Columbus Southern Power 10Q 2011 Q3 Quarterly report

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 September 30, 2011

[ ] 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
1-2680	COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation)	31-4154203
1-3570	INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)	35-0410455
1-6543	OHIO POWER COMPANY (An Ohio Corporation)	31-4271000
0-343	PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)	73-0410895
1-3146	SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation)	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 American Electric Power Company, Inc. has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes	X		No

Indicate by check mark whether Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company have submitted electronically and posted on the AEP corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was 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, Columbus Southern Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers or smaller reporting companies. See 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

Columbus Southern Power Company and Indiana Michigan 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 October 27, 2011

American Electric Power Company, Inc.			482,912,247
			($6.50 par value)
Appalachian Power Company			13,499,500
			(no par value)
Columbus Southern Power Company			16,410,426
			(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

September 30, 2011

		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 and Quantitative and Qualitative Disclosures About Market Risk:

American Electric Power Company, Inc. and Subsidiary Companies:
	Management’s Discussion and Analysis	1
	Quantitative and Qualitative Disclosures About Market Risk	23
	Condensed Consolidated Financial Statements	27
	Index of Condensed Notes to Condensed Consolidated Financial Statements	32

Appalachian Power Company and Subsidiaries:
	Management’s Discussion and Analysis	84
	Quantitative and Qualitative Disclosures About Market Risk	91
	Condensed Consolidated Financial Statements	92
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries	97

Columbus Southern Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis	99
	Quantitative and Qualitative Disclosures About Market Risk	105
	Condensed Consolidated Financial Statements	106
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries	111

Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis	113
	Quantitative and Qualitative Disclosures About Market Risk	117
	Condensed Consolidated Financial Statements	118
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries	123

Ohio Power Company Consolidated:
	Management’s Discussion and Analysis	125
	Quantitative and Qualitative Disclosures About Market Risk	134
	Condensed Consolidated Financial Statements	135
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries	140

Public Service Company of Oklahoma:
	Management’s Discussion and Analysis	142
	Quantitative and Qualitative Disclosures About Market Risk	146
	Condensed Financial Statements	147
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries	152

Southwestern Electric Power Company Consolidated:
	Management’s Discussion and Analysis	154
	Quantitative and Qualitative Disclosures About Market Risk	159
	Condensed Consolidated Financial Statements	160
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries	165

Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries				166

Combined Management’s Discussion and Analysis of Registrant Subsidiaries				232

Controls and Procedures				243

Part II. OTHER INFORMATION

	Item 1.	Legal Proceedings		243
	Item 1A.	Risk Factors		243
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		247
	Item 5.	Other Information		248
	Item 6.	Exhibits:		248
			Exhibit 12
			Exhibit 31(a)
			Exhibit 31(b)
			Exhibit 32(a)
			Exhibit 32(b)
			Exhibit 101.INS
			Exhibit 101.SCH
			Exhibit 101.CAL
			Exhibit 101.DEF
			Exhibit 101.LAB
			Exhibit 101.PRE

SIGNATURE				249

This combined Form 10-Q is separately filed by American Electric Power Company, Inc., Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. 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 holding company.
AEP Consolidated		AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit		AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East companies		APCo, CSPCo, I&M, KPCo and OPCo.
AEP Power Pool		Members are APCo, CSPCo, I&M, KPCo and OPCo. The AEP Power Pool shares the generation, cost of generation and resultant wholesale off-system sales of the member companies.
AEP System or the System		American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
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, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC		Allowance for Funds Used During Construction.
AOCI		Accumulated Other Comprehensive Income.
APCo		Appalachian Power Company, an AEP electric utility subsidiary.
APSC		Arkansas Public Service Commission.
ASU		Accounting Standard Update.
BOA		Bank of America Corporation.
CAA		Clean Air Act.
CLECO		Central Louisiana Electric Company, a nonaffiliated utility company.
CO2		Carbon Dioxide and other greenhouse gases.
Cook Plant		Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M.
CSPCo		Columbus Southern Power Company, an AEP electric utility subsidiary.
CTC		Competition Transition Charge, a transition charge applied to TCC’s transmission and distribution rates for stranded costs and other true-up amounts as required by the Texas Restructuring Legislation.
DCC Fuel		DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC, 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.
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 Utilities, Inc. and MidAmerican Energy Holdings Company Texas Transco, LLC formed to own and operate electric transmission facilities in ERCOT.
FAC		Fuel Adjustment Clause.
FASB		Financial Accounting Standards Board.
Federal EPA		United States Environmental Protection Agency.
FERC		Federal Energy Regulatory Commission.
FGD		Flue Gas Desulfurization or Scrubbers.
FTR		Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.

Term		Meaning

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		Agreement, dated July 6, 1951, as amended, by and among APCo, CSPCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants.
IRS		Internal Revenue Service.
IURC		Indiana Utility Regulatory Commission.
KGPCo		Kingsport Power Company, an AEP electric utility subsidiary.
KPCo		Kentucky Power Company, an AEP electric utility subsidiary.
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.
NOx		Nitrogen oxide.
Nonutility Money Pool		AEP’s Nonutility Money Pool is the centralized funding mechanism AEP uses to meet the short term cash requirements of pool participants.
NSR		New Source Review.
OCC		Corporation Commission of the State of Oklahoma.
OPCo		Ohio Power Company, an AEP electric utility subsidiary.
OPEB		Other Postretirement Benefit Plans.
OTC		Over the counter.
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, CSPCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts		Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant		A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana, owned by AEGCo and I&M.
RTO		Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine		Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity.
SEC		U.S. Securities and Exchange Commission.
SEET		Significantly Excessive Earnings Test.
SIA		System Integration Agreement, effective June 15, 2000, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SNF		Spent Nuclear Fuel.

Term		Meaning

SO2		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.
Texas Restructuring Legislation		Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC		AEP Texas North Company, an AEP electric utility subsidiary.

Transition Funding		AEP Texas Central Transition Funding I LLC and AEP Texas Central Transition Funding II LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas restructuring law.
True-up Proceeding		A filing made under the Texas Restructuring Legislation to finalize the amount of stranded costs and other true-up items and the recovery of such amounts.
Turk Plant		John W. Turk, Jr. Plant.
Utility Money Pool		AEP System’s Utility Money Pool is the centralized funding mechanism AEP uses to meet the short term cash requirements of pool participants.
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 2010 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 storms, and our ability to recover significant storm restoration costs through applicable rate mechanisms.
·	Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·	Availability of necessary generating capacity and the performance of our generating plants.
·	Our ability to resolve I&M’s Donald C. Cook Nuclear Plant Unit 1 restoration and outage-related issues through warranty, insurance and the regulatory process.
·	Our ability to recover regulatory assets and stranded costs in connection with deregulation.
·	Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·	Our ability to build or acquire generating capacity, including the Turk Plant, and transmission 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.
·	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, coal, nuclear fuel and other energy-related commodities.
·	Changes in utility regulation, including the implementation of ESPs and the expected legal separation and transition to market 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.
·	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.

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

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Customer Demand

In comparison to 2010 for both the quarter-to-date and year-to-date periods, cooling degree days in 2011 were up 13% and 19%, respectively, in our western region and down 2% and 7%, respectively, in our eastern region. While cooling degree days in our eastern region were down slightly in comparison to 2010, they were significantly higher than normal. Our non-weather residential and commercial sales remained relatively flat in comparison to 2010. Industrial sales are up just over 5% for the quarter-to-date and year-to-date periods, reflecting a significant increase in production from Ormet, a large aluminum company, and lesser increases from several other industrial customers, reflecting an increase in production at several of our metals and refinery customers. Commercial margins decreased 5% for the year-to-date period primarily due to the loss of retail customers in Ohio. See “Ohio Customer Choice” section below.

Texas Restructuring Appeals

In July 2011, the Supreme Court of Texas overturned a 2006 PUCT order that had denied recovery of capacity auction true-up amounts related to TCC securitized net recoverable stranded generation cost. Based upon the Supreme Court of Texas’ opinion, TCC recorded $421 million of pretax income ($273 million, net of tax) in Extraordinary Item, Net of Tax on the condensed statements of income in the third quarter of 2011.

Also in the third quarter of 2011, TCC recorded $261 million in pretax Carrying Costs Income on the condensed statements of income related to the debt component of carrying costs for the period from January 2002 through September 2011. This carrying costs income represents previously unrecorded earnings associated with restructuring in Texas since 2002. The total regulatory asset related to the capacity auction true-up as of September 30, 2011 was $682 million. In October 2011, TCC filed with the PUCT requesting a final determination of the amount to be securitized. In its filing, TCC presented three alternative carrying cost calculations through March 2012, the anticipated securitization date, where the debt and equity component of carrying costs ranged from $396 million to $756 million, including $280 million to $444 million for the debt component of carrying costs. The final amount of carrying costs will be determined by the PUCT and could vary from the calculations presented by TCC. TCC plans to recognize debt carrying costs income prior to securitization and equity carrying costs income will be recognized as collected over the life of the securitization. A PUCT hearing is scheduled for November 2011. See “Texas Restructuring Appeals” section of Note 3.

Regulatory Activity

Ohio 2009 – 2011 ESPs

In July 2011, CSPCo and OPCo filed their 2010 SEET filings with the PUCO. Based upon the approach in the PUCO 2009 order, management does not currently believe that CSPCo or OPCo will have any significantly excessive earnings. In October 2011, the Ohio Consumers’ Counsel and the Ohio Energy Group filed testimony that recommended CSPCo refund up to $41 million of its 2010 earnings. Also in October 2011, the PUCO staff filed testimony that recommended CSPCo refund $21 million of its 2010 earnings. See “Ohio Electric Security Plan Filings” section of Note 3.

Ohio January 2012 – May 2016 ESP

In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation. In September 2011, a stipulation agreement was filed with the PUCO which involved various issues pending before the PUCO, including the approval of the CSPCo/OPCo merger and the recovery of deferred fuel until securitized. Under the stipulation agreement, rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2016. Prior to June 2015, CSPCo’s and OPCo’s SSO customers continue to pay the tariff rate for non-fuel generation and the fuel adjustment clause. Beginning in June 2015, CSPCo and OPCo will use results from a competitive bidding process performed prior to January 2015 to meet their SSO obligation through May 2016. The stipulation agreement proposed a corporate separation plan of CSPCo’s and OPCo’s generation assets to complete the transition to a fully competitive generation market by June 2015. In addition, to further develop customer choice and facilitate the transition to market generation pricing, CSPCo and OPCo will provide 21% of their generation capacity in 2012, 29% to 31% of their generation capacity in 2013 and 41% of their generation capacity beginning in 2014 through May 2015 to competitive retail suppliers at a charge based on the Reliability Pricing Model auction-clearing prices and the remainder at a discounted cost-based price.

The stipulation agreement also proposed a termination or modification of the Interconnection Agreement. Finally, the stipulation agreement provides for certain CSPCo and OPCo contingent contributions and established a Distribution Investment Rider beginning January 2012 through May 2015 to recover post-2000 distribution investment with certain limitations. See “Ohio Electric Security Plan Filings,” “Proposed CSPCo and OPCo Merger” and “Possible Termination of the Interconnection Agreement” sections of Note 3.

Ohio Distribution Base Rate Case

In February 2011, CSPCo and OPCo filed with the PUCO for annual increases in distribution rates of $34 million and $60 million, respectively. The requested increase is based upon an 11.15% return on common equity to be effective January 2012. In addition to the annual increases, CSPCo and OPCo requested recovery of the projected December 31, 2012 balances of certain distribution regulatory assets of $216 million and $159 million, respectively, including carrying costs, to be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013. The PUCO staff filed testimony that recommended a rate reduction for CSPCo in the range of $2 million to $10 million and a rate increase for OPCo in the range of $23 million to $32 million. In addition, the PUCO staff recommended recovery of the deferred distribution regulatory assets subject to a review of the carrying costs. A decision from the PUCO is expected in the fourth quarter of 2011. See “2011 Ohio Distribution Base Rate Case” section of Note 3.

Virginia Regulatory Activity

In March 2011, APCo filed a generation and distribution base rate request with the Virginia SCC to increase annual base rates by $126 million based upon an 11.65% return on common equity to be effective no later than February 2012. The return on common equity includes a requested 0.5% renewable portfolio standards incentive as allowed by law. APCo proposed to mitigate the requested base rate increase by $51 million by maintaining current depreciation rates until the next biennial filing. If approved, APCo’s net base rate increase would be $75 million. In August 2011, the Virginia Attorney General and the Virginia SCC staff filed testimony recommending no increase in annual base rates and a $31 million increase in annual base rates, respectively. Hearings were held in September 2011. A decision from the Virginia SCC is pending. See “2011 Virginia Biennial Base Rate Case” section of Note 3.

West Virginia Regulatory Activity

In March 2011, the WVPSC modified and approved a settlement agreement which increased annual base rates by approximately $51 million based upon a 10% return on common equity. The approved settlement agreement also resulted in a pretax write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility in the first quarter of 2011. In addition, the WVPSC allowed APCo to defer and amortize $18 million of previously expensed 2009 incremental storm expenses and allowed APCo and WPCo to defer and amortize $15 million of previously expensed costs related to the 2010 cost reduction initiatives, each over a period of seven years. See “2010 West Virginia Base Rate Case” section of Note 3.

Michigan Base Rate Case

In July 2011, I&M filed a request with the MPSC for an annual increase in Michigan base rates of $25 million and a return on equity of 11.15%. The request included an increase in depreciation rates that would result in a $6 million increase in annual depreciation expense. I&M plans to request an interim rate increase, subject to refund, for the portion of the $25 million that, among other things, excludes the depreciation rate changes and other regulatory amortizations. I&M plans to propose the interim rate increase be effective in January 2012.

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 equity of 11.15%. The request included an increase in depreciation rates that would result in a $25 million increase in annual depreciation expense.

Ohio Customer Choice

In our Ohio service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service. As a result, in comparison to the third quarter of 2010 and the first nine months of 2010, we lost approximately $41 million and $94 million, respectively, of generation and transmission related gross margin. We are recovering a portion of lost margins through collection of transmission revenues from competitive CRES providers, off-system sales and new revenues from our CRES provider. Our CRES provider targets retail customers in Ohio, both within and outside of our retail service territory.

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW coal generating unit in Arkansas, which is expected to be in service in 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility. SWEPCo’s share of construction costs is currently estimated to be $1.3 billion, excluding AFUDC, plus an additional $129 million for transmission, excluding AFUDC. The APSC, LPSC and PUCT approved SWEPCo’s original application to build the Turk Plant. In June 2010, the APSC issued an order which reversed and set aside the previously granted Certificate of Environmental Compatibility and Public Need. Various proceedings are pending that challenge the Turk Plant’s construction and its approved wetlands and air permits. In 2010, the motions for preliminary injunction were partially granted by the Federal District Court for the Western District of Arkansas. According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop. Mitigation measures required by the permit are authorized and may be completed. The preliminary injunction affects portions of the water intake and portions of two transmission lines. In July 2011, the U.S. Eighth Circuit Court of Appeals affirmed the preliminary injunction and remanded the case to the district court. Management is unable to predict the timing or the outcome related to this remand proceeding.

In August 2011, a joint stipulation of dismissal was approved by the Federal District Court for the Western District of Arkansas that resolved all pending matters between SWEPCo, the Hempstead County Hunting Club (Hunting Club) and several other parties. As a result, the Hunting Club’s challenge to the U.S. Army Corps of Engineers permit in the Federal District Court for the Western District of Arkansas was dismissed and the Hunting Club’s appeal of the air permit was withdrawn. Additional judicial and administrative proceedings were terminated. The Sierra Club and the Audubon Society challenges to the wetlands and air permits remain pending.

In October 2011, the Sierra Club, the National Audubon Society and Audubon Arkansas filed a complaint with the APSC requesting that construction of the Turk Plant be halted until SWEPCo or the Arkansas Electric Cooperative Corporation obtain either a Certificate of Environmental Compatibility and Public Need, or SWEPCo obtains a Certificate of Convenience and Necessity and performs an Environmental Impact Statement on associated gas facilities. Management believes the complaint is without merit and intends to vigorously defend against the complaint.

Management expects that SWEPCo will ultimately be able to complete construction of the Turk Plant and related transmission facilities and place those facilities in service. However, if SWEPCo is unable to complete the Turk Plant construction, including the related transmission facilities, and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition. See “Turk Plant” section of Note 3.

Cook Plant

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator. Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $408 million. Management believes that I&M should recover a significant portion of repair and replacement costs through the turbine vendor’s warranty, insurance and the regulatory process. I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power. The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors. The installation of the new turbine rotors and other equipment occurred as planned during the fall 2011 refueling outage of Unit 1. If the ultimate costs of the incident are not covered by warranty, insurance or through the related regulatory process or if any future regulatory proceedings are adverse, it could reduce future net income and cash flows and impact financial condition. See “Michigan 2009 and 2010 Power Supply Cost Recovery Reconciliations” section of Note 3 and “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

As a result of the nuclear plant situation in Japan following a March 2011 earthquake, we expect the Nuclear Regulatory Commission and possibly Congress to review 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. We are unable to predict the impact of potential future regulation of nuclear facilities.

LITIGATION

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot predict the eventual resolution, timing or amount of any loss, fine or penalty. We assess the probability of loss for each contingency and accrue a liability for cases that have a probable likelihood of loss if the loss can be estimated. For details on our regulatory proceedings and pending litigation see Note 4 – Rate Matters, Note 6 – Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Financial Discussion and Analysis” in the 2010 Annual Report. Additionally, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies included herein. Adverse results in these proceedings have the potential to materially affect our net income, financial condition and cash flows.

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 SO2, NOx, 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 CO2 emissions to address concerns about global climate change. AEP, various industry groups, affected states and other parties have urged the Federal EPA to conduct additional analysis and either postpone the effective date or extend the time frame for compliance with some of these future requirements. 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. We believe that further analysis and better coordination of these future environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

See a complete discussion of these matters in the “Environmental Issues” section of “Management’s Financial Discussion and Analysis” in the 2010 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 adversely affect future net income, cash flows and possibly financial condition.

Update to 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 September 30, 2011, the AEP System had a total generating capacity of nearly 38,000 MWs, of which 23,900 MWs are coal-fired. In the second quarter of 2011, we refined the cost estimates of complying with these rules and other impacts of the environmental proposals on our coal-fired generating facilities. Based upon the updated estimates, investment to meet these proposed requirements ranges from approximately $6 billion to $8 billion between 2012 and 2020. These amounts include investments to convert 1,070 MWs of coal generation to 932 MWs of natural gas capacity and build approximately 580 MWs of 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 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 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 may retire the following plants or units of plants before 2015:

		Generating
Company	Plant Name and Unit	Capacity
		(in MWs)
KPCo	Big Sandy Plant, Unit 1		278
APCo	Clinch River Plant, Unit 3		235
CSPCo	Conesville Plant, Unit 3		165
APCo	Glen Lyn Plant		335
OPCo	Kammer Plant		630
APCo	Kanawha River Plant		400
OPCo	Muskingum River Plant, Units 1-4		840
APCo/OPCo	Philip Sporn Plant		1,050
CSPCo	Picway Plant		100
I&M	Tanners Creek Plant, Units 1-3		495
SWEPCo	Welsh Plant, Unit 2		528
	Total		5,056

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

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. We are completing construction of the Turk and Dresden Plants. Recovery of the remaining investments in facilities that we may close and cost of new equipment and converted facilities will be subject to regulatory approval.

Cross-State Air Pollution Rule (formerly the Clean Air Act Transport Rule)

In July 2010, the Federal EPA issued a proposed rule to replace the Clean Air Interstate Rule (CAIR) that would impose new and more stringent requirements to control SO2 and NOx emissions from fossil fuel-fired electric generating units in 31 states and the District of Columbia. Each state covered by the proposed Clean Air Act Transport Rule (Transport Rule) was assigned an allowance budget for SO2 and/or NOx. Limited interstate trading was allowed on a sub-regional basis and intrastate trading was allowed among generating units. Our western states (Arkansas, Oklahoma and Texas) would be subject to only the seasonal NOx program, with new limits that were proposed to take effect in 2012. The remainder of the states in which we operate would have been subject to seasonal and annual NOx programs and an annual SO2 emissions reduction program that takes effect in two phases. The first phase was to be effective in 2012 and more stringent SO2 emission reductions were proposed to take effect in 2014 in certain states. The SO2 and NOx programs rely on newly-created allowances rather than relying on the CAIR NOx allowances or the Title IV Acid Rain Program allowances used in CAIR.

In July 2011, the Federal EPA released the final rule, renamed the Cross-State Air Pollution Rule (CSAP Rule). Like the proposed Transport Rule, the CSAP Rule relies on newly-created SO2 and NOx 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 NOx program in the final rule. A proposed supplemental rule would include Oklahoma in the seasonal NOx program. Texas is now subject to the annual programs for SO2 and NOx in addition to the seasonal NOx program. The annual SO2 allowance budgets in Indiana, Ohio and West Virginia have been reduced significantly in the final rule.

In October 2011, the Federal EPA released a supplemental proposed rule revising portions of the final CSAP Rule. The proposed rule would correct errors in unit-specific assumptions and make available additional allowances in ten states, including Louisiana and Texas, and provide additional allowances for the new unit set aside in Arkansas. In addition, the proposed rule would make the allowance trading assurance provisions which restrict interstate trading of allowances effective January 1, 2014 instead of January 1, 2012.

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. The compliance plan described above was based on the requirements of the proposed Transport Rule. The more stringent requirements included in the final CSAP Rule could cause further unit curtailments, increase capital requirements, constrain operations, decrease reliability and unfavorably impact financial condition if the increased costs are not recovered in rates or market prices.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

The Federal EPA issued the Clean Air Mercury Rule (CAMR) in 2005, setting mercury emission standards for new coal-fired power plants and requiring all states to issue new state implementation plans including mercury requirements for existing coal-fired power plants. The CAMR was vacated by the D.C. Circuit Court of Appeals in 2008. In response, the Federal EPA has been developing 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. Compliance is required within three years of the effective date of the final rule, which is expected in December 2011 per the Federal EPA’s settlement agreement with several environmental groups. A one-year extension may be available if the extension is necessary for the installation of controls. In October 2011, various intervenors filed a motion to extend the deadline by which the Federal EPA is required to finalize the HAPs rule for one year, to November 2012. The motion was supported by 25 states’ attorneys general. A joint request of the Federal EPA and the plaintiffs to extend the deadline for finalizing the rule for 30 days, to December 16, 2011, was granted.

We submitted comments on the proposed rule and urged the Federal EPA to carefully consider all of the options available so that costly and inefficient control requirements are not imposed regardless of unit size, age or other operating characteristics. We have older coal units for which it may be economically inefficient to install scrubbers or other environmental controls. Several of these units are included in our current list of potential plant closures discussed above.

Regional Haze

In March 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze state implementation plan (SIP) submitted by the State of Oklahoma through the Department of Environmental Quality. The Federal EPA is proposing to approve all of the NOx control measures in the SIP and disapprove the SO2 control measures for six electric generating units, including two units owned by PSO. The Federal EPA is proposing a federal implementation plan (FIP) that would require these units to install technology capable of reducing SO2 emissions to 0.06 pounds per million British thermal units within three years of the effective date of the FIP. The State of Oklahoma filed suit in Federal District Court in the Western District of Oklahoma seeking to enjoin the Federal EPA from taking final action on the FIP without allowing the state to first respond to the deficiencies identified for the first time in the proposed disapproval of the SIP. Motions for preliminary relief are pending. 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. Final action on the proposal is required to be taken by December 14, 2011 under a consent decree between the Federal EPA and certain environmental advocacy groups.

Coal Combustion Residual Rule

In June 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at our coal-fired electric generating units. The rule contains two alternative proposals. One 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. Comments are due in November 2011.

Currently, approximately 40% of the coal ash and other residual products from our generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses. Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes. In addition, we currently use surface impoundments and landfills to manage these materials at our generating facilities and will incur significant costs to upgrade or close and replace these existing facilities. We estimate that the potential compliance costs associated with the proposed solid waste management alternative could be as high as $3.9 billion including AFUDC for units across the AEP System. Regulation of these materials as hazardous wastes would significantly increase these costs.

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. We submitted comments on the proposal in July and August 2011.

Global Warming

While comprehensive economy-wide regulation of CO2 emissions might be mandated through new legislation, Congress has yet to enact such legislation. The Federal EPA continues to take action to regulate CO2 emissions under the existing requirements of the CAA. The Federal EPA issued a final endangerment finding for CO2 emissions from new motor vehicles in December 2009 and final rules for new motor vehicles in May 2010. The Federal EPA determined that CO2 emissions from stationary sources will be subject to regulation under the CAA and finalized its proposed scheme to streamline and phase in regulation of stationary source CO2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs through the issuance of final federal rules, state implementation plan calls and federal implementation plans. The Federal EPA is reconsidering whether to include CO2 emissions in a number of stationary source standards, including standards that apply to new and modified electric utility units and announced a settlement agreement to issue proposed new source performance standards for utility boilers that would be applicable for both new and existing utility boilers. It is not possible at this time to estimate the costs of compliance with these new standards, but they may be material.

Our fossil fuel-fired generating units are very large sources of CO2 emissions. If substantial CO2 emission reductions are required, there will be significant increases in capital expenditures and operating costs which would impact the ultimate retirement of older, less-efficient, coal-fired units. To the extent we install additional controls on our generating plants to limit CO2 emissions and receive regulatory approvals to increase our rates, cost recovery could have a positive effect on future earnings. Prudently incurred capital investments made by our subsidiaries in rate-regulated jurisdictions to comply with legal requirements and benefit customers are generally included in rate base for recovery and earn a return on investment. We would expect these principles to apply to investments made to address new environmental requirements. However, requests for rate increases reflecting these costs can affect us adversely because our regulators could limit the amount or timing of increased costs that we would recover through higher rates. In addition, to the extent our costs are relatively higher than our competitors’ costs, such as operators of nuclear and natural gas based generation, it could reduce our off-system sales or cause us to lose customers in jurisdictions that permit customers to choose their supplier of generation service.

Several states have adopted programs that directly regulate CO2 emissions from power plants, but none of these programs are currently in effect in states where we have generating facilities. Certain states, including Michigan, Ohio, Texas and Virginia, passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements. We are taking steps to comply with these requirements.

Certain groups have filed lawsuits alleging that emissions of CO2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others. We have been named in pending lawsuits, which we are vigorously defending. It is not possible to predict the outcome of these lawsuits or their impact on our operations or financial condition. See “Carbon Dioxide Public Nuisance Claims” and “Alaskan Villages’ Claims” sections of Note 4.

Future federal and state legislation or regulations that mandate limits on the emission of CO2 would result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force our utility subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets. As a result, mandatory limits could have a material adverse impact on our net income, cash flows and financial condition.

For detailed information on global warming and the actions we are taking to address potential impacts, see Part I of the 2010 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters – Global Warming” and “Management’s Financial Discussion and Analysis.”

RESULTS OF OPERATIONS

SEGMENTS

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

Utility Operations

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

AEP River Operations

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

Generation and Marketing

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

The table below presents our consolidated Income Before Extraordinary Item by segment for the three and nine months ended September 30, 2011 and 2010.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in millions)
Utility Operations	$	642	$	541	$	1,376	$	1,017
AEP River Operations		17		14		23		16
Generation and Marketing		8		-		20		17
All Other (a)		(10)		2		(54)		(10)
Income Before Extraordinary Item	$	657	$	557	$	1,365	$	1,040

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

AEP CONSOLIDATED

Third Quarter of 2011 Compared to Third Quarter of 2010

Income Before Extraordinary Item increased from $557 million in 2010 to $657 million in 2011 primarily due to:

·	An increase in carrying costs income due to the third quarter 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005.
·	Successful rate proceedings in our various jurisdictions.
·	An increase in weather-related usage.

These increases were partially offset by:

·	Various Ohio adjustments in the third quarter of 2011, including the refund provision for POLR charges collected from customers, the impairments of Sporn Unit 5 and the FGD project at Muskingum River Unit 5 and the write-off of allocated Front-End Engineering and Design (FEED) study costs related to the Mountaineer Carbon Capture Project.
·	The loss of retail customers in Ohio to various competitive retail electric service providers.

Average basic shares outstanding increased from 480 million in 2010 to 482 million in 2011.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Income Before Extraordinary Item increased from $1,040 million in 2010 to $1,365 million in 2011 primarily due to the following:

·	A decrease in expenses as a result of the second quarter 2010 cost reduction initiatives.
·	An increase in carrying costs income due to the third quarter 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005.
·	Successful rate proceedings in our various jurisdictions.
·	The unfavorable 2010 tax treatment associated with future reimbursement of Medicare Part D prescription drug benefits.

These increases were partially offset by:

·	Various Ohio adjustments in the third quarter of 2011, including the refund provision for POLR charges collected from customers, the write-off of allocated FEED study costs related to the Mountaineer Carbon Capture Project and the impairments of Sporn Unit 5 and the FGD project at Muskingum River Unit 5.
·	A net-of-tax loss related to the first quarter of 2011 settlement of litigation with BOA and Enron.
·	The loss of retail customers in Ohio to various competitive retail electric service providers.

Average basic shares outstanding increased from 479 million in 2010 to 482 million in 2011. Actual shares outstanding were 483 million as of September 30, 2011.

Our results of operations are discussed below by operating segment.

UTILITY OPERATIONS

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

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2011		2010		2011		2010
		(in millions)
Revenues		$	4,074	$	3,907	$	10,987	$	10,544
Fuel and Purchased Power			1,609		1,427		4,136		3,784
Gross Margin			2,465		2,480		6,851		6,760
Other Operation and Maintenance			882		849		2,587		2,798
Asset Impairments and Other Related Charges			90		-		90		-
Depreciation and Amortization			435		413		1,226		1,205
Taxes Other Than Income Taxes			210		208		618		613
Operating Income			848		1,010		2,330		2,144
Interest and Investment Income			18		2		21		6
Carrying Costs Income			290		17		323		51
Allowance for Equity Funds Used During Construction			26		17		69		60
Interest Expense			(223)		(238)		(682)		(710)
Income Before Income Tax Expense and Equity
	Earnings		959		808		2,061		1,551
Equity Earnings of Unconsolidated Subsidiaries			7		3		19		7
Income Tax Expense			324		270		704		541
Income Before Extraordinary Item		$	642	$	541	$	1,376	$	1,017

Summary of KWH Energy Sales for Utility Operations

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2011		2010		2011		2010
		(in millions of KWHs)
Retail:
	Residential		18,238		17,817		48,690		48,250
	Commercial		14,274		14,032		38,833		38,508
	Industrial		15,206		14,460		44,688		42,503
	Miscellaneous		854		832		2,354		2,328
Total Retail (a)			48,572		47,141		134,565		131,589

Wholesale			13,164		10,689		32,532		25,846

Total KWHs			61,736		57,830		167,097		157,435

(a) Includes energy delivered to customers served by AEP's Texas wires companies.

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

Summary of Heating and Cooling Degree Days for Utility Operations

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2011		2010		2011		2010
		(in degree days)
Eastern Region
Actual - Heating (a)			6		1		1,995		1,976
Normal - Heating (b)			7		7		1,914		1,918

Actual - Cooling (c)			838		859		1,209		1,294
Normal - Cooling (b)			700		691		999		984

Western Region
Actual - Heating (a)			-		-		702		764
Normal - Heating (b)			1		1		601		596

Actual - Cooling (d)			1,669		1,471		2,813		2,357
Normal - Cooling (b)			1,359		1,353		2,179		2,168

(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.

Third Quarter of 2011 Compared to Third Quarter of 2010

Reconciliation of Third Quarter of 2010 to Third Quarter of 2011
Income from Utility Operations before Extraordinary Item
(in millions)

Third Quarter of 2010	$	541

Changes in Gross Margin:
Retail Margins		(19	)
Off-system Sales		(1	)
Transmission Revenues		14
Other Revenues		(9	)
Total Change in Gross Margin		(15	)

Changes in Expenses and Other:
Other Operation and Maintenance		(33	)
Asset Impairments and Other Related Charges		(90	)
Depreciation and Amortization		(22	)
Taxes Other Than Income Taxes		(2	)
Interest and Investment Income		16
Carrying Costs Income		273
Allowance for Equity Funds Used During Construction		9
Interest Expense		15
Equity Earnings of Unconsolidated Subsidiaries		4
Total Change in Expenses and Other		170

Income Tax Expense		(54	)

Third Quarter of 2011	$	642

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

·	Retail Margins decreased $19 million primarily due to the following:
	·	A $41 million decrease attributable to Ohio customers switching to alternative competitive retail electric service (CRES) providers.
	·	A $33 million refund provision for CSPCo POLR charges as a result of the October 2011 PUCO remand order.
	·	A $29 million increase in other variable electric generation expenses.
	·	A $23 million decrease in rate related margins for APCo due to the expiration of E&R cost recovery in Virginia.
	These decreases were partially offset by:
	·	Successful rate proceedings in our service territories which include:
		·	A $57 million rate increase in Ohio.
		·	A $22 million rate increase for APCo.
		·	A $10 million rate increase for I&M.
		·	A $3 million rate increase for SWEPCo.
		·	For the rate increases described above, $41 million of these increases relate to riders/trackers which have corresponding increases in other expense items below.
	·	A $14 million increase in weather-related usage primarily due to a 13% increase in cooling degree days in our western region.
	·	A $5 million increase in revenues related to TCC’s securitization. This increase is offset by an increase in Depreciation and Amortization expenses.
·	Transmission Revenues increased $14 million primarily due to net rate increases in PJM 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 $9 million primarily due to lower amortization of deferred gains.

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

·	Other Operation and Maintenance expenses increased $33 million primarily due to:
	·	A $9 million increase due to the third quarter 2011 write-off of Ohio allocated FEED study costs related to the Mountaineer Carbon Capture Project.
	·	A $9 million increase in plant outage expenses and other plant operating and maintenance expenses.
	·	An $8 million increase in storm-related expenses.
	·	An $8 million increase in transmission-related expenses.
	·	A $4 million increase in demand side management expenses, energy efficiency program expenses and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
	These increases were partially offset by:
	·	A $6 million decrease associated with the favorable resolution of an I&M contingency.
·	Asset Impairments and Other Related Charges includes the third quarter 2011 plant impairments of Sporn Unit 5 ($48 million) and the FGD project at Muskingum River Unit 5 ($42 million).
·	Depreciation and Amortization expenses increased $22 million primarily due to the following:
	·	A $19 million increase for OPCo due to the amortization of debt and equity carrying costs on deferred fuel as a result of the October 2011 PUCO remand order which required the POLR refund to be applied against deferred fuel balances. The equity amortization was partially offset by amounts recognized in Carrying Costs Income.
	·	A $10 million increase in depreciation and amortization for TCC primarily due to increased amortization of TCC’s Securitized Transition Asset. This increase is offset by an increase in revenues within Gross Margin.
	·	Overall higher depreciable property balances.
	These increases were partially offset by:
	·	An $8 million decrease in depreciation and amortization for APCo primarily due to the expiration of E&R amortization of deferred carrying costs in Virginia.
·	Interest and Investment Income increased $16 million primarily due to interest income recorded in the third quarter of 2011 for favorable adjustments related to the 2001-2006 federal income tax audit.
·	Carrying Costs Income increased $273 million primarily due to the following:
	·	A $261 million increase in carrying costs income due to the third quarter 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005.
	·	A $10 million increase due to the recognition of equity carrying costs on deferred fuel as a result of the October 2011 PUCO remand order which required the POLR refund to be applied against any deferred fuel balances. The equity carrying costs income was offset by amounts in Depreciation and Amortization discussed above.
·	Allowance for Equity Funds Used During Construction increased $9 million primarily due to construction of the Turk and Dresden Plants and various environmental upgrades.
·	Interest Expense decreased $15 million primarily due to lower outstanding debt balances.
·	Equity Earnings of Unconsolidated Subsidiaries increased $4 million primarily due to an increase in transmission investments by ETT.
·	Income Tax Expense increased $54 million primarily due to an increase in pre-tax book income.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Reconciliation of Nine Months Ended September 30, 2010 to Nine Months Ended September 30, 2011
Income from Utility Operations before Extraordinary Item
(in millions)

Nine Months Ended September 30, 2010	$	1,017

Changes in Gross Margin:
Retail Margins		8
Off-system Sales		49
Transmission Revenues		34
Total Change in Gross Margin		91

Changes in Expenses and Other:
Other Operation and Maintenance		211
Asset Impairments and Other Related Charges		(90)
Depreciation and Amortization		(21)
Taxes Other Than Income Taxes		(5)
Interest and Investment Income		15
Carrying Costs Income		272
Allowance for Equity Funds Used During Construction		9
Interest Expense		28
Equity Earnings of Unconsolidated Subsidiaries		12
Total Change in Expenses and Other		431

Income Tax Expense		(163)

Nine Months Ended September 30, 2011	$	1,376

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

·	Retail Margins increased $8 million primarily due to the following:
	·	Successful rate proceedings in our service territories which include:
		·	A $90 million rate increase in Ohio.
		·	A $49 million rate increase for APCo.
		·	A $32 million rate increase for KPCo.
		·	A $25 million rate increase for I&M.
		·	A $23 million rate increase for SWEPCo.
		·	For the rate increases described above, $54 million of these increases relate to riders/trackers which have corresponding increases in other expense items below.
	·	A $32 million increase in weather-related usage in our western region primarily due to a 19% increase in cooling degree days.
	·	A $5 million increase related to TCC’s Securitized Transition Asset. This increase is offset by an increase in Depreciation and Amortization expenses.
	These increases were partially offset by:
	·	A $94 million decrease attributable to Ohio customers switching to alternative CRES providers.
	·	A $60 million decrease in rate related margins for APCo due to the expiration of E&R cost recovery in Virginia.
	·	A $37 million increase in other variable electric generation expenses.
	·	A $33 million refund provision for CSPCo POLR charges as a result of the October 2011 PUCO remand order.
	·	A $32 million decrease in weather-related usage in our eastern region primarily due to a 7% decrease in cooling degree days.
·	Margins from Off-system Sales increased $49 million primarily due to an increase in PJM capacity revenues and higher physical sales volumes, partially offset by lower trading and marketing margins.

Transmission Revenues increased $34 million primarily due to net rate increases in PJM 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.

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

·	Other Operation and Maintenance expenses decreased $211 million primarily due to the following:
	·	A $275 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
	·	A $54 million decrease due to the second quarter 2010 write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the Virginia SCC.
	·	A $33 million decrease due to the first quarter 2011 deferral of 2010 costs related to storms and our cost reduction initiatives as allowed by the WVPSC.
	·	A $31 million decrease in administrative and general expenses primarily due to a decrease in fringe benefit expenses.
	·	An $11 million gain on the sale of land.
	These decreases were partially offset by:
	·	A $49 million increase in demand side management, energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
	·	A $41 million increase due to the first quarter 2011 write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC.
	·	A $36 million increase in storm-related expenses.
	·	A $36 million increase in plant outage and other plant operating and maintenance expenses.
	·	A $25 million increase due to the second quarter 2010 deferral of 2009 storm costs as allowed by the Virginia SCC.
	·	A $9 million increase due to the third quarter 2011 write-off of Ohio allocated FEED study costs related to the Mountaineer Carbon Capture Project.
·	Asset Impairments and Other Related Charges includes the third quarter 2011 plant impairments of Sporn Unit 5 ($48 million) and the FGD project at Muskingum River Unit 5 ($42 million).
·	Depreciation and Amortization expenses increased $21 million primarily due to the following:
	·	A $19 million increase for OPCo due to the amortization of debt and equity carrying costs on deferred fuel as a result of the October 2011 PUCO remand order which required the POLR refund to be applied against deferred fuel balances. The equity amortization was partially offset by amounts recognized in Carrying Costs Income as discussed below.
	·	A $15 million increase in depreciation and amortization for TCC primarily due to increased amortization of TCC’s Securitized Transition Asset. This increase is offset by an increase in revenues within Gross Margin.
	·	Overall higher depreciable property balances.
	These increases were partially offset by:
	·	A $22 million decrease in depreciation and amortization for APCo primarily due to the expiration of E&R amortization of deferred carrying costs in Virginia.
·	Interest and Investment Income increased $15 million primarily due to interest income recorded in the third quarter of 2011 for favorable adjustments related to the 2001-2006 federal income tax audit.
·	Carrying Costs Income increased $272 million primarily due to the following:
	·	A $261 million increase in carrying costs income due to the third quarter 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005.
	·	A $10 million increase due to the recognition of equity carrying costs on deferred fuel as a result of the October 2011 PUCO remand order which required the POLR refund to be applied against any deferred fuel balances. The equity carrying costs income was offset by amounts in Depreciation and Amortization discussed above.
·	Allowance for Equity Funds Used During Construction increased $9 million primarily due to construction of the Turk and Dresden Plants and various environmental upgrades, partially offset by a decrease due to the completion of the Stall Unit in June 2010.

·	Interest Expense decreased $28 million primarily due to lower outstanding debt balances.
·	Equity Earnings of Unconsolidated Subsidiaries increased $12 million primarily due to an increase in transmission investments by ETT.
·	Income Tax Expense increased $163 million primarily due to an increase in pretax book income, partially offset by the 2010 tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.

AEP RIVER OPERATIONS

Third Quarter of 2011 Compared to Third Quarter of 2010

Net Income from our AEP River Operations segment increased from $14 million in 2010 to $17 million in 2011. AEP River had increases in revenues related to higher coal exports and increased barge fleet size partially offset by increases in expenses related to higher fuel, maintenance and flood-related costs.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Net Income from our AEP River Operations segment increased from $16 million in 2010 to $23 million in 2011 primarily due to higher grain shipping rates, increased coal exports, increased barge fleet size and the cost reduction initiatives recorded in the second quarter of 2010, partially offset by higher fuel, maintenance and flood-related costs.

GENERATION AND MARKETING

Third Quarter of 2011 Compared to Third Quarter of 2010

Net Income from our Generation and Marketing segment increased from $0 in 2010 to $8 million in 2011 primarily due to increased inception gains from ERCOT marketing activities and increased gross margins at the Oklaunion Plant.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Net Income from our Generation and Marketing segment increased from $17 million in 2010 to $20 million in 2011 primarily due to increased inception gains from ERCOT marketing activities and increased income from our wind farm operations partially offset by lower gross margins at the Oklaunion Plant.

ALL OTHER

Third Quarter of 2011 Compared to Third Quarter of 2010

Net Income from All Other decreased from a gain of $2 million in 2010 to a loss of $10 million in 2011 primarily due to favorable federal income tax adjustments in the third quarter of 2010.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Net Income from All Other decreased from a loss of $10 million in 2010 to a loss of $54 million in 2011 due to a $22 million net-of-tax loss incurred in the first quarter of 2011 related to the settlement of litigation with BOA and Enron and a $10 million net-of-tax gain on the sale of our remaining 138,000 shares of ICE in the second quarter of 2010.

AEP SYSTEM INCOME TAXES

Third Quarter of 2011 Compared to Third Quarter of 2010

Income Tax Expense increased $76 million primarily due to an increase in pretax book income.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Income Tax Expense increased $256 million primarily due to an increase in pretax book income and the unrealized capital loss valuation allowance related to a deferred tax asset associated with the settlement of litigation with BOA and Enron, offset in part by the 2010 tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.

FINANCIAL CONDITION

We measure our financial condition by the strength of our balance sheet and the liquidity provided by our cash flows. Target debt to equity ratios are included in our credit arrangements as covenants that must be met for borrowing to continue.

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

	September 30, 2011				December 31, 2010
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	16,450	50.7	%	$	16,811	52.8	%
Short-term Debt		1,279	3.9			1,346	4.2
Total Debt		17,729	54.6			18,157	57.0
Preferred Stock of Subsidiaries		60	0.2			60	0.2
AEP Common Equity		14,653	45.2			13,622	42.8

Total Debt and Equity Capitalization	$	32,442	100.0	%	$	31,839	100.0	%

Our ratio of debt-to-total capital decreased from 57% at December 31, 2010 to 54.6% at September 30, 2011. The decrease is due to increased equity, as a result of the third quarter 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts written off in 2005, and reduced debt.

In October 2011, we announced our intent to redeem all of the outstanding preferred stock of our subsidiaries in December 2011.

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 September 30, 2011, 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-leaseback or leasing agreements or common stock.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments. At September 30, 2011, our available liquidity was approximately $3.2 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			546
Total Liquidity Sources			3,796
Less:	AEP Commercial Paper Outstanding		529
	Letters of Credit Issued		103

Net Available Liquidity		$	3,164

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. In July 2011, we replaced the $1.5 billion facility due in 2012 with a new $1.75 billion facility maturing in July 2016 and extended the $1.5 billion facility due in 2013 to expire in June 2015.

In March 2011, we terminated a $478 million credit facility, used for letters of credit to support variable rate debt, that was scheduled to mature in April 2011. In March 2011, we issued bilateral letters of credit to support the remarketing of $357 million of the variable rate debt and reacquired the remaining $115 million which are held by a trustee on our behalf.

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 nine months of 2011 was $1.2 billion. The weighted-average interest rate for our commercial paper during 2011 was 0.38%.

Securitized Accounts Receivables

In July 2011, we renewed our receivables securitization agreement. The agreement provides a commitment of $750 million from bank conduits to purchase receivables with an increase to $800 million for the months of July, August and September to accommodate seasonal demand. A commitment of $375 million with the seasonal increase to $425 million for the months of July, August and September expires in June 2012 and the remaining commitment of $375 million expires in June 2014.

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 our 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 September 30, 2011, this contractually-defined percentage was 50.3%. Nonperformance under these covenants could result in an event of default under these credit agreements. At September 30, 2011, 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 either facility if a material adverse change occurs.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders. At September 30, 2011, 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 October 2011. Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. AEP’s income derives from our common stock equity in the earnings of our utility subsidiaries. Various charter provisions and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.

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

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

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.

	Nine Months Ended
	September 30,
	2011		2010
	(in millions)
Cash and Cash Equivalents at Beginning of Period	$	294	$	490
Net Cash Flows from Operating Activities		3,338		1,702
Net Cash Flows Used for Investing Activities		(1,967)		(1,575)
Net Cash Flows from (Used for) Financing Activities		(1,119)		473
Net Increase in Cash and Cash Equivalents		252		600
Cash and Cash Equivalents at End of Period	$	546	$	1,090

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

Operating Activities


	Nine Months Ended
	September 30,
	2011		2010
	(in millions)
Net Income	$	1,638	$	1,040
Depreciation and Amortization		1,258		1,237
Other		442		(575)
Net Cash Flows from Operating Activities	$	3,338	$	1,702

Net Cash Flows from Operating Activities were $3.3 billion in 2011 consisting primarily of Net Income of $1.6 billion and $1.3 billion of noncash Depreciation and Amortization. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. Following a Supreme Court of Texas opinion, we recorded an Extraordinary Item, Net of Tax of $273 million for the third quarter 2011 recognition of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005. We also recorded $261 million in Carrying Costs Income related to the TCC extraordinary item. A significant change in other items includes the favorable impact of a decrease in fuel inventory. 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. We also contributed $150 million to our qualified pension trust.

