Edgar Filing: AMERICAN ELECTRIC POWER CO INC

Unassociated Document

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, 2010

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For The Transition Period from ____ to ____

Commission	Registrant, State of Incorporation,	I.R.S. Employer
File Number	Address of Principal Executive Offices, and Telephone Number	Identification No.

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

All Registrants	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			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 29, 2010

American Electric Power Company, Inc.			480,276,270
			($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 TO QUARTERLY REPORTS ON FORM 10-Q

September 30, 2010

			Page
Glossary of Terms			i

Forward-Looking Information			iv

Part I. FINANCIAL INFORMATION

		Items 1, 2 and 3 - Financial Statements, Management’s Financial Discussion and Analysis and Quantitative and Qualitative Disclosures About Risk Management Activities:
American Electric Power Company, Inc. and Subsidiary Companies:
	Management’s Financial Discussion and Analysis of Results of Operations		1
	Quantitative and Qualitative Disclosures About Risk Management Activities		20
	Condensed Consolidated Financial Statements		24
	Index to Condensed Notes to Condensed Consolidated Financial Statements		29

Appalachian Power Company and Subsidiaries:
	Management’s Financial Discussion and Analysis		85
	Quantitative and Qualitative Disclosures About Risk Management Activities		90
	Condensed Consolidated Financial Statements		91
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		96

Columbus Southern Power Company and Subsidiaries:
	Management’s Narrative Financial Discussion and Analysis		98
	Quantitative and Qualitative Disclosures About Risk Management Activities		102
	Condensed Consolidated Financial Statements		103
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		108

Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Financial Discussion and Analysis		110
	Quantitative and Qualitative Disclosures About Risk Management Activities		114
	Condensed Consolidated Financial Statements		115
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		120

Ohio Power Company Consolidated:
	Management’s Financial Discussion and Analysis		122
	Quantitative and Qualitative Disclosures About Risk Management Activities		128
	Condensed Consolidated Financial Statements		129
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		134

Public Service Company of Oklahoma:
	Management’s Financial Discussion and Analysis		136
	Quantitative and Qualitative Disclosures About Risk Management Activities		140
	Condensed Financial Statements		141
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		146

Southwestern Electric Power Company Consolidated:
	Management’s Financial Discussion and Analysis		148
	Quantitative and Qualitative Disclosures About Risk Management Activities		154
	Condensed Consolidated Financial Statements		155
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		160

Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries				161

Combined Management’s Discussion and Analysis of Registrant Subsidiaries				230

Controls and Procedures				239

Part II. OTHER INFORMATION

	Item 1.	Legal Proceedings		240
	Item 1A.	Risk Factors		240
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		244
	Item 5.	Other Information		244
	Item 6.	Exhibits:		244
			Exhibit 12
			Exhibit 31(a)
			Exhibit 31(b)
			Exhibit 32(a)
			Exhibit 32(b)

SIGNATURE				245

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.
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 Pool shares the generation, cost of generation and resultant wholesale off-system sales of the member companies.
AEP System or the System		American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP West companies		PSO, SWEPCo, TCC and TNC.
AEPEP		AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, asset management and commercial and industrial sales in the deregulated Texas market.
AEPSC		American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC		Allowance for Funds Used During Construction.
AOCI		Accumulated Other Comprehensive Income.
APCo		Appalachian Power Company, an AEP electric utility subsidiary.
APSC		Arkansas Public Service Commission.
ASU		Accounting Standard Update.
CAA		Clean Air Act.
CLECO		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.
CWIP		Construction Work in Progress.
DCC Fuel		DCC Fuel LLC and DCC Fuel II LLC, consolidated variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DETM		Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
DHLC		Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
E&R		Environmental compliance and transmission and distribution system reliability.
EIS		Energy Insurance Services, Inc., a nonaffiliated captive insurance company.
ERCOT		Electric Reliability Council of Texas.
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.

Term		Meaning

FTR		Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP		Accounting Principles Generally Accepted in the United States of America.
I&M		Indiana Michigan Power Company, an AEP electric utility subsidiary.
IGCC		Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
Interconnection Agreement		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.
KPSC		Kentucky Public Service Commission.
kV		Kilovolt.
KWH		Kilowatthour.
LPSC		Louisiana Public Service Commission.
MISO		Midwest Independent Transmission System Operator.
MLR		Member load ratio, the method used to allocate AEP Power Pool transactions to its members.
MMBtu		Million British Thermal Units.
MPSC		Michigan Public Service Commission.
MTM		Mark-to-Market.
MW		Megawatt.
MWH		Megawatthour.
NEIL		Nuclear Electric Insurance Limited.
NOx		Nitrogen oxide.
Nonutility Money Pool		AEP’s Nonutility Money Pool.
NSR		New Source Review.
OCC		Corporation Commission of the State of Oklahoma.
OPCo		Ohio Power Company, an AEP electric utility subsidiary.
OPEB		Other Postretirement Benefit Plans.
OTC		Over the counter.
OVEC		Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PJM		Pennsylvania – New Jersey – Maryland regional transmission organization.
PM		Particulate Matter.
PSO		Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO		Public Utilities Commission of Ohio.
PUCT		Public Utility Commission of Texas.
Registrant Subsidiaries		AEP subsidiaries which are SEC registrants; APCo, CSPCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts		Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant		A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana, owned by AEGCo and I&M.
RTO		Regional Transmission Organization.
Sabine		Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity.

