balance sheets. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to TCC or any other AEP entity. TCC acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on our condensed balance sheets.

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
June 30, 2012
(in millions)

													TCC
	SWEPCo			I&M			Protected Cell						Transition
	Sabine			DCC Fuel			of EIS			AEP Credit			Funding
ASSETS
Current Assets		$	67		$	147		$	125		$	897		$	235
Net Property, Plant and Equipment			170			241			-			-			-
Other Noncurrent Assets			57			143			5			1			2,293	(a)
Total Assets		$	294		$	531		$	130		$	898		$	2,528

LIABILITIES AND EQUITY
Current Liabilities		$	42		$	127		$	43		$	851		$	303
Noncurrent Liabilities			252			404			67			1			2,207
Equity			-			-			20			46			18
Total Liabilities and Equity		$	294		$	531		$	130		$	898		$	2,528

(a) Includes an intercompany item eliminated in consolidation of $92 million.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2011
(in millions)

													TCC
	SWEPCo			I&M			Protected Cell						Transition
	Sabine			DCC Fuel			of EIS			AEP Credit			Funding
ASSETS
Current Assets		$	48		$	118		$	121		$	910		$	220
Net Property, Plant and Equipment			154			188			-			-			-
Other Noncurrent Assets			42			118			6			1			1,580
Total Assets		$	244		$	424		$	127		$	911		$	1,800

LIABILITIES AND EQUITY
Current Liabilities		$	68		$	103		$	40		$	864		$	229
Noncurrent Liabilities			176			321			71			1			1,557
Equity			-			-			16			46			14
Total Liabilities and Equity		$	244		$	424		$	127		$	911		$	1,800

DHLC is a mining operator that sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the three months ended June 30, 2012 and 2011 were $20 million and $15 million, respectively and for the six months ended June 30, 2012 and 2011 were $34 million and $29 million, respectively. We are not required to consolidate DHLC as we are not the primary beneficiary, although we hold a significant variable interest in DHLC. Our equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on our condensed balance sheets.

Our investment in DHLC was:

	June 30, 2012						December 31, 2011
	As Reported on			Maximum			As Reported on			Maximum
	the Balance Sheet			Exposure			the Balance Sheet			Exposure
	(in millions)
Capital Contribution from SWEPCo		$	8		$	8		$	8		$	8
Retained Earnings			1			1			1			1
SWEPCo's Guarantee of Debt			-			57			-			52

Total Investment in DHLC		$	9		$	66		$	9		$	61

We and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH). In February 2011, PJM directed that work on the PATH project be suspended. PATH is a series limited liability company and was created to construct, through its operating companies, a high-voltage transmission line project in the PJM region. PATH consists of the “West Virginia Series (PATH-WV),” owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is 100% owned by a subsidiary of FirstEnergy. Provisions exist within the PATH-WV agreement that make it a VIE. The “Allegheny Series” is not considered a VIE. We are not required to consolidate PATH-WV as we are not the primary beneficiary, although we hold a significant variable interest in PATH-WV. Our equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on our condensed balance sheets. We and FirstEnergy share the returns and losses equally in PATH-WV. Our subsidiaries and FirstEnergy’s subsidiaries provide services to the PATH companies through service agreements. As of June 30, 2012, PATH-WV had no debt outstanding. However, if 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:

	June 30, 2012				December 31, 2011
	As Reported on		Maximum		As Reported on		Maximum
	the Balance Sheet		Exposure		the Balance Sheet		Exposure
			(in millions)
Capital Contribution from AEP	$	19	$	19	$	19	$	19
Retained Earnings		12		12		10		10

Total Investment in PATH-WV	$	31	$	31	$	29	$	29

Earnings Per Share (EPS)

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 tables present our basic and diluted EPS calculations included on our condensed statements of income:

	Three Months Ended June 30,
	2012					2011
	(in millions, except per share data)
			$/share					$/share
Earnings Attributable to AEP Common Shareholders	$	362				$	352

Weighted Average Number of Basic Shares Outstanding		484.5		$	0.75		481.9		$	0.73
Weighted Average Dilutive Effect of:
Stock Options		0.1			-		0.1			-
Restricted Stock Units		0.3			-		0.2			-
Weighted Average Number of Diluted Shares Outstanding		484.9		$	0.75		482.2		$	0.73

	Six Months Ended June 30,
	2012					2011
	(in millions, except per share data)
			$/share					$/share
Earnings Attributable to AEP Common Shareholders	$	751				$	705

Weighted Average Number of Basic Shares Outstanding		484.2		$	1.55		481.5		$	1.46
Weighted Average Dilutive Effect of:
Stock Options		0.1			-		0.1			-
Restricted Stock Units		0.3			-		0.2			-
Weighted Average Number of Diluted Shares Outstanding		484.6		$	1.55		481.8		$	1.46

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

Options to purchase 10,000 and 70,050 shares of common stock at June 30, 2012 and 2011, respectively, 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.

2. RATE MATTERS

As discussed in the 2011 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 2011 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2012 and updates the 2011 Annual Report.

Regulatory Assets Not Yet Being Recovered

	June 30,		December 31,
	2012		2011
	(in millions)
Noncurrent Regulatory Assets (excluding fuel)
Regulatory assets not yet being recovered pending future proceedings to determine the recovery method and timing:
Regulatory Assets Currently Earning a Return
Storm Related Costs	$	24	$	24
Economic Development Rider		13		13
Regulatory Assets Currently Not Earning a Return
Virginia Environmental Rate Adjustment Clause		22		18
Mountaineer Carbon Capture and Storage Product Validation Facility		14		14
Special Rate Mechanism for Century Aluminum		13		13
Litigation Settlement		11		11
Storm Related Costs		8		10
Virginia Deferred Wind Power Costs		4		38
Other Regulatory Assets Not Yet Being Recovered		26		14
Total Regulatory Assets Not Yet Being Recovered	$	135	$	155

OPCo Rate Matters

Ohio Electric Security Plan Filing

2009 – 2011 ESP

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. OPCo collected the 2009 annualized revenue increase over the last nine months of 2009. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. See the “January 2012 – May 2016 ESP as Rejected by the PUCO” section below. The PUCO’s March 2009 order was appealed to the Supreme Court of Ohio, which issued an opinion and remanded certain issues back to the PUCO.

In October 2011, the PUCO issued an order in the remand proceeding. As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011. In February 2012, the Ohio Consumers’ Counsel and the Industrial Energy Users-Ohio (IEU) filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO’s refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which if ordered could total up to $698 million, excluding carrying costs.

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off of certain pretax earnings in 2010 and a subsequent refund to customers during 2011. In May 2011, the IEU and the Ohio Energy Group (OEG) filed appeals with the Supreme Court of Ohio challenging the PUCO’s SEET decision. The OEG’s appeal seeks the inclusion of off-system sales (OSS) in the calculation of SEET which, if ordered, could require an additional refund of $22 million based on the PUCO approved SEET calculation. The IEU’s appeal also sought the inclusion of OSS as well as other items in the determination of SEET, but did not quantify the amount. Oral arguments were held in March 2012 and management is unable to predict the outcome of the appeals. If the Supreme Court of Ohio ultimately determines that additional amounts should be refunded, it could reduce future net income and cash flows and impact financial condition.

In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO’s 2009 order. Subsequent testimony and legal briefs from intervenors recommended a refund of up to $62 million of 2010 earnings, which included OSS in the SEET calculation. In December 2011, the PUCO staff filed testimony that recommended a $23 million refund of 2010 earnings. In the fourth quarter of 2011, OPCo provided a reserve based upon management’s estimate of the probable amount for a PUCO ordered SEET refund. OPCo is required to file its 2011 SEET filing with the PUCO in 2012 on a separate CSPCo and OPCo company basis. The PUCO approved OPCo’s request to file the 2011 SEET on July 31, 2012 or one month after the PUCO issues an order on the 2010 SEET, whichever is later. Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo.

Management is unable to predict the outcome of the unresolved 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.

January 2012 – May 2016 ESP as Rejected by the PUCO

In December 2011, the PUCO approved a modified stipulation which established a new ESP that included a standard service offer (SSO) pricing for generation. Various parties filed for rehearing with the PUCO requesting that the PUCO reconsider adoption of the modified stipulation. In February 2012, the PUCO issued an entry on rehearing which rejected the modified stipulation and ordered a return to the 2011 ESP rates until a new rate plan is approved.

As directed by the February 2012 order, OPCo filed revised tariffs with the PUCO to implement the provisions of the 2011 ESP. Included in the revised tariffs was the Phase-In Recovery Rider (PIRR) to recover deferred fuel costs as authorized under the 2009 – 2011 ESP order. See the “2009 – 2011 ESP” section above. In March 2012, the PUCO issued an order that directed OPCo to file new revised tariffs removing the PIRR and stated that its recovery would be addressed in a future proceeding. OPCo implemented the new revised tariffs in March 2012. In March 2012, OPCo resumed recording a weighted average cost of capital return on the PIRR deferral in accordance with the 2009 - 2011 ESP order. Also in March 2012, OPCo filed a request for rehearing of the March 2012 order relating to the PIRR, which the PUCO denied but provided that all of the substantive concerns and issues raised would be deferred into a separate PIRR docket. See the “Proposed June 2012 – May 2015 ESP” section below.

As a result of the PUCO’s rejection of the modified stipulation, in the first quarter of 2012, OPCo reversed a $35 million obligation to contribute to Partnership with Ohio and Ohio Growth Fund and an $8 million regulatory asset for 2011 storm damage, both originally recorded in the fourth quarter of 2011.

Proposed June 2012 – May 2015 ESP

In March 2012, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing. The SSO rates would be effective through May 2015. The ESP will transition OPCo to an auction-based SSO for capacity and energy by June 2015. OPCo also filed an application with the PUCO for approval of the corporate separation of its generation assets including the transfer of generation assets to a nonregulated AEP subsidiary at net book value. Contingent upon OPCo receiving final orders from the PUCO adopting the ESP as proposed and the corporate separation plan as filed, OPCo will conduct an energy-only auction for 5% of the SSO load with delivery beginning six months after the final orders and extending through December 2014. In addition, a competitive bidding process would determine the price of energy for OPCo’s SSO load from January 2015 through May 2015. The ESP proposed a two-tiered capacity pricing structure for CRES providers. The first tier is priced at the Reliability Pricing Model (RPM) rate in effect in March 2012 of $146/MW day to serve approximately 21%, 31% and 41% of each customer class through December 2012, December 2013 and for the period January 2014 through May 2015, respectively. All other capacity provided to CRES providers would be offered at $255/MW day. In 2012, an additional amount of capacity may be made available at the $146/MW day rate to accommodate any community aggregation load above 21%, if applicable.

The resolution of the capacity rate is also the subject of separate proceedings before the FERC and the PUCO. In those proceedings, OPCo is seeking a wholesale cost-based capacity rate, currently at approximately $355/MW day. In July 2012, the PUCO issued an order in the capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer its incurred capacity costs not recovered from CRES providers to the extent that the total incurred capacity costs do not exceed $188.88/MW day. The RPM price is approximately $20/MW day through May 2013. The order stated that the PUCO would establish an appropriate recovery mechanism in the pending June 2012 – May 2015 ESP proceeding. The PUCO postponed implementation of the order until August 8, 2012 or until an order is issued in OPCo’s pending June 2012 – May 2015 ESP proceeding, whichever is sooner. In July 2012, OPCo requested rehearing of the PUCO order. If OPCo is ultimately not permitted to fully recover its capacity cost deferral, it would reduce future net income and cash flows and impact financial condition.

The ESP also proposed to collect the PIRR from June 2013 through December 2018. As of June 30, 2012, the net PIRR deferral was $538 million, excluding unrecognized equity carrying costs. If OPCo is ultimately not permitted to fully recover its PIRR deferral, it would reduce future net income and cash flows and impact financial condition.

Further, the ESP proposed establishment of a non-bypassable Distribution Investment Rider through May 2015 to recover, with certain caps, post-August 2010 distribution investment. The filing also seeks establishment of a new non-bypassable Retail Stability Rider (RSR) to recover lost generation revenues to provide financial certainty and stability during the ESP transition period. The proposed RSR would be effective through May 2015. Finally, the ESP proposed a storm damage recovery mechanism for the deferral of operation and maintenance costs above $5 million, effective January 2012.

Intervenors and the PUCO staff filed testimony in May 2012 in opposition to many aspects of OPCo’s ESP, including the proposed RSR and the two-tiered capacity pricing structure for CRES providers. Intervenors recommended a flash cut to the current RPM rate for capacity. In addition, the PUCO staff’s testimony included a proposal to increase the vegetation management base used for calculating over/under recovery on incremental vegetation spend from $21 million to $39 million, which could increase future Other Operation and Maintenance expense by $18 million on an annual basis.

Hearings on the June 2012 – May 2015 ESP were held at the PUCO during the second quarter of 2012 and oral arguments were held in July 2012. A decision from the PUCO is expected in August 2012.

2011 Ohio Distribution Base Rate Case

In February 2011, OPCo filed with the PUCO for an annual increase in distribution rates of $94 million based upon an 11.15% return on common equity to be effective January 2012. In December 2011, a stipulation was approved by the PUCO which provided for no change in distribution rates and a new rider for a $15 million annual credit to residential ratepayers due principally to the inclusion of the rate base distribution investment in the Distribution Investment Rider (DIR) as approved by the modified stipulation in the ESP proceeding.

Because the February 2012 PUCO order rejected the ESP modified stipulation, collection of the DIR terminated. In March 2012, OPCo filed an application with the PUCO to approve an ESP for the period June 2012 through May 2015, which includes a request for a new DIR. See the “Proposed June 2012 – May 2015 ESP” section above. A decision in the June 2012 – May 2015 ESP proceeding is expected in August 2012. In March 2012, the PUCO issued an order clarifying that OPCo has the right to file a new distribution base rate case. If OPCo is not ultimately permitted to fully recover its costs, it would reduce future net income and cash flows and impact financial condition.

2009 Fuel Adjustment Clause Audit

The PUCO selected an outside consultant to conduct an audit of OPCo’s FAC for 2009. The outside consultant provided its audit report to the PUCO. In January 2012, the PUCO ordered that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. OPCo recorded a $30 million net favorable adjustment on the statement of income in the second quarter of 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. Management is unable to predict the outcome of any future consultant recommendation. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultants’ review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.

In June 2012, OPCo filed a notice of appeal with the Supreme Court of Ohio challenging the PUCO’s decision to have proceeds from the 2008 coal contract settlement applied to OPCo’s under recovered fuel balance. The PUCO filed a motion to dismiss OPCo’s notice of appeal at the Supreme Court of Ohio. A decision is pending from the Supreme Court of Ohio.

2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its results of the 2010 and 2011 FAC audits. The audit reports included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes. As of June 30, 2012, the amount of OPCo’s carrying costs that could potentially be reduced due to the accumulated income tax issue is estimated to be approximately $34 million, including $18 million of unrecognized equity carrying costs. Decisions from the PUCO are pending. Management is unable to predict the outcome of these proceedings. If the PUCO orders result in a reduction to the FAC deferral, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

proceeding, intervenors requested that OPCo be required to refund the Ormet-related regulatory asset and requested that the PUCO prevent OPCo from collecting the Ormet-related revenues in the future. The PUCO did not take any action on this request in the 2009-2011 ESP proceeding. The intervenors raised the issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement. This issue remains pending before the PUCO. If OPCo is not ultimately permitted to fully recover its requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

Ohio IGCC Plant

In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. Through June 30, 2012, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order. Intervenors have filed motions with the PUCO requesting all collected pre-construction costs be refunded to Ohio ratepayers with interest.

Management cannot predict the outcome of these proceedings concerning the Ohio IGCC plant or what effect, if any, these proceedings would have on future net income and cash flows. However, if OPCo is required to refund pre-construction costs collected, it could reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is scheduled to be in service in the fourth quarter of 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility. The Turk Plant is currently estimated to cost $1.8 billion, excluding AFUDC, plus an additional $120 million for transmission, excluding AFUDC. SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $120 million for transmission, excluding AFUDC. As of June 30, 2012, excluding costs attributable to its joint owners and a $49 million provision for a Texas capital costs cap, SWEPCo has capitalized approximately $1.6 billion of expenditures, including AFUDC and capitalized interest of $269 million for generation and related transmission costs of $121 million. As of June 30, 2012, the joint owners and SWEPCo have contractual construction obligations of approximately $65 million (including related transmission costs of $3 million). SWEPCo’s share of the contractual construction obligations is $48 million.

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. SWEPCo announced that it would continue construction of the Turk Plant and would not currently seek authority to serve Arkansas retail customers. In June 2010, in response to the Arkansas Supreme Court’s decision, the APSC issued an order which reversed and set aside the previously granted CECPN. SWEPCo currently has no contracts for the 88 MW of Turk Plant output but is evaluating its options.

The PUCT approved a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected 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 (TIEC) filed an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant should be revoked because the Turk Plant is unnecessary to serve retail customers. The Texas District Court and the Texas Court of Appeals affirmed the PUCT’s order in all respects. In April 2012, SWEPCo and TIEC filed petitions for review at the Supreme Court of Texas.

If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it could materially reduce future net income and cash flows and materially impact financial condition.

2012 Texas Base Rate Case

APCo and WPCo Rate Matters

Virginia Fuel Filing

In April 2012, APCo filed an application with the Virginia SCC for an annual increase in fuel revenues of $117 million to be effective June 2012. The filing included forecasted costs for the 15-month period ended August 2013 and requested recovery of APCo's anticipated unrecovered fuel balance as of May 2012 over a two-year period commencing in June 2012. The non-incremental portion of APCo's forecasted and deferred wind purchased power costs were reflected in APCo's filing. In June 2012, the Virginia SCC approved the application as filed.

Environmental Rate Adjustment Clause (RAC)

In November 2011, the Virginia SCC issued an order which approved APCo’s environmental RAC recovery of $30 million to be collected over one year beginning in February 2012 but denied recovery of certain environmental costs. As a result, in the fourth quarter of 2011, APCo recorded a pretax write-off of $31 million on the statement of income related to environmental compliance costs incurred from January 2009 through December 2010. In December 2011, APCo filed a notice of appeal with the Supreme Court of Virginia regarding this decision. If the Supreme Court of Virginia were to issue a favorable decision, it could increase future net income and cash flows.

APCo’s Filings for an IGCC Plant

Through June 30, 2012, 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. If the costs are not recoverable, it would reduce future net income and cash flows and impact financial condition.

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

In March 2012, West Virginia passed securitization legislation, which allows the WVPSC to establish a regulatory framework to securitize certain deferred ENEC balances and other ENEC related assets. Also in March 2012, APCo and WPCo filed their ENEC application with the WVPSC for the fourth year of a four year phase-in plan which requested no change in ENEC rates if the WVPSC issues a financing order allowing securitization of the under-recovered ENEC deferral and other ENEC related assets. The proposed rates consist of a Dresden Plant surcharge of $32 million and an increase in the construction surcharge of $2 million, offset by a reduction of $34 million in current ENEC rates. APCo and WPCo anticipate filing, in the third quarter of 2012, a request for a financing order with the WVPSC pursuant to the securitization legislation. Upon completion of the securitization, APCo and WPCo would offset the then current ENEC rates by an amount recovered through the securitization. If the financing order is not issued, APCo and WPCo requested recovery of these costs in current rates. As of June 30, 2012, APCo’s ENEC under-recovery balance of $326 million was recorded in Regulatory Assets on the balance sheet, excluding $6 million of unrecognized equity carrying costs.

In June 2012, a settlement agreement was filed with the WVPSC which recommended no change in total ENEC rates but reflected a $24 million increase in the construction surcharge and a $24 million decrease in ENEC rates. The settlement agreement did not address an intervenor recommendation that the fuel cost recovery for the Mountaineer Plant be limited to the prudently incurred cost of high sulfur coal which, if approved by the WVPSC, could result in a disallowance of approximately $14 million. Approval of the settlement agreement is pending before the WVPSC. If the WVPSC were to disallow a portion of APCo’s and WPCo’s deferred ENEC costs, it could reduce APCo’s future net income and cash flows and impact financial condition.

PSO Rate Matters

PSO 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 Oklahoma Industrial Energy Consumers (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 fuel 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 those ERCOT trading contracts. Hearings were held in June 2011. In June 2012, an Administrative Law Judge issued a report that affirmed the margin sharing amount of 25% and found that the OCC does not have the jurisdiction to grant the relief sought by the OIEC regarding the comprehensive review of all affiliate fuel transactions and the ERCOT trading contracts. If the OCC were to issue an unfavorable decision, it could reduce future net income and cash flows and impact financial condition.

I&M Rate Matters

2011 Indiana Base Rate Case

Life Cycle Management Project

KPCo Rate Matters

Big Sandy Unit 2 FGD System

FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund

In 2004, AEP eliminated transaction-based through-and-out transmission service charges and collected, at the FERC’s direction, load-based charges, referred to as RTO SECA through March 2006. Intervenors objected and 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. In 2006, a FERC Administrative Law Judge 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.

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 supported AEP’s position and required a compliance filing. 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.

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 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 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.

Possible Termination of the Interconnection Agreement

3. COMMITMENTS, GUARANTEES AND CONTINGENCIES

We are subject to certain claims and legal actions arising in our ordinary course of business. In addition, our business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against us cannot be predicted. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on our financial statements. The Commitments, Guarantees and Contingencies note within our 2011 Annual Report should be read in conjunction with this report.

GUARANTEES

We record liabilities for guarantees in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letters of Credit

We enter into standby letters of credit with third parties. As Parent, we issue all of these letters of credit in our ordinary course of business on behalf of our subsidiaries. These letters of credit cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

We have two credit facilities totaling $3.25 billion, under which we may issue up to $1.35 billion as letters of credit. As of June 30, 2012, the maximum future payments for letters of credit issued under the credit facilities were $167 million with maturities ranging from July 2012 to June 2013.

We have $402 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $407 million. The letters of credit have maturities ranging from March 2013 to July 2014.

Guarantees of Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study, 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 June 30, 2012, SWEPCo has collected approximately $56 million through a rider for final mine closure and reclamation costs, of which $11 million is recorded in Other Current Liabilities, $3 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $42 million is recorded in Asset Retirement Obligations on our condensed 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 2011 Annual Report “Dispositions” section of Note 6. As of June 30, 2012, there were no material liabilities recorded for any indemnifications.

Master Lease Agreements

We lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, we are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of June 30, 2012, the maximum potential loss for these lease agreements was approximately $17 million assuming the fair value of the equipment is zero at the end of the lease term.

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 assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $15 million and $17 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2012.

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. The maximum potential losses related to the guarantee are approximately $12 million and $13 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term. However, we believe that the fair value would produce a sufficient sales price to avoid any loss.

ENVIRONMENTAL CONTINGENCIES

Carbon Dioxide Public Nuisance Claims

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO 2 emissions exacerbated the effects of Hurricane Katrina. The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims. The court granted petitions for rehearing. An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place. Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision. The petition was denied in January 2011. Plaintiffs refiled their complaint in federal district court. The court ordered all defendants to respond to the refiled complaints in October 2011. In March 2012, the court granted the defendants’ motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations. Plaintiffs appealed the decision to the Fifth Circuit Court of Appeals. We will continue to defend against the claims. We are unable to determine a range of potential losses that are reasonably possible of occurring.

Alaskan Villages’ Claims

$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. The court heard oral argument in November 2011. We believe the action is without merit and will continue 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.

In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. I&M’s provision is approximately $10 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.

NUCLEAR CONTINGENCIES

I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission. 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 resultant liability could be substantial.

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 cost approximately $400 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. Due to the extensive lead time required to manufacture and install new turbine rotors, I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power. The installation of the new turbine rotors and other equipment occurred as planned during the fall 2011 refueling outage of Unit 1.

I&M maintains insurance through NEIL. As of June 30, 2012, we recorded $64 million in Prepayments and Other Current Assets on our condensed balance sheets representing amounts under NEIL insurance policies. Through June 30, 2012, I&M received payments from NEIL of $203 million for the cost incurred to date to repair the property damage and $185 million under an accidental outage policy.

The claims process with NEIL continues and includes a review of claims made under the insurance policies to ensure that claims associated with the outage are covered by the policies, 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. 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 reduce future net income and cash flows and impact financial condition.

OPERATIONAL CONTINGENCIES

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) was among the companies named as defendants in some of these cases. We settled, received summary judgment or were dismissed from all of these cases. The plaintiffs appealed the dismissal of several cases involving AEP companies in Nevada to the Ninth Circuit Court of Appeals. We will continue to defend the cases on appeal. We believe the provision we have is adequate. We believe the remaining exposure is immaterial.

4. ACQUISITION

2012

BlueStar Energy (Generation and Marketing segment)

In March 2012, we completed the acquisition of BlueStar Energy Holdings, Inc. (BlueStar) and its independent retail electric supplier BlueStar Energy Solutions for $70 million, subject to working capital adjustments. This transaction also included goodwill of $14 million, intangible assets associated with sales contracts and customer accounts of $59 million and liabilities associated with supply contracts of $25 million. These amounts are subject to revision once further evaluations are complete. BlueStar has been in operation since 2002. Beginning in June 2012, BlueStar began doing business as AEP Energy. AEP Energy provides electric supply for retail customers in Ohio, Illinois and other deregulated electricity markets and also provides energy solutions throughout the United States, including demand response and energy efficiency services.

5. BENEFIT PLANS

Components of Net Periodic Benefit Cost

The following tables provide the components of our net periodic benefit cost for the plans for the three and six months ended June 30, 2012 and 2011:

									Other Postretirement
	Pension Plans								Benefit Plans
	Three Months Ended June 30,								Three Months Ended June 30,
	2012				2011				2012				2011
	(in millions)
Service Cost		$	19			$	18			$	11			$	10
Interest Cost			55				60				26				27
Expected Return on Plan Assets			(79	)			(78	)			(25	)			(27	)
Amortization of Prior Service Credit			-				-				(4	)			-
Amortization of Net Actuarial Loss			38				31				15				8
Net Periodic Benefit Cost		$	33			$	31			$	23			$	18

									Other Postretirement
	Pension Plans								Benefit Plans
	Six Months Ended June 30,								Six Months Ended June 30,
	2012				2011				2012				2011
	(in millions)
Service Cost		$	38			$	36			$	23			$	21
Interest Cost			111				119				52				54
Expected Return on Plan Assets			(159	)			(157	)			(50	)			(54	)
Amortization of Prior Service Credit			-				-				(9	)			-
Amortization of Net Actuarial Loss			75				61				29				15
Net Periodic Benefit Cost		$	65			$	59			$	45			$	36

6. BUSINESS SEGMENTS

As outlined in our 2011 Annual Report, our primary business is the generation, transmission and distribution of electricity. 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. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

Utility Operations

·	Generation of electricity for sale to U.S. retail and wholesale customers.

·	Transmission and distribution of electricity through assets owned and operated by our ten utility operating companies.

Transmission Operations

·	Development, construction and operation of transmission facilities through investments in our wholly-owned transmission subsidiaries that were established in 2009 and our transmission joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.

AEP River Operations

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

Generation and Marketing

·	Nonregulated generation in ERCOT.

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

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

·	Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

·	Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005. These contracts were financial derivatives which settled and expired in the fourth quarter of 2011.

·	Revenue sharing related to the Plaquemine Cogeneration Facility which ended in the fourth quarter of 2011.

The tables below present our reportable segment information for the three and six months ended June 30, 2012 and 2011 and balance sheet information as of June 30, 2012 and December 31, 2011. These amounts include certain estimates and allocations where necessary. We reclassified prior year amounts to conform to the current year’s presentation.

					Nonutility Operations
							Generation
	Utility		Transmission		AEP River		and		All Other		Reconciling
	Operations		Operations		Operations		Marketing		(a)		Adjustments		Consolidated
	(in millions)
Three Months Ended June 30, 2012
Revenues from:
External Customers	$	3,234	$	1	$	163	$	148	$	5	$	-	$	3,551
Other Operating Segments		24		1		4		-		1		(30)		-
Total Revenues	$	3,258	$	2	$	167	$	148	$	6	$	(30)	$	3,551

Net Income (Loss)	$	365	$	8	$	3	$	(5)	$	(8)	$	-	$	363

					Nonutility Operations
							Generation
	Utility		Transmission		AEP River		and		All Other		Reconciling
	Operations		Operations		Operations		Marketing		(a)		Adjustments		Consolidated
	(in millions)
Three Months Ended June 30, 2011
Revenues from:
External Customers	$	3,359	$	1	$	162	$	79	$	8	$	-	$	3,609
Other Operating Segments		29		(1)		4		-		2		(34)		-
Total Revenues	$	3,388	$	-	$	166	$	79	$	10	$	(34)	$	3,609

Net Income (Loss)	$	350	$	6	$	(1)	$	11	$	(13)	$	-	$	353

					Nonutility Operations
							Generation
	Utility		Transmission		AEP River		and		All Other		Reconciling
	Operations		Operations		Operations		Marketing		(a)		Adjustments		Consolidated
	(in millions)
Six Months Ended June 30, 2012
Revenues from:
External Customers	$	6,596	$	2	$	335	$	233	$	10	$	-	$	7,176
Other Operating Segments		47		3		11		-		3		(64)		-
Total Revenues	$	6,643	$	5	$	346	$	233	$	13	$	(64)	$	7,176

Net Income (Loss)	$	749	$	17	$	12	$	(6)	$	(19)	$	-	$	753

					Nonutility Operations
							Generation
	Utility		Transmission		AEP River		and		All Other		Reconciling
	Operations		Operations		Operations		Marketing		(a)		Adjustments		Consolidated
	(in millions)
Six Months Ended June 30, 2011
Revenues from:
External Customers	$	6,856	$	1	$	329	$	141	$	12	$	-	$	7,339
Other Operating Segments		56		(1)		9		1		3		(68)		-
Total Revenues	$	6,912	$	-	$	338	$	142	$	15	$	(68)	$	7,339

Net Income (Loss)	$	724	$	10	$	6	$	12	$	(44)	$	-	$	708

					Nonutility Operations
							Generation				Reconciling
	Utility		Transmission		AEP River		and		All Other		Adjustments
	Operations		Operations		Operations		Marketing		(a)		(b)			Consolidated
	(in millions)
June 30, 2012
Total Property, Plant and Equipment	$	55,289	$	508	$	624	$	618	$	11	$	(266)		$	56,784
Accumulated Depreciation and
Amortization		18,627		2		150		232		10		(65)			18,956
Total Property, Plant and
Equipment - Net	$	36,662	$	506	$	474	$	386	$	1	$	(201)		$	37,828

Total Assets	$	50,983	$	865	$	650	$	1,030	$	16,638	$	(16,745)	(c)	$	53,421

					Nonutility Operations
							Generation				Reconciling
	Utility		Transmission		AEP River		and		All Other		Adjustments
	Operations		Operations		Operations		Marketing		(a)		(b)			Consolidated
	(in millions)
December 31, 2011
Total Property, Plant and Equipment	$	54,396	$	323	$	608	$	590	$	11	$	(258)		$	55,670
Accumulated Depreciation and
Amortization		18,393		-		136		219		10		(59)			18,699
Total Property, Plant and
Equipment - Net	$	36,003	$	323	$	472	$	371	$	1	$	(199)		$	36,971

Total Assets	$	50,093	$	594	$	659	$	868	$	16,751	$	(16,742)	(c)	$	52,223

(a)	All Other includes:

·	Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

·	Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005. These contracts were financial derivatives which settled and expired in the fourth quarter of 2011.

·	Revenue sharing related to the Plaquemine Cogeneration Facility which ended in the fourth quarter of 2011.

(b)	Includes eliminations due to an intercompany capital lease.

(c)	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.

7. 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.

The following table represents the gross notional volume of our outstanding derivative contracts as of June 30, 2012 and December 31, 2011:

Notional Volume of Derivative Instruments

	Volume
	June 30,			December 31,			Unit of
	2012			2011			Measure
Primary Risk Exposure	(in millions)
Commodity:
Power			704			609	MWHs
Coal			16			21	Tons
Natural Gas			115			100	MMBtus
Heating Oil and Gasoline			4			6	Gallons
Interest Rate		$	296		$	226	USD

Interest Rate and Foreign Currency		$	803		$	907	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 activities as “Commodity.” We do not hedge all fuel price risk.

We enter into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our floating-rate debt to a fixed rate. We also enter into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. Our forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. We do not hedge all interest rate exposure.

