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

OR

[ ] 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.

i

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.

ii

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.

iv

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.

1

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.

2

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.

3

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.

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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.

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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.”

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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.

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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.

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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.

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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.

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· 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.

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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

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 $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.

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· 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.

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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.

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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.

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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.

16

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.

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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.

18

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.

19

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,

20

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.

21

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

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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)				(in millions)
End	High	Average	Low	End	High	Average	Low
$-	$2	$1	$-	$1	$2	$1	$-

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

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.

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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.

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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
				Shares		Amount		Capital		Earnings		Income (Loss)		Interests		Total
TOTAL EQUITY – DECEMBER 31, 2008					426	$	2,771	$	4,527	$	3,847	$	(452)	$	17	$	10,710
Issuance of Common Stock					71		464		1,294								1,758
Common Stock Dividends											(559)				(5)		(564)
Preferred Stock Dividend Requirements of
	Subsidiaries										(2)						(2)
Purchase of JMG									55						(18)		37
Other Changes in Equity									(50)						1		(49)
SUBTOTAL – EQUITY																	11,890
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of
	Taxes:
		Cash Flow Hedges, Net of Tax of $3											5				5
		Securities Available for Sale, Net of Tax of $5											10				10
		Amortization of Pension and OPEB Deferred
			Costs, Net of Tax of $18										33				33
NET INCOME											1,121				5		1,126
TOTAL COMPREHENSIVE INCOME																	1,174
TOTAL EQUITY – SEPTEMBER 30, 2009					497	$	3,235	$	5,826	$	4,407	$	(404)	$	-	$	13,064
TOTAL EQUITY – DECEMBER 31, 2009					498	$	3,239	$	5,824	$	4,451	$	(374)	$	-	$	13,140
Issuance of Common Stock					2		13		53								66
Common Stock Dividends											(599)				(3)		(602)
Preferred Stock Dividend Requirements of
	Subsidiaries										(2)						(2)
Other Changes in Equity									4								4
SUBTOTAL – EQUITY																	12,606
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
	Taxes:
		Cash Flow Hedges, Net of Tax of $1											2				2
		Securities Available for Sale, Net of Tax of $5											(9)				(9)
		Amortization of Pension and OPEB Deferred
			Costs, Net of Tax of $9										17				17
NET INCOME											1,037				3		1,040
TOTAL COMPREHENSIVE INCOME																	1,050
TOTAL EQUITY – SEPTEMBER 30, 2010					500	$	3,252	$	5,881	$	4,887	$	(364)	$	-	$	13,656
See Condensed Notes to Condensed Consolidated Financial Statements.

25

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2010 and December 31, 2009
(in millions)
(Unaudited)
	2010			2009
CURRENT ASSETS
Cash and Cash Equivalents	$	1,090		$	490
Other Temporary Investments		326			363
Accounts Receivable:
Customers		585			492
Accrued Unbilled Revenues		137			503
Pledged Accounts Receivable - AEP Credit		1,029			-
Miscellaneous		108			92
Allowance for Uncollectible Accounts		(43	)		(37	)
Total Accounts Receivable		1,816			1,050
Fuel		811			1,075
Materials and Supplies		598			586
Risk Management Assets		279			260
Accrued Tax Benefits		165			547
Regulatory Asset for Under-Recovered Fuel Costs		95			85
Margin Deposits		86			89
Prepayments and Other Current Assets		155			211
TOTAL CURRENT ASSETS		5,421			4,756
PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		24,079			23,045
Transmission		8,470			8,315
Distribution		13,940			13,549
Other Property, Plant and Equipment (including coal mining and nuclear fuel)		3,867			3,744
Construction Work in Progress		2,571			3,031
Total Property, Plant and Equipment		52,927			51,684
Accumulated Depreciation and Amortization		17,929			17,340
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		34,998			34,344
OTHER NONCURRENT ASSETS
Regulatory Assets		4,745			4,595
Securitized Transition Assets		1,788			1,896
Spent Nuclear Fuel and Decommissioning Trusts		1,466			1,392
Goodwill		76			76
Long-term Risk Management Assets		488			343
Deferred Charges and Other Noncurrent Assets		910			946
TOTAL OTHER NONCURRENT ASSETS		9,473			9,248
TOTAL ASSETS	$	49,892		$	48,348
See Condensed Notes to Condensed Consolidated Financial Statements.

26

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2010 and December 31, 2009
(dollars in millions)
(Unaudited)
					2010		2009
CURRENT LIABILITIES
Accounts Payable					$	884	$	1,158
Short-term Debt:
	General					716		126
	Securitized Debt for Receivables - AEP Credit					750		-
		Total Short-term Debt				1,466		126
Long-term Debt Due Within One Year						1,286		1,741
Risk Management Liabilities						124		120
Customer Deposits						264		256
Accrued Taxes						470		632
Accrued Interest						255		287
Regulatory Liability for Over-Recovered Fuel Costs						11		76
Liability Related to Litigation						447		-
Other Current Liabilities						941		931
TOTAL CURRENT LIABILITIES						6,148		5,327
NONCURRENT LIABILITIES
Long-term Debt
	(September 30, 2010 amount includes $1,838 related to Transition Funding, DCC Fuel and Sabine)					15,995		15,757
Long-term Risk Management Liabilities						167		128
Deferred Income Taxes						6,928		6,420
Regulatory Liabilities and Deferred Investment Tax Credits						3,109		2,909
Asset Retirement Obligations						1,296		1,254
Employee Benefits and Pension Obligations						1,729		2,189
Deferred Credits and Other Noncurrent Liabilities						804		1,163
TOTAL NONCURRENT LIABILITIES						30,028		29,820
TOTAL LIABILITIES						36,176		35,147
Cumulative Preferred Stock Not Subject to Mandatory Redemption						60		61
Rate Matters (Note 3)
Commitments and Contingencies (Note 4)
EQUITY
Common Stock – Par Value – $6.50 Per Share:
			2010	2009
	Shares Authorized		600,000,000	600,000,000
	Shares Issued		500,319,686	498,333,265
(20,278,858 shares were held in treasury at September 30, 2010 and December 31, 2009)						3,252		3,239
Paid-in Capital						5,881		5,824
Retained Earnings						4,887		4,451
Accumulated Other Comprehensive Income (Loss)						(364)		(374)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY						13,656		13,140
Noncontrolling Interests						-		-
TOTAL EQUITY						13,656		13,140
TOTAL LIABILITIES AND EQUITY					$	49,892	$	48,348
See Condensed Notes to Condensed Consolidated Financial Statements.

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2010 and 2009
(in millions)
(Unaudited)
	2010			2009
OPERATING ACTIVITIES
Net Income	$	1,040		$	1,126
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		1,237			1,200
Deferred Income Taxes		404			662
Extraordinary Loss, Net of Tax		-			5
Carrying Costs Income		(51	)		(33	)
Allowance for Equity Funds Used During Construction		(60	)		(59	)
Mark-to-Market of Risk Management Contracts		(108	)		(99	)
Amortization of Nuclear Fuel		113			41
Property Taxes		157			144
Fuel Over/Under-Recovery, Net		(233	)		(377	)
Pension Contributions to Qualified Plan Trust		(463	)		-
Change in Other Noncurrent Assets		(50	)		13
Change in Other Noncurrent Liabilities		183			164
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		(766	)		68
Fuel, Materials and Supplies		240			(394	)
Margin Deposits		3			(15	)
Accounts Payable		(163	)		(29	)
Customer Deposits		8			11
Accrued Taxes, Net		223			(165	)
Accrued Interest		(32	)		(38	)
Other Current Assets		35			(71	)
Other Current Liabilities		(15	)		(283	)
Net Cash Flows from Operating Activities		1,702			1,871
INVESTING ACTIVITIES
Construction Expenditures		(1,629	)		(2,123	)
Change in Other Temporary Investments, Net		63			72
Purchases of Investment Securities		(1,542	)		(573	)
Sales of Investment Securities		1,477			524
Acquisitions of Nuclear Fuel		(69	)		(153	)
Acquisitions of Assets		(16	)		(70	)
Proceeds from Sales of Assets		160			258
Other Investing Activities		(19	)		(32	)
Net Cash Flows Used for Investing Activities		(1,575	)		(2,097	)
FINANCING ACTIVITIES
Issuance of Common Stock, Net		65			1,706
Issuance of Long-term Debt		1,201			1,912
Borrowings from Revolving Credit Facilities		195			90
Change in Short-term Debt, Net		1,223			347
Retirement of Long-term Debt		(1,454	)		(659	)
Repayments to Revolving Credit Facilities		(78	)		(2,061	)
Principal Payments for Capital Lease Obligations		(74	)		(62	)
Dividends Paid on Common Stock		(602	)		(564	)
Dividends Paid on Cumulative Preferred Stock		(2	)		(2	)
Other Financing Activities		(1	)		(15	)
Net Cash Flows from Financing Activities		473			692
Net Increase in Cash and Cash Equivalents		600			466
Cash and Cash Equivalents at Beginning of Period		490			411
Cash and Cash Equivalents at End of Period	$	1,090		$	877
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	755		$	744
Net Cash Paid (Received) for Income Taxes		(243	)		(74	)
Noncash Acquisitions Under Capital Leases		190			53
Construction Expenditures Included in Accounts Payable at September 30,		229			229
See Condensed Notes to Condensed Consolidated Financial Statements.

28

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX TO CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1.  SIGNIFICANT ACCOUNTING MATTERS

General

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

In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our net income, financial position and cash flows for the interim periods.  Net income for the three and nine months ended September 30, 2010 is not necessarily indicative of results that may be expected for the year ending December 31, 2010.  The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2009 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 26, 2010.

Variable Interest Entities

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE.  A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.  Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.”  In determining whether we are the primary beneficiary of a VIE, we consider factors such as equity at risk, the amount of the VIE’s variability we absorb, guarantees of indebtedness, voting rights including kick-out rights, power to direct the VIE and other factors.  We believe that significant assumptions and judgments were applied consistently.  Also, see the “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.

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

Sabine is a mining operator providing mining services to SWEPCo.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee.  In addition, SWEPCo determines how much coal will be mined for each year.  Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine.  SWEPCo’s total billings from Sabine for the three months ended September 30, 2010 and 2009 were $30 million and $34 million, respectively, and for the nine months ended September 30, 2010 and 2009 were $103 million and $95 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on our Condensed Consolidated Balance Sheets.

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Our subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance.  EIS has multiple protected cells.  Neither AEP nor its subsidiaries have an equity investment in EIS.  The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance.  Our subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims.  Based on our control and the structure of the protected cell and EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate its assets and liabilities.  Our insurance premium payments to the protected cell for the three months ended September 30, 2010 and 2009 were $15 million and $13 million, respectively, and for the nine months ended September 30, 2010 and 2009 were $33 million and $30 million, respectively.  See the tables below for the classification of the protected cell’s assets and liabilities on our Condensed Consolidated Balance Sheets.  The amount reported as equity is the protected cell’s policy holders’ surplus.

In September 2009, I&M entered into a nuclear fuel sale and leaseback transaction with DCC Fuel LLC.  In April 2010, I&M entered into a nuclear fuel sale and leaseback transaction with DCC Fuel II LLC.  DCC Fuel LLC and DCC Fuel II LLC (collectively DCC Fuel) were formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions.  Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  Payments on the leases are made semi-annually and began in April 2010.  Payments on the leases for the nine months ended September 30, 2010 were $22 million.  No payments were made to DCC Fuel during the third quarter of 2010 and during the year 2009.  The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the 48 and 54 month lease term, respectively.  Based on our control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The capital leases are eliminated upon consolidation.  See the tables below for the classification of DCC Fuel’s assets and liabilities on our Condensed Consolidated Balance Sheets.

AEP Credit is a wholly-owned subsidiary of AEP.  AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements.  AEP provides up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings.  Any third party financing of AEP Credit only has recourse to the receivables sold for such financing.  Based on our control of AEP Credit, management has concluded that we are the primary beneficiary and are required to consolidate its assets and liabilities.  See the tables below for the classification of AEP Credit’s assets and liabilities on our Condensed Consolidated Balance Sheets.  See the “ASU 2009-17 ‘Consolidation’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.  Also, see “Sale of Receivables – AEP Credit” section of Note 14 in the 2009 Annual Report for further information.

DHLC is a mining operator who sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  SWEPCo and CLECO share the executive board seats and its voting rights equally.  Each entity guarantees a 50% share of DHLC’s debt.  SWEPCo and CLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee.  Based on the shared control of DHLC’s operations, management concluded as of January 1, 2010 that SWEPCo is no longer the primary beneficiary and is no longer required to consolidate DHLC.  SWEPCo’s total billings from DHLC for the three months ended September 30, 2010 and 2009 were $14 million and $12 million, respectively, and for the nine months ended September 30, 2010 and 2009 were $40 million and $31 million, respectively.  See the tables below for the classification of DHLC’s assets and liabilities on our Condensed Consolidated Balance Sheet at December 31, 2009 as well as our investment and maximum exposure as of September 30, 2010.  As of January 1, 2010, DHLC is reported as an equity investment in Deferred Charges and Other Noncurrent Assets on our Condensed Consolidated Balance Sheet.  Also, see the “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.

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Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas restructuring law.  Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant.  Therefore, TCC is required to consolidate Transition Funding.  The securitized bonds totaled $1.8 billion at September 30, 2010 and are included in current and long-term debt on the Condensed Consolidated Balance Sheets.  Transition Funding has securitized transition assets of $1.8 billion at September 30, 2010, which are presented separately on the face of the Condensed Consolidated Balance Sheets.  The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT.  The securitization bonds are payable only from and secured by the securitized transition assets.  The bondholders have no recourse to TCC or any other AEP entity.  TCC acts as the servicer for Transition Funding’s securitized transition asset and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs.

32

The balances below represent the assets and liabilities of the VIEs that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
September 30, 2010
(in millions)
	SWEPCo			I&M			Protected Cell						Transition
	Sabine			DCC Fuel			of EIS			AEP Credit			Funding
ASSETS
Current Assets		$	42		$	92		$	143		$	1,004		$	160
Net Property, Plant and Equipment			142			118			-			-			-
Other Noncurrent Assets			35			80			1			10			1,791
Total Assets		$	219		$	290		$	144		$	1,014		$	1,951
LIABILITIES AND EQUITY
Current Liabilities		$	26		$	65		$	40		$	961		$	196
Noncurrent Liabilities			193			225			90			1			1,741
Equity			-			-			14			52			14
Total Liabilities and Equity		$	219		$	290		$	144		$	1,014		$	1,951

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2009
(in millions)
	SWEPCo			SWEPCo			I&M			Protected Cell
	Sabine			DHLC			DCC Fuel			of EIS
ASSETS
Current Assets		$	51		$	8		$	47		$	130
Net Property, Plant and Equipment			149			44			89			-
Other Noncurrent Assets			35			11			57			2
Total Assets		$	235		$	63		$	193		$	132
LIABILITIES AND EQUITY
Current Liabilities		$	36		$	17		$	39		$	36
Noncurrent Liabilities			199			38			154			74
Equity			-			8			-			22
Total Liabilities and Equity		$	235		$	63		$	193		$	132

Our investment in DHLC was:

	September 30, 2010
	As Reported on
	the Consolidated			Maximum
	Balance Sheet			Exposure
	(in millions)
Capital Contribution from SWEPCo		$	7		$	7
Retained Earnings			2			2
SWEPCo's Guarantee of Debt			-			42
Total Investment in DHLC		$	9		$	51

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

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

Our investment in PATH-WV was:

	September 30, 2010						December 31, 2009
	As Reported on						As Reported on
	the Consolidated			Maximum			the Consolidated			Maximum
	Balance Sheet			Exposure			Balance Sheet			Exposure
				(in millions)
Capital Contribution from AEP		$	16		$	16		$	13		$	13
Retained Earnings			6			6			3			3
Total Investment in PATH-WV		$	22		$	22		$	16		$	16

Earnings Per Share (EPS)

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
Amounts Attributable to AEP Common Shareholders	2010			2009			2010			2009
	(in millions)
Income Before Extraordinary Loss		$	555		$	443		$	1,035		$	1,124
Extraordinary Loss, Net of Tax			-			-			-			(5	)
Net Income		$	555		$	443		$	1,035		$	1,119

Basic earnings per common share is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period.  Diluted earnings per common share is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.

34

The following table presents our basic and diluted EPS calculations included on our Condensed Consolidated Statements of Income:

		Three Months Ended September 30,
		2010				2009
		(in millions, except per share data)
				$/share				$/share
Earnings Applicable to AEP Common Shareholders		$	555			$	443
Weighted Average Number of Basic Shares Outstanding			479.6	$	1.16		476.9	$	0.93
Weighted Average Dilutive Effect of:
	Performance Share Units		-		-		0.1		-
	Stock Options		0.1		-		-		-
	Restricted Stock Units		0.1		-		0.1		-
Weighted Average Number of Diluted Shares Outstanding			479.8	$	1.16		477.1	$	0.93

		Nine Months Ended September 30,
		2010				2009
		(in millions, except per share data)
				$/share				$/share
Earnings Applicable to AEP Common Shareholders		$	1,035			$	1,119
Weighted Average Number of Basic Shares Outstanding			479.0	$	2.16		452.3	$	2.47
Weighted Average Dilutive Effect of:
	Performance Share Units		0.1		-		0.2		-
	Stock Options		0.1		-		-		-
	Restricted Stock Units		0.1		-		-		-
Weighted Average Number of Diluted Shares Outstanding			479.3	$	2.16		452.5	$	2.47

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

Options to purchase 136,250 and 612,916 shares of common stock were outstanding at September 30, 2010 and 2009, respectively, but were not included in the computation of diluted earnings per share attributable to AEP common shareholders.  Since the options’ exercise prices were greater than the average market price of the common shares, the effect would have been antidilutive.

Supplementary Information
			Three Months Ended				Nine Months Ended
			September 30,				September 30,
Related Party Transactions			2010		2009		2010			2009
			(in millions)
AEP Consolidated Revenues – Utility Operations:
	Ohio Valley Electric Corporation (43.47% owned)		$	-	$	-	$	(20)	(a)	$	-
AEP Consolidated Revenues – Other Revenues:
	Ohio Valley Electric Corporation – Barging and Other
		Transportation Services (43.47% Owned)		6		7		22			22
AEP Consolidated Expenses – Purchased Energy for Resale:
	Ohio Valley Electric Corporation (43.47% Owned)			66		71		223	(b)		213

(a) In January 2010, the AEP Power Pool began purchasing power from OVEC to serve off-system sales through June 2010.

(b) In January 2010, the AEP Power Pool began purchasing power from OVEC to serve retail sales through June 2010.  The total amount reported includes $10 million related to this agreement.

35

Adjustments to Reported Cash Flows

In the Financing Activities section of our Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2009, we corrected the presentation of borrowings on our lines of credit of $90 million from Change in Short-term Debt, Net to Borrowings from Revolving Credit Facilities.  We also corrected the presentation of repayments on our lines of credit of $2.1 billion for the nine months ended September 30, 2009 to Repayments to Revolving Credit Facilities from Change in Short-term Debt, Net.  The correction to present borrowings and repayments on our lines of credit on a gross basis was not material to our financial statements and had no impact on our previously reported net income, changes in shareholders' equity, financial position or net cash flows from financing activities.

Adjustments to Securitized Accounts Receivable Disclosure

In the “Securitized Accounts Receivable – AEP Credit” section of Note 11, we expanded our disclosure to reflect certain prior period amounts related to our securitization agreement that were not previously disclosed.  These omissions were not material to our financial statements and had no impact on our previously reported net income, changes in shareholders’ equity, financial position or cash flows.

2.  NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM

NEW ACCOUNTING PRONOUNCEMENTS

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

Pronouncements Adopted During 2010

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

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

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

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

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

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

·   The power to direct the activities of the VIE that most significantly impact the VIE’s economic performance.

·   The obligation to absorb the losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

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

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

EXTRAORDINARY ITEM

SWEPCo Texas Restructuring

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

3.  RATE MATTERS

As discussed in the 2009 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within our 2009 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition.  The following discusses ratemaking developments in 2010 and updates the 2009 Annual Report.

Regulatory Assets Not Yet Being Recovered
			September 30,			December 31,
			2010			2009
			(in millions)
	Noncurrent Regulatory Assets (excluding fuel)
	Regulatory assets not yet being recovered pending future proceedings
		to determine the recovery method and timing:
	Regulatory Assets Currently Earning a Return
		Customer Choice Deferrals - CSPCo, OPCo	$	58		$	57
		Storm Related Costs - CSPCo, OPCo, TCC		52			49
		Line Extension Carrying Costs - CSPCo, OPCo		52			43
		Acquisition of Monongahela Power - CSPCo		7			10
	Regulatory Assets Currently Not Earning a Return
		Mountaineer Carbon Capture and Storage Project - APCo		59			111
		Environmental Rate Adjustment Clause - APCo		48			25
		Storm Related Costs - APCo, PSO, KGPCo		44			-
		Deferred Wind Power Costs - APCo		24			5
		Transmission Rate Adjustment Clause - APCo		21			26
		Special Rate Mechanism for Century Aluminum - APCo		13			12
		Acquisition of Monongahela Power - CSPCo		4			-
		Storm Related Costs - KPCo		-	(a)		24
		Peak Demand Reduction/Energy Efficiency - CSPCo, OPCo		-	(a)		8
	Total Regulatory Assets Not Yet Being Recovered		$	382		$	370
	(a)	Recovery of regulatory asset was granted during 2010.

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CSPCo and OPCo Rate Matters

Ohio Electric Security Plan Filings

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

The order provides a FAC for the three-year period of the ESP.  The FAC increase will be phased in to avoid having the resultant rate increases exceed the ordered annual caps described above.  The FAC increase is subject to quarterly true-ups, annual accounting audits and prudency reviews.  See the “2009 Fuel Adjustment Clause Audit” section below.  The order allows CSPCo and OPCo to defer any unrecovered FAC costs resulting from the annual caps and to accrue associated carrying charges at CSPCo’s and OPCo’s weighted average cost of capital.  Any deferred FAC regulatory asset balance at the end of the three-year ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018.  That recovery will include deferrals associated with the Ormet interim arrangement and is subject to the PUCO’s ultimate decision regarding the Ormet interim arrangement deferrals plus related carrying charges.  See the “Ormet Interim Arrangement” section below.  The FAC deferrals as of September 30, 2010 were $15 million and $433 million for CSPCo and OPCo, respectively, excluding $2 million and $24 million, respectively, of unrecognized equity carrying costs.

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

The Ohio Consumers’ Counsel filed a notice of appeal with the Supreme Court of Ohio raising several issues including alleged retroactive ratemaking, recovery of carrying charges on certain environmental investments, Provider of Last Resort (POLR) charges and the decision not to offset rates by off-system sales margins.  A decision from the Supreme Court of Ohio is pending.

In November 2009, the Industrial Energy Users-Ohio filed a notice of appeal with the Supreme Court of Ohio challenging components of the ESP order including the POLR charge, the distribution riders for gridSMARTSM and enhanced reliability, the PUCO’s conclusion and supporting evaluation that the modified ESPs are more favorable than the expected results of a market rate offer, the unbundling of the fuel and non-fuel generation rate components, the scope and design of the fuel adjustment clause and the approval of the plan after the 150-day statutory deadline.  A decision from the Supreme Court of Ohio is pending.

In April 2010, the Industrial Energy Users-Ohio filed an additional notice of appeal with the Supreme Court of Ohio challenging alleged retroactive ratemaking, CSPCo's and OPCo's abilities to collect through the FAC amounts deferred under the Ormet interim arrangement and the approval of the plan after the 150-day statutory deadline.  A decision from the Supreme Court of Ohio is pending.

In 2009, the PUCO convened a workshop to determine the methodology for the Significantly Excessive Earnings Test (SEET).  Ohio law requires that the PUCO determine, following the end of each year of the ESP, if rate adjustments included in the ESP resulted in significantly excessive earnings.  If the rate adjustments, in the aggregate, result in significantly excessive earnings, the excess amount could be returned to customers.    The PUCO heard arguments related to various SEET issues including the treatment of the FAC deferrals.  Management believes that CSPCo and OPCo should not be required to refund unrecovered FAC regulatory assets until they are collected, even assuming there are significantly excessive earnings in that year.  In June 2010, the PUCO issued an order resolving some of the SEET issues.  The PUCO determined that the earnings of CSPCo and OPCo shall be calculated on an individual company basis and not on a combined CSPCo/OPCo basis.  The PUCO ruled that many issues, including the treatment of deferrals and off-system sales, should be determined on a case-by-case basis.  The PUCO’s decision on the SEET methodology is not expected to be finalized until after the PUCO issues an order on the SEET filings.  In September 2010, CSPCo and OPCo filed their 2009 SEET filings with the PUCO.  CSPCo’s and OPCo’s returns on common equity were 20.84% and 10.81%, respectively, including off-system sales margins and 18.31% and 9.42%, respectively, excluding off-system sales margins.  Included in the filings was CSPCo’s and OPCo’s determination that the level at which their earned return on common equity may become significantly in excess of the average earned return on

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common equity of the comparable risk group of publicly traded firms was 22.51%.  Based upon the methodology proposed by CSPCo and OPCo in the SEET filings, neither CSPCo’s nor OPCo’s 2009 return on common equity was significantly excessive.  In October 2010, the PUCO staff filed testimony that recommended a return on common equity over 16.05% as significantly excessive but did not address whether adjustments for off-system sales (OSS) and deferrals should be made to reduce the return.  Also, in October 2010, intervenors, including the Ohio Consumers’ Counsel, filed testimony with the PUCO recommending an acceptable return on common equity in the range of 11.58% to 13.58%.  As a result, the intervenors recommended CSPCo refund up to $156 million of its 2009 earnings.  If the PUCO determines that CSPCo’s and/or OPCo’s 2009 return on common equity was significantly excessive, CSPCo and/or OPCo may be required to return a portion of their ESP revenues to customers.

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

Proposed CSPCo and OPCo Merger

In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo.  Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company.  The merger is also subject to regulatory approval by the FERC.  CSPCo and OPCo anticipate completion of the merger during 2011.

Requested Sporn Unit 5 Shutdown and Proposed Distribution Rider

In October 2010, OPCo filed an application with the PUCO for the approval of a December 2010 closure of Sporn Unit 5 and the simultaneous establishment of a new non-bypassable distribution rider, outside the rate caps established in the ESP proceeding.  The proposed rider would recover the net book value of the unit as well as related materials and supplies as of December 2010, which is estimated to be $59 million, as well as future closure costs incurred after December 2010.  OPCo also requested the PUCO to grant accounting authority to record the future closure costs as a regulatory asset or regulatory liability with a weighted average cost of capital carrying charge to be included in the proposed non-bypassable distribution rider after they are incurred.  Also in October 2010, OPCo filed a retirement notification with PJM pending PUCO approval of OPCo’s application to close Sporn Unit 5.  Absent PUCO approval, management intends to operate Sporn Unit 5 through 2013.  Management is unable to predict the outcome of this proceeding.

2009 Fuel Adjustment Clause Audit

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

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Ormet Interim Arrangement

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

Economic Development Rider

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

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

As of September 30, 2010, CSPCo and OPCo have incurred $39 million and $30 million, respectively, in EDR costs including carrying costs.  Of these costs, CSPCo and OPCo have collected $27 million and $20 million, respectively, through the EDR, which CSPCo and OPCo began collecting in January 2010.  The remaining $12 million and $10 million for CSPCo and OPCo, respectively, are recorded as EDR regulatory assets.  If CSPCo and OPCo are not ultimately permitted to recover their deferrals or are required to refund revenue collected, it would reduce future net income and cash flows and impact financial condition.

Environmental Investment Carrying Cost Rider

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

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Ohio IGCC Plant

In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant.  Through September 30, 2010, CSPCo and OPCo have each collected $12 million in pre-construction costs authorized in a June 2006 PUCO order and each incurred $11 million in pre-construction costs.  As a result, CSPCo and OPCo each established a net regulatory liability of approximately $1 million.  The order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant before June 2011, all pre-construction costs that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest.  Intervenors have filed motions with the PUCO requesting all pre-construction costs be refunded to Ohio ratepayers with interest.

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

SWEPCo Rate Matters

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in service in 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, plus an additional $132 million for transmission, excluding AFUDC.  SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $132 million for transmission, excluding AFUDC.  As of September 30, 2010, excluding costs attributable to its joint owners, SWEPCo has capitalized approximately $957 million of expenditures (including AFUDC and capitalized interest of $121 million and related transmission costs of $58 million).  As of September 30, 2010, the joint owners and SWEPCo have contractual construction commitments of approximately $339 million (including related transmission costs of $5 million).  SWEPCo’s share of the contractual construction commitments is $249 million.  If the plant is cancelled, the joint owners and SWEPCo would incur contractual construction cancellation fees, based on construction status as of September 30, 2010, of approximately $121million (including related transmission cancellation fees of $1 million).  SWEPCo’s share of the contractual construction cancellation fees would be approximately $89 million.

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

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

The PUCT issued an order approving a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers.  SWEPCo appealed the PUCT’s order contending the two cost cap restrictions are unlawful.  The Texas Industrial Energy Consumers filed an appeal

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contending that the PUCT’s grant of a conditional CCN for the Turk Plant was unnecessary to serve retail customers.  In February 2010, the Texas District Court affirmed the PUCT’s order in all respects.  In March 2010, SWEPCo and the Texas Industrial Energy Consumers appealed this decision to the Texas Court of Appeals.

The LPSC approved SWEPCo’s application to construct the Turk Plant.  The Sierra Club petitioned the LPSC to begin an investigation into the construction of the Turk Plant which was rejected by the LPSC.  The Sierra Club later refiled its petition as a stand alone complaint proceeding.  SWEPCo filed a motion to dismiss and denied the allegations in the complaint.  In October 2010, an Administrative Law Judge recommended the LPSC dismiss the complaint.

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

The wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009.  In February 2010, the Sierra Club, the Audubon Society and others filed a complaint in the Federal District Court for the Western District of Arkansas against the U.S. Army Corps of Engineers challenging the process used and the terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts.  In May 2010, plaintiffs filed with the Federal District Court for the Western District of Arkansas seeking a preliminary injunction to halt construction and for a temporary restraining order.  

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 the Interior and the U.S. Fish and Wildlife Service seeking a temporary restraining order and preliminary injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws.  The plaintiffs’ federal law claims challenge the process used and terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts.  The plaintiffs’ state law claims challenge SWEPCo's ability to construct the Turk Plant without obtaining a certificate from the APSC.  This motion for preliminary injunction was heard simultaneously with the motion filed by the Sierra Club.  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.

In January 2009, SWEPCo was granted CECPNs by the APSC to build three transmission lines and facilities authorized by the SPP and needed to transmit power from the Turk Plant.  Intervenors appealed the CECPN decisions in April 2009 to the Arkansas Court of Appeals.  In July 2010, the Hempstead County Hunting Club and other appellants filed with the Arkansas Court of Appeals emergency motions to stay the transmission CECPNs to prohibit SWEPCo from taking ownership of private property and undertaking construction of the transmission lines.  In July 2010, the Arkansas Court of Appeals issued a decision remanding all transmission line CECPN appeals to the APSC.  As a result, a stay was not ordered and construction continues on the affected transmission lines.  A hearing is scheduled for January 2011.

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

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Stall Unit

SWEPCo constructed the Stall Unit, an intermediate load 500 MW natural gas-fired combustion turbine combined cycle generating unit, at its existing Arsenal Hill Plant located in Shreveport, Louisiana.  The LPSC and the APSC issued orders capping SWEPCo’s Stall Unit construction costs at $445 million including AFUDC and excluding related transmission costs.  The Stall Unit was placed in service in June 2010.  As of September 30, 2010, the Stall Unit cost $423 million, including $49 million of AFUDC.  Management does not expect the final costs of the Stall Unit to exceed the ordered cap.  In July 2010, the Stall Unit was placed into Arkansas rates.  SWEPCo received CWIP treatment for a portion of the Stall Unit in the 2009 Texas Base Rate Filing.  See “2009 Texas Base Rate Filing” section below.  The Stall Unit will be phased into Louisiana rate base between October 2010 and October 2011.

2009 Texas Base Rate Filing

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

Texas Fuel Reconciliation

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

In September 2010, the Administrative Law Judges issued a Proposal for Decision (PFD) that recommended a disallowance of a significant portion of the charges to a ten-year gas transportation agreement that began in 2009 for the Mattison Plant located in Northwest Arkansas.  The PFD stated that SWEPCo should have pursued other transportation options or sought the supplier’s recourse rate from the FERC.  The estimated recommended disallowance over the ten-year period through December 2018 is $107 million for which the estimated Texas jurisdictional portion is $37 million.  In addition, the PFD also contained recommendations to disallow risk premiums related to the ERCOT trading contracts transferred to AEPEP which are estimated to be $1.5 million on a Texas retail jurisdictional basis.  Through September 30, 2010, SWEPCo’s management estimated the impact of this PFD, if adopted by the PUCT, to be $7 million.  In October 2010, SWEPCo filed exceptions on these issues with the PUCT.  An order may be issued in the fourth quarter of 2010.  Management is unable to predict the outcome of this reconciliation.  If the PUCT disallows any portion of SWEPCo’s fuel and purchase power costs, it could reduce future net income and cash flows and possibly impact financial condition.

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TCC and TNC Rate Matters

TEXAS RESTRUCTURING

Texas Restructuring Appeals

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

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

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

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

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

TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes

In 2006, the PUCT reduced recovery of the amount securitized by $103 million of tax benefits and associated carrying costs related to TCC’s generation assets.  In 2006, TCC obtained a private letter ruling from the IRS which confirmed that such reduction was an IRS normalization violation.  In order to avoid a normalization violation, the PUCT agreed to allow TCC to defer refunding the tax benefits of $103 million plus interest through the CTC refund period pending resolution of the normalization issue.  In 2008, the IRS issued final regulations, which supported the IRS’ private letter ruling which would make the refunding of or the reduction of the amount securitized by such tax benefits a normalization violation.  After the IRS issued its final regulations, at the request of the PUCT, the Texas Court of Appeals remanded the tax normalization issue to the PUCT for the consideration of additional evidence including the IRS regulations.  TCC is not accruing interest on the $103 million because it is not probable that the PUCT will order TCC to violate the normalization provision of the Internal Revenue Code.  If interest were accrued, management estimates interest expense would have been approximately $20 million higher for the period July 2008 through September 2010.