Term		Meaning

SIA		System Integration Agreement.
SNF		Spent Nuclear Fuel.
SO2		Sulfur Dioxide.
SPP		Southwest Power Pool.
Stall Unit		J. Lamar Stall Unit at Arsenal Hill Plant.
SWEPCo		Southwestern Electric Power Company, an AEP electric utility subsidiary.
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.
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. Although AEP and each of its Registrant Subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

·	The economic climate and growth in, or contraction within, our service territory and changes in market demand and demographic patterns.
·	Inflationary or deflationary interest rate trends.
·	Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.
·	The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
·	Electric load, customer growth and the impact of retail competition, particularly in Ohio.
·	Weather conditions, including storms, and our ability to recover significant storm restoration costs through applicable rate mechanisms.
·	Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·	Availability of necessary generating capacity and the performance of our generating plants.
·	Our ability to resolve I&M’s Donald C. Cook Nuclear Plant Unit 1 restoration and outage-related issues through warranty, insurance and the regulatory process.
·	Our ability to recover regulatory assets and stranded costs in connection with deregulation.
·	Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·	Our ability to build or acquire generating capacity, including the Turk Plant, and transmission line facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are cancelled) through applicable rate cases or competitive rates.
·	New legislation, litigation and government regulation, including oversight of energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation and cost recovery of our plants.
·	Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions (including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance).
·	Resolution of litigation (including our dispute with Bank of America).
·	Our ability to constrain operation and maintenance costs.
·	Our ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities.
·	Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
·	Actions of rating agencies, including changes in the ratings of debt.
·	Volatility and changes in markets for electricity, natural gas, coal, nuclear fuel and other energy-related commodities.
·	Changes in utility regulation, including the implementation of ESPs and related regulation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP.
·	Accounting pronouncements periodically issued by accounting standard-setting bodies.
·	The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans and nuclear decommissioning trust and the impact on future funding requirements.
·	Prices and demand for power that we generate and sell at wholesale.
·	Changes in technology, particularly with respect to new, developing or alternative sources of generation.
·	Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.
·	Our ability to recover through rates any remaining unrecovered investment in generating units that may be retired before the end of their previously projected useful lives.

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

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Economic Conditions

Retail margins increased during the first nine months of 2010 due to successful rate proceedings in various jurisdictions and higher residential and commercial demand for electricity as a result of favorable weather throughout our service territories. In comparison to the recessionary lows of 2009, industrial sales increased 6% in the third quarter and 5% during the first nine months of 2010.

Regulatory Activity

Our significant 2010 rate proceedings include:

Kentucky – In June 2010, a settlement was approved by the KPSC to increase annual base rates by $64 million based on a 10.5% return on common equity. New rates became effective with the first billing cycle of July 2010.

Michigan – In October 2010, a settlement was approved by the MPSC to increase annual base rates by $36 million based on a 10.35% return on common equity as well as the approval of certain surcharges. New rates will become effective with the first billing cycle of December 2010.

Oklahoma – In July 2010, PSO filed for an $82 million increase in annual base rates, including $30 million that is currently being recovered through a rider. The requested increase is based on an 11.5% return on common equity. Various parties’ net annual rate recommendations ranged from a rate reduction of $18 million to an increase of less than $1 million. A hearing is scheduled for December 2010.

Texas – In April 2010, a settlement was approved by the PUCT to increase SWEPCo’s base rates by approximately $15 million annually, effective May 2010, including a return on equity of 10.33%. The settlement agreement also allows SWEPCo a $10 million one-year surcharge rider to recover additional vegetation management costs that SWEPCo must spend within two years.

Virginia – In July 2010, the Virginia SCC authorized an annual increase in revenues of $62 million based on a 10.53% return on equity. The order disallowed recovery of $54 million of costs related to the Mountaineer Carbon Capture and Storage Project and allowed the deferral of approximately $25 million of incremental storm expenses incurred in 2009. As a result, APCo recorded a pretax loss of $29 million in the second quarter of 2010.

West Virginia – In May 2010, APCo and WPCo filed a request with the WVPSC to increase annual base rates by $156 million to be effective March 2011. The request is based on an 11.75% return on common equity and includes a request for recovery of and a return on the West Virginia jurisdictional share of the Mountaineer Carbon Capture and Storage Project. A decision from the WVPSC is expected in March 2011.

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW coal unit in Arkansas, which is expected to be in service in 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility. SWEPCo’s share of construction costs is currently estimated to cost $1.3 billion, excluding AFUDC, plus an additional $132 million for transmission, excluding AFUDC. The APSC, LPSC and PUCT approved SWEPCo’s original application to build the Turk Plant. Various proceedings are pending that challenge the Turk Plant’s construction and its approved air and wetlands permits. In July 2010, the Arkansas Court of Appeals issued a decision remanding all transmission line Certificate of Environmental Compatibility and Public Need (CECPN) appeals to the APSC. As a result, a stay was not ordered and construction continues on the affected transmission lines.

In June 2010, the Arkansas Supreme Court denied motions for rehearing filed by the APSC and SWEPCo related to the reversal of the APSC’s earlier grant of a CECPN for SWEPCo’s 88 MW Arkansas portion of the Turk Plant. As a result, in June 2010, SWEPCo filed notice with the APSC of its intent to proceed with construction of the Turk Plant but that SWEPCo no longer intends to pursue a CECPN to seek recovery of its Arkansas portion of Turk Plant costs in Arkansas retail rates.

In July 2010, the Hempstead County Hunting Club 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 Interior and the U.S. Fish and Wildlife Service seeking an injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws. The Sierra Club, the Audubon Society and others filed a similar complaint in the same court. In October 2010, the motions for preliminary injunction were partially granted. According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop. Mitigation measures required by the permit are authorized and may be completed. The preliminary injunction affects portions of the water intake and associated piping and portions of the transmission lines. In October 2010, the Federal District Court certified issues relating to the state law claims to the Arkansas Supreme Court, including whether those claims are within the primary jurisdiction of the APSC. The Arkansas Supreme Court has yet to consider the request. SWEPCo filed a notice of appeal with the Federal Court of Appeals for the Eighth Circuit and is seeking a stay of the preliminary injunction pending appeal.

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

Ohio Customer Choice

In our Ohio service territory, various certified retail electric service (CRES) providers are targeting retail customers by offering alternative generation service. As of September 30, 2010, approximately 2,000 Ohio retail customers have switched to alternative CRES providers while approximately 1,200 additional Ohio customers have provided notice of their intent to switch. As a result, in comparison to 2009, we lost approximately $5 million of generation related gross margin through September 30, 2010 and currently forecast incremental lost margins of approximately $10 million and $53 million for the fourth quarter of 2010 and for all of 2011, respectively. We anticipate recovery of a portion of this lost margin through off-system sales. In addition, we have created our own CRES provider to target retail customers in Ohio, both within and outside of our retail footprint.