At times, we are exposed to foreign currency exchange rate risks primarily when we purchase certain fixed assets from foreign suppliers. In accordance with our risk management policy, we may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. We do not hedge all foreign currency exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of our derivative instruments, we also apply valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with our estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of our risk management contracts.

According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the June 30, 2012 and December 31, 2011 balance sheets, we netted $18 million and $26 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $94 million and $133 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.

The following tables represent the gross fair value impact of our derivative activity on our condensed balance sheets as of June 30, 2012 and December 31, 2011:

Fair Value of Derivative Instruments
June 30, 2012

	Risk Management
	Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location	Commodity (a)		Commodity (a)			Currency (a)			Other (b)			Total
	(in millions)
Current Risk Management Assets	$	996	$	37		$	1		$	(815	)	$	219
Long-term Risk Management Assets		733		15			1			(310	)		439
Total Assets		1,729		52			2			(1,125	)		658

Current Risk Management Liabilities		951		53			33			(872	)		165
Long-term Risk Management Liabilities		586		21			2			(350	)		259
Total Liabilities		1,537		74			35			(1,222	)		424

Total MTM Derivative Contract Net Assets
(Liabilities)	$	192	$	(22	)	$	(33	)	$	97		$	234

Fair Value of Derivative Instruments
December 31, 2011

	Risk Management
	Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location	Commodity (a)		Commodity (a)			Currency (a)			Other (b)			Total
	(in millions)
Current Risk Management Assets	$	852	$	24		$	-		$	(683	)	$	193
Long-term Risk Management Assets		641		15			-			(253	)		403
Total Assets		1,493		39			-			(936	)		596

Current Risk Management Liabilities		847		29			20			(746	)		150
Long-term Risk Management Liabilities		483		15			22			(325	)		195
Total Liabilities		1,330		44			42			(1,071	)		345

Total MTM Derivative Contract Net Assets
(Liabilities)	$	163	$	(5	)	$	(42	)	$	135		$	251

(a)

Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."

(b)

Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." Amounts also include de-designated risk management contracts.

The tables below present our activity of derivative risk management contracts for the three and six months ended June 30, 2012 and 2011:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended June 30, 2012 and 2011

Location of Gain (Loss)	2012		2011
	(in millions)
Utility Operations Revenues	$	4	$	18
Other Revenues		5		13
Regulatory Assets (a)		(17)		(5)
Regulatory Liabilities (a)		13		5
Total Gain (Loss) on Risk Management Contracts	$	5	$	31

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Six Months Ended June 30, 2012 and 2011

Location of Gain (Loss)	2012		2011
	(in millions)
Utility Operations Revenues	$	14	$	38
Other Revenues		8		15
Regulatory Assets (a)		(38)		(1)
Regulatory Liabilities (a)		27		11
Total Gain (Loss) on Risk Management Contracts	$	11	$	63

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

Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the condensed 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 condensed 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 condensed 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 condensed statements of income. During the three and six months ended June 30, 2012, we recognized gains of $1 million and $2 million, respectively, on our hedging instruments and offsetting losses of $1 million and $2 million, respectively, on our long-term debt. During the three and six months ended June 30, 2011, we recognized gains of $4 million and $8 million, respectively, on our hedging instruments and offsetting losses of $5 million and $9 million, respectively, on our long-term debt. During the three and six months ended June 30, 2012 and 2011, hedge ineffectiveness was immaterial.

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on our condensed 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).

Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on our condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on our condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and six months ended June 30, 2012 and 2011, we designated power, coal and natural gas derivatives as cash flow hedges.

We reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our condensed statements of income. During the three and six months ended June 30, 2012 and 2011, we designated heating oil and gasoline derivatives as cash flow hedges.

We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Interest Expense on our condensed statements of income in those periods in which hedged interest payments occur. During the three and six months ended June 30, 2012 and 2011, we designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Depreciation and Amortization expense on our condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and six months ended June 30, 2012 and 2011, we designated foreign currency derivatives as cash flow hedges.

During the three and six months ended June 30, 2012 and 2011, hedge ineffectiveness was immaterial or nonexistent for all cash flow hedge strategies disclosed above.

The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets and the reasons for changes in cash flow hedges for the three and six months ended June 30, 2012 and 2011. All amounts in the following tables are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended June 30, 2012
				Interest Rate
				and Foreign
	Commodity			Currency			Total
	(in millions)
Balance in AOCI as of March 31, 2012	$	(16	)	$	(18	)	$	(34	)
Changes in Fair Value Recognized in AOCI		(3	)		(13	)		(16	)
Amount of (Gain) or Loss Reclassified from AOCI
to Statement of Income/within Balance Sheet:
Utility Operations Revenues		-			-			-
Other Revenues		(2	)		-			(2	)
Purchased Electricity for Resale		6			-			6
Interest Expense		-			1			1
Regulatory Assets (a)		1			-			1
Regulatory Liabilities (a)		-			-			-
Balance in AOCI as of June 30, 2012	$	(14	)	$	(30	)	$	(44	)

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended June 30, 2011
				Interest Rate
				and Foreign
	Commodity			Currency		Total
	(in millions)
Balance in AOCI as of March 31, 2011	$	8		$	4	$	12
Changes in Fair Value Recognized in AOCI		3			-		3
Amount of (Gain) or Loss Reclassified from AOCI
to Statement of Income/within Balance Sheet:
Utility Operations Revenues		2			-		2
Other Revenues		(1	)		-		(1	)
Purchased Electricity for Resale		(1	)		-		(1	)
Interest Expense		-			1		1
Regulatory Assets (a)		1			-		1
Regulatory Liabilities (a)		-			-		-
Balance in AOCI as of June 30, 2011	$	12		$	5	$	17

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Six Months Ended June 30, 2012
				Interest Rate
				and Foreign
	Commodity			Currency			Total
	(in millions)
Balance in AOCI as of December 31, 2011	$	(3	)	$	(20	)	$	(23	)
Changes in Fair Value Recognized in AOCI		(23	)		(12	)		(35	)
Amount of (Gain) or Loss Reclassified from AOCI
to Statement of Income/within Balance Sheet:
Utility Operations Revenues		-			-			-
Other Revenues		(3	)		-			(3	)
Purchased Electricity for Resale		13			-			13
Interest Expense		-			2			2
Regulatory Assets (a)		2			-			2
Regulatory Liabilities (a)		-			-			-
Balance in AOCI as of June 30, 2012	$	(14	)	$	(30	)	$	(44	)

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Six Months Ended June 30, 2011
				Interest Rate
				and Foreign
	Commodity			Currency			Total
	(in millions)
Balance in AOCI as of December 31, 2010	$	7		$	4		$	11
Changes in Fair Value Recognized in AOCI		5			(1	)		4
Amount of (Gain) or Loss Reclassified from AOCI
to Statement of Income/within Balance Sheet:
Utility Operations Revenues		2			-			2
Other Revenues		(2	)		-			(2	)
Purchased Electricity for Resale		(1	)		-			(1	)
Interest Expense		-			2			2
Regulatory Assets (a)		1			-			1
Regulatory Liabilities (a)		-			-			-
Balance in AOCI as of June 30, 2011	$	12		$	5		$	17

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

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of June 30, 2012 and December 31, 2011 were:

Impact of Cash Flow Hedges on the Condensed Balance Sheet
June 30, 2012

				Interest Rate
				and Foreign
	Commodity			Currency			Total
	(in millions)
Hedging Assets (a)	$	38		$	-		$	38
Hedging Liabilities (a)		60			35			95
AOCI Gain (Loss) Net of Tax		(14	)		(30	)		(44	)
Portion Expected to be Reclassified to Net
Income During the Next Twelve Months		(10	)		(3	)		(13	)

Impact of Cash Flow Hedges on the Condensed Balance Sheet
December 31, 2011

				Interest Rate
				and Foreign
	Commodity			Currency			Total
	(in millions)
Hedging Assets (a)	$	20		$	-		$	20
Hedging Liabilities (a)		25			42			67
AOCI Gain (Loss) Net of Tax		(3	)		(20	)		(23	)
Portion Expected to be Reclassified to Net
Income During the Next Twelve Months		(3	)		(2	)		(5	)

(a)	Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed 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 June 30, 2012, 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 39 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.

Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, we are obligated to post an additional amount of collateral if our credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and our total exposure. On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP and its subsidiaries have not experienced a downgrade below investment grade. The following table represents: (a) our 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 June 30, 2012 and December 31, 2011:

	June 30,			December 31,
	2012			2011
	(in millions)
Liabilities for Derivative Contracts with Credit Downgrade Triggers		$	7		$	32
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post			35			39
Amount Attributable to RTO and ISO Activities			33			38

In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts. The following table represents: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral we have posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering our contractual netting arrangements as of June 30, 2012 and December 31, 2011:

	June 30,			December 31,
	2012			2011
	(in millions)
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		$	658		$	515
Amount of Cash Collateral Posted			10			56
Additional Settlement Liability if Cross Default Provision is Triggered			375			291

8. FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

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 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. 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. The main driver of our contracts being classified as Level 3 is the inability to substantiate our energy price curves in the market. To a lesser extent, these contracts could be sensitive to volumetric estimates for some structured transactions. However, a significant portion of our Level 3 volumetric contractual positions have been economically hedged which greatly limits potential earnings volatility.

We utilize our trustee’s external pricing service in our estimate of the fair value of the underlying investments held in the nuclear trusts. Our investment managers review and validate the prices utilized by the trustee to determine fair value. We perform our own valuation testing to verify the fair values of the securities. We receive audit reports of our trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts.

Assets in the nuclear trusts, Cash and Cash Equivalents and Other Temporary Investments are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. 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.

Fair Value Measurements of Long-term Debt

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange.

The book values and fair values of Long-term Debt as of June 30, 2012 and December 31, 2011 are summarized in the following table:

	June 30, 2012				December 31, 2011
	Book Value		Fair Value		Book Value		Fair Value
	(in millions)
Long-term Debt	$	17,302	$	20,025	$	16,516	$	19,259

Fair Value Measurements of Other Temporary Investments

Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds, marketable securities that we intend to hold for less than one year and investments by our protected cell of EIS.

The following is a summary of Other Temporary Investments:

			June 30, 2012
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
Other Temporary Investments			Cost		Gains		Losses		Value
			(in millions)
Restricted Cash (a)			$	217	$	-	$	-	$	217
Fixed Income Securities:
	Mutual Funds			64		1		-		65
Equity Securities - Mutual Funds				11		4		-		15
Total Other Temporary Investments			$	292	$	5	$	-	$	297

			December 31, 2011
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
Other Temporary Investments			Cost		Gains		Losses		Value
			(in millions)
Restricted Cash (a)			$	216	$	-	$	-	$	216
Fixed Income Securities:
	Mutual Funds			64		-		-		64
Equity Securities - Mutual Funds				11		3		-		14
Total Other Temporary Investments			$	291	$	3	$	-	$	294

(a)		Primarily represents amounts held for the repayment of debt.

The following table provides the activity for our debt and equity securities within Other Temporary Investments for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions)
Proceeds from Investment Sales		$	-		$	51		$	-		$	247
Purchases of Investments			1			5			1			153
Gross Realized Gains on Investment Sales			-			-			-			-
Gross Realized Losses on Investment Sales			-			-			-			-

As of June 30, 2012 and December 31, 2011, we had no Other Temporary Investments with an unrealized loss position. As of June 30, 2012, fixed income securities are primarily debt based mutual funds with short and intermediate maturities. Mutual funds may be sold and do not contain maturity dates.

The following tables provide details of Other Temporary Investments included in Accumulated Other Comprehensive Income (Loss) on our balance sheet and the reasons for changes for the three and six months ended June 30, 2012. All amounts in the following table are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Other Temporary Investments
Three Months Ended June 30, 2012

	(in millions)
Balance in AOCI as of March 31, 2012		$	4
Changes in Fair Value Recognized in AOCI			(1	)
Amount of (Gain) or Loss Reclassified from AOCI to Statement of Income:
Interest Income			-
Balance in AOCI as of June 30, 2012		$	3

Total Accumulated Other Comprehensive Income (Loss) Activity for Other Temporary Investments
Six Months Ended June 30, 2012

	(in millions)
Balance in AOCI as of December 31, 2011		$	2
Changes in Fair Value Recognized in AOCI			1
Amount of (Gain) or Loss Reclassified from AOCI to Statement of Income:
Interest Income			-
Balance in AOCI as of June 30, 2012		$	3

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow us to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include:

·	Acceptable investments (rated investment grade or above when purchased).

·	Maximum percentage invested in a specific type of investment.

·	Prohibition of investment in obligations of AEP or its affiliates.

·	Withdrawals permitted only for payment of decommissioning costs and trust expenses.

We maintain trust records for each regulatory jurisdiction. 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 trust funds for decommissioning nuclear facilities and for the disposal of SNF 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 gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in the trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw decommissioning funds.

The following is a summary of nuclear trust fund investments as of June 30, 2012 and December 31, 2011:

		June 30, 2012						December 31, 2011
		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		$	16	$	-	$	-	$	18	$	-	$	-
Fixed Income Securities:
	United States Government		644		104		(1)		544		61		(1)
	Corporate Debt		44		5		(1)		54		5		(2)
	State and Local Government		256		1		(1)		330		-		(2)
	Subtotal Fixed Income Securities		944		110		(3)		928		66		(5)
Equity Securities - Domestic			698		258		(79)		646		215		(80)
Spent Nuclear Fuel and
	Decommissioning Trusts	$	1,658	$	368	$	(82)	$	1,592	$	281	$	(85)

The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in millions)
Proceeds from Investment Sales	$	183	$	177	$	517	$	465
Purchases of Investments		192		186		545		492
Gross Realized Gains on Investment Sales		3		7		5		12
Gross Realized Losses on Investment Sales		1		4		2		9

The adjusted cost of debt securities was $834 million and $862 million as of June 30, 2012 and December 31, 2011, respectively. The adjusted cost of equity securities was $440 million and $431 million as of June 30, 2012 and December 31, 2011, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2012 was as follows:

	Fair Value
	of Debt
	Securities
	(in millions)
Within 1 year		$	40
1 year – 5 years			362
5 years – 10 years			315
After 10 years			227
Total		$	944

Fair Value Measurements of Financial Assets and Liabilities

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 June 30, 2012 and December 31, 2011. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in our valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2012

	Level 1		Level 2		Level 3		Other			Total

Assets:	(in millions)

Cash and Cash Equivalents (a)	$	20	$	-	$	-	$	277		$	297

Other Temporary Investments
Restricted Cash (a)		186		-		-		31			217
Fixed Income Securities:
Mutual Funds		65		-		-		-			65
Equity Securities - Mutual Funds (b)		15		-		-		-			15
Total Other Temporary Investments		266		-		-		31			297

Risk Management Assets
Risk Management Commodity Contracts (c) (f)		53		1,509		163		(1,128	)		597
Cash Flow Hedges:
Commodity Hedges (c)		13		38		1		(14	)		38
Fair Value Hedges		-		2		-		-			2
De-designated Risk Management Contracts (d)		-		-		-		21			21
Total Risk Management Assets		66		1,549		164		(1,121	)		658

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)		-		4		-		12			16
Fixed Income Securities:
United States Government		-		644		-		-			644
Corporate Debt		-		44		-		-			44
State and Local Government		-		256		-		-			256
Subtotal Fixed Income Securities		-		944		-		-			944
Equity Securities - Domestic (b)		698		-		-		-			698
Total Spent Nuclear Fuel and Decommissioning Trusts		698		948		-		12			1,658

Total Assets	$	1,050	$	2,497	$	164	$	(801	)	$	2,910

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (f)	$	47	$	1,419	$	67	$	(1,204	)	$	329
Cash Flow Hedges:
Commodity Hedges (c)		-		74		-		(14	)		60
Interest Rate/Foreign Currency Hedges		-		35		-		-			35
Total Risk Management Liabilities	$	47	$	1,528	$	67	$	(1,218	)	$	424

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2011

	Level 1		Level 2		Level 3		Other			Total

Assets:	(in millions)

Cash and Cash Equivalents (a)	$	6	$	-	$	-	$	215		$	221

Other Temporary Investments
Restricted Cash (a)		191		-		-		25			216
Fixed Income Securities:
Mutual Funds		64		-		-		-			64
Equity Securities - Mutual Funds (b)		14		-		-		-			14
Total Other Temporary Investments		269		-		-		25			294

Risk Management Assets
Risk Management Commodity Contracts (c) (g)		47		1,299		147		(945	)		548
Cash Flow Hedges:
Commodity Hedges (c)		15		23		-		(18	)		20
De-designated Risk Management Contracts (d)		-		-		-		28			28
Total Risk Management Assets		62		1,322		147		(935	)		596

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)		-		5		-		13			18
Fixed Income Securities:
United States Government		-		544		-		-			544
Corporate Debt		-		54		-		-			54
State and Local Government		-		330		-		-			330
Subtotal Fixed Income Securities		-		928		-		-			928
Equity Securities - Domestic (b)		646		-		-		-			646
Total Spent Nuclear Fuel and Decommissioning Trusts		646		933		-		13			1,592

Total Assets	$	983	$	2,255	$	147	$	(682	)	$	2,703

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	43	$	1,209	$	78	$	(1,052	)	$	278
Cash Flow Hedges:
Commodity Hedges (c)		-		43		-		(18	)		25
Interest Rate/Foreign Currency Hedges		-		42		-		-			42
Total Risk Management Liabilities	$	43	$	1,294	$	78	$	(1,070	)	$	345

(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 June 30, 2012 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 2012, $12 million in periods 2013-2015 and ($8) million in periods 2016-2018; Level 2 matures $12 million in 2012, $52 million in periods 2013-2015, $17 million in periods 2016-2017 and $9 million in periods 2018-2030; Level 3 matures $7 million in 2012, $38 million in periods 2013-2015, $24 million in periods 2016-2017 and $27 million in periods 2018-2030. Risk management commodity contracts are substantially comprised of power contracts.

(g)

The December 31, 2011 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $3 million in 2012, $7 million in periods 2013-2015 and ($6) million in periods 2016-2018; Level 2 matures $21 million in 2012, $50 million in periods 2013-2015, $11 million in periods 2016-2017 and $8 million in periods 2018-2030; Level 3 matures ($19) million in 2012, $44 million in periods 2013-2015, $18 million in periods 2016-2017 and $26 million in periods 2018-2030. Risk management commodity contracts are substantially comprised of power contracts.

There were no transfers between Level 1 and Level 2 during the three and six months ended June 30, 2012 and 2011.

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives and other investments classified as Level 3 in the fair value hierarchy:

	Net Risk Management
Three Months Ended June 30, 2012	Assets (Liabilities)
	(in millions)
Balance as of March 31, 2012	$	92
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)		(11	)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
Relating to Assets Still Held at the Reporting Date (a)		4
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		-
Purchases, Issuances and Settlements (c)		15
Transfers into Level 3 (d) (f)		(1	)
Transfers out of Level 3 (e) (f)		(8	)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)		6
Balance as of June 30, 2012	$	97

	Net Risk Management
Three Months Ended June 30, 2011	Assets (Liabilities)
	(in millions)
Balance as of March 31, 2011	$	73
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)		(10	)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
Relating to Assets Still Held at the Reporting Date (a)		10
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		-
Purchases, Issuances and Settlements (c)		14
Transfers into Level 3 (d) (f)		3
Transfers out of Level 3 (e) (f)		(4	)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)		(9	)
Balance as of June 30, 2011	$	77

	Net Risk Management
Six Months Ended June 30, 2012	Assets (Liabilities)
	(in millions)
Balance as of December 31, 2011	$	69
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)		(17	)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
Relating to Assets Still Held at the Reporting Date (a)		5
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		-
Purchases, Issuances and Settlements (c)		33
Transfers into Level 3 (d) (f)		14
Transfers out of Level 3 (e) (f)		(20	)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)		13
Balance as of June 30, 2012	$	97

	Net Risk Management
Six Months Ended June 30, 2011	Assets (Liabilities)
	(in millions)
Balance as of December 31, 2010	$	85
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)		(9	)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
Relating to Assets Still Held at the Reporting Date (a)		7
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		-
Purchases, Issuances and Settlements (c)		6
Transfers into Level 3 (d) (f)		4
Transfers out of Level 3 (e) (f)		(12	)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)		(4	)
Balance as of June 30, 2011	$	77

(a)	Included in revenues on our condensed 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)	Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

(g)	Relates to the net gains (losses) of those contracts that are not reflected on our condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets.

The following table quantifies the significant unobservable inputs used in developing the fair value of our Level 3 positions as of June 30, 2012:

	Fair Value				Valuation	Significant	Forward Price Range
	Assets		Liabilities		Technique	Unobservable Input (a)	Low		High
	(in millions)
Energy Contracts	$	152	$	60	Discounted Cash Flow	Forward Market Price	$	10.76	$	174.18
FTRs		12		7	Discounted Cash Flow	Forward Market Price		(10.77)		10.78
Total	$	164	$	67

(a)

Represents market prices beyond defined terms for Levels 1 and 2.

9. INCOME TAXES

AEP System Tax Allocation Agreement

We, along with our subsidiaries, file a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to our subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

Federal and State Income Tax Audit Status

We are no longer subject to U.S. federal examination for years before 2009. We completed the examination of the years 2007 and 2008 in April 2011 and settled all outstanding issues on appeal for the years 2001 through 2006 in October 2011. The settlements did not have a material impact on net income, cash flows or financial condition. The IRS examination of years 2009 and 2010 started in October 2011. 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 impact net income.

We, along with our subsidiaries, file income tax returns in various state, local and foreign jurisdictions. These taxing authorities routinely examine our tax returns and we are currently under examination in several state and local jurisdictions. 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. In March 2012, AEP settled all outstanding franchise tax issues with the state of Ohio for the years 2000 through 2009. The settlements did not have a material impact on net income, cash flows or financial condition.

10. FINANCING ACTIVITIES

Long-term Debt

Type of Debt	June 30, 2012			December 31, 2011
	(in millions)
Senior Unsecured Notes	$	11,858		$	11,737
Pollution Control Bonds		1,958			2,112
Notes Payable		497			402
Securitization Bonds		2,389			1,688
Junior Subordinated Debentures		315			315
Spent Nuclear Fuel Obligation (a)		265			265
Other Long-term Debt		51			29
Fair Value of Interest Rate Hedges		6			7
Unamortized Discount, Net		(37	)		(39	)
Total Long-term Debt Outstanding		17,302			16,516
Long-term Debt Due Within One Year		1,983			1,433
Long-term Debt	$	15,319		$	15,083

(a)

Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $308 million at both June 30, 2012 and December 31, 2011 and are included in Spent Nuclear Fuel and Decommissioning Trusts on our condensed balance sheets.

Long-term debt and other securities issued, retired and principal payments made during the first six months of 2012 are shown in the tables below:

			Principal			Interest
Company	Type of Debt		Amount			Rate	Due Date
Issuances:		(in millions)				(%)
I&M	Notes Payable		$	110		Variable	2016
I&M	Other Long-term Debt			20	(a)	Variable	2015
PSO	Notes Payable			2		3.00	2027
SWEPCo	Senior Unsecured Notes			275		3.55	2022
SWEPCo	Notes Payable			65		4.58	2032

Non-Registrant:
TCC	Securitization Bonds			312		2.845	2024
TCC	Securitization Bonds			308		0.88	2017
TCC	Securitization Bonds			180		1.976	2020
Total Issuances			$	1,272	(b)

(a)	Consists of a $110 million three-year credit facility to be used for general corporate purposes.

(b)	Amount indicated on the statement of cash flows of $1,261 million is net of issuance costs and premium or discount.

			Principal		Interest
Company	Type of Debt		Amount Paid		Rate	Due Date
Retirements and		(in millions)			(%)
Principal Payments:
APCo	Pollution Control Bonds		$	30	6.05	2024
APCo	Pollution Control Bonds			20	5.00	2021
I&M	Notes Payable			14	5.44	2013
I&M	Notes Payable			11	4.00	2014
I&M	Notes Payable			11	Variable	2015
I&M	Notes Payable			12	Variable	2016
I&M	Notes Payable			8	2.12	2016
OPCo	Pollution Control Bonds			45	4.85	2012
OPCo	Senior Unsecured Notes			150	Variable	2012
SWEPCo	Notes Payable			20	7.03	2012

Non-Registrant:
AEP Subsidiaries	Notes Payable			4	Variable	2017
AEP Subsidiaries	Notes Payable			1	7.59-8.03	2026
AEGCo	Senior Unsecured Notes			3	6.33	2037
TCC	Securitization Bonds			63	4.98	2013
TCC	Securitization Bonds			35	5.96	2013
TCC	Pollution Control Bonds			60	1.125	2012
Total Retirements and
Principal Payments			$	487

In July 2012, I&M retired $9 million of Notes Payable related to DCC Fuel.

In July 2012, TCC retired $73 million of Securitization Bonds.

As of June 30, 2012, trustees held, on our behalf, $583 million of our reacquired Pollution Control Bonds.

Dividend Restrictions

Parent Restrictions

The holders of our common stock are entitled to receive the dividends declared by our Board of Directors provided funds are legally available for such dividends. Our income derives from our common stock equity in the earnings of our utility subsidiaries.

Pursuant to the leverage restrictions in our credit agreements, we must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. None of AEP’s retained earnings were restricted for the purpose of the payment of dividends.

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 and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends. Specifically, several of our public utility subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%.

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 value of the common stock. This restriction does not limit the ability of the utility subsidiaries to pay dividends out of retained earnings.

Short-term Debt

Our outstanding short-term debt was as follows:

	June 30, 2012						December 31, 2011
	Outstanding			Interest			Outstanding			Interest
Type of Debt	Amount			Rate (a)			Amount			Rate (a)
	(in millions)						(in millions)
Securitized Debt for Receivables (b)		$	658		0.27	%		$	666		0.27	%
Commercial Paper			550		0.46	%			967		0.51	%
Line of Credit – Sabine (c)			-		-	%			17		1.79	%
Total Short-term Debt		$	1,208					$	1,650

(a)	Weighted average rate.

(b)	Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance.

(c)	This line of credit does not reduce available liquidity under AEP's credit facilities.

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 3.

Securitized Accounts Receivable – AEP Credit

AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. AEP Credit continues to service the receivables. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase our operating companies’ receivables and accelerate AEP Credit’s cash collections.

In June 2012, AEP Credit renewed its receivables securitization agreement. The agreement provides commitments of $700 million from bank conduits to finance receivables from AEP Credit. A commitment of $385 million expires in June 2013 and the remaining commitment of $315 million expires in June 2015.

Accounts receivable information for AEP Credit is as follows:

	Three Months Ended								Six Months Ended
	June 30,								June 30,
	2012				2011				2012				2011
	(dollars in millions)
Effective Interest Rates on Securitization of
Accounts Receivable			0.26	%			0.26	%			0.26	%			0.28	%
Net Uncollectible Accounts Receivable
Written Off		$	6			$	6			$	14			$	17

	June 30,		December 31,
	2012		2011
	(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral
Less Uncollectible Accounts	$	888	$	902
Total Principal Outstanding		658		666
Delinquent Securitized Accounts Receivable		35		38
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable		21		18
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable		355		370

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.

11. SUSTAINABLE COST REDUCTIONS

In April 2012, we initiated a process to identify employee repositioning opportunities and efficiencies that will result in sustainable cost savings. The process will result in involuntary severances and is expected to be completed by the end of 2012. 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 the second quarter of 2012 related to the sustainable cost reductions initiative.

	Total
	(in millions)
Incurred	$	13
Settled		(5)
Remaining Balance at June 30, 2012	$	8

These expenses relate primarily to severance benefits. They are included primarily in Other Operation on the income statement and Other Current Liabilities on the balance sheet. Approximately 94% of the expense was within the Utility Operations segment. At this time, we are unable to estimate the total amount to be incurred in future periods related to this initiative or to quantify the effects on future earnings, cash flows and financial condition.

APPALACHIAN POWER COMPANY

AND SUBSIDIARIES

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Possible Termination of the Interconnection Agreement

Virginia Regulatory Activity

West Virginia Regulatory Activity

In a November 2009 proceeding established by the WVPSC to explore options to meet WPCo's future power supply requirements, the WVPSC 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, the Virginia SCC and the FERC are required. In December 2011 and February 2012, APCo and WPCo filed merger applications with the WVPSC and the FERC, respectively. In February 2012, APCo and WPCo withdrew their merger application with the FERC. Management intends to refile a merger application with the FERC and also file a merger application with the Virginia SCC in the future. See “WPCo Merger with APCo” section of Note 2.

Storm Damage

In late June 2012 and early July 2012, APCo was significantly impacted by several severe storms. In the second quarter of 2012, APCo recorded minimal incremental operation and maintenance expenses related to the June 2012 storms. APCo expects to incur an estimated $95 million in total storm restoration costs in the third quarter of 2012, including an estimated $25 million in capital spending related to these storms and an estimated $70 million in incremental operation and maintenance costs. APCo intends to defer the majority of the incremental operation and maintenance costs and seek future recovery. If APCo is not ultimately permitted to recover these storm costs, it would reduce future net income and cash flows and impact financial condition.

Litigation and Environmental Issues

In the ordinary course of business, APCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2011 Annual Report. Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 146. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

See the “Executive Overview” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” section beginning on page 201 for additional discussion of relevant factors.

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2012		2011		2012		2011
			(in millions of KWHs)
Retail:
	Residential			2,184		2,367		5,634		6,326
	Commercial			1,683		1,696		3,309		3,394
	Industrial			2,702		2,699		5,306		5,318
	Miscellaneous			201		204		402		414
Total Retail (a)				6,770		6,966		14,651		15,452

Wholesale				1,492		2,336		2,873		4,163

Total KWHs				8,262		9,302		17,524		19,615

(a)		Represents energy delivered to distribution customers.

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

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2012		2011		2012		2011
		(in degree days)
Actual - Heating (a)			61		56		983		1,387
Normal - Heating (b)			97		100		1,440		1,437

Actual - Cooling (c)			419		464		444		470
Normal - Cooling (b)			354		348		360		354

(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.

Second Quarter of 2012 Compared to Second Quarter of 2011

Reconciliation of Second Quarter of 2011 to Second Quarter of 2012
Net Income
(in millions)

Second Quarter of 2011	$	32

Changes in Gross Margin:
Retail Margins		52
Off-system Sales		(2)
Transmission Revenues		2
Other Revenues		(2)
Total Change in Gross Margin		50

Changes in Expenses and Other:
Other Operation and Maintenance		21
Depreciation and Amortization		(17)
Taxes Other Than Income Taxes		1
Carrying Costs Income		(1)
Other Income		(2)
Interest Expense		1
Total Change in Expenses and Other		3

Income Tax Expense		(23)

Second Quarter of 2012	$	62

·	Retail Margins increased $52 million primarily due to the following:
	·	A $28 million increase due to lower capacity settlement expenses under the Interconnection Agreement, net of recovery in West Virginia and environmental deferrals in Virginia. This increase was primarily as a result of a mild winter in 2012 and its impact on APCo’s winter peak, APCo’s completion of the Dresden Plant in January 2012 and the removal of Sporn Unit 5 from the Interconnection Agreement in the third quarter of 2011.
	·	A $9 million increase due to higher rates in Virginia.
	·	A $9 million increase of additional wind purchase recovery costs deferred as a result of the June 2012 Virginia SCC fuel factor order.
	·	A $6 million increase in recoverable PJM expenses.
	These increases were partially offset by:
	·	A $7 million decrease in residential and commercial margins primarily due to lower non-weather related usage.
	·	A $3 million decrease in weather-related usage primarily due to a 9% decrease in cooling degree days.
·	Margins from Off-system Sales decreased $2 million primarily due to lower physical sales volumes and lower trading and marketing margins.