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Management believes that the PUCT will ultimately allow TCC to retain the deferred amounts, which would have a favorable effect on future net income and cash flows.  Although unexpected, if the PUCT fails to issue a favorable order and orders TCC to return the tax benefits to customers, the resulting normalization violation could result in TCC’s repayment to the IRS of Accumulated Deferred Investment Tax Credits (ADITC) on all property, including transmission and distribution property.  This amount approximates $101 million as of September 30, 2010.  It could also lead to a loss of TCC’s right to claim accelerated tax depreciation in future tax returns.  If TCC is required to repay its ADITC to the IRS and is also required to refund ADITC plus unaccrued interest to customers, it would reduce future net income and cash flows and impact financial condition.

TCC Excess Earnings

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

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

OTHER TEXAS RATE MATTERS

Texas Base Rate Appeal

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

ETT 2007 Formation Appeal

ETT is a joint venture between AEP Utilities, Inc. and MidAmerican Energy Holdings Company Texas Transco, LLC.  TCC and TNC have sold transmission assets both in service and under construction to ETT.  The PUCT approved ETT's initial rates, a request for a transfer of in-service assets and CWIP and a certificate of convenience and necessity (CCN) to operate as a stand alone transmission utility in ERCOT.  ETT was allowed a 9.96% return on common equity.  Intervenors appealed the PUCT’s decision.  In March 2010, the Texas Court of Appeals affirmed the PUCT's decision in all material respects.  Intervenors filed for rehearing at the Texas Court of Appeals which was denied in May 2010.  The deadline to appeal this decision to the Texas Supreme Court has expired.

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

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APCo and WPCo Rate Matters

2009 Virginia Base Rate Case

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

2010 West Virginia Base Rate Case

In May 2010, APCo and WPCo filed a request with the WVPSC to increase annual base rates by $156 million based on an 11.75% return on common equity to be effective March 2011.  Hearings are scheduled for December 2010.  A decision from the WVPSC is expected in March 2011.

Mountaineer Carbon Capture and Storage Project

APCo and ALSTOM Power, Inc., an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009.  APCo also constructed and owns the necessary facilities to store the CO2.  In October 2009, APCo started injecting CO2 into the underground storage facilities.  The injection of CO2 required the recording of an asset retirement obligation and an offsetting regulatory asset.  Through September 30, 2010, APCo has recorded a noncurrent regulatory asset of $59 million related to the Mountaineer Carbon Capture and Storage Project.

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

In APCo’s May 2010 West Virginia base rate filing, APCo requested recovery of and a return on its West Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion.  If APCo cannot recover its remaining investment 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.

APCo’s Filings for an IGCC Plant

APCo filed a petition with the WVPSC requesting approval of a Certificate of Public Convenience and Necessity (CPCN) to construct a 629 MW IGCC power plant in Mason County, West Virginia.  APCo also requested the Virginia SCC and the WVPSC to approve a surcharge rate mechanism to provide for the timely recovery of pre-construction costs and the ongoing financing costs of the project during the construction period, as well as the capital costs, operating costs and a return on common equity once the facility is placed into commercial operation.  The WVPSC granted APCo the CPCN and approved the requested cost recovery.  Various intervenors filed petitions with the WVPSC to reconsider the order.

In 2008, the Virginia SCC issued an order denying APCo’s request for a surcharge rate mechanism based upon its finding that the estimated cost of the plant was uncertain and may escalate.  The Virginia SCC also expressed concerns that the estimated costs did not include a retrofitting of carbon capture and sequestration facilities.  During 2009, based on an unfavorable order received in Virginia, the WVPSC removed the IGCC case as an active case from its docket and indicated that the conditional CPCN granted in 2008 must be reconsidered if and when APCo proceeds forward with the IGCC plant.

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Through September 30, 2010, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $9 million applicable to its Virginia jurisdiction.

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

APCo’s and WPCo’s 2009 Expanded Net Energy Charge (ENEC) Filing

In September 2009, the WVPSC issued an order approving APCo’s and WPCo’s March 2009 ENEC request.  The approved order provided for recovery of an under-recovered balance plus a projected increase in ENEC costs over a four-year phase-in period with an overall increase of $355 million and a first-year increase of $124 million, effective October 2009.  The WVPSC also approved a fixed annual carrying cost rate of 4%, effective October 2009, to be applied to the incremental deferred regulatory asset balance that will result from the phase-in plan and lowered annual coal cost projections by $27 million.  As of September 30, 2010, APCo’s ENEC under-recovery balance was $365 million, excluding $1 million of unrecognized equity carrying costs, which is included in noncurrent regulatory assets.

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

PSO Rate Matters

PSO Fuel and Purchased Power

2006 and Prior Fuel and Purchased Power

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

A reallocation of purchased power costs among AEP West companies for periods prior to 2002 resulted in an under-recovery of $42 million of PSO fuel costs.  PSO recovered the $42 million by offsetting it against an existing fuel over-recovery during the period June 2007 through May 2008.  The Oklahoma Industrial Energy Consumers (OIEC) has contended that PSO should not have collected the $42 million without specific OCC approval.  As such, the OIEC contends that the OCC should require PSO to refund the $42 million it collected through its fuel clause.  The OCC has heard the OIEC appeal and a decision is pending.  In March 2010, PSO filed motions to advance this proceeding since the FERC has ruled on the allocation of off-system sales margins and PSO has refunded the additional margins to its retail customers.  If the OCC were to order PSO to refund all or a part of the $42 million, it would reduce future net income and cash flows and impact financial condition.

2008 Fuel and Purchased Power

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

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2008 Oklahoma Base Rate Appeal

In January 2009, the OCC issued a final order approving an $81 million increase in PSO’s non-fuel base revenues based on a 10.5% return on common equity.  The new rates reflecting the final order were implemented with the first billing cycle of February 2009.  PSO and intervenors filed appeals with the Oklahoma Supreme Court raising various issues.  The Oklahoma Supreme Court assigned the case to the Court of Civil Appeals.  In June 2010, the Court of Civil Appeals affirmed the OCC's decision.  No parties sought rehearing or appeal and, as a result, this case has concluded.

2010 Oklahoma Base Rate Case

In July 2010, PSO filed a request with the OCC to increase annual base rates by $82 million, including $30 million that is currently being recovered through a rider.  The requested net annual increase to ratepayers would be $52 million.  The requested increase includes a $24 million increase in depreciation and an 11.5% return on common equity.  In October 2010, various parties, including the OCC staff, filed testimony regarding PSO’s requested base rate increase.  These parties proposed that PSO's request to increase depreciation rates be denied and that existing depreciation rates continue.  PSO’s request to move the $30 million currently recovered through a rider to base rates was not opposed.  The parties’ net annual rate recommendations ranged from a rate reduction of $18 million to an increase of less than $1 million based on a recommended return on common equity range from 9.5% to 10%.  A hearing is scheduled for December 2010.

I&M Rate Matters

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

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

As fully discussed in the “Cook Plant Unit 1 Fire and Shutdown” section of Note 4, Cook Unit 1 (Unit 1) was shut down in September 2008 due to significant turbine damage and a small fire on the electric generator.  Unit 1 was placed back into service in December 2009 at slightly reduced power.  The unit outage resulted in increased replacement power fuel costs.  The filing only requested the cost of replacement power through mid-December 2008, the date when I&M began receiving accidental outage insurance proceeds.  I&M committed to absorb the remaining costs of replacement power through the date the unit returned to service, which occurred in December 2009.

I&M reached an agreement with intervenors, which was approved by the IURC in March 2009, to collect its existing prior period under-recovery regulatory asset deferral balance over twelve months instead of over six months as initially proposed.  Under the agreement, the fuel factors were placed into effect, subject to refund, and a subdocket was established to consider issues relating to the Unit 1 shutdown including the treatment of the accidental outage insurance proceeds.  I&M maintains a separate accidental outage policy with NEIL.  In 2009, I&M recorded $185 million in revenue under the policy and reduced the cost of replacement power in customers’ bills by $78 million.  In October 2010, the Indiana/Michigan Industrial Group and the Indiana Office of Utility Consumer Counselor filed testimony which recommended I&M pay to customers a portion of the accidental outage insurance proceeds up to the extent not previously paid to customers through the fuel adjustment clause or needed to cover costs not covered by I&M’s property damage insurance policy.  Hearings are scheduled to be held in January 2011.

Management believes that I&M is entitled to retain the accidental outage insurance proceeds since it made customers whole regarding the replacement power costs.  If any fuel clause revenues or accidental outage insurance proceeds have to be paid to customers, it would reduce future net income and cash flows and impact financial condition.

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

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

Michigan Base Rate Filing

In January 2010, I&M filed with the MPSC a request for a $63 million increase in annual base rates based on an 11.75% return on common equity.  Starting with the August 2010 billing cycle, I&M, with the MPSC authorization, implemented a $44 million interim rate increase.  The interim increase excluded new trackers and regulatory assets for which I&M was not currently incurring expenses.  In October 2010, a settlement agreement was approved by the MPSC to increase annual base rates by $36 million based on a 10.35% return on common equity, effective December 2010, plus separate recovery of approximately $7 million of customer choice implementation costs over a two year period beginning April 2011.  In addition, the approved revenue requirement includes the amortization of $6 million in previously expensed restructuring costs over five years, which I&M will defer and begin amortizing in the fourth quarter of 2010.  Also, the approved settlement agreement provided for sharing of off-system sales margins between customers (75%) and I&M (25%) with customers receiving a credit in future Power Supply Cost Recovery proceedings for their jurisdictional share of any off-system sales margins.  In September 2010, I&M recorded a provision for refund of $2 million, including interest, related to the implementation of interim rates.

Kentucky Rate Matters

Kentucky Base Rate Filing

In December 2009, KPCo filed a base rate case with the KPSC to increase base revenues by $124 million annually based on an 11.75% return on common equity.  The base rate case also requested recovery of deferred storm restoration expenses over a three-year period.

A settlement agreement was filed with the KPSC to increase base revenue by $64 million annually based on a 10.5% return on common equity.  The settlement agreement included recovery of $23 million of deferred storm restoration expenses over five years.  In June 2010, the KPSC approved the settlement agreement as filed.  New rates became effective the first billing cycle of July 2010.

FERC Rate Matters

Regional Transmission Rate Proceedings at the FERC

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund

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

In 2006, a FERC Administrative Law Judge (ALJ) issued an initial decision finding that the rate design for the recovery of SECA charges was flawed and that a large portion of the “lost revenues” reflected in the SECA rates should not have been recoverable.  The ALJ found that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made.  The ALJ also found that any unpaid SECA rates must be paid in the recommended reduced amount.

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AEP filed briefs jointly with other affected companies noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision.  In May 2010, the FERC issued an order that generally supports AEP’s position and requires a compliance filing to be filed with the FERC by August 2010.  In June 2010, AEP and other affected companies filed a joint request for rehearing with the FERC regarding certain matters including a request to clarify the method for determining the amount of such revenues.  The request also asked the FERC to clarify that interest may be added to SECA charges originally billed to but never paid by Green Mountain Energy (reassigned to British Petroleum Energy).  Eight other groups also filed requests for rehearing with the FERC.

In August 2010, the affected companies, including the AEP East companies, filed a compliance filing with the FERC.  If the compliance filing is accepted, the AEP East companies would have to pay refunds of approximately $20 million including estimated interest of $5 million.  The AEP East companies could also potentially receive payments up to approximately $12 million including estimated interest of $3 million.  A decision is pending from the FERC.

The AEP East companies provided reserves for net refunds for SECA settlements applicable to the remaining $108 million of SECA revenues collected.  Based on the AEP East companies’ analysis of the May 2010 order and the compliance filing, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the May 2010 order or the compliance filing be made final.  Management cannot predict the ultimate outcome of this proceeding at the FERC which could impact future net income and cash flows.

Modification of the Transmission Agreement (TA)

APCo, CSPCo, I&M, KPCo and OPCo are parties to the TA that provides for a sharing of the cost of transmission lines operated at 138-kV and above and transmission stations containing extra-high voltage facilities.  In June 2009, AEPSC, on behalf of the parties to the TA, filed with the FERC a request to modify the TA.  Under the proposed amendments, KGPCo and WPCo will be added as parties to the TA.  In addition, the amendments would provide for the allocation of PJM transmission costs on the basis of the TA parties’ 12-month coincident peak and reimburse transmission revenues based on individual cost of service instead of the MLR method used in the present TA.  AEPSC requested the effective date to be the first day of the month following a final non-appealable FERC order.  The delayed effective date was approved by the FERC when the FERC accepted the new TA for filing.  In August 2010, a settlement agreement was filed with the FERC.  In October 2010, the FERC approved the new TA effective November 1, 2010.  The impacts of the settlement agreement will be phased-in for retail rate making purposes in certain jurisdictions over periods of up to four years.  However, management is unable to predict whether the parties to the TA will experience regulatory lag and its effect on future net income and cash flows.

PJM/MISO Market Flow Calculation Settlement Adjustments

During 2009, an analysis conducted by MISO and PJM discovered several instances of unaccounted for power flows on numerous coordinated flowgates.  These flows affected the settlement data for congestion revenues and expenses and date back to the start of the MISO market in 2005.  PJM has provided MISO an initial analysis of amounts they believe they owe MISO.  MISO disputes PJM’s methodology.

Settlement discussions between MISO and PJM have been unsuccessful, and as a result, in March 2010, MISO filed two related complaints against PJM at the FERC related to the above claim.  MISO seeks to recover a total of approximately $145 million from PJM.  If PJM is held liable for these damages, PJM members, including the AEP East companies, may be billed for a share of the refunds or payments PJM is directed to make to MISO.  AEP has intervened and filed a protest to one complaint.  Management believes that MISO's claims are without merit and that PJM's right to recover any MISO damages from AEP and other members is limited.  If the FERC orders a settlement above the AEP East companies’ reserve related to their estimated portion of PJM additional costs, it could reduce future net income and cash flows and impact financial condition.

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4.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

We are subject to certain claims and legal actions arising in our ordinary course of business.  In addition, our business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation against us cannot be predicted.  For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on our financial statements.  The Commitments, Guarantees and Contingencies note within our 2009 Annual Report should be read in conjunction with this report.

GUARANTEES

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

Letters Of Credit

We enter into standby letters of credit with third parties.  These letters of credit cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.  As the Parent, we issued all of these letters of credit in our ordinary course of business on behalf of our subsidiaries.  We have two $1.5 billion credit facilities, of which $750 million may be issued under one credit facility as letters of credit.  In June 2010, we terminated one of the $1.5 billion facilities that was scheduled to mature in March 2011 and replaced it with a new $1.5 billion credit facility which matures in 2013 and allows for the issuance of up to $600 million as letters of credit.  As of September 30, 2010, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $125 million with maturities ranging from November 2010 to November 2011.

In June 2010, we reduced the $627 million credit agreement to $478 million.  As of September 30, 2010, $477 million of letters of credit with maturities ranging from November 2010 to April 2011 were issued by subsidiaries under this credit agreement to support variable rate Pollution Control Bonds.

Guarantees Of Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of approximately $65 million.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), a consolidated variable interest entity.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study, we estimate the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  As of September 30, 2010, SWEPCo has collected approximately $47 million through a rider for final mine closure and reclamation costs, of which $1 million is recorded in Other Current Liabilities, $23 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $23 million is recorded in Asset Retirement Obligations on our Condensed Consolidated Balance Sheets.

Sabine charges SWEPCo, its only customer, all of its costs.  SWEPCo passes these costs to customers through its fuel clause.

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Indemnifications and Other Guarantees

Contracts

We enter into several types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, our exposure generally does not exceed the sale price.  The status of certain sale agreements is discussed in the 2009 Annual Report “Dispositions” section of Note 7.  These sale agreements include indemnifications with a maximum exposure related to the collective purchase price.  This maximum exposure of approximately $1 billion relates to the Bank of America (BOA) litigation (see “Enron Bankruptcy” section of this note), of which the probable payment/performance risk is $447 million and is recorded in Current Liabilities - Liability Related to Litigation on our Condensed Consolidated Balance Sheet as of September 30, 2010.  The remaining exposure is remote.  There are no material liabilities recorded for any indemnifications other than amounts recorded related to the BOA litigation.

Master Lease Agreements

We lease certain equipment under master lease agreements.  GE Capital Commercial Inc. (GE) notified us in November 2008 that they elected to terminate our Master Leasing Agreements in accordance with the termination rights specified within the contract.  In 2011, we will be required to purchase all equipment under the lease and pay GE an amount equal to the unamortized value of all equipment then leased.  We are currently in negotiations to replace this agreement.  In December 2008 and 2009, we signed new master lease agreements that include lease terms of up to 10 years.

For equipment under the GE master lease agreements that expire in 2011, the lessor is guaranteed receipt of up to 87% of the unamortized balance of the equipment at the end of the lease term.  If the fair value of the leased equipment is below the unamortized balance at the end of the lease term, we are committed to pay the difference between the fair value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance.  Under the new master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, we are committed to pay the difference between the actual fair value and the residual value guarantee.  At September 30, 2010, the maximum potential loss for these lease agreements was approximately $3 million assuming the fair value of the equipment is zero at the end of the lease term.  Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease is accounted for as an operating lease.  In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignment is accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $18 million for I&M and $20 million for SWEPCo for the remaining railcars as of September 30, 2010.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 84% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  I&M’s maximum potential loss related to the guarantee is approximately $12 million ($8 million, net of tax) and SWEPCo’s is approximately $13 million ($9 million, net of tax) assuming the fair value of the equipment is zero at the end of the current five-year lease term.  However, we believe that the fair value would produce a sufficient sales price to avoid any loss.

We have other railcar lease arrangements that do not utilize this type of financing structure.

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ENVIRONMENTAL CONTINGENCIES

Federal EPA Complaint and Notice of Violation

The Federal EPA, certain special interest groups and a number of states alleged that APCo, CSPCo, I&M and OPCo modified certain units at their coal-fired generating plants in violation of the NSR requirements of the CAA.  Cases with similar allegations against CSPCo, Dayton Power and Light Company and Duke Energy Ohio, Inc. were also filed related to their jointly-owned units.  The cases were settled with the exception of a case involving a jointly-owned Beckjord unit which had a liability trial.  Following the trial, the jury found no liability for claims made against the jointly-owned Beckjord unit.  Following a second liability trial in 2009, the jury again found no liability at the jointly-owned Beckjord unit.  The defendants and the plaintiffs appealed to the Seventh Circuit Court of Appeals.  In October 2010, the Seventh Circuit dismissed all of the remaining claims in these cases.  Beckjord is operated by Duke Energy Ohio, Inc.

SWEPCo Notice of Enforcement and Notice of Citizen Suit

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

The Federal EPA issued a Notice of Violation (NOV) based on alleged violations of a percent sulfur in fuel limitation and the heat input values listed in a previous state permit.  The NOV also alleges that a permit alteration issued by the Texas Commission on Environmental Quality in 2007 was improper.  In March 2008, SWEPCo met with the Federal EPA to discuss the alleged violations.  The Federal EPA did not object to the settlement of similar alleged violations in the federal citizen suit.  We are unable to predict the timing of any future action by the Federal EPA.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

Carbon Dioxide Public Nuisance Claims

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

In September 2009, the Second Circuit Court of Appeals issued a ruling on appeal remanding the cases to the Federal District Court for the Southern District of New York.  The Second Circuit held that the issues of climate change and global warming do not raise political questions and that Congress’ refusal to regulate CO2 emissions does not mean that plaintiffs must wait for an initial policy determination by Congress or the President’s administration to secure the relief sought in their complaints.  The court stated that Congress could enact comprehensive legislation to regulate CO2 emissions or that the Federal EPA could regulate CO2 emissions under existing CAA authorities and that either of these actions could override any decision made by the district court under federal common law.  The Second Circuit did not rule on whether the plaintiffs could proceed with their state common law nuisance claims.  The defendants’ petition for rehearing was denied.  We believe the actions are without merit and intend to continue to defend against the claims.  The defendants, excluding TVA, filed a petition for review with the U.S. Supreme Court in August 2010.  The Solicitor General filed a brief in support of the petition on behalf of TVA.  Responses to the petition are due in November 2010.

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In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina.  The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims.  The court granted petitions for rehearing.  An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place.  We were initially dismissed from this case without prejudice, but are named as a defendant in a pending fourth amended complaint.  Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision.  Responses to the petition are due in November 2010.

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

Alaskan Villages’ Claims

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies.  The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together.  The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance.  The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million.  In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim.  The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court.  The plaintiffs appealed the decision.  Briefing is complete and no date has been set for oral argument.  We believe the action is without merit and intend to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

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

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

In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm.  In May 2008, I&M started remediation work in accordance with a plan approved by MDEQ.  I&M recorded approximately $11 million of expense prior to January 1, 2010, $3 million of which I&M recorded in March 2009.  As the remediation work is completed, I&M’s cost may continue to increase as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ.  We cannot predict the amount of additional cost, if any.

Amos Plant – State and Federal Enforcement Proceedings

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

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

We are unable to determine a range of potential losses that are reasonably possible of occurring for either of these pending issues.

Defective Environmental Equipment

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

NUCLEAR CONTINGENCIES

I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission.  We have a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant.  The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037.  The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S.  Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

Cook Plant Unit 1 Fire and Shutdown

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

I&M maintains property insurance through NEIL with a $1 million deductible.  As of September 30, 2010, we recorded $53 million in Prepayments and Other Current Assets on our Condensed Consolidated Balance Sheets representing recoverable amounts under the property insurance policy.  Through September 30, 2010, I&M received partial payments of $203 million from NEIL for the cost incurred to date to repair the property damage.

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

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

OPERATIONAL CONTINGENCIES

Fort Wayne Lease

Since 1975, I&M has leased certain energy delivery assets from the City of Fort Wayne, Indiana under a long-term lease that expired on February 28, 2010.  I&M negotiated with Fort Wayne to purchase the assets at the end of the lease, but no agreement was reached prior to the end of the lease.  Fort Wayne issued a technical notice of default under the lease to I&M in August 2009.  I&M responded to Fort Wayne in October 2009 that it did not agree there was a default under the lease.  In October 2009, I&M filed for declaratory and injunctive relief in Indiana state court.  The parties agreed to submit this matter to mediation.  In February 2010, the court issued a stay to continue mediation.  I&M is expensing monthly payments made into an escrow account in lieu of rent.

I&M and Fort Wayne reached a tentative agreement as a result of the mediation process.  The agreement was signed on October 28, 2010 and is subject to approval by the Fort Wayne Common Council and the IURC.  I&M and Fort Wayne have agreed to cooperate in promptly seeking the requisite approvals.  If the agreement is approved, I&M will purchase the remaining leased property and settle claims Fort Wayne asserted.  The agreement provides that I&M will pay Fort Wayne a total of $39 million, inclusive of interest, over 15 years and Fort Wayne will recognize that I&M is the exclusive electricity supplier in the Fort Wayne area.   I&M will seek recovery in rates of the payments made to Fort Wayne.  If the agreement is not approved by the Fort Wayne Common Council and the IURC, the parties have the right to terminate the agreement and pursue other relief.

Enron Bankruptcy

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

In February 2004, Enron filed Notices of Rejection regarding the cushion gas exclusive right to use agreement and other incidental agreements.  We objected to Enron’s attempted rejection of these agreements and filed an adversary proceeding contesting Enron’s right to reject these agreements.

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In 2003, AEP filed a lawsuit against BOA in the United States District Court for the Southern District of Texas.  BOA led the lending syndicate involving the monetization of the cushion gas to Enron and its subsidiaries.  The lawsuit asserts that BOA made misrepresentations and engaged in fraud to induce and promote the stock sale of HPL, that BOA directly benefited from the sale of HPL and that AEP undertook the stock purchase and entered into the cushion gas arrangement with Enron and BOA based on misrepresentations that BOA made about Enron’s financial condition that BOA knew or should have known were false.  In 2005, the Judge entered an order severing and transferring the declaratory judgment claims involving the right to use and cushion gas consent agreements to the Southern District of New York and retaining in the Southern District of Texas the four counts alleging breach of contract, fraud and negligent misrepresentation.  Trial in federal court in Texas was continued pending a decision in the New York case.

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

The liability for the BOA litigation, including interest, was $447 million at September 30, 2010 and is included in Current Liabilities - Liability Related to Litigation on the Condensed Consolidated Balance Sheet.  $441 million related to this matter was included in Deferred Credits and Other Noncurrent Liabilities on our Condensed Consolidated Balance Sheet at December 31, 2009.  This decision will have no impact on consolidated net income for 2010.

Natural Gas Markets Lawsuits

In 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity.  AEP was dismissed from the case.  A number of similar cases were also filed in California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies.  AEP (or a subsidiary) is among the companies named as defendants in some of these cases.  These cases are at various pre-trial stages.  In 2008, we settled all of the cases pending against us in California.  The settlements did not impact 2008 earnings due to provisions made in prior periods.  We will continue to defend each remaining case where an AEP company is a defendant.  We believe the provision we have for the remaining cases is adequate.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

5.  ACQUISITION AND DISPOSITIONS

ACQUISITION

2010

Valley Electric Membership Corporation (Utility Operations segment)

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

2009

None

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DISPOSITIONS

2010

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

TCC and TNC sold $66 million and $73 million, respectively, of transmission facilities to ETT for the nine months ended September 30, 2010.  There were no gains or losses recorded on these transactions.

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

In April 2010, we sold our remaining 138,000 shares of ICE and recognized a $16 million gain ($10 million, net of tax).  We recorded the gain in Interest and Investment Income on our Condensed Consolidated Statements of Income for the nine months ended September 30, 2010.

2009

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

TCC and TNC sold $93 million and $1 million, respectively, of transmission facilities to ETT for the nine months ended September 30, 2009.  There were no gains or losses recorded on these transactions.

6.  BENEFIT PLANS

Components of Net Periodic Benefit Cost

The following tables provide the components of our net periodic benefit cost for the plans for the three and nine months ended September 30, 2010 and 2009:

									Other Postretirement
	Pension Plans								Benefit Plans
	Three Months Ended September 30,								Three Months Ended September 30,
	2010				2009				2010				2009
	(in millions)
Service Cost		$	28			$	26			$	12			$	11
Interest Cost			63				64				29				27
Expected Return on Plan Assets			(78	)			(80	)			(27	)			(21	)
Amortization of Transition Obligation			-				-				6				7
Amortization of Net Actuarial Loss			22				14				8				11
Net Periodic Benefit Cost		$	35			$	24			$	28			$	35

									Other Postretirement
	Pension Plans								Benefit Plans
	Nine Months Ended September 30,								Nine Months Ended September 30,
	2010				2009				2010				2009
	(in millions)
Service Cost		$	83			$	78			$	35			$	32
Interest Cost			190				191				85				82
Expected Return on Plan Assets			(234	)			(241	)			(79	)			(61	)
Amortization of Transition Obligation			-				-				20				20
Amortization of Net Actuarial Loss			67				44				22				32
Net Periodic Benefit Cost		$	106			$	72			$	83			$	105

We made a $350 million voluntary contribution to the qualified pension trust in September 2010.  This contribution is in addition to the $150 million contribution that we are making ratably throughout 2010.  We made no contributions in 2009.

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7.  BUSINESS SEGMENTS

As outlined in our 2009 Annual Report, our primary business is our electric utility operations.  Within our Utility Operations segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight.  While our Utility Operations segment remains our primary business segment, other segments include our AEP River Operations segment with significant barging activities and our Generation and Marketing segment, which includes our nonregulated generating, marketing and risk management activities primarily in the ERCOT market area.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

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

Utility Operations

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

·  Electricity transmission and distribution in the U.S.

AEP River Operations

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

Generation and Marketing

· Wind farms and marketing and risk management activities primarily in ERCOT.

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

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

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

    ·   Revenue sharing related to the Plaquemine Cogeneration Facility.

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The tables below present our reportable segment information for the three and nine months ended September 30, 2010 and 2009 and balance sheet information as of September 30, 2010 and December 31, 2009.  These amounts include certain estimates and allocations where necessary.

					Nonutility Operations
							Generation
		Utility			AEP River		and		All Other		Reconciling
		Operations			Operations		Marketing		(a)		Adjustments		Consolidated
		(in millions)
Three Months Ended September 30, 2010
Revenues from:
	External Customers	$	3,876		$	147	$	41	$	-	$	-	$	4,064
	Other Operating Segments		31			7		-		3		(41)		-
Total Revenues		$	3,907		$	154	$	41	$	3	$	(41)	$	4,064
Net Income		$	541		$	14	$	-	$	2	$	-	$	557
					Nonutility Operations
							Generation
		Utility			AEP River		and		All Other		Reconciling
		Operations			Operations		Marketing		(a)		Adjustments		Consolidated
		(in millions)
Three Months Ended September 30, 2009
Revenues from:
	External Customers	$	3,364	(d)	$	113	$	68	$	2	$	-	$	3,547
	Other Operating Segments		25	(d)		4		-		1		(30)		-
Total Revenues		$	3,389		$	117	$	68	$	3	$	(30)	$	3,547
Income (Loss) Before Extraordinary Loss		$	448		$	10	$	5	$	(17)	$	-	$	446
Extraordinary Loss, Net of Tax			-			-		-		-		-		-
Net Income (Loss)		$	448		$	10	$	5	$	(17)	$	-	$	446

					Nonutility Operations
							Generation
		Utility			AEP River		and		All Other		Reconciling
		Operations			Operations		Marketing		(a)		Adjustments		Consolidated
		(in millions)
Nine Months Ended September 30, 2010
Revenues from:
	External Customers	$	10,468		$	395	$	130	$	-	$	-	$	10,993
	Other Operating Segments		76			17		-		10		(103)		-
Total Revenues		$	10,544		$	412	$	130	$	10	$	(103)	$	10,993
Net Income (Loss)		$	1,017		$	16	$	17	$	(10)	$	-	$	1,040
					Nonutility Operations
							Generation
		Utility			AEP River		and		All Other		Reconciling
		Operations			Operations		Marketing		(a)		Adjustments		Consolidated
		(in millions)
Nine Months Ended September 30, 2009
Revenues from:
	External Customers	$	9,666	(d)	$	341	$	213	$	(13)	$	-	$	10,207
	Other Operating Segments		46	(d)		13		6		28		(93)		-
Total Revenues		$	9,712		$	354	$	219	$	15	$	(93)	$	10,207
Income (Loss) Before Extraordinary Loss		$	1,121		$	22	$	33	$	(45)	$	-	$	1,131
Extraordinary Loss, Net of Tax			(5)			-		-		-		-		(5)
Net Income (Loss)		$	1,116		$	22	$	33	$	(45)	$	-	$	1,126

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				Nonutility Operations
							Generation						Reconciling
	Utility			AEP River			and			All Other			Adjustments
	Operations			Operations			Marketing			(a)			(b)					Consolidated
	(in millions)
September 30, 2010
Total Property, Plant and Equipment		$	52,041		$	542		$	584		$	10		$	(250	)			$	52,927
Accumulated Depreciation and Amortization			17,667			105			191			9			(43	)				17,929
Total Property, Plant and Equipment - Net		$	34,374		$	437		$	393		$	1		$	(207	)			$	34,998
Total Assets		$	47,964		$	603		$	898		$	15,621		$	(15,194	)	(c)		$	49,892
				Nonutility Operations
							Generation						Reconciling
	Utility			AEP River			and			All Other			Adjustments
	Operations			Operations			Marketing			(a)			(b)					Consolidated
	(in millions)
December 31, 2009
Total Property, Plant and Equipment		$	50,905		$	436		$	571		$	10		$	(238	)			$	51,684
Accumulated Depreciation and Amortization			17,110			88			168			8			(34	)				17,340
Total Property, Plant and Equipment - Net		$	33,795		$	348		$	403		$	2		$	(204	)			$	34,344
Total Assets		$	46,930		$	495		$	779		$	15,094		$	(14,950	)	(c)		$	48,348

(a) All Other includes:

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

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

·   Revenue sharing related to the Plaquemine Cogeneration Facility.

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

(c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP's investments in subsidiary companies.

(d) PSO and SWEPCo transferred certain existing ERCOT energy marketing contracts to AEP Energy Partners, Inc. (AEPEP) (Generation and Marketing segment) and entered into intercompany financial and physical purchase and sales agreements with AEPEP.  As a result, we reported third-party net purchases or sales activity for these energy marketing contracts as Revenues from External Customers for the Utility Operations segment.  This was offset by the Utility Operations segment's related net sales (purchases) for these contracts with AEPEP in Revenues from Other Operating Segments of $(113) thousand and $(6) million for the three and nine months ended September 30, 2009, respectively.  The Generation and Marketing segment also reported these purchase or sales contracts with Utility Operations as Revenues from Other Operating Segments.  These affiliated contracts between PSO and SWEPCo with AEPEP ended in December 2009.

8.  DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

We are exposed to certain market risks as a major power producer and marketer of wholesale electricity, coal and emission allowances.  These risks include commodity price risk, interest rate risk, credit risk and to a lesser extent foreign currency exchange risk.  These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.  We manage these risks using derivative instruments.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Trading Strategies

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

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Risk Management Strategies

Our strategy surrounding the use of derivative instruments focuses on managing our risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. To accomplish our objectives, we primarily employ risk management contracts including physical forward purchase and sale contracts, financial forward purchase and sale contracts and financial swap instruments.  Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.”  Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

We enter into power, coal, natural gas, interest rate and to a lesser degree heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with our energy business.  We enter into interest rate derivative contracts in order to manage the interest rate exposure associated with our commodity portfolio.  For disclosure purposes, such risks are grouped as “Commodity,” as they are related to energy risk management activities.  We also engage in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies.  For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of AEP’s Board of Directors.

The following table represents the gross notional volume of our outstanding derivative contracts as of September 30, 2010 and December 31, 2009:

Notional Volume of Derivative Instruments
	Volume
		September 30,		December 31,		Unit of
		2010		2009		Measure
	(in millions)
Commodity:
Power			789		589	MWHs
Coal			71		60	Tons
Natural Gas			110		127	MMBtus
Heating Oil and Gasoline			7		6	Gallons
Interest Rate		$	180	$	216	USD
Interest Rate and Foreign Currency		$	664	$	83	USD

Fair Value Hedging Strategies

We enter into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt.  Certain interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our fixed-rate debt to a floating rate.  Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.

Cash Flow Hedging Strategies

We enter into and designate as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities.  We monitor the potential impacts of commodity price changes and, where appropriate, enter into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases.  We do not hedge all commodity price risk.

Our vehicle fleet and barge operations are exposed to gasoline and diesel fuel price volatility.  We enter into financial heating oil and gasoline derivative contracts in order to mitigate price risk of our future fuel purchases.  We do not hedge all fuel price risk.  For disclosure purposes, these contracts are included with other hedging activity as “Commodity.”