Net Cash Flows from Operating Activities were $1.7 billion in 2010 consisting primarily of Net Income of $1 billion and $1.2 billion of noncash Depreciation and Amortization. Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. Other includes a $656 million increase in securitized receivables under the application of new accounting guidance for “Transfers and Servicing” related to our sale of receivables agreement. Significant changes in other items include an increase in under-recovered fuel primarily due to the deferral of fuel under the FAC in Ohio and higher fuel costs in Oklahoma and the favorable impact of a decrease in fuel inventory. Deferred Income Taxes increased primarily due to bonus depreciation provisions in the American Recovery and Reinvestment Act of 2009, a change in tax accounting method and an increase in tax versus book temporary differences from operations. Due to these tax changes, Accrued Taxes, Net also increased primarily as a result of the receipt of a federal income tax refund of $419 million related to a net operating loss in 2009 that was carried back to 2007 and 2008. We also contributed $463 million to our qualified pension trust in 2010.

Investing Activities


	Nine Months Ended
	September 30,
	2011		2010
	(in millions)
Construction Expenditures	$	(1,849)	$	(1,629)
Acquisitions of Nuclear Fuel		(104)		(69)
Acquisition of Cushion Gas from BOA		(214)		-
Proceeds from Sales of Assets		116		160
Other		84		(37)
Net Cash Flows Used for Investing Activities	$	(1,967)	$	(1,575)

Net Cash Flows Used for Investing Activities were $2 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.

Net Cash Flows Used for Investing Activities were $1.6 billion in 2010 primarily due to Construction Expenditures for new generation, environmental, distribution and transmission investments. Proceeds from Sales of Assets in 2010 include $139 million for sales of Texas transmission assets to ETT.

Financing Activities


	Nine Months Ended
	September 30,
	2011		2010
	(in millions)
Issuance of Common Stock, Net	$	70	$	65
Issuance (Retirement) of Debt, Net		(469)		1,087
Dividends Paid on Common Stock		(668)		(602)
Other		(52)		(77)
Net Cash Flows from (Used for) Financing Activities	$	(1,119)	$	473

Net Cash Flows Used for Financing Activities in 2011 were $1.1 billion. Our net debt retirements were $469 million. The net retirements included retirements of $683 million of senior unsecured and other debt notes, $678 million of pollution control bonds, $159 million of securitization bonds and a decrease in short-term borrowing of $67 million offset by issuances of $600 million of senior unsecured notes and $526 million of pollution control bonds. We paid common stock dividends of $668 million. See Note 11 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows from Financing Activities were $473 million in 2010. Our net debt issuances were $1.1 billion. The net issuances included issuances of $884 million of notes and $326 million of pollution control bonds, a $594 million increase in commercial paper outstanding and retirements of $1 billion of senior unsecured notes, $148 million of securitization bonds and $222 million of pollution control bonds. Our short-term debt securitized by receivables increased $656 million under the application of new accounting guidance for “Transfers and Servicing” related to our sale of receivables agreement. We paid common stock dividends of $602 million.

In October 2011, APCo remarketed $100 million of 2% Pollution Control Bonds due in 2014.

In October 2011, I&M retired $29 million of Notes Payable related to DCC Fuel.

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 policy restricts 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:

	September 30,		December 31,
	2011		2010
	(in millions)
Rockport Plant Unit 2 Future Minimum Lease Payments	$	1,700	$	1,774
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 2010 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

A summary of our contractual obligations is included in our 2010 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.

MINE SAFETY INFORMATION

The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations. The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters. SWEPCo, through its ownership of DHLC, CSPCo, through its ownership of Conesville Coal Preparation Company (CCPC), and OPCo, through its use of the Conner Run fly ash impoundment, are subject to the provisions of the Mine Act.

The Dodd-Frank Wall Street Reform and Consumer Protection Act requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. DHLC, CCPC and Conner Run received the following notices of violation and proposed assessments under the Mine Act for the quarter ended September 30, 2011:

		DHLC		CCPC		Conner Run
Number of Citations for Violations of Mandatory Health or
	Safety Standards under 104 *		2		-		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	$	-	$	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 are related to actions challenging four violations issued by Mine Safety and Health Administration following an employee fatality in March 2009 and the third legal action is challenging a citation issued in August 2010 related to a dragline boom issue.

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 2010 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.

NEW ACCOUNTING PRONOUNCEMENTS

Pronouncements Effective in the Future

periods beginning after December 15, 2011. Early adoption is permitted. The FASB is currently considering deferral of reclassification adjustment presentation provisions of ASU 2011-05. Absent a deferral of this accounting guidance in its entirety, we expect to adopt ASU 2011-05 for the 2011 Annual Report.

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 statements, contingencies, financial instruments, emission allowances, leases, insurance, hedge accounting, consolidation policy and discontinued operations. We also expect to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP. The ultimate pronouncements resulting from these and future projects could have an impact on our future net income and financial position.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET 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 because occasionally we procure various services and materials used in our energy business from foreign suppliers. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

Our Generation and Marketing segment, operating primarily within ERCOT and, to a lesser extent, Ohio in PJM and MISO, primarily transacts in wholesale energy marketing contracts. This segment is exposed to certain market risks as a marketer of wholesale electricity. These risks include commodity price risk, interest rate risk and credit risk. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

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

We employ risk management contracts including physical forward purchase and sale contracts and financial forward purchase and sale contracts. We engage in risk management of 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 group in accordance with the market risk policy approved by the Finance Committee of our Board of Directors. Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The CORC consists of our President, Chief Financial Officer, Senior Vice President of Commercial Operations and Chief Risk Officer. When commercial activities exceed predetermined limits, we modify the positions to reduce the risk to be within the limits unless specifically approved by the CORC.

The following table summarizes the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2010:

	MTM Risk Management Contract Net Assets (Liabilities)
	Nine Months Ended September 30, 2011

				Generation
		Utility		and
		Operations		Marketing		All Other		Total
		(in millions)
Total MTM Risk Management Contract Net Assets
	at December 31, 2010	$	91	$	140	$	2	$	233
(Gain) Loss from Contracts Realized/Settled During the Period and
	Entered in a Prior Period		(23)		(17)		(2)		(42)
Fair Value of New Contracts at Inception When Entered During the
	Period (a)		3		14		-		17
Net Option Premiums Received for Unexercised or Unexpired
	Option Contracts Entered During the Period		-		-		-		-
Changes in Fair Value Due to Market Fluctuations During the
	Period (b)		5		4		-		9
Changes in Fair Value Allocated to Regulated Jurisdictions (c)			2		-		-		2
Total MTM Risk Management Contract Net Assets
	at September 30, 2011	$	78	$	141	$	-		219

Commodity Cash Flow Hedge Contracts									19
Interest Rate and Foreign Currency Cash Flow Hedge Contracts									(34)
Fair Value Hedge Contracts									-
Collateral Deposits									30
Total MTM Derivative Contract Net Assets at September 30, 2011								$	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 8 – Derivatives and Hedging and Note 9 – 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 September 30, 2011, our credit exposure net of collateral to sub investment grade counterparties was approximately 5.5%, 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 September 30, 2011, 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		$	534	$	1	$	533		1	$	158
Split Rating			1		-		1		1		1
Noninvestment Grade			2		2		-		1		-
No External Ratings:
	Internal Investment Grade		192		-		192		1		76
	Internal Noninvestment Grade		52		10		42		1		36
Total as of September 30, 2011		$	781	$	13	$	768		5	$	271

Total as of December 31, 2010		$	946	$	33	$	913		7	$	347

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 September 30, 2011, 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

Nine Months Ended								Twelve Months Ended
September 30, 2011								December 31, 2010
End		High		Average		Low		End		High		Average		Low
(in millions)								(in millions)
$	-	$	2	$	-	$	-	$	-	$	2	$	1	$	-

We back-test our VaR results against performance due to actual price movements. Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.

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 September 30, 2011 and December 31, 2010, the estimated EaR on our debt portfolio for the following twelve months was $23 million and $5 million, respectively.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2011 and 2010
(in millions, except per-share and share amounts)
(Unaudited)

		Three Months Ended				Nine Months Ended
		2011		2010		2011		2010
REVENUES
Utility Operations		$	4,044	$	3,876	$	10,901	$	10,468
Other Revenues			289		188		771		525
TOTAL REVENUES			4,333		4,064		11,672		10,993
EXPENSES
Fuel and Other Consumables Used for Electric Generation			1,371		1,189		3,407		3,098
Purchased Electricity for Resale			294		247		856		712
Other Operation			747		707		2,130		2,374
Maintenance			283		262		864		776
Asset Impairments and Other Related Charges			90		-		90		-
Depreciation and Amortization			445		424		1,258		1,237
Taxes Other Than Income Taxes			213		210		628		619
TOTAL EXPENSES			3,443		3,039		9,233		8,816

OPERATING INCOME			890		1,025		2,439		2,177

Other Income (Expense):
Interest and Investment Income			19		3		24		24
Carrying Costs Income			291		18		323		51
Allowance for Equity Funds Used During Construction			26		17		69		60
Interest Expense			(242)		(251)		(723)		(750)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS			984		812		2,132		1,562

Income Tax Expense			334		258		786		530
Equity Earnings of Unconsolidated Subsidiaries			7		3		19		8

INCOME BEFORE EXTRAORDINARY ITEM			657		557		1,365		1,040

EXTRAORDINARY ITEM, NET OF TAX			273		-		273		-

NET INCOME			930		557		1,638		1,040

Less: Net Income Attributable to Noncontrolling Interests			1		1		3		3

NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS			929		556		1,635		1,037

Less: Preferred Stock Dividend Requirements of Subsidiaries			1		1		2		2

EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	928	$	555	$	1,633	$	1,035

WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING			482,498,734		479,578,139		481,862,128		479,023,690

BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
Income Before Extraordinary Item		$	1.35	$	1.16	$	2.82	$	2.16
Extraordinary Item, Net of Tax			0.57		-		0.57		-

TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS		$	1.92	$	1.16	$	3.39	$	2.16

WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING			482,796,945		479,750,447		482,126,964		479,261,415

DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
Income Before Extraordinary Item		$	1.35	$	1.16	$	2.82	$	2.16
Extraordinary Item, Net of Tax			0.57		-		0.57		-

TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
	SHAREHOLDERS	$	1.92	$	1.16	$	3.39	$	2.16

CASH DIVIDENDS DECLARED PER SHARE		$	0.46	$	0.42	$	1.38	$	1.25

See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY AND
COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2011 and 2010
(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, 2009					498	$	3,239	$	5,824	$	4,451	$	(374)	$	-	$	13,140

Issuance of Common Stock					2		13		53								66
Common Stock Dividends											(599)				(3)		(602)
Preferred Stock Dividend Requirements of
	Subsidiaries										(2)						(2)
Other Changes in Equity									4								4
SUBTOTAL – EQUITY																	12,606

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
	Taxes:
		Cash Flow Hedges, Net of Tax of $1											2				2
		Securities Available for Sale, Net of Tax of $5											(9)				(9)
		Amortization of Pension and OPEB Deferred
			Costs, Net of Tax of $9										17				17
NET INCOME											1,037				3		1,040
TOTAL COMPREHENSIVE INCOME																	1,050

TOTAL EQUITY – SEPTEMBER 30, 2010					500	$	3,252	$	5,881	$	4,887	$	(364)	$	-	$	13,656

TOTAL EQUITY – DECEMBER 31, 2010					501	$	3,257	$	5,904	$	4,842	$	(381)	$	-	$	13,622

Issuance of Common Stock					2		14		56								70
Common Stock Dividends											(665)				(3)		(668)
Preferred Stock Dividend Requirements of
	Subsidiaries										(2)						(2)
Other Changes in Equity									(8)								(8)
SUBTOTAL – EQUITY																	13,014

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
	Taxes:
		Cash Flow Hedges, Net of Tax of $8											(14)				(14)
		Securities Available for Sale, Net of Tax of $2											(3)				(3)
		Amortization of Pension and OPEB Deferred
			Costs, Net of Tax of $9										18				18
NET INCOME											1,635				3		1,638
TOTAL COMPREHENSIVE INCOME																	1,639

TOTAL EQUITY – SEPTEMBER 30, 2011					503	$	3,271	$	5,952	$	5,810	$	(380)	$	-	$	14,653

See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2011 and December 31, 2010
(in millions)
(Unaudited)

			2011		2010
CURRENT ASSETS
Cash and Cash Equivalents			$	546	$	294
Other Temporary Investments
	(September 30, 2011 and December 31, 2010 amounts include $211 and $287, respectively, related to Transition Funding and EIS)			240		416
Accounts Receivable:
	Customers			622		683
	Accrued Unbilled Revenues			139		195
	Pledged Accounts Receivable - AEP Credit			1,024		949
	Miscellaneous			109		137
	Allowance for Uncollectible Accounts			(34)		(41)
		Total Accounts Receivable		1,860		1,923
Fuel				544		837
Materials and Supplies				629		611
Risk Management Assets				164		232
Accrued Tax Benefits				78		389
Regulatory Asset for Under-Recovered Fuel Costs				78		81
Margin Deposits				62		88
Prepayments and Other Current Assets				173		145
TOTAL CURRENT ASSETS				4,374		5,016

PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			24,666		24,352
	Transmission			8,826		8,576
	Distribution			14,620		14,208
Other Property, Plant and Equipment (including nuclear fuel and coal mining)				3,880		3,846
Construction Work in Progress				3,105		2,758
Total Property, Plant and Equipment				55,097		53,740
Accumulated Depreciation and Amortization				18,680		18,066
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET				36,417		35,674

OTHER NONCURRENT ASSETS
Regulatory Assets				5,731		4,943
Securitized Transition Assets				1,625		1,742
Spent Nuclear Fuel and Decommissioning Trusts				1,513		1,515
Goodwill				76		76
Long-term Risk Management Assets				316		410
Deferred Charges and Other Noncurrent Assets				1,135		1,079
TOTAL OTHER NONCURRENT ASSETS				10,396		9,765

TOTAL ASSETS			$	51,187	$	50,455

See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2011 and December 31, 2010
(dollars in millions)
(Unaudited)

					2011		2010
CURRENT LIABILITIES
Accounts Payable					$	1,003	$	1,061
Short-term Debt:
	Securitized Debt for Receivables - AEP Credit					750		690
	Other Short-term Debt					529		656
		Total Short-term Debt				1,279		1,346
Long-term Debt Due Within One Year
	(September 30, 2011 and December 31, 2010 amounts include $264 and $237, respectively, related to Transition Funding, DCC Fuel and Sabine)					1,267		1,309
Risk Management Liabilities						113		129
Customer Deposits						280		273
Accrued Taxes						501		702
Accrued Interest						235		281
Regulatory Liability for Over-Recovered Fuel Costs						2		17
Deferred Gain and Accrued Litigation Costs						-		448
Other Current Liabilities						1,004		952
TOTAL CURRENT LIABILITIES						5,684		6,518

NONCURRENT LIABILITIES
Long-term Debt
	(September 30, 2011 and December 31, 2010 amounts include $1,625 and $1,857, respectively, related to Transition Funding, DCC Fuel and Sabine)					15,183		15,502
Long-term Risk Management Liabilities						133		141
Deferred Income Taxes						8,108		7,359
Regulatory Liabilities and Deferred Investment Tax Credits						3,229		3,171
Asset Retirement Obligations						1,441		1,394
Employee Benefits and Pension Obligations						1,718		1,893
Deferred Credits and Other Noncurrent Liabilities						978		795
TOTAL NONCURRENT LIABILITIES						30,790		30,255

TOTAL LIABILITIES						36,474		36,773

Cumulative Preferred Stock Not Subject to Mandatory Redemption						60		60

Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

EQUITY
Common Stock – Par Value – $6.50 Per Share:
			2011	2010
	Shares Authorized		600,000,000	600,000,000
	Shares Issued		503,177,402	501,114,881
(20,307,725 shares were held in treasury at September 30, 2011 and December 31, 2010)						3,271		3,257
Paid-in Capital						5,952		5,904
Retained Earnings						5,810		4,842
Accumulated Other Comprehensive Income (Loss)						(380)		(381)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY						14,653		13,622

TOTAL EQUITY						14,653		13,622

TOTAL LIABILITIES AND EQUITY					$	51,187	$	50,455

See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2011 and 2010
(in millions)
(Unaudited)

			2011		2010
OPERATING ACTIVITIES
Net Income			$	1,638	$	1,040
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			1,258		1,237
	Deferred Income Taxes			764		404
	Gain on Settlement with BOA and Enron			(51)		-
	Settlement of Litigation with BOA and Enron			(211)		-
	Extraordinary Item, Net of Tax			(273)		-
	Asset Impairments and Other Related Charges			90		-
	Carrying Costs Income			(323)		(51)
	Allowance for Equity Funds Used During Construction			(69)		(60)
	Mark-to-Market of Risk Management Contracts			84		(108)
	Amortization of Nuclear Fuel			108		113
	Pension Contributions to Qualified Plan Trust			(150)		(463)
	Property Taxes			173		157
	Fuel Over/Under-Recovery, Net			(94)		(233)
	Change in Other Noncurrent Assets			(32)		(50)
	Change in Other Noncurrent Liabilities			225		183
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		51		(766)
		Fuel, Materials and Supplies		275		240
		Margin Deposits		26		3
		Accounts Payable		(66)		(163)
		Accrued Taxes, Net		(42)		223
		Accrued Interest		(46)		(32)
		Other Current Assets		(13)		35
		Other Current Liabilities		16		(7)
Net Cash Flows from Operating Activities				3,338		1,702

INVESTING ACTIVITIES
Construction Expenditures				(1,849)		(1,629)
Change in Other Temporary Investments, Net				62		63
Purchases of Investment Securities				(1,024)		(1,542)
Sales of Investment Securities				1,094		1,477
Acquisitions of Nuclear Fuel				(104)		(69)
Acquisitions of Assets				(10)		(16)
Acquisition of Cushion Gas from BOA				(214)		-
Proceeds from Sales of Assets				116		160
Other Investing Activities				(38)		(19)
Net Cash Flows Used for Investing Activities				(1,967)		(1,575)

FINANCING ACTIVITIES
Issuance of Common Stock, Net				70		65
Issuance of Long-term Debt				1,118		1,201
Commercial Paper and Credit Facility Borrowings				462		195
Change in Short-term Debt, Net				290		1,223
Retirement of Long-term Debt				(1,520)		(1,454)
Commercial Paper and Credit Facility Repayments				(819)		(78)
Principal Payments for Capital Lease Obligations				(53)		(74)
Dividends Paid on Common Stock				(668)		(602)
Dividends Paid on Cumulative Preferred Stock				(2)		(2)
Other Financing Activities				3		(1)
Net Cash Flows from (Used for) Financing Activities				(1,119)		473

Net Increase in Cash and Cash Equivalents				252		600
Cash and Cash Equivalents at Beginning of Period				294		490
Cash and Cash Equivalents at End of Period			$	546	$	1,090

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	716	$	755
Net Cash Paid (Received) for Income Taxes				(119)		(243)
Noncash Acquisitions Under Capital Leases				39		190
Government Grants Included in Accounts Receivable at September 30,				2		-
Construction Expenditures Included in Current Liabilities at September 30,				304		229
Noncash Increase in Long-term Debt Through the Fort Wayne Lease Settlement				27		-

See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX OF CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


1.	Significant Accounting Matters
2.	New Accounting Pronouncements and Extraordinary Item
3.	Rate Matters
4.	Commitments, Guarantees and Contingencies
5.	Acquisition, Dispositions and Impairments
6.	Benefit Plans
7.	Business Segments
8.	Derivatives and Hedging
9.	Fair Value Measurements
10.	Income Taxes
11.	Financing Activities
12.	Cost Reduction Initiatives

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 nine months ended September 30, 2011 is not necessarily indicative of results that may be expected for the year ending December 31, 2011. The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2010 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 25, 2011.

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 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 September 30, 2011 and 2010 were $33 million and $30 million, respectively, and for the nine months ended September 30, 2011 and 2010 were $97 million and $103 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 expense to the

protected cell for the three months ended September 30, 2011 and 2010 was $16 million and $15 million, respectively, and for the nine months ended September 30, 2011 and 2010 was $46 million and $33 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 and DCC Fuel III 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. DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC are separate legal entities from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the DCC Fuel LLC and DCC Fuel II LLC leases are made semi-annually and began in April 2010 and October 2010, respectively. Payments on the DCC Fuel III LLC lease are made monthly and began in January 2011. Payments on the DCC Fuel leases for the three months ended September 30, 2011 and 2010 were $6 million and $0, respectively, and for the nine months ended September 30, 2011 and 2010 were $49 million and $22 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 48, 54 and 54 month lease term, respectively. Based on our control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the tables below for the classification of DCC Fuel’s assets and liabilities on our 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 11.

Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas restructuring law. Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant. Therefore, TCC is required to consolidate Transition Funding. The securitized bonds totaled $1.7 billion and $1.8 billion at September 30, 2011 and December 31, 2010, respectively, and are included in current and long-term debt on the condensed balance sheets. Transition Funding has securitized transition assets of $1.6 billion and $1.7 billion at September 30, 2011 and December 31 2010, 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 asset 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

September 30, 2011

(in millions)


									TCC
	SWEPCo		I&M		Protected Cell				Transition
	Sabine		DCC Fuel		of EIS		AEP Credit		Funding
ASSETS
Current Assets	$	43	$	93	$	126	$	1,013	$	162
Net Property, Plant and Equipment		143		104		-		-		-
Other Noncurrent Assets		26		67		7		1		1,629
Total Assets	$	212	$	264	$	133	$	1,014	$	1,791

LIABILITIES AND EQUITY
Current Liabilities	$	50	$	75	$	46	$	962	$	206
Noncurrent Liabilities		162		189		73		1		1,571
Equity		-		-		14		51		14
Total Liabilities and Equity	$	212	$	264	$	133	$	1,014	$	1,791

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

VARIABLE INTEREST ENTITIES

December 31, 2010

(in millions)


									TCC
	SWEPCo		I&M		Protected Cell				Transition
	Sabine		DCC Fuel		of EIS		AEP Credit		Funding
ASSETS
Current Assets	$	50	$	92	$	131	$	924	$	214
Net Property, Plant and Equipment		139		173		-		-		-
Other Noncurrent Assets		34		112		1		10		1,746
Total Assets	$	223	$	377	$	132	$	934	$	1,960

LIABILITIES AND EQUITY
Current Liabilities	$	33	$	79	$	33	$	886	$	221
Noncurrent Liabilities		190		298		85		1		1,725
Equity		-		-		14		47		14
Total Liabilities and Equity	$	223	$	377	$	132	$	934	$	1,960

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 its 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 September 30, 2011 and 2010 were $18 million and $14 million, respectively, and for the nine months ended September 30, 2011 and 2010 were $47 million and $40 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:

	September 30, 2011						December 31, 2010
	As Reported on			Maximum			As Reported on			Maximum
	the Balance Sheet			Exposure			the Balance Sheet			Exposure
	(in millions)
Capital Contribution from SWEPCo		$	8		$	8		$	6		$	6
Retained Earnings			1			1			2			2
SWEPCo's Guarantee of Debt			-			49			-			48

Total Investment in DHLC		$	9		$	58		$	8		$	56

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 September 30, 2011, PATH-WV had no debt outstanding. However, when debt is issued, the debt to equity ratio in each series should be consistent with other regulated utilities. The entities recover costs through regulated rates.

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

Our investment in PATH-WV was:

	September 30, 2011						December 31, 2010
	As Reported on			Maximum			As Reported on			Maximum
	the Balance Sheet			Exposure			the Balance Sheet			Exposure
				(in millions)
Capital Contribution from AEP		$	19		$	19		$	18		$	18
Retained Earnings			9			9			6			6

Total Investment in PATH-WV		$	28		$	28		$	24		$	24

Earnings Per Share (EPS)

Shown below are income statement amounts attributable to AEP common shareholders:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
Amounts Attributable to AEP Common Shareholders	2011		2010		2011		2010
	(in millions)
Income Before Extraordinary Item	$	655	$	555	$	1,360	$	1,035
Extraordinary Item, Net of Tax		273		-		273		-
Net Income	$	928	$	555	$	1,633	$	1,035

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 September 30,
		2011				2010
		(in millions, except per share data)
				$/share				$/share
Earnings Attributable to AEP Common Shareholders		$	928			$	555

Weighted Average Number of Basic Shares Outstanding			482.5	$	1.92		479.6	$	1.16
Weighted Average Dilutive Effect of:
	Stock Options		0.1		-		0.1		-
	Restricted Stock Units		0.2		-		0.1		-
Weighted Average Number of Diluted Shares Outstanding			482.8	$	1.92		479.8	$	1.16

		Nine Months Ended September 30,
		2011				2010
		(in millions, except per share data)
				$/share				$/share
Earnings Attributable to AEP Common Shareholders		$	1,633			$	1,035

Weighted Average Number of Basic Shares Outstanding			481.9	$	3.39		479.0	$	2.16
Weighted Average Dilutive Effect of:
	Performance Share Units		-		-		0.1		-
	Stock Options		-		-		0.1		-
	Restricted Stock Units		0.2		-		0.1		-
Weighted Average Number of Diluted Shares Outstanding			482.1	$	3.39		479.3	$	2.16

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 136,250 shares of common stock were outstanding at September 30, 2011 and 2010, respectively, but were not included in the computation of diluted earnings per share attributable to AEP common shareholders. Since the options’ exercise prices were greater than the average market price of the common shares, the effect would have been antidilutive.

2. NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM

NEW ACCOUNTING PRONOUNCEMENTS

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

Pronouncements Issued During 2011

The following standard was issued during the first nine months of 2011. The following paragraphs discuss its impact on future financial statements.

ASU 2011-05 “Presentation of Comprehensive Income” (ASU 2011-05)

In June 2011, the FASB issued ASU 2011-05 eliminating the option to present the components of other comprehensive income as a part of the statement of shareholders’ equity. The standard requires other comprehensive income be presented as part of a single continuous statement of comprehensive income or in a statement of other comprehensive income immediately following the statement of net income.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2011. Early adoption is permitted. This standard must be retrospectively applied to all reporting periods presented in financial reports issued after the effective date. This standard will change the presentation of our financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. The FASB is currently considering deferral of reclassification adjustment presentation provisions of ASU 2011-05. Absent a deferral of this accounting guidance in its entirety, we expect to adopt ASU 2011-05 for the 2011 Annual Report.

EXTRAORDINARY ITEM

In February 2006, the PUCT issued an order that denied recovery of capacity auction true-up amounts. Based on the February 2006 PUCT order, TCC recorded the disallowance as a $421 million ($273 million, net of tax) extraordinary loss in the December 31, 2005 financial statements. In July 2011, the Supreme Court of Texas reversed the PUCT’s February 2006 disallowance of capacity auction true-up amounts. In September 2011, the PUCT issued a preliminary order in a remand proceeding. Based upon the Supreme Court of Texas opinion, TCC recorded a pretax gain of $421 million ($273 million, net of tax) in Extraordinary Item, Net of Tax on the condensed statements of income in the third quarter of 2011. See “Texas Restructuring” section of Note 3.

3. RATE MATTERS

As discussed in the 2010 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 2010 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 2011 and updates the 2010 Annual Report.

Regulatory Assets Not Yet Being Recovered

			September 30,		December 31,
			2011		2010
			(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
	Capacity Auction True-Up - TCC		$	682	$	-
	Line Extension Carrying Costs - CSPCo, OPCo			64		55
	Customer Choice Deferrals - CSPCo, OPCo			60		59
	Storm Related Costs - CSPCo, OPCo			31		30
	Storm Related Costs - TCC			25		25
	Economic Development Rider - CSPCo, OPCo			12		6
	Acquisition of Monongahela Power - CSPCo			9		8
	Other Regulatory Assets Not Yet Being Recovered			1		1
Regulatory Assets Currently Not Earning a Return
	Environmental Rate Adjustment Clause - APCo			73		56
	Deferred Wind Power Costs - APCo			40		29
	Storm Related Costs - APCo, KGPCo			27		28
	Mountaineer Carbon Capture and Storage Product Validation Facility - APCo			19		60
	Special Rate Mechanism for Century Aluminum - APCo			13		13
	Mountaineer Carbon Capture and Storage Commercial Scale Facility - APCo,
		I&M, KPCo, PSO, SWEPCo		12		-
	Litigation Settlement - I&M			11		-
	Acquisition of Monongahela Power - CSPCo			4		4
	Storm Related Costs - PSO			-		17
	Other Regulatory Assets Not Yet Being Recovered			6		4
Total Regulatory Assets Not Yet Being Recovered			$	1,089	$	395

CSPCo and OPCo Rate Matters

Ohio Electric Security Plan Filings

2009 – 2011 ESPs

The PUCO issued an order in March 2009 that modified and approved CSPCo’s and OPCo’s ESPs which established rates at the start of the April 2009 billing cycle through 2011. The order also limited annual rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011. Some rate components and increases are exempt from these limitations. CSPCo and OPCo collected the 2009 annualized revenue increase over the last nine months of 2009. In November 2009, the PUCO’s order was appealed to the Supreme Court of Ohio (the Court). In April 2011, the Court issued an opinion and remanded certain issues back to the PUCO.

In October 2011, the PUCO issued an order in the remand proceeding. The order required CSPCo and OPCo to refund Provider of Last Resort (POLR) charges which were collected subject to refund since June 2011. According to the order, CSPCo and OPCo are required to apply the refund first to the FAC deferral with any remaining balance to be credited to CSPCo’s and OPCo’s customers in November and December 2011. As a result, in the third quarter of 2011, CSPCo and OPCo recorded pretax refund provisions of $34 million and $9 million, respectively, on the condensed statements of income. The PUCO order also agreed with CSPCo’s and OPCo’s position that the ESP statute provided a legal basis for reflecting an environmental carrying charge in CSPCo’s and OPCo’s base generation rates. In addition, the PUCO rejected the intervenors’ proposed adjustments to the FAC deferral balance for POLR charges and environmental carrying charges for the period from April 2009 through May 2011. This decision is subject to rehearing and appeal.

In April 2010, the Industrial Energy Users-Ohio (IEU) filed an additional notice of appeal with the Court challenging alleged retroactive ratemaking, CSPCo and OPCo's abilities to collect through the FAC amounts deferred under the Ormet interim arrangement and the approval of the plan after the 150-day statutory deadline. In June 2011, the Court affirmed the PUCO’s decision and dismissed the IEU’s appeal.

In January 2011, the PUCO issued an order on CSPCo’s and OPCo’s 2009 SEET filings and determined that OPCo’s 2009 earnings were not significantly excessive but determined relevant CSPCo earnings exceeded the PUCO determined threshold by 2.13%. As a result, the PUCO ordered CSPCo to refund $43 million of its pretax earnings to customers, which was recorded as a revenue provision on CSPCo’s December 2010 books. The PUCO ordered that the significantly excessive earnings be applied first to CSPCo’s FAC deferral, including unrecognized equity carrying costs, as of the date of the order, with any remaining balance to be credited to CSPCo’s customers on a per kilowatt basis. That credit began with the first billing cycle in February 2011 and will continue through December 2011. Several parties, including CSPCo and OPCo, filed requests for rehearing with the PUCO, which were denied in March 2011. In May 2011, the IEU and the Ohio Energy Group filed appeals with the Court challenging the PUCO’s SEET decisions.

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

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

In September 2011, a stipulation agreement was filed with the PUCO by CSPCo, OPCo, the PUCO staff and multiple other parties which involved various issues pending before the PUCO, including the approval of the CSPCo/OPCo merger and the recovery of deferred fuel until securitized. The FAC deferral as of September 30, 2011 was $542 million for OPCo, excluding $40 million of unrecognized equity carrying costs. CSPCo did not have a FAC deferral as of September 30, 2011. Under the stipulation agreement, rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2016. Prior to June 2015, CSPCo’s and OPCo’s SSO customers continue to pay the tariff rate for non-fuel generation and the fuel adjustment clause. Beginning in June 2015, CSPCo and OPCo will use results from a competitive bidding process performed prior to January 2015 to meet their SSO obligation through May 2016. The stipulation agreement proposed a corporate separation plan of CSPCo’s and OPCo’s generation assets to complete the transition to a fully competitive generation market by June 2015. In addition, to further develop customer choice and facilitate the transition to market generation pricing, CSPCo and OPCo will provide 21% of their generation capacity in 2012, 29% to 31% of their generation capacity in 2013 and 41% of their generation capacity beginning in 2014 through May 2015 to competitive retail suppliers at a charge based on the Reliability Pricing Model auction-clearing prices and the remainder at a discounted cost-based price.

The stipulation agreement also proposed a termination or modification of the Interconnection Agreement. See the “Possible Termination of the Interconnection Agreement” section of FERC rate matters. The current FAC mechanism would continue through May 2015. Finally, the stipulation agreement provides for certain CSPCo and OPCo contingent contributions and established a Distribution Investment Rider beginning January 2012 through May 2015 to recover post-2000 distribution investment with certain limitations.

Various intervenors who did not sign the stipulation agreement filed testimony that generally asserts CSPCo’s and OPCo’s proposed SSO rates are higher than the market-rate offer and that the proposed capacity charges to competitive retail suppliers are anti-competitive. Hearings on the stipulation agreement are ongoing. A decision from the PUCO is expected in the fourth quarter of 2011. If OPCo is not ultimately permitted to fully recover its FAC deferral, it would reduce future net income and cash flows and impact financial condition.

2011 Ohio Distribution Base Rate Case

In addition to the annual increases, CSPCo and OPCo requested recovery of the projected December 31, 2012 balances of certain distribution regulatory assets of $216 million and $159 million, respectively, including approximately $102 million and $84 million, respectively, of unrecognized equity carrying costs. These assets and unrecognized carrying costs would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013. The actual balance of these distribution regulatory assets as of September 30, 2011 was $102 million and $66 million for CSPCo and OPCo, respectively, excluding $64 million and $48 million, respectively, of unrecognized equity carrying costs.

In September 2011, the PUCO staff filed testimony that recommended a rate reduction for CSPCo in the range of $2 million to $10 million and a rate increase for OPCo in the range of $23 million to $32 million based upon a return on common equity range of 8.58% to 9.6%. In addition, the PUCO staff recommended recovery of the deferred distribution regulatory assets subject to a review of the carrying costs. A decision from the PUCO is expected in the fourth quarter of 2011. If CSPCo and OPCo are not ultimately permitted to fully recover their deferrals, it would reduce future net income and cash flows and impact financial condition.

Proposed CSPCo and OPCo Merger

In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo. Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company. In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo. In July 2011, the FERC issued an order approving the proposed merger. In September 2011, a stipulation agreement was filed with the PUCO which recommended CSPCo merge into OPCo by the end of 2011. A decision from the PUCO is expected in the fourth quarter of 2011. See “January 2012 – May 2016 ESP” section above.

Sporn Unit 5

In October 2010, OPCo filed an application with the PUCO for the approval of a December 2010 closure of Sporn Unit 5 and the simultaneous establishment of a new non-bypassable distribution rider outside the rate caps established in the 2009 – 2011 ESP proceeding. In April 2011, intervenors filed comments opposing OPCo’s application. A PUCO decision is pending as to whether a hearing will be ordered.

In the third quarter of 2011, management decided to no longer offer Sporn Unit 5 into the PJM market. Sporn Unit 5 is not expected to operate in the future, resulting in the removal of Sporn Unit 5 from the AEP Power Pool. As a result, in the third quarter of 2011, OPCo recorded a pretax write-off of $48 million in Asset Impairments and Other Related Charges on the condensed statements of income.

2009 Fuel Adjustment Clause Audit

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

2010 Fuel Adjustment Clause Audit

In May 2011, the PUCO-selected outside consultant issued its results of the 2010 FAC audit for CSPCo and OPCo. The audit report included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balances and determine whether the carrying costs on the balances should be net of accumulated income taxes. As of September 30, 2011, the amount of OPCo’s carrying costs that could potentially be at risk is estimated to be $12 million, excluding $14 million of unrecognized equity carrying costs. The amount of carrying costs for CSPCo that could potentially be at risk is immaterial. A decision from the PUCO is pending. Management is unable to predict the outcome of this proceeding. If the PUCO order results in a reduction in the carrying charges related to the FAC deferrals, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

FAC related to the interim arrangement including recognized carrying charges. These amounts exclude $1 million and $1 million, respectively, of unrecognized equity carrying costs. In November 2009, CSPCo and OPCo requested that the PUCO approve recovery of the deferrals under the interim agreement plus a weighted average cost of capital carrying charge. The interim arrangement deferrals are included in CSPCo’s and OPCo’s FAC phase-in deferral balances. See “Ohio Electric Security Plan Filings” section above. In the ESP proceeding, intervenors requested that CSPCo and OPCo be required to refund the Ormet-related regulatory assets and requested that the PUCO prevent CSPCo and OPCo from collecting the Ormet-related revenues in the future. The PUCO did not take any action on this request in the 2009-2011 ESP proceeding. The intervenors raised the issue again in response to CSPCo’s and OPCo’s November 2009 filing to approve recovery of the deferrals under the interim agreement and this issue remains pending before the PUCO. If CSPCo and OPCo are not ultimately permitted to fully recover their requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.

Economic Development Rider

In April 2010, the Industrial Energy Users-Ohio (IEU) filed a notice of appeal of the 2009 PUCO-approved Economic Development Rider (EDR) with the Supreme Court of Ohio. The EDR collects from ratepayers the difference between the standard tariff and lower contract billings to qualifying industrial customers, subject to PUCO approval. The IEU raised several issues including claims that: (a) the PUCO lost jurisdiction over CSPCo’s and OPCo’s ESP proceedings and related proceedings when the PUCO failed to issue ESP orders within the 150-day statutory deadline, (b) the EDR should not be exempt from the ESP annual rate limitations and (c) CSPCo and OPCo should not be allowed to apply a weighted average long-term debt carrying cost on deferred EDR regulatory assets. In June 2011, the Supreme Court of Ohio affirmed the PUCO’s decision and dismissed the IEU’s appeal.

In June 2010, the IEU filed a notice of appeal of the 2010 PUCO-approved EDR with the Supreme Court of Ohio raising the same issues as noted in the 2009 EDR appeal. In addition, the IEU added a claim that CSPCo and OPCo should not be able to take the benefits of the higher ESP rates while simultaneously challenging the ESP orders. In June 2011, the IEU voluntarily dismissed the 2010 EDR appeal issues that were the same issues dismissed by the Supreme Court of Ohio in their 2009 EDR appeal referenced above. In August 2011, the Supreme Court of Ohio affirmed the PUCO’s decision on the remaining issues.

Ohio IGCC Plant

In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. Through September 30, 2011, CSPCo and OPCo have collected $12 million and $12 million, respectively, in pre-construction costs authorized in a June 2006 PUCO order and incurred $11 million and $11 million, respectively, in pre-construction costs. As a result, CSPCo and OPCo established net regulatory liabilities of approximately $1 million and $1 million, respectively. The order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant before June 2011, any pre-construction costs that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest. As of June 2011, there were no active IGCC projects at other AEP sites. In June 2011, CSPCo and OPCo filed a recommendation with the PUCO to refund to customers $2 million and $2 million, respectively, for the over-recovered pre-construction costs including interest. 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 any cost recovery litigation concerning the Ohio IGCC plant or what effect, if any, such litigation would have on future net income and cash flows. However, if CSPCo and OPCo are required to refund pre-construction costs collected in excess of the over-recovered pre-construction costs, it would reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in service in 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility. The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, plus an additional $129 million for transmission, excluding AFUDC. SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $129 million for transmission, excluding AFUDC. As of September 30, 2011, excluding costs attributable to its joint owners, SWEPCo has capitalized approximately $1.3 billion of expenditures (including AFUDC and capitalized interest of $197 million and related transmission costs of $88 million). As of September 30, 2011, the joint owners and SWEPCo have contractual construction commitments of approximately $163 million (including related transmission costs of $13 million). SWEPCo’s share of the contractual construction commitments is $123 million. If the plant is cancelled, the joint owners and SWEPCo would incur contractual construction cancellation fees, based on construction status as of September 30, 2011, of approximately $101 million (including related transmission cancellation fees of $1 million). SWEPCo’s share of the contractual construction cancellation fees would be approximately $74 million.

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

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

The PUCT issued an order approving a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers. SWEPCo appealed the PUCT’s order contending the two cost cap restrictions are unlawful. The Texas Industrial Energy Consumers filed an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant should be revoked because the Turk Plant is unnecessary to serve retail customers. In February 2010, the Texas District Court affirmed the PUCT’s order in all respects. In March 2010, SWEPCo and the Texas Industrial Energy Consumers appealed this decision to the Texas Court of Appeals. Management is unable to predict the timing of the outcome related to this proceeding.

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

Club) also filed a complaint with the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of the Interior and the U.S. Fish and Wildlife Service seeking a temporary restraining order and preliminary injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws. The plaintiffs’ federal law claims challenge the process used and terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts. The plaintiffs’ state law claims challenge SWEPCo's ability to construct the Turk Plant without obtaining a certificate from the APSC. In October 2010, the Federal District Court certified issues relating to the state law claims to the Arkansas Supreme Court, including whether those claims are within the primary jurisdiction of the APSC. In May 2011, the Arkansas Supreme Court determined that these claims must first be brought before the APSC and that the federal court does not have jurisdiction to hear the state law claims. In 2010, the motions for preliminary injunction were partially granted by the Federal District Court for the Western District of Arkansas. According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop. Mitigation measures required by the permit are authorized and may be completed. The preliminary injunction affects portions of the water intake and portions of two transmission lines. SWEPCo appealed the issuance of the preliminary injunction to the U.S. Eighth Circuit Court of Appeals, and in July 2011, the Court of Appeals affirmed the preliminary injunction and remanded the case to the district court. Management is unable to predict the timing or the outcome related to this remand proceeding.

In August 2011, a joint stipulation of dismissal was approved by the Federal District Court for the Western District of Arkansas that resolved all pending matters between SWEPCo, the Hunting Club and several other parties. As a result, the Hunting Club’s challenge to the U.S. Army Corps of Engineers permit in the Federal District Court for the Western District of Arkansas was dismissed and the Hunting Club’s appeal of the air permit was withdrawn. Additional judicial and administrative proceedings were terminated. The Sierra Club and the Audubon Society challenges to the wetlands and air permits remain pending.

In October 2011, the Sierra Club, the National Audubon Society and Audubon Arkansas filed a complaint with the APSC requesting that construction of the Turk Plant be halted until SWEPCo or the Arkansas Electric Cooperative Corporation obtain either a CECPN, or SWEPCo obtains a CCN and performs an Environmental Impact Statement on associated gas facilities. Management believes the complaint is without merit and intends to vigorously defend against the complaint.

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

Texas Turk Plant Rate Plan

In August 2011, SWEPCo requested approval of a three step plan from the PUCT for including the Turk Plant investment in Texas retail rates. If approved, step one would recover financing costs on 40% of the June 2011 Texas jurisdictional share of the Turk Plant construction work in progress balance from April 2012 through October 2012. In step two, which would be implemented in November 2012, additional financing costs would be recovered on 100% of the June 2011 Texas jurisdictional share of the Turk Plant CWIP balance and would continue until the Turk Plant costs are included in base rates. Once the Turk Plant goes into service, which is expected in the fourth quarter of 2012, SWEPCo proposes that it also be allowed to defer Turk Plant related depreciation expense, operating and maintenance expense and additional financing costs incurred for future recovery. The final step would be to file a complete base rate case which will include all of the Turk Plant investment and associated operating expenses. Based upon the Turk Plant being placed into service in the fourth quarter of 2012, SWEPCo expects to file a complete base rate case in the first half of 2013.

TCC Rate Matters

TEXAS RESTRUCTURING

Texas Restructuring Appeals

Pursuant to PUCT restructuring orders, TCC securitized net recoverable stranded generation costs of $2.5 billion and is recovering the principal and interest on the securitization bonds through the end of 2020. TCC also refunded other net true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider under PUCT restructuring orders. TCC and intervenors appealed the PUCT’s true-up related orders. After rulings from the Texas District Court and the Texas Court of Appeals, TCC, the PUCT and intervenors filed petitions for review with the Supreme Court of Texas. In July 2011, the Supreme Court of Texas granted review and issued its opinion. No parties filed for rehearing with the Supreme Court of Texas, and the case was remanded to the PUCT. The following issues were decided by the Supreme Court:

The PUCT’s 2006 order denying recovery of capacity auction true-up amounts was reversed. Based upon the Supreme Court of Texas’ opinion, TCC recorded $421 million of pretax income ($273 million, net of tax) in Extraordinary Item, Net of Tax on the condensed statements of income in the third quarter of 2011. Further, in October 2011, the PUCT issued a preliminary order in the remand proceeding.

Also in the third quarter of 2011, TCC recorded $261 million in pretax Carrying Costs Income on the condensed statements of income related to the debt component of carrying costs for the period from January 2002 through September 2011. This carrying costs income represents previously unrecorded earnings associated with restructuring in Texas since 2002. The total regulatory asset related to the capacity auction true-up as of September 30, 2011 was $682 million. In October 2011, TCC filed with the PUCT requesting a final determination of the amount to be securitized. In its filing, TCC presented three alternative carrying cost calculations through March 2012, the anticipated securitization date, where the debt and equity component of carrying costs ranged from $396 million to $756 million, including $280 million to $444 million for the debt component of carrying costs. As of September 30, 2011, the corresponding range of the debt and equity component of carrying costs was $368 million to $692 million, including $261 million to $410 million for the debt component of carrying costs. The final amount of carrying costs will be determined by the PUCT and could vary from the calculations presented by TCC. TCC plans to recognize debt carrying costs income prior to securitization and equity carrying costs income will be recognized as collected over the life of the securitization. A PUCT hearing is scheduled for November 2011.

·	The Supreme Court of Texas reversed the Texas Court of Appeal’s decision and found that the PUCT could adjust the net book value for what it determined to be commercially unreasonable conduct. This portion of the decision is unfavorable, but was already reflected in our financial statements.

·	The Supreme Court of Texas affirmed the PUCT’s finding that the sales price should be used to value TCC’s nuclear generation. This portion of the decision is favorable, but this issue will have no impact on TCC’s rate recovery as this was already reflected in our financial statements.

The Supreme Court of Texas reversed the Texas Court of Appeal’s decision and found it was appropriate for the PUCT to take into account previously refunded excess mitigation credits to affiliate retail electricity providers. This portion of the decision upheld the PUCT’s decision. However, resolution of related issues will be addressed on remand in the excess earnings proceeding. See the “TCC Excess Earnings” section below.

·	The PUCT decisions allowing recovery of construction work in progress balances and specifying the interest rate on stranded costs were upheld. These decisions are already reflected in our financial statements and were not addressed in the remand proceeding.

If TCC is not ultimately permitted to fully recover its deferrals, it would reduce future net income and cash flows and impact financial condition.

TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes

In 2006, the PUCT reduced recovery of the amount securitized by $103 million of tax benefits including associated carrying costs related to TCC’s generation assets. In 2006, TCC obtained a private letter ruling from the IRS which confirmed that such a reduction was an IRS normalization violation. In order to avoid a normalization violation, the PUCT agreed to allow TCC to defer refunding the tax benefits of $103 million plus additional interest through the CTC refund period pending resolution of the normalization issue. In 2008, the IRS issued final regulations, which supported the IRS’s private letter ruling which would make the refunding of or the reduction of the amount securitized by such tax benefits a normalization violation. After the IRS issued its final regulations, the Texas Court of Appeals, at the request of the PUCT, remanded the tax normalization issue to the PUCT for the consideration of additional evidence including the IRS regulations. The issue was not appealed to the Supreme Court of Texas but it was addressed in connection with the remand of the true-up proceeding. See the “Texas Restructuring Appeals” section above. In August 2011, the Supreme Court of Texas issued a mandate to return this proceeding and other true-up proceedings to the PUCT. The PUCT established a proceeding to address this issue along with other true-up remanded issues. TCC is not accruing interest on the $103 million because management believes it is not probable that the PUCT will order TCC to violate the normalization provision of the Internal Revenue Code. If interest were accrued, management estimates interest expense would have been approximately $30 million higher for the period July 2008 through September 2011.

Management believes that the PUCT will ultimately allow TCC to retain the deferred amounts, which would have a favorable effect on future net income and cash flows. Although unexpected, if the PUCT fails to issue a favorable order and orders TCC to return the tax benefits to customers, the resulting normalization violation could result in TCC’s repayment to the IRS of Accumulated Deferred Investment Tax Credits (ADITC) on all property, including transmission and distribution property. This amount approximates $101 million as of September 30, 2011. It could also lead to a loss of TCC’s right to claim accelerated tax depreciation in future tax returns. If TCC is required to repay its ADITC to the IRS and is also required to refund ADITC plus unaccrued interest to customers, it would reduce future net income and cash flows and impact financial condition.

TCC Excess Earnings

In 2005, a Texas appellate court issued a decision finding that a PUCT order requiring TCC to refund to the Texas Retail Electric Providers excess earnings prior to and outside of the true-up process was unlawful under the Texas Restructuring Legislation. From 2002 to 2005, TCC refunded $55 million of excess earnings, including interest, under the overturned PUCT order. In the true-up proceeding, the PUCT adjusted stranded costs for TCC’s payment of excess earnings under the PUCT order. However, the PUCT did not properly recognize TCC’s payment of interest under the prior order, causing TCC to refund interest twice. The Supreme Court of Texas approved the PUCT treatment of these matters in the true-up case, noting that TCC could pursue its additional interest claim in further proceedings related to the excess earnings order. TCC intends to assert its claims in a remand of this order to the PUCT.

APCo and WPCo Rate Matters

2011 Virginia Biennial Base Rate Case

In August 2011, the Virginia Attorney General filed testimony recommending no increase in annual base rates based on a return on common equity of 11.03%. Also in August 2011, the Virginia SCC staff filed testimony recommending an increase in annual base rates of $31 million based on a return on common equity of 10.83%. Hearings were held in September 2011. A decision from the Virginia SCC is pending.

Rate Adjustment Clauses

In 2007, the Virginia law governing the regulation of electric utility service was amended to, among other items, provide for rate adjustment clauses (RACs) beginning in January 2009 for the timely and current recovery of costs of: (a) transmission services billed by an RTO, (b) demand side management and energy efficiency programs, (c) renewable energy programs, (d) environmental compliance projects and (e) new generation facilities, including major unit modifications. In accordance with Virginia law, APCo is deferring incremental environmental costs incurred after December 2008 and renewable energy costs incurred after December 2007 which are not being recovered in current revenues. As of September 30, 2011, APCo has deferred $73 million of environmental costs (excluding $17 million of unrecognized equity carrying costs) and $40 million of renewable energy costs.

In March 2011, APCo filed for approval of an environmental RAC, a renewable energy program RAC and a generation RAC simultaneous with the 2011 Virginia base rate filing. The environmental RAC is requesting recovery of environmental compliance costs incurred from January 2009 through December 2010 of $77 million to be collected over two years beginning in February 2012. The renewable energy program RAC is requesting the incremental portion of deferred wind power costs for the Camp Grove and Fowler Ridge projects of $6 million. APCo plans to seek recovery of non-incremental deferred wind power costs ($34 million as of September 30, 2011) in future rate proceedings. The generation RAC is requesting recovery of the Dresden Plant, currently under construction. With Virginia SCC approval, APCo purchased the Dresden Plant from AEGCo in August 2011 for $302 million.

In August 2011, the Virginia SCC staff filed testimony in the environmental RAC proceeding recommending recovery, based upon the methodology used, of $37 million to $42 million of environmental compliance costs. In October 2011, a hearing examiner issued a report recommending recovery of $65 million of environmental compliance costs. An order is pending from the Virginia SCC. Also in August 2011, a stipulation agreement was filed with the Virginia SCC related to the generation RAC. The stipulation agreement allows recovery of the Dresden Plant costs totaling up to $27 million annually, effective March 2012. A decision from the Virginia SCC is pending. In September 2011, the Virginia SCC staff filed testimony in the renewable energy program RAC recommending incremental costs of $1 million to $6 million depending on whether 2008 and 2009 costs are includable. Hearings were held in October 2011. If the Virginia SCC were to disallow a portion of APCo’s deferred costs, it would reduce future net income and cash flows.

2010 West Virginia Base Rate Case

In May 2010, APCo and WPCo filed a request with the WVPSC to increase annual base rates by $156 million based on an 11.75% return on common equity to be effective March 2011. In March 2011, the WVPSC modified and approved a settlement agreement which increased annual base rates by approximately $51 million based upon a 10% return on common equity. The approved settlement agreement also resulted in a pretax write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility in the first quarter of 2011. See “Mountaineer Carbon Capture and Storage Project” section below. In addition, the WVPSC allowed APCo to defer and amortize $18 million of previously expensed 2009 incremental storm expenses and allowed APCo and WPCo to defer and amortize $15 million of previously expensed costs related to the 2010 cost reduction initiatives, each over a period of seven years.

Mountaineer Carbon Capture and Storage Project

Product Validation Facility (PVF)

APCo and ALSTOM Power, Inc., an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009. APCo also constructed and owns the necessary facilities to store the CO2. In October 2009, APCo started injecting CO2 into the underground storage facilities. The injection of CO2 required the recording of an asset retirement obligation and an offsetting regulatory asset. In May 2011, the PVF ended operations and decommissioning of the facility began.

In APCo’s and WPCo’s May 2010 West Virginia base rate filing, APCo and WPCo requested rate base treatment of the PVF, including recovery of the related asset retirement obligation regulatory asset amortization and accretion. In March 2011, a WVPSC order denied the request for rate base treatment of the PVF largely due to its experimental operation. The base rate order provided that should APCo construct a commercial scale carbon capture and sequestration (CCS) facility, only the West Virginia portion of the PVF costs, based on load sharing among certain AEP operating companies, may be considered used and useful plant in service and included in future rate base. As a result, in the first quarter of 2011, APCo recorded a pretax write-off of $41 million in Other Operation expense on the condensed statements of operations. See “2010 West Virginia Base Rate Case” section above. As of September 30, 2011, APCo has recorded a noncurrent regulatory asset of $19 million related to the PVF. If APCo cannot recover its remaining PVF investment and related accretion expenses, it would reduce future net income and cash flows.

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

During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale CCS facility at the Mountaineer Plant. AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project. The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million. Management informed the DOE that it completed a Front-End Engineering and Design (FEED) study during the third quarter of 2011 and was postponing any further CCS project activities because of the uncertainty about the regulation of CO2. In June 2011, the FEED study costs were allocated among the AEP East companies, PSO and SWEPCo based on eligible plants that could potentially benefit from the carbon capture. Requests for recovery are in process in Indiana, Michigan and Virginia. In September 2011, a stipulation agreement was filed with the PUCO related to the ESP proceedings. The stipulation agreement withdrew a proposed rider to recover CSPCo’s and OPCo’s portion of the CCS facility costs. As a result, in September 2011, CSPCo and OPCo recorded pretax write-offs of $2 million and $7 million, respectively, in Other Operation expense on the condensed statements of income. A decision is pending from the PUCO. See the “Ohio Electric Security Plan Filings” section above. As of September 30, 2011, the project has incurred $34 million in total costs and has received $13 million of DOE eligible funding resulting in $21 million of net costs, of which $2 million and $7 million was written off by CSPCo and OPCo, respectively. The remaining net costs are recorded in Regulatory Assets on APCo’s, I&M’s, KPCo’s, PSO’s and SWEPCo’s condensed balance sheets as follows:

Company	(in millions)
APCo	$	4
I&M		2
KPCo		1
PSO		1
SWEPCo		4

Total	$	12

If the costs of the CCS project cannot be recovered, it would reduce future net income and cash flows.

APCo’s Filings for an IGCC Plant

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

Through September 30, 2011, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $9 million applicable to its Virginia jurisdiction.

APCo will not start construction of the IGCC plant until sufficient assurance of full cost recovery exists in Virginia and West Virginia. If the plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs. 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 September 2009, the WVPSC issued an order approving APCo’s and WPCo’s March 2009 ENEC request. The approved order provided for recovery of an under-recovered balance plus a projected increase in ENEC costs over a four-year phase-in period with an overall increase of $355 million and a first-year increase of $124 million, effective October 2009.

In June 2010, the WVPSC approved a settlement agreement for $96 million, including $10 million of construction surcharges related to APCo’s and WPCo’s second year ENEC increase. The settlement agreement allows APCo to accrue a weighted average cost of a capital carrying charge on the excess under-recovery balance due to the ENEC phase-in as adjusted for the impacts of Accumulated Deferred Income Taxes. The new rates became effective in July 2010.

In June 2011, the WVPSC issued an order approving a $98 million annual increase including $8 million of construction surcharges and $8 million of carrying charges related to APCo’s and WPCo’s third year ENEC increase. The order also allows APCo to accrue a fixed annual carrying cost rate of 4%. The new rates became effective in July 2011. Additionally, the order approved APCo’s request to purchase the Dresden Plant, currently under construction, from AEGCo and approved deferral of post in-service Dresden Plant costs, including a return, for future recovery. APCo purchased the Dresden Plant at cost from AEGCo in August 2011 for $302 million. As of September 30, 2011, APCo’s ENEC under-recovery balance was $380 million, excluding $8 million of unrecognized equity carrying costs, which is included in noncurrent regulatory assets. If the WVPSC were to disallow a portion of APCo’s and WPCo’s deferred ENEC costs, it could reduce 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 prudency 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. 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

Michigan 2009 and 2010 Power Supply Cost Recovery (PSCR) Reconciliations (Cook Plant Unit 1 Fire and Shutdown)

In March 2010, I&M filed its 2009 PSCR reconciliation with the MPSC. The filing included an adjustment to exclude from the PSCR the incremental fuel cost of replacement power due to the Unit 1 outage from mid-December 2008 through December 2009, the period during which I&M received and recognized accidental outage insurance proceeds. In October 2010, a settlement agreement was filed with the MPSC which included deferring the Unit 1 outage issue to the 2010 PSCR reconciliation. In March 2011, I&M filed its 2010 PSCR reconciliation with the MPSC. If any fuel clause revenues or accidental outage insurance proceeds have to be paid to customers, it would reduce future net income and cash flows and impact financial condition. See the “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

2011 Michigan Base Rate Case

In July 2011, I&M filed a request with the MPSC for an annual increase in Michigan base rates of $25 million and a return on common equity of 11.15%. The request included an increase in depreciation rates that would result in a $6 million increase in annual depreciation expense.

2011 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 request included an increase in depreciation rates that would result in a $25 million increase in annual depreciation expense.

FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund

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

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

AEP filed briefs jointly with other affected companies asking the FERC to reverse the decision. In May 2010, the FERC issued an order that generally supports AEP’s position and required a compliance filing to be filed with the FERC by August 2010. In June 2010, AEP and other affected companies filed a joint request for rehearing with the FERC. In September 2011, the FERC issued orders that denied all parties’ request for rehearing of the initial decision.

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 AEP East companies’ analysis of the May 2010 order and the compliance filing, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the 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

In December 2010, each of the AEP Power Pool members gave notice to AEPSC and each other of their decision to terminate the Interconnection Agreement effective January 2014 or such other date approved by FERC, subject to state regulatory input. No filings have been made at the FERC. It is unknown at this time whether the AEP Power Pool will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers or if each company will choose to operate independently.

In addition, in September 2011, a stipulation agreement was filed in the Ohio ESP proceeding which proposed to dissolve and/or modify the Interconnection Agreement. A decision from the PUCO regarding the stipulation agreement is expected in the fourth quarter of 2011. See “January 2012 - May 2016 ESP” section of the CSPCo and OPCo rate matters.

If any of the AEP Power Pool members experience decreases in revenues or increases in costs as a result of the termination of the AEP Power Pool and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

PJM/MISO Market Flow Calculation Settlement Adjustments

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

4. 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 2010 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 excess of our ownership percentages. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letters of Credit

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

We have credit facilities totaling $3.25 billion, under which we may issue up to $1.35 billion as letters of credit. In July 2011, we replaced the $1.5 billion facility due in 2012 with a new $1.75 billion facility maturing in July 2016 and extended the $1.5 billion facility due in 2013 to expire in June 2015. As of September 30, 2011, the maximum future payments for letters of credit issued under the two credit facilities were $103 million with maturities ranging from November 2011 to April 2012.

In March 2011, we terminated a $478 million credit agreement that was scheduled to mature in April 2011 and was used to support $472 million of variable rate Pollution Control Bonds. In March 2011, we remarketed $357 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $361 million. The remaining $115 million of Pollution Control Bonds were reacquired and are held by trustees.

In July 2011, we remarketed $45 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $46 million. Both letters of credit mature in 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. In July 2011, SWEPCo’s guarantee was increased from $65 million to $100 million due to expansion of the mining area. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), a consolidated variable interest entity. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study, we estimate the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million. As of September 30, 2011, SWEPCo has collected approximately $52 million through a rider for final mine closure and reclamation costs, of which $1 million is recorded in Other Current Liabilities, $38 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $13 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 2010 Annual Report “Dispositions” section of Note 7. As of September 30, 2011, there were no material liabilities recorded for any indemnifications.

Master Lease Agreements

We lease certain equipment under master lease agreements. In December 2010, we signed a new master lease agreement with GE Capital Commercial Inc. (GE) for approximately $137 million to replace existing operating and capital leases with GE. We refinanced $60 million of capital leases and $77 million of operating leases. These assets were included in existing master lease agreements that were to be terminated in 2011 since GE exercised the termination provision related to these leases in 2008. In January 2011, we purchased $5 million of previously leased assets that were not included in the 2010 refinancing. In June 2011, we placed an additional $11 million of previously leased assets under a new capital lease.

For equipment under the GE master lease agreements, the lessor is guaranteed receipt of up to 78% of the unamortized balance of the equipment at the end of the lease term. If the fair value of the leased equipment is below the unamortized balance at the end of the lease term, we are committed to pay the difference between the fair value and the unamortized balance, with the total guarantee not to exceed 78% of the unamortized balance. For equipment under other master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, we are committed to pay the difference between the actual fair value and the residual value guarantee. At September 30, 2011, the maximum potential loss for these lease agreements was approximately $16 million assuming the fair value of the equipment is zero at the end of the lease term. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.

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 $16 million for I&M and $18 million for SWEPCo for the remaining railcars as of September 30, 2011.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 84% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. I&M’s maximum potential loss related to the guarantee is approximately $12 million and SWEPCo’s is approximately $13 million assuming the fair value of the equipment is zero at the end of the current five-year lease term. However, we believe that the fair value would produce a sufficient sales price to avoid any loss.

ENVIRONMENTAL CONTINGENCIES

Carbon Dioxide Public Nuisance Claims

In 2004, eight states and the City of New York filed an action in Federal District Court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority. The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants. The actions allege that CO2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming and sought injunctive relief in the form of specific emission reduction commitments from the defendants. The trial court dismissed the lawsuits.

In September 2009, the Second Circuit Court of Appeals issued a ruling on appeal remanding the cases to the Federal District Court for the Southern District of New York. The Second Circuit held that the issues of climate change and global warming do not raise political questions and that Congress’ refusal to regulate CO2 emissions does not mean that plaintiffs must wait for an initial policy determination by Congress or the President’s administration to secure the relief sought in their complaints. In 2010, the U.S. Supreme Court granted the defendants’ petition for review. In June 2011, the U.S. Supreme Court reversed and remanded the case to the Court of Appeals, finding that plaintiffs’ federal common law claims are displaced by the regulatory authority granted to the Federal EPA under the CAA. After the remand, the plaintiffs asked the Second Circuit to return the case to the district court so that they could withdraw their complaints. The cases have been returned to the district court and the parties have been ordered to advise the court in November 2011 how they intend to proceed.

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 CO2 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 and set a status conference for December 1, 2011. We believe the claims are without merit, and in addition to other defenses, are barred by the doctrine of collateral estoppel and the applicable statute of limitations. We intend to vigorously defend against the claims. We are unable to determine a range of potential losses that are reasonably possible of occurring.

Alaskan Villages’ Claims

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies. The complaint alleges that the defendants' emissions of CO2 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 defendants requested that the court defer setting this case for oral argument until after the Supreme Court issues its decision in the CO2 public nuisance case discussed above. The court entered an order deferring argument until after June 2011 and the parties requested supplemental briefing on the impact of the Supreme Court’s decision. The court has set a November 2011 date for oral argument. We believe the action is without merit and intend to defend against the claims. We are unable to determine a range of potential losses that are reasonably possible of occurring.

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, our generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. We currently incur costs to dispose of these substances safely.

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 $11 million. As the remediation work is completed, I&M’s cost may continue to increase as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ. We cannot predict the amount of additional cost, if any.

Amos Plant – State and Federal Enforcement Proceedings

In March 2010, we received a letter from the West Virginia Department of Environmental Protection, Division of Air Quality (DAQ), alleging that at various times in 2007 through 2009 the units at Amos Plant reported periods of excess opacity (indicator of compliance with PM emission limits) that lasted for more than 30 consecutive minutes in a 24-hour period and that certain required notifications were not made. We met with representatives of DAQ to discuss these occurrences and the steps we have taken to prevent a recurrence. DAQ indicated that additional enforcement action may be taken, including imposition of a civil penalty of approximately $240 thousand. We have denied that violations of the reporting requirements occurred and maintain that the proper reporting was done. In March 2011, we resolved these issues through the entry of a consent order that included the payment of a $75 thousand civil penalty and certain improvements in our opacity reports.

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

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 could cost up to approximately $408 million. Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process. I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power. The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors. 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 September 30, 2011, we recorded $61 million in Prepayments and Other Current Assets on our condensed balance sheets representing amounts under NEIL insurance policies. Through September 30, 2011, I&M received partial payments of $203 million from NEIL for the cost incurred to date to repair the property damage.

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

OPERATIONAL CONTINGENCIES

Fort Wayne Lease

Since 1975, I&M has leased certain energy delivery assets from the City of Fort Wayne, Indiana under a long-term lease that expired on February 28, 2010. I&M negotiated with Fort Wayne to purchase the assets at the end of the lease and reached an agreement (subject to IURC approval) in 2010. The agreement requires I&M to purchase the remaining leased property and settles claims Fort Wayne asserted. The agreement provides that I&M will pay Fort Wayne a total of $39 million, including interest, over 15 years and Fort Wayne will recognize that I&M is the exclusive electricity supplier in the Fort Wayne area. In August 2011, the IURC approved a settlement agreement with the Indiana Office of Utility Consumer Counselor. The transaction is final.

Enron Bankruptcy

In 2001, we purchased Houston Pipeline Company (HPL) from Enron. Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy. In connection with our acquisition of HPL, we entered into an agreement with BAM Lease Company, which granted HPL the exclusive right to use approximately 55 billion cubic feet (BCF) of cushion gas required for the normal operation of the Bammel gas storage facility. At the time of our acquisition of HPL, BOA and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of the cushion gas. Also at the time of our

acquisition, Enron and the BOA Syndicate released HPL from all prior and future liabilities and obligations in connection with the financing arrangement. After the Enron bankruptcy, the BOA Syndicate informed HPL of a purported default by Enron under the terms of the financing arrangement. This dispute was litigated in the Enron bankruptcy proceedings and in federal courts in Texas and New York.

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

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

The deferred gain related to the sale of HPL, plus accrued interest and attorneys’ fees related to the New York court’s judgment was $448 million at December 31, 2010 and was included in Current Liabilities – Deferred Gain and Accrued Litigation Costs on the condensed balance sheet.

In February 2011, we reached a settlement covering all claims with BOA and Enron for $425 million. As part of the settlement, we received title to the 55 BCF of natural gas in the Bammel storage facility and recorded this asset at fair value. Under the HPL sales agreement, we have a service obligation to the buyer for the right to use the cushion gas through May 2031. We recognized the obligation as a liability and will amortize it over the life of the agreement.

The settlement resulted in a pretax gain of $51 million and a net loss after tax of $22 million primarily due to an unrealized capital loss valuation allowance of $56 million.

At the time of the settlement, the following table sets forth its impact on our 2011 financial statements:

	(in millions)
Income Statement:
Other Operation Expense - Pretax Gain on Settlement	$	51
Income Tax Expense		73
Net Loss After Tax	$	(22)

Cash Flow Statement:
Net Income - Loss on Settlement with BOA and Enron	$	(22)
Deferred Income Taxes		91
Gain on Settlement with BOA and Enron		(51)
Settlement of Litigation with BOA and Enron		(211)
Accrued Taxes, Net		(18)
Acquisition of Cushion Gas from BOA		(214)
Cash Paid	$	(425)

Balance Sheet:
Deferred Charges and Other Noncurrent Assets - Gas Acquired	$	214
Deferred Credits and Other Noncurrent Liabilities - Gas Service Liability		187
Accrued Taxes - Tax Benefit on Settlement with BOA and Enron		18
Deferred Income Taxes - Deferred Tax Benefit on Gas Service Liability		66

Natural Gas Markets Lawsuits

In 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP (or a subsidiary) is among the companies named as defendants in some of these cases. In 2008, we settled all of the cases pending against us in California. In July 2011, the judge in the Federal District Court in Las Vegas granted summary judgment dismissing the cases where AEP companies were defendants. Also in July 2011, the plaintiffs in these cases filed notices of appeal to the Ninth Circuit Court of Appeals. We will continue to defend the remaining case in Ohio where an AEP company is a defendant and all appeals of the cases that were dismissed by the Federal District Court in Las Vegas. We believe the provision we have for the remaining cases is adequate. We believe the remaining exposure is immaterial.

5. ACQUISITION, DISPOSITIONS AND IMPAIRMENTS

ACQUISITION

2010

Valley Electric Membership Corporation (Utility Operations segment)

In October 2010, SWEPCo purchased certain transmission and distribution assets of Valley Electric Membership Corporation (VEMCO) for approximately $102 million and began serving VEMCO’s 30,000 customers in Louisiana.

DISPOSITIONS

2010

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

During the nine months ended September 30, 2010, TCC and TNC sold, at cost, $66 million and $73 million, respectively, of transmission facilities to ETT.

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

In April 2010, we sold our remaining 138,000 shares of ICE and recognized a $16 million gain. We recorded the gain in Interest and Investment Income on our condensed statements of income for the nine months ended September 30, 2010.

IMPAIRMENTS

2011

Muskingum River Plant Unit 5 FGD Project (MR5) (Utility Operations segment)

In September 2011, subsequent to the stipulation agreement filed with the PUCO, management determined that OPCo was not likely to complete the previously suspended MR5 project and that the project’s preliminary engineering costs were no longer probable of being recovered. As a result, in the third quarter of 2011, OPCo recorded a pretax write-off of $42 million in Asset Impairments and Other Related Charges on the condensed statements of income.

Sporn Plant Unit 5 (Utility Operations segment)

6. 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 nine months ended September 30, 2011 and 2010:

					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended September 30,				Three Months Ended September 30,
	2011		2010		2011		2010
	(in millions)
Service Cost	$	18	$	28	$	11	$	12
Interest Cost		59		63		27		29
Expected Return on Plan Assets		(79)		(78)		(27)		(27)
Amortization of Transition Obligation		-		-		1		6
Amortization of Prior Service Cost (Credit)		1		-		(1)		-
Amortization of Net Actuarial Loss		31		22		8		8
Net Periodic Benefit Cost	$	30	$	35	$	19	$	28

					Other Postretirement
	Pension Plans				Benefit Plans
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in millions)
Service Cost	$	54	$	83	$	32	$	35
Interest Cost		178		190		81		85
Expected Return on Plan Assets		(236)		(234)		(81)		(79)
Amortization of Transition Obligation		-		-		1		20
Amortization of Prior Service Cost (Credit)		1		-		(1)		-
Amortization of Net Actuarial Loss		92		67		23		22
Net Periodic Benefit Cost	$	89	$	106	$	55	$	83

7. BUSINESS SEGMENTS

As outlined in our 2010 Annual Report, our primary business is our electric utility operations. Within our Utility Operations segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. While our Utility Operations segment remains our primary business segment, other segments include our AEP River Operations segment with significant barging activities and our Generation and Marketing segment, which includes our nonregulated generating, marketing and risk management activities primarily in the ERCOT market area and, to a lesser extent, Ohio in PJM and MISO. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

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

Utility Operations

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

·	Electricity transmission and distribution in the U.S.

AEP River Operations

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

Generation and Marketing

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

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

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

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

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

The tables below present our reportable segment information for the three and nine months ended September 30, 2011 and 2010 and balance sheet information as of September 30, 2011 and December 31, 2010. These amounts include certain estimates and allocations where necessary.

				Nonutility Operations
						Generation
		Utility		AEP River		and		All Other		Reconciling
		Operations		Operations		Marketing		(a)		Adjustments		Consolidated
		(in millions)
Three Months Ended September 30, 2011
Revenues from:
	External Customers	$	4,044	$	177	$	106	$	6	$	-	$	4,333
	Other Operating Segments		30		6		-		4		(40)		-
Total Revenues		$	4,074	$	183	$	106	$	10	$	(40)	$	4,333

Income (Loss) Before Extraordinary Item		$	642	$	17	$	8	$	(10)	$	-	$	657
Extraordinary Item, Net of Tax			273		-		-		-		-		273
Net Income (Loss)		$	915	$	17	$	8	$	(10)	$	-	$	930

				Nonutility Operations
						Generation
		Utility		AEP River		and		All Other		Reconciling
		Operations		Operations		Marketing		(a)		Adjustments		Consolidated
		(in millions)
Three Months Ended September 30, 2010
Revenues from:
	External Customers	$	3,876	$	147	$	41	$	-	$	-	$	4,064
	Other Operating Segments		31		7		-		3		(41)		-
Total Revenues		$	3,907	$	154	$	41	$	3	$	(41)	$	4,064

Net Income		$	541	$	14	$	-	$	2	$	-	$	557

				Nonutility Operations
						Generation
		Utility		AEP River		and		All Other		Reconciling
		Operations		Operations		Marketing		(a)		Adjustments		Consolidated
		(in millions)
Nine Months Ended September 30, 2011
Revenues from:
	External Customers	$	10,901	$	506	$	247	$	18	$	-	$	11,672
	Other Operating Segments		86		15		1		7		(109)		-
Total Revenues		$	10,987	$	521	$	248	$	25	$	(109)	$	11,672

Income (Loss) Before Extraordinary Item		$	1,376	$	23	$	20	$	(54)	$	-	$	1,365
Extraordinary Item, Net of Tax			273		-		-		-		-		273
Net Income (Loss)		$	1,649	$	23	$	20	$	(54)	$	-	$	1,638

				Nonutility Operations
						Generation
		Utility		AEP River		and		All Other		Reconciling
		Operations		Operations		Marketing		(a)		Adjustments		Consolidated
		(in millions)
Nine Months Ended September 30, 2010
Revenues from:
	External Customers	$	10,468	$	395	$	130	$	-	$	-	$	10,993
	Other Operating Segments		76		17		-		10		(103)		-
Total Revenues		$	10,544	$	412	$	130	$	10	$	(103)	$	10,993

Net Income (Loss)		$	1,017	$	16	$	17	$	(10)	$	-	$	1,040

			Nonutility Operations
					Generation				Reconciling
	Utility		AEP River		and		All Other		Adjustments
	Operations		Operations		Marketing		(a)		(b)			Consolidated
	(in millions)
September 30, 2011
Total Property, Plant and Equipment	$	54,151	$	600	$	593	$	11	$	(258)		$	55,097
Accumulated Depreciation and Amortization		18,380		130		215		10		(55)			18,680
Total Property, Plant and Equipment - Net	$	35,771	$	470	$	378	$	1	$	(203)		$	36,417

Total Assets	$	49,651	$	647	$	883	$	16,288	$	(16,282)	(c)	$	51,187

			Nonutility Operations
					Generation				Reconciling
	Utility		AEP River		and		All Other		Adjustments
	Operations		Operations		Marketing		(a)		(b)			Consolidated
	(in millions)
December 31, 2010
Total Property, Plant and Equipment	$	52,822	$	574	$	584	$	11	$	(251)		$	53,740
Accumulated Depreciation and Amortization		17,795		110		198		9		(46)			18,066
Total Property, Plant and Equipment - Net	$	35,027	$	464	$	386	$	2	$	(205)		$	35,674

Total Assets	$	48,780	$	621	$	881	$	15,942	$	(15,769)	(c)	$	50,455

(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 are financial derivatives which settle and expire in the fourth quarter of 2011.

·	Revenue sharing related to the Plaquemine Cogeneration Facility which ends 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.

8. 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 September 30, 2011 and December 31, 2010:

Notional Volume of Derivative Instruments

		Volume
		September 30,		December 31,		Unit of
		2011		2010		Measure
		(in millions)
Commodity:
	Power		730		652	MWHs
	Coal		35		63	Tons
	Natural Gas		92		94	MMBtus
	Heating Oil and Gasoline		7		6	Gallons
	Interest Rate	$	232	$	171	USD

Interest Rate and Foreign Currency		$	614	$	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 activity as “Commodity.” We do not hedge all fuel price risk.

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

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

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 September 30, 2011 and December 31, 2010 balance sheets, we netted $15 million and $8 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $45 million and $109 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 September 30, 2011 and December 31, 2010:

Fair Value of Derivative Instruments
September 30, 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		$	557	$	20	$	-	$	(413)	$	164
Long-term Risk Management Assets			460		16		-		(160)		316
Total Assets			1,017		36		-		(573)		480

Current Risk Management Liabilities			528		12		17		(444)		113
Long-term Risk Management Liabilities			304		5		17		(193)		133
Total Liabilities			832		17		34		(637)		246

Total MTM Derivative Contract Net Assets
	(Liabilities)	$	185	$	19	$	(34)	$	64	$	234

Fair Value of Derivative Instruments
December 31, 2010

		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		$	1,023	$	18	$	30	$	(839)	$	232
Long-term Risk Management Assets			546		12		2		(150)		410
Total Assets			1,569		30		32		(989)		642

Current Risk Management Liabilities			995		13		2		(881)		129
Long-term Risk Management Liabilities			387		6		3		(255)		141
Total Liabilities			1,382		19		5		(1,136)		270

Total MTM Derivative Contract Net Assets
	(Liabilities)	$	187	$	11	$	27	$	147	$	372

(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 nine months ended September 30, 2011 and 2010:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended September 30, 2011 and 2010

Location of Gain (Loss)	2011		2010
	(in millions)
Utility Operations Revenue	$	8	$	24
Other Revenue		6		(4)
Regulatory Assets (a)		(3)		(6)
Regulatory Liabilities (a)		(2)		7
Total Gain (Loss) on Risk Management Contracts	$	9	$	21

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Nine Months Ended September 30, 2011 and 2010

Location of Gain (Loss)	2011		2010
	(in millions)
Utility Operations Revenue	$	46	$	69
Other Revenue		21		5
Regulatory Assets (a)		(3)		(9)
Regulatory Liabilities (a)		8		34
Total Gain (Loss) on Risk Management Contracts	$	72	$	99

(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 nine months ended September 30, 2011, we recognized gains of $1 million and $3 million, respectively, on our hedging instruments and offsetting losses of $3 million and $6 million, respectively, on our long-term debt. We de-designated a significant portion of our interest rate fair value hedges in the third quarter of 2011. Hedge ineffectiveness was immaterial. During the three and nine months ended September 30, 2010, we recognized gains of $3 million and $7 million, respectively, on our outstanding hedging instruments and offsetting losses of $3 million and $7 million, respectively, on our long-term debt. No hedge ineffectiveness was recognized.

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, natural gas and heating oil and gasoline designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on our 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 nine months ended September 30, 2011 and 2010, we designated commodity derivatives as cash flow hedges.

We reclassify gains and losses on financial fuel derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our 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 nine months ended September 30, 2011 and 2010, we designated heating oil and gasoline derivatives as cash flow hedges.

We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2011 and 2010, 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 nine months ended September 30, 2011 and 2010, we designated foreign currency derivatives as cash flow hedges.

During the three and nine months ended September 30, 2011 and 2010, hedge ineffectiveness was immaterial or nonexistent for all of the 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 nine months ended September 30, 2011 and 2010. 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 September 30, 2011
					Interest Rate
					and Foreign
			Commodity		Currency		Total
			(in millions)
Balance in AOCI as of June 30, 2011			$	12	$	5	$	17
Changes in Fair Value Recognized in AOCI				2		(21)		(19)
Amount of (Gain) or Loss Reclassified from AOCI
	to Income Statement/within Balance Sheet:
		Utility Operations Revenue		1		-		1
		Other Revenue		(1)		-		(1)
		Purchased Electricity for Resale		(2)		-		(2)
		Interest Expense		-		1		1
		Regulatory Assets (a)		-		-		-
		Regulatory Liabilities (a)		-		-		-
Balance in AOCI as of September 30, 2011			$	12	$	(15)	$	(3)

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended September 30, 2010
					Interest Rate
					and Foreign
			Commodity		Currency		Total
			(in millions)
Balance in AOCI as of June 30, 2010			$	2	$	(15)	$	(13)
Changes in Fair Value Recognized in AOCI				(2)		(1)		(3)
Amount of (Gain) or Loss Reclassified from AOCI
	to Income Statement/within Balance Sheet:
		Utility Operations Revenue		1		-		1
		Other Revenue		(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 September 30, 2010			$	2	$	(15)	$	(13)

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Nine Months Ended September 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				7		(22)		(15)
Amount of (Gain) or Loss Reclassified from AOCI
	to Income Statement/within Balance Sheet:
		Utility Operations Revenue		3		-		3
		Other Revenue		(3)		-		(3)
		Purchased Electricity for Resale		(3)		-		(3)
		Interest Expense		-		3		3
		Regulatory Assets (a)		1		-		1
		Regulatory Liabilities (a)		-		-		-
Balance in AOCI as of September 30, 2011			$	12	$	(15)	$	(3)

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Nine Months Ended September 30, 2010
					Interest Rate
					and Foreign
			Commodity		Currency		Total
			(in millions)
Balance in AOCI as of December 31, 2009			$	(2)	$	(13)	$	(15)
Changes in Fair Value Recognized in AOCI				2		(5)		(3)
Amount of (Gain) or Loss Reclassified from AOCI
	to Income Statement/within Balance Sheet:
		Utility Operations Revenue		1		-		1
		Other Revenue		(4)		-		(4)
		Purchased Electricity for Resale		3		-		3
		Interest Expense		-		3		3
		Regulatory Assets (a)		2		-		2
		Regulatory Liabilities (a)		-		-		-
Balance in AOCI as of September 30, 2010			$	2	$	(15)	$	(13)

(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 at September 30, 2011 and December 31, 2010 were:

Impact of Cash Flow Hedges on the Condensed Balance Sheet
September 30, 2011

				Interest Rate
				and Foreign
		Commodity		Currency		Total
		(in millions)
Hedging Assets (a)		$	23	$	-	$	23
Hedging Liabilities (a)			4		34		38
AOCI Gain (Loss) Net of Tax			12		(15)		(3)
Portion Expected to be Reclassified to Net
	Income During the Next Twelve Months		5		(2)		3

Impact of Cash Flow Hedges on the Condensed Balance Sheet
December 31, 2010

				Interest Rate
				and Foreign
		Commodity		Currency		Total
		(in millions)
Hedging Assets (a)		$	13	$	25	$	38
Hedging Liabilities (a)			2		4		6
AOCI Gain (Loss) Net of Tax			7		4		11
Portion Expected to be Reclassified to Net
	Income During the Next Twelve Months		3		(2)		1

(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 September 30, 2011, 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 33 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. We do not anticipate a downgrade below investment grade. The following table represents: (a) our aggregate fair value of such derivative contracts, (b) the amount of collateral we would have been required to post for all derivative and non-derivative contracts if our credit ratings had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of September 30, 2011 and December 31, 2010:

		September 30,		December 31,
		2011		2010
		(in millions)
Liabilities for Derivative Contracts with Credit Downgrade Triggers		$	31	$	20
Amount of Collateral AEP Subsidiaries Would Have Been
	Required to Post		59		45
Amount Attributable to RTO and ISO Activities			55		44

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. We do not anticipate a non-performance event under these provisions. The following table represents: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral we have posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering our contractual netting arrangements as of September 30, 2011 and December 31, 2010:

	September 30,		December 31,
	2011		2010
	(in millions)
Liabilities for Contracts with Cross Default Provisions Prior to Contractual
Netting Arrangements	$	339	$	401
Amount of Cash Collateral Posted		21		81
Additional Settlement Liability if Cross Default Provision is Triggered		202		213

9. 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.

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. Fixed income securities do not trade on an exchange and do not have an official closing price. Pricing vendors calculate bond valuations using financial models and matrices. Fixed income securities are typically classified as Level 2 holdings because their valuation inputs are based on observable market data. Observable inputs used for valuing fixed income securities are benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, bids, offers, reference data and economic events. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.

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

	Type of Fixed Income Security
	United States		State and Local
Type of Input	Government	Corporate Debt	Government

Benchmark Yields	X	X	X
Broker Quotes	X	X	X
Discount Margins	X	X
Treasury Market Update	X
Base Spread	X	X	X
Corporate Actions		X
Ratings Agency Updates		X	X
Prepayment Schedule and
History			X
Yield Adjustments	X

Fair Value Measurements of Long-term Debt

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

The book values and fair values of Long-term Debt as of September 30, 2011 and December 31, 2010 are summarized in the following table:

	September 30, 2011				December 31, 2010
	Book Value		Fair Value		Book Value		Fair Value
	(in millions)
Long-term Debt	$	16,450	$	19,003	$	16,811	$	18,285

Fair Value Measurements of Other Temporary Investments

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

The following is a summary of Other Temporary Investments:

			September 30, 2011
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
Other Temporary Investments			Cost		Gains		Losses		Value
			(in millions)
Restricted Cash (a)			$	164	$	-	$	-	$	164
Fixed Income Securities:
	Mutual Funds			63		-		-		63
Equity Securities - Mutual Funds				11		2		-		13
Total Other Temporary Investments			$	238	$	2	$	-	$	240

			December 31, 2010
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
Other Temporary Investments			Cost		Gains		Losses		Value
			(in millions)
Restricted Cash (a)			$	225	$	-	$	-	$	225
Fixed Income Securities:
	Mutual Funds			69		-		-		69
	Variable Rate Demand Notes			97		-		-		97
Equity Securities - Mutual Funds				18		7		-		25
Total Other Temporary Investments			$	409	$	7	$	-	$	416

(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 nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in millions)
Proceeds from Investment Sales	$	21	$	133	$	268	$	390
Purchases of Investments		-		192		153		413
Gross Realized Gains on Investment Sales		4		-		4		16
Gross Realized Losses on Investment Sales		-		-		-		-

At September 30, 2011 and December 31, 2010, we had no Other Temporary Investments with an unrealized loss position. At September 30, 2011, 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.

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 at September 30, 2011 and December 31, 2010:

		September 30, 2011						December 31, 2010
		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		$	14	$	-	$	-	$	20	$	-	$	-
Fixed Income Securities:
	United States Government		550		59		(1)		461		23		(1)
	Corporate Debt		53		5		(2)		59		4		(2)
	State and Local Government		320		-		(1)		341		(1)		-
	Subtotal Fixed Income Securities		923		64		(4)		861		26		(3)
Equity Securities - Domestic			576		144		(84)		634		183		(123)
Spent Nuclear Fuel and
	Decommissioning Trusts	$	1,513	$	208	$	(88)	$	1,515	$	209	$	(126)

The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in millions)
Proceeds from Investment Sales	$	361	$	495	$	826	$	1,087
Purchases of Investments		379		512		871		1,129
Gross Realized Gains on Investment Sales		18		1		30		7
Gross Realized Losses on Investment Sales		12		-		21		-

The adjusted cost of debt securities was $859 million and $835 million as of September 30, 2011 and December 31, 2010, respectively. The adjusted cost of equity securities was $432 million and $451 million as of September 30, 2011 and December 31, 2010, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at September 30, 2011 was as follows:

	Fair Value
	of Debt
	Securities
	(in millions)
Within 1 year		$	79
1 year – 5 years			269
5 years – 10 years			318
After 10 years			257
Total		$	923

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 September 30, 2011 and December 31, 2010. 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
September 30, 2011

			Level 1		Level 2		Level 3		Other		Total
Assets:			(in millions)

Cash and Cash Equivalents (a)			$	13	$	-	$	-	$	533	$	546

Other Temporary Investments
Restricted Cash (a)				123		-		-		41		164
Fixed Income Securities:
	Mutual Funds			63		-		-		-		63
Equity Securities - Mutual Funds (b)				13		-		-		-		13
Total Other Temporary Investments				199		-		-		41		240

Risk Management Assets
Risk Management Commodity Contracts (c) (f)				25		855		105		(562)		423
Cash Flow Hedges:
	Commodity Hedges (c)			11		24		-		(12)		23
De-designated Risk Management Contracts (d)				-		-		-		34		34
Total Risk Management Assets				36		879		105		(540)		480

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)				-		5		-		9		14
Fixed Income Securities:
	United States Government			-		550		-		-		550
	Corporate Debt			-		53		-		-		53
	State and Local Government			-		320		-		-		320
		Subtotal Fixed Income Securities		-		923		-		-		923
Equity Securities - Domestic (b)				576		-		-		-		576
Total Spent Nuclear Fuel and Decommissioning Trusts				576		928		-		9		1,513

Total Assets			$	824	$	1,807	$	105	$	43	$	2,779

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (f)			$	25	$	734	$	41	$	(592)	$	208
Cash Flow Hedges:
	Commodity Hedges (c)			1		15		-		(12)		4
	Interest Rate/Foreign Currency Hedges			-		34		-		-		34
Total Risk Management Liabilities			$	26	$	783	$	41	$	(604)	$	246

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2010

			Level 1		Level 2		Level 3		Other		Total
Assets:			(in millions)

Cash and Cash Equivalents (a)			$	170	$	-	$	-	$	124	$	294

Other Temporary Investments
Restricted Cash (a)				184		-		-		41		225
Fixed Income Securities:
	Mutual Funds			69		-		-		-		69
	Variable Rate Demand Notes			-		97		-		-		97
Equity Securities - Mutual Funds (b)				25		-		-		-		25
Total Other Temporary Investments				278		97		-		41		416

Risk Management Assets
Risk Management Commodity Contracts (c) (g)				20		1,432		112		(1,013)		551
Cash Flow Hedges:
	Commodity Hedges (c)			11		17		-		(15)		13
	Interest Rate/Foreign Currency Hedges			-		25		-		-		25
Fair Value Hedges				-		7		-		-		7
De-designated Risk Management Contracts (d)				-		-		-		46		46
Total Risk Management Assets				31		1,481		112		(982)		642

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)				-		8		-		12		20
Fixed Income Securities:
	United States Government			-		461		-		-		461
	Corporate Debt			-		59		-		-		59
	State and Local Government			-		341		-		-		341
		Subtotal Fixed Income Securities		-		861		-		-		861
Equity Securities - Domestic (b)				634		-		-		-		634
Total Spent Nuclear Fuel and Decommissioning Trusts				634		869		-		12		1,515

Total Assets			$	1,113	$	2,447	$	112	$	(805)	$	2,867

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)			$	25	$	1,325	$	27	$	(1,114)	$	263
Cash Flow Hedges:
	Commodity Hedges (c)			4		13		-		(15)		2
	Interest Rate/Foreign Currency Hedges			-		4		-		-		4
Fair Value Hedges				-		1		-		-		1
Total Risk Management Liabilities			$	29	$	1,343	$	27	$	(1,129)	$	270

(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 September 30, 2011 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $0 in 2011, $6 million in periods 2012-2014 and ($6) million in periods 2015-2016; Level 2 matures $3 million in 2011, $80 million in periods 2012-2014, $22 million in periods 2015-2016 and $16 million in periods 2017-2028; Level 3 matures $5 million in 2011, $17 million in periods 2012-2014, $13 million in periods 2015-2016 and $29 million in periods 2017-2028. Risk management commodity contracts are substantially comprised of power contracts.

(g)

The December 31, 2010 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures ($2) million in 2011, $2 million in periods 2012-2014 and ($5) million in periods 2015-2018; Level 2 matures $13 million in 2011, $66 million in periods 2012-2014, $12 million in periods 2015-2016 and $16 million in periods 2017-2028; Level 3 matures $18 million in 2011, $24 million in periods 2012-2014, $16 million in periods 2015-2016 and $27 million in periods 2017-2028. Risk management commodity contracts are substantially comprised of power contracts.

There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2011 and 2010.

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

		Net Risk Management
Three Months Ended September 30, 2011		Assets (Liabilities)
		(in millions)
Balance as of June 30, 2011		$	77
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)			(16)
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)			3
Transfers into Level 3 (d) (f)			5
Transfers out of Level 3 (e) (f)			(1)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			1
Balance as of September 30, 2011		$	64

		Net Risk Management
Three Months Ended September 30, 2010		Assets (Liabilities)
		(in millions)
Balance as of June 30, 2010		$	100
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)			(4)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
	Relating to Assets Still Held at the Reporting Date (a)		23
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income			-
Purchases, Issuances and Settlements (c)			-
Transfers into Level 3 (d) (f)			5
Transfers out of Level 3 (e) (f)			(22)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			9
Balance as of September 30, 2010		$	111

		Net Risk Management
Nine Months Ended September 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)			(11)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
	Relating to Assets Still Held at the Reporting Date (a)		-
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income			-
Purchases, Issuances and Settlements (c)			5
Transfers into Level 3 (d) (f)			9
Transfers out of Level 3 (e) (f)			(12)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			(12)
Balance as of September 30, 2011		$	64

		Net Risk Management
Nine Months Ended September 30, 2010		Assets (Liabilities)
		(in millions)
Balance as of December 31, 2009		$	62
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)			4
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
	Relating to Assets Still Held at the Reporting Date (a)		60
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income			-
Purchases, Issuances and Settlements (c)			(18)
Transfers into Level 3 (d) (f)			14
Transfers out of Level 3 (e) (f)			(26)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			15
Balance as of September 30, 2010		$	111

(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.

10. INCOME TAXES

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.

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 will 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 have a material effect on net income.