Ohio Electric Security Plan Filings

During 2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s ESPs which established rates through 2011. The order also limits 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. The order provides a FAC for the three-year period of the ESP. Several notices of appeal are outstanding at the Supreme Court of Ohio relating to significant issues in the determination of the approved ESP rates. CSPCo and OPCo filed their 2009 significantly excessive earnings test with the PUCO. Based upon the methodology proposed by CSPCo and OPCo, neither CSPCo’s nor OPCo’s 2009 return on equity was significantly excessive. In October 2010, intervenors filed testimony with the PUCO recommending CSPCo return up to $156 million of its ESP revenues to customers. If the PUCO determines that CSPCo’s and/or OPCo’s 2009 return on equity was significantly excessive, CSPCo and/or OPCo may be required to return a portion of their ESP revenues to customers. See “Ohio Electric Security Plan Filings” section of Note 3.

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. The merger is also subject to regulatory approval by the FERC. CSPCo and OPCo anticipate completion of the merger during 2011. See “Proposed CSPCo and OPCo Merger” section of Note 3.

Cook Plant Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator. Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $395 million. Management believes that I&M should recover a significant portion of repair and replacement costs through the turbine vendor’s warranty, insurance and the regulatory process. I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power. The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors. As a result, the replacement of the repaired turbine rotors and other equipment is scheduled for the Unit 1 planned outage in the fall of 2011. If the ultimate costs of the incident are not covered by warranty, insurance or through the related regulatory process or if any future regulatory proceedings are adverse, it could reduce future net income and cash flows and impact financial condition. See “Indiana Fuel Clause Filing” and “Michigan 2009 Power Supply Cost Recovery Reconciliation” sections of Note 3 and “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

Texas Restructuring Appeals

Pursuant to PUCT restructuring orders, TCC securitized net recoverable stranded generation costs of $2.5 billion and is recovering the principal and interest on the securitization bonds through the end of 2020. TCC also refunded other net true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider under PUCT restructuring orders. TCC and intervenors appealed the PUCT’s true-up related orders. After rulings from the Texas District Court and the Texas Court of Appeals, TCC, the PUCT and intervenors filed petitions for review with the Texas Supreme Court. Review is discretionary and the Texas Supreme Court has not yet determined if it will grant review. See “Texas Restructuring Appeals” section of Note 3.

Mountaineer Carbon Capture and Storage Project

APCo and ALSTOM Power, Inc. (Alstom), 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 APCo’s July 2009 Virginia base rate filing and APCo’s May 2010 West Virginia base rate filing, APCo requested recovery of and a return on its Virginia and West Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion. In July 2010, the Virginia SCC issued a base rate order that denied recovery of the Virginia share of the Mountaineer Carbon Capture and Storage Project costs, which resulted in a pretax write-off of approximately $54 million in the second quarter of 2010. Through September 30, 2010, APCo has recorded a noncurrent regulatory asset of $59 million related to the Mountaineer Carbon Capture and Storage Project. If APCo cannot recover its remaining investments in and expenses related to the Mountaineer Carbon Capture and Storage project, it would reduce future net income and cash flows and impact financial condition. See “Mountaineer Carbon Capture and Storage Project” section of Note 3.

Capital Expenditures

In October 2010, we announced our capital expenditure budgets of $2.6 billion and $2.9 billion for 2011 and 2012, respectively.

LITIGATION

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be. We assess the probability of loss for each contingency and accrue a liability for cases that have a probable likelihood of loss if the loss can be estimated. For details on our regulatory proceedings and pending litigation see Note 4 – Rate Matters, Note 6 – Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2009 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.

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 and new proposals governing the beneficial use and disposal of coal combustion products.

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. See a complete discussion of these matters in the “Environmental Matters” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2009 Annual Report.

Clean Air Act Transport Rule (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 Transport Rule is assigned an allowance budget for SO2 and/or NOx. Limited interstate trading is allowed on a sub-regional basis and intrastate trading is allowed among generating units. Certain of our western states (Texas, Arkansas and Oklahoma) would be subject to only the seasonal NOx program, with new limits that are proposed to take effect in 2012. The remainder of the states in which we operate would be subject to seasonal and annual NOx programs and an annual SO2 emissions reduction program that takes effect in two phases. The first phase becomes effective in 2012 and requires approximately 1 million tons per year more SO2 emission reductions across the region than would have been required under CAIR. The second phase takes effect in 2014 and reduces emissions by an additional 800,000 tons per year. 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 the CAIR rule. The time frames for and the extent of the additional emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and our electric utility customers, as these requirements could accelerate unit retirements, increase capital requirements, constrain operations, decrease reliability and unfavorably impact financial condition if the increased costs are suspended during the early development stages not recovered in rates or market prices. Comments on the proposed rule were due on October 1, 2010. Our comments pointed out the inaccuracies of some of the assumptions used by the Federal EPA, the flawed nature of its modeling analysis and unreasonable time frame for implementing the rule. We believe that the Federal EPA made erroneous assumptions about the existence and/or capabilities of current control equipment at certain of our units, used timeframes for installation of new controls that are inconsistent with our recent experience and made questionable assumptions regarding the ability to switch fuel supplies at existing units. A notice of additional information was issued and comments on that package were accepted until October 15, 2010. The proposal indicates that the requirements are expected to be finalized in June 2011 and become effective January 1, 2012.

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 and remanded to the Federal EPA by the D.C. Circuit Court of Appeals in 2008. The Federal EPA issued an information collection request to owners and operators of existing power plants in 2010 to collect information to support the development of a maximum achievable control technology (MACT) standard for mercury and other hazardous air pollutant emissions under the CAA. Under the terms of a consent decree, the Federal EPA is required to issue final MACT standards for coal and oil-fired power plants by November 2011. The Federal EPA has substantial discretion in determining how to structure the MACT standards. We will urge the Federal EPA to carefully consider all of the options available so that costly and inefficient control requirements are not imposed regardless of unit size, age or other operating characteristics. However, we have approximately 5,000 MW of older coal units, including 2,000 MW of older coal-fired capacity already subject to control requirements under the NSR consent decree, for which it may be economically inefficient to install scrubbers or other environmental controls. The timing and ultimate disposition of those units will be affected by: a) the MACT standards and other environmental regulations, b) the economics of maintaining the units, c) demand for electricity, d) availability and cost of replacement power and e) regulatory decisions about cost recovery of the remaining investment in those units.