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

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

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS

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

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

According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral.  For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the September 30, 2010 and December 31, 2009 balance sheets, we netted $20 million and $12 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $228 million and $98 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.

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The following tables represent the gross fair value impact of our derivative activity on our Condensed Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009:

Fair Value of Derivative Instruments
September 30, 2010
	Risk Management
	Contracts			Hedging Contracts
								Interest Rate
								and Foreign				Other
Balance Sheet Location	Commodity (a)			Commodity (a)				Currency (a)(c)				(a) (b)				Total
	(in millions)
Current Risk Management Assets		$	1,229		$	16			$	4			$	(970	)		$	279
Long-term Risk Management Assets			835			10				3				(360	)			488
Total Assets			2,064			26				7				(1,330	)			767
Current Risk Management Liabilities			1,167			19				3				(1,065	)			124
Long-term Risk Management Liabilities			687			4				3				(527	)			167
Total Liabilities			1,854			23				6				(1,592	)			291
Total MTM Derivative Contract Net Assets    (Liabilities)		$	210		$	3			$	1			$	262			$	476
Fair Value of Derivative Instruments
December 31, 2009
	Risk Management
	Contracts			Hedging Contracts
								Interest Rate
								and Foreign				Other
Balance Sheet Location	Commodity (a)			Commodity (a)				Currency (a)				(a) (b)				Total
	(in millions)
Current Risk Management Assets		$	1,078		$	13			$	-			$	(831	)		$	260
Long-term Risk Management Assets			614			-				-				(271	)			343
Total Assets			1,692			13				-				(1,102	)			603
Current Risk Management Liabilities			997			17				3				(897	)			120
Long-term Risk Management Liabilities			442			-				2				(316	)			128
Total Liabilities			1,439			17				5				(1,213	)			248
Total MTM Derivative Contract Net Assets    (Liabilities)		$	253		$	(4	)		$	(5	)		$	111			$	355

(a) Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the Condensed Consolidated Balance Sheet on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."

(b) Amounts represent counterparty netting of risk management and hedging contracts, associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging" and dedesignated risk management contracts.

(c) At September 30, 2010, Risk Management Assets included $7 million related to fair value hedging strategies while the remainder related to cash flow hedging strategies.  At December 31, 2009, we only employed cash flow hedging strategies.

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The table below presents our activity of derivative risk management contracts for the three and nine months ended September 30, 2010 and 2009:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended September 30, 2010 and 2009
Location of Gain (Loss)	2010		2009
	(in millions)
Utility Operations Revenue	$	24	$	25
Other Revenue		(4)		1
Regulatory Assets (a)		(6)		(7)
Regulatory Liabilities (a)		7		24
Total Gain (Loss) on Risk Management Contracts	$	21	$	43
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Nine Months Ended September 30, 2010 and 2009
Location of Gain (Loss)	2010		2009
	(in millions)
Utility Operations Revenue	$	69	$	124
Other Revenue		5		19
Regulatory Assets (a)		(9)		(17)
Regulatory Liabilities (a)		34		33
Total Gain (Loss) on Risk Management Contracts	$	99	$	159

     (a)  Represents realized and unrealized gains and losses subject to regulatory accounting treatment

            recorded as either current or non-current on the balance sheet.

Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.”  Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the Condensed Consolidated Statements of Income on an accrual basis.

Our accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship.  Depending on the exposure, we designate a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in Revenues on a net basis on the Condensed Consolidated Statements of Income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in Revenues or Expenses on the Condensed Consolidated Statements of Income depending on the relevant facts and circumstances.  However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

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Accounting for Fair Value Hedging Strategies

For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change.

We record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on our Condensed Consolidated Statements of Income.  During the three and nine months ended September 30, 2010, we recognized gains of $3 million and $7 million, respectively, on our hedging instruments with offsetting losses of $3 million and $7 million, respectively, on our long-term debt.  During the three and nine months ended September 30, 2010, no hedge ineffectiveness was recognized.  During the three and nine months ended September 30, 2009, we did not employ any fair value hedging strategies.

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets until the period the hedged item affects Net Income.  We recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Realized gains and losses on derivative contracts for the purchase and sale of power, coal, natural gas, and heating oil and gasoline designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on our Condensed Consolidated Statements of Income, or in Regulatory Assets or Regulatory Liabilities on our Condensed Consolidated Balance Sheets, depending on the specific nature of the risk being hedged.  During the three and nine months ended September 30, 2010 and 2009, we designated commodity derivatives as cash flow hedges.

We reclassify gains and losses on financial fuel derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our Condensed Consolidated Statements of Income.  During the three and nine months ended September 30, 2010 and 2009, we designated heating oil and gasoline derivatives as cash flow hedges.

We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which hedged interest payments occur.  During the three and nine months ended September 30, 2010 and 2009, we designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets into Depreciation and Amortization expense on our Condensed Consolidated Statements of Income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.  During the three and nine months ended September 30, 2010 and 2009, we designated foreign currency derivatives as cash flow hedges.

During the three and nine months ended September 30, 2010 and 2009, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

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The following tables provide details on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2010 and 2009.  All amounts in the following table are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended September 30, 2010
					Interest Rate
					and Foreign
	Commodity				Currency				Total
	(in millions)
Balance in AOCI as of June 30, 2010		$	2			$	(15	)		$	(13	)
Changes in Fair Value Recognized in AOCI			(2	)			(1	)			(3	)
Amount of (Gain) or Loss Reclassified from AOCI
to Income Statement/within Balance Sheet:
Utility Operations Revenue			1				-				1
Other Revenue			(1	)			-				(1	)
Purchased Electricity for Resale			1				-				1
Interest Expense			-				1				1
Regulatory Assets (a)			1				-				1
Regulatory Liabilities (a)			-				-				-
Balance in AOCI as of September 30, 2010		$	2			$	(15	)		$	(13	)
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended September 30, 2009
					Interest Rate
					and Foreign
	Commodity				Currency				Total
	(in millions)
Balance in AOCI as of June 30, 2009		$	6			$	(11	)		$	(5	)
Changes in Fair Value Recognized in AOCI			(6	)			(4	)			(10	)
Amount of (Gain) or Loss Reclassified from AOCI
to Income Statement/within Balance Sheet:
Utility Operations Revenue			(7	)			-				(7	)
Other Revenue			(5	)			-				(5	)
Purchased Electricity for Resale			10				-				10
Interest Expense			-				1				1
Regulatory Assets (a)			2				-				2
Regulatory Liabilities (a)			(3	)			-				(3	)
Balance in AOCI as of September 30, 2009		$	(3	)		$	(14	)		$	(17	)

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Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Nine Months Ended September 30, 2010
					Interest Rate
					and Foreign
	Commodity				Currency				Total
	(in millions)
Balance in AOCI as of December 31, 2009		$	(2	)		$	(13	)		$	(15	)
Changes in Fair Value Recognized in AOCI			2				(5	)			(3	)
Amount of (Gain) or Loss Reclassified from AOCI
to Income Statement/within Balance Sheet:
Utility Operations Revenue			1				-				1
Other Revenue			(4	)			-				(4	)
Purchased Electricity for Resale			3				-				3
Interest Expense			-				3				3
Regulatory Assets (a)			2				-				2
Regulatory Liabilities (a)			-				-				-
Balance in AOCI as of September 30, 2010		$	2			$	(15	)		$	(13	)
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Nine Months Ended September 30, 2009
					Interest Rate
					and Foreign
	Commodity				Currency				Total
	(in millions)
Balance in AOCI as of December 31, 2008		$	7			$	(29	)		$	(22	)
Changes in Fair Value Recognized in AOCI			(9	)			11				2
Amount of (Gain) or Loss Reclassified from AOCI
to Income Statement/within Balance Sheet:
Utility Operations Revenue			(13	)			-				(13	)
Other Revenue			(11	)			-				(11	)
Purchased Electricity for Resale			24				-				24
Interest Expense			-				4				4
Regulatory Assets (a)			5				-				5
Regulatory Liabilities (a)			(6	)			-				(6	)
Balance in AOCI as of September 30, 2009		$	(3	)		$	(14	)		$	(17	)

    (a)  Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded

           as either current or non-current on the balance sheet.

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Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets at September 30, 2010 and December 31, 2009 were:

Impact of Cash Flow Hedges on our Condensed Consolidated Balance Sheet
September 30, 2010
				Interest Rate
				and Foreign
	Commodity			Currency			Total
	(in millions)
Hedging Assets (a)	$	16		$	-		$	16
Hedging Liabilities (a)		(13	)		(6	)		(19	)
AOCI Gain (Loss) Net of Tax		2			(15	)		(13	)
Portion Expected to be Reclassified to Net
Income During the Next Twelve Months		(1	)		(4	)		(5	)
Impact of Cash Flow Hedges on our Condensed Consolidated Balance Sheet
December 31, 2009
				Interest Rate
				and Foreign
	Commodity			Currency			Total
	(in millions)
Hedging Assets (a)	$	8		$	-		$	8
Hedging Liabilities (a)		(12	)		(5	)		(17	)
AOCI Gain (Loss) Net of Tax		(2	)		(13	)		(15	)
Portion Expected to be Reclassified to Net
Income During the Next Twelve Months		(2	)		(4	)		(6	)

(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on our Condensed Consolidated Balance Sheets.

The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.  As of September 30, 2010, the maximum length of time that we are hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) our exposure to variability in future cash flows related to forecasted transactions is 39 months.

Credit Risk

We limit credit risk in our wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.  We use Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

We use standardized master agreements which may include collateral requirements.  These master agreements facilitate the netting of cash flows associated with a single counterparty.  Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk.  The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds our established threshold.  The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with our credit policy.  In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.

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Collateral Triggering Events

Under a limited number of derivative and non-derivative counterparty contracts primarily related to our pre-2002 risk management activities and under the tariffs of the RTOs and Independent System Operators (ISOs), we are obligated to post an amount of collateral if our credit ratings decline below investment grade.  The amount of collateral required fluctuates based on market prices and our total exposure.  On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts.  We do not anticipate a downgrade below investment grade.  The following table represents our aggregate fair value of such derivative contracts, the amount of collateral we would have been required to post for all derivative and non-derivative contracts if our credit ratings had declined below investment grade and how much was attributable to RTO and ISO activities as of September 30, 2010 and December 31, 2009:

	September 30,			December 31,
	2010			2009
	(in millions)
Liabilities for Derivative Contracts with Credit Downgrade Triggers		$	23		$	10
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post			55			34
Amount Attributable to RTO and ISO Activities			54			29

In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable.  These cross-default provisions could be triggered if there was a non-performance event under outstanding debt in excess of $50 million.  On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts.  We do not anticipate a non-performance event under these provisions.  The following table represents the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, the amount this exposure has been reduced by cash collateral we have posted and if a cross-default provision would have been triggered, the settlement amount that would be required after considering our contractual netting arrangements as of September 30, 2010 and December 31, 2009:

	September 30,			December 31,
	2010			2009
	(in millions)
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		$	568		$	567
Amount of Cash Collateral Posted			146			15
Additional Settlement Liability if Cross Default Provision is Triggered			241			199

9.  FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

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For our commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1.  We verify our price curves using these broker quotes and classify these fair values within Level 2 when substantially all of the fair value can be corroborated.  We typically obtain multiple broker quotes, which are non-binding in nature, but are based on recent trades in the marketplace.  When multiple broker quotes are obtained, we average the quoted bid and ask prices.  In certain circumstances, we may discard a broker quote if it is a clear outlier.  We use a historical correlation analysis between the broker quoted location and the illiquid locations and if the points are highly correlated we include these locations within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Long-dated and illiquid complex or structured transactions and FTRs can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.

We utilize our trustee’s external pricing service in our estimate of the fair value of the underlying investments held in the nuclear trusts.  Our investment managers review and validate the prices utilized by the trustee to determine fair value.  We perform our own valuation testing to verify the fair values of the securities.  We receive audit reports of our trustee’s operating controls and valuation processes.  The trustee uses multiple pricing vendors for the assets held in the trusts.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Fixed income securities do not trade on an exchange and do not have an official closing price.  Pricing vendors calculate bond valuations using financial models and matrices.  Fixed income securities are typically classified as Level 2 holdings because their valuation inputs are based on observable market data.  Observable inputs used for valuing fixed income securities are benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, bids, offers, reference data and economic events.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.

Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equities.  They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.

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

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

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Fair Value Measurements of Long-term Debt

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

The book values and fair values of Long-term Debt as of September 30, 2010 and December 31, 2009 are summarized in the following table:

	September 30, 2010				December 31, 2009
	Book Value		Fair Value		Book Value		Fair Value
	(in millions)
Long-term Debt	$	17,281	$	19,641	$	17,498	$	18,479

Fair Value Measurements of Other Temporary Investments

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

The following is a summary of Other Temporary Investments:

			September 30, 2010
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
Other Temporary Investments			Cost		Gains		Losses		Value
			(in millions)
Restricted Cash (a)			$	160	$	-	$	-	$	160
Fixed Income Securities:
	Mutual Funds			69		1		-		70
	Variable Rate Demand Notes			73		-		-		73
Equity Securities - Mutual Funds				18		5		-		23
Total Other Temporary Investments			$	320	$	6	$	-	$	326
			December 31, 2009
					Gross		Gross		Estimated
					Unrealized		Unrealized		Fair
Other Temporary Investments			Cost		Gains		Losses		Value
			(in millions)
Restricted Cash (a)			$	223	$	-	$	-	$	223
Fixed Income Securities:
	Mutual Funds			57		-		-		57
	Variable Rate Demand Notes			45		-		-		45
Equity Securities:
	Domestic			1		15		-		16
	Mutual Funds			18		4		-		22
Total Other Temporary Investments			$	344	$	19	$	-	$	363
(a)		Primarily represents amounts held for the repayment of debt.

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The following table provides the activity for our debt and equity securities within Other Temporary Investments for the three and nine months ended September 30, 2010 and 2009:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(in millions)
Proceeds From Investment Sales		$	133		$	-		$	390		$	-
Purchases of Investments			192			1			413			2
Gross Realized Gains on Investment Sales			-			-			16			-
Gross Realized Losses on Investment Sales			-			-			-			-

In June 2009, we recorded $9 million ($6 million, net of tax) of other-than-temporary impairments of Other Temporary Investments for equity investments of our protected cell captive insurance company.  At September 30, 2010, the fair value of fixed income securities are primarily debt based mutual funds with short and intermediate maturities and variable rate demand notes.  Mutual funds may be sold and do not contain maturity dates for an individual investment holder.

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

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

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

·   Maximum percentage invested in a specific type of investment.

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

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

·   Target asset allocation is 50% fixed income and 50% equity securities.

We maintain trust records for each regulatory jurisdiction.  These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities.  The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value.  I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose.  The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether the investor has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs.  The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment, among other things, is based on whether the investor has the ability and intent to hold the investment to recover its value.  Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the equity and debt investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  The gains, losses or other-than-temporary impairments shown below did not affect earnings or AOCI.  The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities.  Regulatory approval is required to withdraw decommissioning funds.

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The following is a summary of nuclear trust fund investments at September 30, 2010 and December 31, 2009:

		September 30, 2010						December 31, 2009
		Estimated		Gross		Other-Than-		Estimated		Gross		Other-Than-
		Fair		Unrealized		Temporary		Fair		Unrealized		Temporary
		Value		Gains		Impairments		Value		Gains		Impairments
		(in millions)
Cash and Cash Equivalents		$	30	$	-	$	-	$	14	$	-	$	-
Fixed Income Securities:
	United States Government		489		41		(1)		401		13		(4)
	Corporate Debt		65		5		(2)		57		5		(2)
	State and Local Government		308		(7)		-		369		8		1
	Subtotal Fixed Income Securities		862		39		(3)		827		26		(5)
Equity Securities - Domestic			574		124		(123)		551		234		(119)
Spent Nuclear Fuel and
	Decommissioning Trusts	$	1,466	$	163	$	(126)	$	1,392	$	260	$	(124)

The following table provides the securities activity within the decommissioning and SNF trusts 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)
Proceeds From Investment Sales	$	495	$	113	$	1,087	$	524
Purchases of Investments		512		129		1,129		571
Gross Realized Gains on Investment Sales		1		1		7		10
Gross Realized Losses on Investment Sales		-		-		-		1

The adjusted cost of debt securities was $823 million and $801 million as of September 30, 2010 and December 31, 2009, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at September 30, 2010 was as follows:

	Fair Value
	of Debt
	Securities
	(in millions)
Within 1 year		$	13
1 year – 5 years			346
5 years – 10 years			267
After 10 years			236
Total		$	862

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Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2010 and December 31, 2009.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in AEP’s valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2010
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Cash and Cash Equivalents (a)	$	922	$	-	$	-	$	168		$	1,090
Other Temporary Investments
Restricted Cash (a)		122		-		-		38			160
Fixed Income Securities:
Mutual Funds		70		-		-		-			70
Variable Rate Demand Notes		-		73		-		-			73
Equity Securities - Mutual Funds (b)		23		-		-		-			23
Total Other Temporary Investments		215		73		-		38			326
Risk Management Assets
Risk Management Commodity Contracts (c) (f)		30		1,876		149		(1,365	)		690
Cash Flow Hedges:
Commodity Hedges (c)		14		12		-		(10	)		16
Fair Value Hedges		-		7		-		-			7
Dedesignated Risk Management Contracts (d)		-		-		-		54			54
Total Risk Management Assets		44		1,895		149		(1,321	)		767
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)		-		21		-		9			30
Fixed Income Securities:
United States Government		-		489		-		-			489
Corporate Debt		-		65		-		-			65
State and Local Government		-		308		-		-			308
Subtotal Fixed Income Securities		-		862		-		-			862
Equity Securities - Domestic (b)		574		-		-		-			574
Total Spent Nuclear Fuel and Decommissioning Trusts		574		883		-		9			1,466
Total Assets	$	1,755	$	2,851	$	149	$	(1,106	)	$	3,649
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (f)	$	34	$	1,773	$	38	$	(1,573	)	$	272
Cash Flow Hedges:
Commodity Hedges (c)		3		20		-		(10	)		13
Interest Rate/Foreign Currency Hedges		-		6		-		-			6
Total Risk Management Liabilities	$	37	$	1,799	$	38	$	(1,583	)	$	291

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Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2009
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Cash and Cash Equivalents (a)	$	427	$	-	$	-	$	63		$	490
Other Temporary Investments
Restricted Cash (a)		198		-		-		25			223
Fixed Income Securities:
Mutual Funds		57		-		-		-			57
Variable Rate Demand Notes		-		45		-		-			45
Equity Securities (b):
Domestic		16		-		-		-			16
Mutual Funds		22		-		-		-			22
Total Other Temporary Investments		293		45		-		25			363
Risk Management Assets
Risk Management Commodity Contracts (c) (g)		8		1,609		72		(1,119	)		570
Cash Flow Hedges:
Commodity Hedges (c)		1		11		-		(4	)		8
Dedesignated Risk Management Contracts (d)		-		-		-		25			25
Total Risk Management Assets		9		1,620		72		(1,098	)		603
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)		-		3		-		11			14
Fixed Income Securities:
United States Government		-		401		-		-			401
Corporate Debt		-		57		-		-			57
State and Local Government		-		369		-		-			369
Subtotal Fixed Income Securities		-		827		-		-			827
Equity Securities - Domestic (b)		551		-		-		-			551
Total Spent Nuclear Fuel and Decommissioning Trusts		551		830		-		11			1,392
Total Assets	$	1,280	$	2,495	$	72	$	(999	)	$	2,848
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	11	$	1,415	$	10	$	(1,205	)	$	231
Cash Flow Hedges:
Commodity Hedges (c)		-		16		-		(4	)		12
Interest Rate/Foreign Currency Hedges		-		5		-		-			5
Total Risk Management Liabilities	$	11	$	1,436	$	10	$	(1,209	)	$	248

(a) Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties.  Level 1 amounts primarily represent investments in money market funds.

(b) Amounts represent publicly traded equity securities and equity-based mutual funds.

(c) Amounts in ''Other'' column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for ''Derivatives and Hedging.''

(d) Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for ''Derivatives and Hedging.''  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This MTM value will be amortized into revenues over the remaining life of the contracts.

(e) Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions.  Level 2 amounts primarily represent investments in money market funds.

(f) The September 30, 2010 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures $0 million in 2010, $0 million in periods 2011-2013 and ($4) million in periods 2014-2018;  Level 2 matures $17 million in 2010, $58 million in periods 2011-2013, $9 million in periods 2014-2015 and $19 million in periods 2016-2028;  Level 3 matures $6 million in 2010, $44 million in periods 2011-2013, $26 million in periods 2014-2015 and $35 million in periods 2016-2028.  Risk management commodity contracts are substantially comprised of power contracts.

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(g) The December 31, 2009 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows:  Level 1 matures ($1) million in 2010, ($1) million in periods 2011-2013 and ($1) million in periods 2014-2015;  Level 2 matures $65 million in 2010, $84 million in periods 2011-2013, $22 million in periods 2014-2015 and $23 million in periods 2016-2028;  Level 3 matures $17 million in 2010, $16 million in periods 2011-2013, $8 million in periods 2014-2015 and $21 million in periods 2016-2028.

There have been no transfers between Level 1 and Level 2 during the nine months ended September 30, 2010.

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

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

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

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	Net Risk
	Management
	Assets
Three Months Ended September 30, 2009	(Liabilities)
	(in millions)
Balance as of June 30, 2009		$	67
Realized (Gain) Loss Included in Net Income (or Changes in Net Assets) (a)			(8	)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
Relating to Assets Still Held at the Reporting Date (a)			10
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income			-
Purchases, Issuances and Settlements			-
Transfers in and/or out of Level 3 (f)			7
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			28
Balance as of September 30, 2009		$	104

	Net Risk
	Management
	Assets
Nine Months Ended September 30, 2009	(Liabilities)
	(in millions)
Balance as of December 31, 2008		$	49
Realized (Gain) Loss Included in Net Income (or Changes in Net Assets) (a)			(21	)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
Relating to Assets Still Held at the Reporting Date (a)			51
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income			-
Purchases, Issuances and Settlements			-
Transfers in and/or out of Level 3 (f)			(26	)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)			51
Balance as of September 30, 2009		$	104

(a) Included in revenues on our Condensed Consolidated Statements of Income.

(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.

(c) Represents the settlement of risk management commodity contracts for the reporting period.

(d) Represents existing assets or liabilities that were previously categorized as Level 2.

(e) Represents existing assets or liabilities that were previously categorized as Level 3.

(f) Represents existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period.

(g) Relates to the net gains (losses) of those contracts that are not reflected on our Condensed Consolidated Statements of Income.  These net gains (losses) are recorded as regulatory liabilities/assets.

(h) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

10.  INCOME TAXES

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

We are no longer subject to U.S. federal examination for years before 2001.  We have completed the exam for the years 2001 through 2006 and have issues that we are pursuing at the appeals level.  The years 2007 and 2008 are currently under examination.  Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for income taxes have been made for potential liabilities resulting from such matters.  In addition, we accrue interest on these uncertain tax positions.  We are not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on net income.

78

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

Federal Legislation

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

The Small Business Jobs Act was enacted in September 2010.  Included in this act was a one-year extension of the 50% bonus depreciation provision.  The enacted provision will not have a material impact on our net income or financial condition but will have a material favorable impact on cash flows.

11.  FINANCING ACTIVITIES

Long-term Debt
Type of Debt	September 30, 2010			December 31, 2009
	(in millions)
Senior Unsecured Notes	$	12,176		$	12,416
Pollution Control Bonds		2,263			2,159
Notes Payable		368			326
Securitization Bonds		1,847			1,995
Junior Subordinated Debentures		315			315
Spent Nuclear Fuel Obligation (a)		265			265
Other Long-term Debt		90			88
Unamortized Discount (net)		(43	)		(66	)
Total Long-term Debt Outstanding		17,281			17,498
Less Portion Due Within One Year		1,286			1,741
Long-term Portion	$	15,995		$	15,757

(a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M (a nuclear licensee) has an obligation to the United States Department of Energy for spent nuclear fuel disposal.  The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983.  Trust fund assets related to this obligation of $307 million and $306 million at September 30, 2010 and December 31, 2009, respectively, are included in Spent Nuclear Fuel and Decommissioning Trusts on our Condensed Consolidated Balance Sheets.

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Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2010 are shown in the tables below.

				Principal			Interest
Company		Type of Debt		Amount			Rate	Due Date
			(in millions)				(%)
Issuances:
APCo		Senior Unsecured Notes		$	300		3.40	2015
APCo		Pollution Control Bonds			18		4.625	2021
APCo		Pollution Control Bonds			50		5.375	2038
CSPCo		Floating Rate Notes			150		Variable	2012
I&M		Notes Payable			84		4.00	2014
OPCo		Pollution Control Bonds			86		3.125	2015
OPCo		Pollution Control Bonds			79		3.25	2014
OPCo		Pollution Control Bonds			39		2.875	2014
SWEPCo		Senior Unsecured Notes			350		6.20	2040
SWEPCo		Pollution Control Bonds			54		3.25	2015
PSO		Notes Payable			2		3.00	2025
Total Issuances				$	1,212	(a)
The above borrowing arrangements do not contain guarantees, collateral or dividend restrictions.
(a)	Amount indicated on the statement of cash flows of $1,201 million is net of issuance costs and premium or discount.

				Principal		Interest
Company		Type of Debt		Amount Paid		Rate	Due Date
			(in millions)			(%)
Retirements and
	Principal Payments:
AEP		Senior Unsecured Notes		$	490	5.375	2010
APCo		Senior Unsecured Notes			150	4.40	2010
APCo		Pollution Control Bonds			50	7.125	2010
I&M		Notes Payable			19	5.44	2013
OPCo		Senior Unsecured Notes			400	Variable	2010
OPCo		Pollution Control Bonds			79	7.125	2010
OPCo		Pollution Control Bonds			20	5.625	2022
OPCo		Pollution Control Bonds			20	5.625	2023
SWEPCo		Pollution Control Bonds			54	Variable	2019
Non-Registrant:
AEP Subsidiaries		Notes Payable			12	Variable	2017
AEP Subsidiaries		Notes Payable			5	Variable	2011
AEP Subsidiaries		Notes Payable			1	8.03	2026
AEGCo		Senior Unsecured Notes			7	6.33	2037
TCC		Securitization Bonds			32	5.56	2010
TCC		Securitization Bonds			54	4.98	2010
TCC		Securitization Bonds			24	5.96	2013
TCC		Securitization Bonds			37	4.98	2013
Total Retirements and
	Principal Payments			$	1,454

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

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

As of September 30, 2010, trustees held, on our behalf, $303 million of our reacquired auction-rate tax-exempt long-term debt.

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Dividend Restrictions

Parent Restrictions

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

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

We have issued $315 million of Junior Subordinated Debentures.  The debentures will mature on March 1, 2063, subject to extensions to no later than March 1, 2068.  We have the option to defer interest payments on the debentures for one or more periods of up to 10 consecutive years per period.  During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire our common stock.  We do not anticipate any deferral of those interest payments in the foreseeable future.

Utility Subsidiaries’ Restrictions

Various financing arrangements, charter provisions and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.  Specifically, most of our public utility subsidiaries have revolving credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%.  At December 31, 2009, the amount of restricted net assets of AEP’s subsidiaries that may not be distributed to Parent in the form of a loan, advance or dividend was approximately $7 billion.

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

Short-term Debt
Our outstanding short-term debt was as follows:
		September 30, 2010				December 31, 2009
		Outstanding		Interest		Outstanding		Interest
	Type of Debt	Amount		Rate (a)		Amount		Rate (a)
		(in millions)				(in millions)
	Securitized Debt for Receivables (b)	$	750	0.36	%	$	-	-	%
	Commercial Paper		713	0.46	%		119	0.26	%
	Line of Credit – Sabine Mining Company (c)		3	2.20	%		7	2.06	%
	Total Short-term Debt	$	1,466			$	126

(a) Weighted average rate.

(b) Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance.  See ''ASU 2009-16 'Transfers and Servicing' '' section of Note 2.

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

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Credit Facilities

We have credit facilities totaling $3 billion to support our commercial paper program.  The facilities are structured as two $1.5 billion credit facilities, of which $750 million may be issued under one credit facility as letters of credit.   In June 2010, we terminated one of the $1.5 billion facilities that was scheduled to mature in March 2011 and replaced it with a new $1.5 billion credit facility which matures in 2013 and allows for the issuance of up to $600 million as letters of credit.  As of September 30, 2010, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $125 million.

In June 2010, we reduced the $627 million credit agreement to $478 million.  Under the facility, we may issue letters of credit.  As of September 30, 2010, $477 million of letters of credit were issued by subsidiaries under this credit agreement to support variable rate Pollution Control Bonds.

Securitized Accounts Receivable – AEP Credit

AEP Credit has a receivables securitization agreement with bank conduits.  Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries.  Prior to January 1, 2010, this transaction constituted a sale of receivables in accordance with the accounting guidance for “Transfers and Servicing,” allowing the receivables to be removed from our Condensed Consolidated Balance Sheet.  See “ASU 2009-16 ‘Transfers and Servicing’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010 whereby such future transactions do not constitute a sale of receivables and will be accounted for as financings.  AEP Credit continues to service the receivables.  These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase our operating companies’ receivables and accelerate AEP Credit’s cash collections.

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

Accounts receivable information for AEP Credit is as follows:

		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2010			2009			2010			2009
		(dollars in millions)
Proceeds from Sale of Accounts Receivable		$	N/A		$	1,814		$	N/A		$	5,314
Loss on Sale of Accounts Receivable			N/A			-			N/A			2
Average Variable Discount Rate on Sale of
	Accounts Receivable		N/A			0.38	%		N/A			0.68	%
Effective Interest Rates on Securitization of
	Accounts Receivable		0.41	%		N/A			0.32	%		N/A
Net Uncollectible Accounts Receivable
	Written Off		9			9			16			23

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	September 30,		December 31,
	2010		2009
	(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts	$	1,002	$	160
Deferred Revenue from Servicing Accounts Receivable		N/A		1
Retained Interest if 10% Adverse Change in Uncollectible Accounts		N/A		158
Retained Interest if 20% Adverse Change in Uncollectible Accounts		N/A		156
Total Principal Outstanding		750		656
Derecognized Accounts Receivable		N/A		631
Delinquent Securitized Accounts Receivable		49		29
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable		27		20
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable		301		376
N/A = Not Applicable

Customer accounts receivable retained and securitized for our operating companies are managed by AEP Credit.  AEP Credit’s delinquent customer accounts receivable represents accounts greater than 30 days past due.

12.  COST REDUCTION INITIATIVES

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

We recorded a charge to expense in the second quarter of 2010 primarily related to the headcount reduction initiatives.

	Total
	(in millions)
Incurred	$	293
Settled		265
Adjustments		(3	)
Remaining Balance at September 30, 2010	$	25

These costs relate primarily to severance benefits.  They are included primarily in Other Operation on the income statement and Other Current Liabilities on the balance sheet.  Approximately 99% of the expense was within the Utility Operations segment.

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APPALACHIAN POWER COMPANY

AND SUBSIDIARIES

84

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Third Quarter of 2010 Compared to Third Quarter of 2009
Reconciliation of Third Quarter of 2009 to Third Quarter of 2010
Net Income
(in millions)
Third Quarter of 2009	$	27
Changes in Gross Margin:
Retail Margins		44
Off-system Sales		3
Other Revenues		(1	)
Total Change in Gross Margin		46
Total Expenses and Other:
Other Operation and Maintenance		(9	)
Depreciation and Amortization		(7	)
Taxes Other Than Income Taxes		(2	)
Carrying Costs Income		1
Other Income		(2	)
Total Expenses and Other		(19	)
Income Tax Expense		(4	)
Third Quarter of 2010	$	50

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 $44 million primarily due to the following:
	·	A $31 million increase in rate relief primarily due to an 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.  This increase in retail margins had corresponding increases of $15 million related to riders/trackers recognized in other expense items discussed below.
	·	A $16 million increase in residential usage primarily due to a 47% increase in cooling degree days.
	These increases were partially offset by:
	·	A $5 million decrease in industrial sales primarily due to the decreased load for APCo’s largest customer, Century Aluminum.

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

· Other Operation and Maintenance expenses increased $9 million primarily due to the reduction of under-recovery of transmission costs resulting from the implementation of the Transmission Rate Adjustment Clause in Virginia in December 2009.

· Depreciation and Amortization expenses increased $7 million primarily due to a greater depreciation base resulting from environmental upgrades at the Amos Plant and the amortization of carrying charges which are being collected through the Virginia E&R surcharges.

· Income Tax Expense increased $4 million primarily due to an increase in pretax book income, partially  offset by the regulatory accounting treatment of state income taxes and other book/tax differences which are accounted for on a flow-through basis.

85

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
Net Income
(in millions)
Nine Months Ended September 30, 2009	$	131
Changes in Gross Margin:
Retail Margins		100
Off-system Sales		5
Other Revenues		(3)
Total Change in Gross Margin		102
Total Expenses and Other:
Other Operation and Maintenance		(113)
Depreciation and Amortization		(23)
Taxes Other Than Income Taxes		(10)
Carrying Costs Income		7
Other Income		(4)
Interest Expense		(3)
Total Expenses and Other		(146)
Income Tax Expense		14
Nine Months Ended September 30, 2010	$	101

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 $100 million primarily due to the following:
	·	A $106 million increase in rate relief primarily due to the impact of the Virginia interim rate increase implemented in December 2009 and increases in the recoveries of E&R costs in Virginia, costs related to the Transmission Rate Adjustment Clause in Virginia and construction financing costs in West Virginia.  This increase in retail margins had corresponding increases of $48 million related to riders/trackers recognized in other expense items discussed below.
	·	A $33 million increase in residential usage primarily due to a 45% increase in cooling degree days.
	These increases were partially offset by:
	·	A $19 million decrease in industrial sales primarily due to the decreased load for APCo’s largest customer, Century Aluminum.
	·	An $18 million decrease due to higher capacity settlement expenses under the Interconnection Agreement net of recovery in West Virginia and environmental deferrals in Virginia.
·	Margins from Off-system Sales increased $5 million primarily due to increased prices and higher physical sales volumes, partially offset by lower trading and marketing margins.