We, along with our subsidiaries, file income tax returns in various state, local and foreign jurisdictions. These taxing authorities routinely examine our tax returns and we are currently under examination in several state and local jurisdictions. We believe that we have filed tax returns with positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and the ultimate resolution of these audits will not materially impact net income. With few exceptions, we are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2000.

For a discussion of the tax implications of our settlement with BOA and Enron, see “Enron Bankruptcy” section of Note 4.

Federal Tax Legislation

The Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act (Health Care Acts) were enacted in March 2010. The Health Care Acts amend tax rules so that the portion of employer health care costs that are reimbursed by the Medicare Part D prescription drug subsidy will no longer be deductible by the employer for federal income tax purposes effective for years beginning after December 31, 2012. Because of the loss of the future tax deduction, a reduction in the deferred tax asset related to the nondeductible OPEB liabilities accrued to date was recorded in March 2010. This reduction did not materially affect our cash flows or financial condition. For the nine months ended September 30, 2010, deferred tax assets decreased $56 million, partially offset by recording net tax regulatory assets of $35 million in our jurisdictions with regulated operations, resulting in a decrease in net income of $21 million.

The Small Business Jobs Act (the Act) was enacted in September 2010. Included in the Act was a one-year extension of the 50% bonus depreciation provision. The Tax Relief, Unemployment Insurance Reauthorization and the Job Creation Act of 2010 extended the life of research and development, employment and several energy tax credits originally scheduled to expire at the end of 2010. In addition, the Act extended the time for claiming bonus depreciation and increased the deduction to 100% for part of 2010 and 2011. The enacted provisions will not have a material impact on net income or financial condition.

State Tax Legislation

Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rates from 8.5% to 6.5%. The current 8.5% Indiana corporate income tax rate is scheduled for a 0.5% reduction each year beginning after June 30, 2012 with the final reduction occurring in years beginning after June 30, 2015. In addition, Michigan repealed its Business Tax regime in May 2011 and replaced it with a traditional corporate net income tax with a rate of 6%. During the third quarter of 2011, the state of West Virginia determined that the state had achieved certain minimum levels of shortfall reserve funds and thus, the West Virginia corporate income tax rate will be reduced to 7.75% in 2012. The enacted provisions will not have a material impact on net income, cash flows or financial condition.

11. FINANCING ACTIVITIES

Long-term Debt


Type of Debt	September 30, 2011		December 31, 2010
	(in millions)
Senior Unsecured Notes	$	11,737	$	11,669
Pollution Control Bonds		2,112		2,263
Notes Payable		337		396
Securitization Bonds		1,688		1,847
Junior Subordinated Debentures		315		315
Spent Nuclear Fuel Obligation (a)		265		265
Other Long-term Debt		28		91
Unamortized Discount (net)		(32)		(35)
Total Long-term Debt Outstanding		16,450		16,811
Less Portion Due Within One Year		1,267		1,309
Long-term Portion	$	15,183	$	15,502

(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 and $307 million at September 30, 2011 and December 31, 2010, respectively, 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 nine months of 2011 are shown in the tables below:

			Principal			Interest
Company	Type of Debt		Amount			Rate	Due Date
Issuances:		(in millions)				(%)
APCo	Senior Unsecured Notes		$	350		4.60	2021
APCo	Pollution Control Bonds			65		2.00	2012
APCo	Pollution Control Bonds			75	(a)	Variable	2036
APCo	Pollution Control Bonds			54	(a)	Variable	2042
APCo	Pollution Control Bonds			50	(a)	Variable	2036
APCo	Pollution Control Bonds			50	(a)	Variable	2042
I&M	Pollution Control Bonds			52	(a)	Variable	2021
I&M	Pollution Control Bonds			25	(a)	Variable	2019
OPCo	Pollution Control Bonds			50	(a)	Variable	2014
PSO	Senior Unsecured Notes			250		4.40	2021
PSO	Notes Payable			2		3.00	2026

Non-Registrant:
AEGCo	Pollution Control Bonds			22	(a)	Variable	2025
AEGCo	Pollution Control Bonds			23	(a)	Variable	2025
TCC	Pollution Control Bonds			60	(a)	1.125	2012
Total Issuances			$	1,128	(b)

(a)	These pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year on our condensed balance sheets.

(b)	Amount indicated on the statement of cash flows of $1,118 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		$	75	Variable	2036
APCo		Pollution Control Bonds			54	Variable	2042
APCo		Pollution Control Bonds			50	Variable	2042
APCo		Pollution Control Bonds			50	Variable	2036
APCo		Senior Unsecured Notes			250	5.55	2011
I&M		Pollution Control Bonds			52	Variable	2021
I&M		Pollution Control Bonds			25	Variable	2019
I&M		Notes Payable			13	5.16	2014
I&M		Notes Payable			15	5.44	2013
I&M		Notes Payable			17	Variable	2015
OPCo		Pollution Control Bonds			65	Variable	2036
OPCo		Pollution Control Bonds			50	Variable	2014
OPCo		Pollution Control Bonds			50	Variable	2014
PSO		Senior Unsecured Notes			200	6.00	2032
PSO		Senior Unsecured Notes			75	4.70	2011
SWEPCo		Pollution Control Bonds			41	4.50	2011

Non-Registrant:
AEP Subsidiaries		Notes Payable			13	Variable	2017
AEP Subsidiaries		Notes Payable			6	Variable	2011
AEP Subsidiaries		Notes Payable			1	8.03	2026
AEP Subsidiaries		Notes Payable			1	7.59	2026
AEGCo		Other Long-term Debt			85	Variable	2011
AEGCo		Senior Unsecured Notes			7	6.33	2037
AEGCo		Pollution Control Bonds			22	4.15	2025
AEGCo		Pollution Control Bonds			23	4.15	2025
TCC		Securitization Bonds			60	5.96	2013
TCC		Securitization Bonds			99	4.98	2013
TCC		Pollution Control Bonds			121	5.125	2011
Total Retirements and
	Principal Payments			$	1,520

In October 2011, I&M retired $29 million of Notes Payable related to DCC Fuel.

In October 2011, APCo remarketed $100 million of 2% Pollution Control Bonds due in 2014.

As of September 30, 2011, trustees held, on our behalf, $478 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 charter provisions and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.

The Federal Power Act prohibits the utility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the par value of the common stock multiplied by the number of shares outstanding. This restriction does not limit the ability of the utility subsidiaries to pay dividends out of retained earnings.

Short-term Debt

Our outstanding short-term debt was as follows:

	September 30, 2011				December 31, 2010
	Outstanding		Interest		Outstanding		Interest
Type of Debt	Amount		Rate (a)		Amount		Rate (a)
	(in millions)				(in millions)
Securitized Debt for Receivables (b)	$	750	0.27	%	$	690	0.31	%
Commercial Paper		529	0.42	%		650	0.52	%
Line of Credit – Sabine Mining Company (c)		-	-	%		6	2.15	%
Total Short-term Debt	$	1,279			$	1,346

(a)	Weighted average rate.

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

(c)	Sabine Mining Company is a consolidated variable interest entity. This line of credit does not reduce available liquidity under AEP's credit facilities.

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 4.

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 July 2011, AEP Credit renewed its receivables securitization agreement. The agreement provides commitments of $750 million from bank conduits to finance receivables from AEP Credit with an increase to $800 million for the months of July, August and September to accommodate seasonal demand. A commitment of $375 million, with the seasonal increase to $425 million for the months of July, August and September, expires in June 2012 and the remaining commitment of $375 million expires in June 2014.

Accounts receivable information for AEP Credit is as follows:

		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2011			2010			2011			2010
		(dollars in millions)
Effective Interest Rates on Securitization of
	Accounts Receivable		0.23	%		0.41	%		0.27	%		0.32	%
Net Uncollectible Accounts Receivable
	Written Off	$	11		$	9		$	28		$	16

		September 30,		December 31,
		2011		2010
		(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral
	Less Uncollectible Accounts	$	1,005	$	923
Total Principal Outstanding			750		690
Delinquent Securitized Accounts Receivable			45		50
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable			20		26
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable			297		354

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.

12. COST REDUCTION INITIATIVES

In April 2010, we began initiatives to decrease both labor and non-labor expenses with a goal of achieving significant reductions in operation and maintenance expenses. A total of 2,461 positions was eliminated across the AEP System as a result of process improvements, streamlined organizational designs and other efficiencies. Most of the affected employees terminated employment May 31, 2010. The severance program provided two weeks of base pay for every year of service along with other severance benefits.

We recorded a charge of $293 million to Other Operation expense during the second quarter of 2010 primarily related to severance benefits as the result of headcount reduction initiatives.

The following table shows the cost reduction activity for the nine months ended September 30, 2011:

	Total
	(in millions)
Balance as of December 31, 2010	$	17
Incurred		-
Settled		(12)
Adjustments		(1)
Balance as of September 30, 2011	$	4

The remaining accruals are included primarily in Other Current Liabilities on the condensed balance sheets.

APPALACHIAN POWER COMPANY

AND SUBSIDIARIES

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Regulatory Activity

Virginia Regulatory Activity

West Virginia Regulatory Activity

In March 2011, the WVPSC modified and approved a settlement agreement which increased annual base rates by approximately $46 million based upon a 10% return on common equity. The approved settlement agreement also resulted in a pretax write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility in the first quarter of 2011. In addition, the WVPSC allowed APCo to defer and amortize $18 million of previously expensed 2009 incremental storm expenses and $14 million of previously expensed costs related to the 2010 cost reduction initiatives, each over a period of seven years. See “2010 West Virginia Base Rate Case” section of Note 3.

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. No merger approval filings have been made. See “WPCo Merger with APCo” section of Note 3.

Acquisition of Dresden Plant

During the first quarter of 2011, APCo and AEGCo filed with the Virginia and West Virginia regulatory commissions seeking approval for APCo’s purchase of the partially completed Dresden Plant from AEGCo at cost. In June 2011 and July 2011, the WVPSC and the Virginia SCC, respectively, issued orders approving the acquisition. APCo purchased the Dresden Plant from AEGCo in August 2011 for $302 million. The Dresden Plant is located near Dresden, Ohio and is a natural gas, combined cycle power plant. When completed, the Dresden Plant will have a generating capacity of 580 MW.

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 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2010 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 166. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 232 for additional discussion of relevant factors.

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2011		2010		2011		2010
		(in millions of KWHs)
Retail:
	Residential		2,854		2,990		9,180		9,810
	Commercial		1,861		1,880		5,254		5,416
	Industrial		2,738		2,736		8,056		7,922
	Miscellaneous		204		204		617		639
Total Retail			7,657		7,810		23,107		23,787

Wholesale			3,072		2,436		7,235		5,555

Total KWHs			10,729		10,246		30,342		29,342

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				Nine Months Ended
		September 30,				September 30,
		2011		2010		2011		2010
		(in degree days)

Actual - Heating (a)			3		-		1,389		1,611
Normal - Heating (b)			3		3		1,440		1,443

Actual - Cooling (c)			955		971		1,425		1,511
Normal - Cooling (b)			807		798		1,161		1,146

(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.

Third Quarter of 2011 Compared to Third Quarter of 2010

Reconciliation of Third Quarter of 2010 to Third Quarter of 2011
Net Income
(in millions)

Third Quarter of 2010	$	50

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

Changes in Expenses and Other:
Depreciation and Amortization		8
Other Income		4
Interest Expense		2
Total Change in Expenses and Other		14

Income Tax Expense		(14	)

Third Quarter of 2011	$	53

·	Retail Margins increased $3 million primarily due to the following:
	·	A $22 million increase due to higher base rates in Virginia and West Virginia.
	·	A $19 million increase due to lower capacity settlement expenses under the Interconnection Agreement net of recovery in West Virginia and environmental deferrals in Virginia.
	These increases were partially offset by:
	·	A $23 million decrease due to the expiration of E&R cost recovery in Virginia.
	·	A $6 million decrease in residential and commercial margins primarily due to lower non-weather related usage.
	·	A $5 million decrease in other variable electric generation expenses.

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

	·	Depreciation and Amortization expenses decreased $8 million primarily due to the expiration of E&R amortization of deferred carrying costs in Virginia, partially offset by an increased depreciation base resulting from environmental upgrades at the Amos Plant.
	·	Other Income increased $4 million primarily due to an increase in the equity component of AFUDC as a result of construction at the Dresden Plant and for interest income recorded in the third quarter of 2011 for favorable adjustments related to the 2001-2006 federal income tax audit.
	·	Income Tax Expense increased $14 million primarily due to an increase in pretax book income and state income tax adjustments.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Reconciliation of Nine Months Ended September 30, 2010 to Nine Months Ended September 30, 2011
Net Income
(in millions)

Nine Months Ended September 30, 2010	$	101

Changes in Gross Margin:
Retail Margins		(46)
Off-system Sales		3
Transmission Revenues		7
Other Revenues		(1)
Total Change in Gross Margin		(37)

Changes in Expenses and Other:
Other Operation and Maintenance		60
Depreciation and Amortization		22
Taxes Other Than Income Taxes		3
Carrying Costs Income		(6)
Other Income		5
Interest Expense		(1)
Total Change in Expenses and Other		83

Income Tax Expense		(24)

Nine Months Ended September 30, 2011	$	123

·	Retail Margins decreased $46 million primarily due to the following:
	·	A $60 million decrease due to the expiration of E&R cost recovery in Virginia.
	·	A $27 million decrease in other variable electric generation expenses.
	·	A $21 million decrease in weather-related usage primarily due to a 14% decrease in heating degree days and a 6% decrease in cooling degree days.
	·	A $16 million decrease in residential and commercial margins primarily due to lower non-weather related usage.
	These decreases were partially offset by:
	·	A $46 million increase due to lower capacity settlement expenses under the Interconnection Agreement net of recovery in West Virginia and environmental deferrals in Virginia.
	·	A $41 million increase due to higher base rates in Virginia and West Virginia.
	·	An $8 million increase primarily due to formula rate increases in Virginia.
·	Margins from Off-system Sales increased $3 million primarily due to higher physical sales volumes, partially offset by lower trading and marketing margins.
·	Transmission Revenues increased $7 million primarily due to the Transmission Agreement modification effective November 2010.

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

·	Other Operation and Maintenance expenses decreased $60 million primarily due to the following:
·	A $54 million decrease due to the second quarter 2010 write-off of the Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the Virginia SCC.
·	A $51 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
	·	A $32 million decrease due to the first quarter 2011 deferral of 2010 storm costs and costs related to 2010 cost reduction initiatives. These costs were deferred as a result of the approved modified settlement agreement of APCo’s West Virginia base rate case in March 2011.
	·	A $6 million decrease in steam maintenance expenses primarily due to a planned outage at the Amos Plant in 2010.
	·	A $6 million decrease in transmission expenses primarily due to the expiration of E&R amortization in Virginia.
	These decreases were partially offset by:
	·	A $41 million increase 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 $25 million increase due to the second quarter 2010 deferral of 2009 storm costs as allowed by the Virginia SCC.
	·	A $15 million increase in transmission expenses primarily due to the Transmission Agreement modification effective November 2010.
	·	A $14 million increase in storm-related expenses.
·	Depreciation and Amortization expenses decreased $22 million primarily due to the expiration of E&R amortization of deferred carrying costs in Virginia, partially offset by an increased depreciation base resulting from environmental upgrades at the Amos Plant.
·	Taxes Other Than Income Taxes decreased $3 million primarily due to recording a West Virginia franchise tax audit settlement and additional employer payroll taxes incurred related to the cost reduction initiatives in the second quarter of 2010.
·	Carrying Costs Income decreased $6 million primarily due to decreased environmental deferrals in Virginia.
·	Other Income increased $5 million primarily due to an increase in the equity component of AFUDC as a result of construction at the Dresden Plant and for interest income recorded in the third quarter of 2011 for favorable adjustments related to the 2001-2006 federal income tax audit.
·	Income Tax Expense increased $24 million primarily due to an increase in pretax book income and state income tax adjustments.

FINANCIAL CONDITION

LIQUIDITY

APCo participates in the Utility Money Pool, which provides access to AEP’s liquidity. APCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures. See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 232 for additional discussion of liquidity.

Credit Ratings

APCo’s access to capital markets may depend on its credit ratings. In addition, a credit rating downgrade of APCo by one of the rating agencies could increase APCo’s borrowing costs. Failure to maintain investment grade ratings may constrain APCo’s ability to participate in the Utility Money Pool or the amount of APCo’s receivables securitized by AEP Credit. Counterparty concerns about APCo’s credit quality could subject APCo to additional collateral demands under adequate assurance clauses under derivative and non-derivative energy contracts.

CASH FLOW

Cash flows for the nine months ended September 30, 2011 and 2010 were as follows:

	2011			2010
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	951		$	2,006
Net Cash Flows from Operating Activities		645,824			567,464
Net Cash Flows Used for Investing Activities		(672,514	)		(363,246	)
Net Cash Flows from (Used for) Financing Activities		28,408			(204,023	)
Net Increase in Cash and Cash Equivalents		1,718			195
Cash and Cash Equivalents at End of Period	$	2,669		$	2,201

Operating Activities

Net Cash Flows from Operating Activities were $646 million in 2011. APCo produced Net Income of $123 million during the period and had noncash expense items of $205 million for Depreciation and Amortization and $185 million for Deferred Income Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. The $133 million inflow from Fuel, Materials and Supplies was primarily due to a reduction in fuel inventory. The $124 million inflow from Accounts Receivable, Net was primarily due to a decrease in accrued unbilled revenues due to usual seasonal fluctuations and timing of settlements of receivables from affiliated companies. The $73 million outflow from Accounts Payable was primarily due to decreased energy purchases and reduced operation and maintenance expenses. The $54 million outflow from Accrued Taxes, Net was primarily due to decreased accruals related to federal income taxes. The $21 million outflow from Fuel Over/Under-Recovery, Net was primarily due to a net under-recovery of fuel costs in both Virginia and West Virginia.

Net Cash Flows from Operating Activities were $567 million in 2010. APCo produced Net Income of $101 million during the period and had noncash expense items of $227 million for Depreciation and Amortization and $53 million for Deferred Income Taxes. APCo contributed $32 million to the qualified pension trust. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. The $133 million inflow from Fuel, Materials and Supplies was primarily due to a reduction in fuel inventory and a decrease in the average cost of coal per ton. The $114 million outflow from Accounts Payable was primarily due to payments for storm costs accrued in fourth quarter of 2009 and decreased purchases of energy from the system pool. The $107 million inflow from Accrued Taxes, Net includes a third quarter 2010 income tax refund of $170 million as a result of a federal net income tax operating loss in 2009 that was carried back to 2007 and 2008. Items contributing to the net income tax operating loss include bonus depreciation and the favorable impact of a change in tax accounting method related to units of property. The $94 million inflow from Accounts Receivable, Net was primarily due to a decrease in accrued unbilled revenues due to usual seasonal fluctuations and timing of settlements of receivables from affiliated companies.

Investing Activities

Net Cash Flows Used for Investing Activities during 2011 and 2010 were $673 million and $363 million, respectively. Construction Expenditures of $300 million and $363 million in 2011 and 2010, respectively, were primarily for environmental upgrades, as well as projects to improve generation and service reliability for transmission and distribution. Environmental upgrades include FGD projects at the Amos Plant. Acquisitions of Assets in 2011 of $302 million were due to APCo’s purchase of the Dresden Plant from AEGCo in August 2011. During 2011, APCo had a net increase of $82 million in loans to the Utility Money Pool.

Financing Activities

Net Cash Flows from Financing Activities were $28 million in 2011. APCo issued $350 million of Senior Unsecured Notes and $295 million of Pollution Control Bonds, partially offset by the retirement of $250 million of Senior Unsecured Notes and $230 million of Pollution Control Bonds. APCo had a net decrease of $128 million in borrowings from the Utility Money Pool. APCo also received capital contributions from the Parent of $100 million. In addition, APCo paid $98 million in common stock dividends.

Net Cash Flows Used for Financing Activities were $204 million in 2010. APCo issued $300 million of Senior Unsecured Notes and $68 million of Pollution Control Bonds, partially offset by the retirement of $150 million of Senior Unsecured Notes, $100 million of Notes Payable – Affiliated and $50 million of Pollution Control Bonds. APCo had a net decrease of $174 million in borrowings from the Utility Money Pool. In addition, APCo paid $88 million in common stock dividends.

Long-term debt issuances, retirements and principal payments made during the first nine months of 2011 were:

Issuances

	Principal			Interest	Due
Type of Debt	Amount			Rate	Date
	(in thousands)			(%)
Senior Unsecured Notes	$	350,000		4.60	2021
Pollution Control Bonds		65,350		2.00	2012
Pollution Control Bonds		75,000	(a)	Variable	2036
Pollution Control Bonds		50,275	(a)	Variable	2036
Pollution Control Bonds		54,375	(a)	Variable	2042
Pollution Control Bonds		50,000	(a)	Variable	2042

(a)	These pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on APCo’s condensed balance sheets.

Retirements and Principal Payments

	Principal		Interest	Due
Type of Debt	Amount Paid		Rate	Date
	(in thousands)		(%)
Pollution Control Bonds	$	75,000	Variable	2036
Pollution Control Bonds		50,275	Variable	2036
Pollution Control Bonds		54,375	Variable	2042
Pollution Control Bonds		50,000	Variable	2042
Senior Unsecured Notes		250,000	5.55	2011
Land Note		16	13.718	2026

In October 2011, APCo remarketed $100 million of 2% Pollution Control Bonds due in 2014.

CONTRACTUAL OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2010 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

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 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 Discussion and Analysis of Registrant Subsidiaries” beginning on page 232 for a discussion of accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 232 for a discussion of market risk.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2011 and 2010
(in thousands)
(Unaudited)

	Three Months Ended						Nine Months Ended
	2011			2010			2011			2010
REVENUES
Electric Generation, Transmission and Distribution	$	757,366		$	754,940		$	2,175,163		$	2,234,070
Sales to AEP Affiliates		98,419			83,675			259,641			229,811
Other Revenues		2,551			2,007			6,797			6,638
TOTAL REVENUES		858,336			840,622			2,441,601			2,470,519

EXPENSES
Fuel and Other Consumables Used for Electric Generation		230,318			190,538			595,597			540,794
Purchased Electricity for Resale		57,370			60,751			195,715			181,370
Purchased Electricity from AEP Affiliates		222,164			243,772			630,014			690,881
Other Operation		80,376			77,138			268,269			338,085
Maintenance		50,172			53,276			139,628			130,446
Depreciation and Amortization		68,749			76,737			205,492			227,327
Taxes Other Than Income Taxes		26,471			26,350			79,542			82,585
TOTAL EXPENSES		735,620			728,562			2,114,257			2,191,488

OPERATING INCOME		122,716			112,060			327,344			279,031

Other Income (Expense):
Interest Income		2,477			210			3,559			1,163
Carrying Costs Income		7,579			7,565			17,560			23,627
Allowance for Equity Funds Used During Construction		2,451			436			4,546			1,727
Interest Expense		(51,196	)		(52,734	)		(157,323	)		(156,292	)

INCOME BEFORE INCOME TAX EXPENSE		84,027			67,537			195,686			149,256

Income Tax Expense		31,223			17,466			72,275			48,522

NET INCOME		52,804			50,071			123,411			100,734

Preferred Stock Dividend Requirements Including Capital
Stock Expense		199			225			599			675

EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	52,605		$	49,846		$	122,812		$	100,059

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2011 and 2010
(in thousands)
(Unaudited)

								Accumulated
								Other
	Common		Paid-in		Retained			Comprehensive
	Stock		Capital		Earnings			Income (Loss)			Total
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2009	$	260,458	$	1,475,393	$	1,085,980		$	(50,254	)	$	2,771,577

Common Stock Dividends						(88,000	)					(88,000	)
Preferred Stock Dividends						(599	)					(599	)
Capital Stock Expense				78		(76	)					2
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												2,682,980

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $1,953									(3,627	)		(3,627	)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $1,685									3,129			3,129
NET INCOME						100,734						100,734
TOTAL COMPREHENSIVE INCOME												100,236

TOTAL COMMON SHAREHOLDER'S
EQUITY – SEPTEMBER 30, 2010	$	260,458	$	1,475,471	$	1,098,039		$	(50,752	)	$	2,783,216

TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2010	$	260,458	$	1,475,496	$	1,133,748		$	(48,023	)	$	2,821,679

Capital Contribution from Parent				100,000								100,000
Common Stock Dividends						(97,500	)					(97,500	)
Preferred Stock Dividends						(599	)					(599	)
Gain on Reacquired Preferred Stock				3								3
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												2,823,583

COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $413									767			767
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $1,255									2,332			2,332
NET INCOME						123,411						123,411
TOTAL COMPREHENSIVE INCOME												126,510

TOTAL COMMON SHAREHOLDER'S
EQUITY – SEPTEMBER 30, 2011	$	260,458	$	1,575,499	$	1,159,060		$	(44,924	)	$	2,950,093

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2011 and December 31, 2010
(in thousands)
(Unaudited)

	2011			2010
CURRENT ASSETS
Cash and Cash Equivalents	$	2,669		$	951
Advances to Affiliates		81,825			-
Accounts Receivable:
Customers		142,826			166,878
Affiliated Companies		97,664			145,972
Accrued Unbilled Revenues		56,196			108,210
Miscellaneous		1,033			3,090
Allowance for Uncollectible Accounts		(5,571	)		(6,667	)
Total Accounts Receivable		292,148			417,483
Fuel		90,260			230,697
Materials and Supplies		97,313			89,370
Risk Management Assets		30,290			53,242
Accrued Tax Benefits		109,910			104,435
Regulatory Asset for Under-Recovered Fuel Costs		28,635			18,300
Prepayments and Other Current Assets		23,970			35,811
TOTAL CURRENT ASSETS		757,020			950,289

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation		5,118,671			4,736,150
Transmission		1,901,047			1,852,415
Distribution		2,816,694			2,740,752
Other Property, Plant and Equipment		356,081			348,013
Construction Work in Progress		582,528			562,280
Total Property, Plant and Equipment		10,775,021			10,239,610
Accumulated Depreciation and Amortization		2,975,417			2,843,087
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		7,799,604			7,396,523

OTHER NONCURRENT ASSETS
Regulatory Assets		1,498,907			1,486,625
Long-term Risk Management Assets		24,137			38,420
Deferred Charges and Other Noncurrent Assets		105,993			125,296
TOTAL OTHER NONCURRENT ASSETS		1,629,037			1,650,341

TOTAL ASSETS	$	10,185,661		$	9,997,153

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, 2011 and December 31, 2010
(Unaudited)

	2011			2010
	(in thousands)
CURRENT LIABILITIES
Advances from Affiliates	$	-		$	128,331
Accounts Payable:
General		170,319			223,144
Affiliated Companies		138,201			166,884
Long-term Debt Due Within One Year – Nonaffiliated		545,024			479,672
Risk Management Liabilities		19,133			27,993
Customer Deposits		60,091			58,451
Deferred Income Taxes		38,113			44,180
Accrued Taxes		55,183			75,619
Accrued Interest		63,559			57,871
Other Current Liabilities		90,275			93,286
TOTAL CURRENT LIABILITIES		1,179,898			1,355,431

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		3,181,045			3,081,469
Long-term Risk Management Liabilities		7,148			10,873
Deferred Income Taxes		1,802,238			1,642,072
Regulatory Liabilities and Deferred Investment Tax Credits		571,718			562,381
Employee Benefits and Pension Obligations		282,360			306,460
Deferred Credits and Other Noncurrent Liabilities		193,425			199,041
TOTAL NONCURRENT LIABILITIES		6,037,934			5,802,296

TOTAL LIABILITIES		7,217,832			7,157,727

Cumulative Preferred Stock Not Subject to Mandatory Redemption		17,736			17,747

Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

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		1,575,499			1,475,496
Retained Earnings		1,159,060			1,133,748
Accumulated Other Comprehensive Income (Loss)		(44,924	)		(48,023	)
TOTAL COMMON SHAREHOLDER’S EQUITY		2,950,093			2,821,679

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	10,185,661		$	9,997,153

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2011 and 2010
(in thousands)
(Unaudited)

	2011			2010
OPERATING ACTIVITIES
Net Income	$	123,411		$	100,734
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		205,492			227,327
Deferred Income Taxes		184,986			52,798
Carrying Costs Income		(17,560	)		(23,627	)
Allowance for Equity Funds Used During Construction		(4,546	)		(1,727	)
Mark-to-Market of Risk Management Contracts		13,161			(2,573	)
Pension Contributions to Qualified Plan Trust		(14,700	)		(31,952	)
Property Taxes		19,231			19,660
Fuel Over/Under-Recovery, Net		(20,603	)		(17,136	)
Change in Other Noncurrent Assets		(5,856	)		29,275
Change in Other Noncurrent Liabilities		15,714			4,558
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		124,404			93,787
Fuel, Materials and Supplies		132,579			132,801
Accounts Payable		(72,682	)		(113,912	)
Accrued Taxes, Net		(54,214	)		107,404
Other Current Assets		13,023			(4,416	)
Other Current Liabilities		3,984			(5,537	)
Net Cash Flows from Operating Activities		645,824			567,464

INVESTING ACTIVITIES
Construction Expenditures		(300,357	)		(362,792	)
Change in Advances to Affiliates, Net		(81,825	)		-
Acquisitions of Assets		(302,217	)		(9,595	)
Other Investing Activities		11,885			9,141
Net Cash Flows Used for Investing Activities		(672,514	)		(363,246	)

FINANCING ACTIVITIES
Capital Contribution from Parent		100,000			-
Issuance of Long-term Debt – Nonaffiliated		640,027			363,736
Change in Advances from Affiliates, Net		(128,331	)		(174,433	)
Retirement of Long-term Debt – Nonaffiliated		(479,666	)		(200,014	)
Retirement of Long-term Debt – Affiliated		-			(100,000	)
Retirement of Cumulative Preferred Stock		(8	)		(4	)
Principal Payments for Capital Lease Obligations		(5,546	)		(5,350	)
Dividends Paid on Common Stock		(97,500	)		(88,000	)
Dividends Paid on Cumulative Preferred Stock		(599	)		(599	)
Other Financing Activities		31			641
Net Cash Flows from (Used for) Financing Activities		28,408			(204,023	)

Net Increase in Cash and Cash Equivalents		1,718			195
Cash and Cash Equivalents at Beginning of Period		951			2,006
Cash and Cash Equivalents at End of Period	$	2,669		$	2,201

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	145,969		$	140,391
Net Cash Paid (Received) for Income Taxes		(74,384	)		(140,113	)
Noncash Acquisitions Under Capital Leases		697			22,623
Government Grants Included in Accounts Receivable at September 30,		137			-
Construction Expenditures Included in Current Liabilities at September 30,		60,265			52,863

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

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 166.

	Footnote Reference

Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Commitments, Guarantees and Contingencies	Note 4
Acquisitions and Impairments	Note 5
Benefit Plans	Note 6
Business Segments	Note 7
Derivatives and Hedging	Note 8
Fair Value Measurements	Note 9
Income Taxes	Note 10
Financing Activities	Note 11
Cost Reduction Initiatives	Note 12

COLUMBUS SOUTHERN POWER COMPANY

AND SUBSIDIARIES

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Regulatory Activity

2009 – 2011 ESP

In April 2011, the Supreme Court of Ohio issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged and remanded certain issues back to the PUCO. In October 2011, the PUCO issued an order in the remand proceeding. The order required CSPCo to refund POLR charges which were collected subject to refund since June 2011. As a result, in the third quarter of 2011, CSPCo recorded a pretax refund provision of $34 million on the condensed statements of income. In addition, CSPCo filed its 2010 SEET filings with the PUCO. Based upon the approach in the PUCO 2009 order, management does not currently believe that CSPCo will have any significantly excessive earnings. In October 2011, the Ohio Consumers’ Counsel and the Ohio Energy Group filed testimony that recommended CSPCo refund up to $41 million of its 2010 earnings. Also in October 2011, the PUCO staff filed testimony that recommended CSPCo refund $21 million of its 2010 earnings. See “Ohio Electric Security Plan Filings” section of Note 3.

January 2012 – May 2016 ESP

In January 2011, CSPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation. In September 2011, a stipulation agreement was filed with the PUCO which involved various issues pending before the PUCO, including the approval of the CSPCo/OPCo merger and the recovery of deferred fuel until securitized. Under the stipulation agreement, rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2016. Prior to June 2015, CSPCo’s SSO customers continue to pay the tariff rate for non-fuel generation and the fuel adjustment clause. Beginning in June 2015, CSPCo will use results from a competitive bidding process performed prior to January 2015 to meet its SSO obligation through May 2016. The stipulation agreement proposed a corporate separation plan of CSPCo’s generation assets to complete the transition to a fully competitive generation market by June 2015. In addition, to further develop customer choice and facilitate the transition to market generation pricing, CSPCo will provide 21% of its generation capacity in 2012, 29% to 31% of its generation capacity in 2013 and 41% of its generation capacity beginning in 2014 through June 2015 to competitive retail suppliers at a charge based on the Reliability Pricing Model auction-clearing prices and the remainder at a discounted cost-based price.

The stipulation agreement also proposed a termination or modification of the Interconnection Agreement. Finally, the stipulation agreement provides for certain CSPCo contingent contributions and established a Distribution Investment Rider beginning January 2012 through May 2015 to recover post-2000 distribution investment with certain limitations. See “Ohio Electric Security Plan Filings,” “Proposed CSPCo and OPCo Merger” and “Possible Termination of the Interconnection Agreement” sections of Note 3.

Ohio Distribution Base Rate Case

In February 2011, CSPCo filed with the PUCO for an annual increase in distribution rates of $34 million. The requested increase is based upon an 11.15% return on common equity to be effective January 2012. In addition to the annual increase, CSPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets of $216 million, including carrying costs, to be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013. The PUCO staff filed testimony that recommended a rate reduction in the range of $2 million to $10 million plus recovery of the deferred distribution regulatory assets subject to a review of the carrying costs. A decision from the PUCO is expected in the fourth quarter of 2011. See “2011 Ohio Distribution Base Rate Case” section of Note 3.

Proposed CSPCo and OPCo Merger

Ohio Customer Choice

In CSPCo’s service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service. As a result, in comparison to the third quarter of 2010 and the first nine months of 2010, CSPCo lost approximately $34 million and $83 million, respectively, of generation and transmission related gross margin. CSPCo is recovering a portion of lost margins through collection of transmission revenues from competitive CRES providers and off-system sales.

Litigation and Environmental Issues

In the ordinary course of business, CSPCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot 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 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2010 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 166. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2011		2010		2011		2010
		(in millions of KWHs)
Retail:
	Residential		2,157		2,213		5,879		6,006
	Commercial		2,368		2,292		6,481		6,506
	Industrial		1,391		1,190		4,020		3,458
	Miscellaneous		13		12		40		39
Total Retail			5,929		5,707		16,420		16,009

Wholesale			1,644		1,188		3,684		2,544

Total KWHs			7,573		6,895		20,104		18,553

100

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				Nine Months Ended
		September 30,				September 30,
		2011		2010		2011		2010
		(in degree days)

Actual - Heating (a)			3		-		2,052		2,035
Normal - Heating (b)			6		6		1,953		1,956

Actual - Cooling (c)			860		876		1,230		1,306
Normal - Cooling (b)			727		715		1,029		1,011

(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.

101

Third Quarter of 2011 Compared to Third Quarter of 2010

Reconciliation of Third Quarter of 2010 to Third Quarter of 2011
Net Income
(in millions)

Third Quarter of 2010	$	107

Changes in Gross Margin:
Retail Margins		(53	)
Off-system Sales		6
Transmission Revenues		1
Other Revenues		(2	)
Total Change in Gross Margin		(48	)

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

Income Tax Expense		18

Third Quarter of 2011	$	81

·	Retail Margins decreased $53 million due to the following:
	·	A $34 million decrease attributable to customers switching to alternative competitive retail electric service (CRES) providers.
	·	A $33 million refund provision for POLR charges as a result of the October 2011 PUCO remand order.
	·	An $8 million decrease in residential and industrial margins primarily due to a change in the customer mix resulting in lower realizations.
	·	A $3 million decrease in capacity settlements under the Interconnection Agreement.
	These decreases were partially offset by:
	·	A $10 million net increase in transmission rider revenues.
	·	An $8 million increase related to Environmental Investment Carrying Charge Rider (EICCR) revenues.
·	Margins from Off-system Sales increased $6 million primarily due to an increase in PJM capacity revenues and higher physical sales volumes, partially offset by lower trading and marketing margins.

102

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

·	Other Operation and Maintenance expenses increased $1 million primarily due to:
	·	A $2 million increase due to the third quarter 2011 write-off of allocated Front-End Engineering and Design (FEED) study costs related to the Mountaineer Carbon Capture Project.
	·	A $2 million donation to the Ohio Business Development Coalition for JobsOhio.
	·	A $2 million increase in distribution overhead line maintenance expenses primarily due to increased vegetation management and 2011 storm costs, partially offset by the increased under-recovery of the Enhanced Service Reliability Plan (ESRP).
	·	A $1 million increase in remitted Universal Service Fund surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.
	·	A $1 million increase in recoverable PJM expenses.
	These increases were offset by:
	·	A $10 million decrease in transmission expense primarily due to the Transmission Agreement modification effective November 2010, a portion of which is included in the Ohio Transmission Cost Recovery Rider.
·	Other Income increased $2 million due to interest income recorded in the third quarter 2011 for favorable adjustments related to the 2001-2006 federal income tax audit.
·	Income Tax Expense decreased $18 million primarily due to a decrease in pretax book income.

103

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Reconciliation of Nine Months Ended September 30, 2010 to Nine Months Ended September 30, 2011
Net Income
(in millions)

Nine Months Ended September 30, 2010	$	211

Changes in Gross Margin:
Retail Margins		(73	)
Off-system Sales		38
Transmission Revenues		2
Other Revenues		(2	)
Total Change in Gross Margin		(35	)

Changes in Expenses and Other:
Other Operation and Maintenance		32
Depreciation and Amortization		(4	)
Taxes Other Than Income Taxes		(2	)
Carrying Costs Income		3
Other Income		2
Interest Expense		3
Total Change in Expenses and Other		34

Income Tax Expense		4

Nine Months Ended September 30, 2011	$	214

·	Retail Margins decreased $73 million primarily due to:
	·	An $83 million decrease attributable to customers switching to alternative CRES providers.
	·	A $33 million refund provision for POLR charges as a result of the October 2011 PUCO remand order.
	·	A $6 million decrease in transmission recovery revenues.
	·	A $6 million decrease in capacity settlements under the Interconnection Agreement.
	These decreases were partially offset by:
	·	A $19 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Energy Efficiency & Peak Demand Reduction (EE/PDR) Programs. This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
	·	A $15 million increase related to EICCR revenues.
	·	A $10 million increase associated with the final 2009 SEET order.
·	Margins from Off-system Sales increased $38 million primarily due to an increase in PJM capacity revenues and higher physical sales volumes, partially offset by lower trading and marketing margins.

104

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

·	Other Operation and Maintenance expenses decreased $32 million primarily due to:
	·	A $31 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
	·	A $26 million decrease in transmission expense primarily due to the Transmission Agreement modification effective November 2010, a portion of which is included in the Ohio Transmission Cost Recovery Rider.
	·	A $13 million decrease in recoverable PJM expenses.
	These decreases were partially offset by:
	·	A $19 million increase in expenses due to the implementation of PUCO approved EE/PDR programs. This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
	·	A $15 million increase in plant maintenance and operation expenses primarily related to work performed at the Stuart, Waterford and Conesville plants.
	·	A $4 million increase in distribution overhead line maintenance expenses primarily due to increased vegetation management and 2011 storm costs, partially offset by the increased under-recovery of Enhanced Service Reliability Plan (ESRP).
	·	A $2 million increase due to the third quarter 2011 write-off of allocated FEED study costs related to the Mountaineer Carbon Capture Project.
·	Depreciation and Amortization increased $4 million primarily due to the following:
	·	A $4 million increase as a result of recognizing deferred debt and equity carrying charges on deferred fuel as permitted under the final 2009 SEET order.
	·	A $1 million increase primarily due to the amortization of debt and equity carrying costs on deferred fuel as a result of the October 2011 PUCO remand order which allowed the POLR refund to be applied against any deferred fuel balances. The equity amortization was offset by amounts recognized in Carrying Costs Income as discussed below.
		These increases were partially offset by:
	·	A $1 million decrease due to the completion of amortization of MonPower litigation in March 2011.
·	Carrying Costs Income increased $3 million due to equity carrying costs as a result of the 2009 SEET refund order and due to the recognition of equity carrying costs income on deferred fuel as a result of the October 2011 PUCO remand order which allowed the POLR refund to be applied against any deferred fuel balances. The equity carrying costs income was offset by amounts in Depreciation and Amortization discussed above.
·	Interest Expense decreased $3 million primarily as a result of a long-term debt retirement in December 2010.
·	Income Tax Expense decreased $4 million primarily due to other book/tax differences which are accounted for on a flow-through basis.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

105

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2011 and 2010
(in thousands)
(Unaudited)

	Three Months Ended						Nine Months Ended
	2011			2010			2011			2010
REVENUES
Electric Generation, Transmission and Distribution	$	603,622		$	616,823		$	1,589,648		$	1,621,112
Sales to AEP Affiliates		46,793			30,765			125,939			66,687
Other Revenues		470			806			1,359			2,138
TOTAL REVENUES		650,885			648,394			1,716,946			1,689,937

EXPENSES
Fuel and Other Consumables Used for Electric Generation		157,783			99,883			364,456			319,614
Purchased Electricity for Resale		25,244			28,116			73,646			67,899
Purchased Electricity from AEP Affiliates		129,315			134,467			336,295			324,553
Other Operation		83,342			86,360			219,522			266,915
Maintenance		26,767			23,196			88,290			72,593
Depreciation and Amortization		38,874			38,644			117,831			113,733
Taxes Other Than Income Taxes		49,812			50,884			144,089			142,235
TOTAL EXPENSES		511,137			461,550			1,344,129			1,307,542

OPERATING INCOME		139,748			186,844			372,817			382,395

Other Income (Expense):
Interest Income		2,296			385			2,646			694
Carrying Costs Income		3,193			2,028			9,115			6,212
Allowance for Equity Funds Used During Construction		572			267			1,890			1,502
Interest Expense		(20,905	)		(21,382	)		(60,854	)		(64,257	)

INCOME BEFORE INCOME TAX EXPENSE		124,904			168,142			325,614			326,546

Income Tax Expense		43,391			61,085			112,015			115,723

NET INCOME		81,513			107,057			213,599			210,823

Capital Stock Expense		25			39			75			118

EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	81,488		$	107,018		$	213,524		$	210,705

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

106

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2011 and 2010
(in thousands)
(Unaudited)

								Accumulated
								Other
	Common		Paid-in		Retained			Comprehensive
	Stock		Capital		Earnings			Income (Loss)			Total
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2009	$	41,026	$	580,663	$	788,139		$	(49,993	)	$	1,359,835

Common Stock Dividends						(77,500	)					(77,500	)
Capital Stock Expense				118		(118	)					-
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												1,282,335

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $462									(857	)		(857	)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $1,000									1,857			1,857
NET INCOME						210,823						210,823
TOTAL COMPREHENSIVE INCOME												211,823

TOTAL COMMON SHAREHOLDER'S
EQUITY – SEPTEMBER 30, 2010	$	41,026	$	580,781	$	921,344		$	(48,993	)	$	1,494,158

TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2010	$	41,026	$	580,812	$	915,713		$	(51,336	)	$	1,486,215

Common Stock Dividends						(187,500	)					(187,500	)
Capital Stock Expense				75		(75	)					-
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												1,298,715

COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $74									138			138
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $1,187									2,204			2,204
NET INCOME						213,599						213,599
TOTAL COMPREHENSIVE INCOME												215,941

TOTAL COMMON SHAREHOLDER'S
EQUITY – SEPTEMBER 30, 2011	$	41,026	$	580,887	$	941,737		$	(48,994	)	$	1,514,656

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

107

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2011 and December 31, 2010
(in thousands)
(Unaudited)

	2011			2010
CURRENT ASSETS
Cash and Cash Equivalents	$	1,834		$	509
Other Cash Deposits		17			2,260
Advances to Affiliates		156,606			54,202
Accounts Receivable:
Customers		35,946			50,187
Affiliated Companies		41,500			66,788
Accrued Unbilled Revenues		11,740			32,821
Miscellaneous		5,834			14,374
Allowance for Uncollectible Accounts		(1,524	)		(1,584	)
Total Accounts Receivable		93,496			162,586
Fuel		50,022			72,882
Materials and Supplies		42,800			42,033
Emission Allowances		23,883			28,486
Risk Management Assets		18,445			23,774
Accrued Tax Benefits		14,943			8,797
Margin Deposits		8,867			14,762
Prepayments and Other Current Assets		8,394			26,864
TOTAL CURRENT ASSETS		419,307			437,155

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation		2,744,384			2,686,294
Transmission		679,544			662,312
Distribution		1,837,705			1,796,023
Other Property, Plant and Equipment		207,235			203,593
Construction Work in Progress		147,900			172,793
Total Property, Plant and Equipment		5,616,768			5,521,015
Accumulated Depreciation and Amortization		2,021,245			1,927,112
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		3,595,523			3,593,903

OTHER NONCURRENT ASSETS
Regulatory Assets		314,149			298,111
Long-term Risk Management Assets		14,887			22,089
Deferred Charges and Other Noncurrent Assets		72,746			152,932
TOTAL OTHER NONCURRENT ASSETS		401,782			473,132

TOTAL ASSETS	$	4,416,612		$	4,504,190

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

108

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER'S EQUITY
September 30, 2011 and December 31, 2010
(Unaudited)

	2011			2010
	(in thousands)
CURRENT LIABILITIES
Accounts Payable:
General	$	83,974		$	98,925
Affiliated Companies		62,740			78,617
Long-term Debt Due Within One Year – Nonaffiliated		194,500			-
Risk Management Liabilities		11,746			15,967
Customer Deposits		29,975			29,441
Accrued Taxes		120,393			226,572
Accrued Interest		25,212			22,533
Other Current Liabilities		79,516			111,868
TOTAL CURRENT LIABILITIES		608,056			583,923

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		1,244,539			1,438,830
Long-term Risk Management Liabilities		4,382			6,223
Deferred Income Taxes		661,637			604,828
Regulatory Liabilities and Deferred Investment Tax Credits		171,936			163,888
Employee Benefits and Pension Obligations		129,399			136,643
Deferred Credits and Other Noncurrent Liabilities		82,007			83,640
TOTAL NONCURRENT LIABILITIES		2,293,900			2,434,052

TOTAL LIABILITIES		2,901,956			3,017,975

Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 24,000,000 Shares
Outstanding – 16,410,426 Shares		41,026			41,026
Paid-in Capital		580,887			580,812
Retained Earnings		941,737			915,713
Accumulated Other Comprehensive Income (Loss)		(48,994	)		(51,336	)
TOTAL COMMON SHAREHOLDER’S EQUITY		1,514,656			1,486,215

TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$	4,416,612		$	4,504,190

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

109

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2011 and 2010
(in thousands)
(Unaudited)

	2011			2010
OPERATING ACTIVITIES
Net Income	$	213,599		$	210,823
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		117,831			113,733
Deferred Income Taxes		64,204			30,333
Carrying Costs Income		(9,115	)		(6,212	)
Allowance for Equity Funds Used During Construction		(1,890	)		(1,502	)
Mark-to-Market of Risk Management Contracts		6,723			(6,397	)
Property Taxes		83,427			71,795
Fuel Over/Under-Recovery, Net		14,236			22,912
Change in Other Noncurrent Assets		(17,457	)		(5,506	)
Change in Other Noncurrent Liabilities		4,316			(14,413	)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		61,290			11,164
Fuel, Materials and Supplies		25,278			6,419
Accounts Payable		(27,077	)		(20,468	)
Accrued Taxes, Net		(116,972	)		(49,443	)
Other Current Assets		9,873			6,110
Other Current Liabilities		(28,429	)		(219	)
Net Cash Flows from Operating Activities		399,837			369,129

INVESTING ACTIVITIES
Construction Expenditures		(137,360	)		(148,441	)
Change in Other Cash Deposits		2,243			13,890
Change in Advances to Affiliates, Net		(102,404	)		(182,225	)
Proceeds from Sales of Assets		6,855			4,278
Other Investing Activities		22,028			(586	)
Net Cash Flows Used for Investing Activities		(208,638	)		(313,084	)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated		-			149,443
Change in Advances from Affiliates, Net		-			(24,202	)
Retirement of Long-term Debt – Affiliated		-			(100,000	)
Principal Payments for Capital Lease Obligations		(2,519	)		(3,322	)
Dividends Paid on Common Stock		(187,500	)		(77,500	)
Other Financing Activities		145			119
Net Cash Flows Used for Financing Activities		(189,874	)		(55,462	)

Net Increase in Cash and Cash Equivalents		1,325			583
Cash and Cash Equivalents at Beginning of Period		509			1,096
Cash and Cash Equivalents at End of Period	$	1,834		$	1,679

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	56,599		$	59,840
Net Cash Paid for Income Taxes		61,439			51,120
Noncash Acquisitions Under Capital Leases		679			9,521
Government Grants Included in Accounts Receivable at September 30,		1,539			-
Construction Expenditures Included in Current Liabilities at September 30,		12,534			12,561

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

110

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to CSPCo’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 CSPCo. The footnotes begin on page 166.