Coal Combustion Residual Rule

In June 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at our coal-fired electric generating units. The rule contains two alternative proposals, one that would impose federal hazardous waste disposal and management standards on these materials and one that would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management. Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and initiate closure within five years of the issuance of a final rule.

Currently, approximately 40% of the coal ash and other residual products from our generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses. Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes. In addition, we currently use surface impoundments and landfills to manage these materials at our generating facilities and will incur significant costs to upgrade or close and replace these existing facilities. We estimate that the potential compliance costs associated with the proposed solid waste management alternative could be as high as a total of $3.9 billion for units across the AEP System. Regulation of these materials as hazardous wastes would significantly increase these costs. We will seek recovery of expenditures for pollution control technologies and associated costs from customers through our regulated rates (in regulated jurisdictions). We should be able to recover these expenditures through market prices in deregulated jurisdictions. If not, these costs could adversely affect future net income, cash flows and possibly financial condition.

Global Warming

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 beginning in January 2011 at the earliest 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. These rules have been challenged in the courts. 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.

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 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 Ohio, Michigan, Texas and Virginia, passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements. We are taking steps to comply with these requirements.

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 2009 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters – Global Warming” and “Management’s Financial Discussion and Analysis of Results of Operations.”

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.

The table below presents our consolidated Income (Loss) Before Extraordinary Loss by segment for the three and nine months ended September 30, 2010 and 2009.

	Three Months Ended September 30,							Nine Months Ended September 30,
	2010			2009				2010				2009
	(in millions)
Utility Operations		$	541		$	448			$	1,017			$	1,121
AEP River Operations			14			10				16				22
Generation and Marketing			-			5				17				33
All Other (a)			2			(17	)			(10	)			(45	)
Income Before Extraordinary Loss		$	557		$	446			$	1,040			$	1,131

(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 completely expire in 2011.
	·	Revenue sharing related to the Plaquemine Cogeneration Facility.

AEP CONSOLIDATED

Third Quarter of 2010 Compared to Third Quarter of 2009

Income Before Extraordinary Loss in 2010 increased $111 million compared to 2009 primarily due to successful rate proceedings in our various jurisdictions and favorable weather throughout our service territory.

Average basic shares outstanding increased to 480 million in 2010 from 477 million in 2009.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Income Before Extraordinary Loss in 2010 decreased $91 million compared to 2009 primarily due to $182 million of charges incurred (net of tax) related to the cost reduction initiatives partially offset by successful rate proceedings in our various jurisdictions and favorable weather conditions throughout our service territory.

Average basic shares outstanding increased to 479 million in 2010 from 452 million in 2009 primarily due to the April 2009 issuance of 69 million shares of AEP common stock. Actual shares outstanding were 480 million as of September 30, 2010.

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 utility operating 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,
	2010		2009		2010		2009
	(in millions)
Revenues	$	3,907	$	3,389	$	10,544	$	9,712
Fuel and Purchased Power		1,427		1,145		3,784		3,337
Gross Margin		2,480		2,244		6,760		6,375
Depreciation and Amortization		413		412		1,205		1,173
Other Operating Expenses		1,057		988		3,411		2,975
Operating Income		1,010		844		2,144		2,227
Other Income, Net		39		42		124		97
Interest Expense		238		232		710		679
Income Tax Expense		270		206		541		524
Income Before Extraordinary Loss	$	541	$	448	$	1,017	$	1,121

Summary of KWH Energy Sales for Utility Operations
For the Three and Nine Months Ended September 30, 2010 and 2009

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
Energy/Delivery Summary	2010	2009	2010	2009
	(in millions of KWH)
Retail:
Residential	17,817	15,968	48,250	44,730
Commercial	14,032	13,569	38,508	37,773
Industrial	14,460	13,642	42,503	40,563
Miscellaneous	832	798	2,328	2,291
Total Retail (a)	47,141	43,977	131,589	125,357

Wholesale	10,689	8,285	25,846	22,229

Total KWHs	57,830	52,262	157,435	147,586

(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
For the Three and Nine Months Ended September 30, 2010 and 2009

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2010		2009		2010		2009
		(in degree days)
Eastern Region
Actual - Heating (a)			1		6		1,976		1,982
Normal - Heating (b)			7		7		1,918		1,969

Actual - Cooling (c)			859		509		1,294		813
Normal - Cooling (b)			691		703		984		993

Western Region
Actual - Heating (a)			-		-		764		540
Normal - Heating (b)			1		1		596		601

Actual - Cooling (d)			1,471		1,349		2,357		2,309
Normal - Cooling (b)			1,353		1,362		2,168		2,174

(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 2010 Compared to Third Quarter of 2009

Reconciliation of Third Quarter of 2009 to Third Quarter of 2010
Income from Utility Operations Before Extraordinary Loss
(in millions)

Third Quarter of 2009	$	448

Changes in Gross Margin:
Retail Margins		246
Off-system Sales		42
Other Revenues		(52	)
Total Change in Gross Margin		236

Total Expenses and Other:
Other Operation and Maintenance		(52	)
Depreciation and Amortization		(1	)
Taxes Other Than Income Taxes		(17	)
Interest and Investment Income		(4	)
Carrying Costs Income		6
Allowance for Equity Funds Used During Construction		(6	)
Interest Expense		(6	)
Equity Earnings of Unconsolidated Subsidiaries		1
Total Expenses and Other		(79	)

Income Tax Expense		(64	)

Third Quarter of 2010	$	541

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 $246 million primarily due to the following:
	·	Successful rate proceedings in our service territories which include:
		·	A $31 million increase in the recovery of E&R costs in Virginia, construction financing costs in West Virginia and costs related to the Transmission Rate Adjustment Clause in Virginia.
		·	A $22 million rate increase in Kentucky.
		·	An $18 million net rate increase for SWEPCo.
		·	A $16 million net rate increase for I&M.
		·	A $15 million rate increase in Oklahoma.
		·	A $13 million increase in the recovery of advanced metering costs in Texas.
		·	A $9 million net rate increase in our other jurisdictions.
		·	For the increases described above, $50 million of these rate increases relate to riders/trackers which have corresponding increases in Other Operation and Maintenance expense line items discussed below.
	·	A $131 million increase in weather-related usage primarily due to a 69% increase in cooling degree days in our eastern region.
	·	A $19 million increase in fuel margins due to higher fuel and purchased power costs recorded in 2009 related to the Cook Plant Unit 1 (Unit 1) shutdown. This increase in fuel margins was offset by a corresponding decrease in Other Revenues as discussed below.
	These increases were partially offset by:
	·	A $24 million net decrease due to a favorable fuel recovery adjustment in Ohio that was recorded in 2009.
	·	A $9 million decrease due to the termination of an I&M unit power agreement.