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

·	Other Operation and Maintenance expenses decreased $21 million primarily due to the following:
	·	A $10 million decrease in distribution expenses resulting from storm damage repairs in 2011.
	·	A $7 million decrease due to the deferral of transmission costs for the Virginia Transmission Rate Adjustment Clause.
	·	A $6 million decrease due to lower boiler maintenance expenses in 2012 at all six APCo coal-fueled power plants.
	These decreases were partially offset by:
	·	A $3 million increase due to expenses related to the 2012 sustainable cost reductions.
·	Depreciation and Amortization expenses increased $17 million primarily due to:
	·	A $10 million increase in depreciation as a result of increased depreciation rates in Virginia effective February 2012.
	·	A $5 million increase in amortization primarily as a result of the Virginia E&R surcharge and the Virginia Environmental Rate Adjustment Clause, both effective February 2012.
·	Income Tax Expense increased $23 million primarily due to an increase in pretax book income.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Reconciliation of Six Months Ended June 30, 2011 to Six Months Ended June 30, 2012
Net Income
(in millions)

Six Months Ended June 30, 2011	$	71

Changes in Gross Margin:
Retail Margins		95
Off-system Sales		(6)
Transmission Revenues		5
Other Revenues		(4)
Total Change in Gross Margin		90

Changes in Expenses and Other:
Other Operation and Maintenance		46
Depreciation and Amortization		(29)
Taxes Other Than Income Taxes		1
Carrying Costs Income		3
Other Income		(2)
Interest Expense		3
Total Change in Expenses and Other		22

Income Tax Expense		(45)

Six Months Ended June 30, 2012	$	138

·	Retail Margins increased $95 million primarily due to the following:
	·	A $55 million increase due to lower capacity settlement expenses under the Interconnection Agreement, net of recovery in West Virginia and environmental deferrals in Virginia. This increase was primarily as a result of a mild winter in 2012 and its impact on APCo’s winter peak, APCo’s completion of the Dresden Plant in January 2012 and the removal of Sporn Unit 5 from the Interconnection Agreement in the third quarter of 2011.
	·	A $31 million increase due to higher base rates in Virginia and West Virginia.
	·	An $18 million increase in other variable electric generation expenses.
	·	A $13 million increase in recoverable PJM expenses.
	·	A $9 million increase of additional wind purchase recovery costs deferred as a result of the June 2012 Virginia SCC fuel factor order.
	These increases were partially offset by:
	·	A $33 million decrease in weather-related usage primarily due to a 31% decrease in heating degree days.
	·	An $8 million decrease in residential and commercial margins primarily due to lower non-weather related usage.
·	Margins from Off-system Sales decreased $6 million primarily due to lower physical sales volumes and lower trading and marketing margins.
·	Transmission Revenues increased $5 million primarily due to increased Network Transmission Service revenue requirements beginning in July 2011.
·	Other Revenues decreased $4 million primarily due to gains on sales of SO 2 allowances in the first quarter of 2011.

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

·	Other Operation and Maintenance expenses decreased $46 million primarily due to the following:
	·	A $41 million decrease due to the first quarter 2011 write-off of a portion of the West Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC.
	·	A $14 million decrease due to the deferral of transmission costs for the Virginia Transmission Rate Adjustment Clause.
	·	An $11 million decrease due to 2011 storm expenses.
	·	A $7 million decrease due to lower boiler maintenance expenses in 2012 at all six APCo coal-fueled power plants.
	These decreases were partially offset by:
	·	A $32 million increase due to the first quarter 2011 deferral of 2009 storm costs and the 2010 cost reduction initiatives as allowed by the WVPSC in 2011.
	·	A $3 million increase due to expenses related to the 2012 sustainable cost reductions.
·	Depreciation and Amortization expenses increased $29 million primarily due to:
	·	A $17 million increase in depreciation as a result of increased depreciation rates in Virginia effective February 2012.
	·	A $9 million increase in amortization primarily as a result of the Virginia E&R surcharge and the Virginia Environmental Rate Adjustment Clause, both effective February 2012.
·	Carrying Costs Income increased $3 million primarily due to carrying charges on the Dresden Plant resulting from the Virginia Generation Rate Adjustment Clause and the West Virginia Expanded Net Energy Charge.
·	Interest Expense decreased $3 million primarily due to lower interest rates on long-term debt.
·	Income Tax Expense increased $45 million primarily due to an increase in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2011 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of accounting pronouncements.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

	Three Months Ended						Six Months Ended
	2012			2011			2012			2011
REVENUES
Electric Generation, Transmission and Distribution	$	647,236		$	666,785		$	1,385,835		$	1,417,797
Sales to AEP Affiliates		67,043			82,531			131,344			161,222
Other Revenues		2,182			2,129			4,758			4,246
TOTAL REVENUES		716,461			751,445			1,521,937			1,583,265

EXPENSES
Fuel and Other Consumables Used for Electric Generation		181,653			184,698			368,537			365,279
Purchased Electricity for Resale		44,869			69,127			110,225			138,345
Purchased Electricity from AEP Affiliates		125,864			183,661			281,881			407,850
Other Operation		72,685			74,617			147,004			187,893
Maintenance		37,830			57,163			84,165			89,456
Depreciation and Amortization		85,139			67,644			165,552			136,743
Taxes Other Than Income Taxes		24,995			25,968			51,957			53,071
TOTAL EXPENSES		573,035			662,878			1,209,321			1,378,637

OPERATING INCOME		143,426			88,567			312,616			204,628

Other Income (Expense):
Interest Income		359			762			702			1,082
Carrying Costs Income		5,467			6,542			13,252			9,981
Allowance for Equity Funds Used During Construction		4			1,212			517			2,095
Interest Expense		(51,945	)		(53,188	)		(103,252	)		(106,127	)

INCOME BEFORE INCOME TAX EXPENSE		97,311			43,895			223,835			111,659

Income Tax Expense		34,979			12,268			86,192			41,052

NET INCOME		62,332			31,627			137,643			70,607

Preferred Stock Dividend Requirements Including Capital
Stock Expense		-			200			-			400

EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	62,332		$	31,427		$	137,643		$	70,207

The common stock of APCo is wholly-owned by AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

	Three Months Ended				Six Months Ended
	2012		2011		2012		2011
Net Income	$	62,332	$	31,627	$	137,643	$	70,607

OTHER COMPREHENSIVE INCOME, NET OF TAXES
Cash Flow Hedges, Net of Tax of $305 and $377 for the Three Months Ended
June 30, 2012 and 2011, Respectively, and $15 and $652 for the Six
Months Ended June 30, 2012 and 2011, Respectively		566		700		27		1,211
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $484
and $419 for the Three Months Ended June 30, 2012 and 2011,
Respectively, and $969 and $837 for the Six Months Ended June 30,
2012 and 2011, Respectively		899		777		1,799		1,554

TOTAL OTHER COMPREHENSIVE INCOME		1,465		1,477		1,826		2,765

TOTAL COMPREHENSIVE INCOME	$	63,797	$	33,104	$	139,469	$	73,372

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

								Accumulated
								Other
		Common		Paid-in		Retained		Comprehensive
		Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S EQUITY –
	DECEMBER 31, 2010	$	260,458	$	1,475,496	$	1,133,748	$	(48,023)	$	2,821,679

Common Stock Dividends							(67,500)				(67,500)
Preferred Stock Dividends							(400)				(400)
Capital Stock Expense					3						3
Subtotal – Common Shareholder's Equity											2,753,782

Net Income							70,607				70,607
Other Comprehensive Income									2,765		2,765
TOTAL COMMON SHAREHOLDER'S EQUITY –
	JUNE 30, 2011	$	260,458	$	1,475,499	$	1,136,455	$	(45,258)	$	2,827,154

TOTAL COMMON SHAREHOLDER'S EQUITY –
	DECEMBER 31, 2011	$	260,458	$	1,573,752	$	1,160,747	$	(58,543)	$	2,936,414

Common Stock Dividends							(100,000)				(100,000)
Subtotal – Common Shareholder's Equity											2,836,414

Net Income							137,643				137,643
Other Comprehensive Income									1,826		1,826
TOTAL COMMON SHAREHOLDER'S EQUITY –
	JUNE 30, 2012	$	260,458	$	1,573,752	$	1,198,390	$	(56,717)	$	2,975,883

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2012 and December 31, 2011
(in thousands)
(Unaudited)

			2012		2011
CURRENT ASSETS
Cash and Cash Equivalents			$	2,109	$	2,317
Advances to Affiliates				22,573		22,008
Accounts Receivable:
	Customers			145,133		158,382
	Affiliated Companies			70,561		136,194
	Accrued Unbilled Revenues			47,419		68,427
	Miscellaneous			456		5,505
	Allowance for Uncollectible Accounts			(4,413)		(5,289)
		Total Accounts Receivable		259,156		363,219
Fuel				197,342		143,931
Materials and Supplies				103,267		101,724
Risk Management Assets				41,841		39,645
Accrued Tax Benefits				320		7,715
Regulatory Asset for Under-Recovered Fuel Costs				102,091		41,105
Prepayments and Other Current Assets				18,857		21,745
TOTAL CURRENT ASSETS				747,556		743,409

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			5,563,066		5,194,967
	Transmission			2,007,141		1,943,969
	Distribution			2,901,775		2,845,405
Other Property, Plant and Equipment				373,255		357,326
Construction Work in Progress				217,902		565,841
Total Property, Plant and Equipment				11,063,139		10,907,508
Accumulated Depreciation and Amortization				3,087,299		2,994,016
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				7,975,840		7,913,492

OTHER NONCURRENT ASSETS
Regulatory Assets				1,404,116		1,481,193
Long-term Risk Management Assets				44,676		39,226
Deferred Charges and Other Noncurrent Assets				110,514		122,187
TOTAL OTHER NONCURRENT ASSETS				1,559,306		1,642,606

TOTAL ASSETS			$	10,282,702	$	10,299,507

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2012 and December 31, 2011
(Unaudited)

		2012		2011
			(in thousands)
CURRENT LIABILITIES
Advances from Affiliates		$	166,988	$	198,248
Accounts Payable:
	General		139,851		186,612
	Affiliated Companies		107,129		137,376
Long-term Debt Due Within One Year – Nonaffiliated			545,027		594,525
Risk Management Liabilities			23,036		26,606
Customer Deposits			60,971		61,690
Deferred Income Taxes			38,857		14,255
Accrued Taxes			85,479		63,422
Accrued Interest			56,561		57,230
Other Current Liabilities			88,886		105,646
TOTAL CURRENT LIABILITIES			1,312,785		1,445,610

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			3,132,089		3,131,726
Long-term Risk Management Liabilities			22,638		12,923
Deferred Income Taxes			1,766,932		1,736,180
Regulatory Liabilities and Deferred Investment Tax Credits			620,058		576,792
Employee Benefits and Pension Obligations			296,168		302,182
Deferred Credits and Other Noncurrent Liabilities			156,149		157,680
TOTAL NONCURRENT LIABILITIES			5,994,034		5,917,483

TOTAL LIABILITIES			7,306,819		7,363,093

Rate Matters (Note 2)
Commitments and Contingencies (Note 3)

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			1,573,752		1,573,752
Retained Earnings			1,198,390		1,160,747
Accumulated Other Comprehensive Income (Loss)			(56,717)		(58,543)
TOTAL COMMON SHAREHOLDER’S EQUITY			2,975,883		2,936,414

TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	10,282,702	$	10,299,507

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

			2012		2011
OPERATING ACTIVITIES
Net Income			$	137,643	$	70,607
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			165,552		136,743
	Deferred Income Taxes			56,927		127,525
	Carrying Costs Income			(13,252)		(9,981)
	Allowance for Equity Funds Used During Construction			(517)		(2,095)
	Mark-to-Market of Risk Management Contracts			(2,323)		7,343
	Fuel Over/Under-Recovery, Net			26,417		(21,132)
	Change in Other Noncurrent Assets			(16,708)		11,361
	Change in Other Noncurrent Liabilities			18,266		5,239
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		103,680		84,748
		Fuel, Materials and Supplies		(54,954)		85,449
		Accounts Payable		(43,538)		(62,795)
		Accrued Taxes, Net		30,032		(56,411)
		Other Current Assets		2,579		6,281
		Other Current Liabilities		(15,880)		3,316
Net Cash Flows from Operating Activities				393,924		386,198

INVESTING ACTIVITIES
Construction Expenditures				(212,959)		(191,125)
Change in Advances to Affiliates, Net				(565)		(162,787)
Other Investing Activities				3,158		7,832
Net Cash Flows Used for Investing Activities				(210,366)		(346,080)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated				-		640,164
Change in Advances from Affiliates, Net				(31,260)		(128,331)
Retirement of Long-term Debt – Nonaffiliated				(49,512)		(479,661)
Retirement of Cumulative Preferred Stock				-		(8)
Principal Payments for Capital Lease Obligations				(3,258)		(3,720)
Dividends Paid on Common Stock				(100,000)		(67,500)
Dividends Paid on Cumulative Preferred Stock				-		(400)
Other Financing Activities				264		19
Net Cash Flows Used for Financing Activities				(183,766)		(39,437)

Net Increase (Decrease) in Cash and Cash Equivalents				(208)		681
Cash and Cash Equivalents at Beginning of Period				2,317		951
Cash and Cash Equivalents at End of Period			$	2,109	$	1,632

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	100,319	$	100,127
Net Cash Paid (Received) for Income Taxes				(10,090)		(33,371)
Noncash Acquisitions Under Capital Leases				1,265		565
Government Grants Included in Accounts Receivable at June 30,				-		4,061
Construction Expenditures Included in Current Liabilities at June 30,				30,439		52,421

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to APCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to APCo. The footnotes begin on page 146.

	Footnote Reference

Significant Accounting Matters	Note 1
Rate Matters	Note 2
Commitments, Guarantees and Contingencies	Note 3
Benefit Plans	Note 4
Business Segments	Note 5
Derivatives and Hedging	Note 6
Fair Value Measurements	Note 7
Income Taxes	Note 8
Financing Activities	Note 9
Sustainable Cost Reductions	Note 10

INDIANA MICHIGAN POWER COMPANY

AND SUBSIDIARIES

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Possible Termination of the Interconnection Agreement

In December 2010, each of the members of the Interconnection Agreement gave notice to AEPSC and each other of its decision to terminate the Interconnection Agreement effective as of December 31, 2013 or such other date as ordered by the FERC. It is unknown at this time whether the Interconnection Agreement 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. Management intends to file an application to terminate the Interconnection Agreement with the FERC in the future. If any of the members of the Interconnection Agreement experience decreases in revenues or increases in costs as a result of the termination of the Interconnection Agreement and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

Indiana Base Rate Case

Storm Damage

In late June 2012 and early July 2012, I&M was significantly impacted by several severe storms. In the second quarter of 2012, I&M recorded minimal incremental operation and maintenance expenses related to the June 2012 storms. I&M expects to incur an estimated $20 million in total storm restoration costs in the third quarter of 2012, including an estimated $5 million in capital spending related to these storms and an estimated $15 million in incremental operation and maintenance costs. Management is currently evaluating whether I&M will pursue recovery for the incremental operation and maintenance costs in the future.

Michigan Capacity Rate

In April 2012, the FERC issued an order, effective October 2012, which sets I&M's capacity cost to be charged to alternative electric suppliers (AES) serving switching customers in I&M's Michigan service territory at $394/MW day unless a state compensation mechanism is set by the MPSC. In May 2012, the MPSC issued an order to initiate a proceeding to establish a cost of service state compensation mechanism for the capacity rate to be charged to AES. I&M filed its cost of service proposal in June 2012. Under Michigan law, switching is limited to 10% of I&M's Michigan load, which was achieved in June 2012, the second month of customer switching. I&M is currently receiving compensation through PJM from billings to AES at the Reliability Pricing Model rate, which is less than I&M’s cost of service by approximately $8 million annually.

Cook Plant

Unit 1 Fire and Shutdown

Nuclear Regulatory Commission

As a result of the nuclear plant situation in Japan following a March 2011 earthquake, the Nuclear Regulatory Commission (NRC) initiated a review of safety procedures and requirements for nuclear generating facilities. This review could increase procedures and testing requirements, require physical modifications to the plant and increase future operating costs at the Cook Plant. The NRC is also looking into the fuel used at eleven reactors, including the units at the Cook Plant. Their concern relates to fuel temperatures if abnormal conditions are experienced. Management continues to monitor this issue and responds to the NRC’s inquiry, as necessary. In addition to the review by the NRC, Congress could consider legislation tightening oversight of nuclear generating facilities. Management is unable to predict the impact of potential future regulation of nuclear facilities.

Life Cycle Management Project

Litigation and Environmental Issues

In the ordinary course of business, I&M is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2011 Annual Report. Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 146. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2012		2011		2012		2011
			(in millions of KWHs)
Retail:
	Residential			1,217		1,170		2,786		3,006
	Commercial			1,290		1,188		2,456		2,452
	Industrial			1,964		1,871		3,797		3,715
	Miscellaneous			15		15		38		38
Total Retail (a)				4,486		4,244		9,077		9,211

Wholesale				2,068		2,408		4,029		4,504

Total KWHs				6,554		6,652		13,106		13,715

(a)		Represents energy delivered to distribution customers.

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

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2012		2011		2012		2011
		(in degree days)
Actual - Heating (a)			163		228		1,784		2,620
Normal - Heating (b)			235		238		2,420		2,414

Actual - Cooling (c)			369		304		398		304
Normal - Cooling (b)			256		252		257		253

(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.

Second Quarter of 2012 Compared to Second Quarter of 2011

Reconciliation of Second Quarter of 2011 to Second Quarter of 2012
Net Income
(in millions)

Second Quarter of 2011	$	31

Changes in Gross Margin:
Retail Margins		10
FERC Municipals and Cooperatives		(1)
Off-system Sales		(4)
Transmission Revenues		1
Other Revenues		(2)
Total Change in Gross Margin		4

Changes in Expenses and Other:
Other Operation and Maintenance		(1)
Depreciation and Amortization		(4)
Taxes Other Than Income Taxes		2
Other Income		(1)
Interest Expense		(1)
Total Change in Expenses and Other		(5)

Second Quarter of 2012	$	30

·	Retail Margins increased $10 million primarily due to the following:
	·	A $10 million increase due to industrial and commercial usage.
	·	A $6 million increase due to customer credits issued in 2011 for a settlement relating to the Cook Plant Unit 1 (Unit 1) fire outage. This increase was offset by an increase in Other Operation and Maintenance expenses as discussed below.
	·	A $4 million increase in rate recovery primarily due to higher PJM rider revenue. The increase in PJM revenues is offset by a corresponding increase in Other Operation and Maintenance expenses below.
	·	A $3 million increase due to a decrease in the AEGCo power bill.
	These increases were partially offset by:
	·	A $16 million decrease in capacity settlement revenues under the Interconnection Agreement, net of sharing with customers in Michigan. This decrease was primarily a result of a mild winter in 2012 and its impact on APCo’s winter peak.
·	Margins from FERC Municipals and Cooperatives decreased $1 million primarily due to the following:
	·	An $11 million decrease due to an annual base rate adjustment to actual costs.
	This decrease was partially offset by:
	·	A $10 million increase due to favorable fuel adjustments.
·	Margins from Off-system Sales decreased $4 million primarily due to lower physical sales volumes and lower trading and marketing margins.

Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expenses increased $1 million primarily due to the following:
	·	A $6 million increase in steam power expenses related to the Unit 1 fire outage. This increase was offset by an increase in Retail Margins as discussed above.
	This increase was partially offset by:
	·	A $4 million decrease due to maintenance outages at the Tanners Creek and Rockport plants in 2011.
·	Depreciation and Amortization expenses increased $4 million primarily due to higher depreciation rates reflecting a change in Tanners Creek Plant’s estimated life as approved in the Michigan base case settlement effective April 2012.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Reconciliation of Six Months Ended June 30, 2011 to Six Months Ended June 30, 2012
Net Income
(in millions)

Six Months Ended June 30, 2011	$	77

Changes in Gross Margin:
Retail Margins		(20)
FERC Municipals and Cooperatives		(2)
Off-system Sales		(8)
Transmission Revenues		2
Other Revenues		5
Total Change in Gross Margin		(23)

Changes in Expenses and Other:
Other Operation and Maintenance		5
Depreciation and Amortization		(4)
Taxes Other Than Income Taxes		2
Interest Expense		(1)
Total Change in Expenses and Other		2

Income Tax Expense		13

Six Months Ended June 30, 2012	$	69

·	Retail Margins decreased $20 million primarily due to the following:
	·	A $29 million decrease in capacity settlement revenues under the Interconnection Agreement, net of sharing with customers in Michigan. This decrease was primarily a result of a mild winter in 2012 and its impact on APCo’s winter peak.
	·	A $9 million decrease primarily due to lower commercial prices and lower residential usage.
	·	A $7 million decrease in weather-related usage primarily due to a 32% decrease in heating degree days.
	These decreases were offset by:
	·	A $19 million increase in rate recovery primarily due to higher PJM rider revenue, Michigan base rate increases and higher Indiana Demand Side Management (DSM) revenue. The increase in PJM and DSM revenues is offset by a corresponding increase in Other Operation and Maintenance expenses as discussed below.
	·	A $6 million increase due to customer credits issued in 2011 for a settlement relating to the Unit 1 fire outage. This increase was offset by an increase in Other Operation and Maintenance expenses as discussed below.
·	Margins from FERC Municipals and Cooperatives decreased $2 million primarily due to the following:
	·	A $10 million decrease due to an annual base rate adjustment to actual costs.
	This decrease was partially offset by:
	·	An $8 million increase due to favorable fuel adjustments.
·	Margins from Off-system Sales decreased $8 million primarily due to lower physical sales volumes and lower trading and marketing margins.
·	Other Revenues increased $5 million primarily due to increased I&M’s River Transportation Division (RTD) revenues from barging activities. This increase in RTD revenue was offset by a corresponding increase in Other Operation and Maintenance expenses from barging activities as discussed below.

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

·	Other Operation and Maintenance expenses decreased $5 million primarily due to the following:
	·	A $10 million decrease due to maintenance outages at the Tanners Creek and Rockport plants in 2011.
	·	A $5 million decrease in distribution expenses primarily due to decreased overhead line expenses.
	These decreases were partially offset by:
	·	A $6 million increase in steam power expenses related to the Unit 1 fire outage. This increase was offset by a corresponding increase in Retail Margins as discussed above.
	·	A $4 million increase in PJM and DSM expenses. The increase in PJM and DSM expenses was offset by a corresponding increase in Retail Margins as discussed above.
	·	A $2 million increase in RTD expenses from barging activities. The increase in RTD expense was offset by a corresponding increase in Other Revenues from barging activities as discussed above.
·	Depreciation and Amortization expenses increased $4 million primarily due to higher depreciation rates reflecting a change in Tanners Creek Plant’s estimated life as approved in the Michigan base case settlement effective April 2012.
·	Income Tax Expense decreased $13 million primarily due to a decrease in pretax book income, the regulatory accounting treatment of state income taxes and federal income tax adjustments recorded in 2011 related to prior year tax returns.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

	Three Months Ended						Six Months Ended
	2012			2011			2012			2011
REVENUES
Electric Generation, Transmission and Distribution	$	435,965		$	419,627		$	871,992		$	876,489
Sales to AEP Affiliates		45,728			70,902			121,643			145,770
Other Revenues - Affiliated		29,052			28,133			59,763			52,464
Other Revenues - Nonaffiliated		131			2,816			3,685			7,247
TOTAL REVENUES		510,876			521,478			1,057,083			1,081,970

EXPENSES
Fuel and Other Consumables Used for Electric Generation		96,715			108,322			209,085			223,384
Purchased Electricity for Resale		29,488			31,796			65,398			61,088
Purchased Electricity from AEP Affiliates		82,188			82,967			170,141			162,551
Other Operation		134,274			132,846			269,490			266,057
Maintenance		47,244			47,536			89,509			98,536
Depreciation and Amortization		37,560			33,263			71,539			67,350
Taxes Other Than Income Taxes		18,604			20,397			40,793			42,659
TOTAL EXPENSES		446,073			457,127			915,955			921,625

OPERATING INCOME		64,803			64,351			141,128			160,345

Other Income (Expense):
Other Income		2,848			3,467			7,110			7,362
Interest Expense		(25,373	)		(24,193	)		(50,426	)		(49,384	)

INCOME BEFORE INCOME TAX EXPENSE		42,278			43,625			97,812			118,323

Income Tax Expense		12,468			12,239			28,781			41,510

NET INCOME		29,810			31,386			69,031			76,813

Preferred Stock Dividend Requirements		-			85			-			170

EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	29,810		$	31,301		$	69,031		$	76,643

The common stock of I&M is wholly-owned by AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

100

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

	Three Months Ended					Six Months Ended
	2012			2011		2012			2011
Net Income	$	29,810		$	31,386	$	69,031		$	76,813

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of ($4,002) and $284 for the Three Months Ended
June 30, 2012 and 2011, Respectively, and ($2,680) and $570 for the Six
Months Ended June 30, 2012 and 2011, Respectively		(7,433	)		528		(4,977	)		1,059
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $150
and $127 for the Three Months Ended June 30, 2012 and 2011,
Respectively, and $300 and $255 for the Six Months Ended June 30, 2012
and 2011, Respectively		278			236		557			473

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		(7,155	)		764		(4,420	)		1,532

TOTAL COMPREHENSIVE INCOME	$	22,655		$	32,150	$	64,611		$	78,345

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

101

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

								Accumulated
								Other
		Common		Paid-in		Retained		Comprehensive
		Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2010	$	56,584	$	981,294	$	677,360	$	(20,889)	$	1,694,349

Common Stock Dividends							(37,500)				(37,500)
Preferred Stock Dividends							(170)				(170)
Subototal – Common Shareholder's Equity											1,656,679

Net Income							76,813				76,813
Other Comprehensive Income									1,532		1,532
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2011	$	56,584	$	981,294	$	716,503	$	(19,357)	$	1,735,024

TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2011	$	56,584	$	980,896	$	751,721	$	(28,221)	$	1,760,980

Common Stock Dividends							(25,000)				(25,000)
Subototal – Common Shareholder's Equity											1,735,980

Net Income							69,031				69,031
Other Comprehensive Loss									(4,420)		(4,420)
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2012	$	56,584	$	980,896	$	795,752	$	(32,641)	$	1,800,591

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

102

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2012 and December 31, 2011
(in thousands)
(Unaudited)

			2012		2011
CURRENT ASSETS
Cash and Cash Equivalents			$	898	$	1,020
Advances to Affiliates				238,466		95,714
Accounts Receivable:
	Customers			67,410		72,461
	Affiliated Companies			69,138		90,980
	Accrued Unbilled Revenues			19,088		14,780
	Miscellaneous			13,631		22,685
	Allowance for Uncollectible Accounts			(1,725)		(1,750)
		Total Accounts Receivable		167,542		199,156
Fuel				68,321		52,979
Materials and Supplies				170,538		175,924
Risk Management Assets				39,058		32,152
Accrued Tax Benefits				16,769		38,425
Deferred Cook Plant Fire Costs				64,435		63,809
Prepayments and Other Current Assets				41,256		35,395
TOTAL CURRENT ASSETS				807,283		694,574

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			3,932,503		3,932,472
	Transmission			1,261,018		1,224,786
	Distribution			1,506,629		1,481,608
Other Property, Plant and Equipment (Including Nuclear Fuel and Coal Mining)				667,272		709,558
Construction Work in Progress				254,149		236,096
Total Property, Plant and Equipment				7,621,571		7,584,520
Accumulated Depreciation, Depletion and Amortization				3,196,749		3,179,920
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				4,424,822		4,404,600

OTHER NONCURRENT ASSETS
Regulatory Assets				599,542		602,979
Spent Nuclear Fuel and Decommissioning Trusts				1,657,502		1,591,732
Long-term Risk Management Assets				31,408		29,362
Deferred Charges and Other Noncurrent Assets				64,510		69,309
TOTAL OTHER NONCURRENT ASSETS				2,352,962		2,293,382

TOTAL ASSETS			$	7,585,067	$	7,392,556

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

103

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2012 and December 31, 2011
(dollars in thousands)
(Unaudited)

		2012		2011
CURRENT LIABILITIES
Accounts Payable:
	General	$	78,758	$	113,063
	Affiliated Companies		65,145		81,102
Long-term Debt Due Within One Year – Nonaffiliated
	(June 30, 2012 and December 31, 2011 Amounts Include $125,241 and
	$101,620, Respectively, Related to DCC Fuel)		303,240		279,075
Risk Management Liabilities			34,239		16,980
Customer Deposits			30,543		30,696
Accrued Taxes			63,380		65,233
Accrued Interest			27,839		27,798
Other Current Liabilities			85,437		117,879
TOTAL CURRENT LIABILITIES			688,581		731,826

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			1,828,261		1,778,600
Long-term Risk Management Liabilities			15,908		18,871
Deferred Income Taxes			968,806		925,712
Regulatory Liabilities and Deferred Investment Tax Credits			955,482		875,202
Asset Retirement Obligations			1,039,442		1,013,122
Deferred Credits and Other Noncurrent Liabilities			287,996		288,243
TOTAL NONCURRENT LIABILITIES			5,095,895		4,899,750

TOTAL LIABILITIES			5,784,476		5,631,576

Rate Matters (Note 2)
Commitments and Contingencies (Note 3)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
	Authorized – 2,500,000 Shares
	Outstanding – 1,400,000 Shares		56,584		56,584
Paid-in Capital			980,896		980,896
Retained Earnings			795,752		751,721
Accumulated Other Comprehensive Income (Loss)			(32,641)		(28,221)
TOTAL COMMON SHAREHOLDER’S EQUITY			1,800,591		1,760,980

TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	7,585,067	$	7,392,556

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

104

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

			2012		2011
OPERATING ACTIVITIES
Net Income			$	69,031	$	76,813
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			71,539		67,350
	Deferred Income Taxes			40,899		42,561
	Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net			(9,163)		23,086
	Allowance for Equity Funds Used During Construction			(5,335)		(7,440)
	Mark-to-Market of Risk Management Contracts			(2,798)		6,183
	Amortization of Nuclear Fuel			64,228		72,474
	Fuel Over/Under-Recovery, Net			(2,650)		2,947
	Change in Other Noncurrent Assets			6,849		4,433
	Change in Other Noncurrent Liabilities			42,793		12,055
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		31,614		74,240
		Fuel, Materials and Supplies		(8,475)		26,103
		Accounts Payable		(33,573)		(76,440)
		Accrued Taxes, Net		19,642		13,775
		Other Current Assets		(9,183)		(887)
		Other Current Liabilities		(26,557)		(321)
Net Cash Flows from Operating Activities				248,861		336,932

INVESTING ACTIVITIES
Construction Expenditures				(137,473)		(133,064)
Change in Advances to Affiliates, Net				(142,752)		-
Purchases of Investment Securities				(544,981)		(492,162)
Sales of Investment Securities				516,579		464,688
Acquisitions of Nuclear Fuel				(11,263)		(93,230)
Other Investing Activities				26,692		17,125
Net Cash Flows Used for Investing Activities				(293,198)		(236,643)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated				128,533		76,624
Change in Advances from Affiliates, Net				-		(18,232)
Retirement of Long-term Debt – Nonaffiliated				(55,995)		(116,526)
Principal Payments for Capital Lease Obligations				(3,490)		(4,317)
Dividends Paid on Common Stock				(25,000)		(37,500)
Dividends Paid on Cumulative Preferred Stock				-		(170)
Other Financing Activities				167		25
Net Cash Flows from (Used for) Financing Activities				44,215		(100,096)

Net Increase (Decrease) in Cash and Cash Equivalents				(122)		193
Cash and Cash Equivalents at Beginning of Period				1,020		361
Cash and Cash Equivalents at End of Period			$	898	$	554

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	48,565	$	47,401
Net Cash Paid (Received) for Income Taxes				(31,921)		(19,847)
Noncash Acquisitions Under Capital Leases				4,341		1,218
Construction Expenditures Included in Current Liabilities at June 30,				26,509		36,109
Acquisition of Nuclear Fuel Included in Current Liabilities at June 30,				14		-

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

105

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to I&M’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to I&M. The footnotes begin on page 146.

	Footnote Reference

Significant Accounting Matters	Note 1
Rate Matters	Note 2
Commitments, Guarantees and Contingencies	Note 3
Benefit Plans	Note 4
Business Segments	Note 5
Derivatives and Hedging	Note 6
Fair Value Measurements	Note 7
Income Taxes	Note 8
Financing Activities	Note 9
Sustainable Cost Reductions	Note 10

106

OHIO POWER COMPANY CONSOLIDATED

107

OHIO POWER COMPANY CONSOLIDATED

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

CSPCo-OPCo Merger

On December 31, 2011, CSPCo merged into OPCo with OPCo being the surviving entity. All prior reported amounts have been recast as if the merger occurred on the first day of the earliest reporting period. All contracts and operations of CSPCo and its subsidiary are now part of OPCo.