86

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

·	Other Operation and Maintenance expenses increased $113 million primarily due to the following:
	·	A $54 million increase due to the write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Project which was denied for recovery by the Virginia SCC.
	·	A $51 million increase due to expenses related to the cost reduction initiatives.
	·	A $19 million increase primarily due to the reduction of under-recovery of transmission costs resulting from the implementation of the Transmission Rate Adjustment Clause in Virginia in December 2009.
	These increases were partially offset by:
	·	A $25 million decrease due to the deferral of 2009 storm costs as allowed by the Virginia SCC in the second quarter of 2010.
·	Depreciation and Amortization expenses increased $23 million primarily due to a greater depreciation base resulting from environmental upgrades at the Amos Plant and the amortization of carrying charges which are being collected through the Virginia E&R surcharges.
·	Taxes Other Than Income Taxes increased $10 million primarily due to recording a West Virginia franchise tax audit settlement and additional employer payroll taxes incurred related to the cost reduction initiatives.
·	Carrying Costs Income increased $7 million primarily due to increased environmental deferrals in Virginia.
·	Income Tax Expense decreased $14 million primarily due to a decrease in pretax book income, partially offset by other book/tax differences which are accounted for on a flow-through basis.

FINANCIAL CONDITION

LIQUIDITY

APCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  APCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures.  See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 230 for additional discussion of liquidity.

Credit Ratings

Downgrades in credit ratings by one of the rating agencies could increase APCo’s borrowing costs.

CASH FLOW

Cash flows for the nine months ended September 30, 2010 and 2009 were as follows:

	2010			2009
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	2,006		$	1,996
Net Cash Flows from (Used for) Operating Activities		567,464			(53,712	)
Net Cash Flows Used for Investing Activities		(363,246	)		(406,707	)
Net Cash Flows from (Used for) Financing Activities		(204,023	)		460,237
Net Increase (Decrease) in Cash and Cash Equivalents		195			(182	)
Cash and Cash Equivalents at End of Period	$	2,201		$	1,814

87

Operating Activities

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

Net Cash Flows Used for Operating Activities were $54 million in 2009.  APCo produced Net Income of $131 million during the period and had noncash expense items of $229 million for Deferred Income Taxes and $204 million for Depreciation and Amortization.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a number of items.  The $160 million outflow from Fuel, Materials and Supplies was primarily due to an increase in coal inventory.  The $132 million outflow from Accounts Payable was primarily due to APCo’s provision for revenue refund of $77 million which was paid in the first quarter of 2009 to the AEP West companies as part of a FERC order on the SIA.  The $52 million inflow from Accounts Receivable, Net was primarily due to a decrease in accrued unbilled revenues due to usual seasonal fluctuations and timing of settlements of receivables from affiliated companies.  The $181 million outflow from Fuel Over/Under-Recovery, Net was primarily due to a net under-recovery of fuel costs in both Virginia and West Virginia.

Investing Activities

Net Cash Flows Used for Investing Activities during 2010 and 2009 were $363 million and $407 million, respectively.  Construction Expenditures of $363 million and $420 million in 2010 and 2009, respectively, were primarily for projects to improve service reliability for transmission and distribution, as well as environmental upgrades.  Environmental upgrades primarily include the installation of FGD equipment at the Amos Plant.

Financing Activities

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

Net Cash Flows from Financing Activities were $460 million in 2009.  APCo issued $350 million of Senior Unsecured Notes and retired $150 million of Senior Unsecured Notes.  APCo received a capital contribution from Parent of $250 million.  APCo had a net increase of $37 million in borrowings from the Utility Money Pool.  In addition, APCo paid $20 million in dividends on common stock.

88

Long-term debt issuances, retirements and principal payments made during the first nine months of 2010 were:
 

Issuances
		Principal		Interest	Due
	Type of Debt	Amount		Rate	Date
		(in thousands)		(%)
	Pollution Control Bonds	$	17,500	4.625	2021
	Pollution Control Bonds		50,000	5.375	2038
	Senior Unsecured Notes		300,000	3.40	2015

Retirements and Principal Payments
		Principal		Interest	Due
	Type of Debt	Amount Paid		Rate	Date
		(in thousands)		(%)
	Notes Payable – Affiliated	$	100,000	4.708	2010
	Senior Unsecured Notes		150,000	4.40	2010
	Pollution Control Bonds		50,000	7.125	2010
	Land Note		14	13.718	2026

SUMMARY OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2009 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” above.

EXECUTIVE OVERVIEW

REGULATORY ACTIVITY

Virginia Regulatory Activity

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

89

In June 2010, the Virginia SCC denied APCo’s request to include certain wind purchased power agreements (Beech Ridge and Grand Ridge) with a 20-year term in its Virginia renewable energy portfolio standard program.  As a result, APCo recorded an expense of $4 million in June 2010 to reduce the regulatory asset related to the Virginia portion of wind power costs to write off the difference between the actual Grand Ridge purchased power costs incurred from September 2009 through June 2010 and the estimated cost of non-wind power, which management believes is probable of recovery.  Management continues to evaluate several options regarding the Beech Ridge and Grand Ridge contracts.  APCo’s future net income and cash flows will be reduced by the unrecoverable Virginia portion of the Beech Ridge and Grand Ridge costs until such time as the contracts are reassigned, renegotiated or terminated.

West Virginia Regulatory Activity

In May 2010, APCo filed a request with the WVPSC to increase annual base rates by $140 million based on an 11.75% return on common equity to be effective March 2011.  Hearings are scheduled for December 2010.  A decision from the WVPSC is expected in March 2011.  See “2010 West Virginia Base Rate Case” section of Note 3.

In a proceeding established by the WVPSC to explore options to meet WPCo's future power supply requirements, the WVPSC, in November 2009, issued an order approving a joint stipulation among APCo, WPCo, the WVPSC staff and the Consumer Advocate Division.  The order approved the recommendation of the signatories to the stipulation that WPCo merge into APCo and be supplied from APCo's existing power resources.  Merger approvals from the WVPSC, Virginia SCC and the FERC are required.  No merger approval filings have been made.  See “WPCo Merger with APCo” section of Note 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 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 write-off of approximately $54 million in the second quarter of 2010.  In response to the order, APCo filed with the Virginia SCC a petition for reconsideration of the order as it relates to the Mountaineer Carbon Capture and Storage Project which was denied in August 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.

LITIGATION AND ENVIRONMENTAL ISSUES

In the ordinary course of business, APCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2009 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 161.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 230 for additional discussion of relevant factors.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2009 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230 for a discussion of the adoption and impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

See “Quantitative And Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230 for a discussion of risk management activities.

90

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2010 and 2009
(in thousands)
(Unaudited)
	Three Months Ended						Nine Months Ended
	2010			2009			2010			2009
REVENUES
Electric Generation, Transmission and Distribution	$	754,940		$	629,566		$	2,234,070		$	1,929,552
Sales to AEP Affiliates		83,675			63,645			229,811			181,914
Other Revenues		2,007			2,462			6,638			6,348
TOTAL REVENUES		840,622			695,673			2,470,519			2,117,814
EXPENSES
Fuel and Other Consumables Used for Electric Generation		190,538			140,321			540,794			402,893
Purchased Electricity for Resale		60,751			54,087			181,370			189,534
Purchased Electricity from AEP Affiliates		243,772			202,043			690,881			570,231
Other Operation		77,138			68,402			338,085			197,441
Maintenance		53,276			53,164			130,446			158,552
Depreciation and Amortization		76,737			69,701			227,327			203,844
Taxes Other Than Income Taxes		26,350			24,257			82,585			72,156
TOTAL EXPENSES		728,562			611,975			2,191,488			1,794,651
OPERATING INCOME		112,060			83,698			279,031			323,163
Other Income (Expense):
Interest Income		210			301			1,163			1,078
Carrying Costs Income		7,565			6,467			23,627			16,341
Allowance for Equity Funds Used During Construction		436			1,897			1,727			5,734
Interest Expense		(52,734	)		(51,982	)		(156,292	)		(153,144	)
INCOME BEFORE INCOME TAX EXPENSE		67,537			40,381			149,256			193,172
Income Tax Expense		17,466			13,011			48,522			62,225
NET INCOME		50,071			27,370			100,734			130,947
Preferred Stock Dividend Requirements Including Capital
Stock Expense		225			225			675			675
EARNINGS ATTRIBUTABLE TO COMMON
STOCK	$	49,846		$	27,145		$	100,059		$	130,272
The common stock of APCo is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

91

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2010 and 2009
(in thousands)
(Unaudited)
								Accumulated
								Other
	Common		Paid-in		Retained			Comprehensive
	Stock		Capital		Earnings			Income (Loss)			Total
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2008	$	260,458	$	1,225,292	$	951,066		$	(60,225	)	$	2,376,591
Capital Contribution from Parent				250,000								250,000
Common Stock Dividends						(20,000	)					(20,000	)
Preferred Stock Dividends						(599	)					(599	)
Capital Stock Expense				76		(76	)					-
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												2,605,992
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
Taxes:
Cash Flow Hedges, Net of Tax of $545									(1,013	)		(1,013	)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $1,982									3,680			3,680
NET INCOME						130,947						130,947
TOTAL COMPREHENSIVE INCOME												133,614
TOTAL COMMON SHAREHOLDER'S
EQUITY – SEPTEMBER 30, 2009	$	260,458	$	1,475,368	$	1,061,338		$	(57,558	)	$	2,739,606
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2009	$	260,458	$	1,475,393	$	1,085,980		$	(50,254	)	$	2,771,577
Common Stock Dividends						(88,000	)					(88,000	)
Preferred Stock Dividends						(599	)					(599	)
Capital Stock Expense				78		(76	)					2
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												2,682,980
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
Taxes:
Cash Flow Hedges, Net of Tax of $1,953									(3,627	)		(3,627	)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $1,685									3,129			3,129
NET INCOME						100,734						100,734
TOTAL COMPREHENSIVE INCOME												100,236
TOTAL COMMON SHAREHOLDER'S
EQUITY – SEPTEMBER 30, 2010	$	260,458	$	1,475,471	$	1,098,039		$	(50,752	)	$	2,783,216
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

92

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2010 and December 31, 2009
(in thousands)
(Unaudited)
	2010			2009
CURRENT ASSETS
Cash and Cash Equivalents	$	2,201		$	2,006
Accounts Receivable:
Customers		140,479			150,285
Affiliated Companies		66,742			135,686
Accrued Unbilled Revenues		57,588			68,971
Miscellaneous		4,204			6,690
Allowance for Uncollectible Accounts		(6,576	)		(5,408	)
Total Accounts Receivable		262,437			356,224
Fuel		210,998			343,261
Materials and Supplies		88,082			88,575
Risk Management Assets		61,199			67,956
Accrued Tax Benefits		52,903			180,708
Regulatory Asset for Under-Recovered Fuel Costs		16,224			78,685
Prepayments and Other Current Assets		40,266			36,293
TOTAL CURRENT ASSETS		734,310			1,153,708
PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		4,657,079			4,284,361
Transmission		1,841,919			1,813,777
Distribution		2,713,019			2,642,479
Other Property, Plant and Equipment		366,450			329,497
Construction Work in Progress		491,080			730,099
Total Property, Plant and Equipment		10,069,547			9,800,213
Accumulated Depreciation and Amortization		2,847,620			2,751,443
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		7,221,927			7,048,770
OTHER NONCURRENT ASSETS
Regulatory Assets		1,465,997			1,433,791
Long-term Risk Management Assets		51,866			47,141
Deferred Charges and Other Noncurrent Assets		109,374			113,003
TOTAL OTHER NONCURRENT ASSETS		1,627,237			1,593,935
TOTAL ASSETS	$	9,583,474		$	9,796,413
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

93

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, 2010 and December 31, 2009
(Unaudited)
	2010			2009
	(in thousands)
CURRENT LIABILITIES
Advances from Affiliates	$	55,113		$	229,546
Accounts Payable:
General		168,749			291,240
Affiliated Companies		111,005			157,640
Long-term Debt Due Within One Year – Nonaffiliated		250,021			200,019
Long-term Debt Due Within One Year – Affiliated		-			100,000
Risk Management Liabilities		28,193			25,792
Customer Deposits		57,460			57,578
Deferred Income Taxes		48,976			68,706
Accrued Taxes		45,146			65,241
Accrued Interest		71,090			58,962
Other Current Liabilities		84,262			95,292
TOTAL CURRENT LIABILITIES		920,015			1,350,016
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		3,310,938			3,177,287
Long-term Risk Management Liabilities		16,329			20,364
Deferred Income Taxes		1,529,082			1,439,884
Regulatory Liabilities and Deferred Investment Tax Credits		547,810			526,546
Employee Benefits and Pension Obligations		279,060			312,873
Deferred Credits and Other Noncurrent Liabilities		179,277			180,114
TOTAL NONCURRENT LIABILITIES		5,862,496			5,657,068
TOTAL LIABILITIES		6,782,511			7,007,084
Cumulative Preferred Stock Not Subject to Mandatory Redemption		17,747			17,752
Rate Matters (Note 3)
Commitments and Contingencies (Note 4)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 30,000,000 Shares
Outstanding  – 13,499,500 Shares		260,458			260,458
Paid-in Capital		1,475,471			1,475,393
Retained Earnings		1,098,039			1,085,980
Accumulated Other Comprehensive Income (Loss)		(50,752	)		(50,254	)
TOTAL COMMON SHAREHOLDER’S EQUITY		2,783,216			2,771,577
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	9,583,474		$	9,796,413
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

94

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2010 and 2009
(in thousands)
(Unaudited)
	2010			2009
OPERATING ACTIVITIES
Net Income	$	100,734		$	130,947
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for)
Operating Activities:
Depreciation and Amortization		227,327			203,844
Deferred Income Taxes		52,798			229,246
Carrying Costs Income		(23,627	)		(16,341	)
Allowance for Equity Funds Used During Construction		(1,727	)		(5,734	)
Mark-to-Market of Risk Management Contracts		(2,573	)		(31,415	)
Pension Contributions to Qualified Plan Trust		(31,952	)		-
Property Taxes		19,660			18,617
Fuel Over/Under-Recovery, Net		(17,136	)		(181,241	)
Change in Other Noncurrent Assets		29,275			(57,087	)
Change in Other Noncurrent Liabilities		4,558			22,595
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		93,787			51,667
Fuel, Materials and Supplies		132,801			(159,904	)
Accounts Payable		(113,912	)		(131,914	)
Accrued Taxes, Net		107,404			(95,962	)
Other Current Assets		(4,416	)		(14,172	)
Other Current Liabilities		(5,537	)		(16,858	)
Net Cash Flows from (Used for) Operating Activities		567,464			(53,712	)
INVESTING ACTIVITIES
Construction Expenditures		(362,792	)		(420,075	)
Change in Other Cash Deposits		1,970			235
Acquisitions of Assets		(9,595	)		(1,024	)
Proceeds from Sales of Assets		7,171			14,157
Net Cash Flows Used for Investing Activities		(363,246	)		(406,707	)
FINANCING ACTIVITIES
Capital Contribution from Parent		-			250,000
Issuance of Long-term Debt – Nonaffiliated		363,736			345,658
Change in Advances from Affiliates, Net		(174,433	)		36,900
Retirement of Long-term Debt – Nonaffiliated		(200,014	)		(150,012	)
Retirement of Long-term Debt – Affiliated		(100,000	)		-
Retirement of Cumulative Preferred Stock		(4	)		-
Principal Payments for Capital Lease Obligations		(5,350	)		(2,582	)
Dividends Paid on Common Stock		(88,000	)		(20,000	)
Dividends Paid on Cumulative Preferred Stock		(599	)		(599	)
Other Financing Activities		641			872
Net Cash Flows from (Used for) Financing Activities		(204,023	)		460,237
Net Increase (Decrease) in Cash and Cash Equivalents		195			(182	)
Cash and Cash Equivalents at Beginning of Period		2,006			1,996
Cash and Cash Equivalents at End of Period	$	2,201		$	1,814
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	140,391		$	148,745
Net Cash Paid (Received) for Income Taxes		(140,113	)		(14,679	)
Noncash Acquisitions Under Capital Leases		22,623			884
Construction Expenditures Included in Accounts Payable at September 30,		52,863			56,989
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

95

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to APCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to APCo.  The footnotes begin on page 161.

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

96

COLUMBUS SOUTHERN POWER COMPANY

AND SUBSIDIARIES

97

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Third Quarter of 2010 Compared to Third Quarter of 2009
Reconciliation of Third Quarter of 2009 to Third Quarter of 2010
Net Income
(in millions)
Third Quarter of 2009	$	98
Changes in Gross Margin:
Retail Margins		30
Off-system Sales		14
Other Revenues		1
Total Change in Gross Margin		45
Total Expenses and Other:
Other Operation and Maintenance		(17	)
Depreciation and Amortization		(2	)
Taxes Other Than Income Taxes		(7	)
Interest Expense		1
Total Expenses and Other		(25	)
Income Tax Expense		(11	)
Third Quarter of 2010	$	107

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 $30 million due to:
	·	A $32 million increase in residential and commercial revenue from weather-related usage primarily due to a 66% increase in cooling degree days.
	·	A $13 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Ohio Energy Efficiency & Demand Response Program Rider.  This increase in retail margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
	These increases were partially offset by:
	·	A $5 million decrease in capacity settlements under the Interconnection Agreement.
	·	A $4 million decrease as a result of the expiration of the City of Westerville contract as a dedicated customer for CSPCo at the end of 2009.  A new contract was entered into with Westerville on January 1, 2010 which is included as an Off-system Sale and margins are shared by the members of the AEP Power Pool.
·	Margins from Off-system Sales increased $14 million primarily due to increased prices and higher physical sales volumes, partially offset by lower trading and marketing margins.

98

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

· Other Operation and Maintenance expenses increased $17 million primarily due to:

· A $13 million increase in expenses due to the implementation of PUCO approved Ohio Energy Efficiency & Demand Response Program.  This increase in operation and maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.

· A $3 million increase in recoverable customer account expenses due to increased Universal Service Fund surcharge rates for customers who qualify for payment assistance.

· Depreciation and Amortization increased $2 million primarily due to projects at the Conesville Plant that were completed and placed in service in November 2009.

· Taxes Other Than Income Taxes increased $7 million primarily due to a $5 million increase in property taxes.

· Income Tax Expense increased $11 million primarily due to an increase in pretax book income and other book/tax differences which are accounted for a flow-through basis.

99

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
Net Income
(in millions)
Nine Months Ended September 30, 2009	$	231
Changes in Gross Margin:
Retail Margins		18
Off-system Sales		15
Total Change in Gross Margin		33
Total Expenses and Other:
Other Operation and Maintenance		(42)
Depreciation and Amortization		(8)
Taxes Other Than Income Taxes		(10)
Total Expenses and Other		(60)
Income Tax Expense		7
Nine Months Ended September 30, 2010	$	211

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 was as follows:

·	Retail Margins increased $18 million due to:
	·	A $41 million increase in residential and commercial revenue from weather-related usage primarily due to a 53% increase in cooling degree days.
	·	A $16 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Ohio Energy Efficiency & Demand Response Program Rider.  This increase in retail margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
	These increases were partially offset by:
	·	A $16 million decrease in capacity settlements under the Interconnection Agreement.
	·	A $14 million decrease as a result of the elimination of Restructuring Transition Charge (RTC) revenues with the implementation of CSPCo’s ESP.
	·	A $12 million decrease as a result of the expiration of the City of Westerville contract as a dedicated customer for CSPCo at the end of 2009.  A new contract was entered into with Westerville on January 1, 2010 which is included as an Off-system Sale and margins are shared by the members of the AEP Power Pool.
·	Margins from Off-system Sales increased $15 million primarily due to increased prices and higher physical sales volumes, partially offset by lower trading and marketing margins.

100

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

·	Other Operation and Maintenance expenses increased $42 million primarily due to:
	·	A $31 million increase due to expenses incurred related to the cost reduction initiatives.
	·	A $16 million increase in expenses due to the implementation of PUCO approved Ohio Energy Efficiency & Demand Response Program.  This increase in operation and maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
	·	A $10 million increase in recoverable customer account expenses due to increased Universal Service Fund surcharge rates for customers who qualify for payment assistance.
	These increases were partially offset by:
	·	A $7 million decrease related to a 2009 obligation to contribute to the “Partnership with Ohio” fund for low income, at-risk customers ordered by the PUCO’s March 2009 approval of CSPCo’s ESP.
	·	A $6 million decrease in boiler plant maintenance expenses primarily related to work performed at the Conesville and Zimmer plants.
·	Depreciation and Amortization increased $8 million primarily due to projects at the Conesville Plant that were completed and placed in service in November 2009.
·	Taxes Other Than Income Taxes increased $10 million primarily due to an $8 million increase in property taxes.
·	Income Tax Expense decreased $7 million primarily due to a decrease in pretax book income partially offset by other book/tax differences which are accounted for on a flow-through basis.

EXECUTIVE OVERVIEW

Ohio Customer Choice

In CSPCo’s 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 CSPCo retail customers have switched from CSPCo to alternative CRES providers while approximately 1,200 additional customers have provided notice of their intent to switch.  As a result, in comparison to 2009, CSPCo lost approximately $5 million of generation related gross margin through September 30, 2010.  Management currently forecasts incremental lost margins of approximately $10 million and $53 million for the fourth quarter of 2010 and for all of 2011, respectively.  Management anticipates recovery of a portion of this lost margin through off-system sales.

REGULATORY ACTIVITY

Ohio Electric Security Plan Filing

During 2009, the PUCO issued an order that modified and approved CSPCo’s ESP 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.  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 filed its significantly excessive earnings test with the PUCO in September 2010.  Based upon the methodology proposed by CSPCo in the SEET filing, CSPCo’s 2009 return on equity was not 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 2009 return on equity was significantly excessive, CSPCo may be required to return a portion of its 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.

101

LITIGATION AND ENVIRONMENTAL ISSUES

In the ordinary course of business, CSPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2009 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 161.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 230 for additional discussion of relevant factors.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2009 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230 for a discussion of the adoption and impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

See “Quantitative And Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230 for a discussion of risk management activities.

102

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2010 and 2009
(in thousands)
(Unaudited)
	Three Months Ended						Nine Months Ended
	2010			2009			2010			2009
REVENUES
Electric Generation, Transmission and Distribution	$	616,823		$	533,306		$	1,621,112		$	1,482,421
Sales to AEP Affiliates		30,765			22,143			66,687			51,514
Other Revenues		806			694			2,138			1,820
TOTAL REVENUES		648,394			556,143			1,689,937			1,535,755
EXPENSES
Fuel and Other Consumables Used for Electric Generation		99,883			88,523			319,614			222,943
Purchased Electricity for Resale		28,116			21,750			67,899			74,010
Purchased Electricity from AEP Affiliates		134,467			105,120			324,553			294,280
Other Operation		86,360			68,971			266,915			210,614
Maintenance		23,196			23,926			72,593			86,558
Depreciation and Amortization		38,644			36,292			113,733			105,863
Taxes Other Than Income Taxes		50,884			44,149			142,235			132,576
TOTAL EXPENSES		461,550			388,731			1,307,542			1,126,844
OPERATING INCOME		186,844			167,412			382,395			408,911
Other Income (Expense):
Interest Income		385			144			694			618
Carrying Costs Income		2,028			1,984			6,212			5,394
Allowance for Equity Funds Used During Construction		267			914			1,502			2,799
Interest Expense		(21,382	)		(22,487	)		(64,257	)		(64,356	)
INCOME BEFORE INCOME TAX EXPENSE		168,142			147,967			326,546			353,366
Income Tax Expense		61,085			50,374			115,723			122,737
NET INCOME		107,057			97,593			210,823			230,629
Capital Stock Expense		39			39			118			118
EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	107,018		$	97,554		$	210,705		$	230,511
The common stock of CSPCo is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

103

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2010 and 2009
(in thousands)
(Unaudited)
								Accumulated
								Other
	Common		Paid-in		Retained			Comprehensive
	Stock		Capital		Earnings			Income (Loss)			Total
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2008	$	41,026	$	580,506	$	674,758		$	(51,025	)	$	1,245,265
Common Stock Dividends						(150,000	)					(150,000	)
Capital Stock Expense				118		(118	)					-
Noncash Dividend of Property to Parent						(8,123	)					(8,123	)
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												1,087,142
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
Taxes:
Cash Flow Hedges, Net of Tax of $699									(1,299	)		(1,299	)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $894									1,661			1,661
NET INCOME						230,629						230,629
TOTAL COMPREHENSIVE INCOME												230,991
TOTAL COMMON SHAREHOLDER'S
EQUITY – SEPTEMBER 30, 2009	$	41,026	$	580,624	$	747,146		$	(50,663	)	$	1,318,133
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2009	$	41,026	$	580,663	$	788,139		$	(49,993	)	$	1,359,835
Common Stock Dividends						(77,500	)					(77,500	)
Capital Stock Expense				118		(118	)					-
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												1,282,335
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
Taxes:
Cash Flow Hedges, Net of Tax of $462									(857	)		(857	)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $1,000									1,857			1,857
NET INCOME						210,823						210,823
TOTAL COMPREHENSIVE INCOME												211,823
TOTAL COMMON SHAREHOLDER'S
EQUITY – SEPTEMBER 30, 2010	$	41,026	$	580,781	$	921,344		$	(48,993	)	$	1,494,158
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

104

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2010 and December 31, 2009
(in thousands)
(Unaudited)
	2010			2009
CURRENT ASSETS
Cash and Cash Equivalents	$	1,679		$	1,096
Other Cash Deposits		2,260			16,150
Advances to Affiliates		182,225			-
Accounts Receivable:
Customers		29,835			37,158
Affiliated Companies		23,231			28,555
Accrued Unbilled Revenues		12,139			11,845
Miscellaneous		3,856			4,164
Allowance for Uncollectible Accounts		(1,984	)		(3,481	)
Total Accounts Receivable		67,077			78,241
Fuel		65,636			74,158
Materials and Supplies		42,051			39,652
Emission Allowances		22,518			26,587
Risk Management Assets		35,166			34,343
Accrued Tax Benefits		645			29,273
Margin Deposits		14,823			14,874
Prepayments and Other Current Assets		25,676			6,349
TOTAL CURRENT ASSETS		459,756			320,723
PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		2,650,674			2,641,860
Transmission		656,293			623,680
Distribution		1,770,707			1,745,559
Other Property, Plant and Equipment		205,726			189,315
Construction Work in Progress		176,437			155,081
Total Property, Plant and Equipment		5,459,837			5,355,495
Accumulated Depreciation and Amortization		1,915,830			1,838,840
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		3,544,007			3,516,655
OTHER NONCURRENT ASSETS
Regulatory Assets		306,113			341,029
Long-term Risk Management Assets		29,882			23,882
Deferred Charges and Other Noncurrent Assets		74,472			147,217
TOTAL OTHER NONCURRENT ASSETS		410,467			512,128
TOTAL ASSETS	$	4,414,230		$	4,349,506
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

105

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER'S EQUITY
September 30, 2010 and December 31, 2009
(Unaudited)
	2010			2009
	(in thousands)
CURRENT LIABILITIES
Advances from Affiliates	$	-		$	24,202
Accounts Payable:
General		83,817			95,872
Affiliated Companies		54,380			81,338
Long-term Debt Due Within One Year – Nonaffiliated		150,000			150,000
Long-term Debt Due Within One Year – Affiliated		-			100,000
Risk Management Liabilities		15,500			13,052
Customer Deposits		28,741			27,911
Accrued Taxes		120,472			199,001
Accrued Interest		27,283			24,669
Other Current Liabilities		74,563			67,053
TOTAL CURRENT LIABILITIES		554,756			783,098
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		1,438,753			1,286,393
Long-term Risk Management Liabilities		9,389			10,313
Deferred Income Taxes		556,710			535,265
Regulatory Liabilities and Deferred Investment Tax Credits		164,978			174,671
Employee Benefits and Pension Obligations		125,982			133,968
Deferred Credits and Other Noncurrent Liabilities		69,504			65,963
TOTAL NONCURRENT LIABILITIES		2,365,316			2,206,573
TOTAL LIABILITIES		2,920,072			2,989,671
Rate Matters (Note 3)
Commitments and Contingencies (Note 4)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 24,000,000 Shares
Outstanding  – 16,410,426 Shares		41,026			41,026
Paid-in Capital		580,781			580,663
Retained Earnings		921,344			788,139
Accumulated Other Comprehensive Income (Loss)		(48,993	)		(49,993	)
TOTAL COMMON SHAREHOLDER’S EQUITY		1,494,158			1,359,835
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY	$	4,414,230		$	4,349,506
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

106

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2010 and 2009
(in thousands)
(Unaudited)
	2010			2009
OPERATING ACTIVITIES
Net Income	$	210,823		$	230,629
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		113,733			105,863
Deferred Income Taxes		30,333			97,279
Carrying Costs Income		(6,212	)		(5,394	)
Allowance for Equity Funds Used During Construction		(1,502	)		(2,799	)
Mark-to-Market of Risk Management Contracts		(6,397	)		(14,832	)
Property Taxes		71,795			67,012
Fuel Over/Under-Recovery, Net		22,912			(36,401	)
Change in Other Noncurrent Assets		(5,506	)		(18,365	)
Change in Other Noncurrent Liabilities		(14,413	)		22,644
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		11,164			62,244
Fuel, Materials and Supplies		6,419			(28,817	)
Accounts Payable		(20,468	)		(56,723	)
Customer Deposits		830			(2,078	)
Accrued Taxes, Net		(49,443	)		(102,827	)
Other Current Assets		6,110			8,017
Other Current Liabilities		(1,049	)		(5,914	)
Net Cash Flows from Operating Activities		369,129			319,538
INVESTING ACTIVITIES
Construction Expenditures		(148,441	)		(216,737	)
Change in Other Cash Deposits		13,890			12,223
Change in Advances to Affiliates, Net		(182,225	)		-
Acquisitions of Assets		(586	)		(227	)
Proceeds from Sales of Assets		4,278			721
Net Cash Flows Used for Investing Activities		(313,084	)		(204,020	)
FINANCING ACTIVITIES
Issuance of Long-term Debt - Nonaffiliated		149,443			91,204
Change in Advances from Affiliates, Net		(24,202	)		(54,770	)
Retirement of Long-term Debt - Affiliated		(100,000	)		-
Principal Payments for Capital Lease Obligations		(3,322	)		(2,017	)
Dividends Paid on Common Stock		(77,500	)		(150,000	)
Other Financing Activities		119			206
Net Cash Flows Used for Financing Activities		(55,462	)		(115,377	)
Net Increase in Cash and Cash Equivalents		583			141
Cash and Cash Equivalents at Beginning of Period		1,096			1,063
Cash and Cash Equivalents at End of Period	$	1,679		$	1,204
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	59,840		$	71,032
Net Cash Paid for Income Taxes		51,120			10,997
Noncash Acquisitions Under Capital Leases		9,521			784
Construction Expenditures Included in Accounts Payable at September 30,		12,561			26,688
Noncash Dividend of Property to Parent		-			8,123
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

107

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to CSPCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to CSPCo.  The footnotes begin on page 161.

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

108

INDIANA MICHIGAN POWER COMPANY

AND SUBSIDIARIES

109

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Third Quarter of 2010 Compared to Third Quarter of 2009
Reconciliation of Third Quarter of 2009 to Third Quarter of 2010
Net Income
(in millions)
Third Quarter of 2009	$	55
Changes in Gross Margin:
Retail Margins		62
FERC Municipals and Cooperatives		(5	)
Off-system Sales		6
Other Revenues		(40	)
Total Change in Gross Margin		23
Total Expenses and Other:
Other Operation and Maintenance		(6	)
Taxes Other Than Income Taxes		(2	)
Other Income		(1	)
Interest Expense		(2	)
Total Expenses and Other		(11	)
Income Tax Expense		(5	)
Third Quarter of 2010	$	62

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 $62 million primarily due to the following:
	·	A $30 million increase in fuel margins primarily due to a $19 million increase in 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.
	·	A $25 million increase in weather-related usage for residential and commercial customers primarily due to a 130% increase in cooling degree days and increased demand.
	·	A $13 million increase in rate relief primarily due to the impact of the Michigan interim rate increase implemented in August 2010 and Indiana rate riders.
	These increases were partially offset by:
	·	An $8 million increase in PJM costs.
·	FERC Municipals and Cooperatives margins decreased $5 million primarily due to a unit power sales agreement ending in December 2009.
·	Margins from Off-system Sales increased $6 million primarily due to increased prices and higher physical sales volumes, partially offset by lower trading and marketing margins.
·	Other Revenues decreased $40 million primarily due to the following:
	·	A $46 million decrease in the Cook Plant accidental outage insurance proceeds which ended when Unit 1 returned to service in December 2009.  I&M reduced customer bills by approximately $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.
	This decrease was partially offset by:
	·	A $5 million increase in River Transportation Division (RTD) revenues from barging activities.  The increase in RTD revenue was partially offset by a corresponding increase in Other Operation and Maintenance expenses from barging activities as discussed below.

110

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

· Other Operation and Maintenance expenses increased $6 million primarily due to a $5 million increase in RTD expenses from barging activities.  The increase in RTD expense was partially offset by a corresponding increase in Other Revenues from barging activities as discussed above.

· Income Tax Expense increased $5 million primarily due to an increase in pretax book income.

111

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
Net Income
(in millions)
Nine Months Ended September 30, 2009	$	184
Changes in Gross Margin:
Retail Margins		142
FERC Municipals And Cooperatives		(22)
Off-system Sales		9
Transmission Revenues		2
Other Revenues		(134)
Total Change in Gross Margin		(3)
Total Expenses and Other:
Other Operation and Maintenance		(75)
Depreciation and Amortization		(2)
Taxes Other Than Income Taxes		(3)
Other Income		2
Interest Expense		(5)
Total Expenses and Other		(83)
Income Tax Expense		24
Nine Months Ended September 30, 2010	$	122

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

·	Retail Margins increased $142 million primarily due to the following:
	·	A $70 million increase in fuel margins primarily due to a $59 million increase in 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.
	·	A $42 million increase in weather-related usage and increased price for residential and commercial customers primarily due to a 101% increase in cooling degree days.
	·	A $25 million increase in rate relief primarily due to the impact of the Michigan interim rate increase implemented in August 2010 and the approval of the Indiana base rate filing effective March 2009.
	·	A $23 million increase in industrial sale margins due to higher usage reflecting an improvement in demand.
	These increases were partially offset by:
	·	A $13 million increase in PJM costs.
·	FERC Municipals and Cooperatives margins decreased $22 million primarily due to a unit power sales agreement ending in December 2009.
·	Margins from Off-system Sales increased $9 million primarily due to increased prices and higher physical sales volumes, partially offset by lower trading and marketing margins.
·	Other Revenues decreased $134 million primarily due to the following:
	·	A $145 million decrease in the Cook Plant accidental outage insurance proceeds which ended when Unit 1 returned to service in December 2009.  I&M reduced customer bills by approximately $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.
	This decrease was partially offset by:
	·	A $10 million increase in River Transportation Division (RTD) revenues from barging activities.  The increase in RTD revenue was offset by a corresponding increase in Other Operation and Maintenance expenses from barging activities as discussed below.