	Footnote Reference

Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Commitments, Guarantees and Contingencies	Note 4
Benefit Plans	Note 6
Business Segments	Note 7
Derivatives and Hedging	Note 8
Fair Value Measurements	Note 9
Income Taxes	Note 10
Financing Activities	Note 11
Cost Reduction Initiatives	Note 12

111

INDIANA MICHIGAN POWER COMPANY

AND SUBSIDIARIES

112

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Regulatory Activity

Michigan Base Rate Case

Indiana Base Rate Case

Cook Plant

As a result of the nuclear plant situation in Japan following a March 2011 earthquake, management expects the Nuclear Regulatory Commission and possibly Congress to review 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. Management is unable to predict the impact of potential future regulation of nuclear facilities.

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 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2010 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 166. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

113

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2011		2010		2011		2010
		(in millions of KWHs)
Retail:
	Residential		1,657		1,714		4,662		4,689
	Commercial		1,392		1,394		3,844		3,882
	Industrial		1,920		1,851		5,635		5,547
	Miscellaneous		14		16		52		52
Total Retail			4,983		4,975		14,193		14,170

Wholesale			3,024		2,510		7,529		6,210

Total KWHs			8,007		7,485		21,722		20,380

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				Nine Months Ended
		September 30,				September 30,
		2011		2010		2011		2010
		(in degree days)

Actual - Heating (a)			15		2		2,635		2,279
Normal - Heating (b)			11		12		2,425		2,434

Actual - Cooling (c)			767		775		1,071		1,154
Normal - Cooling (b)			585		576		837		822

(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.

114

Third Quarter of 2011 Compared to Third Quarter of 2010

Reconciliation of Third Quarter of 2010 to Third Quarter of 2011
Net Income
(in millions)

Third Quarter of 2010	$	62

Changes in Gross Margin:
Retail Margins		(13	)
FERC Municipals and Cooperatives		3
Off-system Sales		(1	)
Transmission Revenues		(1	)
Other Revenues		1
Total Change in Gross Margin		(11	)

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

Income Tax Expense		1

Third Quarter of 2011	$	52

·	Retail Margins decreased $13 million primarily due to the following:
	·	A $9 million decrease in capacity settlements under the Interconnection Agreement.
	·	An $8 million decrease due to customer credits for a settlement relating to the Cook Plant Unit 1 (Unit 1) fire outage. This decrease was offset by a decrease in Other Operation and Maintenance expenses.
	These decreases were partially offset by:
	·	A $4 million increase due to a Michigan rate settlement effective in December 2010.
·	Margins from FERC Municipals and Cooperatives increased $3 million primarily due to higher sales resulting from favorable summer weather.

Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expenses increased $5 million primarily due to the following:
	·	A $9 million increase in transmission expense primarily due to the Transmission Agreement modification effective November 2010.
	·	A $5 million increase in steam generation maintenance costs associated with scheduled outages.
	·	A $3 million increase in customer service costs associated with higher Demand Side Management (DSM) expenses. This increase is offset by an increase in Retail Margins above.
	These increases were partially offset by:
	·	An $8 million decrease in steam power expenses relating to the Unit 1 fire outage. This decrease was offset by a decrease in Retail Margins.
	·	A $6 million decrease associated with the favorable resolution of a contingency.
·	Interest Expense decreased $4 million primarily due to lower outstanding debt balances.

115

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Reconciliation of Nine Months Ended September 30, 2010 to Nine Months Ended September 30, 2011
Net Income
(in millions)

Nine Months Ended September 30, 2010	$	122

Changes in Gross Margin:
Retail Margins		(12)
FERC Municipals And Cooperatives		3
Off-system Sales		5
Transmission Revenues		(1)
Other Revenues		(2)
Total Change in Gross Margin		(7)

Changes in Expenses and Other:
Other Operation and Maintenance		22
Depreciation and Amortization		1
Taxes Other Than Income Taxes		(2)
Other Income		(2)
Interest Expense		7
Total Change in Expenses and Other		26

Income Tax Expense		(12)

Nine Months Ended September 30, 2011	$	129

·	Retail Margins decreased $12 million primarily due to the following:
	·	A $27 million decrease in capacity settlements under the Interconnection Agreement.
	·	A $14 million decrease due to customer credits for a settlement relating to the Unit 1 fire outage. This decrease was offset by a decrease in Other Operation and Maintenance expenses.
	These decreases were partially offset by:
	·	A $30 million increase due to the Michigan rate settlement effective in December 2010 and recovery of costs through trackers.
·	Margins from Off-system Sales increased $5 million primarily due to higher physical sales volumes, partially offset by lower trading and marketing margins.

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

·	Other Operation and Maintenance expenses decreased $22 million primarily due to the following:
	·	A $41 million decrease due to expenses related to the cost reduction initiatives recorded in the second and third quarters of 2010.
	·	A $14 million decrease in steam power expenses relating to the Unit 1 fire outage. This decrease was offset by a decrease in Retail Margins.
	·	A $6 million decrease associated with the favorable resolution of a contingency.
	These decreases were partially offset by:
	·	A $28 million increase in transmission expense primarily due to the Transmission Agreement modification effective November 2010.
	·	A $6 million increase in customer service costs associated with higher DSM expenses. This increase is offset by an increase in Retail Margins above.
·	Interest Expense decreased $7 million primarily due to lower outstanding debt balances.
·	Income Tax Expense increased $12 million primarily due to an increase in pretax book income, the regulatory accounting treatment of state income taxes and federal income tax adjustments related to prior year tax returns.

116

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

117

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2011 and 2010
(in thousands)
(Unaudited)

	Three Months Ended						Nine Months Ended
	2011			2010			2011			2010
REVENUES
Electric Generation, Transmission and Distribution	$	494,860		$	480,779		$	1,371,349		$	1,327,505
Sales to AEP Affiliates		83,417			93,984			229,187			245,674
Other Revenues - Affiliated		29,230			27,796			81,694			86,447
Other Revenues - Nonaffiliated		3,725			5,691			10,972			11,595
TOTAL REVENUES		611,232			608,250			1,693,202			1,671,221

EXPENSES
Fuel and Other Consumables Used for Electric Generation		135,927			134,721			359,311			356,160
Purchased Electricity for Resale		25,671			27,904			86,759			89,115
Purchased Electricity from AEP Affiliates		112,416			96,405			274,967			247,151
Other Operation		133,327			132,200			399,384			425,859
Maintenance		50,341			46,180			148,877			144,257
Depreciation and Amortization		33,214			34,130			100,564			101,932
Taxes Other Than Income Taxes		19,984			20,806			62,643			60,833
TOTAL EXPENSES		510,880			492,346			1,432,505			1,425,307

OPERATING INCOME		100,352			115,904			260,697			245,914

Other Income (Expense):
Other Income		3,944			4,022			11,306			14,543
Interest Expense		(24,056	)		(28,046	)		(73,440	)		(80,557	)

INCOME BEFORE INCOME TAX EXPENSE		80,240			91,880			198,563			179,900

Income Tax Expense		28,538			29,580			70,048			57,940

NET INCOME		51,702			62,300			128,515			121,960

Preferred Stock Dividend Requirements		85			85			255			255

EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	51,617		$	62,215		$	128,260		$	121,705

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

118

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2011 and 2010
(in thousands)
(Unaudited)

								Accumulated
								Other
	Common		Paid-in		Retained			Comprehensive
	Stock		Capital		Earnings			Income (Loss)			Total
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2009	$	56,584	$	981,292	$	656,608		$	(21,701	)	$	1,672,783

Common Stock Dividends						(78,250	)					(78,250	)
Preferred Stock Dividends						(255	)					(255	)
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												1,594,278

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $77									(144	)		(144	)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $352									655			655
NET INCOME						121,960						121,960
TOTAL COMPREHENSIVE INCOME												122,471

TOTAL COMMON SHAREHOLDER'S
EQUITY – SEPTEMBER 30, 2010	$	56,584	$	981,292	$	700,063		$	(21,190	)	$	1,716,749

TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2010	$	56,584	$	981,294	$	677,360		$	(20,889	)	$	1,694,349

Common Stock Dividends						(56,250	)					(56,250	)
Preferred Stock Dividends						(255	)					(255	)
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												1,637,844

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges, Net of Tax of $2,063									(3,832	)		(3,832	)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $383									711			711
NET INCOME						128,515						128,515
TOTAL COMPREHENSIVE INCOME												125,394

TOTAL COMMON SHAREHOLDER'S
EQUITY – SEPTEMBER 30, 2011	$	56,584	$	981,294	$	749,370		$	(24,010	)	$	1,763,238

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

119

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2011 and December 31, 2010
(in thousands)
(Unaudited)

	2011			2010
CURRENT ASSETS
Cash and Cash Equivalents	$	1,154		$	361
Advances to Affiliates		134,004			-
Accounts Receivable:
Customers		75,435			76,193
Affiliated Companies		73,726			149,169
Accrued Unbilled Revenues		15,137			19,449
Miscellaneous		13,826			10,968
Allowance for Uncollectible Accounts		(2,099	)		(1,692	)
Total Accounts Receivable		176,025			254,087
Fuel		60,545			87,551
Materials and Supplies		164,861			178,331
Risk Management Assets		23,413			27,526
Accrued Tax Benefits		29,346			71,113
Deferred Cook Plant Fire Costs		61,261			45,752
Prepayments and Other Current Assets		33,831			33,713
TOTAL CURRENT ASSETS		684,440			698,434

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation		3,812,564			3,774,262
Transmission		1,209,506			1,188,665
Distribution		1,464,455			1,411,095
Other Property, Plant and Equipment (including nuclear fuel and coal mining)		729,393			719,708
Construction Work in Progress		366,185			301,534
Total Property, Plant and Equipment		7,582,103			7,395,264
Accumulated Depreciation, Depletion and Amortization		3,203,493			3,124,998
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		4,378,610			4,270,266

OTHER NONCURRENT ASSETS
Regulatory Assets		540,210			556,254
Spent Nuclear Fuel and Decommissioning Trusts		1,512,704			1,515,227
Long-term Risk Management Assets		20,140			31,485
Deferred Charges and Other Noncurrent Assets		57,655			77,229
TOTAL OTHER NONCURRENT ASSETS		2,130,709			2,180,195

TOTAL ASSETS	$	7,193,759		$	7,148,895

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

120

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, 2011 and December 31, 2010
(dollars in thousands)
(Unaudited)

	2011			2010
CURRENT LIABILITIES
Advances from Affiliates	$	-		$	42,769
Accounts Payable:
General		110,631			121,665
Affiliated Companies		70,086			105,221
Long-term Debt Due Within One Year – Nonaffiliated
(September 30, 2011 and December 31, 2010 amounts include $72,819 and
$77,457, respectively, related to DCC Fuel)		155,307			154,457
Risk Management Liabilities		12,067			16,785
Customer Deposits		29,362			29,264
Accrued Taxes		99,447			62,637
Accrued Interest		22,602			27,444
Other Current Liabilities		143,836			140,710
TOTAL CURRENT LIABILITIES		643,338			700,952

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		1,830,426			1,849,769
Long-term Risk Management Liabilities		11,821			6,530
Deferred Income Taxes		845,031			760,105
Regulatory Liabilities and Deferred Investment Tax Credits		806,397			852,197
Asset Retirement Obligations		1,000,143			963,029
Deferred Credits and Other Noncurrent Liabilities		285,293			313,892
TOTAL NONCURRENT LIABILITIES		4,779,111			4,745,522

TOTAL LIABILITIES		5,422,449			5,446,474

Cumulative Preferred Stock Not Subject to Mandatory Redemption		8,072			8,072

Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 2,500,000 Shares
Outstanding – 1,400,000 Shares		56,584			56,584
Paid-in Capital		981,294			981,294
Retained Earnings		749,370			677,360
Accumulated Other Comprehensive Income (Loss)		(24,010	)		(20,889	)
TOTAL COMMON SHAREHOLDER’S EQUITY		1,763,238			1,694,349

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	7,193,759		$	7,148,895

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

121

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2011 and 2010
(in thousands)
(Unaudited)

	2011			2010
OPERATING ACTIVITIES
Net Income	$	128,515		$	121,960
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		100,564			101,932
Deferred Income Taxes		71,121			40,125
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net		13,544			(12,323	)
Allowance for Equity Funds Used During Construction		(11,790	)		(11,945	)
Mark-to-Market of Risk Management Contracts		9,014			(16,887	)
Amortization of Nuclear Fuel		107,801			113,031
Pension Contributions to Qualified Plan Trust		(21,030	)		(66,711	)
Fuel Over/Under-Recovery, Net		(4,676	)		(280	)
Change in Other Noncurrent Assets		15,975			20,044
Change in Other Noncurrent Liabilities		45,633			63,409
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		78,062			4,814
Fuel, Materials and Supplies		40,476			(12,021	)
Accounts Payable		(50,265	)		(10,928	)
Accrued Taxes, Net		74,510			72,156
Received Cook Plant Fire Costs		-			63,247
Other Current Assets		2,924			408
Other Current Liabilities		24,264			14,671
Net Cash Flows from Operating Activities		624,642			484,702

INVESTING ACTIVITIES
Construction Expenditures		(224,749	)		(224,488	)
Change in Advances to Affiliates, Net		(134,004	)		(78,767	)
Purchases of Investment Securities		(870,769	)		(1,128,747	)
Sales of Investment Securities		825,689			1,087,484
Acquisitions of Nuclear Fuel		(103,970	)		(69,459	)
Other Investing Activities		35,583			(6,213	)
Net Cash Flows Used for Investing Activities		(472,220	)		(420,190	)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated		76,414			84,564
Change in Advances from Affiliates, Net		(42,769	)		-
Retirement of Long-term Debt – Nonaffiliated		(122,469	)		(19,208	)
Retirement of Long-term Debt – Affiliated		-			(25,000	)
Retirement of Cumulative Preferred Stock		-			(1	)
Principal Payments for Capital Lease Obligations		(6,353	)		(26,785	)
Dividends Paid on Common Stock		(56,250	)		(78,250	)
Dividends Paid on Cumulative Preferred Stock		(255	)		(255	)
Other Financing Activities		53			433
Net Cash Flows Used for Financing Activities		(151,629	)		(64,502	)

Net Increase in Cash and Cash Equivalents		793			10
Cash and Cash Equivalents at Beginning of Period		361			779
Cash and Cash Equivalents at End of Period	$	1,154		$	789

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	76,390		$	81,576
Net Cash Paid (Received) for Income Taxes		(96,339	)		(66,680	)
Noncash Acquisitions Under Capital Leases		2,492			9,708
Construction Expenditures Included in Current Liabilities at September 30,		28,132			19,690
Acquisition of Nuclear Fuel Included in Current Liabilities at September 30,		46			20,332
Noncash Increase in Long-term Debt Through the Fort Wayne Lease Settlement		26,802			-

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

122

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 166.

	Footnote Reference

Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Commitments, Guarantees and Contingencies	Note 4
Benefit Plans	Note 6
Business Segments	Note 7
Derivatives and Hedging	Note 8
Fair Value Measurements	Note 9
Income Taxes	Note 10
Financing Activities	Note 11
Cost Reduction Initiatives	Note 12

123

OHIO POWER COMPANY CONSOLIDATED

124

OHIO POWER COMPANY CONSOLIDATED

MANAGEMENT’S DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Regulatory Activity

2009 – 2011 ESP

In April 2011, the Supreme Court of Ohio issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged and remanded certain issues back to the PUCO. In October 2011, the PUCO issued an order in the remand proceeding. The order required OPCo to refund POLR charges which were collected subject to refund since June 2011. As a result, in the third quarter of 2011, OPCo recorded a pretax refund provision of $9 million on the condensed statements of income. In addition, OPCo filed its 2010 SEET filings with the PUCO. Based upon the approach in the PUCO 2009 order, management does not currently believe that OPCo will have any significantly excessive earnings. See “Ohio Electric Security Plan Filings” section of Note 3.

January 2012 – May 2016 ESP

In January 2011, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation. In September 2011, a stipulation agreement was filed with the PUCO which involved various issues pending before the PUCO, including the approval of the CSPCo/OPCo merger and the recovery of deferred fuel until securitized. Under the stipulation agreement, rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2016. Prior to June 2015, OPCo’s SSO customers continue to pay the tariff rate for non-fuel generation and the fuel adjustment clause. Beginning in June 2015, OPCo will use results from a competitive bidding process performed prior to January 2015 to meet its SSO obligation through May 2016. The stipulation agreement proposed a corporate separation plan of OPCo’s generation assets to complete the transition to a fully competitive generation market by June 2015. In addition, to further develop customer choice and facilitate the transition to market generation pricing, OPCo will provide 21% of its generation capacity in 2012, 29% to 31% of its generation capacity in 2013 and 41% of its generation capacity beginning in 2014 through June 2015 to competitive retail suppliers at a charge based on the Reliability Pricing Model auction-clearing prices and the remainder at a discounted cost-based price.

The stipulation agreement also proposed a termination or modification of the Interconnection Agreement. Finally, the stipulation agreement provides for certain OPCo contingent contributions and established a Distribution Investment Rider beginning January 2012 through May 2015 to recover post-2000 distribution investment with certain limitations. See “Ohio Electric Security Plan Filings,” “Proposed CSPCo and OPCo Merger” and “Possible Termination of the Interconnection Agreement” sections of Note 3.

Ohio Distribution Base Rate Case

In February 2011, OPCo filed with the PUCO for an annual increase in distribution rates of $60 million. The requested increase is based upon an 11.15% return on common equity to be effective January 2012. In addition to the annual increases, OPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets of $159 million, including carrying costs, to be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013. The PUCO staff filed testimony that recommended a rate increase in the range of $23 million to $32 million plus recovery of the deferred distribution regulatory assets subject to a review of the carrying costs. A decision from the PUCO is expected in the fourth quarter of 2011. See “2011 Ohio Distribution Base Rate Case” section of Note 3.

125

Proposed CSPCo and OPCo Merger

Ohio Customer Choice

In OPCo’s service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service. As a result, in comparison to the third quarter of 2010 and the first nine months of 2010, OPCo lost approximately $7 million and $10 million, respectively, of generation and transmission related gross margin. OPCo is recovering a portion of lost margins through collection of transmission revenues from competitive CRES providers and off-system sales.

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 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2010 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 166. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2011		2010		2011		2010
		(in millions of KWHs)
Retail:
	Residential		2,008		2,087		5,879		5,842
	Commercial		1,546		1,534		4,334		4,332
	Industrial		3,451		3,175		10,184		9,469
	Miscellaneous		15		16		51		52
Total Retail			7,020		6,812		20,448		19,695

Wholesale			2,099		1,693		5,740		4,017

Total KWHs			9,119		8,505		26,188		23,712

126

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				Nine Months Ended
		September 30,				September 30,
		2011		2010		2011		2010
		(in degree days)

Actual - Heating (a)			11		3		2,460		2,296
Normal - Heating (b)			11		12		2,293		2,295

Actual - Cooling (c)			693		722		963		1,031
Normal - Cooling (b)			566		559		794		784

(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.

127

Third Quarter of 2011 Compared to Third Quarter of 2010

Reconciliation of Third Quarter of 2010 to Third Quarter of 2011
Net Income
(in millions)

Third Quarter of 2010	$	101

Changes in Gross Margin:
Retail Margins		(2	)
Off-system Sales		(3	)
Transmission Revenues		5
Other Revenues		6
Total Change in Gross Margin		6

Changes in Expenses and Other:
Other Operation and Maintenance		(14	)
Asset Impairments and Other Related Charges		(90	)
Depreciation and Amortization		(20	)
Taxes Other Than Income Taxes		(2	)
Carrying Costs Income		12
Other Income		2
Interest Expense		3
Total Change in Expenses and Other		(109	)

Income Tax Expense		49

Third Quarter of 2011	$	47

·	Retail Margins decreased $2 million primarily due to the following:
	·	A $13 million decrease in capacity settlements under the Interconnection Agreement.
	·	A $7 million decrease attributable to customers switching to alternative competitive retail electric service (CRES) providers.
	·	A $4 million decrease in residential sales due to decreased customer usage.
	These decreases were partially offset by:
	·	A $9 million net increase in transmission rider revenues.
	·	A $7 million increase related to Environmental Investment Carrying Charge Rider (EICCR) revenues.
	·	A $4 million increase in revenues due to a January 2011 Universal Service Fund (USF) surcharge rate increase. This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
·	Transmission Revenues increased $5 million primarily due to the Transmission Agreement modification effective November 2010, a portion of which is included in the Ohio Transmission Cost Recovery Rider and 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 $6 million primarily due to higher revenues from Cook Coal Terminal.

128

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

·	Other Operation and Maintenance expenses increased $14 million primarily due to the following:
	·	A $7 million increase due to the third quarter 2011 write-off of allocated Front-End Engineering and Design (FEED) study costs related to the Mountaineer Carbon Capture Project.
	·	A $4 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
	·	A $4 million increase in expenses related to Cook Coal Terminal.
·	Asset Impairments and Other Related Charges includes the third quarter 2011 plant impairments of Sporn Unit 5 ($48 million) and the FGD project at Muskingum River Unit 5 ($42 million).
·	Depreciation and Amortization increased $20 million primarily due to the amortization of debt and equity carrying costs on deferred fuel as a result of the October 2011 PUCO remand order which allowed the POLR refund to be applied against any deferred fuel balances. The equity amortization was offset by amounts recognized in Carrying Costs Income as discussed below.
·	Carrying Costs Income increased $12 million primarily due to the recognition of equity carrying costs income on deferred fuel as a result of the October 2011 PUCO remand order which allowed the POLR refund to be applied against any deferred fuel balances. The equity carrying costs income was offset by amounts in Depreciation and Amortization discussed above.
·	Interest Expense decreased $3 million primarily as a result of the retirement of long-term debt in November 2010.
·	Income Tax Expense decreased $49 million primarily due to a decrease in pretax book income and state income tax adjustments.

129

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Reconciliation of Nine Months Ended September 30, 2010 to Nine Months Ended September 30, 2011
Net Income
(in millions)

Nine Months Ended September 30, 2010	$	230

Changes in Gross Margin:
Retail Margins		13
Off-system Sales		10
Transmission Revenues		13
Other Revenues		6
Total Change in Gross Margin		42

Changes in Expenses and Other:
Other Operation and Maintenance		13
Asset Impairments and Other Related Charges		(90	)
Depreciation and Amortization		(24	)
Taxes Other Than Income Taxes		(3	)
Carrying Costs Income		16
Interest Expense		9
Total Change in Expenses and Other		(79	)

Income Tax Expense		30

Nine Months Ended September 30, 2011	$	223

·	Retail Margins increased $13 million primarily due to the following:
	·	A $21 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Energy Efficiency & Peak Demand Reduction (EE/PDR) Programs. This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
	·	A $20 million increase in revenues due to the implementation of PUCO approved rider rates in September 2010 related to the Environmental Investment Carrying Cost Rider (EICCR).
	·	A $13 million increase in revenues due to a January 2011 USF surcharge rate increase. This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
	·	A $6 million increase in margins due to increases in industrial customer usage. The industrial increase was driven primarily by increased load for Ormet, a major industrial customer.
	These increases were partially offset by:
	·	A $32 million decrease in capacity settlements under the Interconnection Agreement.
	·	A $10 million decrease attributable to customers switching to alternative CRES providers.
	·	A $4 million decrease related to increased consumable and allowance expenses not recovered through the FAC.
·	Margins from Off-system Sales increased $10 million primarily due to higher physical sales volumes, partially offset by lower trading and marketing margins.
·	Transmission Revenues increased $13 million primarily due to the Transmission Agreement modification effective November 2010, a portion of which is included in the Ohio Transmission Cost Recovery Rider and 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 $6 million primarily due to higher revenues from Cook Coal Terminal.

130

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

·	Other Operation and Maintenance expenses decreased $13 million primarily due to the following:
	·	A $53 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
	·	A $14 million decrease in recoverable PJM expenses.
	·	An $11 million gain from the sale of land in January 2011.
	These decreases were partially offset by:
	·	A $21 million increase in expenses due to the implementation of PUCO approved EE/PDR programs. This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
	·	A $13 million increase in plant maintenance expense primarily related to work performed at the Kammer, Mitchell and Amos plants.
	·	A $13 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
	·	A $7 million increase primarily due to a favorable 2010 employee benefit adjustment.
	·	A $7 million increase due to the third quarter 2011 write-off of allocated FEED study costs related to the Mountaineer Carbon Capture Project.
	·	A $3 million increase in expenses related to Cook Coal terminal.
·	Asset Impairments and Other Related Charges includes the third quarter 2011 plant impairments of Sporn Unit 5 ($48 million) and the FGD project at Muskingum River Unit 5 ($42 million).
·	Depreciation and Amortization increased $24 million primarily due to the following:
	·	A $19 million increase due to the amortization of debt and equity carrying costs on deferred fuel as a result of the October 2011 PUCO remand order which allowed the POLR refund to be applied against any deferred fuel balances. The equity amortization was offset by amounts recognized in Carrying Costs Income as discussed below.
	·	A $5 million increase due to higher depreciable property balances as a result of environmental and various other property additions.
·	Carrying Costs Income increased $16 million primarily due to the recognition of equity carrying costs income on deferred fuel as a result of the October 2011 PUCO remand order which allowed the POLR refund to be applied against any deferred fuel balances. The equity carrying costs income was offset by amounts in Depreciation and Amortization discussed above.
·	Interest Expense decreased $9 million primarily due to the retirement of long-term debt in November 2010.
·	Income Tax Expense decreased $30 million primarily due to a decrease in pretax book income, state income tax adjustments and the 2010 tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.

FINANCIAL CONDITION

LIQUIDITY

OPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity. OPCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures. See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 232 for additional discussion of liquidity.

131

Credit Ratings

OPCo’s access to capital markets may depend on its credit ratings. In addition, a credit rating downgrade of OPCo by one of the rating agencies could increase OPCo’s borrowing costs. Failure to maintain investment grade ratings may constrain OPCo’s ability to participate in the Utility Money Pool or the amount of OPCo’s receivables securitized by AEP Credit. Counterparty concerns about OPCo’s credit quality could subject OPCo to additional collateral demands under adequate assurance clauses under derivative and non-derivative energy contracts.

CASH FLOW

Cash flows for the nine months ended September 30, 2011 and 2010 were as follows:

	2011			2010
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	440		$	1,984
Net Cash Flows from Operating Activities		668,615			627,472
Net Cash Flows Used for Investing Activities		(245,288	)		(54,651	)
Net Cash Flows Used for Financing Activities		(422,358	)		(573,451	)
Net Increase (Decrease) in Cash and Cash Equivalents		969			(630	)
Cash and Cash Equivalents at End of Period	$	1,409		$	1,354

Operating Activities

Net Cash Flows from Operating Activities were $669 million in 2011. OPCo produced Net Income of $223 million during the period and noncash expense items of $295 million for Depreciation and Amortization, $90 million for Asset Impairments and Other Related Charges, $77 million for Property Taxes and $54 million for Deferred Income Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items. Fuel, Materials and Supplies had a $99 million inflow primarily due to a decrease in coal inventory and an increase in allowance usage. The $80 million outflow from Accrued Taxes, Net is primarily due to temporary timing differences of payments for property taxes partially offset by an increase of federal income tax related accruals. Accounts Receivable, Net had a $67 million inflow primarily due to a settlement with an affiliated company, a decrease in estimated accounts receivable balances and settlements of backup power sales. Accounts Payable had a $52 million outflow primarily due to payments to affiliates for allowance settlements.

Net Cash Flows from Operating Activities were $627 million in 2010. OPCo produced Net Income of $230 million during the period and noncash expense items of $270 million for Depreciation and Amortization, $126 million for Deferred Income Taxes and $72 million for Property Taxes. OPCo also contributed $47 million to the qualified pension trust. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. Fuel, Materials and Supplies had a $75 million inflow primarily due to a decrease in coal inventory reflecting increased customer demand for electricity. Accounts Receivable, Net had a $57 million inflow primarily due to decreased sales to affiliates and settlement of allowance sales to affiliated companies. Account Payable had a $46 million outflow primarily due to timing differences of payments. The $37 million inflow from Accrued Taxes, Net includes a third quarter 2010 income tax refund of $138 million as a result of a federal net income tax operating loss in 2009 that was carried back to 2007 and 2008. Items contributing to the net income tax operating loss include bonus depreciation and the favorable impact of a change in tax accounting method related to units of property. The $116 million increase in Fuel Over/Under-Recovery, Net reflects the deferral of fuel costs as a fuel clause was reactivated in 2009 under OPCo’s ESP.

132

Investing Activities

Net Cash Flows Used for Investing Activities were $245 million in 2011. OPCo had Construction Expenditures of $167 million and a net increase of $123 million in loans to the Utility Money Pool. Construction Expenditures were primarily related to projects to improve service reliability. These decreases were partially offset by $45 million in Proceeds from Sales of Assets.

Net Cash Flows Used for Investing Activities were $55 million in 2010. Construction Expenditures of $208 million primarily related to environmental upgrades, as well as projects to improve service reliability for transmission and distribution. Environmental upgrades include FGD projects at the Amos Plant. OPCo had a net decrease of $148 million loans to the Utility Money Pool.

Financing Activities

Net Cash Flows Used for Financing Activities were $422 million in 2011. OPCo retired $165 million of Pollution Control Bonds in March 2011. In addition, OPCo paid $300 million of dividends on common stock. These decreases were partially offset by the issuance of $50 million of Pollution Control Bonds in March 2011.

Net Cash Flows Used for Financing Activities were $573 million in 2010. OPCo issued Pollution Control Bonds of $86 million, $79 million and $39 million. OPCo retired $400 million of Senior Unsecured Notes. OPCo retired $79 million and $39 million of Pollution Control Bonds. In addition, OPCo paid $247 million of dividends on common stock.

Long-term debt issuances and retirements during the first nine months of 2011 were:

Issuances

	Principal			Interest	Due
Type of Debt	Amount			Rate	Date
	(in thousands)			(%)
Pollution Control Bonds	$	50,000	(a)	Variable	2014

(a)	These pollution control bonds are subject to redemption earlier than the maturity date. Consequently, this bond has been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on OPCo’s condensed balance sheets.

Retirements

	Principal		Interest	Due
Type of Debt	Amount Paid		Rate	Date
	(in thousands)		(%)
Pollution Control Bonds	$	65,000	Variable	2036
Pollution Control Bonds		50,000	Variable	2014
Pollution Control Bonds		50,000	Variable	2014

CONTRACTUAL OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2010 Annual Report and has not changed significantly from year-end other than debt issuances and retirements discussed in the “Cash Flow” section above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

133

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

134

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2011 and 2010
(in thousands)
(Unaudited)

	Three Months Ended						Nine Months Ended
	2011			2010			2011			2010
REVENUES
Electric Generation, Transmission and Distribution	$	637,801		$	583,084		$	1,823,480		$	1,617,206
Sales to AEP Affiliates		255,914			263,236			694,039			792,565
Other Revenues - Affiliated		9,066			5,065			20,591			16,794
Other Revenues - Nonaffiliated		4,262			4,474			11,732			12,531
TOTAL REVENUES		907,043			855,859			2,549,842			2,439,096

EXPENSES
Fuel and Other Consumables Used for Electric Generation		322,155			284,857			863,611			836,048	��
Purchased Electricity for Resale		40,590			42,840			129,585			120,476
Purchased Electricity from AEP Affiliates		45,966			36,004			111,828			79,778
Other Operation		119,122			106,314			313,509			341,887
Maintenance		53,820			52,448			187,739			172,151
Asset Impairments and Other Related Charges		89,824			-			89,824			-
Depreciation and Amortization		110,752			91,072			294,905			270,294
Taxes Other Than Income Taxes		54,109			52,261			160,275			157,433
TOTAL EXPENSES		836,338			665,796			2,151,276			1,978,067

OPERATING INCOME		70,705			190,063			398,566			461,029

Other Income (Expense):
Interest Income		1,871			583			2,416			1,322
Carrying Costs Income		18,393			6,324			33,049			16,879
Allowance for Equity Funds Used During Construction		841			947			2,234			2,964
Interest Expense		(35,772	)		(39,013	)		(109,474	)		(118,065	)

INCOME BEFORE INCOME TAX EXPENSE		56,038			158,904			326,791			364,129

Income Tax Expense		9,212			58,039			103,887			133,813

NET INCOME		46,826			100,865			222,904			230,316

Less: Preferred Stock Dividend Requirements		183			183			549			549

EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	46,643		$	100,682		$	222,355		$	229,767

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

135

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2011 and 2010
(in thousands)
(Unaudited)

								Accumulated
								Other
	Common		Paid-in		Retained			Comprehensive
	Stock		Capital		Earnings			Income (Loss)			Total
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2009	$	321,201	$	1,123,149	$	1,908,803		$	(118,458	)	$	3,234,695

Common Stock Dividends						(246,575	)					(246,575	)
Preferred Stock Dividends						(549	)					(549	)
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												2,987,571

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $1,158									(2,150	)		(2,150	)
Amortization of Pension and OPEB Deferred Costs,
Net of Tax of $2,846									5,285			5,285
NET INCOME						230,316						230,316
TOTAL COMPREHENSIVE INCOME												233,451

TOTAL COMMON SHAREHOLDER'S
EQUITY – SEPTEMBER 30, 2010	$	321,201	$	1,123,149	$	1,891,995		$	(115,323	)	$	3,221,022

TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2010	$	321,201	$	1,123,153	$	1,852,889		$	(128,819	)	$	3,168,424

Common Stock Dividends						(300,000	)					(300,000	)
Preferred Stock Dividends						(549	)					(549	)
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												2,867,875

COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $442									(821	)		(821	)
Amortization of Pension and OPEB Deferred Costs,
Net of Tax of $3,234									6,006			6,006
NET INCOME						222,904						222,904
TOTAL COMPREHENSIVE INCOME												228,089

TOTAL COMMON SHAREHOLDER'S
EQUITY – SEPTEMBER 30, 2011	$	321,201	$	1,123,153	$	1,775,244		$	(123,634	)	$	3,095,964

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

136

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2011 and December 31, 2010
(in thousands)
(Unaudited)

	2011			2010
CURRENT ASSETS
Cash and Cash Equivalents	$	1,409		$	440
Advances to Affiliates		223,522			100,500
Accounts Receivable:
Customers		67,724			86,186
Affiliated Companies		156,747			198,845
Accrued Unbilled Revenues		23,114			27,928
Miscellaneous		399			2,368
Allowance for Uncollectible Accounts		(2,034	)		(2,184	)
Total Accounts Receivable		245,950			313,143
Fuel		168,077			257,289
Materials and Supplies		121,759			134,181
Risk Management Assets		22,759			30,773
Accrued Tax Benefits		10,815			69,021
Prepayments and Other Current Assets		25,529			33,998
TOTAL CURRENT ASSETS		819,820			939,345

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation		6,701,929			6,890,110
Transmission		1,260,160			1,234,677
Distribution		1,669,735			1,626,390
Other Property, Plant and Equipment		360,175			359,254
Construction Work in Progress		157,769			153,110
Total Property, Plant and Equipment		10,149,768			10,263,541
Accumulated Depreciation and Amortization		3,671,813			3,606,777
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		6,477,955			6,656,764

OTHER NONCURRENT ASSETS
Regulatory Assets		1,033,130			934,011
Long-term Risk Management Assets		18,091			28,012
Deferred Charges and Other Noncurrent Assets		72,649			189,195
TOTAL OTHER NONCURRENT ASSETS		1,123,870			1,151,218

TOTAL ASSETS	$	8,421,645		$	8,747,327

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

137

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, 2011 and December 31, 2010
(Unaudited)

	2011			2010
	(in thousands)
CURRENT LIABILITIES
Accounts Payable:
General	$	164,059		$	170,240
Affiliated Companies		102,540			136,215
Long-term Debt Due Within One Year – Nonaffiliated		50,000			165,000
Risk Management Liabilities		14,599			22,166
Customer Deposits		23,955			28,228
Accrued Taxes		129,917			229,253
Accrued Interest		44,830			46,184
Other Current Liabilities		93,231			98,687
TOTAL CURRENT LIABILITIES		623,131			895,973

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		2,364,910			2,364,522
Long-term Debt – Affiliated		200,000			200,000
Long-term Risk Management Liabilities		5,521			8,403
Deferred Income Taxes		1,559,386			1,531,639
Regulatory Liabilities and Deferred Investment Tax Credits		131,044			126,403
Employee Benefits and Pension Obligations		230,026			246,517
Deferred Credits and Other Noncurrent Liabilities		195,050			188,830
TOTAL NONCURRENT LIABILITIES		4,685,937			4,666,314

TOTAL LIABILITIES		5,309,068			5,562,287

Cumulative Preferred Stock Not Subject to Mandatory Redemption		16,613			16,616

Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 40,000,000 Shares
Outstanding – 27,952,473 Shares		321,201			321,201
Paid-in Capital		1,123,153			1,123,153
Retained Earnings		1,775,244			1,852,889
Accumulated Other Comprehensive Income (Loss)		(123,634	)		(128,819	)
TOTAL COMMON SHAREHOLDER’S EQUITY		3,095,964			3,168,424

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	8,421,645		$	8,747,327

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

138

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2011 and 2010
(in thousands)
(Unaudited)

	2011			2010
OPERATING ACTIVITIES
Net Income	$	222,904		$	230,316
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		294,905			270,294
Deferred Income Taxes		53,598			126,128
Asset Impairments and Other Related Charges		89,824			-
Carrying Costs Income		(33,049	)		(16,879	)
Allowance for Equity Funds Used During Construction		(2,234	)		(2,964	)
Mark-to-Market of Risk Management Contracts		7,826			(7,726	)
Pension Contributions to Qualified Plan Trust		(12,519	)		(47,174	)
Property Taxes		77,039			72,392
Fuel Over/Under-Recovery, Net		(56,225	)		(115,926	)
Change in Other Noncurrent Assets		(42,723	)		(4,136	)
Change in Other Noncurrent Liabilities		27,312			1,009
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		67,193			56,752
Fuel, Materials and Supplies		99,299			74,604
Accounts Payable		(51,959	)		(45,601	)
Accrued Taxes, Net		(80,406	)		36,534
Other Current Assets		7,493			(5,170	)
Other Current Liabilities		337			5,019
Net Cash Flows from Operating Activities		668,615			627,472

INVESTING ACTIVITIES
Construction Expenditures		(166,822	)		(207,663	)
Change in Advances to Affiliates, Net		(123,022	)		147,638
Acquisitions of Assets		(1,200	)		(4,876	)
Proceeds from Sales of Assets		44,549			10,406
Other Investing Activities		1,207			(156	)
Net Cash Flows Used for Investing Activities		(245,288	)		(54,651	)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated		49,757			202,382
Retirement of Long-term Debt – Nonaffiliated		(165,000	)		(518,580	)
Retirement of Cumulative Preferred Stock		(2	)		-
Principal Payments for Capital Lease Obligations		(6,437	)		(5,886	)
Dividends Paid on Common Stock		(300,000	)		(246,575	)
Dividends Paid on Cumulative Preferred Stock		(549	)		(549	)
Other Financing Activities		(127	)		(4,243	)
Net Cash Flows Used for Financing Activities		(422,358	)		(573,451	)

Net Increase (Decrease) in Cash and Cash Equivalents		969			(630	)
Cash and Cash Equivalents at Beginning of Period		440			1,984
Cash and Cash Equivalents at End of Period	$	1,409		$	1,354

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	109,001		$	116,140
Net Cash Paid (Received) for Income Taxes		41,871			(110,627	)
Noncash Acquisitions Under Capital Leases		1,519			23,645
Construction Expenditures Included in Current Liabilities at September 30,		33,604			13,156

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

139

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 166.

	Footnote Reference

Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Commitments, Guarantees and Contingencies	Note 4
Acquisitions and Impairments	Note 5
Benefit Plans	Note 6
Business Segments	Note 7
Derivatives and Hedging	Note 8
Fair Value Measurements	Note 9
Income Taxes	Note 10
Financing Activities	Note 11
Cost Reduction Initiatives	Note 12

140

PUBLIC SERVICE COMPANY OF OKLAHOMA

141

PUBLIC SERVICE COMPANY OF OKLAHOMA

MANAGEMENT’S DISCUSSION AND ANALYSIS

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 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2010 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 166. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2011		2010		2011		2010
		(in millions of KWHs)
Retail:
	Residential		2,423		2,303		5,500		5,363
	Commercial		1,476		1,510		3,996		3,953
	Industrial		1,378		1,321		3,743		3,714
	Miscellaneous		390		376		1,007		974
Total Retail			5,667		5,510		14,246		14,004

Wholesale			314		352		866		906

Total KWHs			5,981		5,862		15,112		14,910

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				Nine Months Ended
		September 30,				September 30,
		2011		2010		2011		2010
		(in degree days)

Actual - Heating (a)			-		-		1,276		1,344
Normal - Heating (b)			2		2		1,102		1,090

Actual - Cooling (c)			1,749		1,553		2,694		2,330
Normal - Cooling (b)			1,391		1,387		2,028		2,021

(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.

142

Third Quarter of 2011 Compared to Third Quarter of 2010

Reconciliation of Third Quarter of 2010 to Third Quarter of 2011
Net Income
(in millions)

Third Quarter of 2010	$	55

Changes in Gross Margin:
Retail Margins (a)		8
Off-system Sales		1
Transmission Revenues		1
Other Revenues		1
Total Change in Gross Margin		11

Changes in Expenses and Other:
Other Operation and Maintenance		(14	)
Depreciation and Amortization		2
Taxes Other Than Income Taxes		(1	)
Other Income		1
Interest Expense		2
Total Change in Expenses and Other		(10	)

Income Tax Expense		1

Third Quarter of 2011	$	57

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

·	Retail Margins increased $8 million primarily due to the following:
	·	A $7 million increase in weather-related usage primarily due to a 13% increase in cooling degree days.
	This increase was partially offset by:
	·	A net $1 million decrease primarily due to revenue decreases from rate riders. Some of the significant rider decreases include the Lawton rider, which ended in August 2010, and decreased purchased power capacity riders. These revenue decreases were partially offset by certain rider increases including the 2010 ice storm rider, which began in August 2011, and demand side management riders. This net decrease in retail margins had corresponding decreases to riders/trackers recognized in other expense items.

Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expenses increased $14 million primarily due to the following:
	·	A $5 million increase in SPP transmission services and administrative fees.
	·	A $3 million increase in distribution maintenance expenses primarily due to increased storm amortization that began in August 2011 related to the 2010 ice storm. This increase in Other Operation and Maintenance expenses was offset by a corresponding increase in Retail Margins discussed above.
	·	A $3 million increase in demand side management programs. This increase in Other Operation and Maintenance expenses was offset by a corresponding increase in Retail Margins discussed above.

143

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Reconciliation of Nine Months Ended September 30, 2010 to Nine Months Ended September 30, 2011
Net Income
(in millions)

Nine Months Ended September 30, 2010	$	75

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		26
Depreciation and Amortization		8
Taxes Other Than Income Taxes		(1)
Interest Expense		5
Total Change in Expenses and Other		38

Income Tax Expense		(16)

Nine Months Ended September 30, 2011	$	104

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

·	Retail Margins increased $6 million primarily due to the following:
	·	An $11 million increase in weather-related usage primarily due to a 16% increase in cooling degree days.
	·	A $6 million increase primarily due to decreased capacity and fuel costs.
	These increases were partially offset by:
	·	An $11 million decrease primarily due to revenue decreases from rate riders. This decrease in retail margins had corresponding decreases to riders/trackers recognized in other expense items.

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

·	Other Operation and Maintenance expenses decreased $26 million primarily due to the following:
	·	A $23 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
	·	A $5 million decrease in plant maintenance expenses resulting primarily from the 2011 deferral of generation maintenance expenses as a result of PSO’s base rate case.
	These decreases were partially offset by:
	·	A $6 million increase in demand side management programs.
·	Depreciation and Amortization expenses decreased $8 million primarily due to a decrease in amortization of regulatory assets related to the Lawton settlement which was fully recovered in August 2010.
·	Interest Expense decreased $5 million primarily due to lower interest rates and lower long-term debt outstanding in 2011 and 2010 Oklahoma income tax settlements.
·	Income Tax Expense increased $16 million primarily due to in an increase in pretax book income.

144

FINANCIAL CONDITION

LIQUIDITY

PSO participates in the Utility Money Pool, which provides access to AEP’s liquidity. PSO relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures. See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 232 for additional discussion of liquidity.

Credit Ratings

PSO’s access to capital markets may depend on its credit ratings. In addition, a credit rating downgrade of PSO by one of the rating agencies could increase PSO’s borrowing costs. Failure to maintain investment grade ratings may constrain PSO’s ability to participate in the Utility Money Pool or the amount of PSO’s receivables securitized by AEP Credit. Counterparty concerns about PSO’s credit quality could subject PSO to additional collateral demands under adequate assurance clauses under derivative and non-derivative energy contracts.