Proposed June 2012 – May 2015 Ohio ESP

Ohio Customer Choice

In OPCo’s service territory, various CRES providers are targeting retail customers by offering alternative generation service. As a result, in comparison to the second quarter of 2011 and the first six months of 2011, OPCo lost approximately $64 million and $112 million, respectively, of gross margin. OPCo is recovering a portion of lost margins through collection of capacity revenues from CRES providers and off-system sales. OPCo has lost 34% of its load to CRES providers.

Ohio Capacity Rate

Proposed Corporate Separation and Termination of the Interconnection Agreement

108

If all regulatory approvals are received, OPCo’s results of operations related to generation will be determined by its ability to sell power and capacity at a profit at rates determined by the prevailing market. If OPCo is unable to sell power and capacity at a profit, it could reduce future net income and cash flows and impact financial condition. A decision is pending from the PUCO.

Storm Damage

In late June 2012 and early July 2012, OPCo was significantly impacted by several severe storms. In the second quarter of 2012, OPCo incurred minimal incremental operation and maintenance expenses related to the June 2012 storms. OPCo expects to incur an estimated $100 million in total storm restoration costs in the third quarter of 2012, including an estimated $35 million in capital spending related to these storms and an estimated $65 million in incremental operation and maintenance costs. OPCo intends to defer the majority of the incremental operation and maintenance costs and seek future recovery. If OPCo is not ultimately permitted to recover these storm costs, it would reduce future net income and cash flows and impact financial condition.

Securitization of Regulatory Assets

Significantly Excessive Earnings Test

Ohio Distribution Base Rate Case

In December 2011, a stipulation was approved by the PUCO which provided for no change in distribution rates and a new rider for a $15 million annual credit to residential ratepayers due principally to the inclusion of the rate base distribution investment in the Distribution Investment Rider (DIR) as approved by the modified stipulation in the ESP proceeding. Because the February 2012 PUCO order rejected the ESP modified stipulation, collection of the DIR terminated. In March 2012, OPCo filed an application with the PUCO to approve an ESP for the period June 2012 through May 2015, which includes a request for a new DIR. A decision in the June 2012 – May 2015 ESP proceeding is expected in August 2012. In March 2012, the PUCO issued an order clarifying that OPCo has the right to file a new distribution base rate case. See “2011 Ohio Distribution Base Rate Case” section of Note 2.

109

Litigation and Environmental Issues

In the ordinary course of business, OPCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2011 Annual Report. Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 146. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2012		2011		2012		2011
			(in millions of KWHs)
Retail:
	Residential			3,002		3,141		6,881		7,592
	Commercial			3,582		3,512		6,818		6,901
	Industrial			4,799		4,815		9,520		9,355
	Miscellaneous			27		28		58		63
Total Retail (a)				11,410		11,496		23,277		23,911

Wholesale				2,798		2,911		5,304		5,682

Total KWHs				14,208		14,407		28,581		29,593

(a)		Represents energy delivered to distribution customers.

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

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2012		2011		2012		2011
		(in degree days)
Actual - Heating (a)			146		161		1,543		2,234
Normal - Heating (b)			195		198		2,112		2,101

Actual - Cooling (c)			401		323		428		324
Normal - Cooling (b)			270		266		273		268

(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.

110

Second Quarter of 2012 Compared to Second Quarter of 2011

Reconciliation of Second Quarter of 2011 to Second Quarter of 2012
Net Income
(in millions)

Second Quarter of 2011	$	142

Changes in Gross Margin:
Retail Margins		(98)
Off-system Sales		12
Transmission Revenues		10
Other Revenues		10
Total Change in Gross Margin		(66)

Changes in Expenses and Other:
Other Operation and Maintenance		25
Depreciation and Amortization		(7)
Taxes Other Than Income Taxes		(3)
Carrying Costs Income		(5)
Other Income		(1)
Interest Expense		3
Total Change in Expenses and Other		12

Income Tax Expense		13

Second Quarter of 2012	$	101

·	Retail Margins decreased $98 million primarily due to the following:
	·	A $70 million decrease attributable to customers switching to alternative CRES providers. This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
	·	A $48 million decrease in capacity settlement revenues under the Interconnection Agreement. This decrease was primarily as a result of a mild winter in 2012 and its impact on APCo’s winter peak, APCo’s completion of the Dresden Plant in January 2012 and the removal of Sporn Unit 5 from the Interconnection Agreement in the third quarter of 2011.
	·	A $13 million net decrease in regulated revenue primarily due to the elimination of POLR charges effective June 2011, resulting from an October 2011 PUCO remand order.
	These decreases were partially offset by:
	·	A $35 million increase due to the partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
	·	A $9 million increase in weather-related usage primarily due to a 24% increase in cooling degree days.
·	Margins from Off-system Sales increased $12 million primarily due to higher PJM capacity revenues, partially offset by lower physical sales volumes and lower trading and marketing margins.
·	Transmission Revenues increased $10 million primarily due to increased transmission revenues for customers who have switched to alternative CRES providers. The increase in transmission revenues related to CRES providers partially offsets lost revenues included in Retail Margins above.
·	Other Revenues increased $10 million primarily due to sales to Buckeye Power, Inc. to provide backup energy under the Cardinal Station Agreement and increased revenues from Cook Coal Terminal.

111

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

·	Other Operation and Maintenance expenses decreased $25 million primarily due to the following:
	·	A $28 million decrease in plant maintenance expenses at various plants.
	·	A $4 million reserve recorded in second quarter of 2011 as a result of a legal proceeding.
	·	A $3 million decrease in employee-related expenses.
	These decreases were partially offset by:
	·	A $7 million increase in advertising expenses.
	·	A $3 million increase due to expenses related to the 2012 sustainable cost reductions.
·	Depreciation and Amortization expenses increased $7 million primarily due to the following:
	·	An $18 million increase due to shortened depreciable lives for certain generating plants effective December 2011.
	·	A $2 million increase in amortization of the Deferred Asset Recovery Rider assets as approved by the PUCO in the 2011 Ohio Distribution Base Rate Case.
	These increases were partially offset by:
	·	A $10 million decrease due to an amortization adjustment approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.
	·	A $5 million decrease in depreciation due to the third quarter 2011 plant impairment of Sporn Unit 5.
·	Carrying Costs Income decreased $5 million primarily due to a reduction in debt carrying charges associated with the 2008 coal contract settlement for the period January 2009 through March 2012 as ordered by the PUCO in April 2012 related to the 2009 FAC audit.
·	Income Tax Expense decreased $13 million primarily due to a decrease in pretax book income partially offset by other book/tax differences which are accounted for on a flow-through basis.

112

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Reconciliation of Six Months Ended June 30, 2011 to Six Months Ended June 30, 2012
Net Income
(in millions)

Six Months Ended June 30, 2011	$	308

Changes in Gross Margin:
Retail Margins		(201)
Off-system Sales		19
Transmission Revenues		17
Other Revenues		17
Total Change in Gross Margin		(148)

Changes in Expenses and Other:
Other Operation and Maintenance		78
Depreciation and Amortization		(8)
Taxes Other Than Income Taxes		(3)
Carrying Costs Income		(13)
Interest Expense		6
Total Change in Expenses and Other		60

Income Tax Expense		32

Six Months Ended June 30, 2012	$	252

·	Retail Margins decreased $201 million primarily due to the following:
	·	A $124 million decrease attributable to customers switching to alternative CRES providers. This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
	·	An $88 million decrease in capacity settlement revenues under the Interconnection Agreement. This decrease was primarily as a result of a mild winter in 2012 and its impact on APCo’s winter peak, APCo’s completion of the Dresden Plant in January 2012 and the removal of Sporn Unit 5 from the Interconnection Agreement in the third quarter of 2011.
	·	A $17 million net decrease in regulated revenue primarily due to the elimination of POLR charges effective June 2011, resulting from an October 2011 PUCO remand order.
	·	A $13 million decrease in weather-related usage primarily due to a 31% decrease in heating degree days.
	These decreases were partially offset by:
	·	A $35 million increase due to the second quarter 2012 partial reversal of a 2011 fuel provision based on an April 2012 PUCO order related to the 2009 FAC audit.
·	Margins from Off-system Sales increased $19 million primarily due to higher PJM capacity revenues, partially offset by lower physical sales volumes and lower trading and marketing margins.
·	Transmission Revenues increased $17 million primarily due to increased transmission revenues for customers who have switched to alternative CRES providers. The increase in transmission revenues related to CRES providers offsets lost revenues included in Retail Margins above.
·	Other Revenues increased $17 million primarily due to higher sales to Buckeye Power, Inc. to provide backup energy under the Cardinal Station Agreement and increased revenues from Cook Coal Terminal.

113

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

·	Other Operation and Maintenance expenses decreased $78 million primarily due to the following:
	·	A $40 million decrease in plant maintenance expenses at various plants.
	·	A $35 million decrease due to the first quarter 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of the Ohio modified stipulation.
	·	A $10 million decrease in employee-related expenses.
	These decreases were partially offset by:
	·	An $11 million gain from the sale of land in January 2011.
	·	A $7 million increase in advertising expenses.
	·	A $3 million increase due to expenses related to the 2012 sustainable cost reductions.
·	Depreciation and Amortization expenses increased $8 million primarily due to the following:
	·	A $32 million increase due to shortened depreciable lives for certain generating plants effective December 2011.
	·	A $5 million increase in amortization of the Deferred Asset Recovery Rider assets as approved by the PUCO in the 2011 Ohio Distribution Base Rate Case.
	These increases were partially offset by:
	·	A $19 million decrease due to an amortization adjustment approved by the PUCO in the 2011 Ohio Distribution Base Rate Case effective January 2012.
	·	A $10 million decrease in depreciation due to the third quarter 2011 plant impairment of Sporn Unit 5.
·	Carrying Costs Income decreased $13 million primarily due to the following:
	·	A $5 million reduction in debt carrying charges associated with the 2008 coal contract settlement for the period January 2009 through March 2012 as ordered by the PUCO in April 2012 related to the 2009 FAC audit.
	·	The collection of $3 million in carrying costs in first quarter 2012 on phase-in FAC deferrals.
	·	A $3 million decrease due to line extension carrying charges recorded in 2011.
·	Interest Expense decreased $6 million as a result of the reversal of capitalized interest on ESP Projects, an increase in the debt component of AFUDC as a result of new construction and the reversal of interest accruals related to federal tax reserve positions.
·	Income Tax Expense decreased $32 million primarily due to a decrease in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

114

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

	Three Months Ended						Six Months Ended
	2012			2011			2012			2011
REVENUES
Electric Generation, Transmission and Distribution	$	929,487		$	1,041,528		$	1,970,318		$	2,171,705
Sales to AEP Affiliates		172,561			235,625			354,318			488,159
Other Revenues - Affiliated		7,979			4,507			17,090			11,525
Other Revenues - Nonaffiliated		3,723			3,898			9,247			8,359
TOTAL REVENUES		1,113,750			1,285,558			2,350,973			2,679,748

EXPENSES
Fuel and Other Consumables Used for Electric Generation		298,294			340,733			668,287			748,129
Purchased Electricity for Resale		52,104			68,983			110,238			137,397
Purchased Electricity from AEP Affiliates		81,818			127,894			170,501			244,345
Other Operation		162,086			159,553			292,428			329,952
Maintenance		74,015			102,030			154,619			195,442
Depreciation and Amortization		137,009			129,698			271,439			263,110
Taxes Other Than Income Taxes		98,420			95,133			203,838			200,443
TOTAL EXPENSES		903,746			1,024,024			1,871,350			2,118,818

OPERATING INCOME		210,004			261,534			479,623			560,930

Other Income (Expense):
Interest Income		345			437			1,443			895
Carrying Costs Income		4,511			9,847			7,269			20,578
Allowance for Equity Funds Used During Construction		915			1,508			2,038			2,711
Interest Expense		(53,147	)		(56,631	)		(107,408	)		(113,651	)

INCOME BEFORE INCOME TAX EXPENSE		162,628			216,695			382,965			471,463

Income Tax Expense		61,205			74,501			130,712			163,299

NET INCOME		101,423			142,194			252,253			308,164

Preferred Stock Dividend Requirements Including
Capital Stock Expense		-			208			-			416

EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	101,423		$	141,986		$	252,253		$	307,748

The common stock of OPCo is wholly-owned by AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

115

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

	Three Months Ended				Six Months Ended
	2012		2011		2012			2011
Net Income	$	101,423	$	142,194	$	252,253		$	308,164

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $91 and $122 for the Three Months Ended
June 30, 2012 and 2011, Respectively, and $846 and $280 for the Six
Months Ended June 30, 2012 and 2011, Respectively		170		228		(1,571	)		521
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,745
and $1,422 for the Three Months Ended June 30, 2012 and 2011,
Respectively, and $3,490 and $2,844 for the Six Months Ended June 30,
2012 and 2011, Respectively		3,240		2,640		6,481			5,281

TOTAL OTHER COMPREHENSIVE INCOME		3,410		2,868		4,910			5,802

TOTAL COMPREHENSIVE INCOME	$	104,833	$	145,062	$	257,163		$	313,966

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

116

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

								Accumulated
								Other
		Common		Paid-in		Retained		Comprehensive
		Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2010	$	321,201	$	1,744,991	$	2,768,602	$	(180,155)	$	4,654,639

Common Stock Dividends							(325,000)				(325,000)
Preferred Stock Dividends							(366)				(366)
Capital Stock Expense					50		(50)				-
Subtotal – Common Shareholder's Equity											4,329,273

Net Income							308,164				308,164
Other Comprehensive Income									5,802		5,802
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2011	$	321,201	$	1,745,041	$	2,751,350	$	(174,353)	$	4,643,239

TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2011	$	321,201	$	1,744,099	$	2,582,600	$	(197,722)	$	4,450,178

Common Stock Dividends							(150,000)				(150,000)
Subtotal – Common Shareholder's Equity											4,300,178

Net Income							252,253				252,253
Other Comprehensive Income									4,910		4,910
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2012	$	321,201	$	1,744,099	$	2,684,853	$	(192,812)	$	4,557,341

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

117

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2012 and December 31, 2011
(in thousands)
(Unaudited)

			2012		2011
CURRENT ASSETS
Cash and Cash Equivalents			$	2,366	$	2,095
Advances to Affiliates				32,671		219,458
Accounts Receivable:
	Customers			116,264		146,432
	Affiliated Companies			146,434		162,830
	Accrued Unbilled Revenues			13,865		19,012
	Miscellaneous			5,030		16,994
	Allowance for Uncollectible Accounts			(3,712)		(3,563)
		Total Accounts Receivable		277,881		341,705
Fuel				344,642		262,886
Materials and Supplies				191,005		201,325
Risk Management Assets				62,962		54,293
Accrued Tax Benefits				6,643		11,975
Prepayments and Other Current Assets				29,430		41,560
TOTAL CURRENT ASSETS				947,600		1,135,297

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			9,552,733		9,502,614
	Transmission			1,971,788		1,948,329
	Distribution			3,631,335		3,545,574
Other Property, Plant and Equipment				568,702		546,642
Construction Work in Progress				346,531		354,465
Total Property, Plant and Equipment				16,071,089		15,897,624
Accumulated Depreciation and Amortization				5,764,534		5,742,561
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				10,306,555		10,155,063

OTHER NONCURRENT ASSETS
Regulatory Assets				1,405,104		1,370,504
Long-term Risk Management Assets				66,290		53,614
Deferred Charges and Other Noncurrent Assets				193,784		309,775
TOTAL OTHER NONCURRENT ASSETS				1,665,178		1,733,893

TOTAL ASSETS			$	12,919,333	$	13,024,253

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

118

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2012 and December 31, 2011
(Unaudited)

		2012		2011
			(in thousands)
CURRENT LIABILITIES
Accounts Payable:
	General	$	224,892	$	293,730
	Affiliated Companies		97,248		183,898
Long-term Debt Due Within One Year – Nonaffiliated			606,000		244,500
Risk Management Liabilities			35,141		36,561
Accrued Taxes			327,397		450,570
Accrued Interest			65,405		66,441
Other Current Liabilities			240,361		238,275
TOTAL CURRENT LIABILITIES			1,596,444		1,513,975

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			3,054,044		3,609,648
Long-term Debt – Affiliated			200,000		200,000
Long-term Risk Management Liabilities			33,753		17,890
Deferred Income Taxes			2,323,655		2,245,380
Regulatory Liabilities and Deferred Investment Tax Credits			507,454		301,124
Employee Benefits and Pension Obligations			318,506		335,029
Deferred Credits and Other Noncurrent Liabilities			328,136		351,029
TOTAL NONCURRENT LIABILITIES			6,765,548		7,060,100

TOTAL LIABILITIES			8,361,992		8,574,075

Rate Matters (Note 2)
Commitments and Contingencies (Note 3)

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			1,744,099		1,744,099
Retained Earnings			2,684,853		2,582,600
Accumulated Other Comprehensive Income (Loss)			(192,812)		(197,722)
TOTAL COMMON SHAREHOLDER’S EQUITY			4,557,341		4,450,178

TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	12,919,333	$	13,024,253

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

119

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

			2012		2011
OPERATING ACTIVITIES
Net Income			$	252,253	$	308,164
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			271,439		263,110
	Deferred Income Taxes			82,961		115,726
	Carrying Costs Income			(7,269)		(20,578)
	Allowance for Equity Funds Used During Construction			(2,038)		(2,711)
	Mark-to-Market of Risk Management Contracts			(8,328)		9,491
	Property Taxes			109,892		108,074
	Fuel Over/Under-Recovery, Net			(19,433)		(50,113)
	Change in Other Noncurrent Assets			(20,063)		(54,116)
	Change in Other Noncurrent Liabilities			416		24,932
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		64,404		114,701
		Fuel, Materials and Supplies		(70,666)		69,406
		Accounts Payable		(134,823)		(62,574)
		Accrued Taxes, Net		(115,596)		(156,417)
		Other Current Assets		7,982		3,700
		Other Current Liabilities		(13,884)		(30,536)
Net Cash Flows from Operating Activities				397,247		640,259

INVESTING ACTIVITIES
Construction Expenditures				(246,657)		(201,512)
Change in Advances to Affiliates, Net				186,787		(53,586)
Acquisitions of Assets				(48)		(1,714)
Proceeds from Sales of Assets				5,475		45,129
Other Investing Activities				6,753		19,495
Net Cash Flows Used for Investing Activities				(47,690)		(192,188)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated				-		49,768
Retirement of Long-term Debt – Nonaffiliated				(194,500)		(165,000)
Retirement of Cumulative Preferred Stock				-		(1)
Principal Payments for Capital Lease Obligations				(4,920)		(5,852)
Dividends Paid on Common Stock				(150,000)		(325,000)
Dividends Paid on Cumulative Preferred Stock				-		(366)
Other Financing Activities				134		(122)
Net Cash Flows Used for Financing Activities				(349,286)		(446,573)

Net Increase in Cash and Cash Equivalents				271		1,498
Cash and Cash Equivalents at Beginning of Period				2,095		949
Cash and Cash Equivalents at End of Period			$	2,366	$	2,447

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	107,216	$	109,135
Net Cash Paid for Income Taxes				15,019		52,476
Noncash Acquisitions Under Capital Leases				4,239		1,002
Government Grants Included in Accounts Receivable at June 30,				1,094		2,000
Construction Expenditures Included in Current Liabilities at June 30,				41,873		26,719

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

120

OHIO POWER COMPANY CONSOLIDATED

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to OPCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to OPCo. The footnotes begin on page 146.

	Footnote Reference

Significant Accounting Matters	Note 1
Rate Matters	Note 2
Commitments, Guarantees and Contingencies	Note 3
Benefit Plans	Note 4
Business Segments	Note 5
Derivatives and Hedging	Note 6
Fair Value Measurements	Note 7
Income Taxes	Note 8
Financing Activities	Note 9
Sustainable Cost Reductions	Note 10

121

PUBLIC SERVICE COMPANY OF OKLAHOMA

122

PUBLIC SERVICE COMPANY OF OKLAHOMA

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Litigation and Environmental Issues

In the ordinary course of business, PSO is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2011 Annual Report. Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 146. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2012		2011		2012		2011
			(in millions of KWHs)
Retail:
	Residential			1,542		1,537		2,879		3,077
	Commercial			1,373		1,389		2,474		2,520
	Industrial			1,298		1,243		2,491		2,366
	Miscellaneous			341		339		641		617
Total Retail (a)				4,554		4,508		8,485		8,580

Wholesale				394		317		939		552

Total KWHs				4,948		4,825		9,424		9,132

(a)		Represents energy delivered to distribution customers.

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

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2012		2011		2012		2011
		(in degree days)
Actual - Heating (a)			-		19		676		1,276
Normal - Heating (b)			41		42		1,107		1,100

Actual - Cooling (c)			871		912		935		945
Normal - Cooling (b)			635		624		648		637

(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.

123

Second Quarter of 2012 Compared to Second Quarter of 2011

Reconciliation of Second Quarter of 2011 to Second Quarter of 2012
Net Income
(in millions)

Second Quarter of 2011		$	32

Changes in Gross Margin:
Retail Margins (a)			4
Total Change in Gross Margin			4

Changes in Expenses and Other:
Depreciation and Amortization			1
Other Income			(1)
Total Change in Expenses and Other			-

Income Tax Expense			(1)

Second Quarter of 2012		$	35

(a)	Includes firm wholesale sales to municipals and cooperatives.

·	Retail Margins increased $4 million primarily due to the following:
	·	A $6 million increase primarily due to higher margins from the residential and commercial classes.
	·	A $2 million increase primarily due to revenue increases from rate riders. This increase in retail margins has corresponding increases to riders/trackers recognized in other expense items.
	These increases were partially offset by:
	·	A $4 million decrease in weather-related usage primarily due to a 4% decrease in cooling degree days.

124

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Reconciliation of Six Months Ended June 30, 2011 to Six Months Ended June 30, 2012
Net Income
(in millions)

Six Months Ended June 30, 2011		$	47

Changes in Gross Margin:
Retail Margins (a)			11
Transmission Revenues			(2)
Total Change in Gross Margin			9

Changes in Expenses and Other:
Other Operation and Maintenance			(10)
Depreciation and Amortization			1
Taxes Other Than Income Taxes			(1)
Interest Expense			2
Total Change in Expenses and Other			(8)

Six Months Ended June 30, 2012		$	48

(a)	Includes firm wholesale sales to municipals and cooperatives.

·	Retail Margins increased $11 million primarily due to the following:
	·	A $13 million increase primarily due to higher margins from the residential and commercial classes.
	·	A $6 million increase primarily due to revenue increases from rate riders. This increase in retail margins has corresponding increases to riders/trackers recognized in other expense items below.
	These increases were partially offset by:
	·	A $9 million decrease in weather-related usage primarily due to a decrease in heating and cooling degree days.

Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expenses increased $10 million primarily due to the following:
	·	A $7 million increase in transmission expenses primarily due to increased SPP transmission services.
	·	A $6 million increase in plant expenses primarily due to the 2011 deferral of generation maintenance expenses as a result of an order in PSO’s base rate case and an increase in generation plant maintenance.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

125

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

	Three Months Ended						Six Months Ended
	2012			2011			2012			2011
REVENUES
Electric Generation, Transmission and Distribution	$	311,310		$	322,028		$	603,832		$	606,615
Sales to AEP Affiliates		5,407			5,785			12,512			8,581
Other Revenues		594			775			1,498			1,395
TOTAL REVENUES		317,311			328,588			617,842			616,591

EXPENSES
Fuel and Other Consumables Used for Electric Generation		91,126			100,796			216,551			192,544
Purchased Electricity for Resale		44,822			46,018			70,264			87,197
Purchased Electricity from AEP Affiliates		4,260			9,111			10,458			25,722
Other Operation		48,880			48,736			95,859			93,140
Maintenance		24,853			25,152			53,178			45,873
Depreciation and Amortization		23,390			24,096			46,923			47,959
Taxes Other Than Income Taxes		10,681			10,494			21,820			21,090
TOTAL EXPENSES		248,012			264,403			515,053			513,525

OPERATING INCOME		69,299			64,185			102,789			103,066

Other Income (Expense):
Interest Income		97			28			1,032			80
Carrying Costs Income		529			1,876			1,142			2,523
Allowance for Equity Funds Used During Construction		468			284			890			650
Interest Expense		(13,766	)		(14,258	)		(28,477	)		(30,196	)

INCOME BEFORE INCOME TAX EXPENSE		56,627			52,115			77,376			76,123

Income Tax Expense		21,416			20,555			29,517			29,174

NET INCOME		35,211			31,560			47,859			46,949

Preferred Stock Dividend Requirements		-			49			-			98

EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	35,211		$	31,511		$	47,859		$	46,851

The common stock of PSO is wholly-owned by AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

126

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

	Three Months Ended						Six Months Ended
	2012			2011			2012			2011
Net Income	$	35,211		$	31,560		$	47,859		$	46,949

OTHER COMPREHENSIVE LOSS, NET OF TAXES
Cash Flow Hedges, Net of Tax of $193 and $168 for the Three Months Ended
June 30, 2012 and 2011, Respectively, and $222 and $407 for the Six
Months Ended June 30, 2012 and 2011, Respectively		(359	)		(313	)		(412	)		(756	)

TOTAL COMPREHENSIVE INCOME	$	34,852		$	31,247		$	47,447		$	46,193

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

127

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDER'S EQUITY
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

								Accumulated
								Other
		Common		Paid-in		Retained		Comprehensive
		Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2010	$	157,230	$	364,307	$	312,441	$	8,494	$	842,472

Common Stock Dividends							(32,500)				(32,500)
Preferred Stock Dividends							(98)				(98)
Subtotal – Common Shareholder's Equity											809,874

Net Income							46,949				46,949
Other Comprehensive Loss									(756)		(756)
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2011	$	157,230	$	364,307	$	326,792	$	7,738	$	856,067

TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2011	$	157,230	$	364,037	$	364,389	$	7,149	$	892,805

Common Stock Dividends							(30,000)				(30,000)
Subtotal – Common Shareholder's Equity											862,805

Net Income							47,859				47,859
Other Comprehensive Loss									(412)		(412)
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2012	$	157,230	$	364,037	$	382,248	$	6,737	$	910,252

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

128

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
June 30, 2012 and December 31, 2011
(in thousands)
(Unaudited)

			2012		2011
CURRENT ASSETS
Cash and Cash Equivalents			$	1,233	$	1,413
Advances to Affiliates				120,424		39,876
Accounts Receivable:
	Customers			39,426		39,977
	Affiliated Companies			22,922		23,079
	Miscellaneous			7,408		8,993
	Allowance for Uncollectible Accounts			(951)		(777)
		Total Accounts Receivable		68,805		71,272
Fuel				18,311		20,854
Materials and Supplies				50,409		50,347
Risk Management Assets				592		565
Deferred Income Tax Benefits				10,439		7,013
Accrued Tax Benefits				5,508		6,733
Regulatory Asset for Under-Recovered Fuel Costs				-		4,313
Prepayments and Other Current Assets				5,248		6,440
TOTAL CURRENT ASSETS				280,969		208,826

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			1,326,618		1,317,948
	Transmission			701,121		692,644
	Distribution			1,812,061		1,762,110
Other Property, Plant and Equipment				222,958		214,626
Construction Work in Progress				59,916		70,371
Total Property, Plant and Equipment				4,122,674		4,057,699
Accumulated Depreciation and Amortization				1,266,744		1,266,816
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				2,855,930		2,790,883

OTHER NONCURRENT ASSETS
Regulatory Assets				254,017		266,545
Long-term Risk Management Assets				131		314
Deferred Charges and Other Noncurrent Assets				32,220		13,536
TOTAL OTHER NONCURRENT ASSETS				286,368		280,395

TOTAL ASSETS			$	3,423,267	$	3,280,104

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

129

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND COMMON SHAREHOLDER'S EQUITY
June 30, 2012 and December 31, 2011
(Unaudited)

		2012		2011
			(in thousands)
CURRENT LIABILITIES
Accounts Payable:
	General	$	71,070	$	76,607
	Affiliated Companies		49,294		45,029
Long-term Debt Due Within One Year – Nonaffiliated			758		311
Risk Management Liabilities			4,651		1,280
Customer Deposits			46,818		47,493
Accrued Taxes			53,566		21,660
Accrued Interest			12,285		12,637
Regulatory Liability for Over-Recovered Fuel Costs			71,785		-
Other Current Liabilities			41,277		43,586
TOTAL CURRENT LIABILITIES			351,504		248,603

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			949,139		947,053
Long-term Risk Management Liabilities			2,490		1,330
Deferred Income Taxes			740,600		726,463
Regulatory Liabilities and Deferred Investment Tax Credits			343,762		334,812
Employee Benefits and Pension Obligations			82,625		84,548
Deferred Credits and Other Noncurrent Liabilities			42,895		44,490
TOTAL NONCURRENT LIABILITIES			2,161,511		2,138,696

TOTAL LIABILITIES			2,513,015		2,387,299


Rate Matters (Note 2)
Commitments and Contingencies (Note 3)

COMMON SHAREHOLDER’S EQUITY
Common Stock – Par Value – $15 Per Share:
	Authorized – 11,000,000 Shares
	Issued – 10,482,000 Shares
	Outstanding – 9,013,000 Shares		157,230		157,230
Paid-in Capital			364,037		364,037
Retained Earnings			382,248		364,389
Accumulated Other Comprehensive Income (Loss)			6,737		7,149
TOTAL COMMON SHAREHOLDER’S EQUITY			910,252		892,805

TOTAL LIABILITIES AND COMMON SHAREHOLDER'S EQUITY		$	3,423,267	$	3,280,104

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

130

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

				2012		2011
OPERATING ACTIVITIES
Net Income				$	47,859	$	46,949
Adjustments to Reconcile Net Income to Net Cash Flows from Operating
	Activities:
		Depreciation and Amortization			46,923		47,959
		Deferred Income Taxes			15,275		33,821
		Carrying Costs Income			(1,142)		(2,523)
		Allowance for Equity Funds Used During Construction			(890)		(650)
		Mark-to-Market of Risk Management Contracts			4,652		(292)
		Property Taxes			(19,347)		(18,742)
		Fuel Over/Under-Recovery, Net			76,098		(55)
		Change in Other Noncurrent Assets			1,043		8,705
		Change in Other Noncurrent Liabilities			(5,409)		21,377
		Changes in Certain Components of Working Capital:
			Accounts Receivable, Net		2,560		32,603
			Fuel, Materials and Supplies		2,481		(3,744)
			Accounts Payable		(3,263)		29,830
			Accrued Taxes, Net		32,771		16,468
			Other Current Assets		919		(3,070)
			Other Current Liabilities		(3,987)		10,048
Net Cash Flows from Operating Activities					196,543		218,684

INVESTING ACTIVITIES
Construction Expenditures					(102,354)		(65,343)
Change in Advances to Affiliates, Net					(80,548)		(110)
Other Investing Activities					413		760
Net Cash Flows Used for Investing Activities					(182,489)		(64,693)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated					2,395		247,554
Change in Advances from Affiliates, Net					-		(91,382)
Retirement of Long-term Debt – Nonaffiliated					(32)		(275,000)
Principal Payments for Capital Lease Obligations					(1,704)		(2,068)
Dividends Paid on Common Stock					(15,000)		(32,500)
Dividends Paid on Cumulative Preferred Stock					-		(98)
Other Financing Activities					107		6
Net Cash Flows Used for Financing Activities					(14,234)		(153,488)

Net Increase (Decrease) in Cash and Cash Equivalents					(180)		503
Cash and Cash Equivalents at Beginning of Period					1,413		470
Cash and Cash Equivalents at End of Period				$	1,233	$	973

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts				$	26,581	$	12,293
Net Cash Paid for Income Taxes					5,992		383
Noncash Acquisitions Under Capital Leases					759		415
Construction Expenditures Included in Current Liabilities at June 30,					14,881		8,319
Cash Dividends Declared but Not Paid					15,000		-

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

131

PUBLIC SERVICE COMPANY OF OKLAHOMA

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to PSO’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to PSO. The footnotes begin on page 146.

	Footnote Reference

Significant Accounting Matters	Note 1
Rate Matters	Note 2
Commitments, Guarantees and Contingencies	Note 3
Benefit Plans	Note 4
Business Segments	Note 5
Derivatives and Hedging	Note 6
Fair Value Measurements	Note 7
Income Taxes	Note 8
Financing Activities	Note 9
Sustainable Cost Reductions	Note 10

132

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

133

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Turk Plant

Texas Base Rate Case

Litigation and Environmental Issues

In the ordinary course of business, SWEPCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated. For details on regulatory proceedings and pending litigation, see Note 3 – Rate Matters and Note 5 – Commitments, Guarantees and Contingencies in the 2011 Annual Report. Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 146. Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales

			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2012		2011		2012		2011
			(in millions of KWHs)
Retail:
	Residential			1,570		1,645		2,952		3,249
	Commercial			1,643		1,664		2,954		3,029
	Industrial			1,513		1,425		2,831		2,676
	Miscellaneous			21		22		41		41
Total Retail (a)				4,747		4,756		8,778		8,995

Wholesale				1,607		1,787		3,879		3,665

Total KWHs				6,354		6,543		12,657		12,660

(a)		Represents energy delivered to distribution customers.