·	Margins from Off-system Sales increased $42 million primarily due to increased prices and higher physical sales volumes in our eastern region, partially offset by lower trading and marketing margins.
·	Other Revenues decreased $52 million primarily due to the Cook Plant accidental outage insurance proceeds of $46 million which ended when Unit 1 returned to service in December 2009. I&M reduced customer bills by approximately $19 million in the third quarter of 2009 for the cost of replacement power resulting from the Unit 1 outage. This decrease in insurance proceeds was offset by a corresponding increase in Retail Margins as discussed above.

Total Expenses and Other and Income Taxes changed between years as follows:

·	Other Operation and Maintenance expenses increased $52 million primarily due to:
	·	A $45 million increase in demand side management, energy efficiency, vegetation management programs and other related expenses. All of these expenses are currently recovered dollar-for-dollar in rate recovery riders/trackers in Gross Margin.
	·	A $7 million increase primarily due to a net increase in employee related expenses.
·	Taxes Other Than Income Taxes increased $17 million primarily due to increased revenue taxes as the result of higher than anticipated generation load and higher property taxes.
·	Carrying Costs Income increased $6 million primarily due to increased environmental construction deferrals in Virginia and a higher under-recovered fuel balance for OPCo.
·	Allowance for Equity Funds Used During Construction decreased $6 million primarily due to SWEPCo’s completed construction of the Stall Unit in June 2010.
·	Interest Expense increased $6 million primarily due to an increase in long-term debt.
·	Income Tax Expense increased $64 million primarily due to an increase in pretax book income and other book/tax differences which are accounted for on a flow-through basis.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Reconciliation of Nine Months Ended September 30, 2009 to Nine Months Ended September 30, 2010
Income from Utility Operations Before Extraordinary Loss
(in millions)

Nine Months Ended September 30, 2009	$	1,121

Changes in Gross Margin:
Retail Margins		526
Off-system Sales		43
Transmission Revenues		8
Other Revenues		(192)
Total Change in Gross Margin		385

Total Expenses and Other:
Other Operation and Maintenance		(396)
Depreciation and Amortization		(32)
Taxes Other Than Income Taxes		(40)
Interest and Investment Income		4
Carrying Costs Income		18
Allowance for Equity Funds Used During Construction		1
Interest Expense		(31)
Equity Earnings of Unconsolidated Subsidiaries		4
Total Expenses and Other		(472)

Income Tax Expense		(17)

Nine Months Ended September 30, 2010	$	1,017

·	Retail Margins increased $526 million primarily due to the following:
	·	Successful rate proceedings in our service territories which include:
		·	A $106 million increase in the recovery of E&R costs in Virginia, construction financing costs in West Virginia and costs related to the Transmission Rate Adjustment Clause in Virginia.
		·	A $38 million increase in the recovery of advanced metering costs in Texas.
		·	A $34 million rate increase in Oklahoma.
		·	A $31 million net increase in rates for SWEPCo.
		·	A $26 million rate increase in Kentucky.
		·	A $25 million rate increase in Ohio.
		·	A $24 million net rate increase for I&M.
		·	A $6 million net increase in rates in our other jurisdictions.
		·	For the increases described above, $115 million of these rate increases relate to riders/trackers which have corresponding increases in Other Operation and Maintenance expense line items discussed below.
	·	A $202 million increase in weather-related usage primarily due to a 59% increase in cooling degree days in our eastern region and a 41% increase in heating degree days in our western region.
	·	A $59 million increase in fuel margins due to higher fuel and purchased power costs recorded in 2009 related to the Unit 1 shutdown. This increase in fuel margins was offset by a corresponding decrease in Other Revenues as discussed below.
	These increases were partially offset by:
	·	A $27 million decrease due to the termination of an I&M unit power agreement.
·	Margins from Off-system Sales increased $43 million primarily due to increased prices and higher physical sales volumes in our eastern region, partially offset by lower trading and marketing margins.

·	Transmission Revenues increased $8 million primarily due to increased revenues in the ERCOT, PJM and SPP regions.
·	Other Revenues decreased $192 million primarily due to the Cook Plant accidental outage insurance proceeds of $145 million which ended when Unit 1 returned to service in December 2009. I&M reduced customer bills by approximately $59 million in the first nine months of 2009 for the cost of replacement power resulting from the Unit 1 outage. This decrease in insurance proceeds was offset by a corresponding increase in Retail Margins as discussed above. Other Revenues also decreased due to lower gains on sales of emission allowances of $26 million, partially offset by sharing in certain fuel clauses.