112

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

· Other Operation and Maintenance expenses increased $75 million primarily due to the following:

· A $41 million increase due to expenses related to the cost reduction initiatives.

· An $11 million increase in RTD expenses from barging activities.  The increase in RTD expense was partially offset by a corresponding increase in Other Revenues from barging activities as discussed above.

· A $10 million increase in transmission expense primarily due to lower credits under the Transmission Agreement.

· A $5 million increase in administrative and general expenses primarily due to an increase in benefit and insurance costs.

· A $4 million increase in distribution expenses associated with storm restoration expenses from June 2010 storms.

· Taxes Other Than Income Taxes increased $3 million primarily due to expenses related to the cost reduction initiatives.

· Interest Expense increased $5 million related to the nuclear fuel financing.

· Income Tax Expense decreased $24 million primarily due to a decrease in pretax book income partially offset by the regulatory accounting treatment of state income taxes.

EXECUTIVE OVERVIEW

REGULATORY ACTIVITY

Michigan Regulatory Activity

In October 2010, a settlement agreement was approved by the MPSC to increase annual base rates by $36 million based on a 10.35% return on common equity, effective December 2010, plus separate recovery of approximately $7 million of customer choice implementation costs over a two year period beginning April 2011.  In addition, the approved revenue requirement includes the amortization of $6 million in previously expensed restructuring costs over five years, which I&M will defer and begin amortizing in the fourth quarter of 2010.  Also, the approved settlement agreement provided for sharing of off-system sales margins between customers (75%) and I&M (25%) with customers receiving a credit in future Power Supply Cost Recovery proceedings for their jurisdictional share of any off-system sales margins.  See “Michigan Base Rate Filing” section of Note 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.

113

LITIGATION AND ENVIRONMENTAL ISSUES

In the ordinary course of business, I&M is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2009 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 161.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 230 for additional discussion of relevant factors.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2009 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230 for a discussion of the adoption and impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

See “Quantitative And Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230 for a discussion of risk management activities.

114

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2010 and 2009
(in thousands)
(Unaudited)
	Three Months Ended						Nine Months Ended
	2010			2009			2010			2009
REVENUES
Electric Generation, Transmission and Distribution	$	480,779		$	435,399		$	1,327,505		$	1,257,673
Sales to AEP Affiliates		93,984			43,796			245,674			161,167
Other Revenues - Affiliated		27,796			24,958			86,447			80,890
Other Revenues - Nonaffiliated		5,691			48,114			11,595			149,997
TOTAL REVENUES		608,250			552,267			1,671,221			1,649,727
EXPENSES
Fuel and Other Consumables Used for Electric Generation		134,721			105,287			356,160			316,449
Purchased Electricity for Resale		27,904			28,203			89,115			97,417
Purchased Electricity from AEP Affiliates		96,405			93,093			247,151			253,964
Other Operation		132,200			121,737			425,859			346,421
Maintenance		46,180			50,650			144,257			148,412
Depreciation and Amortization		34,130			34,032			101,932			100,406
Taxes Other Than Income Taxes		20,806			19,122			60,833			58,071
TOTAL EXPENSES		492,346			452,124			1,425,307			1,321,140
OPERATING INCOME		115,904			100,143			245,914			328,587
Other Income (Expense):
Interest Income		1,079			1,532			2,598			5,049
Allowance for Equity Funds Used During Construction		2,943			3,492			11,945			7,830
Interest Expense		(28,046	)		(25,668	)		(80,557	)		(75,372	)
INCOME BEFORE INCOME TAX EXPENSE		91,880			79,499			179,900			266,094
Income Tax Expense		29,580			24,640			57,940			81,774
NET INCOME		62,300			54,859			121,960			184,320
Preferred Stock Dividend Requirements		85			85			255			255
EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	62,215		$	54,774		$	121,705		$	184,065
The common stock of I&M is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

115

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2010 and 2009
(in thousands)
(Unaudited)
								Accumulated
								Other
	Common		Paid-in		Retained			Comprehensive
	Stock		Capital		Earnings			Income (Loss)			Total
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2008	$	56,584	$	861,291	$	538,637		$	(21,694	)	$	1,434,818
Capital Contribution from Parent				120,000								120,000
Common Stock Dividends						(73,500	)					(73,500	)
Preferred Stock Dividends						(255	)					(255	)
Gain on Reacquired Preferred Stock				1								1
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												1,481,064
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
Taxes:
Cash Flow Hedges, Net of Tax of $265									(492	)		(492	)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $334									620			620
NET INCOME						184,320						184,320
TOTAL COMPREHENSIVE INCOME												184,448
TOTAL COMMON SHAREHOLDER'S
EQUITY – SEPTEMBER 30, 2009	$	56,584	$	981,292	$	649,202		$	(21,566	)	$	1,665,512
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2009	$	56,584	$	981,292	$	656,608		$	(21,701	)	$	1,672,783
Common Stock Dividends						(78,250	)					(78,250	)
Preferred Stock Dividends						(255	)					(255	)
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												1,594,278
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
Taxes:
Cash Flow Hedges, Net of Tax of $77									(144	)		(144	)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $352									655			655
NET INCOME						121,960						121,960
TOTAL COMPREHENSIVE INCOME												122,471
TOTAL COMMON SHAREHOLDER'S
EQUITY – SEPTEMBER 30, 2010	$	56,584	$	981,292	$	700,063		$	(21,190	)	$	1,716,749
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

116

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2010 and December 31, 2009
(in thousands)
(Unaudited)
	2010			2009
CURRENT ASSETS
Cash and Cash Equivalents	$	789		$	779
Advances to Affiliates		192,779			114,012
Accounts Receivable:
Customers		63,520			71,120
Affiliated Companies		84,372			83,248
Accrued Unbilled Revenues		7,357			8,762
Miscellaneous		11,545			8,638
Allowance for Uncollectible Accounts		(2,105	)		(2,265	)
Total Accounts Receivable		164,689			169,503
Fuel		95,096			79,554
Materials and Supplies		160,921			164,439
Risk Management Assets		39,717			34,438
Accrued Tax Benefits		59,764			144,473
Deferred Cook Plant Fire Costs		52,507			134,322
Prepayments and Other Current Assets		24,940			29,395
TOTAL CURRENT ASSETS		791,202			870,915
PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		3,713,372			3,634,215
Transmission		1,172,639			1,154,026
Distribution		1,398,319			1,360,553
Other Property, Plant and Equipment (including nuclear fuel and coal mining)		761,286			755,132
Construction Work in Progress		306,628			278,278
Total Property, Plant and Equipment		7,352,244			7,182,204
Accumulated Depreciation, Depletion and Amortization		3,125,414			3,073,695
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		4,226,830			4,108,509
OTHER NONCURRENT ASSETS
Regulatory Assets		507,358			496,464
Spent Nuclear Fuel and Decommissioning Trusts		1,465,699			1,391,919
Long-term Risk Management Assets		41,500			29,134
Deferred Charges and Other Noncurrent Assets		68,998			82,047
TOTAL OTHER NONCURRENT ASSETS		2,083,555			1,999,564
TOTAL ASSETS	$	7,101,587		$	6,978,988
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

117

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, 2010 and December 31, 2009
(dollars in thousands)
(Unaudited)
CURRENT LIABILITIES	2010			2009
Accounts Payable:
General	$	103,098		$	171,192
Affiliated Companies		64,027			61,315
Long-term Debt Due Within One Year - Nonaffiliated
(September 30, 2010 amount includes $61,435 related to DCC Fuel)		211,435			37,544
Long-term Debt Due Within One Year – Affiliated		-			25,000
Risk Management Liabilities		16,055			13,436
Customer Deposits		28,615			27,711
Accrued Taxes		42,622			56,814
Accrued Interest		23,451			27,633
Obligations Under Capital Leases		14,306			25,065
Other Current Liabilities		163,013			126,800
TOTAL CURRENT LIABILITIES		666,622			572,510
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		1,907,476			2,015,362
Long-term Risk Management Liabilities		9,713			10,386
Deferred Income Taxes		752,172			696,163
Regulatory Liabilities and Deferred Investment Tax Credits		818,084			756,845
Asset Retirement Obligations		935,586			894,746
Deferred Credits and Other Noncurrent Liabilities		287,109			352,116
TOTAL NONCURRENT LIABILITIES		4,710,140			4,725,618
TOTAL LIABILITIES		5,376,762			5,298,128
Cumulative Preferred Stock Not Subject to Mandatory Redemption		8,076			8,077
Rate Matters (Note 3)
Commitments and Contingencies (Note 4)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 2,500,000 Shares
Outstanding  – 1,400,000 Shares		56,584			56,584
Paid-in Capital		981,292			981,292
Retained Earnings		700,063			656,608
Accumulated Other Comprehensive Income (Loss)		(21,190	)		(21,701	)
TOTAL COMMON SHAREHOLDER’S EQUITY		1,716,749			1,672,783
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	7,101,587		$	6,978,988
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

118

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2010 and 2009
(in thousands)
(Unaudited)
	2010			2009
OPERATING ACTIVITIES
Net Income	$	121,960		$	184,320
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		101,932			100,406
Deferred Income Taxes		40,125			133,959
Deferral of Incremental Nuclear Refueling Outage Expenses, Net		(12,323	)		(4,563	)
Allowance for Equity Funds Used During Construction		(11,945	)		(7,830	)
Mark-to-Market of Risk Management Contracts		(16,887	)		(14,580	)
Amortization of Nuclear Fuel		113,031			41,198
Pension Contributions to Qualified Plan Trust		(66,711	)		-
Fuel Over/Under Recovery, Net		(280	)		20,588
Change in Other Noncurrent Assets		20,044			285
Change in Other Noncurrent Liabilities		63,409			50,932
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		4,814			(2,322	)
Fuel, Materials and Supplies		(12,021	)		(1,591	)
Accounts Payable		(10,928	)		(48,044	)
Accrued Taxes, Net		72,156			(15,005	)
Received (Deferred) Cook Plant Fire Costs		63,247			(69,921	)
Other Current Assets		408			(7,208	)
Other Current Liabilities		14,671			(18,278	)
Net Cash Flows from Operating Activities		484,702			342,346
INVESTING ACTIVITIES
Construction Expenditures		(224,488	)		(242,256	)
Change in Advances to Affiliates, Net		(78,767	)		(160,749	)
Purchases of Investment Securities		(1,128,747	)		(571,167	)
Sales of Investment Securities		1,087,484			523,927
Acquisitions of Nuclear Fuel		(69,459	)		(153,172	)
Other Investing Activities		(6,213	)		18,990
Net Cash Flows Used for Investing Activities		(420,190	)		(584,427	)
FINANCING ACTIVITIES
Capital Contribution from Parent		-			120,000
Issuance of Long-term Debt - Nonaffiliated		84,564			670,060
Issuance of Long-term Debt - Affiliated		-			25,000
Change in Advances from Affiliates, Net		-			(476,036	)
Retirement of Long-term Debt - Nonaffiliated		(19,208	)		-
Retirement of Long-term Debt - Affiliated		(25,000	)		-
Retirement of Cumulative Preferred Stock		(1	)		(2	)
Principal Payments for Capital Lease Obligations		(26,785	)		(23,640	)
Dividends Paid on Common Stock		(78,250	)		(73,500	)
Dividends Paid on Cumulative Preferred Stock		(255	)		(255	)
Other Financing Activities		433			569
Net Cash Flows from (Used for) Financing Activities		(64,502	)		242,196
Net Increase in Cash and Cash Equivalents		10			115
Cash and Cash Equivalents at Beginning of Period		779			728
Cash and Cash Equivalents at End of Period	$	789		$	843
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	81,576		$	81,833
Net Cash Paid (Received) for Income Taxes		(66,680	)		(21,414	)
Noncash Acquisitions Under Capital Leases		9,708			2,344
Construction Expenditures Included in Accounts Payable at September 30,		19,690			42,576
Acquisition of Nuclear Fuel Included in Current Liabilities at September 30,		20,332			2
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

119

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to I&M’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to I&M.  The footnotes begin on page 161.

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

120

OHIO POWER COMPANY CONSOLIDATED

121

OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Third Quarter of 2010 Compared to Third Quarter of 2009
Reconciliation of Third Quarter of 2009 to Third Quarter of 2010
Net Income
(in millions)
Third Quarter of 2009	$	97
Changes in Gross Margin:
Retail Margins		8
Off-system Sales		19
Transmission Revenues		1
Other Revenues		(1	)
Total Change in Gross Margin		27
Total Expenses and Other:
Other Operation and Maintenance		(17	)
Depreciation and Amortization		(2	)
Taxes Other Than Income Taxes		(4	)
Carrying Costs Income		3
Interest Expense		2
Total Expenses and Other		(18	)
Income Tax Expense		(5	)
Third Quarter of 2010	$	101

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

·	Retail Margins increased $8 million primarily due to the following:
	·	A $31 million increase in retail sales as a result of an increase in weather-related usage of residential and commercial customers primarily due to a 98% increase in cooling degree days and increased usage of industrial customers resulting from an improvement in demand.
	·	A $14 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Ohio Energy Efficiency & Demand Response Program Rider.  This increase in retail margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
	These increases were partially offset by:
	·	A $30 million decrease in fuel recovery primarily due to favorable adjustments recorded in September 2009 related to deferred fuel.
	·	A $6 million decrease as a result of the timing of approval and implementation of rates set by the Ohio ESP from April through December 2009.
·	Margins from Off-system Sales increased $19 million primarily due to increased prices and higher physical sales volumes.

122

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

· Other Operation and Maintenance expenses increased $17 million primarily due to a $14 million increase in expenses due to the implementation of PUCO approved Ohio Energy Efficiency & Demand Response Program.  This increase in operation and maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.

· Income Tax Expense increased $5 million primarily due to an increase in pretax book income and the regulatory accounting treatment of state income taxes.

123

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
Net Income
(in millions)
Nine Months Ended September 30, 2009	$	233
Changes in Gross Margin:
Retail Margins		76
Off-system Sales		18
Transmission Revenues		(1)
Other Revenues		(20)
Total Change in Gross Margin		73
Total Expenses and Other:
Other Operation and Maintenance		(58)
Depreciation and Amortization		(8)
Taxes Other Than Income Taxes		(11)
Carrying Costs Income		10
Other Income		1
Interest Expense		(4)
Total Expenses and Other		(70)
Income Tax Expense		(6)
Nine Months Ended September 30, 2010	$	230

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

·	Retail Margins increased $76 million primarily due to the following:
	·	A $44 million increase in capacity settlements under the Interconnection Agreement.
	·	A $29 million increase in retail sales primarily a result of an increase in weather-related usage of residential customers primarily due to an 82% increase in cooling degree days  and increased usage of industrial customers resulting from an improvement in demand.
	·	A $19 million increase in demand charges from WPCo effective January 2010.
	·	An $18 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Ohio Energy Efficiency & Demand Response Program Rider.  This increase in retail margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
	These increases were partially offset by:
	·	A $10 million decrease in fuel recovery related to coal pile survey adjustments recorded in 2009 for the 2008 consumption portion.  The 2008 portion was excluded from the deferred fuel calculation.  The PUCO’s March 2009 approval of OPCo’s ESP allowed for the recovery of fuel and related costs beginning January 1, 2009.
	·	A $7 million decrease related to increased consumable and allowance expenses.
·	Margins from Off-system Sales increased $18 million primarily due to increased prices and higher physical sales volumes, partially offset by lower trading and marketing margins.
·	Other Revenues decreased $20 million primarily due to reduced gains on sales of emission allowances which are partially offset by sharing in the fuel clause.

124

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

·	Other Operation and Maintenance expenses increased $58 million primarily due to:
	·	A $53 million increase due to expenses related to the cost reduction initiatives.
	·	An $18 million increase in expenses due to the implementation of PUCO approved Ohio Energy Efficiency & Demand Response Program.  This increase in operation and maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
	·	An $8 million increase in recoverable customer account expenses due to increased Universal Service Fund surcharge rates for customers who qualify for payment assistance.
	These increases were partially offset by:
	·	A $7 million decrease related to a 2009 obligation to contribute to the “Partnership with Ohio” fund for low income, at-risk customers ordered by the PUCO’s March 2009 approval of OPCo’s ESP.
·	Depreciation and Amortization increased $8 million primarily due to:
	·	A $12 million increase from higher depreciable property balances as a result of environmental improvements placed in service and various other property additions.
	This increase was partially offset by:
	·	A $4 million decrease due to the completion of the amortization of software and leasehold improvements in the fourth quarter of 2009.
·	Taxes Other Than Income Taxes increased $11 million primarily due to a $6 million increase in real and property taxes, a $3 million increase in state excise taxes as well as a $2 million increase due to the employer portion of payroll taxes incurred related to the cost reduction initiatives.
·	Carrying Costs Income increased $10 million primarily due to higher Ohio ESP FAC carrying charges in 2010 related to an increase in the deferred fuel regulatory asset balance.
·	Income Tax Expense increased $6 million primarily due to an increase in pretax book income and the tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.

FINANCIAL CONDITION

LIQUIDITY

OPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  OPCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures.  See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 144 for additional discussion of liquidity.

Credit Ratings

Downgrades in credit ratings by one of the rating agencies could increase OPCo’s borrowing costs.

CASH FLOW

Cash flows for the nine months ended September 30, 2010 and 2009 were as follows:

	2010			2009
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	1,984		$	12,679
Net Cash Flows from Operating Activities		627,472			136,802
Net Cash Flows Used for Investing Activities		(54,651	)		(674,647	)
Net Cash Flows from (Used for) Financing Activities		(573,451	)		528,116
Net Decrease in Cash and Cash Equivalents		(630	)		(9,729	)
Cash and Cash Equivalents at End of Period	$	1,354		$	2,950

125

Operating Activities

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

Net Cash Flows from Operating Activities were $137 million in 2009.  OPCo produced Net Income of $233 million during the period and noncash expense items of $263 million for Depreciation and Amortization, $213 million for Deferred Income Taxes and $67 million for Property Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital primarily relates to a number of items.  Fuel, Materials and Supplies had a $181 million outflow primarily due to an increase in coal inventory reflecting decreased customer demand for electricity as a result of the economic slowdown.  Accounts Payable had a $139 million outflow primarily due to OPCo’s provision for revenue refund of $62 million which was paid in the first quarter of 2009 to the AEP West companies as part of the FERC’s order on the SIA.  Accrued Taxes, Net had a $104 million outflow due to temporary timing differences of payments for property taxes and a decrease of federal income tax related accruals.  The $242 million change in Fuel Over/Under-Recovery, Net reflects the deferral of fuel costs as a fuel clause was reactivated in 2009 under OPCo’s ESP.

Investing Activities

Net Cash Flows Used for Investing Activities were $55 million and $675 million in 2010 and 2009, respectively.  Construction Expenditures of $208 million and $343 million in 2010 and 2009, respectively, primarily related to environmental upgrades, as well as projects to improve service reliability for transmission and distribution.  Environmental upgrades include FGD projects at the Amos Plant.  OPCo had a net decrease of $148 million and a net increase of $368 million in loans to the Utility Money Pool during 2010 and 2009, respectively.

Financing Activities

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

Net Cash Flows from Financing Activities were $528 million in 2009 primarily due to a $550 million Capital Contribution from Parent as well as a $500 million issuance of Senior Unsecured Notes.  These increases were partially offset by a $218 million reacquisition of Pollution Control Bonds related to JMG and a $78 million retirement of Notes Payable – Nonaffiliated.  OPCo also had a net decrease in borrowings of $134 million from the Utility Money Pool.

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

126

Long-term debt issuances and retirements during the first nine months of 2010 were:

Issuances
		Principal		Interest	Due
	Type of Debt	Amount		Rate	Date
		(in thousands)		(%)
	Pollution Control Bonds	$	86,000	3.125	2015
	Pollution Control Bonds		79,450	3.25	2014
	Pollution Control Bonds		39,130	2.875	2014

Retirements
		Principal		Interest	Due
	Type of Debt	Amount Paid		Rate	Date
		(in thousands)		(%)
	Senior Unsecured Notes	$	400,000	Variable	2010
	Pollution Control Bonds		79,450	7.125	2010
	Pollution Control Bonds		19,565	5.625	2022
	Pollution Control Bonds		19,565	5.625	2023

SUMMARY OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2009 Annual Report and has not changed significantly from year-end other than debt issuances and retirements discussed in “Cash Flow” above.

EXECUTIVE OVERVIEW

REGULATORY ACTIVITY

Ohio Electric Security Plan Filing

During 2009, the PUCO issued an order that modified and approved OPCo’s ESP which established rates through 2011.  The order also limits annual rate increases 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.  OPCo filed its significantly excessive earnings test with the PUCO in September 2010.  Based upon the methodology proposed by OPCo in the SEET filing, OPCo’s 2009 return on equity was not significantly excessive.  However, if the PUCO determines that OPCo’s 2009 return on equity was significantly excessive, OPCo may be required to return a portion of its 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.

127

LITIGATION AND ENVIRONMENTAL ISSUES

In the ordinary course of business, OPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2009 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 161.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 230 for additional discussion of relevant factors.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2009 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230 for a discussion of the adoption and impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

See “Quantitative And Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230 for a discussion of risk management activities.

128

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2010 and 2009
(in thousands)
(Unaudited)
	Three Months Ended						Nine Months Ended
	2010			2009			2010			2009
REVENUES
Electric Generation, Transmission and Distribution	$	583,084		$	481,049		$	1,617,206		$	1,463,200
Sales to AEP Affiliates		263,236			276,947			792,565			714,639
Other Revenues - Affiliated		5,065			5,646			16,794			19,415
Other Revenues - Nonaffiliated		4,474			2,329			12,531			9,445
TOTAL REVENUES		855,859			765,971			2,439,096			2,206,699
EXPENSES
Fuel and Other Consumables Used for Electric Generation		284,857			238,574			836,048			681,523
Purchased Electricity for Resale		42,840			42,160			120,476			138,398
Purchased Electricity from AEP Affiliates		36,004			19,782			79,778			56,989
Other Operation		106,314			91,162			341,887			287,009
Maintenance		52,448			50,703			172,151			168,893
Depreciation and Amortization		91,072			89,169			270,294			262,576
Taxes Other Than Income Taxes		52,261			48,300			157,433			146,274
TOTAL EXPENSES		665,796			579,850			1,978,067			1,741,662
OPERATING INCOME		190,063			186,121			461,029			465,037
Other Income (Expense):
Interest Income		583			242			1,322			1,002
Carrying Costs Income		6,324			3,143			16,879			7,152
Allowance for Equity Funds Used During Construction		947			1,081			2,964			1,849
Interest Expense		(39,013	)		(40,614	)		(118,065	)		(114,536	)
INCOME BEFORE INCOME TAX EXPENSE		158,904			149,973			364,129			360,504
Income Tax Expense		58,039			53,398			133,813			127,408
NET INCOME		100,865			96,575			230,316			233,096
Less: Net Income Attributable to Noncontrolling Interest		-			1,026			-			2,042
NET INCOME ATTRIBUTABLE TO OPCo
SHAREHOLDERS		100,865			95,549			230,316			231,054
Less: Preferred Stock Dividend Requirements		183			183			549			549
EARNINGS ATTRIBUTABLE TO OPCo COMMON
SHAREHOLDER	$	100,682		$	95,366		$	229,767		$	230,505
The common stock of OPCo is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

129

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2010 and 2009
(in thousands)
(Unaudited)
				OPCo Common Shareholder
										Accumulated
										Other
				Common		Paid-in		Retained		Comprehensive		Noncontrolling
				Stock		Capital		Earnings		Income (Loss)		Interest		Total
TOTAL EQUITY – DECEMBER 31, 2008				$	321,201	$	536,640	$	1,697,962	$	(133,858)	$	16,799	$	2,438,744
Capital Contribution from Parent							550,000								550,000
Common Stock Dividends - Affiliated									(50,000)						(50,000)
Common Stock Dividends - Nonaffiliated													(2,042)		(2,042)
Preferred Stock Dividends									(549)						(549)
Purchase of JMG							54,431						(17,910)		36,521
Other Changes in Equity													1,111		1,111
SUBTOTAL – EQUITY															2,973,785
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
		Cash Flow Hedges, Net of Tax of $4,946									9,185				9,185
		Amortization of Pension and OPEB Deferred
			Costs, Net of Tax of $2,566								4,765				4,765
NET INCOME									231,054				2,042		233,096
TOTAL COMPREHENSIVE INCOME															247,046
TOTAL EQUITY – SEPTEMBER 30, 2009				$	321,201	$	1,141,071	$	1,878,467	$	(119,908)	$	-	$	3,220,831
TOTAL COMMON SHAREHOLDER'S
		EQUITY – DECEMBER 31, 2009		$	321,201	$	1,123,149	$	1,908,803	$	(118,458)	$	-	$	3,234,695
Common Stock Dividends									(246,575)						(246,575)
Preferred Stock Dividends									(549)						(549)
SUBTOTAL – COMMON SHAREHOLDER'S
		EQUITY													2,987,571
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
	Taxes:
		Cash Flow Hedges, Net of Tax of $1,158									(2,150)				(2,150)
		Amortization of Pension and OPEB Deferred
			Costs, Net of Tax of $2,846								5,285				5,285
NET INCOME									230,316						230,316
TOTAL COMPREHENSIVE INCOME															233,451
TOTAL COMMON SHAREHOLDER'S
		EQUITY –  SEPTEMBER 30, 2010		$	321,201	$	1,123,149	$	1,891,995	$	(115,323)	$	-	$	3,221,022
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

130

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2010 and December 31, 2009
(in thousands)
(Unaudited)
	2010			2009
CURRENT ASSETS
Cash and Cash Equivalents	$	1,354		$	1,984
Advances to Affiliates		290,714			438,352
Accounts Receivable:
Customers		57,695			60,711
Affiliated Companies		144,481			200,579
Accrued Unbilled Revenues		18,116			15,021
Miscellaneous		2,006			2,701
Allowance for Uncollectible Accounts		(2,703	)		(2,665	)
Total Accounts Receivable		219,595			276,347
Fuel		256,594			336,866
Materials and Supplies		121,154			115,486
Risk Management Assets		44,849			50,048
Accrued Tax Benefits		33,414			143,473
Prepayments and Other Current Assets		31,545			26,301
TOTAL CURRENT ASSETS		999,219			1,388,857
PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		6,837,111			6,731,469
Transmission		1,219,276			1,166,557
Distribution		1,610,866			1,567,871
Other Property, Plant and Equipment		379,362			348,718
Construction Work in Progress		149,300			198,843
Total Property, Plant and Equipment		10,195,915			10,013,458
Accumulated Depreciation and Amortization		3,548,026			3,318,896
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		6,647,889			6,694,562
OTHER NONCURRENT ASSETS
Regulatory Assets		886,214			742,905
Long-term Risk Management Assets		36,823			28,003
Deferred Charges and Other Noncurrent Assets		114,312			184,812
TOTAL OTHER NONCURRENT ASSETS		1,037,349			955,720
TOTAL ASSETS	$	8,684,457		$	9,039,139
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

131

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, 2010 and December 31, 2009
(Unaudited)
	2010			2009
	(in thousands)
CURRENT LIABILITIES
Accounts Payable:
General	$	147,690		$	182,848
Affiliated Companies		65,550			92,766
Long-term Debt Due Within One Year – Nonaffiliated		200,000			679,450
Risk Management Liabilities		22,293			24,391
Customer Deposits		28,110			22,409
Accrued Taxes		130,219			203,335
Accrued Interest		46,335			46,431
Other Current Liabilities		106,736			104,889
TOTAL CURRENT LIABILITIES		746,933			1,356,519
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		2,529,386			2,363,055
Long-term Debt – Affiliated		200,000			200,000
Long-term Risk Management Liabilities		11,978			12,510
Deferred Income Taxes		1,437,077			1,302,939
Regulatory Liabilities and Deferred Investment Tax Credits		128,278			128,187
Employee Benefits and Pension Obligations		212,393			269,485
Deferred Credits and Other Noncurrent Liabilities		180,763			155,122
TOTAL NONCURRENT LIABILITIES		4,699,875			4,431,298
TOTAL LIABILITIES		5,446,808			5,787,817
Cumulative Preferred Stock Not Subject to Mandatory Redemption		16,627			16,627
Rate Matters (Note 3)
Commitments and Contingencies (Note 4)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
Authorized – 40,000,000 Shares
Outstanding  – 27,952,473 Shares		321,201			321,201
Paid-in Capital		1,123,149			1,123,149
Retained Earnings		1,891,995			1,908,803
Accumulated Other Comprehensive Income (Loss)		(115,323	)		(118,458	)
TOTAL COMMON SHAREHOLDER’S EQUITY		3,221,022			3,234,695
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	8,684,457		$	9,039,139
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

132

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2010 and 2009
(in thousands)
(Unaudited)
	2010			2009
OPERATING ACTIVITIES
Net Income	$	230,316		$	233,096
Adjustments to Reconcile Net Income to Net Cash Flows from
Operating Activities:
Depreciation and Amortization		270,294			262,576
Deferred Income Taxes		126,128			213,458
Carrying Costs Income		(16,879	)		(7,152	)
Allowance for Equity Funds Used During Construction		(2,964	)		(1,849	)
Mark-to-Market of Risk Management Contracts		(7,726	)		(15,226	)
Pension Contributions to Qualified Plan Trust		(47,174	)		-
Property Taxes		72,392			66,976
Fuel Over/Under-Recovery, Net		(115,926	)		(242,392	)
Change in Other Noncurrent Assets		(4,136	)		12,690
Change in Other Noncurrent Liabilities		1,009			40,709
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		56,752			15,155
Fuel, Materials and Supplies		74,604			(180,514	)
Accounts Payable		(45,601	)		(138,828	)
Accrued Taxes, Net		36,534			(103,965	)
Other Current Assets		(5,170	)		(4,164	)
Other Current Liabilities		5,019			(13,768	)
Net Cash Flows from Operating Activities		627,472			136,802
INVESTING ACTIVITIES
Construction Expenditures		(207,663	)		(342,633	)
Change in Advances to Affiliates, Net		147,638			(367,743	)
Acquisitions of Assets		(4,876	)		(1,053	)
Proceeds from Sales of Assets		10,406			31,253
Other Investing Activities		(156	)		5,529
Net Cash Flows Used for Investing Activities		(54,651	)		(674,647	)
FINANCING ACTIVITIES
Capital Contribution from Parent		-			550,000
Issuance of Long-term Debt – Nonaffiliated		202,382			494,078
Change in Advances from Affiliates, Net		-			(133,887	)
Retirement of Long-term Debt – Nonaffiliated		(518,580	)		(295,500	)
Retirement of Cumulative Preferred Stock		-			(1	)
Principal Payments for Capital Lease Obligations		(5,886	)		(3,435	)
Dividends Paid on Common Stock – Nonaffiliated		-			(2,042	)
Dividends Paid on Common Stock – Affiliated		(246,575	)		(50,000	)
Dividends Paid on Cumulative Preferred Stock		(549	)		(549	)
Acquisition of JMG Noncontrolling Interest		-			(28,221	)
Other Financing Activities		(4,243	)		(2,327	)
Net Cash Flows from (Used for) Financing Activities		(573,451	)		528,116
Net Decrease in Cash and Cash Equivalents		(630	)		(9,729	)
Cash and Cash Equivalents at Beginning of Period		1,984			12,679
Cash and Cash Equivalents at End of Period	$	1,354		$	2,950
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	116,140		$	119,763
Net Cash Paid (Received) for Income Taxes		(110,627	)		(23,241	)
Noncash Acquisitions Under Capital Leases		23,645			2,022
Construction Expenditures Included in Accounts Payable at September 30,		13,156			15,527
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

133

OHIO POWER COMPANY CONSOLIDATED

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to OPCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to OPCo.  The footnotes begin on page 161.

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

134

PUBLIC SERVICE COMPANY OF OKLAHOMA

135

PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Third Quarter of 2010 Compared to Third Quarter of 2009
Reconciliation of Third Quarter of 2009 to Third Quarter of 2010
Net Income
(in millions)
Third Quarter of 2009	$	44
Changes in Gross Margin:
Retail Margins (a)		29
Transmission Revenues		(2	)
Total Change in Gross Margin		27
Total Expenses and Other:
Other Operation and Maintenance		(4	)
Depreciation and Amortization		1
Taxes Other Than Income Taxes		(1	)
Other Income		(1	)
Interest Expense		(2	)
Total Expenses and Other		(7	)
Income Tax Expense		(9	)
		.
Third Quarter of 2010	$	55
(a)Includes firm wholesale sales to municipals and cooperatives.

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

· Retail Margins increased $29 million primarily due to the following:

· A $19 million increase in weather-related usage primarily due to a 34% increase in cooling degree days.

· A $15 million increase primarily resulting from rate increases, including revenue increases from rate riders.  This increase in retail margins had corresponding increases of $4 million related to riders/trackers recognized in other expense items.

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

· Other Operation and Maintenance expenses increased $4 million primarily due to planned generation plant maintenance.

· Income Tax Expense increased $9 million primarily due to an increase in pretax book income.

136

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
Net Income
(in millions)
Nine Months Ended September 30, 2009	$	74
Changes in Gross Margin:
Retail Margins (a)		52
Transmission Revenues		1
Other Revenues		(1)
Total Change in Gross Margin		52
Total Expenses and Other:
Other Operation and Maintenance		(43)
Depreciation and Amortization		3
Other Income		(3)
Interest Expense		(5)
Total Expenses and Other		(48)
Income Tax Expense		(3)
Nine Months Ended September 30, 2010	$	75
(a)Includes firm wholesale sales to municipals and cooperatives.

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

· Retail Margins increased $52 million primarily due to the following:

· A $34 million increase primarily resulting from rate increases, including revenue increases from rate riders.  This increase in retail margins had corresponding increases of $10 million related to riders/trackers recognized in other expense items.

· A $28 million increase in weather-related usage primarily due to a 27% increase in heating degree days and a 26% increase in cooling degree days.

Total Expenses and Other changed between years as follows:

· Other Operation and Maintenance expenses increased $43 million primarily due to the following:

· A $23 million increase primarily due to expenses related to the cost reduction initiatives.

· An $8 million increase in plant maintenance expense resulting primarily from the 2009 deferral of generation maintenance expenses as a result of PSO’s base rate case.

· A $7 million increase in employee-related expenses.