134

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

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2012		2011		2012		2011
		(in degree days)
Actual - Heating (a)			4		17		427		866
Normal - Heating (b)			27		28		773		773

Actual - Cooling (c)			910		934		1,024		985
Normal - Cooling (b)			710		700		740		731

(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.

135

Second Quarter of 2012 Compared to Second Quarter of 2011

Reconciliation of Second Quarter of 2011 to Second Quarter of 2012
Net Income
(in millions)

Second Quarter of 2011		$	51

Changes in Gross Margin:
Retail Margins (a)			6
Transmission Revenues			1
Total Change in Gross Margin			7

Changes in Expenses and Other:
Other Operation and Maintenance			2
Asset Impairment and Other Related Charges			(13)
Depreciation and Amortization			(2)
Taxes Other Than Income Taxes			(1)
Allowance for Equity Funds Used During Construction			3
Interest Expense			(1)
Total Change in Expenses and Other			(12)

Income Tax Expense			9

Second Quarter of 2012		$	55

(a)	Includes firm wholesale sales to municipals and cooperatives.

·	Retail Margins increased $6 million primarily due to the following:
	·	A $9 million increase in wholesale fuel recovery.
	This increase was partially offset by:
	·	A $2 million decrease in weather-related usage primarily due to a 3% decrease in cooling degree days.
	·	A $2 million decrease in municipal and cooperative revenues due to formula rate adjustments, partially offset by higher rates.

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

·	Other Operation and Maintenance expenses decreased $2 million primarily due to the following:
	·	A $4 million decrease in generation maintenance expenses primarily due to the timing of planned plant outages.
	This decrease was partially offset by:
	·	A $2 million increase due to expenses related to the 2012 sustainable cost reductions.
·	Asset Impairment and Other Related Charges include a second quarter 2012 write-off of $13 million related to the expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap.
·	Depreciation and Amortization expenses increased $2 million primarily due to a greater depreciable base.
·	Allowance for Equity Funds Used During Construction increased $3 million primarily due to construction at the Turk Plant.
·	Income Tax Expense decreased $9 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 decrease in pretax book income.

136

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Reconciliation of Six Months Ended June 30, 2011 to Six Months Ended June 30, 2012
Net Income
(in millions)

Six Months Ended June 30, 2011		$	81

Changes in Gross Margin:
Retail Margins (a)			(5)
Off-system Sales			1
Transmission Revenues			1
Total Change in Gross Margin			(3)

Changes in Expenses and Other:
Other Operation and Maintenance			12
Asset Impairment and Other Related Charges			(13)
Depreciation and Amortization			(3)
Interest Income			1
Allowance for Equity Funds Used During Construction			6
Total Change in Expenses and Other			3

Income Tax Expense			10

Six Months Ended June 30, 2012		$	91

(a)	Includes firm wholesale sales to municipals and cooperatives.

·	Retail Margins decreased $5 million primarily due to the following:
	·	A $7 million decrease in weather-related usage primarily due to a decrease in heating and cooling degree days.
	·	A $5 million decrease primarily due to fuel cost adjustments.
	These decreases were partially offset by:
	·	A $7 million increase in municipal and cooperative revenues due to formula rate adjustments and higher rates.

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

·	Other Operation and Maintenance expenses decreased $12 million primarily due to the following:
	·	A $10 million decrease in generation maintenance expenses primarily due to the timing of planned plant outages.
	·	A $3 million decrease in distribution maintenance expenses primarily due to decreased vegetation management and storm-related expenses.
	These decreases were partially offset by:
	·	A $2 million increase due to expenses related to the 2012 sustainable cost reductions.
·	Asset Impairment and Other Related Charges include a second quarter 2012 write-off of $13 million related to the expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap.
·	Depreciation and Amortization expenses increased $3 million primarily due to a greater depreciable base.
·	Allowance for Equity Funds Used During Construction increased $6 million primarily due to construction at the Turk Plant.
·	Income Tax Expense decreased $10 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.

137

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

138

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

	Three Months Ended						Six Months Ended
	2012			2011			2012			2011
REVENUES
Electric Generation, Transmission and Distribution	$	383,659		$	388,197		$	723,362		$	735,264
Sales to AEP Affiliates		6,890			10,671			15,847			26,250
Other Revenues		397			666			723			975
TOTAL REVENUES		390,946			399,534			739,932			762,489

EXPENSES
Fuel and Other Consumables Used for Electric Generation		138,008			139,713			266,242			273,725
Purchased Electricity for Resale		26,574			39,691			62,041			78,280
Purchased Electricity from AEP Affiliates		4,589			5,116			10,844			7,227
Other Operation		54,067			50,722			105,660			104,790
Maintenance		29,757			34,790			51,019			64,181
Asset Impairment and Other Related Charges		13,000			-			13,000			-
Depreciation and Amortization		34,655			32,718			68,676			66,008
Taxes Other Than Income Taxes		17,320			16,730			34,106			33,696
TOTAL EXPENSES		317,970			319,480			611,588			627,907

OPERATING INCOME		72,976			80,054			128,344			134,582

Other Income (Expense):
Interest Income		11			167			1,132			111
Allowance for Equity Funds Used During Construction		14,412			11,573			28,185			22,169
Interest Expense		(21,710	)		(20,835	)		(43,712	)		(43,260	)

INCOME BEFORE INCOME TAX EXPENSE AND
EQUITY EARNINGS		65,689			70,959			113,949			113,602

Income Tax Expense		11,505			20,571			23,977			33,967
Equity Earnings of Unconsolidated Subsidiary		718			683			1,325			1,263

NET INCOME		54,902			51,071			91,297			80,898

Net Income Attributable to Noncontrolling Interest		1,061			1,036			2,144			2,118

NET INCOME ATTRIBUTABLE TO SWEPCo
SHAREHOLDERS		53,841			50,035			89,153			78,780

Preferred Stock Dividend Requirements		-			57			-			114

EARNINGS ATTRIBUTABLE TO SWEPCo COMMON
SHAREHOLDER	$	53,841		$	49,978		$	89,153		$	78,666

The common stock of SWEPCo is wholly-owned by AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

139

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Three and Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

	Three Months Ended					Six Months Ended
	2012		2011			2012			2011
Net Income	$	54,902	$	51,071		$	91,297		$	80,898

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES
Cash Flow Hedges, Net of Tax of $213 and $65 for the Three Months Ended
June 30, 2012 and 2011, Respectively, and $743 and $137 for the Six
Months Ended June 30, 2012 and 2011, Respectively		396		(121	)		(1,379	)		255
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $90
and $612 for the Three Months Ended June 30, 2012 and 2011,
Respectively, and $179 and $681 for the Six Months Ended June 30,
2012 and 2011, Respectively		167		1,137			332			1,265

TOTAL OTHER COMPREHENSIVE INCOME (LOSS)		563		1,016			(1,047	)		1,520

TOTAL COMPREHENSIVE INCOME		55,465		52,087			90,250			82,418

Total Comprehensive Income Attributable to Noncontrolling Interest		1,061		1,036			2,144			2,118

TOTAL COMPREHENSIVE INCOME ATTRIBUTABLE TO SWEPCo
SHAREHOLDERS	$	54,404	$	51,051		$	88,106		$	80,300

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

140

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

	SWEPCo Common Shareholder
							Accumulated
							Other
	Common		Paid-in		Retained		Comprehensive		Noncontrolling
	Stock		Capital		Earnings		Income (Loss)		Interest		Total

TOTAL EQUITY – DECEMBER 31, 2010	$	135,660	$	674,979	$	868,840	$	(12,491)	$	361	$	1,667,349

Common Stock Dividends – Nonaffiliated										(2,126)		(2,126)
Preferred Stock Dividends						(114)						(114)
Subtotal – Equity												1,665,109

Net Income						78,780				2,118		80,898
Other Comprehensive Income								1,520				1,520
TOTAL EQUITY – JUNE 30, 2011	$	135,660	$	674,979	$	947,506	$	(10,971)	$	353	$	1,747,527

TOTAL EQUITY – DECEMBER 31, 2011	$	135,660	$	674,606	$	1,029,915	$	(26,815)	$	391	$	1,813,757

Common Stock Dividends – Nonaffiliated										(2,195)		(2,195)
Subtotal – Equity												1,811,562

Net Income						89,153				2,144		91,297
Other Comprehensive Loss								(1,047)				(1,047)
TOTAL EQUITY – JUNE 30, 2012	$	135,660	$	674,606	$	1,119,068	$	(27,862)	$	340	$	1,901,812

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

141

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2012 and December 31, 2011
(in thousands)
(Unaudited)

			2012		2011
CURRENT ASSETS
Cash and Cash Equivalents
	(June 30, 2012 Amount Includes $13,517 Related to Sabine)		$	14,617	$	801
Advances to Affiliates				97,022		-
Accounts Receivable:
	Customers			39,210		35,054
	Affiliated Companies			29,043		23,730
	Miscellaneous			22,886		19,370
	Allowance for Uncollectible Accounts			(960)		(989)
		Total Accounts Receivable		90,179		77,165
Fuel
	(June 30, 2012 and December 31, 2011 Amounts Include $23,616 and
	$32,651, Respectively, Related to Sabine)			104,499		102,015
Materials and Supplies				69,742		55,325
Risk Management Assets				1,297		445
Deferred Income Tax Benefits				7,286		8,195
Accrued Tax Benefits				52,285		1,541
Regulatory Asset for Under-Recovered Fuel Costs				12,835		10,843
Prepayments and Other Current Assets				25,930		16,827
TOTAL CURRENT ASSETS				475,692		273,157

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			2,332,494		2,326,102
	Transmission			1,053,582		988,534
	Distribution			1,721,839		1,675,764
Other Property, Plant and Equipment
	(June 30, 2012 and December 31, 2011 Amounts Include $245,607 and
	$232,948, Respectively, Related to Sabine)			660,819		637,019
Construction Work in Progress				1,520,783		1,443,569
Total Property, Plant and Equipment				7,289,517		7,070,988
Accumulated Depreciation and Amortization
	(June 30, 2012 and December 31, 2011 Amounts Include $107,859 and
	$103,586, Respectively, Related to Sabine)			2,249,214		2,211,912
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				5,040,303		4,859,076

OTHER NONCURRENT ASSETS
Regulatory Assets				423,048		394,276
Long-term Risk Management Assets				368		282
Deferred Charges and Other Noncurrent Assets				98,986		74,992
TOTAL OTHER NONCURRENT ASSETS				522,402		469,550

TOTAL ASSETS			$	6,038,397	$	5,601,783

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

142

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2012 and December 31, 2011
(Unaudited)

		2012		2011
			(in thousands)
CURRENT LIABILITIES
Advances from Affiliates		$	-	$	132,473
Accounts Payable:
	General		155,153		181,268
	Affiliated Companies		58,582		59,201
Short-term Debt – Nonaffiliated			-		17,016
Long-term Debt Due Within One Year – Nonaffiliated			3,250		20,000
Risk Management Liabilities			8,009		24,359
Customer Deposits			53,552		52,095
Accrued Taxes			54,527		44,404
Accrued Interest			43,685		39,629
Obligations Under Capital Leases			16,695		15,058
Regulatory Liability for Over-Recovered Fuel Costs			2,626		5,032
Other Current Liabilities			67,227		64,413
TOTAL CURRENT LIABILITIES			463,306		654,948

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			2,044,426		1,708,637
Long-term Risk Management Liabilities			335		221
Deferred Income Taxes			828,904		665,668
Regulatory Liabilities and Deferred Investment Tax Credits			459,529		428,571
Asset Retirement Obligations			80,851		65,673
Employee Benefits and Pension Obligations			91,985		87,159
Obligations Under Capital Leases			115,535		112,802
Deferred Credits and Other Noncurrent Liabilities			51,714		64,347
TOTAL NONCURRENT LIABILITIES			3,673,279		3,133,078

TOTAL LIABILITIES			4,136,585		3,788,026

Rate Matters (Note 2)
Commitments and Contingencies (Note 3)

EQUITY
Common Stock – Par Value – $18 Per Share:
	Authorized – 7,600,000 Shares
	Outstanding – 7,536,640 Shares		135,660		135,660
Paid-in Capital			674,606		674,606
Retained Earnings			1,119,068		1,029,915
Accumulated Other Comprehensive Income (Loss)			(27,862)		(26,815)
TOTAL COMMON SHAREHOLDER’S EQUITY			1,901,472		1,813,366

Noncontrolling Interest			340		391

TOTAL EQUITY			1,901,812		1,813,757

TOTAL LIABILITIES AND EQUITY		$	6,038,397	$	5,601,783

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

143

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2012 and 2011
(in thousands)
(Unaudited)

				2012		2011
OPERATING ACTIVITIES
Net Income				$	91,297	$	80,898
Adjustments to Reconcile Net Income to Net Cash Flows from
	Operating Activities:
		Depreciation and Amortization			68,676		66,008
		Deferred Income Taxes			138,594		23,562
		Asset Impairment and Other Related Charges			13,000		-
		Allowance for Equity Funds Used During Construction			(28,185)		(22,169)
		Mark-to-Market of Risk Management Contracts			1,927		(1,863)
		Property Taxes			(19,790)		(20,356)
		Fuel Over/Under-Recovery, Net			(4,398)		(25,144)
		Change in Other Noncurrent Assets			1,678		17,791
		Change in Other Noncurrent Liabilities			17,707		27,255
		Changes in Certain Components of Working Capital:
			Accounts Receivable, Net		(12,989)		9,062
			Fuel, Materials and Supplies		(16,901)		(8,929)
			Accounts Payable		2,938		37,823
			Accrued Taxes, Net		(40,616)		24,753
			Other Current Assets		(7,685)		(1,485)
			Other Current Liabilities		(6,367)		2,657
Net Cash Flows from Operating Activities					198,886		209,863

INVESTING ACTIVITIES
Construction Expenditures					(246,957)		(237,834)
Change in Advances to Affiliates, Net					(97,022)		51,538
Other Investing Activities					(1,927)		(7,953)
Net Cash Flows Used for Investing Activities					(345,906)		(194,249)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated					336,576		-
Credit Facility Borrowings					21,462		27,413
Change in Advances from Affiliates, Net					(132,473)		-
Retirement of Long-term Debt – Nonaffiliated					(20,000)		-
Retirement of Cumulative Preferred Stock					-		(1)
Credit Facility Repayments					(38,478)		(33,630)
Principal Payments for Capital Lease Obligations					(7,899)		(6,655)
Dividends Paid on Common Stock – Nonaffiliated					(2,195)		(2,126)
Dividends Paid on Cumulative Preferred Stock					-		(114)
Other Financing Activities					3,843		74
Net Cash Flows from (Used for) Financing Activities					160,836		(15,039)

Net Increase in Cash and Cash Equivalents					13,816		575
Cash and Cash Equivalents at Beginning of Period					801		1,514
Cash and Cash Equivalents at End of Period				$	14,617	$	2,089

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts				$	32,595	$	37,681
Net Cash Paid (Received) for Income Taxes					(47,741)		8,026
Noncash Acquisitions Under Capital Leases					12,350		4,378
Construction Expenditures Included in Current Liabilities at June 30,					79,960		96,959

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 146.

144

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to SWEPCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to SWEPCo. The footnotes begin on page 146.

	Footnote Reference

Significant Accounting Matters	Note 1
Rate Matters	Note 2
Commitments, Guarantees and Contingencies	Note 3
Benefit Plans	Note 4
Business Segments	Note 5
Derivatives and Hedging	Note 6
Fair Value Measurements	Note 7
Income Taxes	Note 8
Financing Activities	Note 9
Sustainable Cost Reductions	Note 10

145

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to condensed financial statements that follow are a combined presentation for the Registrant Subsidiaries. The following list indicates the registrants to which the footnotes apply:

1.	Significant Accounting Matters	APCo, I&M, OPCo, PSO, SWEPCo
2.	Rate Matters	APCo, I&M, OPCo, PSO, SWEPCo
3.	Commitments, Guarantees and Contingencies	APCo, I&M, OPCo, PSO, SWEPCo
4.	Benefit Plans	APCo, I&M, OPCo, PSO, SWEPCo
5.	Business Segments	APCo, I&M, OPCo, PSO, SWEPCo
6.	Derivatives and Hedging	APCo, I&M, OPCo, PSO, SWEPCo
7.	Fair Value Measurements	APCo, I&M, OPCo, PSO, SWEPCo
8.	Income Taxes	APCo, I&M, OPCo, PSO, SWEPCo
9.	Financing Activities	APCo, I&M, OPCo, PSO, SWEPCo
10.	Sustainable Cost Reductions	APCo, I&M, OPCo, PSO, SWEPCo

146

1. SIGNIFICANT ACCOUNTING MATTERS

General

The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and six months ended June 30, 2012 is not necessarily indicative of results that may be expected for the year ending December 31, 2012. The condensed financial statements are unaudited and should be read in conjunction with the audited 2011 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2011 as filed with the SEC on February 28, 2012.

Variable Interest Entities

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.

SWEPCo is the primary beneficiary of Sabine. I&M is the primary beneficiary of DCC Fuel. APCo, I&M, OPCo, PSO and SWEPCo each hold a significant variable interest in AEPSC. I&M and OPCo 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 three months ended June 30, 2012 and 2011 were $36 million and $30 million, respectively, and for the six months ended June 30, 2012 and 2011 were $91 million and $64 million, respectively. See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s condensed balance sheets.

147

The balances below represent the assets and liabilities of Sabine that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
June 30, 2012 and December 31, 2011
(in thousands)
	Sabine
ASSETS	2012		2011
Current Assets	$	66,966	$	48,044
Net Property, Plant and Equipment		169,929		153,715
Other Noncurrent Assets		57,005		42,574
Total Assets	$	293,900	$	244,333

LIABILITIES AND EQUITY
Current Liabilities	$	42,028	$	67,779
Noncurrent Liabilities		251,532		176,163
Equity		340		391
Total Liabilities and Equity	$	293,900	$	244,333

I&M has nuclear fuel lease agreements with DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC and DCC Fuel V LLC (collectively DCC Fuel). DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended June 30, 2012 and 2011 were $42 million and $38 million, respectively, and for the six months ended June 30, 2012 and 2011 were $59 million and $43 million, respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s condensed balance sheets.

The balances below represent the assets and liabilities of DCC Fuel that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
June 30, 2012 and December 31, 2011
(in thousands)
	DCC Fuel
ASSETS	2012		2011
Current Assets	$	146,857	$	118,144
Net Property, Plant and Equipment		240,961		188,375
Other Noncurrent Assets		142,837		117,772
Total Assets	$	530,655	$	424,291

LIABILITIES AND EQUITY
Current Liabilities	$	126,595	$	102,946
Noncurrent Liabilities		404,060		321,345
Equity		-		-
Total Liabilities and Equity	$	530,655	$	424,291

148

DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the three months ended June 30, 2012 and 2011 were $20 million and $15 million, respectively, and for the six months ended June 30, 2012 and 2011 were $34 million and $29 million, respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s condensed balance sheets.

SWEPCo’s investment in DHLC was:

	June 30, 2012				December 31, 2011
	As Reported on		Maximum		As Reported on		Maximum
	the Balance Sheet		Exposure		the Balance Sheet		Exposure
	(in thousands)
Capital Contribution from SWEPCo	$	7,643	$	7,643	$	7,643	$	7,643
Retained Earnings		1,163		1,163		1,120		1,120
SWEPCo's Guarantee of Debt		-		56,706		-		52,310

Total Investment in DHLC	$	8,806	$	65,512	$	8,763	$	61,073

AEPSC provides certain managerial and professional services to AEP’s subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.

Total AEPSC billings to the Registrant Subsidiaries were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
Company	2012		2011		2012		2011
	(in thousands)
APCo	$	43,894	$	47,352	$	82,440	$	92,293
I&M		31,377		31,006		57,484		62,834
OPCo		67,490		72,992		120,935		136,869
PSO		21,301		21,130		38,897		40,548
SWEPCo		33,246		31,560		59,966		61,393

The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows:

	June 30, 2012				December 31, 2011
	As Reported on the		Maximum		As Reported on the		Maximum
Company	Balance Sheet		Exposure		Balance Sheet		Exposure
	(in thousands)
APCo	$	16,077	$	16,077	$	20,812	$	20,812
I&M		11,526		11,526		13,741		13,741
OPCo		19,233		19,233		29,823		29,823
PSO		8,067		8,067		9,280		9,280
SWEPCo		12,302		12,302		14,699		14,699

149

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 OPCo. AEP guarantees all the debt obligations of AEGCo. I&M and OPCo are considered to have a significant interest in AEGCo due to these transactions. I&M and OPCo 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, OPCo and KPCo, this financing would be provided by AEP. For additional information regarding AEGCo’s lease, see the “Rockport Lease” section of Note 12 in the 2011 Annual Report.

Total billings from AEGCo were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
Company	2012		2011		2012		2011
	(in thousands)
I&M	$	53,917	$	49,852	$	112,739	$	102,673
OPCo		44,823		40,983		103,239		92,017

The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows:

	June 30, 2012				December 31, 2011
	As Reported on		Maximum		As Reported on		Maximum
Company	the Balance Sheet		Exposure		the Balance Sheet		Exposure
	(in thousands)
I&M	$	20,912	$	20,912	$	25,731	$	25,731
OPCo		16,822		16,822		22,139		22,139

CSPCo-OPCo Merger

150

2. RATE MATTERS

As discussed in the 2011 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2011 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2012 and updates the 2011 Annual Report.

Regulatory Assets Not Yet Being Recovered

			APCo
			June 30,		December 31,
			2012		2011
Noncurrent Regulatory Assets (excluding fuel)			(in thousands)
Regulatory assets not yet being recovered pending future proceedings to determine
	the recovery method and timing:
Regulatory Assets Currently Not Earning a Return
	Virginia Environmental Rate Adjustment Clause		$	22,336	$	17,950
	Mountaineer Carbon Capture and Storage
		Product Validation Facility		14,155		14,155
	Special Rate Mechanism for Century Aluminum			12,939		12,811
	Dresden Operating Costs			7,265		-
	Virginia Deferred Wind Power Costs			4,277		38,192
	Transmission Agreement Phase-In			2,510		1,925
	Mountaineer Carbon Capture and Storage
		Commercial Scale Facility		1,289		1,335
	Other Regulatory Assets Not Yet Being Recovered			3,049		1,010
Total Regulatory Assets Not Yet Being Recovered			$	67,820	$	87,378

			I&M
			June 30,		December 31,
			2012		2011
Noncurrent Regulatory Assets (excluding fuel)			(in thousands)
Regulatory assets not yet being recovered pending future proceedings to determine
	the recovery method and timing:
Regulatory Assets Currently Not Earning a Return
	Litigation Settlement		$	10,954	$	10,803
	Mountaineer Carbon Capture and Storage
		Commercial Scale Facility		1,382		1,680
	Other Regulatory Asset Not Being Recovered			658		-
Total Regulatory Assets Not Yet Being Recovered			$	12,994	$	12,483

		OPCo
		June 30,		December 31,
		2012		2011
Noncurrent Regulatory Assets (excluding fuel)		(in thousands)
Regulatory assets not yet being recovered pending future proceedings to determine
	the recovery method and timing:
Regulatory Assets Currently Earning a Return
	Economic Development Rider	$	12,892	$	12,572
Regulatory Assets Currently Not Earning a Return
	Storm Related Costs		-		8,375
Total Regulatory Assets Not Yet Being Recovered		$	12,892	$	20,947

151

			SWEPCo
			June 30,		December 31,
			2012		2011
Noncurrent Regulatory Assets (excluding fuel)			(in thousands)
Regulatory assets not yet being recovered pending future proceedings to determine
	the recovery method and timing:
Regulatory Assets Currently Not Earning a Return
	Rate Case Expenses		$	2,760	$	-
	Mountaineer Carbon Capture and Storage
		Commercial Scale Facility		2,298		2,380
	Other Regulatory Assets Not Yet Being Recovered			2,006		1,699
Total Regulatory Assets Not Yet Being Recovered			$	7,064	$	4,079

OPCo Rate Matters

Ohio Electric Security Plan Filing

2009 – 2011 ESP

In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off of certain pretax earnings in 2010 and a subsequent refund to customers during 2011. In May 2011, the IEU and the Ohio Energy Group (OEG) filed appeals with the Supreme Court of Ohio challenging the PUCO’s SEET decision. The OEG’s appeal seeks the inclusion of off-system sales (OSS) in the calculation of SEET which, if ordered, could require an additional refund of $22 million based on the PUCO approved SEET calculation. The IEU’s appeal also sought the inclusion of OSS as well as other items in the determination of SEET, but did not quantify the amount. Oral arguments were held in March 2012 and management is unable to predict the outcome of the appeals. If the Supreme Court of Ohio ultimately determines that additional amounts should be refunded, it could reduce future net income and cash flows and impact financial condition.

152

January 2012 – May 2016 ESP as Rejected by the PUCO

Proposed June 2012 – May 2015 ESP

153

Intervenors and the PUCO staff filed testimony in May 2012 in opposition to many aspects of OPCo’s ESP, including the proposed RSR and the two-tiered capacity pricing structure for CRES providers. Intervenors recommended a flash cut to the current RPM rate for capacity. In addition, the PUCO staff’s testimony included a proposal to increase the vegetation management base used for calculating over/under recovery on incremental vegetation spend from $21 million to $39 million, which could increase future Other Operation and Maintenance expense by $18 million on an annual basis.

Hearings on the June 2012 – May 2015 ESP were held at the PUCO during the second quarter of 2012 and oral arguments were held in July 2012. A decision from the PUCO is expected in August 2012.

2011 Ohio Distribution Base Rate Case

2009 Fuel Adjustment Clause Audit

154

2010 and 2011 Fuel Adjustment Clause Audits

Ormet Interim Arrangement

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 filing and the FAC aspect of the ESP order was upheld by the Supreme Court of Ohio. The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record a regulatory asset for the difference between the approved market price and the rate paid by Ormet. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. In November 2009, OPCo requested that the PUCO approve recovery of the deferral under the interim agreement plus a weighted average cost of capital carrying charge. The deferral amount is included in OPCo’s FAC phase-in deferral balance. In the ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related regulatory asset and requested that the PUCO prevent OPCo from collecting the Ormet-related revenues in the future. The PUCO did not take any action on this request in the 2009-2011 ESP proceeding. The intervenors raised the issue again in response to OPCo’s November 2009 filing to approve recovery of the deferral under the interim agreement. This issue remains pending before the PUCO. If OPCo is not ultimately permitted to fully recover its requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

Ohio IGCC Plant

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 scheduled to be in service in the fourth quarter of 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility. The Turk Plant is currently estimated to cost $1.8 billion, excluding AFUDC, plus an additional $120 million for transmission, excluding AFUDC. SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $120 million for transmission, excluding AFUDC. As of June 30, 2012, excluding costs attributable to its joint owners and a $62 million provision for a Texas capital costs cap, SWEPCo has capitalized approximately $1.6 billion of expenditures, including AFUDC and capitalized interest of $269 million for generation and related transmission costs of $121 million. As of June 30, 2012, the joint owners and SWEPCo have contractual construction obligations of approximately $65 million (including related transmission costs of $3 million). SWEPCo’s share of the contractual construction obligations is $48 million.

155

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. SWEPCo announced that it would continue construction of the Turk Plant and would not currently seek authority to serve Arkansas retail customers. In June 2010, in response to the Arkansas Supreme Court's decision, the APSC issued an order which reversed and set aside the previously granted CECPN. SWEPCo currently has no contracts for the 88 MW of Turk Plant output but is evaluating its options.

If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it could materially reduce future net income and cash flows and materially impact financial condition.

2012 Texas Base Rate Case

Louisiana 2010 Formula Rate Filing

In April 2010, SWEPCo filed its third formula rate plan (FRP) which decreased annual Louisiana retail rates by $3 million effective August 2010, subject to refund. In October 2010 and September 2011, consultants for the LPSC filed testimony objecting to certain components of SWEPCo’s FRP calculations. Hearings were scheduled for May 2012 but were postponed pending settlement negotiations. In the second quarter of 2012, SWEPCo recorded a reserve related to these settlement negotiations. Management believes that the reserve is adequate to pay any refunds. However, if the LPSC orders a refund greater than the booked reserve, it would reduce future net income and cash flows.

156

APCo Rate Matters

Virginia Fuel Filing

Environmental Rate Adjustment Clause (RAC)

APCo’s Filings for an IGCC Plant

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

WPCo Merger with APCo

157

PSO Rate Matters

PSO 2008 Fuel and Purchased Power

I&M Rate Matters

2011 Indiana Base Rate Case

Life Cycle Management Project

158

FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund – Affecting APCo, I&M and OPCo

In 2004, AEP eliminated transaction-based through-and-out transmission service charges and collected, at the FERC’s direction, load-based charges, referred to as RTO SECA through March 2006. Intervenors objected and 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. APCo’s, I&M’s and OPCo’s portions of recognized gross SECA revenues are as follows:

Company	(in millions)
APCo	$	70.2
I&M		41.3
OPCo		92.1

In 2006, a FERC Administrative Law Judge 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 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, I&M’s and OPCo’s portions of the provision are as follows:

Company	(in millions)
APCo	$	14.1
I&M		8.3
OPCo		18.5

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 June 30, 2012 was $32 million. APCo’s, I&M’s and OPCo’s reserve balances as of June 30, 2012 were:

Company	June 30, 2012
	(in millions)
APCo	$	10.0
I&M		5.9
OPCo		13.2

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, I&M’s and OPCo’s portions of potential refund payments and potential payments to be received are as follows:

	Potential		Potential
	Refund		Payments to
Company	Payments		be Received
	(in millions)
APCo	$	6.4	$	3.2
I&M		3.7		1.9
OPCo		8.3		4.2

159

Based on the 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 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.

Possible Termination of the Interconnection Agreement – Affecting APCo, I&M and OPCo

3. COMMITMENTS, GUARANTEES AND CONTINGENCIES

The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation cannot be predicted. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2011 Annual Report should be read in conjunction with this report.

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 credit facilities totaling $3.25 billion, under which up to $1.35 billion may be issued as letters of credit. As of June 30, 2012, the maximum future payments for letters of credit issued under the credit facilities were as follows:

Company	Amount		Maturity
	(in thousands)
I&M	$	150	March 2013
SWEPCo		4,448	March 2013

160

The Registrant Subsidiaries have $357 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $361 million as follows:

			Bilateral		Maturity of
	Pollution		Letters		Bilateral Letters
Company	Control Bonds		of Credit		of Credit
	(in thousands)
APCo	$	229,650	$	232,293	March 2013 to March 2014
I&M		77,000		77,886	March 2013
OPCo		50,000		50,575	March 2013

Guarantees of Third-Party Obligations – Affecting SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study, 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 June 30, 2012, SWEPCo has collected approximately $56 million through a rider for final mine closure and reclamation costs, of which $11 million is recorded in Other Current Liabilities, $3 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $42 million is recorded in Asset Retirement Obligations on SWEPCo’s condensed 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, I&M, OPCo, PSO and SWEPCo

Contracts

The Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of June 30, 2012, there were no material liabilities recorded for any indemnifications.

APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies related to power purchase and sale activity pursuant to the SIA. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to purchase power and sale activity pursuant to the SIA.

161

Master Lease Agreements

The Registrant Subsidiaries lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of June 30, 2012, 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 was as follows:

	Maximum
Company	Potential Loss
	(in thousands)
APCo	$	2,798
I&M		2,302
OPCo		3,187
PSO		1,036
SWEPCo		2,415

Railcar Lease

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. The maximum potential losses related to the guarantee are approximately $12 million and $13 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss.