CASH FLOW

Cash flows for the nine months ended September 30, 2011 and 2010 were as follows:

	2011			2010
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	470		$	796
Net Cash Flows from Operating Activities		377,813			107,685
Net Cash Flows Used for Investing Activities		(201,372	)		(90,344	)
Net Cash Flows Used for Financing Activities		(174,638	)		(16,550	)
Net Increase in Cash and Cash Equivalents		1,803			791
Cash and Cash Equivalents at End of Period	$	2,273		$	1,587

Operating Activities

Net Cash Flows from Operating Activities were $378 million in 2011. PSO produced Net Income of $104 million during the period and had noncash expense items of $73 million for Depreciation and Amortization and $46 million for Deferred Income Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. The $64 million inflow from Accrued Taxes, Net was primarily the result of a refund for the 2010 overpayment of federal income taxes and increased accruals related to property and income taxes. The $54 million inflow from Accounts Receivable, Net was primarily due to decreases in both affiliated and customer receivables.

Net Cash Flows from Operating Activities were $108 million in 2010. PSO produced Net Income of $75 million during the period and had noncash expense items of $81 million for Depreciation and Amortization and $44 million for Deferred Income Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a $39 million inflow from Accrued Taxes, Net that includes a third quarter 2010 income tax refund of $11 million as a result of a federal net income tax operating loss in 2009 that was carried back to 2007 and 2008. Items contributing to the net income tax operating loss include bonus depreciation and the favorable impact of a change in tax accounting method related to units of property. The $108 million outflow from Fuel Over/Under-Recovery, Net was the result of higher fuel costs in relation to commission-approved fuel recovery rates.

145

Investing Activities

Net Cash Flows Used for Investing Activities during 2011 and 2010 were $201 million and $90 million, respectively. Construction Expenditures of $97 million and $153 million in 2011 and 2010, respectively, were primarily for projects to improve generation and service reliability for transmission and distribution in addition to customer service work. Construction Expenditures in 2010 also included storm restoration work. During 2011, PSO had a net increase of $105 million in loans to the Utility Money Pool. During 2010, PSO had a net decrease of $63 million in loans to the Utility Money Pool.

Financing Activities

Net Cash Flows Used for Financing Activities were $175 million during 2011. PSO retired $275 million of Senior Unsecured Notes. PSO had a net decrease of $91 million in borrowings from the Utility Money Pool. In addition, PSO paid $53 million in common stock dividends. These decreases were partially offset by the issuance of $250 million of Senior Unsecured Notes.

Net Cash Flows from Financing Activities were $17 million during 2010. PSO paid $38 million in common stock dividends. This outflow was partially offset by a net increase of $23 million in borrowings from the Utility Money Pool.

Long-term debt issuances and retirements during the first nine months of 2011 were:

Issuances

	Principal		Interest	Due
Type of Debt	Amount		Rate	Date
	(in thousands)		(%)
Senior Unsecured Notes	$	250,000	4.40	2021
Notes Payable		1,187	3.00	2026

Retirements

	Principal		Interest	Due
Type of Debt	Amount Paid		Rate	Date
	(in thousands)		(%)
Senior Unsecured Notes	$	200,000	6.00	2032
Senior Unsecured Notes		75,000	4.70	2011

CONTRACTUAL OBLIGATION INFORMATION

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

146

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2011 and 2010
(in thousands)
(Unaudited)

	Three Months Ended						Nine Months Ended
	2011			2010			2011			2010
REVENUES
Electric Generation, Transmission and Distribution	$	454,802		$	420,877		$	1,061,417		$	971,822
Sales to AEP Affiliates		2,115			4,665			10,696			17,816
Other Revenues		669			1,027			2,064			2,372
TOTAL REVENUES		457,586			426,569			1,074,177			992,010

EXPENSES
Fuel and Other Consumables Used for Electric Generation		168,230			140,367			360,774			269,954
Purchased Electricity for Resale		42,455			50,691			129,652			149,226
Purchased Electricity from AEP Affiliates		17,477			17,458			43,199			38,921
Other Operation		58,225			50,575			151,365			171,074
Maintenance		31,892			25,867			77,765			83,844
Depreciation and Amortization		24,802			26,703			72,761			80,911
Taxes Other Than Income Taxes		11,499			10,254			32,589			31,539
TOTAL EXPENSES		354,580			321,915			868,105			825,469

OPERATING INCOME		103,006			104,654			206,072			166,541

Other Income (Expense):
Interest Income		164			27			244			302
Carrying Costs Income		810			763			3,333			2,449
Allowance for Equity Funds Used During Construction		189			21			839			387
Interest Expense		(13,831	)		(15,759	)		(44,027	)		(48,887	)

INCOME BEFORE INCOME TAX EXPENSE		90,338			89,706			166,461			120,792

Income Tax Expense		32,989			34,274			62,163			45,732

NET INCOME		57,349			55,432			104,298			75,060

Preferred Stock Dividend Requirements		49			48			147			151

EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	57,300		$	55,384		$	104,151		$	74,909

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

147

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2011 and 2010
(in thousands)
(Unaudited)

								Accumulated
								Other
	Common		Paid-in		Retained			Comprehensive
	Stock		Capital		Earnings			Income (Loss)			Total
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2009	$	157,230	$	364,231	$	290,880		$	(599	)	$	811,742

Common Stock Dividends						(38,026	)					(38,026	)
Preferred Stock Dividends						(151	)					(151	)
Gain on Reacquired Preferred Stock				76								76
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												773,641

COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $97									181			181
NET INCOME						75,060						75,060
TOTAL COMPREHENSIVE INCOME												75,241

TOTAL COMMON SHAREHOLDER'S
EQUITY – SEPTEMBER 30, 2010	$	157,230	$	364,307	$	327,763		$	(418	)	$	848,882

TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2010	$	157,230	$	364,307	$	312,441		$	8,494		$	842,472

Common Stock Dividends						(52,500	)					(52,500	)
Preferred Stock Dividends						(147	)					(147	)
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												789,825

COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $640									(1,188	)		(1,188	)
NET INCOME						104,298						104,298
TOTAL COMPREHENSIVE INCOME												103,110

TOTAL COMMON SHAREHOLDER'S
EQUITY – SEPTEMBER 30, 2011	$	157,230	$	364,307	$	364,092		$	7,306		$	892,935

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

148

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2011 and December 31, 2010
(in thousands)
(Unaudited)

	2011			2010
CURRENT ASSETS
Cash and Cash Equivalents	$	2,273		$	470
Advances to Affiliates		105,116			-
Accounts Receivable:
Customers		24,887			43,049
Affiliated Companies		30,898			65,070
Miscellaneous		3,812			5,497
Allowance for Uncollectible Accounts		(947	)		(971	)
Total Accounts Receivable		58,650			112,645
Fuel		17,248			20,176
Materials and Supplies		48,707			46,247
Risk Management Assets		1,155			14,225
Accrued Tax Benefits		8,560			38,589
Regulatory Asset for Under-Recovered Fuel Costs		32,873			37,262
Prepayments and Other Current Assets		15,379			9,416
TOTAL CURRENT ASSETS		289,961			279,030

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation		1,317,603			1,330,368
Transmission		689,780			663,994
Distribution		1,743,446			1,686,470
Other Property, Plant and Equipment		239,615			235,406
Construction Work in Progress		46,114			59,091
Total Property, Plant and Equipment		4,036,558			3,975,329
Accumulated Depreciation and Amortization		1,281,237			1,255,064
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		2,755,321			2,720,265

OTHER NONCURRENT ASSETS
Regulatory Assets		252,127			263,545
Long-term Risk Management Assets		1,373			252
Deferred Charges and Other Noncurrent Assets		24,138			20,979
TOTAL OTHER NONCURRENT ASSETS		277,638			284,776

TOTAL ASSETS	$	3,322,920		$	3,284,071

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

149

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, 2011 and December 31, 2010
(Unaudited)

	2011		2010
	(in thousands)
CURRENT LIABILITIES
Advances from Affiliates	$	-	$	91,382
Accounts Payable:
General		80,309		69,155
Affiliated Companies		49,605		53,179
Long-term Debt Due Within One Year – Nonaffiliated		350		25,000
Risk Management Liabilities		616		922
Customer Deposits		46,508		41,217
Accrued Taxes		67,962		25,390
Accrued Interest		15,889		9,238
Other Current Liabilities		40,872		38,095
TOTAL CURRENT LIABILITIES		302,111		353,578

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		945,385		946,186
Long-term Risk Management Liabilities		210		197
Deferred Income Taxes		699,188		660,783
Regulatory Liabilities and Deferred Investment Tax Credits		337,480		336,961
Employee Benefits and Pension Obligations		92,714		98,107
Deferred Credits and Other Noncurrent Liabilities		48,015		40,905
TOTAL NONCURRENT LIABILITIES		2,122,992		2,083,139

TOTAL LIABILITIES		2,425,103		2,436,717

Cumulative Preferred Stock Not Subject to Mandatory Redemption		4,882		4,882

Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

COMMON SHAREHOLDER’S EQUITY
Common Stock – Par Value – $15 Per Share:
Authorized – 11,000,000 Shares
Issued – 10,482,000 Shares
Outstanding – 9,013,000 Shares		157,230		157,230
Paid-in Capital		364,307		364,307
Retained Earnings		364,092		312,441
Accumulated Other Comprehensive Income (Loss)		7,306		8,494
TOTAL COMMON SHAREHOLDER’S EQUITY		892,935		842,472

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	3,322,920	$	3,284,071

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

150

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2011 and 2010
(in thousands)
(Unaudited)

	2011			2010
OPERATING ACTIVITIES
Net Income	$	104,298		$	75,060
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		72,761			80,911
Deferred Income Taxes		45,927			43,631
Carrying Costs Income		(3,333	)		(2,449	)
Allowance for Equity Funds Used During Construction		(839	)		(387	)
Mark-to-Market of Risk Management Contracts		(2,226	)		(3,248	)
Property Taxes		(9,715	)		(9,198	)
Fuel Over/Under-Recovery, Net		4,389			(107,657	)
Change in Other Noncurrent Assets		14,041			(11,319	)
Change in Other Noncurrent Liabilities		22,794			6,110
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		53,995			(162	)
Fuel, Materials and Supplies		468			2,190
Accounts Payable		3,506			6,421
Accrued Taxes, Net		63,993			38,830
Other Current Assets		(3,839	)		(494	)
Other Current Liabilities		11,593			(10,554	)
Net Cash Flows from Operating Activities		377,813			107,685

INVESTING ACTIVITIES
Construction Expenditures		(97,038	)		(152,589	)
Change in Advances to Affiliates, Net		(105,116	)		62,695
Other Investing Activities		782			(450	)
Net Cash Flows Used for Investing Activities		(201,372	)		(90,344	)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated		247,481			1,740
Change in Advances from Affiliates, Net		(91,382	)		23,024
Retirement of Long-term Debt – Nonaffiliated		(275,000	)		-
Retirement of Cumulative Preferred Stock		-			(300	)
Principal Payments for Capital Lease Obligations		(3,103	)		(3,025	)
Dividends Paid on Common Stock		(52,500	)		(38,026	)
Dividends Paid on Cumulative Preferred Stock		(147	)		(151	)
Other Financing Activities		13			188
Net Cash Flows Used for Financing Activities		(174,638	)		(16,550	)

Net Increase in Cash and Cash Equivalents		1,803			791
Cash and Cash Equivalents at Beginning of Period		470			796
Cash and Cash Equivalents at End of Period	$	2,273		$	1,587

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	23,397		$	37,915
Net Cash Paid (Received) for Income Taxes		(26,536	)		(18,520	)
Noncash Acquisitions Under Capital Leases		634			13,572
Construction Expenditures Included in Current Liabilities at September 30,		13,400			5,254

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

151

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 166.

	Footnote Reference

Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Commitments, Guarantees and Contingencies	Note 4
Benefit Plans	Note 6
Business Segments	Note 7
Derivatives and Hedging	Note 8
Fair Value Measurements	Note 9
Income Taxes	Note 10
Financing Activities	Note 11
Cost Reduction Initiatives	Note 12

152

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

153

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

MANAGEMENT’S DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Regulatory Activity

Turk Plant

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 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2010 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 166. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

154

RESULTS OF OPERATIONS

KWH Sales/Degree Days

Summary of KWH Energy Sales

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2011		2010		2011		2010
		(in millions of KWHs)
Retail:
	Residential		2,372		2,106		5,621		5,095
	Commercial		1,831		1,830		4,861		4,743
	Industrial		1,372		1,347		4,049		3,877
	Miscellaneous		19		20		61		60
Total Retail			5,594		5,303		14,592		13,775

Wholesale			2,410		2,053		6,074		5,604

Total KWHs			8,004		7,356		20,666		19,379

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				Nine Months Ended
		September 30,				September 30,
		2011		2010		2011		2010
		(in degree days)

Actual - Heating (a)			-		-		866		1,043
Normal - Heating (b)			1		1		774		767

Actual - Cooling (c)			1,732		1,586		2,717		2,484
Normal - Cooling (b)			1,381		1,371		2,112		2,094

(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.

155

Third Quarter of 2011 Compared to Third Quarter of 2010

Reconciliation of Third Quarter of 2010 to Third Quarter of 2011
Net Income
(in millions)

Third Quarter of 2010	$	82

Changes in Gross Margin:
Retail Margins (a)		17
Transmission Revenues		3
Total Change in Gross Margin		20

Changes in Expenses and Other:
Other Operation and Maintenance		(18	)
Depreciation and Amortization		(2	)
Interest Income		1
Allowance for Equity Funds Used During Construction		4
Interest Expense		2
Total Change in Expenses and Other		(13	)

Income Tax Expense		(1	)

Third Quarter of 2011	$	88

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

·	Retail Margins increased $17 million primarily due to:
	·	A $12 million increase due to increased gross margin from sales to customers previously served by Valley Electric Membership Corporation (VEMCO). SWEPCo acquired VEMCO assets and began serving VEMCO customers in October 2010.
	·	An $8 million increase in weather-related usage primarily due to a 9% increase in cooling degree days.

Expenses and Other changed between years as follows:

·	Other Operation and Maintenance expenses increased $18 million primarily due to:
	·	A $7 million increase in maintenance expenses primarily due to planned and unplanned generation plant outages in addition to increased storm-related expenses.
	·	A $4 million increase in employee-related expenses.
	·	A $3 million increase in SPP transmission services and administrative fees.
	·	A $2 million increase in litigation expenses.
·	Allowance for Equity Funds Used During Construction increased $4 million primarily due to construction at the Turk Plant.

156

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Reconciliation of Nine Months Ended September 30, 2010 to Nine Months Ended September 30, 2011
Net Income
(in millions)

Nine Months Ended September 30, 2010	$	139

Changes in Gross Margin:
Retail Margins (a)		55
Other Revenues		1
Total Change in Gross Margin		56

Changes in Expenses and Other:
Other Operation and Maintenance		(1)
Depreciation and Amortization		(5)
Taxes Other Than Income Taxes		(2)
Interest Income		1
Allowance for Equity Funds Used During Construction		(2)
Interest Expense		(1)
Total Change in Expenses and Other		(10)

Income Tax Expense		(16)

Nine Months Ended September 30, 2011	$	169

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

·	Retail Margins increased $55 million primarily due to:
	·	A $29 million increase due to increased gross margin from sales to customers previously served by VEMCO. SWEPCo acquired VEMCO assets and began serving VEMCO customers in October 2010.
	·	A $23 million increase primarily due to rate increases from wholesale customers on formula rates and base rate increases in Texas.

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

·	Other Operation and Maintenance expenses increased $1 million primarily due to:
	·	A $26 million increase in maintenance expenses primarily due to planned and unplanned generation plant outages in addition to increased storm-related expenses.
	This increase was partially offset by:
	·	A $28 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
·	Depreciation and Amortization expenses increased $5 million primarily due to a greater depreciation base, including the addition of the Stall Unit which was placed into service in June 2010.
·	Allowance for Equity Funds Used During Construction decreased $2 million primarily due to completed construction of the Stall Unit in June 2010, partially offset by construction at the Turk Plant.
·	Income Tax Expense increased $16 million primarily due to an increase in pretax book income.

157

FINANCIAL CONDITION

LIQUIDITY

SWEPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity. SWEPCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures. See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 232 for additional discussion of liquidity.

Credit Ratings

SWEPCo’s access to capital markets may depend on its credit ratings. In addition, a credit rating downgrade of SWEPCo by one of the rating agencies could increase SWEPCo’s borrowing costs. Failure to maintain investment grade ratings may constrain SWEPCo’s ability to participate in the Utility Money Pool or the amount of SWEPCo’s receivables securitized by AEP Credit. Counterparty concerns about SWEPCo’s credit quality could subject SWEPCo to additional collateral demands under adequate assurance clauses under derivative and non-derivative energy contracts.

CASH FLOW

Cash flows for the nine months ended September 30, 2011 and 2010 were as follows:

	2011			2010
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	1,514		$	1,661
Net Cash Flows from Operating Activities		332,271			168,196
Net Cash Flows Used for Investing Activities		(312,450	)		(449,053	)
Net Cash Flows from (Used for) Financing Activities		(15,551	)		281,078
Net Increase in Cash and Cash Equivalents		4,270			221
Cash and Cash Equivalents at End of Period	$	5,784		$	1,882

Operating Activities

Net Cash Flows from Operating Activities were $332 million in 2011. SWEPCo produced Net Income of $169 million during the period and had noncash items of $100 million for Depreciation and Amortization and $37 million for Deferred Income Taxes, partially offset by $35 million in Allowance for Equity Funds Used During Construction. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. The $69 million inflow from Accrued Taxes, Net was the result of increased accruals related to income and property taxes and tax refunds for the prior year. The $22 million outflow from Accrued Interest was primarily due to timing between interest accruals and payments related to SWEPCo’s Senior Unsecured Notes. The $30 million outflow from Fuel Over/Under-Recovery, Net was primarily due to lower fuel cost recovery and SIA refunds in Arkansas and Louisiana.

Net Cash Flows from Operating Activities were $168 million in 2010. SWEPCo produced Net Income of $139 million during the period and had a noncash item of $95 million for Depreciation and Amortization, partially offset by $37 million in Allowance for Equity Funds Used During Construction. SWEPCo contributed $27 million to the qualified pension trust. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. The $49 million inflow from Accrued Taxes, Net was the result of an increase in accruals related to federal and property taxes. The $36 million outflow from Accounts Payable was primarily due to decreases related to customer accounts factored, net and purchased power payable. The $28 million inflow from Fuel, Materials and Supplies was primarily due to decreased coal and lignite inventories. The $24 million outflow from Accounts Receivable, Net was primarily due to increased affiliated receivables.

158

Investing Activities

Net Cash Flows Used for Investing Activities during 2011 and 2010 were $312 million and $449 million, respectively. Construction Expenditures of $395 million and $288 million in 2011 and 2010, respectively, were primarily for generation projects at the Turk Plant and Stall Unit, as well as projects to improve service reliability for distribution and transmission. The Stall Unit was placed in service in the second quarter of 2010. During 2011, SWEPCo had a net decrease of $86 million in loans to the Utility Money Pool. During 2010, SWEPCo had a net increase of $162 million in loans to the Utility Money Pool.

Financing Activities

Net Cash Flows Used for Financing Activities were $16 million during 2011. SWEPCo retired $41 million of Pollution Control Bonds and paid $10 million in principal payments for capital lease obligations. In addition, SWEPCo had a $6 million net decrease in revolving credit facility balances. These decreases were partially offset by a net increase of $42 million in borrowings from the Utility Money Pool.

Net Cash Flows from Financing Activities were $281 million during 2010. SWEPCo issued $350 million of Senior Unsecured Notes and $54 million of Pollution Control Bonds. These increases were partially offset by a $54 million retirement of Pollution Control Bonds and a $50 million retirement of Notes Payable – Affiliated. In addition, SWEPCo had a $4 million net decrease in revolving credit facility balances.

Long-term debt retirements during the first nine months of 2011 were:

Retirements

	Principal		Interest	Due
Type of Debt	Amount Paid		Rate	Date
	(in thousands)		(%)
Pollution Control Bonds	$	41,135	4.50	2011

CONTRACTUAL OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2010 Annual Report and has not changed significantly from year-end other than the debt retirements discussed in the “Cash Flow” section above.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

159

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2011 and 2010
(in thousands)
(Unaudited)

	Three Months Ended						Nine Months Ended
	2011			2010			2011			2010
REVENUES
Electric Generation, Transmission and Distribution	$	512,767		$	459,013		$	1,248,031		$	1,139,748
Sales to AEP Affiliates		21,618			21,356			47,868			43,920
Other Revenues		597			613			1,572			1,585
TOTAL REVENUES		534,982			480,982			1,297,471			1,185,253

EXPENSES
Fuel and Other Consumables Used for Electric Generation		213,004			194,340			486,729			452,279
Purchased Electricity for Resale		47,241			29,794			125,521			94,521
Purchased Electricity from AEP Affiliates		1,880			4,191			9,107			18,154
Other Operation		63,655			52,839			168,445			193,357
Maintenance		30,895			23,979			95,076			69,531
Depreciation and Amortization		33,919			31,828			99,927			94,939
Taxes Other Than Income Taxes		15,982			15,583			49,678			47,058
TOTAL EXPENSES		406,576			352,554			1,034,483			969,839

OPERATING INCOME		128,406			128,428			262,988			215,414

Other Income (Expense):
Interest Income		1,070			186			1,181			434
Allowance for Equity Funds Used During Construction		12,692			8,651			34,861			36,630
Interest Expense		(20,964	)		(23,459	)		(64,224	)		(63,478	)

INCOME BEFORE INCOME TAX EXPENSE AND
EQUITY EARNINGS		121,204			113,806			234,806			189,000

Income Tax Expense		34,217			32,870			68,184			51,733
Equity Earnings of Unconsolidated Subsidiary		808			749			2,071			2,206

NET INCOME		87,795			81,685			168,693			139,473

Less: Net Income Attributable to Noncontrolling Interest		1,023			774			3,141			3,198

NET INCOME ATTRIBUTABLE TO SWEPCo
SHAREHOLDERS		86,772			80,911			165,552			136,275

Less: Preferred Stock Dividend Requirements		58			58			172			172

EARNINGS ATTRIBUTABLE TO SWEPCo COMMON
SHAREHOLDER	$	86,714		$	80,853		$	165,380		$	136,103

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

160

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2011 and 2010
(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, 2009	$	135,660	$	674,979	$	726,478		$	(12,991	)	$	31		$	1,524,157

Common Stock Dividends – Nonaffiliated												(2,966	)		(2,966	)
Preferred Stock Dividends						(172	)								(172	)
SUBTOTAL – EQUITY															1,521,019

COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $248									461						461
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $379									703						703
NET INCOME						136,275						3,198			139,473
TOTAL COMPREHENSIVE INCOME															140,637

TOTAL EQUITY – SEPTEMBER 30, 2010	$	135,660	$	674,979	$	862,581		$	(11,827	)	$	263		$	1,661,656

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

Common Stock Dividends – Nonaffiliated												(3,183	)		(3,183	)
Preferred Stock Dividends						(172	)								(172	)
SUBTOTAL – EQUITY															1,663,994

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
Taxes:
Cash Flow Hedges, Net of Tax of $5,195									(9,648	)					(9,648	)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $206									383						383
NET INCOME						165,552						3,141			168,693
TOTAL COMPREHENSIVE INCOME															159,428

TOTAL EQUITY – SEPTEMBER 30, 2011	$	135,660	$	674,979	$	1,034,220		$	(21,756	)	$	319		$	1,823,422

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

161

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2011 and December 31, 2010
(in thousands)
(Unaudited)

	2011			2010
CURRENT ASSETS
Cash and Cash Equivalents	$	5,784		$	1,514
Advances to Affiliates		-			86,222
Accounts Receivable:
Customers		16,955			34,434
Affiliated Companies		46,927			43,219
Miscellaneous		22,547			17,739
Allowance for Uncollectible Accounts		(1,174	)		(588	)
Total Accounts Receivable		85,255			94,804
Fuel
(September 30, 2011 and December 31, 2010 amounts include $26,484 and $35,055, respectively, related to Sabine)		96,908			91,777
Materials and Supplies		55,772			50,395
Risk Management Assets		556			1,209
Deferred Income Tax Benefits		6,012			15,529
Accrued Tax Benefits		623			37,900
Regulatory Asset for Under-Recovered Fuel Costs		14,585			758
Prepayments and Other Current Assets		21,956			24,270
TOTAL CURRENT ASSETS		287,451			404,378

PROPERTY, PLANT AND EQUIPMENT
Electric:
Generation		2,310,811			2,297,463
Transmission		960,618			943,724
Distribution		1,653,098			1,611,129
Other Property, Plant and Equipment
(September 30, 2011 and December 31, 2010 amounts include $231,991 and
$224,857, respectively, related to Sabine)		642,833			632,158
Construction Work in Progress		1,398,465			1,071,603
Total Property, Plant and Equipment		6,965,825			6,556,077
Accumulated Depreciation and Amortization
(September 30, 2011 and December 31, 2010 amounts include $99,690 and
$91,840, respectively, related to Sabine)		2,206,849			2,130,351
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		4,758,976			4,425,726

OTHER NONCURRENT ASSETS
Regulatory Assets		356,589			332,698
Long-term Risk Management Assets		207			438
Deferred Charges and Other Noncurrent Assets		83,651			80,327
TOTAL OTHER NONCURRENT ASSETS		440,447			413,463

TOTAL ASSETS	$	5,486,874		$	5,243,567

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

162

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2011 and December 31, 2010
(Unaudited)

	2011			2010
	(in thousands)
CURRENT LIABILITIES
Advances from Affiliates	$	41,537		$	-
Accounts Payable:
General		178,461			162,271
Affiliated Companies		53,281			64,474
Short-term Debt – Nonaffiliated		-			6,217
Long-term Debt Due Within One Year – Nonaffiliated		20,000			41,135
Risk Management Liabilities		16,696			4,067
Customer Deposits		50,926			48,245
Accrued Taxes		68,023			30,516
Accrued Interest		17,785			39,856
Obligations Under Capital Leases		14,628			13,265
Regulatory Liability for Over-Recovered Fuel Costs		-			16,432
Other Current Liabilities		64,020			67,118
TOTAL CURRENT LIABILITIES		525,357			493,596

NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		1,708,574			1,728,385
Long-term Risk Management Liabilities		159			338
Deferred Income Taxes		657,199			624,333
Regulatory Liabilities and Deferred Investment Tax Credits		426,210			393,673
Asset Retirement Obligations		48,744			56,632
Employee Benefits and Pension Obligations		88,302			96,314
Obligations Under Capital Leases		113,915			115,399
Deferred Credits and Other Noncurrent Liabilities		90,298			62,852
TOTAL NONCURRENT LIABILITIES		3,133,401			3,077,926

TOTAL LIABILITIES		3,658,758			3,571,522

Cumulative Preferred Stock Not Subject to Mandatory Redemption		4,694			4,696

Rate Matters (Note 3)
Commitments and Contingencies (Note 4)

EQUITY
Common Stock – Par Value – $18 Per Share:
Authorized – 7,600,000 Shares
Outstanding – 7,536,640 Shares		135,660			135,660
Paid-in Capital		674,979			674,979
Retained Earnings		1,034,220			868,840
Accumulated Other Comprehensive Income (Loss)		(21,756	)		(12,491	)
TOTAL COMMON SHAREHOLDER’S EQUITY		1,823,103			1,666,988

Noncontrolling Interest		319			361

TOTAL EQUITY		1,823,422			1,667,349

TOTAL LIABILITIES AND EQUITY	$	5,486,874		$	5,243,567

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

163

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2011 and 2010
(in thousands)
(Unaudited)

	2011			2010
OPERATING ACTIVITIES
Net Income	$	168,693		$	139,473
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		99,927			94,939
Deferred Income Taxes		36,979			1,227
Allowance for Equity Funds Used During Construction		(34,861	)		(36,630	)
Mark-to-Market of Risk Management Contracts		(3,148	)		230
Pension Contributions to Qualified Plan Trust		(7,215	)		(26,684	)
Fuel Over/Under-Recovery, Net		(30,259	)		(14,371	)
Change in Other Noncurrent Assets		19,606			(16,101	)
Change in Other Noncurrent Liabilities		39,900			41,231
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		9,718			(23,562	)
Fuel, Materials and Supplies		(10,508	)		27,811
Accounts Payable		2,906			(35,890	)
Accrued Taxes, Net		68,674			49,249
Accrued Interest		(22,240	)		(15,085	)
Other Current Assets		(3,356	)		(1,864	)
Other Current Liabilities		(2,545	)		(15,777	)
Net Cash Flows from Operating Activities		332,271			168,196

INVESTING ACTIVITIES
Construction Expenditures		(395,193	)		(288,043	)
Change in Advances to Affiliates, Net		86,222			(161,873	)
Other Investing Activities		(3,479	)		863
Net Cash Flows Used for Investing Activities		(312,450	)		(449,053	)

FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated		-			399,394
Credit Facility Borrowings		32,532			74,449
Change in Advances from Affiliates, Net		41,537			-
Retirement of Long-term Debt – Nonaffiliated		(41,135	)		(53,500	)
Retirement of Long-term Debt – Affiliated		-			(50,000	)
Retirement of Cumulative Preferred Stock		(2	)		-
Credit Facility Repayments		(38,749	)		(78,170	)
Principal Payments for Capital Lease Obligations		(10,029	)		(8,873	)
Dividends Paid on Common Stock – Nonaffiliated		(3,183	)		(2,966	)
Dividends Paid on Cumulative Preferred Stock		(172	)		(172	)
Other Financing Activities		3,650			916
Net Cash Flows from (Used for) Financing Activities		(15,551	)		281,078

Net Increase in Cash and Cash Equivalents		4,270			221
Cash and Cash Equivalents at Beginning of Period		1,514			1,661
Cash and Cash Equivalents at End of Period	$	5,784		$	1,882

SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	78,239		$	72,270
Net Cash Paid (Received) for Income Taxes		(8,586	)		25,575
Noncash Acquisitions Under Capital Leases		10,296			653
Construction Expenditures Included in Current Liabilities at September 30,		99,600			101,017

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 166.

164

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 166.

	Footnote Reference

Significant Accounting Matters	Note 1
New Accounting Pronouncements	Note 2
Rate Matters	Note 3
Commitments, Guarantees and Contingencies	Note 4
Acquisitions and Impairments	Note 5
Benefit Plans	Note 6
Business Segments	Note 7
Derivatives and Hedging	Note 8
Fair Value Measurements	Note 9
Income Taxes	Note 10
Financing Activities	Note 11
Cost Reduction Initiatives	Note 12

165

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, CSPCo, I&M, OPCo, PSO, SWEPCo
2.	New Accounting Pronouncements	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
3.	Rate Matters	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
4.	Commitments, Guarantees and Contingencies	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
5.	Acquisition and Impairments	APCo, OPCo, SWEPCo
6.	Benefit Plans	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
7.	Business Segments	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
8.	Derivatives and Hedging	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
9.	Fair Value Measurements	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
10.	Income Taxes	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
11.	Financing Activities	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
12.	Cost Reduction Initiatives	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo

166

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 nine months ended September 30, 2011 is not necessarily indicative of results that may be expected for the year ending December 31, 2011. The condensed financial statements are unaudited and should be read in conjunction with the audited 2010 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2010 as filed with the SEC on February 25, 2011.

Variable Interest Entities

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.

SWEPCo is the primary beneficiary of Sabine. I&M is the primary beneficiary of DCC Fuel. APCo, CSPCo, I&M, OPCo, PSO and SWEPCo each hold a significant variable interest in AEPSC. I&M and CSPCo each hold a significant variable interest in AEGCo. SWEPCo holds a significant variable interest in DHLC.

Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the three months ended September 30, 2011 and 2010 were $33 million and $30 million, respectively, and for the nine months ended September 30, 2011 and 2010 were $97 million and $103 million, respectively. See the table below for the classification of Sabine’s assets and liabilities on SWEPCo’s condensed balance sheets.

167

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
September 30, 2011 and December 31, 2010
(in millions)
	Sabine
ASSETS	2011		2010
Current Assets	$	43	$	50
Net Property, Plant and Equipment		143		139
Other Noncurrent Assets		26		34
Total Assets	$	212	$	223

LIABILITIES AND EQUITY
Current Liabilities	$	50	$	33
Noncurrent Liabilities		162		190
Total Liabilities and Equity	$	212	$	223

I&M has nuclear fuel lease agreements with DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III 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. DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC are separate legal entities from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on DCC Fuel LLC and DCC Fuel II LLC leases are made semi-annually and began in April 2010 and October 2010, respectively. Payments on the DCC Fuel III LLC lease are made monthly and began in January 2011. Payments on the DCC Fuel leases for the three months ended September 30, 2011 and 2010 were $6 million and $0, respectively, and for the nine months ended September 30, 2011 and 2010 were $49 million and $22 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 48, 54 and 54 month lease term, respectively. Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the 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
September 30, 2011 and December 31, 2010
(in millions)
	DCC Fuel
ASSETS	2011		2010
Current Assets	$	93	$	92
Net Property, Plant and Equipment		104		173
Other Noncurrent Assets		67		112
Total Assets	$	264	$	377

LIABILITIES AND EQUITY
Current Liabilities	$	75	$	79
Noncurrent Liabilities		189		298
Total Liabilities and Equity	$	264	$	377

168

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 its voting rights equally. Each entity guarantees a 50% share of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the three months ended September 30, 2011 and 2010 were $18 million and $14 million, respectively, and for the nine months ended September 30, 2011 and 2010 were $47 million and $40 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:

	September 30, 2011				December 31, 2010
	As Reported on		Maximum		As Reported on		Maximum
	the Balance Sheet		Exposure		the Balance Sheet		Exposure
	(in millions)
Capital Contribution from SWEPCo	$	8	$	8	$	6	$	6
Retained Earnings		1		1		2		2
SWEPCo's Guarantee of Debt		-		49		-		48
Total Investment in DHLC	$	9	$	58	$	8	$	56

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 September 30,				Nine Months Ended September 30,
Company	2011		2010		2011		2010
	(in thousands)
APCo	$	52,105	$	50,972	$	144,398	$	177,130
CSPCo		31,037		29,288		85,538		103,782
I&M		32,127		30,887		94,961		106,067
OPCo		42,627		40,975		124,995		152,754
PSO		21,924		22,503		62,471		77,682
SWEPCo		35,101		31,917		96,494		110,454

169

The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows:

	September 30, 2011				December 31, 2010
	As Reported on the		Maximum		As Reported on the		Maximum
Company	Balance Sheet		Exposure		Balance Sheet		Exposure
	(in thousands)
APCo	$	21,396	$	21,396	$	23,230	$	23,230
CSPCo		13,283		13,283		12,676		12,676
I&M		13,416		13,416		12,980		12,980
OPCo		17,981		17,981		16,927		16,927
PSO		9,495		9,495		9,384		9,384
SWEPCo		14,554		14,554		14,465		14,465

AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant Unit 1, leases a 50% interest in Rockport Plant Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo leases the Lawrenceburg Generating Station to CSPCo. AEP guarantees all the debt obligations of AEGCo. I&M and CSPCo are considered to have a significant interest in AEGCo due to these transactions. I&M and CSPCo are exposed to losses to the extent they cannot recover the costs of AEGCo through their normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M, CSPCo and KPCo, this financing would be provided by AEP. For additional information regarding AEGCo’s lease, see the “Rockport Lease” section of Note 13 in the 2010 Annual Report.

Total billings from AEGCo were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
Company	2011		2010		2011		2010
	(in thousands)
CSPCo	$	47,712	$	44,459	$	139,729	$	81,160
I&M		64,948		63,679		167,620		168,330

The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows:

	September 30, 2011				December 31, 2010
	As Reported in		Maximum		As Reported in		Maximum
Company	the Balance Sheet		Exposure		the Balance Sheet		Exposure
	(in thousands)
CSPCo	$	12,333	$	12,333	$	18,165	$	18,165
I&M		21,757		21,757		27,899		27,899

2. NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business. The following represents a summary of final pronouncements that impact the financial statements.

Pronouncements Issued During 2011

The following standard was issued during the first nine months of 2011. The following paragraphs discuss its impact on future financial statements.

ASU 2011-05 “Presentation of Comprehensive Income” (ASU 2011-05)

170

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2011. Early adoption is permitted. This standard must be retrospectively applied to all reporting periods presented in financial reports issued after the effective date. This standard will change the presentation of the financial statements but will not affect the calculation of net income or comprehensive income. The FASB is currently considering deferral of reclassification adjustment presentation provisions of ASU 2011-05. Absent a deferral of this accounting guidance in its entirety, management expects to adopt ASU 2011-05 for the 2011 Annual Report.

3. RATE MATTERS

As discussed in the 2010 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 2010 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 2011 and updates the 2010 Annual Report.

Regulatory Assets Not Yet Being Recovered

			APCo				I&M
			September 30,		December 31,		September 30,		December 31,
			2011		2010		2011		2010
Noncurrent Regulatory Assets (excluding fuel)			(in thousands)				(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
	Environmental Rate Adjustment Clause		$	73,335	$	55,724	$	-	$	-
	Deferred Wind Power Costs			39,882		28,584		-		-
	Storm Related Costs			25,225		25,225		-		-
	Mountaineer Carbon Capture and Storage
		Product Validation Facility		19,245		59,866		-		-
	Special Rate Mechanism for Century Aluminum			12,750		12,628		-		-
	Mountaineer Carbon Capture and Storage
		Commercial Scale Facility		3,681		-		2,440		-
	Litigation Settlement			-		-		10,732		-
	Other Regulatory Assets Not Yet Being Recovered			2,417		604		-		-
Total Regulatory Assets Not Yet Being Recovered			$	176,535	$	182,631	$	13,172	$	-

			CSPCo				OPCo
			September 30,		December 31,		September 30,		December 31,
			2011		2010		2011		2010
Noncurrent Regulatory Assets (excluding fuel)			(in thousands)				(in thousands)
Regulatory assets not yet being recovered
	pending future proceedings to determine
	the recovery method and timing:
Regulatory Assets Currently Earning a Return
	Line Extension Carrying Costs		$	39,034	$	33,709	$	24,962	$	21,246
	Customer Choice Deferrals			30,304		29,716		29,670		29,141
	Storm Related Costs			19,853		19,122		11,441		11,021
	Acquisition of Monongahela Power			8,955		7,929		-		-
	Economic Development Rider			6,201		3,057		6,200		3,057
	Other Regulatory Assets Not Yet Being Recovered			293		287		399		391
Regulatory Assets Currently Not Earning a Return
	Acquisition of Monongahela Power			4,052		4,052		-		-
	Other Regulatory Assets Not Yet Being Recovered			51		43		68		58
Total Regulatory Assets Not Yet Being Recovered			$	108,743	$	97,915	$	72,740	$	64,914

171

			PSO				SWEPCo
			September 30,		December 31,		September 30,		December 31,
			2011		2010		2011		2010
Noncurrent Regulatory Assets (excluding fuel)			(in thousands)				(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
	Mountaineer Carbon Capture and Storage
		Commercial Scale Facility	$	1,117	$	-	$	3,456	$	-
	Storm Related Costs			-		17,256		-		1,239
	Other Regulatory Assets Not Yet Being Recovered			-		574		843		613
Total Regulatory Assets Not Yet Being Recovered			$	1,117	$	17,830	$	4,299	$	1,852

CSPCo and OPCo Rate Matters

Ohio Electric Security Plan Filings

2009 – 2011 ESPs

172

January 2012 – May 2016 ESP

2011 Ohio Distribution Base Rate Case

173

unrecognized carrying costs would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013. The actual balance of these distribution regulatory assets as of September 30, 2011 was $102 million and $66 million for CSPCo and OPCo, respectively, excluding $64 million and $48 million, respectively, of unrecognized equity carrying costs.

Proposed CSPCo and OPCo Merger

Sporn Unit 5

2009 Fuel Adjustment Clause Audit

2010 Fuel Adjustment Clause Audit

174

Ormet Interim Arrangement

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

Economic Development Rider

Ohio IGCC Plant

175

SWEPCo Rate Matters

Turk Plant

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

176

A wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009. In 2010, the Sierra Club, the Audubon Society and others filed a complaint in the Federal District Court for the Western District of Arkansas against the U.S. Army Corps of Engineers challenging the process used and the terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts, and sought a preliminary injunction to halt construction and for a temporary restraining order. In July 2010, the Hempstead County Hunting Club (Hunting Club) also filed a complaint with the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of the Interior and the U.S. Fish and Wildlife Service seeking a temporary restraining order and preliminary injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws. The plaintiffs’ federal law claims challenge the process used and terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts. The plaintiffs’ state law claims challenge SWEPCo's ability to construct the Turk Plant without obtaining a certificate from the APSC. In October 2010, the Federal District Court certified issues relating to the state law claims to the Arkansas Supreme Court, including whether those claims are within the primary jurisdiction of the APSC. In May 2011, the Arkansas Supreme Court determined that these claims must first be brought before the APSC and that the federal court does not have jurisdiction to hear the state law claims. In 2010, the motions for preliminary injunction were partially granted by the Federal District Court for the Western District of Arkansas. According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop. Mitigation measures required by the permit are authorized and may be completed. The preliminary injunction affects portions of the water intake and portions of two transmission lines. SWEPCo appealed the issuance of the preliminary injunction to the U.S. Eighth Circuit Court of Appeals, and in July 2011, the Court of Appeals affirmed the preliminary injunction and remanded the case to the district court. Management is unable to predict the timing or the outcome related to this remand proceeding.

In August 2011, a joint stipulation of dismissal was approved by the Federal District Court for the Western District of Arkansas that resolved all pending matters between SWEPCo, the Hunting Club and several other parties. As a result, the Hunting Club’s challenge to the U.S. Army Corps of Engineers permit in the Federal District Court for the Western District of Arkansas was dismissed and the Hunting Club’s appeal of the air permit was withdrawn. Additional judicial and administrative proceedings were terminated. The Sierra Club and the Audubon Society challenges to the wetlands and air permits remain pending.

In October 2011, the Sierra Club, the National Audubon Society and Audubon Arkansas filed a complaint with the APSC requesting that construction of the Turk Plant be halted until SWEPCo or the Arkansas Electric Cooperative Corporation obtain either a CECPN, or SWEPCo obtains a CCN and performs an Environmental Impact Statement on associated gas facilities. Management believes the complaint is without merit and intends to vigorously defend against the complaint.

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

Texas Turk Plant Rate Plan

177

Louisiana Fuel Adjustment Clause Audit

Consultants for the LPSC issued their audit report of SWEPCo’s Louisiana retail FAC recommending that the LPSC discontinue SWEPCo’s tiered sharing mechanism related to the off-system sales margins and reduce the FAC. In April 2011, a settlement agreement was filed with the LPSC which resulted in an immaterial impact for SWEPCo. The settlement agreement deferred the off-system sales issue to SWEPCo’s upcoming formula rate plan (FRP) extension filing, which is expected to be filed in the fourth quarter of 2011. In June 2011, the LPSC approved the settlement agreement.

Louisiana 2008 Formula Rate Filing

In April 2008, SWEPCo filed its first formula rate filing under an approved three-year FRP. SWEPCo requested an increase in its annual Louisiana retail rates of $11 million to be effective in August 2008 in order to earn the approved formula return on common equity of 10.565%. In August 2008, as provided by the FRP, SWEPCo implemented the FRP rates, subject to refund. During 2009, SWEPCo recorded a provision for refund of approximately $1 million after reaching a settlement in principle with intervenors. SWEPCo began refunding customers in August 2010. In March 2011, the LPSC approved the settlement stipulation.

Louisiana 2009 Formula Rate Filing

In April 2009, SWEPCo filed the second FRP which would increase its annual Louisiana retail rates by an additional $4 million effective in August 2009. SWEPCo implemented the FRP rate increase as filed in August 2009, subject to refund. Consultants for the LPSC objected to certain components of SWEPCo’s FRP calculation. A settlement stipulation was reached by the parties and approved by the LPSC in March 2011. The settlement stipulation provided for a $2 million refund, which was recorded in 2010 as a provision in Other Current Liabilities on SWEPCo's condensed balance sheets. The refund to customers, with interest, began in August 2011.

Louisiana 2010 Formula Rate Filing

In April 2010, SWEPCo filed the third FRP which would decrease its annual Louisiana retail rates by $3 million effective in August 2010 pursuant to the approved FRP, subject to refund. In October 2010 and September 2011, consultants for the LPSC filed testimony objecting to certain components of SWEPCo’s FRP calculations. Hearings are scheduled for November 2011. SWEPCo believes the rates as filed are in compliance with the FRP methodology previously approved by the LPSC. If the LPSC disagrees with SWEPCo, it could result in refunds which could reduce future net income and cash flows.

APCo Rate Matters

2011 Virginia Biennial Base Rate Case

178

Rate Adjustment Clauses

2010 West Virginia Base Rate Case

In May 2010, APCo filed a request with the WVPSC to increase APCo’s annual base rates by $140 million based on an 11.75% return on common equity to be effective March 2011. In March 2011, the WVPSC modified and approved a settlement agreement which increased annual base rates by approximately $46 million based upon a 10% return on common equity. The settlement agreement also resulted in a pretax write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility in the first quarter of 2011. See “Mountaineer Carbon Capture and Storage Project” section below. In addition, the WVPSC allowed APCo to defer and amortize $18 million of previously expensed 2009 incremental storm expenses and $14 million of previously expensed costs related to the 2010 cost reduction initiatives, each over a period of seven years.

Mountaineer Carbon Capture and Storage Project

Product Validation Facility (PVF)

In APCo’s May 2010 West Virginia base rate filing, APCo requested rate base treatment of the PVF, including recovery of the related asset retirement obligation regulatory asset amortization and accretion. In March 2011, a WVPSC order denied the request for rate base treatment of the PVF largely due to its experimental operation. The base rate order provided that should APCo construct a commercial scale carbon capture and sequestration (CCS)

179

facility, only the West Virginia portion of the PVF costs, based on load sharing among certain AEP operating companies, may be considered used and useful plant in service and included in future rate base. As a result, in the first quarter of 2011, APCo recorded a pretax write-off of $41 million in Other Operation expense on the condensed statements of operations. See “2010 West Virginia Base Rate Case” section above. As of September 30, 2011, APCo has recorded a noncurrent regulatory asset of $19 million related to the PVF. If APCo cannot recover its remaining PVF investment and related accretion expenses, it would reduce future net income and cash flows.

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

Company	(in millions)
APCo	$	3.7
I&M		2.4
PSO		1.1
SWEPCo		3.5

If the costs of the CCS project cannot be recovered, it would reduce future net income and cash flows.

APCo’s Filings for an IGCC Plant

180

APCo’s 2009 Expanded Net Energy Charge (ENEC) Filing

In September 2009, the WVPSC issued an order approving APCo’s March 2009 ENEC request. The approved order provided for recovery of an under-recovered balance plus a projected increase in ENEC costs over a four-year phase-in period with an overall increase of $320 million and a first-year increase of $112 million, effective October 2009.