· Interest Expense increased $5 million primarily due to an increase in long-term borrowings in the last half of 2009.

137

FINANCIAL CONDITION

LIQUIDITY

PSO participates in the Utility Money Pool, which provides access to AEP’s liquidity.  PSO relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures.  See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 230 for additional discussion of liquidity.

Credit Ratings

Downgrades in credit ratings by one of the rating agencies could increase PSO’s borrowing costs.

CASH FLOW

Cash flows for the nine months ended September 30, 2010 and 2009 were as follows:

	2010			2009
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	796		$	1,345
Net Cash Flows from Operating Activities		107,685			232,759
Net Cash Flows Used for Investing Activities		(90,344	)		(142,945	)
Net Cash Flows Used For Financing Activities		(16,550	)		(89,852	)
Net Increase (Decrease) in Cash and Cash Equivalents		791			(38	)
Cash and Cash Equivalents at End of Period	$	1,587		$	1,307

Operating Activities

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

Net Cash Flows from Operating Activities were $233 million in 2009.  PSO produced Net Income of $74 million during the period and had a noncash expense item of $84 million for Depreciation and Amortization.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a number of items.  The $86 million inflow from Accounts Receivable, Net was primarily due to receiving the SIA refund from the AEP East companies and lower customer receivables.  The $46 million inflow from Accrued Taxes, Net was the result of increased accruals related to property and income taxes.  The $38 million outflow from Accounts Payable was primarily due to decreases in customer accounts factored, fuel and purchased power payables.

Investing Activities

Net Cash Flows Used for Investing Activities during 2010 and 2009 were $90 million and $143 million, respectively.  Construction Expenditures of $153 million and $135 million in 2010 and 2009, respectively, were primarily related to project improvements made during the restoration of damage from a 2010 ice storm and for improved generation, transmission and distribution service.  During 2010, PSO had a net decrease of $63 million in loans to the Utility Money Pool.  During 2009, PSO had a net increase of $8 million in loans to the Utility Money Pool.

138

Financing Activities

Net Cash Flows Used for Financing Activities were $17 million during 2010.  PSO paid $38 million in dividends on common stock.  This outflow was partially offset by a net increase of $23 million in borrowings from the Utility Money Pool.

Net Cash Flows Used for Financing Activities were $90 million during 2009.  PSO had a net decrease of $70 million in borrowings from the Utility Money Pool.  PSO retired $50 million of Senior Unsecured Notes and issued $34 million of Pollution Control Bonds.  PSO paid $22 million in dividends on common stock.  In addition, PSO received a capital contribution from Parent of $20 million.

Long-term debt issuances and retirements during the first nine months of 2010 were:

Issuances
		Principal		Interest	Due
	Type of Debt	Amount		Rate	Date
		(in thousands)		(%)
	Notes Payable	$	1,750	3.00	2025

Retirements

None

SUMMARY OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2009 Annual Report and has not changed significantly from year-end other than debt issuances discussed in “Cash Flow” above.

EXECUTIVE OVERVIEW

REGULATORY ACTIVITY

Oklahoma Regulatory Activity

In July 2010, PSO filed a request with the OCC to increase annual base rates by $82 million, including $30 million that is currently being recovered through a rider.  The requested net annual increase to ratepayers would be $52 million.  The requested increase includes a $24 million increase in depreciation and an 11.5% return on common equity.  In October 2010, various parties, including the OCC staff, filed testimony regarding PSO’s requested base rate increase.  These parties proposed that PSO's request to increase depreciation rates be denied and that existing depreciation rates continue.  PSO’s request to move the $30 million currently recovered through a rider to base rates was not opposed.  The parties’ net annual rate recommendations ranged from a rate reduction of $18 million to an increase of less than $1 million based on a recommended return on common equity range from 9.5% to 10%.  A hearing is scheduled for December 2010.  See “2010 Oklahoma Base Rate Case” section of Note 3.

LITIGATION AND ENVIRONMENTAL ISSUES

In the ordinary course of business, PSO is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2009 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 161.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

139

See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 230 for additional discussion of relevant factors.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2009 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230 for a discussion of the adoption and impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

See “Quantitative And Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230 for a discussion of risk management activities.

140

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2010 and 2009
(in thousands)
(Unaudited)
	Three Months Ended						Nine Months Ended
	2010			2009			2010			2009
REVENUES
Electric Generation, Transmission and Distribution	$	420,877		$	311,274		$	971,822		$	853,808
Sales to AEP Affiliates		4,665			6,668			17,816			34,181
Other Revenues		1,027			613			2,372			2,994
TOTAL REVENUES		426,569			318,555			992,010			890,983
EXPENSES
Fuel and Other Consumables Used for Electric Generation		140,367			79,610			269,954			261,762
Purchased Electricity for Resale		50,691			42,090			149,226			132,623
Purchased Electricity from AEP Affiliates		17,458			5,424			38,921			14,755
Other Operation		50,575			48,145			171,074			134,211
Maintenance		25,867			24,601			83,844			77,996
Depreciation and Amortization		26,703			27,799			80,911			84,278
Taxes Other Than Income Taxes		10,254			9,534			31,539			31,243
TOTAL EXPENSES		321,915			237,203			825,469			736,868
OPERATING INCOME		104,654			81,352			166,541			154,115
Other Income (Expense):
Interest Income		27			342			302			1,570
Carrying Costs Income		763			986			2,449			3,716
Allowance for Equity Funds Used During Construction		21			483			387			1,224
Interest Expense		(15,759	)		(13,884	)		(48,887	)		(43,852	)
INCOME BEFORE INCOME TAX EXPENSE		89,706			69,279			120,792			116,773
Income Tax Expense		34,274			25,702			45,732			43,036
NET INCOME		55,432			43,577			75,060			73,737
Preferred Stock Dividend Requirements		48			53			151			159
EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	55,384		$	43,524		$	74,909		$	73,578
The common stock of PSO is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

141

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2010 and 2009
(in thousands)
(Unaudited)
								Accumulated
								Other
	Common		Paid-in		Retained			Comprehensive
	Stock		Capital		Earnings			Income (Loss)			Total
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2008	$	157,230	$	340,016	$	251,704		$	(704	)	$	748,246
Capital Contribution from Parent				20,000								20,000
Common Stock Dividends						(21,750	)					(21,750	)
Preferred Stock Dividends						(159	)					(159	)
Gain on Reacquired Preferred Stock				1								1
Other Changes in Common Shareholder's
Equity				4,214		(4,214	)					-
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												746,338
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
Cash Flow Hedges, Net of Tax of $78									(145	)		(145	)
NET INCOME						73,737						73,737
TOTAL COMPREHENSIVE INCOME												73,592
TOTAL COMMON SHAREHOLDER'S
EQUITY – SEPTEMBER 30, 2009	$	157,230	$	364,231	$	299,318		$	(849	)	$	819,930
TOTAL COMMON SHAREHOLDER'S
EQUITY – DECEMBER 31, 2009	$	157,230	$	364,231	$	290,880		$	(599	)	$	811,742
Common Stock Dividends						(38,026	)					(38,026	)
Preferred Stock Dividends						(151	)					(151	)
Gain on Reacquired Preferred Stock				76								76
SUBTOTAL – COMMON
SHAREHOLDER'S EQUITY												773,641
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
Cash Flow Hedges, Net of Tax of $97									181			181
NET INCOME						75,060						75,060
TOTAL COMPREHENSIVE INCOME												75,241
TOTAL COMMON SHAREHOLDER'S
EQUITY – SEPTEMBER 30, 2010	$	157,230	$	364,307	$	327,763		$	(418	)	$	848,882
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page161.

142

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2010 and December 31, 2009
(in thousands)
(Unaudited)
			2010		2009
CURRENT ASSETS
Cash and Cash Equivalents			$	1,587	$	796
Advances to Affiliates				-		62,695
Accounts Receivable:
	Customers			31,750		38,239
	Affiliated Companies			66,928		59,096
	Miscellaneous			5,900		7,242
	Allowance for Uncollectible Accounts			(143)		(304)
		Total Accounts Receivable		104,435		104,273
Fuel				16,646		20,892
Materials and Supplies				46,970		44,914
Risk Management Assets				3,000		2,376
Deferred Income Tax Benefits				5,658		26,335
Accrued Tax Benefits				7,059		15,291
Regulatory Asset for Under-Recovered Fuel Costs				56,570		-
Prepayments and Other Current Assets				9,560		9,139
TOTAL CURRENT ASSETS				251,485		286,711
PROPERTY, PLANT AND EQUIPMENT
Electric:
	Production			1,321,952		1,300,069
	Transmission			658,623		617,291
	Distribution			1,670,406		1,596,355
Other Property, Plant and Equipment				247,581		228,705
Construction Work in Progress				43,893		67,138
Total Property, Plant and Equipment				3,942,455		3,809,558
Accumulated Depreciation and Amortization				1,253,107		1,220,177
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				2,689,348		2,589,381
OTHER NONCURRENT ASSETS
Regulatory Assets				263,269		279,185
Long-term Risk Management Assets				501		50
Deferred Charges and Other Noncurrent Assets				23,110		13,880
TOTAL OTHER NONCURRENT ASSETS				286,880		293,115
TOTAL ASSETS			$	3,227,713	$	3,169,207
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

143

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
September 30, 2010 and December 31, 2009
(Unaudited)
	2010			2009
	(in thousands)
CURRENT LIABILITIES
Advances from Affiliates	$	23,024		$	-
Accounts Payable:
General		68,411			76,895
Affiliated Companies		79,357			71,099
Long-term Debt Due Within One Year – Nonaffiliated		75,350			-
Risk Management Liabilities		308			2,579
Customer Deposits		40,740			42,002
Accrued Taxes		49,468			19,471
Regulatory Liability for Over-Recovered Fuel Costs		-			51,087
Other Current Liabilities		54,587			60,905
TOTAL CURRENT LIABILITIES		391,245			324,038
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		895,293			968,121
Long-term Risk Management Liabilities		119			144
Deferred Income Taxes		618,378			588,768
Regulatory Liabilities and Deferred Investment Tax Credits		327,234			326,931
Employee Benefits and Pension Obligations		97,893			107,748
Deferred Credits and Other Noncurrent Liabilities		43,787			36,457
TOTAL NONCURRENT LIABILITIES		1,982,704			2,028,169
TOTAL LIABILITIES		2,373,949			2,352,207
Cumulative Preferred Stock Not Subject to Mandatory Redemption		4,882			5,258
Rate Matters (Note 3)
Commitments and Contingencies (Note 4)
COMMON SHAREHOLDER’S EQUITY
Common Stock – Par Value – $15 Per Share:
Authorized – 11,000,000 Shares
Issued – 10,482,000 Shares
Outstanding – 9,013,000 Shares		157,230			157,230
Paid-in Capital		364,307			364,231
Retained Earnings		327,763			290,880
Accumulated Other Comprehensive Income (Loss)		(418	)		(599	)
TOTAL COMMON SHAREHOLDER’S EQUITY		848,882			811,742
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	3,227,713		$	3,169,207
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

144

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2010 and 2009
(in thousands)
(Unaudited)
			2010		2009
OPERATING ACTIVITIES
Net Income			$	75,060	$	73,737
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			80,911		84,278
	Deferred Income Taxes			43,631		13,103
	Carrying Costs Income			(2,449)		(3,716)
	Allowance for Equity Funds Used During Construction			(387)		(1,224)
	Mark-to-Market of Risk Management Contracts			(3,248)		2,185
	Property Taxes			(9,198)		(8,993)
	Fuel Over/Under-Recovery, Net			(107,657)		(14,566)
	Change in Other Noncurrent Assets			(11,319)		8,040
	Change in Other Noncurrent Liabilities			6,110		(2,768)
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		(162)		86,010
		Fuel, Materials and Supplies		2,190		4,199
		Accounts Payable		6,421		(38,023)
		Accrued Taxes, Net		38,830		46,119
		Other Current Assets		(494)		(3,822)
		Other Current Liabilities		(10,554)		(11,800)
Net Cash Flows from Operating Activities				107,685		232,759
INVESTING ACTIVITIES
Construction Expenditures				(152,589)		(134,756)
Change in Advances to Affiliates, Net				62,695		(8,450)
Other Investing Activities				(450)		261
Net Cash Flows Used for Investing Activities				(90,344)		(142,945)
FINANCING ACTIVITIES
Capital Contribution from Parent				-		20,000
Issuance of Long-term Debt – Nonaffiliated				1,740		33,248
Change in Advances from Affiliates, Net				23,024		(70,308)
Retirement of Long-term Debt – Nonaffiliated				-		(50,000)
Retirement of Cumulative Preferred Stock				(300)		(2)
Principal Payments for Capital Lease Obligations				(3,025)		(1,128)
Dividends Paid on Common Stock				(38,026)		(21,750)
Dividends Paid on Cumulative Preferred Stock				(151)		(159)
Other Financing Activities				188		247
Net Cash Flows Used For Financing Activities				(16,550)		(89,852)
Net Increase (Decrease) in Cash and Cash Equivalents				791		(38)
Cash and Cash Equivalents at Beginning of Period				796		1,345
Cash and Cash Equivalents at End of Period			$	1,587	$	1,307
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	37,915	$	55,152
Net Cash Paid (Received) for Income Taxes				(18,520)		4,423
Noncash Acquisitions Under Capital Leases				13,572		2,802
Construction Expenditures Included in Accounts Payable at September 30,				5,254		7,315
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

145

PUBLIC SERVICE COMPANY OF OKLAHOMA

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to PSO’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to PSO.  The footnotes begin on page 161.

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

146

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

147

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
RESULTS OF OPERATIONS
Third Quarter of 2010 Compared to Third Quarter of 2009
Reconciliation of Third Quarter of 2009 to Third Quarter of 2010
Income Before Extraordinary Loss
(in millions)
Third Quarter of 2009	$	65
Changes in Gross Margin:
Retail Margins (a)		49
Transmission Revenues		(1	)
Other Revenues		(11	)
Total Change in Gross Margin		37
Total Expenses and Other:
Other Operation and Maintenance		5
Depreciation and Amortization		5
Taxes Other Than Income Taxes		(1	)
Other Income		(5	)
Interest Expense		(7	)
Equity Earnings of Unconsolidated Subsidiaries		1
Total Expenses and Other		(2	)
Income Tax Expense		(18	)
Third Quarter of 2010	$	82
(a)Includes firm wholesale sales to municipals and cooperatives.

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

· Retail Margins increased $49 million primarily due to:

· An $18 million increase in base rates in Arkansas and Texas.

· A $16 million increase in weather-related usage primarily due to a 35% increase in cooling degree days.

· A $6 million increase in fuel recovery primarily due to lower capacity costs and increased wholesale fuel recovery.

· A $5 million increase in industrial sales due to higher demand.

· Other Revenues decreased $11 million resulting from the deconsolidation of SWEPCo’s mining subsidiary, DHLC.  Prior to the deconsolidation, SWEPCo recorded revenues from coal deliveries from DHLC to CLECO.  SWEPCo prospectively adopted the “Consolidation” accounting guidance effective January 1, 2010 and began accounting for DHLC under the equity method of accounting.  The decreased revenue from coal deliveries was partially offset by a corresponding decrease in Other Operation and Maintenance expenses from mining operations as discussed below.

148

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

·	Other Operation and Maintenance expenses decreased $5 million primarily due to:
	·	An $11 million decrease in expenses for coal deliveries from SWEPCo’s mining subsidiary, DHLC.  The decreased expenses for coal deliveries were offset by a corresponding decrease in revenues from mining operations as discussed above.
	This decrease was partially offset by:
	·	A $7 million increase in distribution maintenance resulting primarily from storm-related amortization expense.
·	Depreciation and Amortization expenses decreased $5 million primarily due to lower Arkansas and Texas depreciation resulting from the Arkansas and Texas base rate orders and the deconsolidation of DHLC, partially offset by plant additions including the Stall Unit.
·	Other Income decreased $5 million primarily due to a decrease in the equity component of AFUDC as a result of the completion of the Stall Unit construction project in June 2010.
·	Interest Expense increased $7 million primarily due to increased long-term debt outstanding.
·	Income Tax Expense increased $18 million primarily due to an increase in pretax book income and other book/tax differences accounted for on a flow-through basis.

149

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 Before Extraordinary Loss
(in millions)
Nine Months Ended September 30, 2009	$	113
Changes in Gross Margin:
Retail Margins (a)		91
Off-system Sales		1
Transmission Revenues		1
Other Revenues		(29)
Total Change in Gross Margin		64
Total Expenses and Other:
Other Operation and Maintenance		(17)
Depreciation and Amortization		14
Taxes Other Than Income Taxes		(2)
Other Income		3
Interest Expense		(12)
Equity Earnings of Unconsolidated Subsidiaries		2
Total Expenses and Other		(12)
Income Tax Expense		(26)
Nine Months Ended September 30, 2010	$	139
(a) Includes firm wholesale sales to municipals and cooperatives.

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

· Retail Margins increased $91 million primarily due to:

· A $32 million increase in weather-related usage primarily due to a 42% increase in heating degree days and a 30% increase in cooling degree days.

· A $31 million increase in base rates in Arkansas and Texas.

· An $11 million increase in fuel recovery primarily due to lower capacity costs and increased wholesale fuel recovery.

· An $11 million increase in industrial sales due to higher demand.

· Other Revenues decreased $29 million resulting from the deconsolidation of SWEPCo’s mining subsidiary, DHLC.  Prior to the deconsolidation, SWEPCo recorded revenues from coal deliveries from DHLC to CLECO.  SWEPCo prospectively adopted the “Consolidation” accounting guidance effective January 1, 2010 and began accounting for DHLC under the equity method of accounting.  The decreased revenue from coal deliveries was partially offset by a corresponding decrease in Other Operation and Maintenance expenses from mining operations as discussed below.

150

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

·	Other Operation and Maintenance expenses increased $17 million primarily due to:
	·	A $28 million increase due to expenses related to the cost reduction initiatives.
	·	A $5 million increase in other generation operation expenses primarily related to Stall Unit testing for commercial operation.  The Stall Unit was placed in service in June 2010.
	·	A $4 million increase in employee-related expenses.
	·	A $2 million gain on sale of property during the first quarter of 2009 related to the sale of percentage ownership of Turk Plant to nonaffiliated companies who exercised their participation options.
	These increases were partially offset by:
	·	A $24 million decrease in expenses for coal deliveries from SWEPCo’s mining subsidiary, DHLC.  The decreased expenses for coal deliveries were partially offset by a corresponding decrease in revenues from mining operations as discussed above.
·	Depreciation and Amortization expenses decreased $14 million primarily due to lower Arkansas and Texas depreciation resulting from the Arkansas and Texas base rate orders and the deconsolidation of DHLC, partially offset by plant additions including the Stall Unit.
·	Other Income increased $3 million primarily due to an increase in the equity component of AFUDC as a result of construction at the Turk Plant and Stall Unit and the reapplication of “Regulated Operations” accounting guidance for the generation portion of Texas’ retail jurisdiction effective the second quarter of 2009.  This increase was partially offset by decreases in approved return on common equity, the completion of the Stall Unit construction project in June 2010 and the discontinuance of AFUDC in Arkansas related to Turk Plant construction.
·	Interest Expense increased $12 million primarily due to increased long-term debt outstanding.
·	Income Tax Expense increased $26 million primarily due to an increase in pretax book income and other book/tax differences accounted for on a flow-through basis.

FINANCIAL CONDITION

LIQUIDITY

SWEPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  SWEPCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures.  See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 230 for additional discussion of liquidity.

Credit Ratings

In June 2010, Fitch downgraded SWEPCo's senior unsecured rating to BBB.  Further downgrades in SWEPCo's ratings by one of the rating agencies could increase SWEPCo's borrowing costs and affect SWEPCo's ability to finance construction costs.

CASH FLOW

Cash flows for the nine months ended September 30, 2010 and 2009 were as follows:

	2010			2009
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	1,661		$	1,910
Net Cash Flows from Operating Activities		168,196			335,922
Net Cash Flows Used for Investing Activities		(449,053	)		(472,183	)
Net Cash Flows from Financing Activities		281,078			136,440
Net Increase in Cash and Cash Equivalents		221			179
Cash and Cash Equivalents at End of Period	$	1,882		$	2,089

151

Operating Activities

Net Cash Flows from Operating Activities were $168 million in 2010.  SWEPCo produced Net Income of $139 million during the period and had a noncash item of $95 million for Depreciation and Amortization, partially offset by $37 million for Allowance for Equity Funds Used During Construction.  SWEPCo contributed $27 million to the qualified pension trust.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a number of items.  The $49 million inflow from Accrued Taxes, Net was the result of an increase in accruals related to federal and property taxes.  The $36 million outflow from Accounts Payable was primarily due to decreases related to customer accounts factored, net and purchased power payable.  The $28 million inflow from Fuel, Materials and Supplies was primarily due to decreased coal and lignite inventories.  The $24 million outflow from Accounts Receivable, Net was primarily due to increased affiliated receivables.

Net Cash Flows from Operating Activities were $336 million in 2009.  SWEPCo produced Net Income of $107 million during the period and had a noncash item of $109 million for Depreciation and Amortization, partially offset by $32 million in Allowance for Equity Funds Used During Construction and $21 million in Deferred Income Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a number of items.  The $81 million inflow from Accounts Receivable, Net was primarily due to the receipt of payment for SIA from the AEP East companies.  The $53 million outflow from Other Current Liabilities was due to a decrease in check clearing, a refund to wholesale customers for the SIA and payments of employee-related expenses.  The $50 million inflow from Accrued Taxes, Net was the result of an increase in accruals related to federal and property taxes.  The $25 million inflow from Accounts Payable was primarily due to increases in accruals related to tax payments, partially offset by a decrease in customer accounts factored, net.  The $20 million outflow from Accrued Interest was primarily due to timing between accruals and payments for Senior Unsecured Notes.  The $62 million inflow from Fuel Over/Under-Recovery, Net was the result of a surcharge to customers in Texas for under-recovered fuel and a decrease in fuel costs.

Investing Activities

Net Cash Flows Used for Investing Activities during 2010 and 2009 were $449 million and $472 million, respectively.  Construction Expenditures of $288 million and $470 million in 2010 and 2009, respectively, were primarily related to new generation projects at the Turk Plant and Stall Unit.  SWEPCo’s net increase in loans to the Utility Money Pool during 2010 and 2009 were $162 million and $107 million, respectively.  Proceeds from Sales of Assets in 2009 primarily included $104 million related to the sale of a portion of Turk Plant to joint owners.

152

Financing Activities

Net Cash Flows from Financing Activities were $281 million during 2010 related to a $350 million issuance of Senior Unsecured Notes and a $54 million issuance of Pollution Control Bonds.  These increases were partially offset by a $54 million retirement of Pollution Control Bonds and a $50 million retirement of Notes Payable – Affiliated.

Net Cash Flows from Financing Activities were $136 million during 2009.  SWEPCo received a capital contribution from Parent of $143 million and $12 million from proceeds on sale leaseback of a utility property.

Long-term debt issuances and retirements during the first nine months of 2010 were:

Issuances
		Principal		Interest	Due
	Type of Debt	Amount		Rate	Date
		(in thousands)		(%)
	Senior Unsecured Notes	$	350,000	6.20	2040
	Pollution Control Bonds		53,500	3.25	2015

Retirements
		Principal		Interest	Due
	Type of Debt	Amount Paid		Rate	Date
		(in thousands)		(%)
	Notes Payable – Affiliated	$	50,000	4.45	2010
	Pollution Control Bonds		53,500	Variable	2019

SUMMARY OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2009 Annual Report and has not changed significantly from year-end other than debt issuances and retirements discussed in “Cash Flow” above.

EXECUTIVE OVERVIEW

REGULATORY ACTIVITY

Texas Regulatory Activity

In April 2010, a settlement agreement was approved by the PUCT to increase SWEPCo’s base rates by approximately $15 million annually, effective May 2010, including a return on equity of 10.33%.  In addition, the settlement agreement will decrease annual depreciation expense by $17 million and allows SWEPCo a $10 million one-year surcharge rider to recover additional vegetation management costs that SWEPCo must spend within two years.  See “2009 Texas Base Rate Filing” section of Note 3.

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in-service in 2012.  SWEPCo owns 73% of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, plus an additional $132 million for transmission, excluding AFUDC.  SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus an additional $132 million for transmission, excluding AFUDC.  Notices of appeal are outstanding at the Circuit Court of Hempstead County, Arkansas and the Federal Court of Appeals.  Matters are also outstanding at the Texas Court of Appeals, the APSC and the LPSC.  See “Turk Plant” section of Note 3.

153

LITIGATION AND ENVIRONMENTAL ISSUES

In the ordinary course of business SWEPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2009 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 161.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 230 for additional discussion of relevant factors.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2009 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230 for a discussion of the adoption and impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

See “Quantitative And Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230 for a discussion of risk management activities.

154

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2010 and 2009
(in thousands)
(Unaudited)
	Three Months Ended						Nine Months Ended
	2010			2009			2010			2009
REVENUES
Electric Generation, Transmission and Distribution	$	459,013		$	392,616		$	1,139,748		$	1,021,991
Sales to AEP Affiliates		21,356			9,420			43,920			23,470
Lignite Revenues – Nonaffiliated		-			12,334			-			30,572
Other Revenues		613			604			1,585			1,525
TOTAL REVENUES		480,982			414,974			1,185,253			1,077,558
EXPENSES
Fuel and Other Consumables Used for Electric Generation		194,340			161,879			452,279			405,329
Purchased Electricity for Resale		29,794			30,413			94,521			85,149
Purchased Electricity from AEP Affiliates		4,191			6,865			18,154			30,395
Other Operation		52,839			64,686			193,357			178,456
Maintenance		23,979			17,267			69,531			67,283
Depreciation and Amortization		31,828			36,714			94,939			109,065
Taxes Other Than Income Taxes		15,583			14,127			47,058			44,995
TOTAL EXPENSES		352,554			331,951			969,839			920,672
OPERATING INCOME		128,428			83,023			215,414			156,886
Other Income (Expense):
Interest Income		186			388			434			1,205
Allowance for Equity Funds Used During Construction		8,651			12,932			36,630			31,706
Interest Expense		(23,459	)		(16,605	)		(63,478	)		(51,894	)
INCOME BEFORE INCOME TAX EXPENSE AND
EQUITY EARNINGS		113,806			79,738			189,000			137,903
Income Tax Expense		32,870			14,680			51,733			25,367
Equity Earnings of Unconsolidated Subsidiaries		749			-			2,206			-
INCOME BEFORE EXTRAORDINARY LOSS		81,685			65,058			139,473			112,536
EXTRAORDINARY LOSS, NET OF TAX		-			-			-			(5,325	)
NET INCOME		81,685			65,058			139,473			107,211
Less: Net Income Attributable to Noncontrolling Interest		774			1,022			3,198			2,971
NET INCOME ATTRIBUTABLE TO SWEPCo
SHAREHOLDERS		80,911			64,036			136,275			104,240
Less: Preferred Stock Dividend Requirements		58			58			172			172
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON
SHAREHOLDER	$	80,853		$	63,978		$	136,103		$	104,068
The common stock of SWEPCo is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

155

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2010 and 2009
(in thousands)
(Unaudited)
			SWEPCo Common Shareholder
									Accumulated
									Other
			Common		Paid-in		Retained		Comprehensive		Noncontrolling
			Stock		Capital		Earnings		Income (Loss)		Interest		Total
TOTAL EQUITY – DECEMBER 31, 2008			$	135,660	$	530,003	$	615,110	$	(32,120)	$	276	$	1,248,929
Capital Contribution from Parent						142,500								142,500
Common Stock Dividends – Nonaffiliated												(2,886)		(2,886)
Preferred Stock Dividends								(172)						(172)
Other Changes in Equity						2,476		(2,476)						-
SUBTOTAL – EQUITY														1,388,371
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
	Cash Flow Hedges, Net of Tax of $421									782				782
	Amortization of Pension and OPEB Deferred
		Costs, Net of Tax of $8,919								16,563				16,563
NET INCOME								104,240				2,971		107,211
TOTAL COMPREHENSIVE INCOME														124,556
TOTAL EQUITY – SEPTEMBER 30, 2009			$	135,660	$	674,979	$	716,702	$	(14,775)	$	361	$	1,512,927
TOTAL EQUITY – DECEMBER 31, 2009			$	135,660	$	674,979	$	726,478	$	(12,991)	$	31	$	1,524,157
Common Stock Dividends – Nonaffiliated												(2,966)		(2,966)
Preferred Stock Dividends								(172)						(172)
SUBTOTAL – EQUITY														1,521,019
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
	Cash Flow Hedges, Net of Tax of $248									461				461
	Amortization of Pension and OPEB Deferred
		Costs, Net of Tax of $379								703				703
NET INCOME								136,275				3,198		139,473
TOTAL COMPREHENSIVE INCOME														140,637
TOTAL EQUITY – SEPTEMBER 30, 2010			$	135,660	$	674,979	$	862,581	$	(11,827)	$	263	$	1,661,656
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

156

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2010 and December 31, 2009
(in thousands)
(Unaudited)
	2010			2009
CURRENT ASSETS
Cash and Cash Equivalents	$	1,882		$	1,661
Advances to Affiliates		213,689			34,883
Accounts Receivable:
Customers		23,833			46,657
Affiliated Companies		42,393			19,542
Miscellaneous		23,753			9,952
Allowance for Uncollectible Accounts		(454	)		(64	)
Total Accounts Receivable		89,525			76,087
Fuel
(September 30, 2010 amount includes $31,649 related to Sabine)		86,154			121,453
Materials and Supplies		48,770			54,484
Risk Management Assets		2,017			3,049
Deferred Income Tax Benefits		14,470			13,820
Accrued Tax Benefits		2,859			16,164
Regulatory Asset for Under-Recovered Fuel Costs		7,622			1,639
Prepayments and Other Current Assets		20,388			20,503
TOTAL CURRENT ASSETS		487,376			343,743
PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		2,267,397			1,837,318
Transmission		906,837			870,069
Distribution		1,476,596			1,447,559
Other Property, Plant and Equipment
(September 30, 2010 amount includes $224,987 related to Sabine)		640,697			733,310
Construction Work in Progress		1,003,889			1,176,639
Total Property, Plant and Equipment		6,295,416			6,064,895
Accumulated Depreciation and Amortization
(September 30, 2010 amount includes $89,703 related to Sabine)		2,080,258			2,086,333
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET		4,215,158			3,978,562
OTHER NONCURRENT ASSETS
Regulatory Assets		295,590			268,165
Long-term Risk Management Assets		419			84
Deferred Charges and Other Noncurrent Assets		80,591			49,479
TOTAL OTHER NONCURRENT ASSETS		376,600			317,728
TOTAL ASSETS	$	5,079,134		$	4,640,033
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

157

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
September 30, 2010 and December 31, 2009
(Unaudited)
	2010			2009
	(in thousands)
CURRENT LIABILITIES
Accounts Payable:
General	$	168,300		$	160,870
Affiliated Companies		45,767			59,818
Short-term Debt – Nonaffiliated		3,170			6,890
Long-term Debt Due Within One Year – Nonaffiliated		41,135			4,406
Long-term Debt Due Within One Year – Affiliated		-			50,000
Risk Management Liabilities		523			844
Customer Deposits		43,467			41,269
Accrued Taxes		58,319			24,720
Accrued Interest		18,088			33,179
Obligations Under Capital Leases		12,679			14,617
Regulatory Liability for Over-Recovered Fuel Costs		5,377			13,762
Provision for SIA Refund		20,766			19,307
Other Current Liabilities		45,115			71,781
TOTAL CURRENT LIABILITIES		462,706			501,463
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated		1,728,322			1,419,747
Long-term Risk Management Liabilities		272			221
Deferred Income Taxes		514,576			485,936
Regulatory Liabilities and Deferred Investment Tax Credits		385,825			333,935
Asset Retirement Obligations		49,720			60,562
Employee Benefits and Pension Obligations		98,684			125,956
Obligations Under Capital Leases		114,017			134,044
Deferred Credits and Other Noncurrent Liabilities		58,659			49,315
TOTAL NONCURRENT LIABILITIES		2,950,075			2,609,716
TOTAL LIABILITIES		3,412,781			3,111,179
Cumulative Preferred Stock Not Subject to Mandatory Redemption		4,697			4,697
Rate Matters (Note 3)
Commitments and Contingencies (Note 4)
EQUITY
Common Stock – Par Value – $18 Per Share:
Authorized –  7,600,000 Shares
Outstanding  – 7,536,640 Shares		135,660			135,660
Paid-in Capital		674,979			674,979
Retained Earnings		862,581			726,478
Accumulated Other Comprehensive Income (Loss)		(11,827	)		(12,991	)
TOTAL COMMON SHAREHOLDER’S EQUITY		1,661,393			1,524,126
Noncontrolling Interest		263			31
TOTAL EQUITY		1,661,656			1,524,157
TOTAL LIABILITIES AND EQUITY	$	5,079,134		$	4,640,033
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

158

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2010 and 2009
(in thousands)
(Unaudited)
	2010			2009
OPERATING ACTIVITIES
Net Income	$	139,473		$	107,211
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization		94,939			109,065
Deferred Income Taxes		1,227			(20,571	)
Extraordinary Loss, Net of Tax		-			5,325
Allowance for Equity Funds Used During Construction		(36,630	)		(31,706	)
Mark-to-Market of Risk Management Contracts		230			510
Pension Contributions to Qualified Plan Trust		(26,684	)		-
Fuel Over/Under-Recovery, Net		(14,371	)		61,880
Change in Other Noncurrent Assets		(16,101	)		13,498
Change in Other Noncurrent Liabilities		41,231			4,539
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		(23,562	)		81,322
Fuel, Materials and Supplies		27,811			4,396
Accounts Payable		(35,890	)		24,584
Accrued Taxes, Net		49,249			50,027
Accrued Interest		(15,085	)		(19,816	)
Other Current Assets		(1,864	)		(1,017	)
Other Current Liabilities		(15,777	)		(53,325	)
Net Cash Flows from Operating Activities		168,196			335,922
INVESTING ACTIVITIES
Construction Expenditures		(288,043	)		(470,379	)
Change in Advances to Affiliates, Net		(161,873	)		(106,662	)
Proceeds from Sales of Assets		1,337			105,500
Other Investing Activities		(474	)		(642	)
Net Cash Flows Used for Investing Activities		(449,053	)		(472,183	)
FINANCING ACTIVITIES
Capital Contribution from Parent		-			142,500
Issuance of Long-term Debt – Nonaffiliated		399,394			-
Borrowings from Revolving Credit Facilities		74,449			90,478
Change in Advances from Affiliates, Net		-			(2,526	)
Retirement of Long-term Debt – Nonaffiliated		(53,500	)		(3,304	)
Retirement of Long-term Debt – Affiliated		(50,000	)		-
Repayments to Revolving Credit Facilities		(78,170	)		(92,377	)
Proceeds from Sale/Leaseback		-			12,222
Principal Payments for Capital Lease Obligations		(8,873	)		(7,853	)
Dividends Paid on Common Stock – Nonaffiliated		(2,966	)		(2,971	)
Dividends Paid on Cumulative Preferred Stock		(172	)		(172	)
Other Financing Activities		916			443
Net Cash Flows from Financing Activities		281,078			136,440
Net Increase in Cash and Cash Equivalents		221			179
Cash and Cash Equivalents at Beginning of Period		1,661			1,910
Cash and Cash Equivalents at End of Period	$	1,882		$	2,089
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts	$	72,270		$	82,033
Net Cash Paid (Received) for Income Taxes		25,575			(6,196	)
Noncash Acquisitions Under Capital Leases		653			26,175
Construction Expenditures Included in Accounts Payable at September 30,		101,017			60,219
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161.