ENVIRONMENTAL CONTINGENCIES

Carbon Dioxide Public Nuisance Claims – Affecting APCo, I&M, OPCo, PSO and SWEPCo

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO 2 emissions exacerbated the effects of Hurricane Katrina. The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims. The court granted petitions for rehearing. An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place. Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision. The petition was denied in January 2011. Plaintiffs refiled their complaint in federal district court. The court ordered all defendants to respond to the refiled complaints in October 2011. In March 2012, the court granted the defendants’ motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations. Plaintiffs appealed the decision to the Fifth Circuit Court of Appeals. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

162

Alaskan Villages’ Claims – Affecting APCo, I&M, OPCo, PSO and SWEPCo

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies. The complaint alleges that the defendants' emissions of CO 2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together. The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance. The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million. In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim. The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court. The plaintiffs appealed the decision. The court heard oral argument in November 2011. Management believes the action is without merit and will continue 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 I&M

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.

In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. I&M’s provision is approximately $10 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.

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. 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 resultant liability could be substantial.

Cook Plant Unit 1 Fire and Shutdown

163

I&M maintains insurance through NEIL. As of June 30, 2012, I&M recorded $64 million on its condensed balance sheet representing amounts under NEIL insurance policies. Through June 30, 2012, I&M received payments from NEIL of $203 million for the cost incurred to date to repair the property damage and $185 million under an accidental outage policy.

4. BENEFIT PLANS

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 plan 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.

Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost by Registrant Subsidiary for the plans for the three and six months ended June 30, 2012 and 2011:

APCo					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended June 30,				Three Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)
Service Cost	$	1,891	$	1,800	$	1,347	$	1,246
Interest Cost		7,553		8,076		4,615		4,867
Expected Return on Plan Assets		(10,486)		(10,458)		(4,188)		(4,496)
Amortization of Transition Obligation		-		-		200		287
Amortization of Prior Service Cost (Credit)		119		229		(715)		(43)
Amortization of Net Actuarial Loss		5,084		4,144		2,632		1,459
Net Periodic Benefit Cost	$	4,161	$	3,791	$	3,891	$	3,320

					Other Postretirement
	Pension Plans				Benefit Plans
	Six Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)
Service Cost	$	3,782	$	3,600	$	2,694	$	2,492
Interest Cost		15,106		16,146		9,231		9,734
Expected Return on Plan Assets		(20,972)		(20,916)		(8,376)		(8,992)
Amortization of Transition Obligation		-		-		400		573
Amortization of Prior Service Cost (Credit)		238		458		(1,431)		(86)
Amortization of Net Actuarial Loss		10,169		8,285		5,263		2,914
Net Periodic Benefit Cost	$	8,323	$	7,573	$	7,781	$	6,635

164

I&M					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended June 30,				Three Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)
Service Cost	$	2,477	$	2,365	$	1,655	$	1,529
Interest Cost		6,561		6,934		3,197		3,402
Expected Return on Plan Assets		(9,392)		(9,214)		(3,212)		(3,471)
Amortization of Transition Obligation		-		-		33		47
Amortization of Prior Service Cost (Credit)		102		186		(596)		(59)
Amortization of Net Actuarial Loss		4,393		3,538		1,763		892
Net Periodic Benefit Cost	$	4,141	$	3,809	$	2,840	$	2,340

					Other Postretirement
	Pension Plans				Benefit Plans
	Six Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)
Service Cost	$	4,954	$	4,723	$	3,310	$	3,059
Interest Cost		13,122		13,863		6,393		6,805
Expected Return on Plan Assets		(18,783)		(18,428)		(6,423)		(6,943)
Amortization of Transition Obligation		-		-		66		94
Amortization of Prior Service Cost (Credit)		204		372		(1,192)		(118)
Amortization of Net Actuarial Loss		8,785		7,072		3,525		1,783
Net Periodic Benefit Cost	$	8,282	$	7,602	$	5,679	$	4,680

OPCo					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended June 30,				Three Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)
Service Cost	$	2,751	$	2,558	$	2,187	$	1,956
Interest Cost		11,299		12,098		6,048		6,373
Expected Return on Plan Assets		(17,101)		(16,367)		(5,639)		(6,127)
Amortization of Transition Obligation		-		-		26		38
Amortization of Prior Service Cost (Credit)		185		368		(968)		(54)
Amortization of Net Actuarial Loss		7,610		6,214		3,417		1,845
Net Periodic Benefit Cost	$	4,744	$	4,871	$	5,071	$	4,031

					Other Postretirement
	Pension Plans				Benefit Plans
	Six Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)
Service Cost	$	5,502	$	5,115	$	4,374	$	3,913
Interest Cost		22,597		24,176		12,095		12,748
Expected Return on Plan Assets		(34,201)		(32,733)		(11,278)		(12,256)
Amortization of Transition Obligation		-		-		52		75
Amortization of Prior Service Cost (Credit)		371		736		(1,936)		(107)
Amortization of Net Actuarial Loss		15,220		12,414		6,834		3,649
Net Periodic Benefit Cost	$	9,489	$	9,708	$	10,141	$	8,022

165

PSO					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended June 30,				Three Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)
Service Cost	$	1,488	$	1,442	$	709	$	656
Interest Cost		3,075		3,338		1,450		1,511
Expected Return on Plan Assets		(4,504)		(4,366)		(1,481)		(1,566)
Amortization of Prior Service Credit		(237)		(239)		(269)		(19)
Amortization of Net Actuarial Loss		2,051		1,700		797		388
Net Periodic Benefit Cost	$	1,873	$	1,875	$	1,206	$	970

					Other Postretirement
	Pension Plans				Benefit Plans
	Six Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)
Service Cost	$	2,976	$	2,880	$	1,418	$	1,311
Interest Cost		6,150		6,643		2,899		3,023
Expected Return on Plan Assets		(9,008)		(8,732)		(2,961)		(3,132)
Amortization of Prior Service Credit		(474)		(475)		(539)		(38)
Amortization of Net Actuarial Loss		4,103		3,378		1,594		776
Net Periodic Benefit Cost	$	3,747	$	3,694	$	2,411	$	1,940

SWEPCo					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended June 30,				Three Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)
Service Cost	$	1,774	$	1,644	$	831	$	757
Interest Cost		3,135		3,348		1,668		1,743
Expected Return on Plan Assets		(4,716)		(4,595)		(1,698)		(1,800)
Amortization of Prior Service Cost (Credit)		(199)		(200)		(233)		64
Amortization of Net Actuarial Loss		2,082		1,700		914		446
Net Periodic Benefit Cost	$	2,076	$	1,897	$	1,482	$	1,210

					Other Postretirement
	Pension Plans				Benefit Plans
	Six Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)
Service Cost	$	3,549	$	3,286	$	1,662	$	1,514
Interest Cost		6,269		6,666		3,336		3,485
Expected Return on Plan Assets		(9,433)		(9,190)		(3,397)		(3,600)
Amortization of Prior Service Cost (Credit)		(397)		(398)		(466)		129
Amortization of Net Actuarial Loss		4,165		3,380		1,829		892
Net Periodic Benefit Cost	$	4,153	$	3,744	$	2,964	$	2,420

5. 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.

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6. 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.

167

The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of June 30, 2012 and December 31, 2011:

Notional Volume of Derivative Instruments
June 30, 2012

Primary Risk			Unit of
Exposure			Measure	APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Commodity:
	Power		MWHs		179,238		126,489		264,309		35		44
	Coal		Tons		2,745		1,842		6,337		1,915		2,857
	Natural Gas		MMBtus		12,501		8,793		18,435		78		98
	Heating Oil and
		Gasoline	Gallons		667		348		823		372		357
	Interest Rate		USD	$	36,230	$	25,484	$	53,426	$	-	$	-

Interest Rate and
	Foreign Currency		USD	$	-	$	200,000	$	-	$	-	$	-

Notional Volume of Derivative Instruments
December 31, 2011

Primary Risk			Unit of
Exposure			Measure	APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Commodity:
	Power		MWHs		169,459		109,326		229,468		39		49
	Coal		Tons		3,714		1,920		8,337		3,574		2,974
	Natural Gas		MMBtus		7,923		5,081		10,728		115		145
	Heating Oil and
		Gasoline	Gallons		1,057		525		1,254		618		569
	Interest Rate		USD	$	31,029	$	19,890	$	42,093	$	175	$	203

Interest Rate and
	Foreign Currency		USD	$	-	$	200,000	$	-	$	-	$	200,069

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 activities as “Commodity.” The Registrant Subsidiaries do not hedge all fuel price risk.

168

AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure.

At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed balance sheet at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrant Subsidiaries also apply valuation adjustments for discounting, liquidity and credit quality.

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.

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 June 30, 2012 and December 31, 2011 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:

	June 30, 2012				December 31, 2011
	Cash Collateral		Cash Collateral		Cash Collateral		Cash Collateral
	Received		Paid		Received		Paid
	Netted Against		Netted Against		Netted Against		Netted Against
	Risk Management		Risk Management		Risk Management		Risk Management
Company	Assets		Liabilities		Assets		Liabilities
	(in thousands)
APCo	$	2,664	$	19,667	$	4,291	$	28,964
I&M		1,874		13,793		2,752		18,547
OPCo		3,929		28,948		5,810		39,183
PSO		30		136		53		130
SWEPCo		37		133		66		124

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The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of June 30, 2012 and December 31, 2011:

Fair Value of Derivative Instruments
June 30, 2012

APCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (b)		Total
		(in thousands)
Current Risk Management Assets		$	252,825	$	979	$	-	$	(211,963)	$	41,841
Long-term Risk Management Assets			112,302		236		-		(67,862)		44,676
Total Assets			365,127		1,215		-		(279,825)		86,517

Current Risk Management Liabilities			243,424		3,363		-		(223,751)		23,036
Long-term Risk Management Liabilities			95,932		660		-		(73,954)		22,638
Total Liabilities			339,356		4,023		-		(297,705)		45,674

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	25,771	$	(2,808)	$	-	$	17,880	$	40,843

Fair Value of Derivative Instruments
December 31, 2011

APCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (b)		Total
		(in thousands)
Current Risk Management Assets		$	232,784	$	1,040	$	-	$	(194,179)	$	39,645
Long-term Risk Management Assets			99,751		90		-		(60,615)		39,226
Total Assets			332,535		1,130		-		(254,794)		78,871

Current Risk Management Liabilities			235,354		2,767		-		(211,515)		26,606
Long-term Risk Management Liabilities			82,058		350		-		(69,485)		12,923
Total Liabilities			317,412		3,117		-		(281,000)		39,529

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	15,123	$	(1,987)	$	-	$	26,206	$	39,342

170

Fair Value of Derivative Instruments
June 30, 2012

I&M
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (b)		Total
		(in thousands)
Current Risk Management Assets		$	186,932	$	689	$	-	$	(148,563)	$	39,058
Long-term Risk Management Assets			78,944		166		-		(47,702)		31,408
Total Assets			265,876		855		-		(196,265)		70,466

Current Risk Management Liabilities			170,637		2,326		18,095		(156,819)		34,239
Long-term Risk Management Liabilities			67,432		458		-		(51,982)		15,908
Total Liabilities			238,069		2,784		18,095		(208,801)		50,147

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	27,807	$	(1,929)	$	(18,095)	$	12,536	$	20,319

Fair Value of Derivative Instruments
December 31, 2011

I&M
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (b)		Total
		(in thousands)
Current Risk Management Assets		$	154,628	$	667	$	-	$	(123,143)	$	32,152
Long-term Risk Management Assets			68,047		58		-		(38,743)		29,362
Total Assets			222,675		725		-		(161,886)		61,514

Current Risk Management Liabilities			149,466		1,747		-		(134,233)		16,980
Long-term Risk Management Liabilities			52,441		224		10,637		(44,431)		18,871
Total Liabilities			201,907		1,971		10,637		(178,664)		35,851

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	20,768	$	(1,246)	$	(10,637)	$	16,778	$	25,663

171

Fair Value of Derivative Instruments
June 30, 2012

OPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (b)		Total
		(in thousands)
Current Risk Management Assets		$	387,633	$	1,445	$	-	$	(326,116)	$	62,962
Long-term Risk Management Assets			166,799		347		-		(100,856)		66,290
Total Assets			554,432		1,792		-		(426,972)		129,252

Current Risk Management Liabilities			373,685		4,906		-		(343,450)		35,141
Long-term Risk Management Liabilities			142,621		966		-		(109,834)		33,753
Total Liabilities			516,306		5,872		-		(453,284)		68,894

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	38,126	$	(4,080)	$	-	$	26,312	$	60,358

Fair Value of Derivative Instruments
December 31, 2011

OPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (b)		Total
		(in thousands)
Current Risk Management Assets		$	325,904	$	1,409	$	-	$	(273,020)	$	54,293
Long-term Risk Management Assets			136,519		122		-		(83,027)		53,614
Total Assets			462,423		1,531		-		(356,047)		107,907

Current Risk Management Liabilities			329,307		3,712		-		(296,458)		36,561
Long-term Risk Management Liabilities			112,454		474		-		(95,038)		17,890
Total Liabilities			441,761		4,186		-		(391,496)		54,451

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	20,662	$	(2,655)	$	-	$	35,449	$	53,456

172

Fair Value of Derivative Instruments
June 30, 2012

PSO
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (b)		Total
		(in thousands)
Current Risk Management Assets		$	4,961	$	-	$	-	$	(4,369)	$	592
Long-term Risk Management Assets			383		-		-		(252)		131
Total Assets			5,344		-		-		(4,621)		723

Current Risk Management Liabilities			8,987		120		-		(4,456)		4,651
Long-term Risk Management Liabilities			2,740		21		-		(271)		2,490
Total Liabilities			11,727		141		-		(4,727)		7,141

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(6,383)	$	(141)	$	-	$	106	$	(6,418)

Fair Value of Derivative Instruments
December 31, 2011

PSO
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (b)		Total
		(in thousands)
Current Risk Management Assets		$	6,980	$	-	$	-	$	(6,415)	$	565
Long-term Risk Management Assets			914		-		-		(600)		314
Total Assets			7,894		-		-		(7,015)		879

Current Risk Management Liabilities			7,665		107		-		(6,492)		1,280
Long-term Risk Management Liabilities			1,930		-		-		(600)		1,330
Total Liabilities			9,595		107		-		(7,092)		2,610

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(1,701)	$	(107)	$	-	$	77	$	(1,731)

173

Fair Value of Derivative Instruments
June 30, 2012

SWEPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (b)		Total
		(in thousands)
Current Risk Management Assets		$	13,572	$	-	$	-	$	(12,275)	$	1,297
Long-term Risk Management Assets			1,074		-		-		(706)		368
Total Assets			14,646		-		-		(12,981)		1,665

Current Risk Management Liabilities			20,246		115		-		(12,352)		8,009
Long-term Risk Management Liabilities			1,039		21		-		(725)		335
Total Liabilities			21,285		136		-		(13,077)		8,344

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(6,639)	$	(136)	$	-	$	96	$	(6,679)

Fair Value of Derivative Instruments
December 31, 2011

SWEPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (b)		Total
		(in thousands)
Current Risk Management Assets		$	6,327	$	-	$	3	$	(5,885)	$	445
Long-term Risk Management Assets			818		-		-		(536)		282
Total Assets			7,145		-		3		(6,421)		727

Current Risk Management Liabilities			11,062		97		19,143		(5,943)		24,359
Long-term Risk Management Liabilities			757		-		-		(536)		221
Total Liabilities			11,819		97		19,143		(6,479)		24,580

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(4,674)	$	(97)	$	(19,140)	$	58	$	(23,853)

(a)	Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."

(b)	Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." Amounts also include de-designated risk management contracts.

174

The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and six months ended June 30, 2012 and 2011:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended June 30, 2012

Location of Gain (Loss)		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	(599)	$	2,579	$	2,538	$	165	$	303
Sales to AEP Affiliates			-		-		-		-		-
Fuel and Other Consumables Used for
	Electric Generation		-		-		-		-		-
Regulatory Assets (a)			(3,796)		(2,905)		(8,895)		(757)		(364)
Regulatory Liabilities (a)			4,711		392		7,178		(26)		(27)
Total Gain (Loss) on Risk Management
	Contracts	$	316	$	66	$	821	$	(618)	$	(88)

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended June 30, 2011

Location of Gain (Loss)		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	883	$	3,702	$	11,564	$	539	$	403
Sales to AEP Affiliates			13		6		13		(1)		(1)
Fuel and Other Consumables Used for
	Electric Generation		-		-		-		-		-
Regulatory Assets (a)			(150)		(1,018)		(4,603)		644		404
Regulatory Liabilities (a)			4,142		(1,077)		-		461		692
Total Gain (Loss) on Risk Management
	Contracts	$	4,888	$	1,613	$	6,974	$	1,643	$	1,498

175

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Six Months Ended June 30, 2012

Location of Gain (Loss)		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	(926)	$	5,392	$	11,031	$	160	$	252
Sales to AEP Affiliates			-		-		-		-		-
Fuel and Other Consumables Used for
	Electric Generation		-		-		-		-		-
Regulatory Assets (a)			(7,277)		(6,015)		(12,026)		(5,958)		(7,092)
Regulatory Liabilities (a)			11,120		7,118		7,178		1		(5)
Total Gain (Loss) on Risk Management
	Contracts	$	2,917	$	6,495	$	6,183	$	(5,797)	$	(6,845)

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Six Months Ended June 30, 2011

Location of Gain (Loss)		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	2,699	$	9,117	$	22,154	$	658	$	526
Sales to AEP Affiliates			33		23		45		-		-
Fuel and Other Consumables Used for
	Electric Generation		-		-		-		-		-
Regulatory Assets (a)			223		115		(4,208)		276		2,046
Regulatory Liabilities (a)			10,896		(1,664)		(105)		853		1,032
Total Gain (Loss) on Risk Management
	Contracts	$	13,851	$	7,591	$	17,886	$	1,787	$	3,604

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

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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO and SWEPCo) for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

176

Accounting for Fair Value Hedging Strategies

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 condensed statements of income. During the three and six months ended June 30, 2012 and 2011, the Registrant Subsidiaries did not designate any fair value hedging strategies.

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and six months ended June 30, 2012 and 2011, APCo, I&M and OPCo designated power, coal and natural gas derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. During the three and six months ended June 30, 2012 and 2011, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three and six months ended June 30, 2012, I&M and SWEPCo designated interest rate derivatives as cash flow hedges. During the three and six months ended June 30, 2011, SWEPCo designated interest rate derivatives as cash flow hedges. During the six months ended June 30, 2011, APCo and PSO 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 condensed balance sheets into Depreciation and Amortization expense on the condensed 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 the three and six months ended June 30, 2012 and 2011, SWEPCo designated foreign currency derivatives as cash flow hedges.

During the three and six months ended June 30, 2012 and 2011, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

177

The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and six months ended June 30, 2012 and 2011. All amounts in the following tables are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended June 30, 2012

Commodity Contracts				APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2012				$	(2,117)	$	(1,508)	$	(3,149)	$	67	$	66
Changes in Fair Value Recognized in AOCI					(403)		(234)		(525)		(155)		(149)
Amount of (Gain) or Loss Reclassified
	from AOCI to Statement of Income/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		(3)		(9)		(24)		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		-
		Purchased Electricity for Resale			157		419		1,099		-		-
		Other Operation Expense			(14)		(8)		(19)		(9)		(7)
		Maintenance Expense			(6)		(3)		(8)		(2)		(2)
		Property, Plant and Equipment			(10)		(6)		(13)		(3)		(5)
		Regulatory Assets (a)			576		103		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-
Balance in AOCI as of June 30, 2012				$	(1,820)	$	(1,246)	$	(2,639)	$	(102)	$	(97)

Interest Rate and
Foreign Currency Contracts				APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2012				$	1,293	$	(11,320)	$	9,114	$	7,029	$	(17,365)
Changes in Fair Value Recognized in AOCI					-		(7,844)		-		-		(1)
Amount of (Gain) or Loss Reclassified
	from AOCI to Statement of Income/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		1		-		-
		Other Operation Expense			-		-		-		-		-
		Interest Expense			269		149		(341)		(190)		560
Balance in AOCI as of June 30, 2012				$	1,562	$	(19,015)	$	8,774	$	6,839	$	(16,806)

Total Contracts				APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2012				$	(824)	$	(12,828)	$	5,965	$	7,096	$	(17,299)
Changes in Fair Value Recognized in AOCI					(403)		(8,078)		(525)		(155)		(150)
Amount of (Gain) or Loss Reclassified
	from AOCI to Statement of Income/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		(3)		(9)		(24)		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		-
		Purchased Electricity for Resale			157		419		1,099		-		-
		Other Operation Expense			(14)		(8)		(19)		(9)		(7)
		Maintenance Expense			(6)		(3)		(8)		(2)		(2)
		Depreciation and Amortization
			Expense		-		-		1		-		-
		Interest Expense			269		149		(341)		(190)		560
		Property, Plant and Equipment			(10)		(6)		(13)		(3)		(5)
		Regulatory Assets (a)			576		103		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-
Balance in AOCI as of June 30, 2012				$	(258)	$	(20,261)	$	6,135	$	6,737	$	(16,903)

178

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended June 30, 2011

Commodity Contracts				APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2011				$	238	$	101	$	269	$	264	$	244
Changes in Fair Value Recognized in AOCI					(55)		(25)		(64)		(32)		(26)
Amount of (Gain) or Loss Reclassified
	from AOCI to Statement of Income/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		175		396		1,060		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		-
		Purchased Electricity for Resale			(41)		(92)		(246)		-		-
		Other Operation Expense			(31)		(28)		(60)		(34)		(33)
		Maintenance Expense			(65)		(22)		(51)		(22)		(24)
		Property, Plant and Equipment			(57)		(28)		(71)		(36)		(29)
		Regulatory Assets (a)			505		76		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-
Balance in AOCI as of June 30, 2011				$	669	$	378	$	837	$	140	$	132

Interest Rate and
Foreign Currency Contracts				APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2011				$	217	$	(8,255)	$	10,473	$	7,787	$	(4,058)
Changes in Fair Value Recognized in AOCI					-		-		-		-		794
Amount of (Gain) or Loss Reclassified
	from AOCI to Statement of Income/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		1		-		-
		Other Operation Expense			-		-		-		-		-
		Interest Expense			269		251		(341)		(189)		207
Balance in AOCI as of June 30, 2011				$	486	$	(8,004)	$	10,133	$	7,598	$	(3,057)

Total Contracts				APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2011				$	455	$	(8,154)	$	10,742	$	8,051	$	(3,814)
Changes in Fair Value Recognized in AOCI					(55)		(25)		(64)		(32)		768
Amount of (Gain) or Loss Reclassified
	from AOCI to Statement of Income/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		175		396		1,060		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		-
		Purchased Electricity for Resale			(41)		(92)		(246)		-		-
		Other Operation Expense			(31)		(28)		(60)		(34)		(33)
		Maintenance Expense			(65)		(22)		(51)		(22)		(24)
		Depreciation and Amortization
			Expense		-		-		1		-		-
		Interest Expense			269		251		(341)		(189)		207
		Property, Plant and Equipment			(57)		(28)		(71)		(36)		(29)
		Regulatory Assets (a)			505		76		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-
Balance in AOCI as of June 30, 2011				$	1,155	$	(7,626)	$	10,970	$	7,738	$	(2,925)

179

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Six Months Ended June 30, 2012

Commodity Contracts				APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2011				$	(1,309)	$	(819)	$	(1,748)	$	(69)	$	(62)
Changes in Fair Value Recognized in AOCI					(2,248)		(1,628)		(3,402)		(16)		(17)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		(3)		(9)		(24)		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		-
		Purchased Electricity for Resale			376		986		2,585		-		-
		Other Operation Expense			(16)		(10)		(24)		(11)		(9)
		Maintenance Expense			(9)		(4)		(10)		(2)		(3)
		Property, Plant and Equipment			(12)		(7)		(16)		(4)		(6)
		Regulatory Assets (a)			1,401		245		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-
Balance in AOCI as of June 30, 2012				$	(1,820)	$	(1,246)	$	(2,639)	$	(102)	$	(97)

Interest Rate and
Foreign Currency Contracts				APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2011				$	1,024	$	(14,465)	$	9,454	$	7,218	$	(15,462)
Changes in Fair Value Recognized in AOCI					-		(4,848)		-		-		(2,777)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		2		-		-
		Other Operation Expense			-		-		-		-		-
		Interest Expense			538		298		(682)		(379)		1,433
Balance in AOCI as of June 30, 2012				$	1,562	$	(19,015)	$	8,774	$	6,839	$	(16,806)

Total Contracts				APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2011				$	(285)	$	(15,284)	$	7,706	$	7,149	$	(15,524)
Changes in Fair Value Recognized in AOCI					(2,248)		(6,476)		(3,402)		(16)		(2,794)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		(3)		(9)		(24)		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		-
		Purchased Electricity for Resale			376		986		2,585		-		-
		Other Operation Expense			(16)		(10)		(24)		(11)		(9)
		Maintenance Expense			(9)		(4)		(10)		(2)		(3)
		Depreciation and Amortization
			Expense		-		-		2		-		-
		Interest Expense			538		298		(682)		(379)		1,433
		Property, Plant and Equipment			(12)		(7)		(16)		(4)		(6)
		Regulatory Assets (a)			1,401		245		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-
Balance in AOCI as of June 30, 2012				$	(258)	$	(20,261)	$	6,135	$	6,737	$	(16,903)

180

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Six Months Ended June 30, 2011

Commodity Contracts				APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2010				$	(273)	$	(178)	$	(364)	$	88	$	82
Changes in Fair Value Recognized in AOCI					123		53		143		180		168
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		171		386		1,034		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		-
		Purchased Electricity for Resale			46		102		275		-		-
		Other Operation Expense			(44)		(37)		(83)		(47)		(46)
		Maintenance Expense			(90)		(32)		(70)		(29)		(32)
		Property, Plant and Equipment			(80)		(39)		(98)		(52)		(40)
		Regulatory Assets (a)			816		123		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-
Balance in AOCI as of June 30, 2011				$	669	$	378	$	837	$	140	$	132

Interest Rate and
Foreign Currency Contracts				APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2010				$	217	$	(8,507)	$	10,813	$	8,406	$	(4,272)
Changes in Fair Value Recognized in AOCI					(373)		-		-		(476)		801
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		2		-		-
		Other Operation Expense			-		-		-		-		-
		Interest Expense			642		503		(682)		(332)		414
Balance in AOCI as of June 30, 2011				$	486	$	(8,004)	$	10,133	$	7,598	$	(3,057)

Total Contracts				APCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2010				$	(56)	$	(8,685)	$	10,449	$	8,494	$	(4,190)
Changes in Fair Value Recognized in AOCI					(250)		53		143		(296)		969
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		171		386		1,034		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		-
		Purchased Electricity for Resale			46		102		275		-		-
		Other Operation Expense			(44)		(37)		(83)		(47)		(46)
		Maintenance Expense			(90)		(32)		(70)		(29)		(32)
		Depreciation and Amortization
			Expense		-		-		2		-		-
		Interest Expense			642		503		(682)		(332)		414
		Property, Plant and Equipment			(80)		(39)		(98)		(52)		(40)
		Regulatory Assets (a)			816		123		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-
Balance in AOCI as of June 30, 2011				$	1,155	$	(7,626)	$	10,970	$	7,738	$	(2,925)

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

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Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of June 30, 2012 and December 31, 2011 were:

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
June 30, 2012

	Hedging Assets (a)				Hedging Liabilities (a)				AOCI Gain (Loss) Net of Tax
			Interest Rate				Interest Rate				Interest Rate
			and Foreign				and Foreign				and Foreign
Company	Commodity		Currency		Commodity		Currency		Commodity		Currency
	(in thousands)
APCo	$	963	$	-	$	3,771	$	-	$	(1,820)	$	1,562
I&M		677		-		2,606		18,095		(1,246)		(19,015)
OPCo		1,420		-		5,500		-		(2,639)		8,774
PSO		-		-		141		-		(102)		6,839
SWEPCo		-		-		136		-		(97)		(16,806)

	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	$	(1,543)	$	(1,021)		23
I&M		(1,057)		(938)		23
OPCo		(2,236)		1,359		23
PSO		(89)		759		18
SWEPCo		(84)		(2,369)		18

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
December 31, 2011

	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	$	431	$	-	$	2,418	$	-	$	(1,309)	$	1,024
I&M		277		-		1,523		10,637		(819)		(14,465)
OPCo		584		-		3,239		-		(1,748)		9,454
PSO		-		-		107		-		(69)		7,218
SWEPCo		-		3		97		19,143		(62)		(15,462)

	Expected to be Reclassified to
	Net Income During the Next
	Twelve Months
					Interest Rate
					and Foreign
Company	Commodity				Currency
	(in thousands)
APCo		$	(1,140	)		$	(1,052	)
I&M			(712	)			(595	)
OPCo			(1,518	)			1,359
PSO			(70	)			759
SWEPCo			(63	)			(1,864	)

(a)	Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.

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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.

Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. The following tables represent: (a) the Registrant Subsidiaries’ 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 June 30, 2012 and December 31, 2011:

	June 30, 2012
	Liabilities for		Amount of Collateral the		Amount
	Derivative Contracts		Registrant Subsidiaries		Attributable to
	with Credit		Would Have Been		RTO and ISO
Company	Downgrade Triggers		Required to Post		Activities
	(in thousands)
APCo	$	1,929	$	2,664	$	2,664
I&M		1,357		1,874		1,874
OPCo		2,845		3,928		3,928
PSO		-		1,002		269
SWEPCo		-		1,263		339

	December 31, 2011
	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	$	10,007	$	6,211	$	6,211
I&M		6,418		3,983		3,983
OPCo		13,550		8,410		8,410
PSO		-		856		414
SWEPCo		-		1,128		522

As of June 30, 2012 and December 31, 2011, the Registrant Subsidiaries were not required to post any collateral.

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In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries’ contractual netting arrangements as of June 30, 2012 and December 31, 2011:

	June 30, 2012
	Liabilities for				Additional
	Contracts with Cross				Settlement
	Default Provisions				Liability if Cross
	Prior to Contractual		Amount of Cash		Default Provision
Company	Netting Arrangements		Collateral Posted		is Triggered
	(in thousands)
APCo	$	92,276	$	2,294	$	37,533
I&M		83,000		1,613		44,495
OPCo		136,073		3,383		55,347
PSO		150		-		44
SWEPCo		189		-		55

	December 31, 2011
	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	$	76,868	$	8,107	$	27,603
I&M		59,936		5,200		28,339
OPCo		104,091		10,978		37,380
PSO		142		-		61
SWEPCo		19,322		-		19,220

7. FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

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

184

trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. 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. The main driver of the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. To a lesser extent, these contracts could be sensitive to volumetric estimates for some structured transactions. However, a significant portion of the Level 3 volumetric contractual positions have been economically hedged which greatly limits potential earnings volatility.

AEP utilizes its trustee’s external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts.

Assets in the nuclear trusts, Other Cash Deposits and Cash and Cash Equivalents are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. 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.

Fair Value Measurements of Long-term Debt

The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of June 30, 2012 and December 31, 2011 are summarized in the following table:

	June 30, 2012				December 31, 2011
Company	Book Value		Fair Value		Book Value		Fair Value
	(in thousands)
APCo	$	3,677,116	$	4,380,840	$	3,726,251	$	4,431,912
I&M		2,131,501		2,402,581		2,057,675		2,339,344
OPCo		3,860,044		4,453,479		4,054,148		4,665,739
PSO		949,897		1,138,292		947,364		1,123,306
SWEPCo		2,047,676		2,315,719		1,728,637		2,019,094

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Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

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 or its affiliates.

·	Withdrawals permitted only for payment of decommissioning costs and trust expenses.

I&M maintains trust records 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 trust funds for decommissioning nuclear facilities and for the disposal of SNF 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 gain or loss due to the adjusted cost of investment. I&M records 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 SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw decommissioning funds.