In June 2010, the WVPSC approved a settlement agreement for $86 million, including $9 million of construction surcharges related to APCo’s second year ENEC increase. The settlement agreement allows APCo to accrue a weighted average cost of capital carrying charge on the excess under-recovery balance due to the ENEC phase-in as adjusted for the impacts of Accumulated Deferred Income Taxes. The new rates became effective in July 2010.

In June 2011, the WVPSC issued an order approving an $88 million annual increase including $7 million of construction surcharges and $7 million of carrying charges related to APCo’s third year ENEC increase. The order also allows APCo to accrue a fixed annual carrying cost rate of 4%. The new rates became effective in July 2011. Additionally, the order approved APCo’s request to purchase the Dresden Plant, currently under construction, from AEGCo and approved deferral of post in-service Dresden Plant costs, including a return, for future recovery. APCo purchased the Dresden Plant at cost from AEGCo in August 2011 for $302 million. As of September 30, 2011, APCo’s ENEC under-recovery balance was $380 million, excluding $8 million of unrecognized equity carrying costs, which is included in noncurrent regulatory assets. If the WVPSC were to disallow a portion of APCo’s deferred ENEC costs, it could reduce future net income and cash flows and impact financial condition.

WPCo Merger with APCo

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, Virginia SCC and the FERC are required. No merger approval filings have been made.

PSO Rate Matters

PSO 2008 Fuel and Purchased Power

I&M Rate Matters

Michigan 2009 and 2010 Power Supply Cost Recovery (PSCR) Reconciliations (Cook Plant Unit 1 Fire and Shutdown)

181

2011 Michigan Base Rate Case

2011 Indiana Base Rate Case

FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund – Affecting APCo, CSPCo, I&M and OPCo

Company	(in millions)
APCo	$	70.2
CSPCo		38.8
I&M		41.3
OPCo		53.3

The AEP East companies provided reserves for net refunds for SECA settlements totaling $44 million applicable to the $220 million of SECA revenues collected. APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the provision are as follows:

Company	(in millions)
APCo	$	14.1
CSPCo		7.8
I&M		8.3
OPCo		10.7

182

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 September 30, 2011 was $32 million. APCo’s, CSPCo’s, I&M’s and OPCo’s reserve balances as of September 30, 2011 were:

Company	September 30, 2011
	(in millions)
APCo	$	10.0
CSPCo		5.6
I&M		5.9
OPCo		7.6

	Potential		Potential
	Refund		Payments to
Company	Payments		be Received
	(in millions)
APCo	$	6.4	$	3.2
CSPCo		3.5		1.8
I&M		3.7		1.9
OPCo		4.8		2.4

Based on the AEP East companies’ analysis of the May 2010 order and the compliance filing, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the 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, CSPCo, I&M and OPCo

183

PJM/MISO Market Flow Calculation Settlement Adjustments - Affecting APCo, CSPCo, I&M and OPCo

Modification of the Transmission Coordination Agreement (TCA) – Affecting PSO and SWEPCo

PSO, SWEPCo and TNC are parties to the TCA, originally dated January 1, 1997, as amended. The TCA provides for the allocation among the parties of revenues collected for transmission and ancillary services provided under the Open Access Transmission Tariff (OATT).

In April 2011, the FERC accepted proposed revisions to the TCA. Under this amendment, TNC was removed from the TCA. In addition, the amended TCA provides for the allocation of SPP OATT revenues between PSO and SWEPCo based on the SPP formula rate revenue requirements for transmission investment and related expenses of each company. The amended TCA was effective May 1, 2011.

4. 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 2010 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 credit facilities totaling $3.25 billion, under which up to $1.35 billion may be issued as letters of credit. In July 2011, AEP replaced the $1.5 billion facility due in 2012 with a new $1.75 billion facility maturing in July 2016 and extended the $1.5 billion facility due in 2013 to expire in June 2015. As of September 30, 2011, the maximum future payments of the letters of credit were as follows:

Company	Amount		Maturity
	(in thousands)
I&M	$	150	March 2012
SWEPCo		4,448	March 2012

184

In March 2011, the Registrant Subsidiaries and certain other companies in the AEP System terminated a $478 million credit agreement that was scheduled to mature in April 2011 and was used to support $472 million of variable rate Pollution Control Bonds. In March 2011, certain of these variable rate Pollution Control Bonds were remarketed and supported by bilateral letters of credit for $361 million while others were reacquired and are being held in trust as follows:

			Reacquired		Bilateral		Maturity of
			and Held		Letters of		Bilateral Letters
Company	Remarketed		in Trust		Credit Issued		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		115,000		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. In July 2011, SWEPCo’s guarantee was increased from $65 million to $100 million due to expansion of the mining area. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), a consolidated variable interest entity. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million. As of September 30, 2011, SWEPCo has collected approximately $52 million through a rider for final mine closure and reclamation costs, of which $1 million is recorded in Other Current Liabilities, $38 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $13 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, CSPCo, I&M, OPCo, PSO and SWEPCo

Contracts

The Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of September 30, 2011, there were no material liabilities recorded for any indemnifications.

The AEP East companies, PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to power purchase and sale activity conducted pursuant to the SIA.

Master Lease Agreements

The Registrant Subsidiaries lease certain equipment under master lease agreements. In December 2010, management signed a new master lease agreement with GE Capital Commercial Inc. (GE) to replace existing operating and capital leases with GE. These assets were included in existing master lease agreements that were to be terminated in 2011 since GE exercised the termination provision related to these leases in 2008. Certain previously leased assets were not included in the 2010 refinancing, but were purchased in January 2011.

185

For equipment under the GE master lease agreements, the lessor is guaranteed receipt of up to 78% of the unamortized balance of the equipment at the end of the lease term. If the fair value of the leased equipment is below the unamortized balance at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the fair value and the unamortized balance, with the total guarantee not to exceed 78% of the unamortized balance. For equipment under other master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee. At September 30, 2011, 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	$	1,715
CSPCo		1,016
I&M		1,954
OPCo		1,578
PSO		791
SWEPCo		2,771

Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.

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. I&M’s maximum potential loss related to the guarantee is approximately $12 million and SWEPCo’s is approximately $13 million 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, CSPCo, I&M, OPCo, PSO and SWEPCo

186

administration to secure the relief sought in their complaints. In 2010, the U.S. Supreme Court granted the defendants’ petition for review. In June 2011, the U.S. Supreme Court reversed and remanded the case to the Court of Appeals, finding that plaintiffs’ federal common law claims are displaced by the regulatory authority granted to the Federal EPA under the CAA. After the remand, the plaintiffs asked the Second Circuit to return the case to the district court so that they could withdraw their complaints. The cases have been returned to the district court and the parties have been ordered to advise the court in November 2011 how they intend to proceed.

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 CO2 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 and set a status conference for December 1, 2011. Management believes the claims are without merit, and in addition to other defenses, are barred by the doctrine of collateral estoppel and the applicable statute of limitations. Management intends to vigorously defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

Alaskan Villages’ Claims – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies. The complaint alleges that the defendants' emissions of CO2 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 defendants requested that the court defer setting this case for oral argument until after the Supreme Court issues its decision in the CO2 public nuisance case discussed above. The court entered an order deferring argument until after June 2011 and the parties requested supplemental briefing on the impact of the Supreme Court’s decision. The court has set a November 2011 date for oral argument. Management believes the action is without merit and intends to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting 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 $11 million. As the remediation work is completed, I&M’s cost may continue to increase as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ. Management cannot predict the amount of additional cost, if any.

187

Amos Plant – State and Federal Enforcement Proceedings – Affecting APCo and OPCo

In March 2010, APCo and OPCo received a letter from the West Virginia Department of Environmental Protection, Division of Air Quality (DAQ), alleging that at various times in 2007 through 2009 the units at Amos Plant reported periods of excess opacity (indicator of compliance with PM emission limits) that lasted for more than 30 consecutive minutes in a 24-hour period and that certain required notifications were not made. Management met with representatives of DAQ to discuss these occurrences and the steps taken to prevent a recurrence. DAQ indicated that additional enforcement action may be taken, including imposition of a civil penalty of approximately $240 thousand. APCo and OPCo denied that violations of the reporting requirements occurred and maintain that the proper reporting was done. In March 2011, APCo and OPCo resolved these issues through the entry of a consent order that included the payment of a $75 thousand civil penalty and certain improvements in the opacity reports.

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

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

I&M maintains insurance through NEIL. As of September 30, 2011, I&M recorded $61 million on its condensed balance sheet representing amounts under NEIL insurance policies. Through September 30, 2011, I&M received partial payments of $203 million from NEIL for the cost incurred to date to repair the property damage.

188

OPERATIONAL CONTINGENCIES

Fort Wayne Lease – Affecting I&M

Coal Transportation Rate Dispute – Affecting PSO

In 1985, the Burlington Northern Railroad Co. (now BNSF) entered into a coal transportation agreement with PSO. The agreement contained a base rate subject to adjustment, a rate floor, a reopener provision and an arbitration provision. In 1992, PSO reopened the pricing provision. The parties failed to reach an agreement and the matter was arbitrated, with the arbitration panel establishing a lowered rate as of July 1, 1992 (the 1992 Rate) and modifying the rate adjustment formula. The decision did not mention the rate floor. From April 1996 through the contract termination in December 2001, the 1992 Rate exceeded the adjusted rate determined according to the decision. PSO paid the adjusted rate and contended that the panel eliminated the rate floor. BNSF invoiced at the 1992 Rate and contended that the 1992 Rate was the new rate floor. PSO terminated the contract by paying a termination fee, as required by the agreement. BNSF contends that the termination fee should have been calculated on the 1992 Rate, not the adjusted rate, resulting in an underpayment of approximately $9.5 million, including interest.

This matter was submitted to an arbitration board. In April 2006, the arbitration board filed its decision, denying BNSF’s underpayments claim. PSO filed a request for an order confirming the arbitration award and a request for entry of judgment on the award with the U.S. District Court for the Northern District of Oklahoma. On July 14, 2006, the U.S. District Court issued an order confirming the arbitration award. BNSF pursued the matter by filing a Motion to Reconsider, which was granted, but in August 2009, the U.S. District Court upheld the arbitration board’s decision. BNSF further pursued the decision by appealing to the U.S. Court of Appeals, where in December 2010, the Tenth Circuit Court of Appeals affirmed the U.S. District Court’s order confirming the arbitration award. PSO then sought and received approval for reimbursement for attorneys’ fees and expenses related to the proceedings at the district and appellate courts. This matter is resolved.

5. ACQUISITIONS AND IMPAIRMENTS

ACQUISITIONS

2011

Dresden Plant - Affecting APCo

In August 2011, APCo purchased the partially completed Dresden Plant from AEGCo, at cost, for $302 million. The Dresden Plant is located near Dresden, Ohio and is a natural gas, combined cycle power plant. When completed, the Dresden Plant will have a generating capacity of 580 MW.

2010

Valley Electric Membership Corporation – Affecting SWEPCo

189

IMPAIRMENTS

2011

Muskingum River Plant Unit 5 FGD Project (MR5) – Affecting OPCo

Sporn Plant Unit 5 – Affecting OPCo

6. 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 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 nine months ended September 30, 2011 and 2010:

APCo					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended September 30,				Three Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	1,799	$	3,227	$	1,245	$	1,431
Interest Cost		8,073		8,489		4,867		5,075
Expected Return on Plan Assets		(10,458)		(10,952)		(4,496)		(4,407)
Amortization of Transition Obligation		-		-		286		1,311
Amortization of Prior Service Cost (Credit)		230		229		(42)		-
Amortization of Net Actuarial Loss		4,142		2,961		1,465		1,352
Net Periodic Benefit Cost	$	3,786	$	3,954	$	3,325	$	4,762

					Other Postretirement
	Pension Plans				Benefit Plans
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	5,399	$	9,681	$	3,737	$	4,291
Interest Cost		24,219		25,467		14,601		15,225
Expected Return on Plan Assets		(31,374)		(32,854)		(13,488)		(13,220)
Amortization of Transition Obligation		-		-		859		3,933
Amortization of Prior Service Cost (Credit)		688		687		(128)		-
Amortization of Net Actuarial Loss		12,427		8,882		4,379		4,057
Net Periodic Benefit Cost	$	11,359	$	11,863	$	9,960	$	14,286

190

CSPCo					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended September 30,				Three Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	849	$	1,469	$	609	$	690
Interest Cost		4,302		4,789		2,040		2,178
Expected Return on Plan Assets		(5,723)		(6,589)		(1,987)		(1,979)
Amortization of Transition Obligation		-		-		11		608
Amortization of Prior Service Cost (Credit)		141		141		(18)		-
Amortization of Net Actuarial Loss		2,210		1,677		1,018		565
Net Periodic Benefit Cost	$	1,779	$	1,487	$	1,673	$	2,062

					Other Postretirement
	Pension Plans				Benefit Plans
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	2,548	$	4,405	$	1,826	$	2,070
Interest Cost		12,906		14,367		6,119		6,535
Expected Return on Plan Assets		(17,172)		(19,767)		(5,960)		(5,937)
Amortization of Transition Obligation		-		-		33		1,824
Amortization of Prior Service Cost (Credit)		423		423		(55)		-
Amortization of Net Actuarial Loss		6,630		5,031		2,173		1,695
Net Periodic Benefit Cost	$	5,335	$	4,459	$	4,136	$	6,187

I&M					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended September 30,				Three Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	2,362	$	3,821	$	1,531	$	1,688
Interest Cost		6,931		7,271		3,402		3,541
Expected Return on Plan Assets		(9,213)		(8,759)		(3,471)		(3,350)
Amortization of Transition Obligation		-		-		47		704
Amortization of Prior Service Cost (Credit)		186		186		(59)		-
Amortization of Net Actuarial Loss		3,536		2,516		891		881
Net Periodic Benefit Cost	$	3,802	$	5,035	$	2,341	$	3,464

					Other Postretirement
	Pension Plans				Benefit Plans
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	7,085	$	11,463	$	4,590	$	5,063
Interest Cost		20,794		21,814		10,207		10,623
Expected Return on Plan Assets		(27,641)		(26,279)		(10,414)		(10,048)
Amortization of Transition Obligation		-		-		141		2,111
Amortization of Prior Service Cost (Credit)		558		558		(177)		-
Amortization of Net Actuarial Loss		10,608		7,548		2,674		2,644
Net Periodic Benefit Cost	$	11,404	$	15,104	$	7,021	$	10,393

191

OPCo					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended September 30,				Three Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	1,708	$	2,845	$	1,348	$	1,356
Interest Cost		7,785		8,186		4,335		4,446
Expected Return on Plan Assets		(10,641)		(10,680)		(4,142)		(4,043)
Amortization of Transition Obligation		-		-		26		1,052
Amortization of Prior Service Cost (Credit)		227		227		(35)		-
Amortization of Net Actuarial Loss		3,997		2,861		1,247		1,154
Net Periodic Benefit Cost	$	3,076	$	3,439	$	2,779	$	3,965

					Other Postretirement
	Pension Plans				Benefit Plans
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	5,124	$	8,536	$	4,044	$	4,069
Interest Cost		23,357		24,558		13,004		13,339
Expected Return on Plan Assets		(31,925)		(32,040)		(12,425)		(12,132)
Amortization of Transition Obligation		-		-		79		3,158
Amortization of Prior Service Cost (Credit)		681		681		(105)		-
Amortization of Net Actuarial Loss		11,991		8,582		3,741		3,462
Net Periodic Benefit Cost	$	9,228	$	10,317	$	8,338	$	11,896

PSO					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended September 30,				Three Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	1,440	$	1,513	$	655	$	704
Interest Cost		3,321		3,722		1,512		1,590
Expected Return on Plan Assets		(4,366)		(4,934)		(1,566)		(1,528)
Amortization of Transition Obligation		-		-		-		701
Amortization of Prior Service Credit		(238)		(238)		(19)		-
Amortization of Net Actuarial Loss		1,690		1,297		389		394
Net Periodic Benefit Cost	$	1,847	$	1,360	$	971	$	1,861

					Other Postretirement
	Pension Plans				Benefit Plans
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	4,320	$	4,539	$	1,966	$	2,111
Interest Cost		9,964		11,166		4,535		4,770
Expected Return on Plan Assets		(13,098)		(14,804)		(4,698)		(4,583)
Amortization of Transition Obligation		-		-		-		2,104
Amortization of Prior Service Credit		(713)		(713)		(57)		-
Amortization of Net Actuarial Loss		5,068		3,891		1,165		1,180
Net Periodic Benefit Cost	$	5,541	$	4,079	$	2,911	$	5,582

192

SWEPCo					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended September 30,				Three Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	1,644	$	1,761	$	757	$	777
Interest Cost		3,333		3,773		1,742		1,735
Expected Return on Plan Assets		(4,596)		(4,871)		(1,800)		(1,661)
Amortization of Transition Obligation		-		-		-		615
Amortization of Prior Service Cost (Credit)		(199)		(199)		64		-
Amortization of Net Actuarial Loss		1,690		1,310		447		427
Net Periodic Benefit Cost	$	1,872	$	1,774	$	1,210	$	1,893

					Other Postretirement
	Pension Plans				Benefit Plans
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	4,930	$	5,284	$	2,271	$	2,331
Interest Cost		9,999		11,320		5,227		5,205
Expected Return on Plan Assets		(13,786)		(14,616)		(5,400)		(4,984)
Amortization of Transition Obligation		-		-		-		1,845
Amortization of Prior Service Cost (Credit)		(597)		(597)		193		-
Amortization of Net Actuarial Loss		5,070		3,931		1,339		1,283
Net Periodic Benefit Cost	$	5,616	$	5,322	$	3,630	$	5,680

7. 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.

8. 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

193

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.

The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of September 30, 2011 and December 31, 2010:

Notional Volume of Derivative Instruments
September 30, 2011

Primary Risk			Unit of
Exposure			Measure	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Commodity:
	Power		MWHs		208,400		129,013		134,409		153,187		55		69
	Coal		Tons		7,024		3,355		2,445		10,768		6,325		3,720
	Natural Gas		MMBtus		5,075		3,142		3,255		3,730		142		179
	Heating Oil and
		Gasoline	Gallons		1,345		599		668		998		787		724
	Interest Rate		USD	$	31,783	$	19,660	$	20,350	$	23,464	$	246	$	271

Interest Rate and
	Foreign Currency		USD	$	-	$	-	$	200,000	$	-	$	-	$	200,069

Notional Volume of Derivative Instruments
December 31, 2010

Primary Risk			Unit of
Exposure			Measure	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Commodity:
	Power		MWHs		194,217		111,959		117,862		136,657		21		34
	Coal		Tons		11,195		5,550		6,571		23,033		4,936		8,777
	Natural Gas		MMBtus		2,166		1,248		1,302		1,524		15		19
	Heating Oil and
		Gasoline	Gallons		1,054		467		521		776		616		564
	Interest Rate		USD	$	9,541	$	5,471	$	5,732	$	7,185	$	609	$	793

Interest Rate and
	Foreign Currency		USD	$	200,000	$	-	$	-	$	-	$	200,000	$	189

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.

194

Cash Flow Hedging Strategies

AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk.

The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. For disclosure purposes, these contracts are included with other hedging activity as “Commodity.” The Registrant Subsidiaries do not hedge all fuel price risk.

AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt. The anticipated fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure.

At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the 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.

195

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 September 30, 2011 and December 31, 2010 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:

	September 30, 2011				December 31, 2010
	Cash Collateral		Cash Collateral		Cash Collateral		Cash Collateral
	Received		Paid		Received		Paid
	Netted Against		Netted Against		Netted Against		Netted Against
	Risk Management		Risk Management		Risk Management		Risk Management
Company	Assets		Liabilities		Assets		Liabilities
	(in thousands)
APCo	$	1,404	$	8,406	$	1,809	$	16,229
CSPCo		869		5,137		1,042		9,347
I&M		901		5,338		1,087		9,757
OPCo		1,032		6,179		1,272		11,561
PSO		16		211		-		44
SWEPCo		21		195		-		72

196

The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of September 30, 2011 and December 31, 2010:

Fair Value of Derivative Instruments
September 30, 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		$	144,864	$	1,806	$	-	$	(116,380)	$	30,290
Long-term Risk Management Assets			62,747		662		-		(39,272)		24,137
Total Assets			207,611		2,468		-		(155,652)		54,427

Current Risk Management Liabilities			141,417		2,044		-		(124,328)		19,133
Long-term Risk Management Liabilities			47,259		418		-		(40,529)		7,148
Total Liabilities			188,676		2,462		-		(164,857)		26,281

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	18,935	$	6	$	-	$	9,205	$	28,146

Fair Value of Derivative Instruments
December 31, 2010

APCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (b)		Total
		(in thousands)
Current Risk Management Assets		$	267,702	$	1,956	$	11,888	$	(228,304)	$	53,242
Long-term Risk Management Assets			79,560		714		-		(41,854)		38,420
Total Assets			347,262		2,670		11,888		(270,158)		91,662

Current Risk Management Liabilities			262,027		2,363		-		(236,397)		27,993
Long-term Risk Management Liabilities			61,724		701		-		(51,552)		10,873
Total Liabilities			323,751		3,064		-		(287,949)		38,866

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	23,511	$	(394)	$	11,888	$	17,791	$	52,796

197

Fair Value of Derivative Instruments
September 30, 2011

CSPCo
		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		$	87,738	$	1,105	$	-	$	(70,398)	$	18,445
Long-term Risk Management Assets			38,538		410		-		(24,061)		14,887
Total Assets			126,276		1,515		-		(94,459)		33,332

Current Risk Management Liabilities			85,804		1,206		-		(75,264)		11,746
Long-term Risk Management Liabilities			28,963		246		-		(24,827)		4,382
Total Liabilities			114,767		1,452		-		(100,091)		16,128

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	11,509	$	63	$	-	$	5,632	$	17,204

Fair Value of Derivative Instruments
December 31, 2010

CSPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (b)		Total
		(in thousands)
Current Risk Management Assets		$	149,886	$	1,164	$	-	$	(127,276)	$	23,774
Long-term Risk Management Assets			45,413		412		-		(23,736)		22,089
Total Assets			195,299		1,576		-		(151,012)		45,863

Current Risk Management Liabilities			146,540		1,362		-		(131,935)		15,967
Long-term Risk Management Liabilities			35,144		404		-		(29,325)		6,223
Total Liabilities			181,684		1,766		-		(161,260)		22,190

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	13,615	$	(190)	$	-	$	10,248	$	23,673

198

Fair Value of Derivative Instruments
September 30, 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		$	93,307	$	1,147	$	-	$	(71,041)	$	23,413
Long-term Risk Management Assets			44,354		425		-		(24,639)		20,140
Total Assets			137,661		1,572		-		(95,680)		43,553

Current Risk Management Liabilities			86,899		1,263		-		(76,095)		12,067
Long-term Risk Management Liabilities			29,670		257		7,329		(25,435)		11,821
Total Liabilities			116,569		1,520		7,329		(101,530)		23,888

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	21,092	$	52	$	(7,329)	$	5,850	$	19,665

Fair Value of Derivative Instruments
December 31, 2010

I&M
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (b)		Total
		(in thousands)
Current Risk Management Assets		$	162,896	$	1,151	$	-	$	(136,521)	$	27,526
Long-term Risk Management Assets			56,154		429		-		(25,098)		31,485
Total Assets			219,050		1,580		-		(161,619)		59,011

Current Risk Management Liabilities			156,750		1,421		-		(141,386)		16,785
Long-term Risk Management Liabilities			37,039		421		-		(30,930)		6,530
Total Liabilities			193,789		1,842		-		(172,316)		23,315

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	25,261	$	(262)	$	-	$	10,697	$	35,696

199

Fair Value of Derivative Instruments
September 30, 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		$	117,495	$	1,328	$	-	$	(96,064)	$	22,759
Long-term Risk Management Assets			48,066		487		-		(30,462)		18,091
Total Assets			165,561		1,815		-		(126,526)		40,850

Current Risk Management Liabilities			115,002		1,503		-		(101,906)		14,599
Long-term Risk Management Liabilities			36,599		308		-		(31,386)		5,521
Total Liabilities			151,601		1,811		-		(133,292)		20,120

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	13,960	$	4	$	-	$	6,766	$	20,730

Fair Value of Derivative Instruments
December 31, 2010

OPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (b)		Total
		(in thousands)
Current Risk Management Assets		$	262,751	$	1,316	$	-	$	(233,294)	$	30,773
Long-term Risk Management Assets			63,533		503		-		(36,024)		28,012
Total Assets			326,284		1,819		-		(269,318)		58,785

Current Risk Management Liabilities			259,635		1,663		-		(239,132)		22,166
Long-term Risk Management Liabilities			50,757		493		-		(42,847)		8,403
Total Liabilities			310,392		2,156		-		(281,979)		30,569

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	15,892	$	(337)	$	-	$	12,661	$	28,216

200

Fair Value of Derivative Instruments
September 30, 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		$	9,242	$	41	$	-	$	(8,128)	$	1,155
Long-term Risk Management Assets			2,623		-		-		(1,250)		1,373
Total Assets			11,865		41		-		(9,378)		2,528

Current Risk Management Liabilities			8,711		186		-		(8,281)		616
Long-term Risk Management Liabilities			1,457		45		-		(1,292)		210
Total Liabilities			10,168		231		-		(9,573)		826

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	1,697	$	(190)	$	-	$	195	$	1,702

Fair Value of Derivative Instruments
December 31, 2010

PSO
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (b)		Total
		(in thousands)
Current Risk Management Assets		$	19,174	$	134	$	13,558	$	(18,641)	$	14,225
Long-term Risk Management Assets			1,944		-		-		(1,692)		252
Total Assets			21,118		134		13,558		(20,333)		14,477

Current Risk Management Liabilities			19,607		-		-		(18,685)		922
Long-term Risk Management Liabilities			1,889		-		-		(1,692)		197
Total Liabilities			21,496		-		-		(20,377)		1,119

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(378)	$	134	$	13,558	$	44	$	13,358

201

Fair Value of Derivative Instruments
September 30, 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		$	6,745	$	38	$	3	$	(6,230)	$	556
Long-term Risk Management Assets			1,157		-		2		(952)		207
Total Assets			7,902		38		5		(7,182)		763

Current Risk Management Liabilities			6,704		170		16,187		(6,365)		16,696
Long-term Risk Management Liabilities			1,109		41		-		(991)		159
Total Liabilities			7,813		211		16,187		(7,356)		16,855

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	89	$	(173)	$	(16,182)	$	174	$	(16,092)

Fair Value of Derivative Instruments
December 31, 2010

SWEPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (b)		Total
		(in thousands)
Current Risk Management Assets		$	33,284	$	123	$	-	$	(32,198)	$	1,209
Long-term Risk Management Assets			3,346		-		5		(2,913)		438
Total Assets			36,630		123		5		(35,111)		1,647

Current Risk Management Liabilities			36,338		-		-		(32,271)		4,067
Long-term Risk Management Liabilities			3,250		-		-		(2,912)		338
Total Liabilities			39,588		-		-		(35,183)		4,405

Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(2,958)	$	123	$	5	$	72	$	(2,758)

(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.

202

The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and nine months ended September 30, 2011 and 2010:

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

Location of Gain (Loss)		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	960	$	2,247	$	3,094	$	2,405	$	(530)	$	(186)
Sales to AEP Affiliates			103		57		58		69		2		2
Fuel and Other Consumables Used for
	Electric Generation		-		-		-		(2)		-		-
Regulatory Assets (a)			139		(1,330)		71		(1,516)		(264)		(219)
Regulatory Liabilities (a)			(1,058)		-		(2,566)		26		1,930		174
Total Gain (Loss) on Risk Management
	Contracts	$	144	$	974	$	657	$	982	$	1,138	$	(229)

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended September 30, 2010

Location of Gain (Loss)		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	1,938	$	6,436	$	6,374	$	5,378	$	686	$	1,123
Sales to AEP Affiliates			(522)		(704)		(571)		2,605		(204)		(486)
Fuel and Other Consumables Used for
	Electric Generation		-		-		-		-		-		-
Regulatory Assets (a)			-		(2,013)		-		(4,064)		16		-
Regulatory Liabilities (a)			4,538		-		1,956		-		999		893
Total Gain (Loss) on Risk Management
	Contracts	$	5,954	$	3,719	$	7,759	$	3,919	$	1,497	$	1,530

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Nine Months Ended September 30, 2011

Location of Gain (Loss)		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	3,659	$	12,171	$	12,211	$	14,635	$	128	$	340
Sales to AEP Affiliates			136		76		81		95		2		2
Fuel and Other Consumables Used for
	Electric Generation		-		-		-		(2)		-		-
Regulatory Assets (a)			373		(3,426)		186		(3,602)		285		2,975
Regulatory Liabilities (a)			9,827		-		(4,230)		(105)		2,509		58
Total Gain (Loss) on Risk Management
	Contracts	$	13,995	$	8,821	$	8,248	$	11,021	$	2,924	$	3,375

203

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Nine Months Ended September 30, 2010

Location of Gain (Loss)		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	4,419	$	19,513	$	15,762	$	17,609	$	1,716	$	2,524
Sales to AEP Affiliates			(2,098)		(2,153)		(1,913)		5,014		(502)		(1,024)
Fuel and Other Consumables Used for
	Electric Generation		-		-		-		-		-		-
Regulatory Assets (a)			-		(3,557)		-		(5,725)		321		73
Regulatory Liabilities (a)			19,686		-		10,418		-		3,763		1,406
Total Gain (Loss) on Risk Management
	Contracts	$	22,007	$	13,803	$	24,267	$	16,898	$	5,298	$	2,979

(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.”

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 nine months ended September 30, 2011 and 2010, the Registrant Subsidiaries did not employ 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).

204

Realized gains and losses on derivative contracts for the purchase and sale of power, coal, natural gas and heating oil and gasoline designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the 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 nine months ended September 30, 2011 and 2010, APCo, CSPCo, I&M and OPCo designated commodity derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on financial fuel derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the 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 nine months ended September 30, 2011 and 2010, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2011, I&M and SWEPCo designated interest rate derivatives as cash flow hedges. During the nine months ended September 30, 2011, APCo and PSO designated interest rate derivatives as cash flow hedges. During the three and nine months ended September 30, 2010, APCo 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 nine months ended September 30, 2011 and 2010, SWEPCo designated foreign currency derivatives as cash flow hedges.

During the three and nine months ended September 30, 2011 and 2010, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

205

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 nine months ended September 30, 2011 and 2010. 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 September 30, 2011

Commodity Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of June 30, 2011				$	669	$	358	$	378	$	479	$	140	$	132
Changes in Fair Value Recognized in AOCI					(646)		(322)		(332)		(443)		(162)		(148)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		84		208		167		253		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		-		-
		Purchased Electricity for Resale			(70)		(182)		(148)		(220)		-		-
		Other Operation Expense			(32)		(22)		(22)		(28)		(28)		(28)
		Maintenance Expense			(51)		(16)		(21)		(30)		(20)		(21)
		Property, Plant and Equipment			(51)		(20)		(28)		(43)		(32)		(27)
		Regulatory Assets (a)			53		-		5		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-		-
Balance in AOCI as of September 30, 2011				$	(44)	$	4	$	(1)	$	(32)	$	(102)	$	(92)

Interest Rate and
Foreign Currency Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of June 30, 2011				$	486	$	-	$	(8,004)	$	10,133	$	7,598	$	(3,057)
Changes in Fair Value Recognized in AOCI					-		-		(4,764)		-		-		(10,896)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		-		1		-		-
		Other Operation Expense			-		-		-		-		-		-
		Interest Expense			269		-		252		(340)		(190)		207
Balance in AOCI as of September 30, 2011				$	755	$	-	$	(12,516)	$	9,794	$	7,408	$	(13,746)

Total Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of June 30, 2011				$	1,155	$	358	$	(7,626)	$	10,612	$	7,738	$	(2,925)
Changes in Fair Value Recognized in AOCI					(646)		(322)		(5,096)		(443)		(162)		(11,044)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		84		208		167		253		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		-		-
		Purchased Electricity for Resale			(70)		(182)		(148)		(220)		-		-
		Other Operation Expense			(32)		(22)		(22)		(28)		(28)		(28)
		Maintenance Expense			(51)		(16)		(21)		(30)		(20)		(21)
		Depreciation and Amortization
			Expense		-		-		-		1		-		-
		Interest Expense			269		-		252		(340)		(190)		207
		Property, Plant and Equipment			(51)		(20)		(28)		(43)		(32)		(27)
		Regulatory Assets (a)			53		-		5		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-		-
Balance in AOCI as of September 30, 2011				$	711	$	4	$	(12,517)	$	9,762	$	7,306	$	(13,838)

206

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended September 30, 2010

Commodity Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of June 30, 2010				$	(1,437)	$	(807)	$	(813)	$	(941)	$	(84)	$	(33)
Changes in Fair Value Recognized in AOCI					(1,212)		(729)		(776)		(914)		69		60
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		60		159		127		184		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		40		-
		Purchased Electricity for Resale			56		156		138		195		-		-
		Other Operation Expense			(7)		(5)		(5)		(6)		(7)		(7)
		Maintenance Expense			(11)		(3)		(5)		(6)		(4)		(3)
		Property, Plant and Equipment			(11)		(4)		(5)		(9)		(7)		(5)
		Regulatory Assets (a)			436		-		58		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-		-
Balance in AOCI as of September 30, 2010				$	(2,126)	$	(1,233)	$	(1,281)	$	(1,497)	$	7	$	12

Interest Rate and
Foreign Currency Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of June 30, 2010				$	(8,298)	$	-	$	(9,011)	$	11,492	$	(443)	$	(4,812)
Changes in Fair Value Recognized in AOCI					(790)		-		-		1		-		122
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		-		1		-		-
		Other Operation Expense			-		-		-		-		-		(3)
		Interest Expense			394		-		252		(341)		18		207
Balance in AOCI as of September 30, 2010				$	(8,694)	$	-	$	(8,759)	$	11,153	$	(425)	$	(4,486)

Total Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of June 30, 2010				$	(9,735)	$	(807)	$	(9,824)	$	10,551	$	(527)	$	(4,845)
Changes in Fair Value Recognized in AOCI					(2,002)		(729)		(776)		(913)		69		182
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		60		159		127		184		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		40		-
		Purchased Electricity for Resale			56		156		138		195		-		-
		Other Operation Expense			(7)		(5)		(5)		(6)		(7)		(10)
		Maintenance Expense			(11)		(3)		(5)		(6)		(4)		(3)
		Depreciation and Amortization
			Expense		-		-		-		1		-		-
		Interest Expense			394		-		252		(341)		18		207
		Property, Plant and Equipment			(11)		(4)		(5)		(9)		(7)		(5)
		Regulatory Assets (a)			436		-		58		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-		-
Balance in AOCI as of September 30, 2010				$	(10,820)	$	(1,233)	$	(10,040)	$	9,656	$	(418)	$	(4,474)

207

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Nine Months Ended September 30, 2011

Commodity Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2010				$	(273)	$	(134)	$	(178)	$	(230)	$	88	$	82
Changes in Fair Value Recognized in AOCI					(523)		(334)		(279)		(288)		18		20
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		255		678		553		817		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		-		-
		Purchased Electricity for Resale			(24)		(57)		(46)		(70)		-		-
		Other Operation Expense			(76)		(57)		(59)		(76)		(75)		(74)
		Maintenance Expense			(141)		(40)		(53)		(76)		(49)		(53)
		Property, Plant and Equipment			(131)		(52)		(67)		(109)		(84)		(67)
		Regulatory Assets (a)			869		-		128		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-		-
Balance in AOCI as of September 30, 2011				$	(44)	$	4	$	(1)	$	(32)	$	(102)	$	(92)

Interest Rate and
Foreign Currency Contracts				APCo		CSPCo		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)		-		(4,764)		-		(476)		(10,095)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		-		3		-		-
		Other Operation Expense			-		-		-		-		-		-
		Interest Expense			911		-		755		(1,022)		(522)		621
Balance in AOCI as of September 30, 2011				$	755	$	-	$	(12,516)	$	9,794	$	7,408	$	(13,746)

Total Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2010				$	(56)	$	(134)	$	(8,685)	$	10,583	$	8,494	$	(4,190)
Changes in Fair Value Recognized in AOCI					(896)		(334)		(5,043)		(288)		(458)		(10,075)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		255		678		553		817		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		-		-
		Purchased Electricity for Resale			(24)		(57)		(46)		(70)		-		-
		Other Operation Expense			(76)		(57)		(59)		(76)		(75)		(74)
		Maintenance Expense			(141)		(40)		(53)		(76)		(49)		(53)
		Depreciation and Amortization
			Expense		-		-		-		3		-		-
		Interest Expense			911		-		755		(1,022)		(522)		621
		Property, Plant and Equipment			(131)		(52)		(67)		(109)		(84)		(67)
		Regulatory Assets (a)			869		-		128		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-		-
Balance in AOCI as of September 30, 2011				$	711	$	4	$	(12,517)	$	9,762	$	7,306	$	(13,838)

208

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Nine Months Ended September 30, 2010

Commodity Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2009				$	(743)	$	(376)	$	(382)	$	(366)	$	(78)	$	112
Changes in Fair Value Recognized in AOCI					(3,069)		(1,806)		(1,859)		(2,214)		(36)		(36)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		117		303		247		351		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		(13)		190		-
		Purchased Electricity for Resale			267		706		593		828		-		-
		Other Operation Expense			(31)		(24)		(22)		(26)		(26)		(30)
		Maintenance Expense			(47)		(15)		(19)		(21)		(16)		(15)
		Property, Plant and Equipment			(44)		(21)		(22)		(31)		(27)		(19)
		Regulatory Assets (a)			1,424		-		183		-		-		-
		Regulatory Liabilities (a)			-		-		-		(5)		-		-
Balance in AOCI as of September 30, 2010				$	(2,126)	$	(1,233)	$	(1,281)	$	(1,497)	$	7	$	12

Interest Rate and
Foreign Currency Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2009				$	(6,450)	$	-	$	(9,514)	$	12,172	$	(521)	$	(5,047)
Changes in Fair Value Recognized in AOCI					(3,475)		-		-		1		-		(81)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		-		3		-		-
		Other Operation Expense			-		-		-		-		-		21
		Interest Expense			1,231		-		755		(1,023)		96		621
Balance in AOCI as of September 30, 2010				$	(8,694)	$	-	$	(8,759)	$	11,153	$	(425)	$	(4,486)

Total Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2009				$	(7,193)	$	(376)	$	(9,896)	$	11,806	$	(599)	$	(4,935)
Changes in Fair Value Recognized in AOCI					(6,544)		(1,806)		(1,859)		(2,213)		(36)		(117)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		117		303		247		351		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		(13)		190		-
		Purchased Electricity for Resale			267		706		593		828		-		-
		Other Operation Expense			(31)		(24)		(22)		(26)		(26)		(9)
		Maintenance Expense			(47)		(15)		(19)		(21)		(16)		(15)
		Depreciation and Amortization
			Expense		-		-		-		3		-		-
		Interest Expense			1,231		-		755		(1,023)		96		621
		Property, Plant and Equipment			(44)		(21)		(22)		(31)		(27)		(19)
		Regulatory Assets (a)			1,424		-		183		-		-		-
		Regulatory Liabilities (a)			-		-		-		(5)		-		-
Balance in AOCI as of September 30, 2010				$	(10,820)	$	(1,233)	$	(10,040)	$	9,656	$	(418)	$	(4,474)

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

209

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets at September 30, 2011 and December 31, 2010 were:

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
September 30, 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	$	798	$	-	$	792	$	-	$	(44)	$	755
CSPCo		480		-		417		-		4		-
I&M		501		-		449		7,329		(1)		(12,516)
OPCo		587		-		583		-		(32)		9,794
PSO		41		-		231		-		(102)		7,408
SWEPCo		38		5		211		16,187		(92)		(13,746)

	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	$	(215)	$	(1,068)		32
CSPCo		(110)		-		32
I&M		(120)		(647)		32
OPCo		(158)		1,359		32
PSO		(73)		759		15
SWEPCo		(66)		(1,334)		15

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
December 31, 2010

	Hedging Assets (a)				Hedging Liabilities (a)				AOCI Gain (Loss) Net of Tax
			Interest Rate				Interest Rate				Interest Rate
			and Foreign				and Foreign				and Foreign
Company	Commodity		Currency		Commodity		Currency		Commodity		Currency
	(in thousands)
APCo	$	333	$	11,888	$	727	$	-	$	(273)	$	217
CSPCo		229		-		419		-		(134)		-
I&M		175		-		437		-		(178)		(8,507)
OPCo		174		-		511		-		(230)		10,813
PSO		134		13,558		-		-		88		8,406
SWEPCo		123		5		-		-		82		(4,272)

210

	Expected to be Reclassified to
	Net Income During the Next
	Twelve Months
			Interest Rate
			and Foreign
Company	Commodity		Currency
	(in thousands)
APCo	$	(280)	$	(1,173)
CSPCo		(137)		-
I&M		(184)		(955)
OPCo		(236)		1,359
PSO		88		735
SWEPCo		82		(829)

(a)	Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.

The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.

Credit Risk

AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements which may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.

211

Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. Management does not anticipate a downgrade below investment grade. The following tables represent: (a) the Registrant Subsidiaries’ aggregate fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of September 30, 2011 and December 31, 2010:

	September 30, 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	$	9,626	$	11,725	$	11,725
CSPCo		5,959		7,259		7,259
I&M		6,174		7,520		7,520
OPCo		7,076		8,619		8,619
PSO		-		3,629		2,123
SWEPCo		-		4,573		2,676

	December 31, 2010
	Liabilities for		Amount of Collateral the		Amount
	Derivative Contracts		Registrant Subsidiaries		Attributable to
	with Credit		Would Have Been		RTO and ISO
Company	Downgrade Triggers		Required to Post		Activities
	(in thousands)
APCo	$	6,594	$	12,607	$	12,574
CSPCo		3,801		7,267		7,248
I&M		3,965		7,581		7,561
OPCo		4,640		8,871		8,847
PSO		16		1,785		1,385
SWEPCo		19		2,139		1,659

As of September 30, 2011 and December 31, 2010, the Registrant Subsidiaries were not required to post any collateral.

212

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. Management does not anticipate a non-performance event under these provisions. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries’ contractual netting arrangements as of September 30, 2011 and December 31, 2010:

	September 30, 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	$	44,124	$	546	$	15,478
CSPCo		27,315		338		9,581
I&M		35,626		350		17,254
OPCo		32,440		401		11,383
PSO		56		-		21
SWEPCo		16,256		-		16,211

	December 31, 2010
	Liabilities for				Additional
	Contracts with Cross				Settlement
	Default Provisions				Liability if Cross
	Prior to Contractual		Amount of Cash		Default Provision
Company	Netting Arrangements		Collateral Posted		is Triggered
	(in thousands)
APCo	$	76,810	$	6,637	$	23,748
CSPCo		44,277		3,826		13,689
I&M		46,188		3,991		14,280
OPCo		54,066		4,670		16,731
PSO		60		-		28
SWEPCo		75		-		37

9. 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

213

quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are non-binding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Long-dated and illiquid complex or structured transactions and FTRs can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.

AEP utilizes its trustee’s external pricing service 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 investment managers perform their own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts.

Assets in the nuclear trusts and Other Cash Deposits are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Fixed income securities do not trade on an exchange and do not have an official closing price. Pricing vendors calculate bond valuations using financial models and matrices. Fixed income securities are typically classified as Level 2 holdings because their valuation inputs are based on observable market data. Observable inputs used for valuing fixed income securities are benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, bids, offers, reference data and economic events. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.

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

		Type of Fixed Income Security
		United States		State and Local
Type of Input		Government	Corporate Debt	Government

Benchmark Yields		X	X	X
Broker Quotes		X	X	X
Discount Margins		X	X
Treasury Market Update		X
Base Spread		X	X	X
Corporate Actions			X
Ratings Agency Updates			X	X
Prepayment Schedule and
	History			X
Yield Adjustments		X

Fair Value Measurements of Long-term Debt

214

The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of September 30, 2011 and December 31, 2010 are summarized in the following table:

	September 30, 2011				December 31, 2010
Company	Book Value		Fair Value		Book Value		Fair Value
	(in thousands)
APCo	$	3,726,069	$	4,362,079	$	3,561,141	$	3,878,557
CSPCo		1,439,039		1,673,882		1,438,830		1,571,219
I&M		1,985,733		2,245,484		2,004,226		2,169,520
OPCo		2,614,910		2,965,698		2,729,522		2,945,280
PSO		945,735		1,106,839		971,186		1,040,656
SWEPCo		1,728,574		1,996,103		1,769,520		1,931,516

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.