159

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to SWEPCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to SWEPCo.  The footnotes begin on page 161.

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

160

INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to condensed financial statements that follow are a combined presentation for the Registrant Subsidiaries.  The following list indicates the registrants to which the footnotes apply:
1.	Significant Accounting Matters	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
2.	New Accounting Pronouncements and Extraordinary Item	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
3.	Rate Matters	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
4.	Commitments, Guarantees and Contingencies	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
5.	Acquisition	SWEPCo
6.	Benefit Plans	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
7.	Business Segments	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
8.	Derivatives and Hedging	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
9.	Fair Value Measurements	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
10.	Income Taxes	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
11.	Financing Activities	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo

12. Cost Reduction Initiatives APCo, CSPCo, I&M, OPCo, PSO, SWEPCo

161

1.  SIGNIFICANT ACCOUNTING MATTERS

General

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

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary.  Net income for the three and nine months ended September 30, 2010 is not necessarily indicative of results that may be expected for the year ending December 31, 2010.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2009 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2009 as filed with the SEC on February 26, 2010.

Variable Interest Entities

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE.  A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.  Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE as defined by the accounting guidance for “Variable Interest Entities.”  In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, power to direct the VIE and other factors.  Management believes that significant assumptions and judgments were applied consistently.  In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.  Also, see the “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.

SWEPCo is the primary beneficiary of Sabine.  As of January 1, 2010, SWEPCo is no longer the primary beneficiary of DHLC as defined by new accounting guidance for “Variable Interest Entities.”  I&M is the primary beneficiary of DCC Fuel LLC and DCC Fuel II LLC.  APCo, CSPCo, I&M, OPCo, PSO and SWEPCo each hold a significant variable interest in AEPSC.  I&M and CSPCo each hold a significant variable interest in AEGCo.  SWEPCo holds a significant variable interest in DHLC.

Sabine is a mining operator providing mining services to SWEPCo.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee.  In addition, SWEPCo determines how much coal will be mined for each year.  Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine.  SWEPCo’s total billings from Sabine for the three months ended September 30, 2010 and 2009 were $30 million and $34 million, respectively, and for the nine months ended September 30, 2010 and 2009 were $103 million and $95 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on SWEPCo’s Condensed Consolidated Balance Sheets.

DHLC is a mining operator who sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  SWEPCo and CLECO share the executive board seats and its voting rights equally.  Each entity guarantees a 50% share of DHLC’s debt.  SWEPCo and CLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee.  Based on the shared control of DHLC’s operations, management concluded as of January 1, 2010 that SWEPCo is no longer the primary beneficiary and is no longer required to consolidate DHLC.  SWEPCo’s total billings from DHLC for the three months ended September 30, 2010 and 2009 were $14 million

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and $12 million, respectively, and for the nine months ended September 30, 2010 and 2009 were $40 million and $31 million, respectively.  See the tables below for the classification of DHLC’s assets and liabilities on SWEPCo’s Condensed Consolidated Balance Sheet at December 31, 2009 as well as SWEPCo’s investment and maximum exposure as of September 30, 2010.  As of September 30, 2010, DHLC is reported as an equity investment in Deferred Charges and Other Noncurrent Assets on SWEPCo’s Condensed Consolidated Balance Sheet.  Also, see the “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.

The balances below represent the assets and liabilities of the VIEs that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
September 30, 2010
(in millions)
	Sabine
ASSETS
Current Assets	$	42
Net Property, Plant and Equipment		142
Other Noncurrent Assets		35
Total Assets	$	219
LIABILITIES AND EQUITY
Current Liabilities	$	26
Noncurrent Liabilities		193
Equity		-
Total Liabilities and Equity	$	219

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
December 31, 2009
(in millions)
	Sabine		DHLC
ASSETS
Current Assets	$	51	$	8
Net Property, Plant and Equipment		149		44
Other Noncurrent Assets		35		11
Total Assets	$	235	$	63
LIABILITIES AND EQUITY
Current Liabilities	$	36	$	17
Noncurrent Liabilities		199		38
Equity		-		8
Total Liabilities and Equity	$	235	$	63

SWEPCo’s investment in DHLC was:

	September 30, 2010
	As Reported on
	the Consolidated			Maximum
	Balance Sheet			Exposure
	(in millions)
Capital Contribution from SWEPCo		$	7		$	7
Retained Earnings			2			2
SWEPCo's Guarantee of Debt			-			42
Total Investment in DHLC		$	9		$	51

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In September 2009, I&M entered into a nuclear fuel sale and leaseback transaction with DCC Fuel LLC.  In April 2010, I&M entered into a nuclear fuel sale and leaseback transaction with DCC Fuel II LLC.  DCC Fuel LLC and DCC Fuel II LLC (collectively DCC Fuel) were formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions.  Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  Payments on the leases are made semi-annually and began in April 2010.  Payments on the leases for the for the nine months ended September 30, 2010 were $22 million.  No payments were made to DCC Fuel during the third quarter of 2010 and during the year 2009.  The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the 48 and 54 month lease term, respectively.  Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The capital leases are eliminated upon consolidation.  See the tables below for the classification of DCC Fuel’s assets and liabilities on I&M’s Condensed Consolidated Balance Sheets.

The balances below represent the assets and liabilities of the VIE that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
September 30, 2010
(in millions)
	DCC Fuel
ASSETS
Current Assets	$	92
Net Property, Plant and Equipment		118
Other Noncurrent Assets		80
Total Assets	$	290
LIABILITIES AND EQUITY
Current Liabilities	$	65
Noncurrent Liabilities		225
Equity		-
Total Liabilities and Equity	$	290

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
December 31, 2009
(in millions)
	DCC Fuel
ASSETS
Current Assets	$	47
Net Property, Plant and Equipment		89
Other Noncurrent Assets		57
Total Assets	$	193
LIABILITIES AND EQUITY
Current Liabilities	$	39
Noncurrent Liabilities		154
Equity		-
Total Liabilities and Equity	$	193

AEPSC provides certain managerial and professional services to AEP’s subsidiaries.  AEP is the sole equity owner of AEPSC.  AEP management controls the activities of AEPSC.  The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost.  No AEP subsidiary has provided financial or other support outside of the reimbursement of costs for services rendered.  AEPSC finances its operations through cost reimbursement from other AEP subsidiaries.  There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business.  AEPSC and its billings are subject to regulation by the FERC.  AEP’s subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations.  All Registrant Subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure.  However, no Registrant Subsidiary has control over AEPSC.  AEPSC is consolidated by AEP.  In the event AEPSC would require financing

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or other support outside the cost reimbursement billings, this financing would be provided by AEP.

Total AEPSC billings to the Registrant Subsidiaries were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
Company	2010		2009		2010		2009
	(in millions)
APCo	$	51	$	50	$	177	$	146
CSPCo		30		31		104		91
I&M		31		32		106		93
OPCo		41		43		153		130
PSO		23		21		78		64
SWEPCo		31		35		110		94

The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows:

	September 30, 2010						December 31, 2009
	As Reported in the			Maximum			As Reported in the			Maximum
Company	Balance Sheet			Exposure			Balance Sheet			Exposure
	(in millions)
APCo		$	18		$	18		$	23		$	23
CSPCo			10			10			13			13
I&M			11			11			13			13
OPCo			14			14			18			18
PSO			6			6			9			9
SWEPCo			11			11			14			14

AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP.  AEGCo owns a 50% ownership interest in Rockport Plant Unit 1, leases a 50% interest in Rockport Plant Unit 2 and owns 100% of the Lawrenceburg Generating Station.  AEGCo sells all the output from the Rockport Plant to I&M and KPCo.   AEGCo leases the Lawrenceburg Generating Station to CSPCo.  AEP guarantees all the debt obligations of AEGCo.  I&M and CSPCo are considered to have a significant interest in AEGCo due to these transactions.  I&M and CSPCo are exposed to losses to the extent they cannot recover the costs of AEGCo through their normal business operations.  In the event AEGCo would require financing or other support outside the billings to I&M, CSPCo and KPCo, this financing would be provided by AEP.  For additional information regarding AEGCo’s lease, see the “Rockport Lease” section of Note 13 in the 2009 Annual Report.

Total billings from AEGCo were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
Company	2010			2009			2010			2009
	(in millions)
CSPCo		$	44		$	28		$	81		$	60
I&M			64			59			168			183

The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows:

	September 30, 2010						December 31, 2009
	As Reported in						As Reported in
	the Consolidated			Maximum			the Consolidated			Maximum
Company	Balance Sheet			Exposure			Balance Sheet			Exposure
	(in millions)
CSPCo		$	9		$	9		$	6		$	6
I&M			28			28			23			23

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Related Party Transactions

SWEPCo Lignite Purchases from DHLC

Effective January 1, 2010, SWEPCo deconsolidated DHLC due to the adoption of new accounting guidance.  See “ASU 2009-17 ‘Consolidations’ ” section of Note 2.  DHLC sells 50% of its lignite mining output to SWEPCo and the other 50% to CLECO.  SWEPCo purchased $40 million of lignite from DHLC and recorded these costs in Fuel on its Condensed Consolidated Balance Sheet at September 30, 2010.

AEP Power Pool Purchases from OVEC

In January 2010, the AEP Power Pool began purchasing power from OVEC to serve off-system sales and retail sales through June 2010.  Purchases serving off-system sales are reported net as a reduction in Electric Generation, Transmission and Distribution revenues and purchases serving retail sales are reported in Purchased Electricity for Resale expenses on the respective income statements.  The following table shows the amounts recorded for the nine months ended September 30, 2010:

	Nine Months Ended September 30, 2010
	Reported in			Reported in
Company	Revenues			Expenses
	(in thousands)
APCo		$	6,631		$	3,635
CSPCo			3,689			1,963
I&M			3,721			1,980
OPCo			4,248			2,268

SWEPCo Revised Depreciation Rates

Effective December 2009 and May 2010, SWEPCo revised book depreciation rates for its Arkansas and Texas jurisdictions, respectively, as a result of base rate orders.  In comparing 2010 and 2009, the change in depreciation rates resulted in a net decrease in depreciation expense of:

Total Depreciation Expense Variance
Three Months Ended		Nine Months Ended
September 30, 2010/2009		September 30, 2010/2009
(in thousands)
$	9,285	$	19,718

Adjustments to Reported Cash Flows

In the Financing Activities section of SWEPCo’s Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2009, SWEPCo corrected the presentation of borrowings on lines of credit of $90 million from Change in Short-term Debt, Net – Nonaffiliated to Borrowings from Revolving Credit Facilities.  SWEPCo also corrected the presentation of repayments on lines of credit of $92 million for the nine months ended September 30, 2009 to Repayments to Revolving Credit Facilities from Change in Short-term Debt, Net – Nonaffiliated.  The correction to present borrowings and repayments on lines of credit on a gross basis was not material to SWEPCo’s financial statements and had no impact on SWEPCo’s previously reported net income, changes in shareholder’s equity, financial position or net cash flows from financing activities.

Adjustments to Sale of Receivables Disclosure

In the “Sale of Receivables – AEP Credit” section of Note 11, the disclosure was expanded for the Registrant Subsidiaries to reflect certain prior period amounts related to the sale of receivables that were not previously disclosed.  These omissions were not material to the financial statements and had no impact on the Registrant Subsidiaries’ previously reported net income, changes in shareholder’s equity, financial position or cash flows.

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Adjustments to Benefit Plans Footnote

In Note 6 – Benefit Plans, the disclosure was expanded for the Registrant Subsidiaries to reflect certain prior period amounts related to the Net Periodic Benefit Cost and the Estimated Future Benefit Payments and Contributions that were not previously disclosed.  These omissions were not material to the financial statements and had no impact on the Registrant Subsidiaries’ previously reported net income, changes in shareholder’s equity, financial position or cash flows.

2.  NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM

NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business.  The following represents a summary of final pronouncements that impact the financial statements.

Pronouncements Adopted During 2010

The following standard was effective during the first nine months of 2010.  Consequently, its impact is reflected in the financial statements.  The following paragraphs discuss its impact.

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

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

   •   The power to direct the activities of the VIE that most significantly impact the VIE’s economic performance.

   •   The obligation to absorb the losses of the entity that could potentially be significant to the VIE or the right

        to receive benefits from the entity that could potentially be significant to the VIE.

The Registrant Subsidiaries adopted the prospective provisions of ASU 2009-17 effective January 1, 2010.  This standard required separate presentation of material consolidated VIEs’ assets and liabilities on the balance sheets.  Upon adoption, SWEPCo deconsolidated DHLC.  DHLC was deconsolidated due to the shared control between SWEPCo and CLECO.  After January 1, 2010, SWEPCo reports DHLC using the equity method of accounting.

EXTRAORDINARY ITEM

SWEPCo Texas Restructuring

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

3.  RATE MATTERS

As discussed in the 2009 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within the 2009 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition.  The following discusses ratemaking developments in 2010 and updates the 2009 Annual Report.

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Regulatory Assets Not Yet Being Recovered
			APCo					I&M
			September 30,			December 31,		September 30,			December 31,
			2010			2009		2010			2009
	Noncurrent Regulatory Assets (excluding fuel)		(in thousands)					(in thousands)
	Regulatory assets not yet being recovered pending
		future proceedings to determine the recovery
		method and timing:
	Regulatory Assets Currently Earning a Return
		Customer Choice Implementation Costs	$	-		$	-	$	6,650	(a)	$	6,311
	Regulatory Assets Currently Not Earning a Return
		Mountaineer Carbon Capture and Storage Project		59,144			110,665		-			-
		Virginia Environmental Rate Adjustment Clause		48,141			25,311		-			-
		Storm Related Costs		25,225			-		-			-
		Deferred Wind Power Costs		23,794			5,372		-			-
		Virginia Transmission Rate Adjustment Clause		21,088			26,184		-			-
		Special Rate Mechanism for Century Aluminum		12,578			12,422		-			-
		Deferred PJM Fees		-			-		7,200			6,254
	Total Regulatory Assets Not Yet Being Recovered		$	189,970		$	179,954	$	13,850		$	12,565
			CSPCo					OPCo
			September 30,			December 31,		September 30,			December 31,
			2010			2009		2010			2009
	Noncurrent Regulatory Assets (excluding fuel)		(in thousands)					(in thousands)
	Regulatory assets not yet being recovered pending
		future proceedings to determine the recovery
		method and timing:
	Regulatory Assets Currently Earning a Return
		Line Extension Carrying Costs	$	31,915		$	26,590	$	19,993		$	16,278
		Customer Choice Deferrals		29,457			28,781		28,906			28,330
		Storm Related Costs		18,878			17,014		10,881			9,794
		Acquisition of Monongahela Power		7,483			10,282		-			-
		Economic Development Rider		3,014			-		3,014			-
	Regulatory Assets Currently Not Earning a Return
		Acquisition of Monongahela Power		4,052			-		-			-
		Peak Demand Reduction/Energy Efficiency		-	(b)		4,071		-	(b)		4,007
	Total Regulatory Assets Not Yet Being Recovered		$	94,799		$	86,738	$	62,794		$	58,409
			PSO					SWEPCo
			September 30,			December 31,		September 30,			December 31,
			2010			2009		2010			2009
	Noncurrent Regulatory Assets (excluding fuel)		(in thousands)					(in thousands)
	Regulatory assets not yet being recovered pending
		future proceedings to determine the recovery
		method and timing:
	Regulatory Assets Currently Not Earning a Return
		Storm Related Costs	$	17,256		$	-	$	-		$	-
		Asset Retirement Obligation		-			-		588			471
	Total Regulatory Assets Not Yet Being Recovered		$	17,256		$	-	$	588		$	471
	(a)  In October 2010, the Michigan base rate settlement agreement was approved which granted recovery of this regulatory asset.
	(b)  Recovery of regulatory asset was granted during 2010.

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CSPCo and OPCo Rate Matters

Ohio Electric Security Plan Filings

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

The order provides a FAC for the three-year period of the ESP.  The FAC increase will be phased in to avoid having the resultant rate increases exceed the ordered annual caps described above.  The FAC increase is subject to quarterly true-ups, annual accounting audits and prudency reviews.  See the “2009 Fuel Adjustment Clause Audit” section below.  The order allows CSPCo and OPCo to defer any unrecovered FAC costs resulting from the annual caps and to accrue associated carrying charges at CSPCo’s and OPCo’s weighted average cost of capital.  Any deferred FAC regulatory asset balance at the end of the three-year ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018.  That recovery will include deferrals associated with the Ormet interim arrangement and is subject to the PUCO’s ultimate decision regarding the Ormet interim arrangement deferrals plus related carrying charges.  See the “Ormet Interim Arrangement” section below.  The FAC deferrals as of September 30, 2010 were $15 million and $433 million for CSPCo and OPCo, respectively, excluding $2 million and $24 million, respectively, of unrecognized equity carrying costs.

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

The Ohio Consumers’ Counsel filed a notice of appeal with the Supreme Court of Ohio raising several issues including alleged retroactive ratemaking, recovery of carrying charges on certain environmental investments, Provider of Last Resort (POLR) charges and the decision not to offset rates by off-system sales margins.  A decision from the Supreme Court of Ohio is pending.

In November 2009, the Industrial Energy Users-Ohio filed a notice of appeal with the Supreme Court of Ohio challenging components of the ESP order including the POLR charge, the distribution riders for gridSMARTSM and enhanced reliability, the PUCO’s conclusion and supporting evaluation that the modified ESPs are more favorable than the expected results of a market rate offer, the unbundling of the fuel and non-fuel generation rate components, the scope and design of the fuel adjustment clause and the approval of the plan after the 150-day statutory deadline.  A decision from the Supreme Court of Ohio is pending.

In April 2010, the Industrial Energy Users-Ohio filed an additional notice of appeal with the Supreme Court of Ohio challenging alleged retroactive ratemaking, CSPCo's and OPCo's abilities to collect through the FAC amounts deferred under the Ormet interim arrangement and the approval of the plan after the 150-day statutory deadline.  A decision from the Supreme Court of Ohio is pending.

In 2009, the PUCO convened a workshop to determine the methodology for the Significantly Excessive Earnings Test (SEET).  Ohio law requires that the PUCO determine, following the end of each year of the ESP, if rate adjustments included in the ESP resulted in significantly excessive earnings.  If the rate adjustments, in the aggregate, result in significantly excessive earnings, the excess amount could be returned to customers.    The PUCO heard arguments related to various SEET issues including the treatment of the FAC deferrals.  Management believes that CSPCo and OPCo should not be required to refund unrecovered FAC regulatory assets until they are collected, even assuming there are significantly excessive earnings in that year.  In June 2010, the PUCO issued an order resolving some of the SEET issues.  The PUCO determined that the earnings of CSPCo and OPCo shall be calculated on an individual company basis and not on a combined CSPCo/OPCo basis.  The PUCO ruled that many issues, including the treatment of deferrals and off-system sales, should be determined on a case-by-case basis.  The PUCO’s decision on the SEET methodology is not expected to be finalized until after the PUCO issues an order on the SEET filings.  In September 2010, CSPCo and OPCo filed their 2009 SEET filings with the PUCO.  CSPCo’s and OPCo’s returns on common equity were 20.84% and 10.81%, respectively, including off-system sales margins and 18.31% and 9.42%, respectively, excluding off-system sales margins.  Included in the filings was CSPCo’s and OPCo’s determination that the level at which

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their earned return on common equity may become significantly in excess of the average earned return on common equity of the comparable risk group of publicly traded firms was 22.51%.  Based upon the methodology proposed by CSPCo and OPCo in the SEET filings, neither CSPCo’s nor OPCo’s 2009 return on common equity was significantly excessive.  In October 2010, the PUCO staff filed testimony that recommended a return on common equity over 16.05% as significantly excessive but did not address whether adjustments for off-system sales (OSS) and deferrals should be made to reduce the return.  Also, in October 2010, intervenors, including the Ohio Consumers’ Counsel, filed testimony with the PUCO recommending an acceptable return on common equity in the range of 11.58% to 13.58%.  As a result, the intervenors recommended CSPCo refund up to $156 million of its 2009 earnings.  If the PUCO determines that CSPCo’s and/or OPCo’s 2009 return on common equity was significantly excessive, CSPCo and/or OPCo may be required to return a portion of their ESP revenues to customers.

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

Proposed CSPCo and OPCo Merger

In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo.  Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company.  The merger is also subject to regulatory approval by the FERC.  CSPCo and OPCo anticipate completion of the merger during 2011.

Requested Sporn Unit 5 Shutdown and Proposed Distribution Rider

In October 2010, OPCo filed an application with the PUCO for the approval of a December 2010 closure of Sporn Unit 5 and the simultaneous establishment of a new non-bypassable distribution rider, outside the rate caps established in the ESP proceeding.  The proposed rider would recover the net book value of the unit as well as related materials and supplies as of December 2010, which is estimated to be $59 million, as well as future closure costs incurred after December 2010.  OPCo also requested the PUCO to grant accounting authority to record the future closure costs as a regulatory asset or regulatory liability with a weighted average cost of capital carrying charge to be included in the proposed non-bypassable distribution rider after they are incurred.  Also in October 2010, OPCo filed a retirement notification with PJM pending PUCO approval of OPCo’s application to close Sporn Unit 5.  Absent PUCO approval, management intends to operate Sporn Unit 5 through 2013.  Management is unable to predict the outcome of this proceeding.

2009 Fuel Adjustment Clause Audit

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

Ormet Interim Arrangement

CSPCo, OPCo and Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet.  This interim arrangement was approved by the PUCO and was effective from January 2009 through September 2009.  In March 2009, the PUCO approved a FAC in the ESP filings.  The approval of the FAC, together with the PUCO approval of the interim arrangement, provided the basis to record regulatory assets for the difference between the approved market price and the rate paid by Ormet.  Through September 2009, the last month of the interim arrangement, CSPCo and OPCo had $30 million and $34 million, respectively, of deferred FAC related to the interim arrangement including recognized carrying charges but excluding $1 million and $1 million, respectively, of unrecognized equity carrying costs.  In

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

Economic Development Rider

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

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

As of September 30, 2010, CSPCo and OPCo have incurred $39 million and $30 million, respectively, in EDR costs including carrying costs.  Of these costs, CSPCo and OPCo have collected $27 million and $20 million, respectively, through the EDR, which CSPCo and OPCo began collecting in January 2010.  The remaining $12 million and $10 million for CSPCo and OPCo, respectively, are recorded as EDR regulatory assets.  If CSPCo and OPCo are not ultimately permitted to recover their deferrals or are required to refund revenue collected, it would reduce future net income and cash flows and impact financial condition.

Environmental Investment Carrying Cost Rider

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

Ohio IGCC Plant

In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant.  Through September 30, 2010, CSPCo and OPCo have each collected $12 million in pre-construction costs authorized in a June 2006 PUCO order and each incurred $11 million in pre-construction costs.  As a result, CSPCo and OPCo each established a net regulatory liability of approximately $1 million.  The order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant before June 2011, all pre-construction costs that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest.  Intervenors have filed motions with the PUCO requesting all pre-construction costs be refunded to Ohio ratepayers with interest.

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

SWEPCo Rate Matters

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in service in 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, plus an additional $132 million for transmission, excluding AFUDC.  SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $132 million for transmission, excluding AFUDC.  As of September 30, 2010, excluding costs attributable to its joint owners, SWEPCo has capitalized approximately $957 million of expenditures (including AFUDC and capitalized interest of $121 million and related transmission costs of $58 million).  As of September 30, 2010, the joint owners and SWEPCo have contractual construction commitments of approximately $339 million (including related transmission costs of $5 million).  SWEPCo’s share of the contractual construction commitments is $249 million.  If the plant is cancelled, the joint owners and SWEPCo would incur contractual construction cancellation fees, based on construction status as of September 30, 2010, of approximately $121million (including related transmission cancellation fees of $1 million).  SWEPCo’s share of the contractual construction cancellation fees would be approximately $89 million.

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

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

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

The LPSC approved SWEPCo’s application to construct the Turk Plant.  The Sierra Club petitioned the LPSC to begin an investigation into the construction of the Turk Plant which was rejected by the LPSC.  The Sierra Club later refiled its petition as a stand alone complaint proceeding.  SWEPCo filed a motion to dismiss and denied the allegations in the complaint.  In October 2010, an Administrative Law Judge recommended the LPSC dismiss the complaint.

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

The wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009.  In February 2010, the Sierra Club, the Audubon Society and others filed a complaint in the Federal District Court for the Western District of Arkansas against the U.S. Army Corps of Engineers challenging the process used and the terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts.  In May 2010, plaintiffs filed with the Federal District Court for the Western District of Arkansas seeking a preliminary injunction to halt construction and for a temporary restraining order.  

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 the Interior and the U.S. Fish and Wildlife Service seeking a temporary restraining order and preliminary injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws.  The plaintiffs' federal law claims challenge the process used and terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts.  The plaintiffs' state law claims challenge SWEPCo's ability to construct the Turk Plant without obtaining a certificate from the APSC.  This motion for preliminary injunction was heard simultaneously with the motion filed by the Sierra Club.  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.

In January 2009, SWEPCo was granted CECPNs by the APSC to build three transmission lines and facilities authorized by the SPP and needed to transmit power from the Turk Plant.  Intervenors appealed the CECPN decisions in April 2009 to the Arkansas Court of Appeals.  In July 2010, the Hempstead County Hunting Club and other appellants filed with the Arkansas Court of Appeals emergency motions to stay the transmission CECPNs to prohibit SWEPCo from taking ownership of private property and undertaking construction of the transmission lines.  In July 2010, the Arkansas Court of Appeals issued a decision remanding all transmission line CECPN appeals to the APSC.  As a result, a stay was not ordered and construction continues on the affected transmission lines.  A hearing is scheduled for January 2011.

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

Stall Unit

SWEPCo constructed the Stall Unit, an intermediate load 500 MW natural gas-fired combustion turbine combined cycle generating unit, at its existing Arsenal Hill Plant located in Shreveport, Louisiana.  The LPSC and the APSC issued orders capping SWEPCo’s Stall Unit construction costs at $445 million including AFUDC and excluding related transmission costs.  The Stall Unit was placed in service in June 2010.  As of September 30, 2010, the Stall Unit cost $423 million, including $49 million of AFUDC.  Management does not expect the final costs of the Stall Unit to exceed the ordered cap.  In July 2010, the Stall Unit was placed into Arkansas rates.  SWEPCo received CWIP treatment for a portion of the Stall Unit in the 2009 Texas Base Rate Filing.  See “2009 Texas Base Rate Filing” section below.  The Stall Unit will be phased into Louisiana rate base between October 2010 and October 2011.

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Louisiana Fuel Adjustment Clause Audit

Consultants for the LPSC issued their audit report of SWEPCo’s Louisiana retail FAC.  The audit report included a significant recommendation that might result in a financial impact that could be material for SWEPCo.  The audit report recommended that the LPSC discontinue SWEPCo’s tiered sharing mechanism related to off-system sales margins on a prospective basis and that SWEPCo included inappropriate costs in the FAC.  In September 2010, the LPSC consultants filed testimony supporting their audit report findings but did not quantify their recommendations.  Hearings are scheduled for January 2011.  Management is unable to predict how the LPSC will rule on the recommendations in the audit report and its financial statement impact on net income, cash flows and financial condition.

2009 Texas Base Rate Filing

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

Texas Fuel Reconciliation

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

In September 2010, the Administrative Law Judges issued a Proposal for Decision (PFD) that recommended a disallowance of a significant portion of the charges to a ten-year gas transportation agreement that began in 2009 for the Mattison Plant located in Northwest Arkansas.  The PFD stated that SWEPCo should have pursued other transportation options or sought the supplier’s recourse rate from the FERC.  The estimated recommended disallowance over the ten-year period through December 2018 is $107 million for which the estimated Texas jurisdictional portion is $37 million.  In addition, the PFD also contained recommendations to disallow risk premiums related to the ERCOT trading contracts transferred to AEPEP which are estimated to be $1.5 million on a Texas retail jurisdictional basis.  Through September 30, 2010, SWEPCo’s management estimated the impact of this PFD, if adopted by the PUCT, to be $7 million.  In October 2010, SWEPCo filed exceptions on these issues with the PUCT.  An order may be issued in the fourth quarter of 2010.  Management is unable to predict the outcome of this reconciliation.  If the PUCT disallows any portion of SWEPCo’s fuel and purchase power costs, it could reduce future net income and cash flows and possibly impact financial condition.

Louisiana 2008 Formula Rate Filing

In April 2008, SWEPCo filed its first formula rate filing under an approved three-year formula rate plan (FRP).  SWEPCo requested an increase in its annual Louisiana retail rates of $11 million to be effective in August 2008 in order to earn the approved formula return on common equity of 10.565%.  In August 2008, as provided by the FRP, SWEPCo implemented the FRP rates, subject to refund.  During 2009, SWEPCo recorded a provision for refund of approximately $1 million after reaching a settlement in principle with intervenors.  A settlement stipulation was reached by the parties and is pending LPSC approval.

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Louisiana 2009 Formula Rate Filing

In April 2009, SWEPCo filed the second FRP which would increase its annual Louisiana retail rates by an additional $4 million effective in August 2009.  SWEPCo implemented the FRP rate increase as filed in August 2009, subject to refund.  In October 2009, consultants for the LPSC objected to certain components of SWEPCo’s FRP calculation.  SWEPCo is currently in settlement discussions.  If a refund is required, it could reduce future net income and cash flows and impact financial condition.

Louisiana 2010 Formula Rate Filing

In April 2010, SWEPCo filed the third FRP which would decrease its annual Louisiana retail rates by $3 million effective in August 2010 pursuant to the approved FRP, subject to refund.  SWEPCo believes the rates as filed are in compliance with the FRP methodology previously approved by the LPSC.  If the LPSC disagrees with SWEPCo, it could result in refunds which could reduce future net income and cash flows and impact financial condition.

APCo Rate Matters

2009 Virginia Base Rate Case

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

2010 West Virginia Base Rate Case

In May 2010, APCo filed a request with the WVPSC to increase annual base rates by $140 million based on an 11.75% return on common equity to be effective March 2011.  Hearings are scheduled for December 2010.  A decision from the WVPSC is expected in March 2011.

Mountaineer Carbon Capture and Storage Project

APCo and ALSTOM Power, Inc., an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009.  APCo also constructed and owns the necessary facilities to store the CO2.  In October 2009, APCo started injecting CO2 into the underground storage facilities.  The injection of CO2 required the recording of an asset retirement obligation and an offsetting regulatory asset.  Through September 30, 2010, APCo has recorded a noncurrent regulatory asset of $59 million related to the Mountaineer Carbon Capture and Storage Project.

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

In APCo’s May 2010 West Virginia base rate filing, APCo requested recovery of and a return on its West Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion.  If APCo cannot recover its remaining investment 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.

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APCo’s Filings for an IGCC Plant

APCo filed a petition with the WVPSC requesting approval of a Certificate of Public Convenience and Necessity (CPCN) to construct a 629 MW IGCC power plant in Mason County, West Virginia.  APCo also requested the Virginia SCC and the WVPSC to approve a surcharge rate mechanism to provide for the timely recovery of pre-construction costs and the ongoing financing costs of the project during the construction period, as well as the capital costs, operating costs and a return on common equity once the facility is placed into commercial operation.  The WVPSC granted APCo the CPCN and approved the requested cost recovery.  Various intervenors filed petitions with the WVPSC to reconsider the order.

In 2008, the Virginia SCC issued an order denying APCo’s request for a surcharge rate mechanism based upon its finding that the estimated cost of the plant was uncertain and may escalate.  The Virginia SCC also expressed concerns that the estimated costs did not include a retrofitting of carbon capture and sequestration facilities.  During 2009, based on an unfavorable order received in Virginia, the WVPSC removed the IGCC case as an active case from its docket and indicated that the conditional CPCN granted in 2008 must be reconsidered if and when APCo proceeds forward with the IGCC plant.

Through September 30, 2010, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $9 million applicable to its Virginia jurisdiction.

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

APCo’s 2009 Expanded Net Energy Charge (ENEC) Filing

In September 2009, the WVPSC issued an order approving APCo’s March 2009 ENEC request.  The approved order provided for recovery of an under-recovered balance plus a projected increase in ENEC costs over a four-year phase-in period with an overall increase of $320 million and a first-year increase of $112 million, effective October 2009.  The WVPSC also approved a fixed annual carrying cost rate of 4%, effective October 2009, to be applied to the incremental deferred regulatory asset balance that will result from the phase-in plan and lowered annual coal cost projections by $27 million.  As of September 30, 2010, APCo’s ENEC under-recovery balance was $365 million, excluding $1 million of unrecognized equity carrying costs, which is included in noncurrent regulatory assets.

In June 2010, a settlement agreement for $86 million, including $9 million of construction surcharges, was filed with the WVPSC related to APCo’s second year ENEC increase.  The settlement agreement provided for recovery of the amounts related to the renegotiated coal contracts and allows APCo to accrue weighted average cost of capital carrying costs on the excess under-recovery balance due to the ENEC phase-in as adjusted for the impacts of Accumulated Deferred Income Taxes.  In June 2010, the WVPSC approved the settlement agreement which made rates effective in July 2010.

WPCo Merger with APCo

In a proceeding established by the WVPSC to explore options to meet WPCo's future power supply requirements, the WVPSC, in November 2009, issued an order approving a joint stipulation among APCo, WPCo, the WVPSC staff and the Consumer Advocate Division.  The order approved the recommendation of the signatories to the stipulation that WPCo merge into APCo and be supplied from APCo's existing power resources.  Merger approvals from the WVPSC, Virginia SCC and the FERC are required.  No merger approval filings have been made.