Total Expenses and Other and Income Taxes changed between years as follows:

·	Other Operation and Maintenance expenses increased $396 million primarily due to the following:
	·	A $275 million increase due to expenses related to cost reduction initiatives.
	·	A $101 million increase in demand side management, energy efficiency, vegetation management programs and other related expenses. All of these expenses are currently recovered dollar-for-dollar in rate recovery riders/trackers in Gross Margin.
	·	A $54 million increase due to the write-off of APCo’s Virginia Share of the Mountaineer Carbon Capture and Storage Project as denied for recovery by the Virginia SCC.
	·	A $33 million increase primarily due to a net increase in employee related expenses.
	These increases were partially offset by:
	·	A $47 million decrease in storm related expenses primarily due to the deferral of $29 million of 2009 storm costs in Virginia as allowed by the Virginia SCC.
	·	A $20 million decrease in customer assistance and other customer accounts expense.
·	Depreciation and Amortization increased $32 million primarily due to new environmental control improvements placed in service at APCo, CSPCo and OPCo.
·	Taxes Other Than Income Taxes increased $40 million primarily due to increased revenue taxes as the result of higher than anticipated generation load, higher property and franchise taxes and the employer portion of payroll taxes incurred related to the cost reduction initiatives.
·	Carrying Costs Income increased $18 million primarily due to increased environmental construction deferrals in Virginia and a higher under-recovered fuel balance for OPCo.
·	Interest Expense increased $31 million primarily due to an increase in long-term debt and a decrease in the debt component of AFUDC due to lower CWIP balances at APCo, CSPCo and OPCo.
·	Income Tax Expense increased $17 million primarily due to the regulatory accounting treatment of state income taxes, other book/tax differences which are accounted for on a flow-through basis and the tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits, partially offset by a decrease in pretax book income.

AEP RIVER OPERATIONS

Third Quarter of 2010 Compared to Third Quarter of 2009

Income Before Extraordinary Loss from our AEP River Operations segment increased from $10 million in 2009 to $14 million in 2010 primarily due to improved grain freight rates and increased volumes. Barge volumes increased 25% due to increased barge fleet, towboat additions and the earlier-than-normal harvest season.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Income Before Extraordinary Loss from our AEP River Operations segment decreased from $22 million in 2009 to $16 million in 2010 primarily due to expenses related to the cost reduction initiatives, increased interest expense on new equipment financing and a gain on the sale of two older towboats in 2009.

GENERATION AND MARKETING

Third Quarter of 2010 Compared to Third Quarter of 2009

Income Before Extraordinary Loss from our Generation and Marketing segment decreased from $5 million in 2009 to $0 million in 2010 primarily due to reduced inception gains from ERCOT marketing activities and lower gross margins at the Oklaunion Plant.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Income Before Extraordinary Loss from our Generation and Marketing segment decreased from $33 million in 2009 to $17 million in 2010 primarily due to reduced inception gains from ERCOT marketing activities partially offset by improved plant performance, hedging activities on our generation assets and increased income from our wind farm operations.

ALL OTHER

Third Quarter of 2010 Compared to Third Quarter of 2009

Income Before Extraordinary Loss from All Other increased from a loss of $17 million in 2009 to a gain of $2 million in 2010 primarily due to the recording of federal income tax adjustments.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Income Before Extraordinary Loss from All Other increased from a loss of $45 million in 2009 to a loss of $10 million in 2010 due to $16 million in pretax gains ($10 million, net of tax) on the sale of our remaining 138,000 shares of ICE in the second quarter of 2010 and the recording of federal income tax adjustments.

AEP SYSTEM INCOME TAXES

Third Quarter of 2010 Compared to Third Quarter of 2009

Income Tax Expense increased $50 million in comparison to 2009 primarily due to an increase in pretax book income and other book/tax differences which are accounted for on a flow-through basis, offset in part by federal income tax adjustments.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Income Tax Expense decreased $5 million in comparison to 2009 primarily due to a decrease in pretax book income and federal income tax adjustments, partially offset by the regulatory accounting treatment of state income taxes, other book/tax differences which are accounted for on a flow-through basis and the tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.

FINANCIAL CONDITION

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

DEBT AND EQUITY CAPITALIZATION

	September 30, 2010				December 31, 2009
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	17,281	53.2	%	$	17,498	56.8	%
Short-term Debt		1,466	4.5			126	0.4
Total Debt		18,747	57.7			17,624	57.2
Preferred Stock of Subsidiaries		60	0.2			61	0.2
AEP Common Equity		13,656	42.1			13,140	42.6

Total Debt and Equity Capitalization	$	32,463	100.0	%	$	30,825	100.0	%

Our ratio of debt-to-total capital increased from 57.2% in 2009 to 57.7% in 2010 primarily due to an increase in short-term debt of $750 million as a result of a change in an accounting standard applicable to our sale of receivables agreement and an increase of $594 million in commercial paper outstanding.

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, 2010, we had $3.4 billion in aggregate credit facility commitments to support our operations, including our obligation to make payment of $447 million due to an unfavorable judgment issued in October 2010 related to the Bank of America litigation. See "Enron Bankruptcy" section of Note 4. Additional liquidity is available from cash from operations and a sale of receivables agreement. We are committed to maintaining adequate liquidity. We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged. Sources of long-term funding include issuance of long-term debt, sale-leaseback or leasing agreements or common stock.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments. At September 30, 2010, our available liquidity was approximately $3.2 billion as illustrated in the table below:

		Amount		Maturity
		(in millions)
Commercial Paper Backup:
	Revolving Credit Facility	$	1,454	April 2012
	Revolving Credit Facility		1,500	June 2013
Revolving Credit Facility			478	April 2011
Total			3,432
Cash and Cash Equivalents			1,090
Total Liquidity Sources			4,522
Less:	AEP Commercial Paper Outstanding		713
	Letters of Credit Issued		602

Net Available Liquidity		$	3,207

We have credit facilities totaling $3.4 billion, of which two $1.5 billion credit facilities support our commercial paper program. In June 2010, we terminated one of the $1.5 billion facilities that was scheduled to mature in March 2011 and replaced it with a new $1.5 billion credit facility which matures in 2013. These credit facilities also allow us to have letters of credit issued in an amount up to $1.35 billion. In June 2010, we also reduced the credit facility that matures in April 2011 from $627 million to $478 million. This facility can be utilized for letters of credit or draws.

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 2010 was $868 million. The weighted-average interest rate for our commercial paper during 2010 was 0.42%.

Securitized Accounts Receivables

In July 2010, we renewed our receivables securitization agreement. The agreement provides a commitment of $750 million from bank conduits to purchase receivables. A commitment of $375 million expires in July 2011 and the remaining commitment of $375 million expires in July 2013.