215

The following is a summary of nuclear trust fund investments at September 30, 2011 and December 31, 2010:

		September 30, 2011						December 31, 2010
		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		$	13,906	$	-	$	-	$	20,039	$	-	$	-
Fixed Income Securities:
	United States Government		549,523		59,452		(506)		461,084		22,582		(1,489)
	Corporate Debt		53,714		4,673		(1,567)		59,463		3,716		(1,905)
	State and Local Government		319,906		461		(1,350)		340,786		(975)		(340)
	Subtotal Fixed Income Securities		923,143		64,586		(3,423)		861,333		25,323		(3,734)
Equity Securities - Domestic			575,655		144,264		(84,344)		633,855		183,447		(122,889)
Spent Nuclear Fuel and
	Decommissioning Trusts	$	1,512,704	$	208,850	$	(87,767)	$	1,515,227	$	208,770	$	(126,623)

The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
	(in thousands)
Proceeds from Investment Sales	$	361,001	$	495,221	$	825,689	$	1,087,484
Purchases of Investments		378,607		511,688		870,769		1,128,747
Gross Realized Gains on Investment Sales		17,256		1,168		29,661		7,518
Gross Realized Losses on Investment Sales		11,313		33		20,603		450

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at September 30, 2011 was as follows:

	Fair Value
	of Debt
	Securities
	(in thousands)
Within 1 year	$	78,797
1 year – 5 years		268,611
5 years – 10 years		318,475
After 10 years		257,260
Total	$	923,143

216

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 September 30, 2011 and December 31, 2010. 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
September 30, 2011
APCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	1,617	$	183,140	$	13,153	$	(146,484)	$	51,426
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,426		1		(1,629)		798
De-designated Risk Management Contracts (b)			-		-		-		2,203		2,203
Total Risk Management Assets		$	1,617	$	185,566	$	13,154	$	(145,910)	$	54,427

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	964	$	165,672	$	12,339	$	(153,486)	$	25,489
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,375		46		(1,629)		792
Total Risk Management Liabilities		$	964	$	168,047	$	12,385	$	(155,115)	$	26,281

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2010
APCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	1,686	$	330,605	$	13,791	$	(270,012)	$	76,070
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,591		-		(2,258)		333
	Interest Rate/Foreign Currency Hedges		-		11,888		-		-		11,888
De-designated Risk Management Contracts (b)			-		-		-		3,371		3,371
Total Risk Management Assets		$	1,686	$	345,084	$	13,791	$	(268,899)	$	91,662

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	1,653	$	312,258	$	8,660	$	(284,432)	$	38,139
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,985		-		(2,258)		727
Total Risk Management Liabilities		$	1,653	$	315,243	$	8,660	$	(286,690)	$	38,866

217

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2011
CSPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	1,001	$	111,138	$	8,142	$	(88,793)	$	31,488
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,488		-		(1,008)		480
De-designated Risk Management Contracts (b)			-		-		-		1,364		1,364
Total Risk Management Assets		$	1,001	$	112,626	$	8,142	$	(88,437)	$	33,332

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	597	$	100,537	$	7,638	$	(93,061)	$	15,711
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,397		28		(1,008)		417
Total Risk Management Liabilities		$	597	$	101,934	$	7,666	$	(94,069)	$	16,128

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2010
CSPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	972	$	185,699	$	7,950	$	(150,930)	$	43,691
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,531		-		(1,302)		229
De-designated Risk Management Contracts (b)			-		-		-		1,943		1,943
Total Risk Management Assets		$	972	$	187,230	$	7,950	$	(150,289)	$	45,863

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	953	$	175,078	$	4,975	$	(159,235)	$	21,771
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,721		-		(1,302)		419
Total Risk Management Liabilities		$	953	$	176,799	$	4,975	$	(160,537)	$	22,190

218

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2011
I&M
			Level 1		Level 2		Level 3		Other		Total
Assets:			(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (f)			$	1,037	$	121,993	$	8,436	$	(89,827)	$	41,639
Cash Flow Hedges:
	Commodity Hedges (a)			-		1,545		-		(1,044)		501
De-designated Risk Management Contracts (b)				-		-		-		1,413		1,413
Total Risk Management Assets				1,037		123,538		8,436		(89,458)		43,553

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (d)				-		4,548		-		9,358		13,906
Fixed Income Securities:
	United States Government			-		549,523		-		-		549,523
	Corporate Debt			-		53,714		-		-		53,714
	State and Local Government			-		319,906		-		-		319,906
		Subtotal Fixed Income Securities		-		923,143		-		-		923,143
Equity Securities - Domestic (e)				575,655		-		-		-		575,655
Total Spent Nuclear Fuel and Decommissioning Trusts				575,655		927,691		-		9,358		1,512,704

Total Assets			$	576,692	$	1,051,229	$	8,436	$	(80,100)	$	1,556,257

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)			$	618	$	101,843	$	7,913	$	(94,264)	$	16,110
Cash Flow Hedges:
	Commodity Hedges (a)			-		1,464		29		(1,044)		449
	Interest Rate/Foreign Currency Hedges			-		7,329		-		-		7,329
Total Risk Management Liabilities			$	618	$	110,636	$	7,942	$	(95,308)	$	23,888

219

		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		December 31, 2010
I&M
			Level 1		Level 2		Level 3		Other		Total
Assets:			(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (f)			$	1,014	$	209,031	$	8,295	$	(161,531)	$	56,809
Cash Flow Hedges:
	Commodity Hedges (a)			-		1,533		-		(1,358)		175
De-designated Risk Management Contracts (b)				-		-		-		2,027		2,027
Total Risk Management Assets				1,014		210,564		8,295		(160,862)		59,011

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (d)				-		7,898		-		12,141		20,039
Fixed Income Securities:
	United States Government			-		461,084		-		-		461,084
	Corporate Debt			-		59,463		-		-		59,463
	State and Local Government			-		340,786		-		-		340,786
		Subtotal Fixed Income Securities		-		861,333		-		-		861,333
Equity Securities - Domestic (e)				633,855		-		-		-		633,855
Total Spent Nuclear Fuel and Decommissioning Trusts				633,855		869,231		-		12,141		1,515,227

Total Assets			$	634,869	$	1,079,795	$	8,295	$	(148,721)	$	1,574,238

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)			$	994	$	186,898	$	5,187	$	(170,201)	$	22,878
Cash Flow Hedges:
	Commodity Hedges (a)			-		1,795		-		(1,358)		437
Total Risk Management Liabilities			$	994	$	188,693	$	5,187	$	(171,559)	$	23,315

220

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	September 30, 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)			1,188		147,519		9,668		(119,731)		38,644
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,784		-		(1,197)		587
De-designated Risk Management Contracts (b)			-		-		-		1,619		1,619
Total Risk Management Assets			1,188		149,303		9,668		(119,309)		40,850

Total Assets		$	1,214	$	149,303	$	9,668	$	(119,287)	$	40,898

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	708	$	134,637	$	9,070	$	(124,878)	$	19,537
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,747		33		(1,197)		583
Total Risk Management Liabilities		$	708	$	136,384	$	9,103	$	(126,075)	$	20,120

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2010
OPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Other Cash Deposits (c)		$	26	$	-	$	-	$	-	$	26

Risk Management Assets
Risk Management Commodity Contracts (a) (f)			1,186		314,560		9,709		(269,216)		56,239
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,764		-		(1,590)		174
De-designated Risk Management Contracts (b)			-		-		-		2,372		2,372
Total Risk Management Assets			1,186		316,324		9,709		(268,434)		58,785

Total Assets		$	1,212	$	316,324	$	9,709	$	(268,434)	$	58,811

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	1,163	$	302,299	$	6,101	$	(279,505)	$	30,058
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,101		-		(1,590)		511
Total Risk Management Liabilities		$	1,163	$	304,400	$	6,101	$	(281,095)	$	30,569

221

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	September 30, 2011
PSO
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	37	$	11,776	$	-	$	(9,326)	$	2,487
Cash Flow Hedges:
	Commodity Hedges		-		41		-		-		41
Total Risk Management Assets		$	37	$	11,817	$	-	$	(9,326)	$	2,528

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	11	$	10,105	$	-	$	(9,521)	$	595
Cash Flow Hedges:
	Commodity Hedges		-		231		-		-		231
Total Risk Management Liabilities		$	11	$	10,336	$	-	$	(9,521)	$	826

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2010
PSO
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	-	$	21,119	$	1	$	(20,335)	$	785
Cash Flow Hedges:
	Commodity Hedges		-		134		-		-		134
	Interest Rate/Foreign Currency Hedges		-		13,558		-		-		13,558
Total Risk Management Assets		$	-	$	34,811	$	1	$	(20,335)	$	14,477

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	-	$	21,498	$	-	$	(20,379)	$	1,119

222

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2011
SWEPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	47	$	7,816	$	-	$	(7,143)	$	720
Cash Flow Hedges:
	Commodity Hedges		-		38		-		-		38
	Interest Rate/Foreign Currency Hedges		-		5		-		-		5
Total Risk Management Assets		$	47	$	7,859	$	-	$	(7,143)	$	763

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	14	$	7,760	$	-	$	(7,317)	$	457
Cash Flow Hedges:
	Commodity Hedges		-		211		-		-		211
	Interest Rate/Foreign Currency Hedges		-		16,187		-		-		16,187
Total Risk Management Liabilities		$	14	$	24,158	$	-	$	(7,317)	$	16,855

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2010
SWEPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	-	$	36,632	$	2	$	(35,115)	$	1,519
Cash Flow Hedges:
	Commodity Hedges		-		123		-		-		123
	Interest Rate/Foreign Currency Hedges		-		5		-		-		5
Total Risk Management Assets		$	-	$	36,760	$	2	$	(35,115)	$	1,647

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	-	$	39,592	$	-	$	(35,187)	$	4,405

(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 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, CSPCo, 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 nine months ended September 30, 2011 and 2010.

223

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 September 30, 2011		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of June 30, 2011		$	5,321	$	3,077	$	3,150	$	3,682	$	-	$	-
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		(4,553)		(2,805)		(2,904)		(3,333)		-		-
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		(406)		-		(533)		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		(7)		(6)		(7)		(7)		-		-
Purchases, Issuances and Settlements (c)			358		278		297		321		-		-
Transfers into Level 3 (d) (f)			-		-		-		-		-		-
Transfers out of Level 3 (e) (f)			(259)		(150)		(154)		(180)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		(91)		488		112		615		-		-
Balance as of September 30, 2011		$	769	$	476	$	494	$	565	$	-	$	-

Three Months Ended September 30, 2010		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of June 30, 2010		$	10,874	$	6,153	$	6,209	$	7,069	$	(2)	$	(2)
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		(1,680)		(845)		(850)		(981)		2		2
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		5,941		-		9,258		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		-		-		-		-		-		-
Purchases, Issuances and Settlements (c)			195		118		133		157		2		3
Transfers into Level 3 (d) (f)			380		215		217		247		-		-
Transfers out of Level 3 (e) (f)			(890)		(503)		(508)		(579)		(1)		(2)
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		7,686		(1,532)		4,757		(3,514)		1		1
Balance as of September 30, 2010		$	16,565	$	9,547	$	9,958	$	11,657	$	2	$	2

Nine Months Ended September 30, 2011		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of December 31, 2010		$	5,131	$	2,975	$	3,108	$	3,608	$	1	$	2
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		(2,373)		(1,367)		(1,401)		(1,640)		-		-
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		908		-		1,039		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		(45)		(28)		(29)		(33)		-		-
Purchases, Issuances and Settlements (c)			2,835		1,620		1,656		1,947		-		-
Transfers into Level 3 (d) (f)			1,299		744		764		894		-		-
Transfers out of Level 3 (e) (f)			(3,057)		(1,762)		(1,834)		(2,146)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		(3,021)		(2,614)		(1,770)		(3,104)		(1)		(2)
Balance as of September 30, 2011		$	769	$	476	$	494	$	565	$	-	$	-

224

Nine Months Ended September 30, 2010		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of December 31, 2009		$	9,428	$	4,776	$	4,816	$	5,569	$	2	$	3
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		1,269		713		721		825		1		3
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		10,670		-		14,651		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		-		-		-		-		-		-
Purchases, Issuances and Settlements (c)			(5,463)		(3,059)		(3,100)		(3,565)		(1)		(2)
Transfers into Level 3 (d) (f)			986		530		528		615		-		-
Transfers out of Level 3 (e) (f)			(2,088)		(1,195)		(1,199)		(1,376)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		12,433		(2,888)		8,192		(5,062)		-		(2)
Balance as of September 30, 2010		$	16,565	$	9,547	$	9,958	$	11,657	$	2	$	2

(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.

10. INCOME TAXES

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

The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 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 will 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.

225

Federal Tax Legislation

The Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act (Health Care Acts) were enacted in March 2010. The Health Care Acts amend tax rules so that the portion of employer health care costs that are reimbursed by the Medicare Part D prescription drug subsidy will no longer be deductible by the employer for federal income tax purposes effective for years beginning after December 31, 2012. Because of the loss of the future tax deduction, a reduction in the deferred tax asset related to the nondeductible OPEB liabilities accrued to date was recorded by the Registrant Subsidiaries in March 2010. This reduction did not materially affect the Registrant Subsidiaries' cash flows or financial condition. For the nine months ended September 30, 2010, the Registrant Subsidiaries reflected a decrease in deferred tax assets, which was partially offset by recording net tax regulatory assets in jurisdictions with regulated operations, resulting in a decrease in net income as follows:

	Net Reduction		Tax
	to Deferred		Regulatory		Decrease in
Company	Tax Assets		Assets, Net		Net Income
	(in thousands)
APCo	$	9,397	$	8,831	$	566
CSPCo		4,386		2,970		1,416
I&M		7,212		6,528		684
OPCo		8,385		4,020		4,365
PSO		3,172		3,172		-
SWEPCo		3,412		3,412		-

State Tax Legislation

226

11. FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2011 are shown in the tables below:

		Principal			Interest	Due
Company	Type of Debt	Amount			Rate	Date
Issuances:		(in thousands)			(%)
APCo	Senior Unsecured Notes	$	350,000		4.60	2021
APCo	Pollution Control Bonds		65,350		2.00	2012
APCo	Pollution Control Bonds		75,000	(a)	Variable	2036
APCo	Pollution Control Bonds		54,375	(a)	Variable	2042
APCo	Pollution Control Bonds		50,275	(a)	Variable	2036
APCo	Pollution Control Bonds		50,000	(a)	Variable	2042
I&M	Pollution Control Bonds		52,000	(a)	Variable	2021
I&M	Pollution Control Bonds		25,000	(a)	Variable	2019
OPCo	Pollution Control Bonds		50,000	(a)	Variable	2014
PSO	Senior Unsecured Notes		250,000		4.40	2021
PSO	Notes Payable		1,187		3.00	2026

(a)	These pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year – Nonaffiliated on the condensed balance sheets.

			Principal		Interest	Due
Company		Type of Debt	Amount Paid		Rate	Date
Retirements and			(in thousands)		(%)
	Principal Payments:
APCo		Pollution Control Bonds	$	75,000	Variable	2036
APCo		Pollution Control Bonds		54,375	Variable	2042
APCo		Pollution Control Bonds		50,000	Variable	2042
APCo		Pollution Control Bonds		50,275	Variable	2036
APCo		Senior Unsecured Notes		250,000	5.55	2011
APCo		Land Note		16	13.718	2026
I&M		Pollution Control Bonds		52,000	Variable	2021
I&M		Pollution Control Bonds		25,000	Variable	2019
I&M		Notes Payable		16,490	Variable	2015
I&M		Notes Payable		13,150	5.16	2014
I&M		Notes Payable		15,482	5.44	2013
I&M		Other Long-term Debt		347	6.00	2025
OPCo		Pollution Control Bonds		65,000	Variable	2036
OPCo		Pollution Control Bonds		50,000	Variable	2014
OPCo		Pollution Control Bonds		50,000	Variable	2014
PSO		Senior Unsecured Notes		200,000	6.00	2032
PSO		Senior Unsecured Notes		75,000	4.70	2011
SWEPCo		Pollution Control Bonds		41,135	4.50	2011

In October 2011, I&M retired $29 million of Notes Payable related to DCC Fuel.

In October 2011, APCo remarketed $100 million of 2% Pollution Control Bonds due in 2014.

As of September 30, 2011, trustees held, on behalf of OPCo, $418 million of its reacquired Pollution Control Bonds.

227

Dividend Restrictions

The Registrant Subsidiaries pay dividends to Parent provided funds are legally available. Various charter provisions and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

Federal Power Act

The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. As applicable, the Registrant Subsidiaries understand “capital account” to mean the par value of the common stock multiplied by the number of shares outstanding.

Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generating plants. Because of their respective ownership of such plants, this reserve applies to APCo, I&M and OPCo.

None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.

Charter and Leverage Restrictions

Provisions within the articles or certificates of incorporation of the Registrant Subsidiaries relating to preferred stock or shares restrict the payment of cash dividends on common and preferred stock or shares.

Utility Money Pool – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of its subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions approved in a regulatory order. The amount of outstanding loans (borrowings) to/from the Utility Money Pool as of September 30, 2011 and December 31, 2010 is included in Advances to/from Affiliates on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2011 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		September 30, 2011		Limit
	(in thousands)
APCo	$	217,876	$	393,811	$	117,206	$	117,655	$	81,825	$	600,000
CSPCo		21,771		188,803		14,549		93,340		156,606		350,000
I&M		57,352		134,004		23,793		31,985		134,004		500,000
OPCo		51,169		245,481		17,873		128,890		223,522		600,000
PSO		96,034		255,611		41,971		85,846		105,116		300,000
SWEPCo		86,241		105,184		29,098		38,798		(41,537)		350,000

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:

	Nine Months Ended September 30,
	2011		2010
Maximum Interest Rate	0.56	%	0.55	%
Minimum Interest Rate	0.06	%	0.09	%

228

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2011 and 2010 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
	Nine Months Ended September 30,				Nine Months Ended September 30,
Company	2011		2010		2011		2010

APCo	0.38	%	0.25	%	0.31	%	-	%
CSPCo	0.52	%	0.18	%	0.32	%	0.27	%
I&M	0.39	%	-	%	0.31	%	0.24	%
OPCo	0.41	%	-	%	0.30	%	0.20	%
PSO	0.41	%	0.29	%	0.26	%	0.16	%
SWEPCo	0.34	%	0.19	%	0.33	%	0.27	%

Short-term Debt

The Registrant Subsidiaries’ outstanding short-term debt was as follows:

September 30, 2011

December 31, 2010

Outstanding

Interest

Outstanding

Interest

Company

Type of Debt

Amount

Rate (b)

Amount

Rate (b)

(in thousands)

SWEPCo

Line of Credit – Sabine (a)

6,217

2.15

(a)

Sabine Mining Company is a consolidated variable interest entity.

(b)

Weighted average rate.

Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 4.

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’ income statements. The Registrant Subsidiaries manage and service their customer accounts receivable sold.

229

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of September 30, 2011 and December 31, 2010 was as follows:

	September 30,		December 31,
Company	2011		2010
	(in thousands)
APCo	$	113,630	$	145,515
CSPCo		194,804		175,997
I&M		128,785		123,366
OPCo		181,080		168,701
PSO		169,872		121,679
SWEPCo		178,230		135,092

The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:

	Three Months Ended September 30,				Nine Months Ended September 30,
Company	2011		2010		2011		2010
	(in thousands)
APCo	$	2,500	$	2,949	$	7,314	$	6,725
CSPCo		3,492		3,300		8,418		8,990
I&M		1,623		1,832		4,758		5,276
OPCo		2,093		2,345		5,607		7,494
PSO		2,081		1,537		4,798		4,287
SWEPCo		1,850		1,441		4,254		4,574

The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:

	Three Months Ended September 30,				Nine Months Ended September 30,
Company	2011		2010		2011		2010
	(in thousands)
APCo	$	307,364	$	338,446	$	958,288	$	1,097,276
CSPCo		472,335		521,030		1,253,906		1,368,343
I&M		350,108		348,039		1,016,680		984,631
OPCo		484,574		473,773		1,445,876		1,325,613
PSO		436,339		398,177		1,021,967		924,707
SWEPCo		475,219		430,270		1,165,245		1,087,515

12. COST REDUCTION INITIATIVES

In April 2010, management began initiatives to decrease both labor and non-labor expenses with a goal of achieving significant reductions in operation and maintenance expenses. A total of 2,461 positions was eliminated across the AEP System as a result of process improvements, streamlined organizational designs and other efficiencies. Most of the affected employees terminated employment May 31, 2010. The severance program provided two weeks of base pay for every year of service along with other severance benefits.

The Registrant Subsidiaries recorded a charge to Other Operation expense during the second quarter of 2010 primarily related to severance benefits as the result of headcount reduction initiatives. The total amount incurred in 2010 by Registrant Subsidiary was as follows:

Company	Total Cost Incurred
	(in thousands)
APCo	$	56,925
CSPCo		32,292
I&M		45,036
OPCo		53,108
PSO		24,005
SWEPCo		29,662

230

The Registrant Subsidiaries’ cost reduction activity for the nine months ended September 30, 2011 is described in the following table:

	Balance at								Balance at
Company	December 31, 2010		Incurred		Settled		Adjustments		September 30, 2011
	(in thousands)
APCo	$	3,726	$	-	$	(2,701)	$	(420)	$	605
CSPCo		1,454		-		(1,404)		1		51
I&M		2,198		-		(1,874)		(134)		190
OPCo		2,919		-		(2,500)		(111)		308
PSO		1,526		-		(1,174)		(160)		192
SWEPCo		1,753		-		(1,503)		7		257

The remaining accruals are included primarily in Other Current Liabilities on the condensed balance sheets.

231

COMBINED MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the Registrant Subsidiaries’ management’s discussion and analysis. The information in this section completes the information necessary for management’s discussion and analysis of financial condition and net income and is meant to be read with (a) Management’s Discussion and Analysis, (b) financial statements, (c) footnotes and (d) the schedules of each individual registrant. The Combined Management’s Discussion and Analysis of Registrant Subsidiaries section of the 2010 Annual Report should also be read in conjunction with this report.

EXECUTIVE OVERVIEW

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 SO2, NOx, 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 involved in development of possible future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change. AEP, various industry groups, affected states and other parties have urged the Federal EPA to conduct additional analysis and either postpone the effective date or extend the time frame for compliance with some of these future requirements. 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 future 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 Discussion and Analysis of Registrant Subsidiaries” in the 2010 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 adversely affect future net income, cash flows and possibly financial condition.

232

Update to 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 September 30, 2011, the AEP System had a total generating capacity of nearly 38,000 MWs, of which 23,900 MWs are coal-fired. In the second quarter of 2011, management refined 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, based upon the updates are listed below:

	2012 to 2020
	Estimated Environmental Investment
Company	Low		High
	(in millions)
APCo	$	580	$	765
CSPCo		552		736
I&M		660		885
OPCo		1,549		2,065
PSO		700		940
SWEPCo		900		1,200

For APCo, the projected environmental investments above include both the conversion of 470 MWs of coal generation to 422 MWs of natural gas generation and the building of 580 MWs of natural gas-fired generation. For OPCo, the investments above include the conversion of 600 MWs of coal generation to 510 MWs of 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 management’s continuing evaluation, the Registrant Subsidiaries may retire the following plants or units of plants before 2015:

		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		1,050
CSPCo	Conesville Plant, Unit 3		165
CSPCo	Picway Plant		100
I&M	Tanners Creek Plant, Units 1-3		495
OPCo	Kammer Plant		630
OPCo	Muskingum River Plant, Units 1-4		840
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. CSPCo owns 12.5% (54 MWs) of one unit at that station.

233

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. SWEPCo and APCo are completing construction of the Turk and Dresden Plants, respectively. Recovery of the remaining investments in facilities that may be closed will be subject to regulatory approval.

Cross-State Air Pollution Rule (formerly the Clean Air Act Transport Rule)

In July 2010, the Federal EPA issued a proposed rule to replace the Clean Air Interstate Rule (CAIR) that would impose new and more stringent requirements to control SO2 and NOx emissions from fossil fuel-fired electric generating units in 31 states and the District of Columbia. Each state covered by the proposed Clean Air Act Transport Rule (Transport Rule) was assigned an allowance budget for SO2 and/or NOx. Limited interstate trading was allowed on a sub-regional basis and intrastate trading was allowed among generating units. PSO’s and SWEPCo’s western states (Arkansas, Oklahoma and Texas) would be subject to only the seasonal NOx program, with new limits that were proposed to take effect in 2012. The remainder of the states in which the AEP System operates would be subject to seasonal and annual NOx programs and an annual SO2 emissions reduction program that takes effect in two phases. The first phase was to be effective in 2012 and more stringent SO2 emission reductions were proposed to take effect in 2014 in certain states. The SO2 and NOx programs rely on newly-created allowances rather than relying on the CAIR NOx allowances or the Title IV Acid Rain Program allowances used in CAIR.

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. The compliance plan described above was based on the requirements of the proposed Transport Rule. The more stringent requirements included in the final CSAP Rule could cause further unit curtailments, increase capital requirements, constrain operations, decrease reliability and unfavorably impact financial condition if the increased costs are not recovered in rates or market prices.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

234

Management submitted comments on the proposed rule and urged the Federal EPA to carefully consider all of the options available so that costly and inefficient control requirements are not imposed regardless of unit size, age or other operating characteristics. The AEP System has older coal units for which it may be economically inefficient to install scrubbers or other environmental controls. Several of these units are included in the current list of potential plant closures discussed above.

Regional Haze – Oklahoma Affecting PSO

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. Comments are due in November 2011.

Currently, approximately 40% of the coal ash and other residual products from the AEP System’s generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses. Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes. In addition, surface impoundments and landfills to manage these materials are currently used at the generating facilities. The Registrant Subsidiaries will incur significant costs to upgrade or close and replace their existing facilities. Management estimates that the potential compliance costs associated with the proposed solid waste management alternative could be as high as $3.9 billion including AFUDC for units across the AEP System. Regulation of these materials as hazardous wastes would significantly increase these costs.

Clean Water Act Regulations

235

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. Comments on the proposal were submitted in July and August 2011.

Global Warming

While comprehensive economy-wide regulation of CO2 emissions might be achieved through new legislation, Congress has yet to enact such legislation. The Federal EPA continues to take action to regulate CO2 emissions under the existing requirements of the CAA. The Federal EPA issued a final endangerment finding for CO2 emissions from new motor vehicles in December 2009 and final rules for new motor vehicles in May 2010. The Federal EPA determined that CO2 emissions from stationary sources will be subject to regulation under the CAA and finalized its proposed scheme to streamline and phase-in regulation of stationary source CO2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs through the issuance of final federal rules, state implementation plan calls and federal implementation plans. The Federal EPA is reconsidering whether to include CO2 emissions in a number of stationary source standards, including standards that apply to new and modified electric utility units and announced a settlement agreement to issue proposed new source performance standards for utility boilers that would be applicable for both new and existing utility boilers. It is not possible at this time to estimate the costs of compliance with these new standards, but they may be material.

The Registrant Subsidiaries’ fossil fuel-fired generating units are very large sources of CO2 emissions. If substantial CO2 emission reductions are required, there will be significant increases in capital expenditures and operating costs which would impact the ultimate retirement of older, less-efficient, coal-fired units. To the extent the Registrant Subsidiaries install additional controls on their generating plants to limit CO2 emissions and receive regulatory approvals to increase rates, cost recovery could have a positive effect on future earnings. Prudently incurred capital investments made by the Registrant Subsidiaries in rate-regulated jurisdictions to comply with legal requirements and benefit customers are generally included in rate base for recovery and earn a return on investment. Management would expect these principles to apply to investments made to address new environmental requirements. However, requests for rate increases reflecting these costs can affect the Registrant Subsidiaries adversely because the regulators could limit the amount or timing of increased costs that would be recoverable through higher rates. In addition, to the extent the Registrant Subsidiaries’ costs are relatively higher than their competitors’ costs, such as operators of nuclear generation, it could reduce off-system sales or cause the Registrant Subsidiaries to lose customers in jurisdictions that permit customers to choose their supplier of generation service.

Several states have adopted programs that directly regulate CO2 emissions from power plants, but none of these programs are currently in effect in states where the Registrant Subsidiaries have generating facilities. Certain states, including Ohio, Michigan, Texas and Virginia, passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements. Management is taking steps to comply with these requirements.

Certain groups have filed lawsuits alleging that emissions of CO2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others. The Registrant Subsidiaries have been named in pending lawsuits, which management is vigorously defending. It is not possible to predict the outcome of these lawsuits or their impact on operations or financial condition. See “Carbon Dioxide Public Nuisance Claims” and “Alaskan Villages’ Claims” sections of Note 4.

Future federal and state legislation or regulations that mandate limits on the emission of CO2 would result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force the Registrant Subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets. As a result, mandatory limits could have a material adverse impact on net income, cash flows and financial condition.

236

For detailed information on global warming and the actions the AEP System is taking to address potential impacts, see Part I of the 2010 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters – Global Warming and “Combined Management Discussion and Analysis of Registrant Subsidiaries.”

FINANCIAL CONDITION

LIQUIDITY AND CAPITAL RESOURCES

Sources of Funding

Short-term funding for the Registrant Subsidiaries comes from AEP’s commercial paper program and revolving credit facilities through the Utility Money Pool. AEP and its Registrant Subsidiaries operate a money pool to minimize the AEP System’s external short-term funding requirements and sell accounts receivable to provide liquidity. Under credit facilities, $1.35 billion may be issued as letters of credit. The Registrant Subsidiaries generally use short-term funding sources (the Utility Money Pool or receivables sales) to provide for interim financing of capital expenditures that exceed internally generated funds and periodically reduce their outstanding short-term debt through issuances of long-term debt, sale-leasebacks, leasing arrangements and additional capital contributions from Parent.

In March 2011, the Registrant Subsidiaries and certain other companies in the AEP System terminated a $478 million credit facility, used for letters of credit to support variable rate debt, that was scheduled to mature in April 2011. In March 2011, APCo, I&M and OPCo issued bilateral letters of credit to support the remarketing of $230 million, $77 million and $50 million, respectively, of their variable rate debt. OPCo reacquired $115 million which is held by a trustee on its behalf.

Dividend Restrictions

Under the Federal Power Act, the Registrant Subsidiaries are restricted from paying dividends out of stated capital. Various charter provisions and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

Sales of Receivables

In July 2011, AEP Credit renewed its receivables securitization agreement. The agreement provides a commitment of $750 million from bank conduits to purchase receivables with an increase to $800 million for the months of July, August and September to accommodate seasonal demand. A commitment of $375 million with the seasonal increase to $425 million for the months of July, August and September expires in June 2012 and the remaining commitment of $375 million expires in June 2014. AEP Credit purchases accounts receivable from the Registrant Subsidiaries.

Redemption of Preferred Stock

In October 2011, management announced that APCo, I&M, OPCo, PSO and SWEPCo will redeem all of their preferred stock in December 2011.

MINE SAFETY INFORMATION

237

		DHLC		CCPC		Conner Run
Number of Citations for Violations of Mandatory Health or
	Safety Standards under 104 *		2		-		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	$	-	$	Not assessed
Number of Mining-related Fatalities			-		-		-

* References to sections under the Mine Act

ACCOUNTING PRONOUNCEMENTS

Pronouncements Effective in the Future

The FASB issued ASU 2011-05 “Presentation of Comprehensive Income” eliminating the option to present the components of other comprehensive income as a part of the statement of shareholders’ equity. The standard requires other comprehensive income be presented as part of a single continuous statement of comprehensive income or in a statement of other comprehensive income immediately following the statement of net income. This standard will change the presentation of the financial statements but will not affect the calculation of net income or comprehensive income. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2011. Early adoption is permitted. The FASB is currently considering deferral of reclassification adjustment presentation provisions of ASU 2011-05. Absent a deferral of this accounting guidance in its entirety, management expects to adopt ASU 2011-05 for the 2011 Annual Report.

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 statements, contingencies, financial instruments, emission allowances, leases, insurance, hedge accounting, consolidation policy and discontinued operations. Management also expects to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP. The ultimate pronouncements resulting from these and future projects could have an impact on future net income and financial position.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

The Registrant Subsidiaries’ risk management assets and liabilities are managed by AEPSC as agent. The related risk management policies and procedures are instituted and administered by AEPSC. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Market Risk” section. Also, see Note 8 – Derivatives and Hedging and Note 9 – Fair Value Measurements for additional information related to the Registrant Subsidiaries’ risk management contracts.

238

The following tables summarize the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2010:

	MTM Risk Management Contract Net Assets (Liabilities)
	Nine Months Ended September 30, 2011
	(in thousands)


APCo

Total MTM Risk Management Contract Net Assets at December 31, 2010		$	26,882
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period			(7,848)
Fair Value of New Contracts at Inception When Entered During the Period (a)			-
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
	During the Period		(42)
Changes in Fair Value Due to Market Fluctuations During the Period (b)			(820)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)			2,966
Total MTM Risk Management Contract Net Assets at September 30, 2011			21,138
Commodity Cash Flow Hedge Contracts			6
Collateral Deposits			7,002
Total MTM Derivative Contract Net Assets at September 30, 2011		$	28,146

OPCo

Total MTM Risk Management Contract Net Assets at December 31, 2010		$	18,264
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period			(4,961)
Fair Value of New Contracts at Inception When Entered During the Period (a)			1,880
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
	During the Period		(65)
Changes in Fair Value Due to Market Fluctuations During the Period (b)			3,565
Changes in Fair Value Allocated to Regulated Jurisdictions (c)			(3,104)
Total MTM Risk Management Contract Net Assets at September 30, 2011			15,579
Commodity Cash Flow Hedge Contracts			4
Collateral Deposits			5,147
Total MTM Derivative Contract Net Assets at September 30, 2011		$	20,730

PSO

Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2010		$	(378)
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period			366
Fair Value of New Contracts at Inception When Entered During the Period (a)			-
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
	During the Period		(27)
Changes in Fair Value Due to Market Fluctuations During the Period (b)			(7)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)			1,743
Total MTM Risk Management Contract Net Assets at September 30, 2011			1,697
Commodity Cash Flow Hedge Contracts			(190)
Collateral Deposits			195
Total MTM Derivative Contract Net Assets at September 30, 2011		$	1,702

239


SWEPCo

Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2010		$	(2,958)
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period			2,755
Fair Value of New Contracts at Inception When Entered During the Period (a)			-
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
	During the Period		(20)
Changes in Fair Value Due to Market Fluctuations During the Period (b)			(6)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)			318
Total MTM Risk Management Contract Net Assets at September 30, 2011			89
Commodity Cash Flow Hedge Contracts			(16,355)
Collateral Deposits			174
Total MTM Derivative Contract Net Liabilities at September 30, 2011		$	(16,092)

(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.

The following tables present the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate or (require) cash:

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets (Liabilities)
September 30, 2011

		Remainder
APCo		2011		2012-2014		2015		Total
		(in thousands)
Level 1 (a)		$	6	$	647	$	-	$	653
Level 2 (b)			83		16,083		1,302		17,468
Level 3 (c)			129		258		427		814
Total			218		16,988		1,729		18,935
De-designated Risk Management
	Contracts (d)		670		1,533		-		2,203
Total MTM Risk Management
	Contract Net Assets	$	888	$	18,521	$	1,729	$	21,138

		Remainder
OPCo		2011		2012-2014		2015		Total
		(in thousands)
Level 1 (a)		$	4	$	476	$	-	$	480
Level 2 (b)			(96)		12,021		957		12,882
Level 3 (c)			95		189		314		598
Total			3		12,686		1,271		13,960
De-designated Risk Management
	Contracts (d)		492		1,127		-		1,619
Total MTM Risk Management
	Contract Net Assets	$	495	$	13,813	$	1,271	$	15,579

240

		Remainder
PSO		2011		2012-2014		Total
		(in thousands)
Level 1 (a)		$	-	$	26	$	26
Level 2 (b)			208		1,463		1,671
Level 3 (c)			-		-		-
Total MTM Risk Management
	Contract Net Assets (Liabilities)	$	208	$	1,489	$	1,697

		Remainder
SWEPCo		2011		2012-2014		Total
		(in thousands)
Level 1 (a)		$	-	$	33	$	33
Level 2 (b)			(30)		86		56
Level 3 (c)			-		-		-
Total MTM Risk Management
	Contract Net Assets (Liabilities)	$	(30)	$	119	$	89

(a)	Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.
(b)	Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1 and OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market.
(c)	Level 3 inputs are unobservable inputs for the asset or liability. Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.
(d)	De-designated Risk Management Contracts are contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for “Derivatives and Hedging.” At the time of the normal election, the MTM value was frozen and no longer fair valued. This will be amortized into Revenues over the remaining life of the contracts.

Credit Risk

Counterparty credit quality and exposure of the Registrant Subsidiaries is generally consistent with that of AEP.

Value at Risk (VaR) Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates VaR to measure commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at September 30, 2011, a near term typical change in commodity prices is not expected to have a material effect on net income, cash flows or financial condition.

241

The following table shows the end, high, average and low market risk as measured by VaR for the trading portfolio for the periods indicated:

	Nine Months Ended									Twelve Months Ended
	September 30, 2011									December 31, 2010
Company		End		High		Average		Low		End		High		Average		Low
	(in thousands)									(in thousands)
APCo		$	156	$	553	$	143	$	66	$	124	$	659	$	193	$	71
OPCo			121		423		121		53		100		545		161		54
PSO			5		39		14		2		3		70		15		1
SWEPCo			4		46		17		2		6		93		21		2

Management back-tests its VaR results against performance due to actual price movements. Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.

As the VaR calculations capture recent price movements, management also performs regular stress testing of the portfolio to understand the exposure to extreme price movements. Management employs a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last four years in order to ascertain which historical price movements translated into the largest potential MTM loss. Management then researches the underlying positions, price movements and market events that created the most significant exposure and reports the findings to the Risk Executive Committee or the Commercial Operations Risk Committee as appropriate.

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. As calculated on the Registrant Subsidiaries’ outstanding debt as of September 30, 2011 and December 31, 2010, the estimated EaR on the Registrant Subsidiaries’ debt portfolio was as follows:

	September 30,		December 31,
Company	2011		2010
	(in thousands)
APCo	$	4,780	$	1,165
CSPCo		276		178
I&M		1,044		274
OPCo		6,212		926
PSO		471		658
SWEPCo		2,176		1,027

242

CONTROLS AND PROCEDURES

During the third quarter of 2011, management, including the principal executive officer and principal financial officer of each of AEP, APCo, CSPCo, 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 September 30, 2011, 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 third quarter of 2011 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 4 incorporated herein by reference.

Item 1A. Risk Factors

The Annual Report on Form 10-K for the year ended December 31, 2010 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 2010 Annual Report on Form 10-K.

RISKS RELATING TO REGULATED OPERATIONS

All of the investment in and expenses related to the Turk Plant may not be fully recovered. – Affecting AEP and SWEPCo

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

·	The validity of the air permit issued by the Arkansas Department of Environmental Quality in connection with the operation of the Turk Plant.

A preliminary injunction issued by the Federal District Court for the Western District of Arkansas, and upheld by the Eighth Circuit Federal Court of Appeals, enjoining SWEPCo from completing work authorized by the permit issued by the U.S. Army Corps of Engineers, the U.S. Department of Interior and the U.S. Fish and Wildlife Service. The preliminary injunction also raises other alleged violations of various federal and state laws.

·	Whether SWEPCo is required to obtain APSC approval to construct the Turk Plant without pursuing authority to seek recovery of the originally approved 88 MW portion of Turk Plant costs in Arkansas retail rates.

·	The validity of PUCT approval of the Texas jurisdictional cost recovery and uncertainty regarding the caps on recovery included in the approval.

243

If SWEPCo is unable to complete the Turk Plant construction and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would reduce future net income and cash flows and impact financial condition.

Rate recovery approved in Ohio may have to be returned and/or may not provide full recovery of costs. – Affecting AEP, CSPCo and OPCo

The PUCO issued an order in March 2009 that modified and approved the Electric Security Plans (ESPs) of CSPCo and OPCo. The ESPs established rates in effect through 2011. The ESP order generally authorized rate increases during the ESP period, subject to caps that limit the rate increases, and also provides a fuel adjustment clause for the three-year period of the ESPs. The recovery includes 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 July 2011, CSPCo and OPCo filed their 2010 SEET filings with the PUCO. 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 fully recovered for other reasons, it could reduce future net income and cash flows and impact financial condition.

Request for rate and other recovery in Ohio for distribution service may not be approved in its entirety. – Affecting AEP, CSPCo and OPCo

In February 2011, CSPCo and OPCo filed with the PUCO for annual increases in distribution rates to be effective January 2012. In addition to the annual increase, CSPCo and OPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets, including unrecognized equity carrying costs. These assets would be recovered in a distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013. If the PUCO denies all or part of the requested rate and other recovery, it could reduce future net income and cash flows and impact financial condition.

Request for rate recovery in Ohio for generation service may not be approved in its entirety. – Affecting AEP, CSPCo and OPCo

In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer pricing for generation effective with the first billing cycle of January 2012 through the last billing cycle of May 2014. In September 2011, a stipulation agreement was filed with the PUCO. If the PUCO denies all or part of the stipulation agreement, it could reduce future net income and cash flows.

Request for rate and other recovery in Virginia for generation and distribution service may not be approved in its entirety. – Affecting AEP and APCo

In March 2011, APCo filed a generation and distribution base rate request with the Virginia SCC to increase annual base rates to be effective no later than February 2012. APCo proposed to mitigate a portion of the requested base rate increase by maintaining current depreciation rates until the next biennial filing. In addition, APCo filed for approval of rate adjustment clauses for various costs including environmental, renewable energy and generation costs relating to the partially completed Dresden Plant. If the Virginia SCC denies all or part of the requested rate and other recovery, it could reduce future net income and cash flows.

Request for rate recovery in Michigan may not be approved in its entirety. – Affecting AEP and I&M

In July 2011, I&M filed a request with the MPSC for annual increases in Michigan base rates. If the MPSC denies all or part of the requested rate recovery, it could reduce future net income and cash flows.

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.

244

RISKS RELATING TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER

Courts adjudicating nuisance and other similar claims against us may order us to limit or reduce our CO2 emissions. – Affecting each registrant

In 2004, eight states and the City of New York filed an action in Federal District Court for the Southern District of New York against AEP, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority. The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants. The actions allege that CO2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming and sought injunctive relief in the form of specific emission reduction commitments from the defendants. The Second Circuit Court of Appeals reinstated this lawsuit on appeal after the lower court had dismissed it. The U.S. Supreme Court reversed the Court of Appeals, finding that any federal common law nuisance claim has been displaced by the provisions of the Clean Air Act that authorize the Federal EPA to regulate CO2 emissions. The Supreme Court remanded the case for consideration of plaintiffs' state law nuisance claims.

If the court, on remand, orders the defendants, including us, to limit or reduce CO2 emissions, it or similar remedies could require us to purchase power from third parties to fulfill our commitments to supply power to our customers. This could have a material impact on our costs. While management believes such costs should be recoverable from customers as costs of doing business, without such recovery those costs could reduce our future net income and cash flows and harm our financial condition.

Other pending cases seek damages based on allegations of federal and state common law nuisance. If these or other future actions are resolved against us, substantial modifications of our existing coal-fired power plants could be required. In addition, we could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay damages or penalties and/or halt operations. Moreover, our results of operations and financial position could be reduced due to the timing of recovery of these investments and the expense of ongoing litigation.

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

Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety. Approximately 90% of the electricity generated by the AEP System is produced by the combustion of fossil fuels. Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generating plants are expected to be subject to increased regulations, controls and mitigation expenses. Compliance with these legal requirements requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees and permits at all of our facilities and could cause us to retire generating capacity prior to the end of its estimated useful life. These expenditures have been significant in the past and we expect that they will continue to be significant in order to comply with the current and proposed regulations. Costs of compliance with environmental regulations could adversely affect our net income and financial position, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increase. If we retire generating plants prior to the end of their estimated useful life, there can be no assurance that we will recover the remaining costs associated with such plants. While we expect to recover our expenditures for pollution control technologies, replacement generation and associated operating costs from customers through regulated rates (in regulated jurisdictions) or market prices, without such recovery those costs could reduce our future net income and cash flows and possibly harm our financial condition.

245

RISKS RELATING TO MARKET ECONOMICS OR FINANCIAL VOLATILITY AND OTHER RISKS

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

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

·	Operator error and breakdown or failure of equipment or processes.

·	Operating limitations that may be imposed by environmental or other regulatory requirements.

·	Labor disputes.

·	Compliance with mandatory reliability standards, including mandatory cyber security standards.

·	Information technology failure or cyber intrusion that impairs our information technology infrastructure or disrupts normal business operations.

·	Information technology failure or cyber intrusion that affects our ability to access customer information or causes us to lose confidential or proprietary data that materially and adversely affects our reputation or exposes us to legal claims.

·	Fuel supply interruptions caused by transportation constraints, adverse weather, non-performance by our suppliers and other factors.

·	Catastrophic events such as fires, earthquakes, explosions, hurricanes, terrorism, floods or other similar occurrences.

A decrease or elimination of revenues from our electric generation, transmission and distribution facilities or an increase in the cost of operating the facilities would adversely affect our results of operations.

RISKS RELATED TO STATE RESTRUCTURING

There is uncertainty as to our recovery of capacity auction true-up and related amounts resulting from industry restructuring in Texas. – Affecting AEP

Restructuring legislation in Texas required utilities with stranded costs to use market-based methods to value certain generating assets for determining stranded costs. We elected to use the sale of assets method to determine the market value of TCC’s generation assets for stranded cost purposes. In general terms, the amount of stranded costs under this market valuation methodology is the amount by which the book value of generating assets, including regulatory assets and liabilities that were not securitized, exceeds the market value of the generation assets, as measured by the net proceeds from the sale of the assets. In May 2005, TCC filed its stranded cost quantification application with the PUCT seeking recovery of stranded generation costs and other recoverable true-up items. A final order was issued in April 2006. We appealed the PUCT’s final order seeking additional recovery consistent with the Texas Restructuring Legislation and related rules, other parties appealed the PUCT’s final order as unwarranted or too large. In July 2011, the Supreme Court of Texas granted review and reversed the PUCT’s order denying recovery of capacity auction true-up amounts. As a result, we recorded a regulatory asset related to the capacity auction true-up as of September 30, 2011 in the amount of $682 million. If we are not ultimately permitted to fully recover our deferrals, it would reduce future net income and cash flows and impact financial condition.

We are unable to fully predict the effects of legal separation in Ohio and becoming subject to market forces. – Affecting AEP, CSPCo and OPCo

In September 2011, CSPCo, OPCo, the PUCO staff and multiple other parties filed a stipulation agreement with the PUCO which, among other things, authorized the merger of CSPCo into OPCo by the end of 2011. In addition, the stipulation agreement proposed a corporate separation plan of CSPCo’s and OPCo’s generation assets to complete the transition to a fully competitive generation market by June 2015. The proposed corporate separation plan will require approval by the PUCO and the FERC under provisions of the Federal Power Act. If the stipulation agreement is approved as is, our results of operations related to Ohio generation would be determined by our ability to sell power at a profit at rates determined by the prevailing market. We can give no assurance that the PUCO or the FERC would not impose material adverse terms as a condition to approving our legal separation. Additionally,

246

certain of our generation units may no longer be cost effective and may be retired prior to the end of their anticipated useful life, which could result in material impairments. If the PUCO denies all or part of the stipulation agreement, it could reduce future net income and cash flows.

We are unable to predict the consequences of terminating the Interconnection Agreement and breaking up the Power Pool. – Affecting AEP, APCo, CSPCo, I&M and OPCo

The proposed corporate separation plans of CSPCo’s and OPCo’s generation assets will require us to either terminate or substantially alter the Interconnection Agreement. The Interconnection Agreement establishes the Power Pool which 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 Power Pool will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bi-lateral 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 Power Pool 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. In addition, the termination or alteration of the Interconnection Agreement will require the approval of the FERC and may require the approval of other state utility commissions. We can give no assurance that the FERC or other state utility commissions would not impose material adverse terms as a condition to approving our alteration of the Interconnection Agreement.

Customers have recently begun to select alternative electric generation service providers, as allowed by Ohio legislation. – Affecting AEP, CSPCo and OPCo

Under current Ohio legislation, electric generation is sold in a competitive market in Ohio and native load customers in Ohio have the ability to switch to alternative suppliers for their electric generation service. Competitive power suppliers are targeting retail customers by offering alternative generation service. A growing number of commercial retail customers (primarily CSPCo’s) have switched to alternative generation providers while additional Ohio customers have provided notice of their intent to switch. Although, to date, OPCo’s losses have not been significant, OPCo could experience additional customer switching in the future. These evolving market conditions will continue to impact our results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information about purchases by AEP or its publicly-traded subsidiaries during the quarter ended September 30, 2011 of equity securities that are registered by AEP or its publicly-traded subsidiaries pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASES OF EQUITY SECURITIES

Period	Total Number of Shares Purchased			Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
07/01/11 – 07/31/11		22	(a)	$	84.00		-	$	-
08/01/11 – 08/31/11		4	(b)		80.00		-		-
09/01/11 – 09/30/11		-			-		-		-

(a)	OPCo purchased 10 shares of its 4.50% cumulative preferred stock and SWEPCo purchased 5 shares of its 4.65% and 7 shares of its 5.00% cumulative preferred stock in privately-negotiated transactions outside of an announced program.
(b)	I&M purchased 4 shares of its 4.125% cumulative preferred stock in a privately-negotiated transaction outside of an announced program.

247

Item 5. Other Information

NONE

Item 6. Exhibits

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.

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

248

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

COLUMBUS SOUTHERN 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: October 28, 2011

249

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Avg

Columbus Southern Power Inactive 10-Q2011 Q3 Quarterly report

Content analysis