The following is a summary of nuclear trust fund investments as of June 30, 2012 and December 31, 2011:

		June 30, 2012						December 31, 2011
		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		$	15,826	$	-	$	-	$	18,229	$	-	$	-
Fixed Income Securities:
	United States Government		643,542		104,394		(640)		543,506		60,946		(547)
	Corporate Debt		44,354		5,113		(1,463)		53,979		4,932		(1,536)
	State and Local Government		256,373		698		(1,182)		329,986		(430)		(2,236)
	Subtotal Fixed Income Securities		944,269		110,205		(3,285)		927,471		65,448		(4,319)
Equity Securities - Domestic			697,407		257,975		(78,841)		646,032		214,748		(79,536)
Spent Nuclear Fuel and
	Decommissioning Trusts	$	1,657,502	$	368,180	$	(82,126)	$	1,591,732	$	280,196	$	(83,855)

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The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(in thousands)
Proceeds from Investment Sales	$	182,179	$	176,927	$	516,579	$	464,688
Purchases of Investments		192,104		186,217		544,981		492,162
Gross Realized Gains on Investment Sales		3,380		7,392		4,932		12,405
Gross Realized Losses on Investment Sales		803		4,043		2,219		9,290

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2012 was as follows:

	Fair Value
	of Debt
	Securities
	(in thousands)
Within 1 year		$	39,580
1 year – 5 years			361,676
5 years – 10 years			315,547
After 10 years			227,466
Total		$	944,269

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Fair Value Measurements of Financial Assets and Liabilities

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 June 30, 2012 and December 31, 2011. 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.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2012
APCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	5,566	$	331,309	$	27,645	$	(279,843)	$	84,677
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,186		29		(252)		963
De-designated Risk Management Contracts (b)			-		-		-		877		877
Total Risk Management Assets		$	5,566	$	332,495	$	27,674	$	(279,218)	$	86,517

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	2,784	$	321,155	$	14,810	$	(296,846)	$	41,903
Cash Flow Hedges:
	Commodity Hedges (a)		-		4,023		-		(252)		3,771
Total Risk Management Liabilities		$	2,784	$	325,178	$	14,810	$	(297,098)	$	45,674

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2011
APCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	4,680	$	302,128	$	25,423	$	(255,324)	$	76,907
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,095		-		(664)		431
De-designated Risk Management Contracts (b)			-		-		-		1,533		1,533
Total Risk Management Assets		$	4,680	$	303,223	$	25,423	$	(254,455)	$	78,871

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	2,535	$	291,194	$	23,379	$	(279,997)	$	37,111
Cash Flow Hedges:
	Commodity Hedges (a)		-		3,009		73		(664)		2,418
Total Risk Management Liabilities		$	2,535	$	294,203	$	23,452	$	(280,661)	$	39,529

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Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2012
I&M
			Level 1		Level 2		Level 3		Other		Total
Assets:			(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (f)			$	3,915	$	242,091	$	19,445	$	(196,279)	$	69,172
Cash Flow Hedges:
	Commodity Hedges (a)			-		834		21		(178)		677
De-designated Risk Management Contracts (b)				-		-		-		617		617
Total Risk Management Assets				3,915		242,925		19,466		(195,840)		70,466

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (d)				-		3,984		-		11,842		15,826
Fixed Income Securities:
	United States Government			-		643,542		-		-		643,542
	Corporate Debt			-		44,354		-		-		44,354
	State and Local Government			-		256,373		-		-		256,373
		Subtotal Fixed Income Securities		-		944,269		-		-		944,269
Equity Securities - Domestic (e)				697,407		-		-		-		697,407
Total Spent Nuclear Fuel and Decommissioning Trusts				697,407		948,253		-		11,842		1,657,502

Total Assets			$	701,322	$	1,191,178	$	19,466	$	(183,998)	$	1,727,968

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)			$	1,958	$	225,269	$	10,417	$	(208,198)	$	29,446
Cash Flow Hedges:
	Commodity Hedges (a)			-		2,784		-		(178)		2,606
	Interest Rate/Foreign Currency Hedges			-		18,095		-		-		18,095
Total Risk Management Liabilities			$	1,958	$	246,148	$	10,417	$	(208,376)	$	50,147

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		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		December 31, 2011
I&M
			Level 1		Level 2		Level 3		Other		Total
Assets:			(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (f)			$	3,001	$	203,175	$	16,305	$	(162,227)	$	60,254
Cash Flow Hedges:
	Commodity Hedges (a)			-		702		-		(425)		277
De-designated Risk Management Contracts (b)				-		-		-		983		983
Total Risk Management Assets				3,001		203,877		16,305		(161,669)		61,514

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (d)				-		5,431		-		12,798		18,229
Fixed Income Securities:
	United States Government			-		543,506		-		-		543,506
	Corporate Debt			-		53,979		-		-		53,979
	State and Local Government			-		329,986		-		-		329,986
		Subtotal Fixed Income Securities		-		927,471		-		-		927,471
Equity Securities - Domestic (e)				646,032		-		-		-		646,032
Total Spent Nuclear Fuel and Decommissioning Trusts				646,032		932,902		-		12,798		1,591,732

Total Assets			$	649,033	$	1,136,779	$	16,305	$	(148,871)	$	1,653,246

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)			$	1,626	$	185,092	$	14,995	$	(178,022)	$	23,691
Cash Flow Hedges:
	Commodity Hedges (a)			-		1,901		47		(425)		1,523
	Interest Rate/Foreign Currency Hedges			-		10,637		-		-		10,637
Total Risk Management Liabilities			$	1,626	$	197,630	$	15,042	$	(178,447)	$	35,851

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	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	June 30, 2012
OPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Other Cash Deposits (c)		$	-	$	26	$	-	$	39	$	65

Risk Management Assets
Risk Management Commodity Contracts (a) (f)			8,207		504,483		40,766		(426,917)		126,539
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,749		43		(372)		1,420
De-designated Risk Management Contracts (b)			-		-		-		1,293		1,293
Total Risk Management Assets			8,207		506,232		40,809		(425,996)		129,252

Total Assets		$	8,207	$	506,258	$	40,809	$	(425,957)	$	129,317

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	4,106	$	489,384	$	21,840	$	(451,936)	$	63,394
Cash Flow Hedges:
	Commodity Hedges (a)		-		5,872		-		(372)		5,500
Total Risk Management Liabilities		$	4,106	$	495,256	$	21,840	$	(452,308)	$	68,894

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2011
OPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Other Cash Deposits (c)		$	26	$	-	$	-	$	22	$	48

Risk Management Assets
Risk Management Commodity Contracts (a) (f)			6,339		421,249		34,425		(356,766)		105,247
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,483		-		(899)		584
De-designated Risk Management Contracts (b)			-		-		-		2,076		2,076
Total Risk Management Assets			6,339		422,732		34,425		(355,589)		107,907

Total Assets		$	6,365	$	422,732	$	34,425	$	(355,567)	$	107,955

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	3,433	$	406,259	$	31,659	$	(390,139)	$	51,212
Cash Flow Hedges:
	Commodity Hedges (a)		-		4,038		100		(899)		3,239
Total Risk Management Liabilities		$	3,433	$	410,297	$	31,759	$	(391,038)	$	54,451

191

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	June 30, 2012
PSO
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	74	$	5,245	$	-	$	(4,596)	$	723

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	40	$	11,662	$	-	$	(4,702)	$	7,000
Cash Flow Hedges:
	Commodity Hedges		-		141		-		-		141
Total Risk Management Liabilities		$	40	$	11,803	$	-	$	(4,702)	$	7,141

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2011
PSO
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	97	$	7,797	$	-	$	(7,015)	$	879

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	53	$	9,542	$	-	$	(7,092)	$	2,503
Cash Flow Hedges:
	Commodity Hedges		-		107		-		-		107
Total Risk Management Liabilities		$	53	$	9,649	$	-	$	(7,092)	$	2,610

192

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2012
SWEPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Cash and Cash Equivalents (c)		$	13,515	$	-	$	-	$	1,102	$	14,617

Risk Management Assets
Risk Management Commodity Contracts (a) (f)			93		14,480		-		(12,908)		1,665

Total Assets		$	13,608	$	14,480	$	-	$	(11,806)	$	16,282

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	50	$	21,162	$	-	$	(13,004)	$	8,208
Cash Flow Hedges:
	Commodity Hedges		-		136		-		-		136
Total Risk Management Liabilities		$	50	$	21,298	$	-	$	(13,004)	$	8,344

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2011
SWEPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	122	$	7,023	$	-	$	(6,421)	$	724
Cash Flow Hedges:
	Interest Rate/Foreign Currency Hedges		-		3		-		-		3
Total Risk Management Assets		$	122	$	7,026	$	-	$	(6,421)	$	727

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	66	$	11,753	$	-	$	(6,479)	$	5,340
Cash Flow Hedges:
	Commodity Hedges		-		97		-		-		97
	Interest Rate/Foreign Currency Hedges		-		19,143		-		-		19,143
Total Risk Management Liabilities		$	66	$	30,993	$	-	$	(6,479)	$	24,580

(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)	Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.

(d)	Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 2 amounts primarily represent investments in money market funds.

(e)	Amounts represent publicly traded equity securities and equity-based mutual funds.

(f)	Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.

There were no transfers between Level 1 and Level 2 during the three and six months ended June 30, 2012 and 2011.

193

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:

Three Months Ended June 30, 2012		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of March 31, 2012		$	7,981	$	5,614	$	11,767	$	-	$	-
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		(3,210)		(2,258)		(4,734)		-		-
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		-		1,711		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		(11)		(8)		(16)		-		-
Purchases, Issuances and Settlements (c)			4,988		3,508		7,355		-		-
Transfers into Level 3 (d) (f)			1,301		915		1,919		-		-
Transfers out of Level 3 (e) (f)			(557)		(392)		(821)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		2,372		1,670		1,788		-		-
Balance as of June 30, 2012		$	12,864	$	9,049	$	18,969	$	-	$	-

Three Months Ended June 30, 2011		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of March 31, 2011		$	5,472	$	3,209	$	6,893	$	-	$	-
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		(3,219)		(1,910)		(4,096)		-		-
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		-		1,149		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		(50)		(30)		(64)		-		-
Purchases, Issuances and Settlements (c)			4,814		2,856		6,126		-		-
Transfers into Level 3 (d) (f)			1,125		661		1,417		-		-
Transfers out of Level 3 (e) (f)			(213)		(125)		(269)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		(2,608)		(1,511)		(4,397)		-		-
Balance as of June 30, 2011		$	5,321	$	3,150	$	6,759	$	-	$	-

194

Six Months Ended June 30, 2012		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of December 31, 2011		$	1,971	$	1,263	$	2,666	$	-	$	-
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		(5,313)		(3,590)		(7,533)		-		-
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		-		7,035		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		52		34		71		-		-
Purchases, Issuances and Settlements (c)			11,499		7,811		16,397		-		-
Transfers into Level 3 (d) (f)			3,562		2,341		4,934		-		-
Transfers out of Level 3 (e) (f)			(4,676)		(3,028)		(6,388)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		5,769		4,218		1,787		-		-
Balance as of June 30, 2012		$	12,864	$	9,049	$	18,969	$	-	$	-

Six Months Ended June 30, 2011		APCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of December 31, 2010		$	5,131	$	3,108	$	6,583	$	1	$	2
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		(2,489)		(1,473)		(3,158)		-		-
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		-		4,949		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		(50)		(30)		(64)		-		-
Purchases, Issuances and Settlements (c)			3,881		2,311		4,955		-		-
Transfers into Level 3 (d) (f)			1,221		718		1,539		-		-
Transfers out of Level 3 (e) (f)			(2,853)		(1,713)		(3,648)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		480		229		(4,397)		(1)		(2)
Balance as of June 30, 2011		$	5,321	$	3,150	$	6,759	$	-	$	-

(a)	Included in revenues on the condensed 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)	Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

(g)	Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.

195

The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of June 30, 2012:

APCo	Fair Value				Valuation	Significant	Forward Price Range
	Assets		Liabilities		Technique	Unobservable Input (a)	Low		High
	(in thousands)
Energy Contracts	$	24,551	$	12,881	Discounted Cash Flow	Forward Market Price	$	10.76	$	161.12
FTRs		3,123		1,929	Discounted Cash Flow	Forward Market Price		(4.02)		10.78
Total	$	27,674	$	14,810

I&M	Fair Value				Valuation	Significant	Forward Price Range
	Assets		Liabilities		Technique	Unobservable Input (a)	Low		High
	(in thousands)
Energy Contracts	$	17,269	$	9,060	Discounted Cash Flow	Forward Market Price	$	10.76	$	161.12
FTRs		2,197		1,357	Discounted Cash Flow	Forward Market Price		(4.02)		10.78
Total	$	19,466	$	10,417

OPCo	Fair Value				Valuation	Significant	Forward Price Range
	Assets		Liabilities		Technique	Unobservable Input (a)	Low		High
	(in thousands)
Energy Contracts	$	36,203	$	18,995	Discounted Cash Flow	Forward Market Price	$	10.76	$	161.12
FTRs		4,606		2,845	Discounted Cash Flow	Forward Market Price		(4.02)		10.78
Total	$	40,809	$	21,840

(a)	Represents market prices beyond defined terms for Levels 1 and 2.

8. INCOME TAXES

AEP System Tax Allocation Agreement

The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

Federal and State Income Tax Audit Status

The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2009. The Registrant Subsidiaries completed the examination of the years 2007 and 2008 in April 2011 and settled all outstanding issues on appeal for the years 2001 through 2006 in October 2011. The settlements did not have a material impact on the Registrant Subsidiaries’ net income, cash flows or financial condition. The IRS examination of years 2009 and 2010 started in October 2011. 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 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. In March 2012, AEP settled all outstanding franchise tax issues with the State of Ohio for the years 2000 through 2009. The settlements did not have a material impact on the Registrants Subsidiaries' net income, cash flows or financial condition.

196

Uncertain Tax Positions

The reconciliation of the beginning and ending amount of unrecognized tax benefits for OPCo as a result of the franchise tax settlement with the State of Ohio is as follows:

	OPCo
	(in thousands)
Balance at December 31, 2011	$	43,565
Increase - Tax Positions Taken During a Prior Period		-
Decrease - Tax Positions Taken During a Prior Period		(23,813)
Increase - Tax Positions Taken During the Current Year		-
Decrease - Tax Positions Taken During the Current Year		-
Decrease - Settlements with Taxing Authorities		(4,742)
Decrease - Lapse of the Applicable Statute of Limitations		-
Balance at June 30, 2012	$	15,010

9. FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first six months of 2012 are shown in the tables below:

		Principal			Interest
Company	Type of Debt	Amount			Rate	Due Date
Issuances:		(in thousands)			(%)
I&M	Notes Payable	$	109,500		Variable	2016
I&M	Other Long-term Debt		20,000	(a)	Variable	2015
PSO	Notes Payable		2,395		3.00	2027
SWEPCo	Senior Unsecured Notes		275,000		3.55	2022
SWEPCo	Notes Payable		65,000		4.58	2032

(a) Consists of a $110 million three-year credit facility to be used for general corporate purposes.

			Principal		Interest
Company		Type of Debt	Amount Paid		Rate	Due Date
Retirements and			(in thousands)		(%)
	Principal Payments:
APCo		Pollution Control Bonds	$	30,000	6.05	2024
APCo		Pollution Control Bonds		19,500	5.00	2021
APCo		Land Note		12	13.718	2026
I&M		Notes Payable		13,860	5.44	2013
I&M		Notes Payable		10,590	4.00	2014
I&M		Notes Payable		11,038	Variable	2015
I&M		Notes Payable		11,971	Variable	2016
I&M		Notes Payable		8,291	2.12	2016
I&M		Other Long-term Debt		245	6.00	2025
OPCo		Pollution Control Bonds		44,500	4.85	2012
OPCo		Senior Unsecured Notes		150,000	Variable	2012
PSO		Notes Payable		32	3.00	2027
SWEPCo		Notes Payable		20,000	7.03	2012

In July 2012, I&M retired $9 million of Notes Payable related to DCC Fuel.

As of June 30, 2012, trustees held, on behalf of OPCo, $463 million of its reacquired Pollution Control Bonds.

197

Dividend Restrictions

The Registrant Subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

Federal Power Act

The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. As applicable, the Registrant Subsidiaries understand “capital account” to mean the value of the common stock.

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.

Leverage Restrictions

Pursuant to the credit agreement leverage restrictions, APCo, I&M and OPCo must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%.

Utility Money Pool – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of the subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s 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 June 30, 2012 and December 31, 2011 is included in Advances to/from Affiliates on each of the Registrant Subsidiaries’ condensed balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the six months ended June 30, 2012 are described in the following table:

									Net
									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		June 30, 2012		Limit
	(in thousands)
APCo	$	275,241	$	22,979	$	193,156	$	22,570	$	(144,415)	$	600,000
I&M		-		246,882		-		163,557		238,466		500,000
OPCo		126,975		290,356		50,680		97,642		32,671		600,000
PSO		-		120,424		-		66,085		120,424		300,000
SWEPCo		227,087		97,022		147,338		46,496		97,022		350,000

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:

	Six Months Ended June 30,
	2012		2011
Maximum Interest Rate	0.56	%	0.56	%
Minimum Interest Rate	0.45	%	0.06	%

198

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the six months ended June 30, 2012 and 2011 are summarized for all Registrant Subsidiaries in the following table:

	Average Interest Rate				Average Interest Rate
	for Funds Borrowed				for Funds Loaned
	from Utility Money Pool for				to Utility Money Pool for
	Six Months Ended June 30,				Six Months Ended June 30,
Company	2012		2011		2012		2011
APCo	0.49	%	0.38	%	0.49	%	0.27	%
I&M	-	%	0.44	%	0.49	%	0.23	%
OPCo	0.47	%	0.45	%	0.51	%	0.25	%
PSO	-	%	0.41	%	0.48	%	0.19	%
SWEPCo	0.53	%	0.25	%	0.48	%	0.33	%

Short-term Debt

The Registrant Subsidiaries’ outstanding short-term debt was as follows:

June 30, 2012

December 31, 2011

Outstanding

Interest

Outstanding

Interest

Company

Type of Debt

Amount

Rate (a)

Amount

Rate (a)

(in thousands)

SWEPCo

Line of Credit – Sabine

17,016

1.79

(a) Weighted average weight.

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 3.

Sale of Receivables – AEP Credit

Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ condensed income statements. The Registrant Subsidiaries manage and service their customer accounts receivable sold.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of June 30, 2012 and December 31, 2011 was as follows:

	June 30,		December 31,
Company	2012		2011
	(in thousands)
APCo	$	125,942	$	121,605
I&M		126,865		121,597
OPCo		319,996		346,695
PSO		122,215		123,172
SWEPCo		158,924		140,440

199

The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:

	Three Months Ended June 30,				Six Months Ended June 30,
Company	2012		2011		2012		2011
	(in thousands)
APCo	$	1,556	$	2,239	$	3,686	$	4,814
I&M		1,521		1,508		3,064		3,135
OPCo		4,622		4,405		10,538		8,440
PSO		1,825		1,483		3,557		2,717
SWEPCo		1,548		1,303		2,934		2,403

The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:

	Three Months Ended June 30,				Six Months Ended June 30,
Company	2012		2011		2012		2011
	(in thousands)
APCo	$	295,879	$	284,715	$	642,405	$	650,924
I&M		320,415		315,551		659,996		666,572
OPCo		656,737		831,835		1,494,634		1,742,873
PSO		303,729		317,060		576,524		585,629
SWEPCo		379,114		375,903		700,722		690,027

10. SUSTAINABLE COST REDUCTIONS

In April 2012, management initiated a process to identify employee repositioning opportunities and efficiencies that will result in sustainable cost savings. The process will result in involuntary severances and is expected to be completed by the end of 2012. The severance program provides two weeks of base pay for every year of service along with other severance benefits.

The Registrant Subsidiaries recorded a charge to expense in the second quarter of 2012 related to the sustainable cost reductions initiative.

		Expense	Incurred for					Remaining
		Allocation from	Registrant					Balance at
	AEPSC		Subsidiaries		Settled		June 30, 2012
	(in thousands)
APCo	$	2,010	$	730	$	(2,035)	$	705
I&M		1,204		71		(1,088)		187
OPCo		3,005		442		(3,260)		187
PSO		1,080		3		(1,083)		-
SWEPCo		1,324		533		(1,432)		425

These expenses relate primarily to severance benefits. They are included primarily in Other Operation on the income statement and Other Current Liabilities on the balance sheet. At this time, management is unable to estimate the total amount to be incurred in future periods related to this initiative or to quantify the effects on future earnings, cash flows and financial condition.

200

COMBINED MANAGEMENT’S NARRATIVE DISCUSSION

AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the Registrant Subsidiaries’ management’s discussion and analysis. The information in this section completes the information necessary for management’s discussion and analysis of financial condition and net income and is meant to be read with (a) Management’s Narrative Discussion and Analysis of Results of Operations, (b) financial statements, (c) footnotes and (d) the schedules of each individual registrant. The Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries section of the 2011 Annual Report should also be read in conjunction with this report.

EXECUTIVE OVERVIEW

Sustainable Cost Reductions

In April 2012, management initiated a process to identify employee repositioning opportunities and efficiencies that will result in sustainable cost savings. A charge to expense of $13 million was recorded in the second quarter of 2012 related to the elimination of approximately 170 positions across the AEP System in the first phase of this process. In May 2012, management selected one consulting firm to conduct an organizational and process optimization evaluation and a second consulting firm to evaluate current employee benefit programs. The second phase of this process is expected to be completed by the end of 2012 with additional cost reductions.

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, new proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.

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 including the items discussed below and reductions of CO 2 emissions to address concerns about global climate change. AEP, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court. The U.S. House of Representatives passed legislation called the Transparency in Regulatory Analysis of Impacts on the Nation (the TRAIN Act) that would delay implementation of certain Federal EPA rules to facilitate a comprehensive analysis of their impacts. The Senate is considering similar legislation. Management believes that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

See a complete discussion of these matters in the “Environmental Issues” section of “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries” in the 2011 Annual Report. Management will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. The Registrant Subsidiaries should be able to recover certain of these expenditures through market prices in deregulated jurisdictions. If not, the costs of environmental compliance could reduce future net income and cash flows and impact financial condition.

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Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System. Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. As of June 30, 2012, the AEP System had a total generating capacity of 37,035 MWs, of which 23,900 MWs are coal-fired. Management continues to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on the coal-fired generating facilities. For the Registrant Subsidiaries, management’s current ranges of estimates of environmental investments to comply with these proposed requirements are listed below:

	2012 to 2020
	Estimated Environmental Investment
Company	Low		High
	(in millions)
APCo	$	415	$	515
I&M		1,490		1,710
OPCo		1,260		1,510
PSO		430		530
SWEPCo		1,250		1,450

For APCo and OPCo, the projected environmental investments above include the conversion of 470 MWs and 585 MWs, respectively, of coal generation to natural gas-fired generation.

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

Subject to the factors listed above and based upon continuing evaluation, management has given notice to the applicable RTOs of the intent to retire the following plants or units of plants before or during 2016:

		Generating
Company	Plant Name and Unit	Capacity
		(in MWs)
APCo	Clinch River Plant, Unit 3		235
APCo	Glen Lyn Plant		335
APCo	Kanawha River Plant		400
APCo/OPCo	Philip Sporn Plant, Units 1-4		600
I&M	Tanners Creek Plant, Units 1-3		495
OPCo	Conesville Plant, Unit 3		165
OPCo	Kammer Plant		630
OPCo	Muskingum River Plant, Units 1-4		840
OPCo	Picway Plant		100
SWEPCo	Welsh Plant, Unit 2		528

Duke Energy Corporation, the operator of W. C. Beckjord Generating Station, has announced its intent to close the facility in 2015. OPCo owns 12.5% (54 MWs) of one unit at that station.

Management is monitoring the potential impact that the proposed corporate separation of OPCo’s generation assets and the proposed termination of the Interconnection Agreement could have on the recoverability of OPCo’s generation assets.

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In April 2012, management reached an agreement in principle with the Federal EPA, the State of Oklahoma and other parties to retire one coal-fired unit of PSO’s Northeastern Station no later than 2016, install emission controls on the second coal-fired Northeastern unit in 2016 and retire the second unit no later than 2026. These two coal-fired units have a combined generating capacity of 930 MWs. The parties are working toward a final settlement agreement. Management expects this agreement, if approved, to reduce PSO’s environmental investments for 2012 to 2020 by approximately $400 million to the amounts shown in the table above.

Plans for and the timing of conversion of some of the coal units to natural gas, installing emission control equipment on other units and closure of existing units will be impacted by changes in emission requirements and demand for power. To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows.

Environmental Control Applications

Rockport Plant

Flint Creek Plant

Clean Air Act Requirements

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for SO 2 and NO x emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states. As a result, depending on how the states decide to implement the CAVR, compliance with the CSAPR requirements may be sufficient to satisfy CAVR's BART requirements without the need for additional unit-specific controls.

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 facilities as a result of those evaluations. Management cannot currently predict the nature, stringency or timing of those requirements.

Notable developments in significant CAA regulatory requirements affecting the Registrant Subsidiaries’ operations are discussed in the following sections.

Cross-State Air Pollution Rule (CSAPR)

In August 2011, the Federal EPA issued CSAPR. Certain revisions to the rule were finalized in March 2012. CSAPR relies on newly-created SO 2 and NO x allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states. Interstate trading of allowances is allowed on a restricted sub-regional basis beginning in 2012. Arkansas and Louisiana are subject only to the seasonal NO x program in the rule. Texas is subject to the annual programs for SO 2 and NO x in addition to the seasonal NO x program. The annual SO 2 allowance budgets in Indiana, Ohio and West Virginia have been reduced significantly in the rule. Numerous affected entities, states and other parties filed petitions to review the CSAPR in the United States Court of Appeals for the District of Columbia Circuit. Several of the petitioners filed motions to stay the implementation of the rule pending judicial review. In December 2011, the court granted the motions for stay. Oral argument was heard in April 2012. A supplemental rule includes Oklahoma in the seasonal NO x program. The supplemental rule was finalized in December 2011, with an increased NO x emission budget for the 2012 compliance year. A separate appeal of the supplemental rule has been filed, but is being held in abeyance until the court issues a decision in the main CSAPR appeal. The Federal EPA issued a final Error Corrections Rule and further CSAPR revisions in 2012 to make corrections to state budgets and unit allocations and to remove the restrictions on interstate trading in the first phase of CSAPR. Challenges to these rules have also been filed, but are being held in abeyance pending a decision in the main appeal.

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

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

In February 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants. The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal, on a site-wide 30-day rolling average basis. In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans. The effective date of the final rule was April 16, 2012 and compliance is required within three years. The AEP System is participating through various organizations in the petitions for administrative reconsideration and judicial review that have been filed. In July 2012, the Federal EPA issued a letter announcing that it will grant petitions for administrative reconsideration of certain issues related to the new source standards, including measurement issues and application of variability factors that may have an impact on the level of the standards. The letter also announced a three-month stay in the effective date of the new source standards. It is uncertain whether any of the information generated during the reconsideration process will affect the standards for existing sources.

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The final rule contains a slightly less stringent PM limit for existing sources than the original proposal and allows operators to exclude periods of startup and shutdown from the emissions averaging periods. The compliance time frame remains a serious concern. A one-year administrative extension may be available if the extension is necessary for the installation of controls or to avoid a serious reliability problem. In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades. Management is concerned about the availability of compliance extensions and the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines. The AEP System is participating in petitions for review filed in the United States Court of Appeals for the District of Columbia Circuit by several organizations in which the Registrant Subsidiaries are members. Certain issues related to the standards for new coal-fired units have been severed from the main case and will be considered by the court on an expedited basis. The Federal EPA’s grant of certain reconsideration petitions may alter this schedule.

Regional Haze – Affecting PSO

In March 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze SIP submitted by the State of Oklahoma through the Department of Environmental Quality. The Federal EPA proposed to approve all of the NO x control measures in the SIP and disapprove the SO 2 control measures for six electric generating units, including two units owned by PSO. The Federal EPA proposed a FIP that would require these units to install technology capable of reducing SO 2 emissions to 0.06 pounds per million British thermal units within three years of the effective date of the FIP. PSO submitted comments on the proposed action demonstrating that the cost-effectiveness calculations performed by the Federal EPA were unsound, challenging the period for compliance with the final rule and showing that the visibility improvements secured by the proposed SIP were significant and cost-effective. The Federal EPA finalized the FIP in December 2011 that mirrored the proposed rule but established a five-year compliance schedule. PSO filed a petition for review of the FIP in the Tenth Circuit Court of Appeals and engaged in settlement discussions with the Federal EPA, the State of Oklahoma and other parties. In April 2012, an agreement in principle was reached that would provide for submission of a revised Regional Haze SIP requiring the retirement of one coal-fired unit of PSO’s Northeastern Station no later than 2016, installation of emission controls on the second coal-fired Northeastern unit in 2016 and retirement of the second unit no later than 2026. The parties are working toward finalizing a settlement agreement which is intended to allow PSO to meet its compliance obligations under the regional haze and HAPs rules.

CO 2 Regulation

In March 2012, the Federal EPA issued a proposal to regulate CO 2 emissions from new fossil fuel-fired electricity generating units. The proposed rule establishes a new source performance standard of 1,000 pounds of CO 2 per megawatt hour of electricity generated, a rate that most natural gas combined cycle units can meet, but that is substantially below the emission rate of a new pulverized coal generator or an integrated gas combined cycle unit that uses coal for fuel. As proposed, the rule does not apply to new gas-fired stationary combustion turbines used as peaking units, does not apply to existing, modified or reconstructed sources, and does not apply to units whose CO 2 emission rate increases as a result of the addition of pollution control equipment to control criteria or HAPs. The rule is not anticipated to have a significant immediate impact on the AEP System since it does not apply to existing units or units that have already commenced construction, like SWEPCo’s Turk Plant. The comment period closed in June 2012. New Source Performance Standards affect units that have not yet received permits, but complete the permitting process while the proposal is pending. The standards have been challenged in the United States Court of Appeals for the District of Columbia Circuit. Management cannot predict the outcome of that litigation.

In June 2012, the United States Court of Appeals for the District of Columbia Circuit issued a decision upholding, in all material respects, the Federal EPA’s endangerment finding, its regulatory program for CO 2 emissions from new motor vehicles and its plan to phase in regulation of CO 2 emissions from stationary source under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs. The Federal EPA also finalized a rule in June 2012 that retains the current thresholds for permitting stationary sources under the PSD and Title V operating permit programs at 100,000 tons per year for new sources and 75,000 tons per year for modified sources. The Federal EPA also confirmed that it will re-evaluate these thresholds during its five-year review in 2016. The AEP System’s generating units are large sources of CO 2 emissions and management will continue to evaluate the permitting obligations in light of these thresholds.

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

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

Clean Water Act Regulations

In April 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water. Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress. The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement. Compliance with this standard is required within eight years of the effective date of the final rule. The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment. The proposed entrainment standard for new units at existing facilities requires either intake flows commensurate with closed cycle cooling or achieving entrainment reductions equivalent to 90% or greater of the reductions that could be achieved with closed cycle cooling. Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority. Management is evaluating the proposal and engaged in the collection of additional information regarding the feasibility of implementing this proposal at the AEP System’s facilities. In June 2012, the Federal EPA issued additional Notices of Data Availability and requested public comments. Management submitted comments in July 2012. Issuance of a final rule is not expected until July 2013. Management is preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.

Global Warming

National public policy makers and regulators in the 10 states the Registrant Subsidiaries serve have conflicting views on 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.

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 Michigan, Ohio, Texas and Virginia, passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements. Management is taking steps to comply with these requirements.

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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 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 3.

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 reduce future net income and cash flows and impact financial condition.

For additional information on global warming, other environmental issues and the actions management is taking to address potential impacts, see Part I of the 2011 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters” and “Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries.”

ACCOUNTING PRONOUNCEMENTS

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, management cannot determine the impact on the reporting of the Registrant Subsidiaries’ operations and financial position that may result from any such future changes. The FASB is currently working on several projects including revenue recognition, financial instruments, leases, insurance, hedge accounting and consolidation policy. 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.

Item 4. Controls and Procedures

During the second quarter of 2012, management, including the principal executive officer and principal financial officer of each of AEP, APCo, I&M, OPCo, PSO and SWEPCo (collectively, the Registrants), evaluated the Registrants’ 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 SEC’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 the Registrants’ 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 June 30, 2012, 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 was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the second quarter of 2012 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 3 incorporated herein by reference.

Item 1A. Risk Factors

The Annual Report on Form 10-K for the year ended December 31, 2011 includes a detailed discussion of risk factors. The information presented below amends and restates, in their entirety, certain of those risk factors that have been updated and should be read in conjunction with the risk factors and information disclosed in the 2011 Annual Report on Form 10-K.

GENERAL RISKS OF OUR REGULATED OPERATIONS

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

SWEPCo is currently constructing the Turk Plant in Arkansas and holds a 73% ownership interest in the planned 600 MW coal-fired generating facility. 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. SWEPCo announced that it would continue construction of the Turk Plant and would not currently seek authority to serve Arkansas retail customers. In June 2010, the APSC reversed and set aside the previously granted CECPN. SWEPCo currently has no contracts for the 88 MW of Turk Plant output but is evaluating its options. If SWEPCo cannot recover all of its investment and expenses related to the Turk Plant, it could materially reduce future net income and cash flows and materially impact financial condition.