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 other capital 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, 2010, this contractually-defined percentage was 54%. Nonperformance under these covenants could result in an event of default under these credit agreements. At September 30, 2010, we complied with all of the covenants contained in these credit agreements. In addition, the acceleration of our payment obligations, or the obligations of certain of our major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements and in a majority of our non-exchange traded commodity contracts which would permit the lenders and counterparties to declare the outstanding amounts payable. However, a default under our non-exchange traded commodity contracts does not cause an event of default under our revolving credit agreements.

The revolving credit facilities do not permit the lenders to refuse a draw on 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, 2010, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.46 per share in October 2010, a $0.04 increase from the prior quarter. Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time. Our income derives from our common stock equity in the earnings of our utility subsidiaries. Various financing arrangements, charter provisions and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.

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

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

Credit Ratings

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.

CASH FLOW

Managing our cash flows is a major factor in maintaining our liquidity strength.

	Nine Months Ended
	September 30,
	2010				2009
	(in millions)
Cash and Cash Equivalents at Beginning of Period		$	490			$	411
Net Cash Flows from Operating Activities			1,702				1,871
Net Cash Flows Used for Investing Activities			(1,575	)			(2,097	)
Net Cash Flows from Financing Activities			473				692
Net Increase in Cash and Cash Equivalents			600				466
Cash and Cash Equivalents at End of Period		$	1,090			$	877

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,
	2010				2009
	(in millions)
Net Income		$	1,040			$	1,126
Depreciation and Amortization			1,237				1,200
Other			(575	)			(455	)
Net Cash Flows from Operating Activities		$	1,702			$	1,871

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.

Net Cash Flows from Operating Activities were $1.9 billion in 2009 consisting primarily of Net Income of $1.1 billion and $1.2 billion of noncash Depreciation and Amortization. Other represents items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. Significant changes in other items include the negative impact on cash of an increase in coal inventory reflecting decreased customer demand for electricity as the result of the economic slowdown and unfavorable weather conditions and an increase in under-recovered fuel primarily in Ohio and West Virginia. Deferred Income Taxes increased primarily due to the American Recovery and Reinvestment Act of 2009 extending bonus depreciation provisions, a change in tax accounting method and an increase in tax versus book temporary differences from operations.

Investing Activities

	Nine Months Ended
	September 30,
	2010				2009
	(in millions)
Construction Expenditures		$	(1,629	)		$	(2,123	)
Acquisitions of Nuclear Fuel			(69	)			(153	)
Proceeds from Sales of Assets			160				258
Other			(37	)			(79	)
Net Cash Flows Used for Investing Activities		$	(1,575	)		$	(2,097	)

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

Net Cash Flows Used for Investing Activities were $2.1 billion in 2009 primarily due to Construction Expenditures for our new generation, environmental and distribution investments. Proceeds from Sales of Assets in 2009 include $104 million relating to the sale of a portion of Turk Plant to joint owners and $95 million for sales of transmission assets in Texas to ETT.

Financing Activities

	Nine Months Ended
	September 30,
	2010				2009
	(in millions)
Issuance of Common Stock, Net		$	65			$	1,706
Issuance/Retirement of Debt, Net			1,087				(371	)
Dividends Paid on Common Stock			(602	)			(564	)
Other			(77	)			(79	)
Net Cash Flows from Financing Activities		$	473			$	692

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. See Note 11 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows from Financing Activities in 2009 were $692 million. Issuance of Common Stock, Net of $1.7 billion is comprised of our issuance of 69 million shares of common stock with net proceeds of $1.64 billion and additional shares through our dividend reinvestment, employee savings and incentive programs. Our net debt retirements were $371 million. These retirements included a repayment of $2 billion outstanding under our credit facilities primarily from the proceeds of our common stock issuance and issuances of $1.6 billion of senior unsecured and debt notes and $327 million of pollution control bonds.

In October 2010, I&M retired its $150 million 6% Senior Unsecured Notes due 2032.

In November 2010, OPCo retired its $200 million 5.3% Senior Unsecured Notes due 2010.

OFF-BALANCE SHEET ARRANGEMENTS

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

	September 30,			December 31,
	2010			2009
	(in millions)
AEP Credit Accounts Receivable Purchase Commitments		$	-		$	631
Rockport Plant Unit 2 Future Minimum Lease Payments			1,846			1,920
Railcars Maximum Potential Loss From Lease Agreement			25			25

Effective January 1, 2010, we record the receivables and debt related to AEP Credit on our Condensed Consolidated Balance Sheet. 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 of Results of Operations” in the 2009 Annual Report.

SUMMARY OBLIGATION INFORMATION

A summary of our contractual obligations is included in our 2009 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” 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 Connor Run fly ash impoundment, are subject to the provisions of the Mine Act.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. DHLC, CCPC and Connor Run received the following notices of violation and proposed assessments under the Mine Act for the quarter ended September 30, 2010:

		DHLC		CCPC		Conner Run
Number of Citations for Violations of Mandatory Health or
	Safety Standards under 104 *		7		-		-
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) *		1		-		-
Number of Flagrant Violations under 110(b)(2) *			-		-		-
Number of Imminent Danger Orders Issued under 107(a) *			-		-		-
Total Dollar Value of Proposed Assessments		$	11,472	$	-	$	-
Number of Mining-related Fatalities			-		-		-

* References to sections under the Mine Act

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2009 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

New Accounting Pronouncements Adopted During 2010

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

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

See Note 2 for further discussion of accounting pronouncements.