Rate and other recovery in Ohio for distribution service may not provide full recovery of costs. – Affecting AEP and OPCo

In February 2011, OPCo filed with the PUCO for an annual increase in distribution rates. In December 2011, a stipulation was approved by the PUCO providing recovery of certain distribution regulatory assets. Because the February 2012 PUCO order rejected the ESP modified stipulation, collection of the Distribution Investment Rider (DIR) terminated. In March 2012, OPCo filed an application with the PUCO to approve an ESP for the period June 2012 through May 2015, which includes a request for a new DIR. If OPCo is not ultimately permitted to fully recover its costs, it would reduce future net income and cash flows and impact financial condition.

Rate recovery in Ohio for generation service may not provide full recovery of costs. – Affecting AEP and OPCo

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Rate recovery approved in Ohio may have to be returned and/or may not provide full recovery of costs. – Affecting AEP and OPCo

The PUCO issued an order in March 2009 that modified and approved the ESP which established rates through 2011. The ESP order generally authorized rate increases during the ESP period, subject to caps that limit the rate increases, and also provided a fuel adjustment clause for the three-year period of the ESP. The recovery under the fuel adjustment clause included 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. In January 2011, the PUCO issued an order on the 2009 SEET filing, which is currently under appeal at the Supreme Court of Ohio. In July 2011, OPCo filed its 2010 SEET filing with the PUCO. OPCo is required to file its 2011 SEET filing with the PUCO in 2012 on a separate CSPCo and OPCo company basis. If the PUCO and/or the Supreme Court of Ohio reverses all or part of the rate recovery or if deferred fuel costs are not recovered for other reasons, it could reduce future net income and cash flows and impact financial condition.

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

In January 2012, the PUCO ordered that proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. Further, the January 2012 PUCO order stated that a consultant be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. Management is unable to predict the outcome of the consultant’s recommendation. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultants’ review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.

The PUCO-selected outside consultant issued its results of the 2010 and 2011 FAC audit. The audit reports included recommendations that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes. If the PUCO orders result in a reduction to the FAC deferral, it would reduce future net income and cash flows and impact financial condition.

Request for rate recovery in Indiana may not be approved in its entirety. – Affecting AEP and I&M

In September 2011, I&M filed a request with the IURC for annual increases in Indiana base rates. If the IURC denies all or part of the requested rate recovery, it could reduce future net income and cash flows.

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

In July 2012, SWEPCo filed a request with the PUCT for an annual increase in Texas base rates. If the PUCT denies all or part of the requested rate recovery, it could reduce future net income and cash flows.

RISKS RELATING TO STATE RESTRUCTURING

We are unable to fully predict the effects of corporate separation in Ohio and becoming subject to market forces. – Affecting AEP and OPCo

In March 2012, OPCo filed a corporate separation plan with the PUCO for its generation assets. Additional filings at the FERC and other state commissions related to corporate separation are expected to be filed in the future. Our results of operations related to generation will be determined by our ability to sell power and capacity at a profit at rates determined by the prevailing market. If we are unable to sell power and capacity at a profit, it could reduce future net income and cash flows and impact financial condition. We can give no assurance that the PUCO, the FERC or other state commissions will not impose material adverse terms as a condition to approving our corporate separation. Additionally, certain of our generation units may no longer be cost effective and may be retired prior to the end of their anticipated useful life. This could result in material impairments.

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We are unable to predict the consequences of terminating the Interconnection Agreement. – Affecting AEP, APCo, I&M and OPCo

The proposed corporate separation plans of OPCo’s generation assets will require us to either terminate or substantially alter the Interconnection Agreement. The Interconnection Agreement permits AEP East companies to share costs and benefits associated with their generating plants on a cost basis. It is unknown at this time whether the Interconnection Agreement 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. If the Interconnection Agreement is terminated without any subsequent agreements between some or all of the parties, surplus members will no longer automatically sell to deficit members, and they may not be able to otherwise sell that surplus in amounts or at rates equal to what they obtained under the Interconnection Agreement. Conversely, deficit members will no longer automatically purchase from surplus members, and they may not be able to otherwise purchase in amounts or at rates equal to what they obtained under the Interconnection Agreement. The possible loss of these sales by the surplus members and the potential increase in costs for the deficit members could reduce future net income and cash flows. We intend to file an application to terminate the Interconnection Agreement with the FERC in the future. We can give no assurance that the FERC will not impose material adverse terms as a condition to approving these arrangements.

RISKS RELATED TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER

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

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was signed into law. The federal legislation was enacted to reform financial markets and significantly alter how over-the-counter (OTC) derivatives are regulated. The law increased regulatory oversight of OTC energy derivatives, including: (a) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the Commodity Futures Trading Commission (CFTC), (b) imposing new and potentially higher capital and margin requirements and (c) authorizing the establishment of overall volume and position limits. Regulations recently issued by CFTC exempt end users of energy commodities from being required to clear OTC derivatives if they are hedge commercial risk and satisfy certain other requirements, which could reduce the effect of the law's clearing requirements on our hedging activity. The CFTC has also recently issued other rules that further define the OTC derivative products and entities subject to additional regulatory oversight. These requirements could subject us to additional regulatory oversight related to our OTC derivative transactions, cause our OTC derivative transactions to be more costly and have an 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.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

NONE

Item 4. Mine Safety Disclosures

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, and OPCo, through its ownership of Conesville Coal Preparation Company (CCPC) and 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 and its related regulations require companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. Exhibit 95 contains the notices of violation and proposed assessments received by DHLC, CCPC and Conner Run under the Mine Act for the quarter ended June 30, 2012.

Item 5. Other Information

NONE

Item 6. Exhibits

10 – AEP System Senior Officer Incentive Plan Amended and Restated as of February 28, 2012

12 – Computation of Consolidated Ratio of Earnings to Fixed Charges

31(a) – Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31(b) – Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32(a) – Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

32(b) – Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code

95 – Mine Safety Disclosures

101.INS – XBRL Instance Document

101.SCH – XBRL Taxonomy Extension Schema

101.CAL – XBRL Taxonomy Extension Calculation Linkbase

101.DEF – XBRL Taxonomy Extension Definition Linkbase

101.LAB – XBRL Taxonomy Extension Label Linkbase

101.PRE – XBRL Taxonomy Extension Presentation Linkbase

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SIGNATURE

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

AMERICAN ELECTRIC POWER COMPANY, INC.

By: /s/ Joseph M. Buonaiuto

Joseph M. Buonaiuto

Controller and Chief Accounting Officer

APPALACHIAN POWER COMPANY

INDIANA MICHIGAN POWER COMPANY

OHIO POWER COMPANY

PUBLIC SERVICE COMPANY OF OKLAHOMA

SOUTHWESTERN ELECTRIC POWER COMPANY

By: /s/ Joseph M. Buonaiuto

Joseph M. Buonaiuto

Controller and Chief Accounting Officer

Date: July 27, 2012

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Exhibit 10

AMERICAN ELECTRIC POWER COMPANY, INC.

SENIOR OFFICER INCENTIVE PLAN

ARTICLE I

INTRODUCTION AND PURPOSE

American Electric Power Company, Inc. previously adopted the American Electric Power System Senior Officer Annual Incentive Compensation Plan (the “Incentive Plan”) effective January 1, 1997. This document amends and restates the Incentive Plan effective as of February 28, 2012 (the date the changes made by this Incentive Plan by resolution of the Human Resources Committee were ratified by Board of Directors of the Company) (the “Effective Date”). Any changes made to the Incentive Plan by this document shall not affect Awards granted prior to the Effective Date. Grants of Awards under the Incentive Plan, as amended hereby, may be made on or after the Effective Date.

ARTICLE II

DEFINITIONS

For purposes of the Plan, the following terms shall have the following meanings:

(a) “Award” means an incentive award, which entitles a Participant to receive a payment from the Company or a Subsidiary pursuant to Article IV, subject to such terms and conditions as the Committee may prescribe.

(b) “Board” means the Board of Directors of the Company.

(c) “Code” means the Internal Revenue Code of 1986, as amended from time to time, or any successor statute, and applicable regulations.

(d) “Committee” means the Human Resources Committee of the Board or such other committee or subcommittee as may be designated by the Board to oversee the Company’s executive compensation; provided that any such Committee shall consist of two or more persons, each of whom is an “outside director” within the meaning of Code Section 162(m).

(e) “Company” means American Electric Power Company, Inc., a New York corporation.

(f) “Covered Employee” means a Participant who the Committee determines meets the definition of a Covered Employee as defined in Code Section 162(m)(3).

(g) “Effective Date” is defined in Article I.

(h) “Participant” means a corporate officer of the Company or of a Subsidiary who is granted an Award by the Committee.

(i) “Performance-Based Compensation” means an Award that is intended to constitute “remuneration payable solely on account of the attainment of one or more or performance goals” or “qualified performance-based compensation” within the meaning of Section 162(m)(4)(C) of the Code and the regulations promulgated thereunder.

(j) “Performance Objective” is defined in Section 4.2.

(k) “Performance Period” is defined in Section 4.2.

(l) “Plan” means the American Electric Power System Senior Officer Incentive Plan, as set forth herein and as amended from time to time.

(m) “Subsidiary” means any corporation (other than the Company), limited liability company, partnership or other business organization of which a majority of the outstanding voting stock or voting power is beneficially owned directly or indirectly by the Company.

ARTICLE III

ELIGIBILITY

Awards may be granted to any Participant from time to time by the Committee. The Committee shall determine the terms, conditions, and limitations applicable to each Award consistent with the Plan. Designation by the Committee as a Participant for an Award in one period shall not confer on such Participant the right to participate in the Plan for any other period.

ARTICLE IV

INCENTIVE AWARDS

Section 4.1. General.

(a)

Awards may be granted to a Participant in such amounts and upon such terms, and at any time and from time to time, as shall be determined by the Committee. The Committee, at the time an Award is made, shall specify the terms and conditions which govern the Award, which terms and conditions shall prescribe that the Award shall be earned only upon, and to the extent that, Performance Objectives as described in Section 4.2, are satisfied within a designated time.

(b)	Different terms and conditions may be established by the Committee for different Awards and for different Participants with respect to the same or different Performance Periods.

Section 4.2. Performance Objectives. The vesting and payment of Awards shall be contingent upon the degree of attainment of such performance goal(s) (the “Performance Objectives”) over such period (the “Performance Period”) as shall be specified by the Committee at the time the Award is granted. Performance Objectives will be established prior to or within the first ninety (90) days of each Performance Period (or within the first 25% of the Performance Period, if the Performance Period is shorter than 360 days).

The criteria for developing the Performance Objectives upon which payment or vesting of an Award intended to qualify for the exemption under Code Section 162(m) may be based shall be limited to one or more of the following, as determined by the Committee: (i) earnings measures: primary earnings per share; fully diluted earnings per share; net income; pre-tax income; operating income; earnings before interest, taxes, depreciation and amortization; net operating profits after taxes; income before income taxes, minority interest and equity earnings; income before discontinued operations, extraordinary items and cumulative effect of accounting changes, or any combination thereof; (ii) expense control: operations & maintenance expense; total expenditures; expense ratios; and expense reduction; (iii) customer measures: customer satisfaction; service cost; service levels; responsiveness; bad debt collections or losses; and reliability—such as outage frequency, outage duration, and frequency of momentary outages; (iv) safety measures: recordable case rate; severity rate; and vehicle accident rate; (v) diversity measures: minority placement rate and utilization; (vi) environmental measures: emissions; project completion milestones; regulatory/legislative/cost recovery goals; and notices of violation; (vii) revenue measures: revenue and margin; (viii) shareholder return measures: total shareholder return; economic value added; cumulative shareholder value added; return on equity; return on capital; return on assets; dividend payout ratio and cash flow(s)—such as operating cash flows, free cash flow, discounted cash flow return on investment and cash flow in excess of cost of capital or any combination thereof; (ix) valuation measures: stock price increase; price to book value ratio; and price to earnings ratio; (x) capital and risk measures: debt to equity ratio and dividend payout as percentage of net income; (xi) employee satisfaction; (xii) project measures: completion of key milestones; (xiii) production measures: generating capacity factor; performance against the Institute of Nuclear Power Operation index; generating equivalent availability; heat rates and production cost. The targeted level or levels of performance with respect to such business criteria may be established at such levels and in such terms as the Committee may determine, in its discretion, including in absolute terms, as a goal relative to performance in prior periods (e.g., earnings growth), or as a goal compared to the performance of one or more comparable companies or an index covering multiple companies.

Performance Objectives may relate to attainment of specified objectives by the Participant or by the Company or one or more Subsidiaries, including a division or a department of the Company or of one or more Subsidiaries.

Section 4.3. Payment of Awards. An Award shall not become payable unless, after the expiration of the Performance Period, the Committee has certified either that the Performance Objectives with respect to such Award have been satisfied or the level of attainment of each Performance Objective. Unless otherwise expressly stated in the terms and conditions of a particular Award, the Committee retains the power, authority and discretion to reduce or eliminate, but not to increase, the amount calculated as payable under the terms of any Award in order to reflect other performance criteria. Payment of such Awards that have been certified shall be made to Participants in a single lump sum in cash at such time determined by the Committee, and generally no later than two and one-half months after the end of the Performance Period; provided that unless otherwise clearly specified in the terms and conditions of a particular Award, payment shall be made no later than 2-1/2 months after the end of the calendar year during which the Award became vested, or as soon as practical thereafter. In no event shall any Participant receive an Award payment or payments in any fiscal year that exceeds the lesser of (i) $6,000,000 or (ii) 400% of the Participant’s base salary (prior to any salary reduction or deferral elections) as of the date of grant of the Award.

Section 4.4. Recoupment of Incentive Compensation. Each Participant who is granted an Award shall reimburse the amount awarded, earned, received or paid under such Award if the Committee, in its discretion, determines that: (i) the Award or any compensation resulting from it was predicated upon the achievement of financial or other results that were subsequently materially restated or corrected, and (ii) the Participant engaged in misconduct that caused or partially caused the need for the restatement or correction, and (iii) a lower payment would have been made to the Participant based upon the restated or corrected financial results. If and to the extent that the Committee, in its sole discretion, determines that the conditions set forth in (i) through (iii) have been met and such reimbursement is warranted by the facts and circumstances of the particular case or if the applicable legal requirements impose more stringent requirements on the Company or any of its Subsidiaries to obtain reimbursement of such compensation, then the Participant will be required to reimburse Company or its Subsidiaries, as applicable, for the value of such compensation paid to that Participant. The Company or its Subsidiaries, as applicable, also may retain any deferred compensation previously credited to the Participant and not paid, provided that the Company or its Subsidiaries, as applicable, will retain such deferred compensation only if, when and to the extent that it otherwise becomes payable to the Participant. This right to reimbursement is in addition to, and not in substitution for, any and all other rights the Company and its Subsidiaries might have to pursue reimbursement or such other remedies against an employee for misconduct in the course of employment or otherwise based on applicable legal considerations, all of which are expressly retained by the Company and its Subsidiaries.

ARTICLE V

ADMINISTRATION

The Plan shall be administered by the Committee. The Committee shall have all of the powers necessary to enable it to properly carry out its duties under the Plan. Not in limitation of the foregoing, the Committee shall have the power and discretion to construe and interpret the Plan and to determine all questions that shall arise thereunder. The Committee shall have such other and further specified duties, powers, authority and discretion as are elsewhere in the Plan either expressly or by necessary implication conferred upon it. The Committee may appoint such agents, who need not be members of the Committee, as it may deem necessary for the effective performance of its duties, and may delegate to such agents such powers and duties as the Committee may deem expedient or appropriate that are not inconsistent with the intent of the Plan to the fullest extent permitted under applicable law. The decision of the Committee or any agent of the Committee upon all matters within the scope of its authority shall be final and conclusive on all persons.

ARTICLE VI

AMENDMENT AND TERMINATION

Section 6.1. Amendment of Plan. The Company has the right, at any time and from time to time, to amend in whole or in part any of the terms and provisions of the Plan to the extent permitted by law for whatever reason(s) the Company may deem appropriate; provided, however, that any such amendment which requires approval of the

Company’s shareholders in order to maintain the qualification of Awards as performance-based compensation pursuant to Code Section 162(m) (4)(C) shall not be made without such approval.

Section 6.2. Termination of Plan. The Company expressly reserves the right, at any time, to suspend or terminate the Plan to the extent permitted by law for whatever reason(s) the Company may deem appropriate, including, without limitation, suspension or termination as to any Subsidiary, Employee, or class of Employees.

Section 6.3. Procedure for Amendment or Termination. Any amendment to the Plan or termination of the Plan shall be made by the Company by resolution of the Committee and shall not require the approval or consent of any Subsidiary or Participant to be effective to the extent permitted by law. Any amendment to the Plan or termination of the Plan may be retroactive to the extent not prohibited by applicable law.

ARTICLE VII

MISCELLANEOUS

Section 7.1. Rights of Employees. Status as an eligible Employee shall not be construed as a commitment that any Award will be made under the Plan to such eligible Employee or to eligible Employees generally. Nothing contained in the Plan (or in any other documents related to this Plan or to any Award) shall confer upon any Employee any right to continue in the employ or service of the Company or any Subsidiary or constitute any contract or limit in any way the right of the Company to change such person’s compensation or other benefits or to terminate the employment or service of such person with or without cause.

Section 7.2. Unfunded Status. The Plan shall be unfunded. Neither the Company, any Subsidiary, the Committee, nor the Board shall be required to segregate any assets that may at any time be represented by Awards made pursuant to the Plan. Neither the Company, any Subsidiary, the Committee, nor the Board shall be deemed to be a trustee of any amounts to be paid under the Plan.

Section 7.3. Limits on Liability. Any liability of the Company or any Subsidiary to any Participant with respect to an Award shall be based solely upon contractual obligations created by the Plan. Neither the Company nor any Subsidiary nor any member of the Board or the Committee, nor any other person participating in any determination of any question under the Plan, or in the interpretation, administration or application of the Plan, shall have any liability to any party for any action taken or not taken in good faith under the Plan. To the extent permitted by applicable law, the Company shall indemnify and hold harmless each member of the Board and the Committee from and against any and all liability, claims, demands, costs, and expenses (including the costs and expenses of attorneys incurred in connection with the investigation or defense of claims) in any manner connected with or arising out of any actions or inactions in connection with the administration of the Plan except for such actions or inactions which are not in good faith or which constitute willful misconduct.

Section 7.4. Interpretation. Unless otherwise expressly stated by the Committee with respect to an Award, each Award granted to a Covered Employee under the Plan is intended to (i) be Performance-Based Compensation that is fully deductible by the Company for federal income taxes and not subject to the deduction limitation of Section 162(m) of the Code and (ii) comply with the requirements of Code Section 409A (including by reason of being exempt from the application of Code Section 409A), and the Plan shall be construed or deemed amended to the extent possible to conform any Award to effect such intent. The Committee shall not have any discretion to determine that an Award will be paid to a Covered Employee if the Performance Objective for such Award is not attained.

Section 7.5. Tax Withholding. The Company shall be entitled to withhold from any payment made under the Plan the full amount of any required federal, state or local taxes or such other amounts as may be required by applicable law.

Section 7.6. Nontransferability of Benefits. A Participant may not assign or transfer any interest in an Award. Notwithstanding the foregoing, upon the death of a Participant, the Participant’s rights and benefits under the Plan shall pass by will or by the laws of descent and distribution.

Section 7.7. Governing Law. To the extent not governed by federal law, the Plan shall be construed in accordance with and governed by the laws of the State of Ohio.

ARTICLE VIII

EFFECTIVE DATE; DURATION OF THE PLAN

The Plan shall be effective as of the Effective Date. Notwithstanding any provision of this Plan to the contrary, this Plan shall be subject to approval by a vote of the shareholders of the Company at its 2012 annual meeting, and such shareholder approval shall be a pre-condition to the right of any Participant to receive any benefits pursuant to an Award made under this Plan on or after the Effective Date.

EXHIBIT 12

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIAIRIES

Computation of Consolidated Ratios of Earnings to Fixed Charges

(in millions except ratio data)

																Twelve			Six
																Months			Months
	Years Ended December 31,															Ended			Ended
	2007			2008			2009			2010			2011			6/30/2012			6/30/2012
EARNINGS
Income Before Income Tax Expense and Equity Earnings	$	1,663		$	2,015		$	1,938		$	1,849		$	2,367		$	2,332		$	1,113
Fixed Charges (as below)		1,146			1,240			1,237			1,254			1,209			1,195			602
Preferred Security Dividend Requirements of Consolidated Subsidiaries		(4	)		(4	)		(4	)		(4	)		(8	)		(6	)		-
Total Earnings	$	2,805		$	3,251		$	3,171		$	3,099		$	3,568		$	3,521		$	1,715

FIXED CHARGES
Interest Expense	$	838		$	957		$	973		$	999		$	933		$	916		$	464
Credit for Allowance for Borrowed Funds Used During Construction		79			75			67			53			63			68			35
Estimated Interest Element in Lease Rentals		225			204			193			198			205			205			103
Preferred Security Dividend Requirements of Consolidated Subsidiaries		4			4			4			4			8			6			-
Total Fixed Charges	$	1,146		$	1,240		$	1,237		$	1,254		$	1,209		$	1,195		$	602

Ratio of Earnings to Fixed Charges		2.44			2.62			2.56			2.47			2.95			2.94			2.84

EXHIBIT 12

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

Computation of Consolidated Ratios of Earnings to Fixed Charges

(in thousands except ratio data)

											Twelve		Six
											Months		Months
	Years Ended December 31,										Ended		Ended
	2007			2008	2009		2010		2011		6/30/2012		6/30/2012
EARNINGS
Income Before Income Taxes	$	195,613	$	166,801	$	201,263	$	210,898	$	252,618	$	364,794	$	223,835
Fixed Charges (as below)		178,067		225,573		215,640		217,500		217,280		213,432		106,997
Total Earnings	$	373,680	$	392,374	$	416,903	$	428,398	$	469,898	$	578,226	$	330,832

FIXED CHARGES
Interest Expense	$	165,405	$	209,733	$	202,426	$	207,649	$	204,623	$	201,748	$	103,252
Credit for Allowance for Borrowed Funds Used During Construction		6,962		9,040		6,014		2,251		6,257		5,284		545
Estimated Interest Element in Lease Rentals		5,700		6,800		7,200		7,600		6,400		6,400		3,200
Total Fixed Charges	$	178,067	$	225,573	$	215,640	$	217,500	$	217,280	$	213,432	$	106,997

Ratio of Earnings to Fixed Charges		2.09		1.73		1.93		1.96		2.16		2.70		3.09

EXHIBIT 12

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

Computation of Consolidated Ratios of Earnings to Fixed Charges

(in thousands except ratio data)

											Twelve		Six
											Months		Months
	Years Ended December 31,										Ended		Ended
	2007			2008		2009	2010		2011		6/30/2012		6/30 / 2012
EARNINGS
Income Before Income Taxes	$	204,394	$	190,133	$	297,347	$	189,517	$	201,434	$	180,923	$	97,812
Fixed Charges (as below)		161,849		164,660		173,293		174,965		168,003		167,826		84,306
Total Earnings	$	366,243	$	354,793	$	470,640	$	364,482	$	369,437	$	348,749		182,118

FIXED CHARGES
Interest Expense	$	80,034	$	89,851	$	101,145	$	104,465	$	97,665		98,707		50,426
Credit for Allowance for Borrowed Funds Used During Construction		5,315		4,609		8,348		8,500		7,838		6,619		2,630
Estimated Interest Element in Lease Rentals		76,500		70,200		63,800		62,000		62,500		62,500		31,250
Total Fixed Charges	$	161,849	$	164,660	$	173,293	$	174,965	$	168,003		167,826		84,306

Ratio of Earnings to Fixed Charges		2.26		2.15		2.71		2.08		2.19		2.07		2.16

EXHIBIT 12

OHIO POWER COMPANY CONSOLIDATED

Computation of Consolidated Ratios of Earnings to Fixed Charges

(in thousands except ratio data)

												Twelve		Six
												Months		Months
	Years Ended December 31,											Ended		Ended
	2007		2008		2009		2010		2011			6/30/2012		6/30/2012
EARNINGS
Income Before Income Taxes	$	804,622	$	693,946	$	890,471	$	842,922	$	678,690	$	590,192	$	382,965
Fixed Charges (as below)		260,794		318,684		283,540		269,886		248,026		244,488		124,204
Total Earnings	$	1,065,416	$	1,012,630	$	1,174,011	$	1,112,808	$	926,716	$	834,680	$	507,169

FIXED CHARGES
Interest Expense	$	196,978	$	265,938	$	241,134	$	242,000	$	221,976	$	215,733	$	107,408
Credit for Allowance for Borrowed Funds Used During Construction		43,916		27,946		16,506		3,786		2,350		5,055		4,946
Estimated Interest Element in Lease Rentals		19,900		24,800		25,900		24,100		23,700		23,700		11,850
Total Fixed Charges	$	260,794	$	318,684	$	283,540	$	269,886	$	248,026	$	244,488	$	124,204

Ratio of Earnings to Fixed Charges		4.08		3.17		4.14		4.12		3.73		3.41		4.08

EXHIBIT 12

PUBLIC SERVICE COMPANY OF OKLAHOMA

Computation of Ratios of Earnings to Fixed Charges

(in thousands except ratio data)

													Twelve		Six
													Months		Months
	Years Ended December 31,												Ended		Ended
	2007			2008		2009		2010		2011			6/30/2012		6/30/2012
EARNINGS
Income (Loss) Before Income Taxes	$	(46,139	)	$	120,761	$	119,523	$	122,887	$	192 ,257	$	193,510	$	77,376
Fixed Charges (as below)		54,716			81,584		62,235		65,834		58,822		57,153		30,622
Total Earnings	$	8,577		$	202,345	$	181,758	$	188,721	$	251,079	$	250,663	$	107,998

FIXED CHARGES
Interest Expense	$	46,560		$	76,910	$	59,093	$	63,362	$	54,700	$	52,981	$	28,477
Credit for Allowance for Borrowed Funds Used During Construction		5,156			2,174		1,142		572		822		872		495
Estimated Interest Element in Lease Rentals		3,000			2,500		2,000		1,900		3,300		3,300		1,650
Total Fixed Charges	$	54,716		$	81,584	$	62,235	$	65,834	$	58,822	$	57,153	$	30,622

Ratio of Earnings to Fixed Charges		0.15			2.48		2.92		2.86		4.26		4.38		3.52

For the year ended December 31, 2007, the Earnings to cover Fixed Charges was deficient by $46,139,000.

EXHIBIT 12

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

Computation of Consolidated Ratios of Earnings to Fixed Charges

(in thousands except ratio data)

													Twelve		Six
													Months		Months
	Years Ended December 31,												Ended		Ended
	2007			2008				2009	2010		2011		6 /30/2012		6/30/2012
EARNINGS
Income Before Income Taxes and Equity Earnings	$	87,333		$	129,489		$	140,035	$	208,484	$	219,283	$	219,630	$	113,949
Fixed Charges (as below)		79,435			119,516			109,146		132,106		134,285		139,787		73,661
Total Earnings	$	166,768		$	249,005		$	249,181	$	340,590	$	353,568	$	359,417	$	187,610

FIXED CHARGES
Interest Expense	$	60,619		$	93,150		$	70,500	$	86,538	$	81,781	$	82,233	$	43,712
Credit for Allowance for Borrowed Funds Used During Construction		9,795			19,800			29,546		33,668		40,904		45,954		24,149
Trust Dividends		(179	)		(134	)		-		-		-		-		-
Estimated Interest Element in Lease Rentals		9,200			6,700			9,100		11,900		11,600		11,600		5,800
Total Fixed Charges	$	79,435		$	119,516		$	109,146	$	132,106	$	134,285	$	139,787	$	73,661

Ratio of Earnings to Fixed Charges		2.09			2.08			2.28		2.57		2 .63		2.57		2.54

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1.	I have reviewed this report on Form 10-Q 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;

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:

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;

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

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: July 27, 2012

By:

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1. I have reviewed this report on Form 10-Q of Appalachian Power Company;

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;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of each registrant as of, and for, the periods presented in this report;

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

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):

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

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: July 27, 2012

By:

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1. I have reviewed this report on Form 10-Q of Indiana Michigan Power Company;

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: July 27, 2012

By:

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1. I have reviewed this report on Form 10-Q of Ohio Power Company;

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: July 27, 2012

By:

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1. I have reviewed this report on Form 10-Q of Public Service Company of Oklahoma;

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: July 27, 2012

By:

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

EXHIBIT 31(a)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas K. Akins, certify that:

1. I have reviewed this report on Form 10-Q of Southwestern Electric Power Company;

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: July 27, 2012

By:

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1.	I have reviewed this report on Form 10-Q 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;

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:

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

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: July 27, 2012

By:

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1. I have reviewed this report on Form 10-Q of Appalachian Power Company;

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:

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

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: July 27, 2012

By:

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1. I have reviewed this report on Form 10-Q of Indiana Michigan Power Company;

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:

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

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: July 27, 2012

By:

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1. I have reviewed this report on Form 10-Q of Ohio Power Company;

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:

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

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: July 27, 2012

By:

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1. I have reviewed this report on Form 10-Q of Public Service Company of Oklahoma;

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:

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

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: July 27, 2012

By:

/s/ Brian X. Tierney

Brian X. Tierney

Chief Financial Officer

EXHIBIT 31(b)

CERTIFICATION PURSUANT TO SECTION 302

OF THE SARBANES-OXLEY ACT OF 2002

I, Brian X. Tierney, certify that:

1. I have reviewed this report on Form 10-Q of Southwestern Electric Power Company;

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:

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

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: July 27, 2012

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 Quarterly Report of American Electric Power Company, Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2012 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

July 27, 2012

A signed original of this written statement required by Section 906 has been provided to American Electric Power Company, Inc. and will be retained by American Electric Power Company, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Appalachian Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2012 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

July 27, 2012

A signed original of this written statement required by Section 906 has been provided to Appalachian Power Company and will be retained by Appalachian Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Indiana Michigan Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2012 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

July 27, 2012

A signed original of this written statement required by Section 906 has been provided to Indiana Michigan Power Company and will be retained by Indiana Michigan Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Ohio Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2012 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

July 27, 2012

A signed original of this written statement required by Section 906 has been provided to Ohio Power Company and will be retained by Ohio Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Public Service Company of Oklahoma (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2012 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

July 27, 2012

A signed original of this written statement required by Section 906 has been provided to Public Service Company of Oklahoma and will be retained by Public Service Company of Oklahoma and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(a)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Southwestern Electric Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2012 as filed with the Securities and Exchange Commission on the date hereof, I, Nicholas K. Akins, the chief executive officer of the Company certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that, based on my knowledge (i) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and (ii) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Nicholas K. Akins

Nicholas K. Akins

Chief Executive Officer

July 27, 2012

A signed original of this written statement required by Section 906 has been provided to Southwestern Electric Power Company and will be retained by Southwestern Electric Power Company and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32(b)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of American Electric Power Company, Inc. (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2012 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

July 27, 2012

Exhibit 32(b)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Appalachian Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2012 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

July 27, 2012

Exhibit 32(b)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Indiana Michigan Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2012 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

July 27, 2012

Exhibit 32(b)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Ohio Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2012 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

July 27, 2012

Exhibit 32(b)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Public Service Company of Oklahoma (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2012 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

July 27, 2012

Exhibit 32(b)

Certification Pursuant to Section 1350 of Chapter 63

of Title 18 of the United States Code

In connection with the Quarterly Report of Southwestern Electric Power Company (the “Company”) on Form 10-Q (the “Report”) for the quarter ended June 30, 2012 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

July 27, 2012

Exhibit 95

MINE SAFETY INFORMATION

The Dodd-Frank Wall Street Reform and Consumer Protection Act and its related regulations require 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 June 30, 2012:

		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		$	Not Assessed	$	-	$	-
Number of Mining-related Fatalities			-		-		-

* References to sections under the Mine Act

DHLC currently has three legal actions pending before the Federal Mine Safety and Health Review Commission. Two actions are challenging four violations issued by Mine Safety and Health Administration following an employee fatality in March 2009. The third legal action is challenging a citation issued in August 2010 related to a dragline boom issue.