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, we cannot determine the impact on the reporting of our operations and financial position that may result from any such future changes. The FASB is currently working on several projects including revenue recognition, financial statements, contingencies, financial instruments, emission allowances, fair value measurements, leases, insurance, hedge accounting, consolidation policy and discontinued operations. We also expect to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP. The ultimate pronouncements resulting from these and future projects could have an impact on our future net income and financial position.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our Utility Operations segment is exposed to certain market risks as a major power producer and transacts in wholesale electricity, coal and emission allowance trading and marketing contracts. These risks include commodity price risk, interest rate risk and credit risk. In addition, we are exposed to foreign currency exchange risk because occasionally we procure various services and materials used in our energy business from foreign suppliers. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

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

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

We employ risk management contracts including physical forward purchase and sale contracts and financial forward purchase and sale contracts. We engage in risk management of electricity, coal, natural gas and emission allowances and to a lesser degree other commodities associated with our energy business. As a result, we are subject to price risk. The amount of risk taken is determined by the commercial operations group in accordance with the market risk policy approved by the Finance Committee of our Board of Directors. Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The CORC consists of our Executive Vice President - Generation,

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, 2009:

	MTM Risk Management Contract Net Assets (Liabilities)
	Nine Months Ended September 30, 2010
	(in millions)
				Generation
		Utility		and
		Operations		Marketing		All Other		Total
Total MTM Risk Management Contract Net Assets (Liabilities)
	at December 31, 2009	$	134	$	147	$	(3)	$	278
(Gain) Loss from Contracts Realized/Settled During the Period and
	Entered in a Prior Period		(62)		(13)		5		(70)
Fair Value of New Contracts at Inception When Entered During the Period (a)			15		8		-		23
Net Option Premiums Received for Unexercised or Unexpired
	Option Contracts Entered During the Period		(1)		-		-		(1)
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b)			(2)		(2)		-		(4)
Changes in Fair Value Due to Market Fluctuations During thePeriod (c)			11		2		-		13
Changes in Fair Value Allocated to Regulated Jurisdictions (d)			25		-		-		25
Total MTM Risk Management Contract Net Assets at September 30, 2010		$	120	$	142	$	2		264

Commodity Cash Flow Hedge Contracts									3
Interest Rate and Foreign Currency Cash Flow Hedge Contracts									(6)
Fair Value Hedge Contracts									7
Collateral Deposits									208
Total MTM Derivative Contract Net Assets at September 30, 2010								$	476

(a)	Reflects fair value on long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged.
(b)	Reflects changes in methodology in calculating the credit and discounting liability fair value adjustments.
(c)	Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(d)	Relates to the net gains (losses) of those contracts that are not reflected on the Condensed Consolidated 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, 2010, our credit exposure net of collateral to sub investment grade counterparties was approximately 8.9%, 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, 2010, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

		Exposure						Number of		Net Exposure
		Before						Counterparties		of
		Credit		Credit		Net		>10% of		Counterparties
Counterparty Credit Quality		Collateral		Collateral		Exposure		Net Exposure		>10%

		(dollars in millions)
Investment Grade		$	801	$	41	$	760		2	$	221
Split Rating			4		-		4		1		4
Noninvestment Grade			2		1		1		2		1
No External Ratings:
	Internal Investment Grade		210		-		210		2		133
	Internal Noninvestment Grade		104		11		93		4		72
Total as of September 30, 2010		$	1,121	$	53	$	1,068		11	$	431

Total as of December 31, 2009		$	846	$	58	$	788		12	$	317

Value at Risk (VaR) Associated with Risk Management Contracts

We use a risk measurement model, which calculates VaR, to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, as of September 30, 2010, a near term typical change in commodity prices is not expected to have a material effect on our net income, cash flows or financial condition.

The following table shows the end, high, average and low market risk as measured by VaR for the trading portfolio for the periods indicated:

VaR Model

Nine Months Ended

Twelve Months Ended

September 30, 2010

December 31, 2009

(in millions)

End

High

Average

Low

End

High

Average

Low

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 moves 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 AEP’s 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 for both September 30, 2010 and December 31, 2009, the estimated EaR on our debt portfolio for the following twelve months was $4 million.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2010 and 2009
(in millions, except per-share and share amounts)
(Unaudited)

	Three Months Ended						Nine Months Ended
	2010			2009			2010			2009
REVENUES
Utility Operations	$	3,876		$	3,364		$	10,468		$	9,666
Other Revenues		188			183			525			541
TOTAL REVENUES		4,064			3,547			10,993			10,207
EXPENSES
Fuel and Other Consumables Used for Electric Generation		1,189			931			3,098			2,624
Purchased Electricity for Resale		247			247			712			800
Other Operation		707			642			2,374			1,890
Maintenance		262			255			776			821
Depreciation and Amortization		424			421			1,237			1,200
Taxes Other Than Income Taxes		210			193			619			582
TOTAL EXPENSES		3,039			2,689			8,816			7,917

OPERATING INCOME		1,025			858			2,177			2,290

Other Income (Expense):
Interest and Investment Income		3			5			24			5
Carrying Costs Income		18			12			51			33
Allowance for Equity Funds Used During Construction		17			23			60			59
Interest Expense		(251	)		(248	)		(750	)		(726	)

INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		812			650			1,562			1,661

Income Tax Expense		258			208			530			535
Equity Earnings of Unconsolidated Subsidiaries		3			4			8			5

INCOME BEFORE EXTRAORDINARY LOSS		557			446			1,040			1,131

EXTRAORDINARY LOSS, NET OF TAX		-			-			-			(5	)

NET INCOME		557			446			1,040			1,126

Less: Net Income Attributable to Noncontrolling Interests		1			2			3			5

NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS		556			444			1,037			1,121

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

EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	555		$	443		$	1,035		$	1,119

WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING		479,578,139			476,948,143			479,023,690			452,255,119

BASIC EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
Income Before Extraordinary Loss	$	1.16		$	0.93		$	2.16		$	2.48
Extraordinary Loss, Net of Tax		-			-			-			(0.01	)

TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	1.16		$	0.93		$	2.16		$	2.47


WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING		479,750,447			477,111,144			479,261,415			452,495,494

DILUTED EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
Income Before Extraordinary Loss	$	1.16		$	0.93		$	2.16		$	2.48
Extraordinary Loss, Net of Tax		-			-			-			(0.01	)

TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
SHAREHOLDERS	$	1.16		$	0.93		$	2.16		$	2.47

CASH DIVIDENDS PAID PER SHARE	$	0.42		$	0.41		$	1.25		$	1.23

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, 2010 and 2009

(in millions)

(Unaudited)

AEP Common Shareholders

Common Stock

Accumulated

Other

Paid-in

Retained

Comprehensive

Noncontrolling

Amount

Capital

Earnings

Income (Loss)

Interests

Total

TOTAL EQUITY – DECEMBER 31, 2008

426

2,771

4,527

3,847

(452)

10,710

Issuance of Common Stock