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PSO Rate Matters

PSO Fuel and Purchased Power

2006 and Prior Fuel and Purchased Power

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

A reallocation of purchased power costs among AEP West companies for periods prior to 2002 resulted in an under-recovery of $42 million of PSO fuel costs.  PSO recovered the $42 million by offsetting it against an existing fuel over-recovery during the period June 2007 through May 2008.  The Oklahoma Industrial Energy Consumers (OIEC) has contended that PSO should not have collected the $42 million without specific OCC approval.  As such, the OIEC contends that the OCC should require PSO to refund the $42 million it collected through its fuel clause.  The OCC has heard the OIEC appeal and a decision is pending.  In March 2010, PSO filed motions to advance this proceeding since the FERC has ruled on the allocation of off-system sales margins and PSO has refunded the additional margins to its retail customers.  If the OCC were to order PSO to refund all or a part of the $42 million, it would reduce future net income and cash flows and impact financial condition.

2008 Fuel and Purchased Power

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

2008 Oklahoma Base Rate Appeal

In January 2009, the OCC issued a final order approving an $81 million increase in PSO’s non-fuel base revenues based on a 10.5% return on common equity.  The new rates reflecting the final order were implemented with the first billing cycle of February 2009.  PSO and intervenors filed appeals with the Oklahoma Supreme Court raising various issues.  The Oklahoma Supreme Court assigned the case to the Court of Civil Appeals.  In June 2010, the Court of Civil Appeals affirmed the OCC's decision.  No parties sought rehearing or appeal and, as a result, this case has concluded.

2010 Oklahoma Base Rate Case

In July 2010, PSO filed a request with the OCC to increase annual base rates by $82 million, including $30 million that is currently being recovered through a rider.  The requested net annual increase to ratepayers would be $52 million.  The requested increase includes a $24 million increase in depreciation and an 11.5% return on common equity.  In October 2010, various parties, including the OCC staff, filed testimony regarding PSO’s requested base rate increase.  These parties proposed that PSO's request to increase depreciation rates be denied and that existing depreciation rates continue.  PSO’s request to move the $30 million currently recovered through a rider to base rates was not opposed.  The parties’ net annual rate recommendations ranged from a rate reduction of $18 million to an increase of less than $1 million based on a recommended return on common equity range from 9.5% to 10%.  A hearing is scheduled for December 2010.

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I&M Rate Matters

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

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

As fully discussed in the “Cook Plant Unit 1 Fire and Shutdown” section of Note 4, Cook Unit 1 (Unit 1) was shut down in September 2008 due to significant turbine damage and a small fire on the electric generator.  Unit 1 was placed back into service in December 2009 at slightly reduced power.  The unit outage resulted in increased replacement power fuel costs.  The filing only requested the cost of replacement power through mid-December 2008, the date when I&M began receiving accidental outage insurance proceeds.  I&M committed to absorb the remaining costs of replacement power through the date the unit returned to service, which occurred in December 2009.

I&M reached an agreement with intervenors, which was approved by the IURC in March 2009, to collect its existing prior period under-recovery regulatory asset deferral balance over twelve months instead of over six months as initially proposed.  Under the agreement, the fuel factors were placed into effect, subject to refund, and a subdocket was established to consider issues relating to the Unit 1 shutdown including the treatment of the accidental outage insurance proceeds.  I&M maintains a separate accidental outage policy with NEIL.  In 2009, I&M recorded $185 million in revenue under the policy and reduced the cost of replacement power in customers’ bills by $78 million.  In October 2010, the Indiana/Michigan Industrial Group and the Indiana Office of Utility Consumer Counselor filed testimony which recommended I&M pay to customers a portion of the accidental outage insurance proceeds up to the extent not previously paid to customers through the fuel adjustment clause or needed to cover costs not covered by I&M’s property damage insurance policy.  Hearings are scheduled to be held in January 2011.

Management believes that I&M is entitled to retain the accidental outage insurance proceeds since it made customers whole regarding the replacement power costs.  If any fuel clause revenues or accidental outage insurance proceeds have to be paid to customers, it would reduce future net income and cash flows and impact financial condition.

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

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

Michigan Base Rate Filing

In January 2010, I&M filed with the MPSC a request for a $63 million increase in annual base rates based on an 11.75% return on common equity.  Starting with the August 2010 billing cycle, I&M, with the MPSC authorization, implemented a $44 million interim rate increase.  The interim increase excluded new trackers and regulatory assets for which I&M was not currently incurring expenses.  In October 2010, a settlement agreement was approved by the MPSC to increase annual base rates by $36 million based on a 10.35% return on common equity, effective December 2010, plus separate recovery of approximately $7 million of customer choice implementation costs over a two year period beginning April 2011.  In addition, the approved revenue requirement includes the amortization of $6 million in previously expensed restructuring costs over five years, which I&M will defer and begin amortizing in the fourth quarter of 2010.  Also, the approved settlement agreement provided for sharing of off-system sales margins between customers (75%) and I&M (25%) with customers receiving a credit in future Power Supply Cost Recovery proceedings for their jurisdictional share of any off-system sales margins.  In September 2010, I&M recorded a provision for refund of $2 million, including interest, related to the implementation of interim rates.

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FERC Rate Matters

Regional Transmission Rate Proceedings at the FERC – Affecting APCo, CSPCo, I&M and OPCo

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund

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

Company	(in millions)
APCo	$	70.2
CSPCo		38.8
I&M		41.3
OPCo		53.3

In 2006, a FERC Administrative Law Judge (ALJ) issued an initial decision finding that the rate design for the recovery of SECA charges was flawed and that a large portion of the “lost revenues” reflected in the SECA rates should not have been recoverable.  The ALJ found that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made.  The ALJ also found that any unpaid SECA rates must be paid in the recommended reduced amount.

AEP filed briefs jointly with other affected companies noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision.  In May 2010, the FERC issued an order that generally supports AEP’s position and requires a compliance filing to be filed with the FERC by August 2010.  In June 2010, AEP and other affected companies filed a joint request for rehearing with the FERC regarding certain matters including a request to clarify the method for determining the amount of such revenues.  The request also asked the FERC to clarify that interest may be added to SECA charges originally billed to but never paid by Green Mountain Energy (reassigned to British Petroleum Energy).  Eight other groups also filed requests for rehearing with the FERC.

The AEP East companies provided reserves for net refunds for SECA settlements totaling $44 million applicable to the $220 million of SECA revenues collected.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the provision are as follows:

Company	(in millions)
APCo	$	14.1
CSPCo		7.8
I&M		8.3
OPCo		10.7

Settlements approved by the FERC consumed $10 million of the reserve for refunds applicable to $112 million of SECA revenue.  The balance in the reserve for future settlements as of September 30, 2010 was $34 million.  APCo’s, CSPCo’s, I&M’s and OPCo’s reserve balances at September 30, 2010 were:

Company	September 30, 2010
	(in millions)
APCo	$	10.7
CSPCo		5.9
I&M		6.3
OPCo		8.1

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In August 2010, the affected companies, including the AEP East companies, filed a compliance filing with the FERC.  If the compliance filing is accepted, the AEP East companies would have to pay refunds of approximately $20 million including estimated interest of $5 million.  The AEP East companies could also potentially receive payments up to approximately $12 million including estimated interest of $3 million.  A decision is pending from the FERC.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of potential refund payments and potential payments received are as follows:

Company	Potential Refund Payments		Potential Payments Received
	(in millions)
APCo	$	6.4	$	3.8
CSPCo		3.5		2.1
I&M		3.7		2.2
OPCo		4.8		2.9

Based on the AEP East companies’ analysis of the May 2010 order and the compliance filing, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the May 2010 order or the compliance filing be made final.  Management cannot predict the ultimate outcome of this proceeding at the FERC which could impact future net income and cash flows.

Allocation of Off-system Sales Margins – Affecting SWEPCo

The OCC filed a complaint at the FERC alleging that AEP inappropriately allocated off-system sales margins between the AEP East companies and the AEP West companies and did not properly allocate off-system sales margins within the AEP West companies.

In 2009, AEP made a compliance filing with the FERC and the AEP East companies refunded approximately $250 million to the AEP West companies.  Following authorized regulatory treatment, the AEP West companies shared a portion of SIA margins with their customers during the period June 2000 to March 2006.  In 2008, the AEP West companies recorded a provision for refund reflecting the sharing.  Refunds have been or are currently being returned to PSO, SWEPCo and FERC customers.  Management believes the AEP West companies’ provision for refund is adequate.

Modification of the Transmission Agreement (TA) – Affecting APCo, CSPCo, I&M and OPCo

APCo, CSPCo, I&M, KPCo and OPCo are parties to the TA that provides for a sharing of the cost of transmission lines operated at 138-kV and above and transmission stations containing extra-high voltage facilities.  In June 2009, AEPSC, on behalf of the parties to the TA, filed with the FERC a request to modify the TA.  Under the proposed amendments, KGPCo and WPCo will be added as parties to the TA.  In addition, the amendments would provide for the allocation of PJM transmission costs on the basis of the TA parties’ 12-month coincident peak and reimburse transmission revenues based on individual cost of service instead of the MLR method used in the present TA.  AEPSC requested the effective date to be the first day of the month following a final non-appealable FERC order.  The delayed effective date was approved by the FERC when the FERC accepted the new TA for filing.  In August 2010, a settlement agreement was filed with the FERC.  In October 2010, the FERC approved the new TA effective November 1, 2010.  The impacts of the settlement agreement will be phased-in for retail rate making purposes in certain jurisdictions over periods of up to four years.  However, management is unable to predict whether the parties to the TA will experience regulatory lag and its effect on future net income and cash flows.

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PJM Transmission Formula Rate Filing – Affecting APCo, CSPCo, I&M and OPCo

AEP filed an application with the FERC in July 2008 to increase its open access transmission tariff (OATT) rates for wholesale transmission service within PJM.  The filing sought to implement a formula rate allowing annual adjustments reflecting future changes in the AEP East companies' cost of service.  The FERC issued an order conditionally accepting AEP’s proposed formula rate and delayed the requested October 2008 effective date for five months.  AEP began settlement discussions with the intervenors and the FERC staff which resulted in a settlement that was filed with the FERC in April 2010.

The pending settlement results in a $51 million annual increase beginning in April 2009 for service as of March 2009, of which approximately $7 million is being collected from nonaffiliated customers within PJM.  The remaining $44 million is being billed to the AEP East companies and is generally offset by compensation from PJM for use of the AEP East companies’ transmission facilities so that net income is not directly affected.

The pending settlement also results in an additional $30 million increase for the first annual update of the formula rate, beginning in August 2009 for service as of July 2009.  Approximately $4 million of the increase will be collected from nonaffiliated customers within PJM with the remaining $26 million being billed to the AEP East companies.

Under the formula, an annual update will be filed to be effective July 2010 and each year thereafter.  Also, beginning with the July 2010 update, the rates each year will include an adjustment to true-up the prior year's collections to the actual costs for the prior year.  In May 2010, the second annual update was filed with the FERC to decrease the revenue requirement by $58 million for service as of July 2010.  Approximately $8 million of the decrease will be refunded to nonaffiliated customers within PJM.  In October 2010, the settlement agreement was approved by the FERC.

Transmission Agreement (TA) – Affecting APCo, CSPCo, I&M and OPCo

Certain transmission facilities placed in service in 1998 were inadvertently excluded from the AEP East companies’ TA calculation prior to January 2009.  The excluded equipment was KPCo’s Inez Station which had been determined as eligible equipment for inclusion in the TA in 1995 by the AEP TA transmission committee.  The amount involved was $7 million annually.  In June 2010, the KPSC approved a settlement agreement in KPCo’s base rate filing which set new base rates effective July 2010 but excluded consideration of this issue.

PJM/MISO Market Flow Calculation Settlement Adjustments - Affecting APCo, CSPCo, I&M and OPCo

During 2009, an analysis conducted by MISO and PJM discovered several instances of unaccounted for power flows on numerous coordinated flowgates.  These flows affected the settlement data for congestion revenues and expenses and date back to the start of the MISO market in 2005.  PJM has provided MISO an initial analysis of amounts they believe they owe MISO.  MISO disputes PJM’s methodology.

Settlement discussions between MISO and PJM have been unsuccessful, and as a result, in March 2010, MISO filed two related complaints against PJM at the FERC related to the above claim.  MISO seeks to recover a total of approximately $145 million from PJM.  If PJM is held liable for these damages, PJM members, including the AEP East companies, may be billed for a share of the refunds or payments PJM is directed to make to MISO.  AEP has intervened and filed a protest to one complaint.  Management believes that MISO's claims are without merit and that PJM's right to recover any MISO damages from AEP and other members is limited.  If the FERC orders a settlement above the AEP East companies’ reserve related to their estimated portion of PJM additional costs, it could reduce future net income and cash flows and impact financial condition.

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4.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business.  In addition, their business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation cannot be predicted.  For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on the financial statements.  The Commitments, Guarantees and Contingencies note within the 2009 Annual Report should be read in conjunction with this report.

GUARANTEES

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

Letters of Credit – Affecting APCo, I&M, OPCo and SWEPCo

Certain Registrant Subsidiaries enter into standby letters of credit with third parties.  These letters of credit cover items such as insurance programs, security deposits and debt service reserves.  These letters of credit were issued in the ordinary course of business under the two $1.5 billion credit facilities, of which $750 million may be issued under one credit facility as letters of credit.  In June 2010, AEP terminated one of the $1.5 billion facilities that was scheduled to mature in March 2011 and replaced it with a new $1.5 billion credit facility which matures in 2013 and allows for the issuance of up to $600 million as letters of credit.

In June 2010, the Registrant Subsidiaries and certain other companies in the AEP System reduced the $627 million credit agreement to $478 million.  As of September 30, 2010, $477 million of letters of credit were issued by Registrant Subsidiaries under the agreement to support variable rate Pollution Control Bonds.

At September 30, 2010, the maximum future payments of the letters of credit were as follows:

				Borrower
Company	Amount		Maturity	Sublimit
	(in thousands)			(in thousands)
$1.5 billion letters of credit:
I&M	$	300	March 2011		N/A
SWEPCo		4,448	December 2010		N/A
$478 million letter of credit:
APCo	$	232,292	November 2010 to April 2011	$	300,000
I&M		77,886	April 2011		230,000
OPCo		166,899	April 2011		400,000

Guarantees of Third-Party Obligations – Affecting SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of approximately $65 million.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), a consolidated variable interest entity.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  As of September 30, 2010, SWEPCo has collected approximately $47 million through a rider for final mine closure and reclamation costs, of which $1 million is recorded in Other Current Liabilities, $23 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $23 million is recorded in Asset Retirement Obligations on SWEPCo’s Condensed Consolidated Balance Sheets.

Sabine charges SWEPCo, its only customer, all of its costs.  SWEPCo passes these costs to customers through its fuel clause.

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Indemnifications and Other Guarantees – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

Contracts

The Registrant Subsidiaries enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  Prior to September 30, 2010, the Registrant Subsidiaries entered into sale agreements including indemnifications with a maximum exposure that was not significant for any individual Registrant Subsidiary.  There are no material liabilities recorded for any indemnifications.

The AEP East companies, PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to power purchase and sale activity conducted pursuant to the SIA.

Master Lease Agreements

The Registrant Subsidiaries lease certain equipment under master lease agreements.  GE Capital Commercial Inc. (GE) notified management in November 2008 that they elected to terminate the Master Leasing Agreements in accordance with the termination rights specified within the contract.  In 2011, the Registrant Subsidiaries will be required to purchase all equipment under the lease and pay GE an amount equal to the unamortized value of all equipment then leased.  Management is currently in negotiations to replace this agreement.  In December 2008 and 2009, management signed new master lease agreements that include lease terms of up to 10 years.

For equipment under the GE master lease agreements that expire in 2011, the lessor is guaranteed receipt of up to 87% of the unamortized balance of the equipment at the end of the lease term.  If the fair value of the leased equipment is below the unamortized balance at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the fair value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance.  Under the new master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee.  At September 30, 2010, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows:

	Maximum
	Potential
Company	Loss
	(in thousands)
APCo		$	294
CSPCo			70
I&M			181
OPCo			411
PSO			323
SWEPCo			231

Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.

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Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease is accounted for as an operating lease.  In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignment is accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $18 million for I&M and $20 million for SWEPCo for the remaining railcars as of September 30, 2010.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 84% under the current five year lease term to 77% at the end of the 20 year term of the projected fair value of the equipment.  I&M and SWEPCo have assumed the guarantee under the return-and-sale option.  I&M’s maximum potential loss related to the guarantee is approximately $12 million ($8 million, net of tax) and SWEPCo’s is approximately $13 million ($9 million, net of tax) assuming the fair value of the equipment is zero at the end of the current five-year lease term.  However, management believes that the fair value would produce a sufficient sales price to avoid any loss.

The Registrant Subsidiaries have other railcar lease arrangements that do not utilize this type of financing structure.

ENVIRONMENTAL CONTINGENCIES

Federal EPA Complaint and Notice of Violation – Affecting CSPCo

The Federal EPA, certain special interest groups and a number of states alleged that APCo, CSPCo, I&M and OPCo modified certain units at their coal-fired generating plants in violation of the NSR requirements of the CAA.  Cases with similar allegations against CSPCo, Dayton Power and Light Company and Duke Energy Ohio, Inc. were also filed related to their jointly-owned units.  The cases were settled with the exception of a case involving a jointly-owned Beckjord unit which had a liability trial.  Following the trial, the jury found no liability for claims made against the jointly-owned Beckjord unit.  Following a second liability trial in 2009, the jury again found no liability at the jointly-owned Beckjord unit.  The defendants and the plaintiffs appealed to the Seventh Circuit Court of Appeals.  In October 2010, the Seventh Circuit dismissed all of the remaining claims in these cases.  Beckjord is operated by Duke Energy Ohio, Inc.

Notice of Enforcement and Notice of Citizen Suit – Affecting SWEPCo

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

The Federal EPA issued a Notice of Violation (NOV) based on alleged violations of a percent sulfur in fuel limitation and the heat input values listed in a previous state permit.  The NOV also alleges that a permit alteration issued by the Texas Commission on Environmental Quality in 2007 was improper.  In March 2008, SWEPCo met with the Federal EPA to discuss the alleged violations.  The Federal EPA did not object to the settlement of similar alleged violations in the federal citizen suit.  Management is unable to predict the timing of any future action by the Federal EPA.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.

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Carbon Dioxide Public Nuisance Claims – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

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

In September 2009, the Second Circuit Court of Appeals issued a ruling on appeal remanding the cases to the Federal District Court for the Southern District of New York.  The Second Circuit held that the issues of climate change and global warming do not raise political questions and that Congress’ refusal to regulate CO2 emissions does not mean that plaintiffs must wait for an initial policy determination by Congress or the President’s administration to secure the relief sought in their complaints.  The court stated that Congress could enact comprehensive legislation to regulate CO2 emissions or that the Federal EPA could regulate CO2 emissions under existing CAA authorities and that either of these actions could override any decision made by the district court under federal common law.  The Second Circuit did not rule on whether the plaintiffs could proceed with their state common law nuisance claims.  The defendants’ petition for rehearing was denied.  Management believes the actions are without merit and intends to continue to defend against the claims.  The defendants, excluding TVA, filed a petition for review with the U.S. Supreme Court in August 2010.  The Solicitor General filed a brief in support of the petition on behalf of TVA.  Responses to the petition are due in November 2010.

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina.  The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims.  The court granted petitions for rehearing.  An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place.  The Registrant Subsidiaries were initially dismissed from this case without prejudice, but are named as defendants in a pending fourth amended complaint.  Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision.  Responses to the petition are due in November 2010.

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

Alaskan Villages’ Claims – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies.  The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together.  The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance.  The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million.  In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim.  The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court.  The plaintiffs appealed the decision.  Briefing is complete and no date has been set for oral argument.  Management believes the action is without merit and intends to defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.

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The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting I&M

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

In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm.  In May 2008, I&M started remediation work in accordance with a plan approved by MDEQ.  I&M recorded approximately $11 million of expense prior to January 1, 2010, $3 million of which I&M recorded in March 2009.  As the remediation work is completed, I&M’s cost may continue to increase as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ.  Management cannot predict the amount of additional cost, if any.

Amos Plant – State and Federal Enforcement Proceedings – Affecting APCo and OPCo

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

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

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

Defective Environmental Equipment – Affecting CSPCo and OPCo

As part of the AEP System’s continuing environmental investment program, management chose to retrofit wet flue gas desulfurization systems on units utilizing the jet bubbling reactor (JBR) technology.  The retrofits on two Cardinal Plant units and a Conesville Plant unit are operational.  Contracts for other projects were suspended during their early development stages.  Due to unexpected operating results, management completed an extensive review in 2009 of the design and manufacture of the JBR internal components.  The review concluded that there are fundamental design deficiencies and that inferior and/or inappropriate materials were selected for the internal fiberglass components.  Management initiated discussions with Black & Veatch, the original equipment manufacturer, to develop a repair or replacement corrective action plan.  In August 2010, management signed a settlement agreement with Black & Veatch that resolved the issues involving the internal components.  Management also reached an agreement in principle regarding JBR vessel corrosion issues.  These settlements result in an immaterial increase in the capitalized costs of the projects for modification of the scope of the contracts.

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NUCLEAR CONTINGENCIES – AFFECTING I&M

I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission.  I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant.  The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037.  The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements.  By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S.  Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.

Cook Plant Unit 1 Fire and Shutdown

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

I&M maintains property insurance through NEIL with a $1 million deductible.  As of September 30, 2010, I&M recorded $53 million on its Condensed Consolidated Balance Sheet representing recoverable amounts under the property insurance policy.  Through September 30, 2010, I&M received partial payments of $203 million from NEIL for the cost incurred to date to repair the property damage.

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

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

OPERATIONAL CONTINGENCIES

Fort Wayne Lease – Affecting I&M

Since 1975 I&M has leased certain energy delivery assets from the City of Fort Wayne, Indiana under a long-term lease that expired on February 28, 2010.  I&M negotiated with Fort Wayne to purchase the assets at the end of the lease, but no agreement was reached prior to the end of the lease.   Fort Wayne issued a technical notice of default under the lease to I&M in August 2009.  I&M responded to Fort Wayne in October 2009 that it did not agree there was a default under the lease.  In October 2009, I&M filed for declaratory and injunctive relief in Indiana state court.  The parties agreed to submit this matter to mediation.  In February 2010, the court issued a stay to continue mediation.  I&M is expensing monthly payments made into an escrow account in lieu of rent.

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I&M and Fort Wayne reached a tentative agreement as a result of the mediation process.  The agreement was signed on October 28, 2010 and is subject to approval by the Fort Wayne Common Council and the IURC.  I&M and Fort Wayne have agreed to cooperate in promptly seeking the requisite approvals.  If the agreement is approved, I&M will purchase the remaining leased property and settle claims Fort Wayne asserted.  The agreement provides that I&M will pay Fort Wayne a total of $39 million, inclusive of interest, over 15 years and Fort Wayne will recognize that I&M is the exclusive electricity supplier in the Fort Wayne area.   I&M will seek recovery in rates of the payments made to Fort Wayne.  If the agreement is not approved by the Fort Wayne Common Council and the IURC, the parties have the right to terminate the agreement and pursue other relief.

Coal Transportation Rate Dispute – Affecting PSO

In 1985, the Burlington Northern Railroad Co. (now BNSF) entered into a coal transportation agreement with PSO.  The agreement contained a base rate subject to adjustment, a rate floor, a reopener provision and an arbitration provision.  In 1992, PSO reopened the pricing provision.  The parties failed to reach an agreement and the matter was arbitrated, with the arbitration panel establishing a lowered rate as of July 1, 1992 (the 1992 Rate) and modifying the rate adjustment formula.  The decision did not mention the rate floor.  From April 1996 through the contract termination in December 2001, the 1992 Rate exceeded the adjusted rate determined according to the decision.  PSO paid the adjusted rate and contended that the panel eliminated the rate floor.  BNSF invoiced at the 1992 Rate and contended that the 1992 Rate was the new rate floor.  PSO terminated the contract by paying a termination fee, as required by the agreement.  BNSF contends that the termination fee should have been calculated on the 1992 Rate, not the adjusted rate, resulting in an underpayment of approximately $9.5 million, including interest.

This matter was submitted to an arbitration board.  In April 2006, the arbitration board filed its decision, denying BNSF’s underpayments claim.  PSO filed a request for an order confirming the arbitration award and a request for entry of judgment on the award with the U.S. District Court for the Northern District of Oklahoma.  On July 14, 2006, the U.S. District Court issued an order confirming the arbitration award.  On July 24, 2006, BNSF filed a Motion to Reconsider the July 14, 2006 Arbitration Confirmation Order and Final Judgment and its Motion to Vacate and Correct the Arbitration Award with the U.S. District Court.  In February 2007, the U.S. District Court granted BNSF’s Motion to Reconsider.  In August 2009, the U.S. District Court upheld the arbitration board’s decision.  BNSF appealed the U.S. District Court’s decision.  In September 2010, oral arguments were heard by a panel for the U.S. Court of Appeals.

5.  ACQUISITION

2010

Valley Electric Membership Corporation – Affecting SWEPCo

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

2009

None

6.  BENEFIT PLANS

APCo, CSPCo, I&M, OPCo, PSO and SWEPCo participate in AEP sponsored qualified pension plans and nonqualified pension plans.  A substantial majority of employees are covered by either one qualified plan or both a qualified and a nonqualified pension plan.  In addition, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo participate in other postretirement benefit plans sponsored by AEP to provide medical and death benefits for retired employees.

188

Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost by Registrant Subsidiary for the plans for the three and nine months ended September 30, 2010 and 2009:

APCo					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended September 30,				Three Months Ended September 30,
	2010		2009		2010		2009
	(in thousands)
Service Cost	$	3,227	$	3,172	$	1,431	$	1,285
Interest Cost		8,489		8,512		5,075		4,928
Expected Return on Plan Assets		(10,952)		(11,222)		(4,407)		(3,383)
Amortization of Transition Obligation		-		-		1,311		1,311
Amortization of Prior Service Cost		229		230		-		-
Amortization of Net Actuarial Loss		2,961		1,922		1,352		1,917
Net Periodic Benefit Cost	$	3,954	$	2,614	$	4,762	$	6,058

					Other Postretirement
	Pension Plans				Benefit Plans
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	(in thousands)
Service Cost	$	9,681	$	9,517	$	4,291	$	3,857
Interest Cost		25,467		25,537		15,225		14,783
Expected Return on Plan Assets		(32,854)		(33,664)		(13,220)		(10,149)
Amortization of Transition Obligation		-		-		3,933		3,933
Amortization of Prior Service Cost		687		688		-		-
Amortization of Net Actuarial Loss		8,882		5,766		4,057		5,749
Net Periodic Benefit Cost	$	11,863	$	7,844	$	14,286	$	18,173

CSPCo					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended September 30,				Three Months Ended September 30,
	2010		2009		2010		2009
	(in thousands)
Service Cost	$	1,469	$	1,376	$	690	$	618
Interest Cost		4,789		4,882		2,178		2,124
Expected Return on Plan Assets		(6,589)		(6,820)		(1,979)		(1,532)
Amortization of Transition Obligation		-		-		608		607
Amortization of Prior Service Cost		141		141		-		-
Amortization of Net Actuarial Loss		1,677		1,108		565		821
Net Periodic Benefit Cost	$	1,487	$	687	$	2,062	$	2,638

					Other Postretirement
	Pension Plans				Benefit Plans
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	(in thousands)
Service Cost	$	4,405	$	4,128	$	2,070	$	1,853
Interest Cost		14,367		14,647		6,535		6,370
Expected Return on Plan Assets		(19,767)		(20,458)		(5,937)		(4,595)
Amortization of Transition Obligation		-		-		1,824		1,823
Amortization of Prior Service Cost		423		423		-		-
Amortization of Net Actuarial Loss		5,031		3,323		1,695		2,464
Net Periodic Benefit Cost	$	4,459	$	2,063	$	6,187	$	7,915

189

I&M					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended September 30,				Three Months Ended September 30,
	2010		2009		2010		2009
	(in thousands)
Service Cost	$	3,821	$	3,501	$	1,688	$	1,498
Interest Cost		7,271		7,130		3,541		3,419
Expected Return on Plan Assets		(8,759)		(8,934)		(3,350)		(2,565)
Amortization of Transition Obligation		-		-		704		703
Amortization of Prior Service Cost		186		186		-		-
Amortization of Net Actuarial Loss		2,516		1,601		881		1,304
Net Periodic Benefit Cost	$	5,035	$	3,484	$	3,464	$	4,359

					Other Postretirement
	Pension Plans				Benefit Plans
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	(in thousands)
Service Cost	$	11,463	$	10,502	$	5,063	$	4,493
Interest Cost		21,814		21,390		10,623		10,256
Expected Return on Plan Assets		(26,279)		(26,800)		(10,048)		(7,694)
Amortization of Transition Obligation		-		-		2,111		2,110
Amortization of Prior Service Cost		558		558		-		-
Amortization of Net Actuarial Loss		7,548		4,804		2,644		3,910
Net Periodic Benefit Cost	$	15,104	$	10,454	$	10,393	$	13,075

OPCo					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended September 30,				Three Months Ended September 30,
	2010		2009		2010		2009
	(in thousands)
Service Cost	$	2,845	$	2,759	$	1,356	$	1,219
Interest Cost		8,186		8,275		4,446		4,331
Expected Return on Plan Assets		(10,680)		(11,070)		(4,043)		(3,140)
Amortization of Transition Obligation		-		-		1,052		1,053
Amortization of Prior Service Cost		227		228		-		-
Amortization of Net Actuarial Loss		2,861		1,875		1,154		1,676
Net Periodic Benefit Cost	$	3,439	$	2,067	$	3,965	$	5,139

					Other Postretirement
	Pension Plans				Benefit Plans
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	(in thousands)
Service Cost	$	8,536	$	8,276	$	4,069	$	3,658
Interest Cost		24,558		24,825		13,339		12,994
Expected Return on Plan Assets		(32,040)		(33,208)		(12,132)		(9,420)
Amortization of Transition Obligation		-		-		3,158		3,158
Amortization of Prior Service Cost		681		683		-		-
Amortization of Net Actuarial Loss		8,582		5,625		3,462		5,028
Net Periodic Benefit Cost	$	10,317	$	6,201	$	11,896	$	15,418

190

PSO					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended September 30,				Three Months Ended September 30,
	2010		2009		2010		2009
	(in thousands)
Service Cost	$	1,513	$	1,436	$	704	$	631
Interest Cost		3,722		3,842		1,590		1,538
Expected Return on Plan Assets		(4,934)		(5,109)		(1,528)		(1,174)
Amortization of Transition Obligation		-		-		701		701
Amortization of Prior Service Credit		(238)		(270)		-		-
Amortization of Net Actuarial Loss		1,297		871		394		587
Net Periodic Benefit Cost	$	1,360	$	770	$	1,861	$	2,283

					Other Postretirement
	Pension Plans				Benefit Plans
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	(in thousands)
Service Cost	$	4,539	$	4,308	$	2,111	$	1,892
Interest Cost		11,166		11,526		4,770		4,615
Expected Return on Plan Assets		(14,804)		(15,328)		(4,583)		(3,522)
Amortization of Transition Obligation		-		-		2,104		2,104
Amortization of Prior Service Credit		(713)		(811)		-		-
Amortization of Net Actuarial Loss		3,891		2,615		1,180		1,761
Net Periodic Benefit Cost	$	4,079	$	2,310	$	5,582	$	6,850

SWEPCo					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended September 30,				Three Months Ended September 30,
	2010		2009		2010		2009
	(in thousands)
Service Cost	$	1,761	$	1,689	$	777	$	704
Interest Cost		3,773		3,889		1,735		1,684
Expected Return on Plan Assets		(4,871)		(5,020)		(1,661)		(1,280)
Amortization of Transition Obligation		-		-		615		615
Amortization of Prior Service Credit		(199)		(229)		-		-
Amortization of Net Actuarial Loss		1,310		879		427		640
Net Periodic Benefit Cost	$	1,774	$	1,208	$	1,893	$	2,363

					Other Postretirement
	Pension Plans				Benefit Plans
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	(in thousands)
Service Cost	$	5,284	$	5,067	$	2,331	$	2,113
Interest Cost		11,320		11,668		5,205		5,052
Expected Return on Plan Assets		(14,616)		(15,062)		(4,984)		(3,840)
Amortization of Transition Obligation		-		-		1,845		1,845
Amortization of Prior Service Credit		(597)		(687)		-		-
Amortization of Net Actuarial Loss		3,931		2,637		1,283		1,920
Net Periodic Benefit Cost	$	5,322	$	3,623	$	5,680	$	7,090

191

The following table provides the actual contributions and payments by Registrant Subsidiary for the pension and OPEB plans during the first nine months of 2010 and the expected contributions and payments for the remainder of 2010:

	Paid as of September 30,						Remainder Expected to be Paid in 2010
				Other Postretirement						Other Postretirement
Company	Pension Plans			Benefit Plans			Pension Plans			Benefit Plans
	(in thousands)
APCo		$	31,979		$	15,579		$	4,627		$	3,067
CSPCo			5,361			6,683			1,565			1,787
I&M			66,733			11,541			4,754			3,549
OPCo			47,222			13,661			4,286			3,068
PSO			11,147			6,133			1,663			2,013
SWEPCo			26,739			6,267			2,294			2,049

7.  BUSINESS SEGMENTS

The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business.  The Registrant Subsidiaries’ other activities are insignificant.  The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.

8.  DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, coal and emission allowances.  These risks include commodity price risk, interest rate risk, credit risk and to a lesser extent foreign currency exchange risk.  These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates.  These risks are managed using derivative instruments.

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Trading Strategies

The strategy surrounding the use of derivative instruments for trading purposes focuses on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries.

Risk Management Strategies

The strategy surrounding the use of derivative instruments focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical forward purchase and sale contracts, financial forward purchase and sale contracts and financial swap instruments.  Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and to a lesser degree heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with the energy business.  AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with long-term commodity derivative positions.   For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities.  From time to time, AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies.  For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors.

192

The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of September 30, 2010 and December 31, 2009:

Notional Volume of Derivative Instruments
September 30, 2010
(in thousands)
Primary Risk			Unit of
Exposure			Measure	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
Commodity:
	Power		MWHs		237,981		137,187		144,273		167,450		33		57
	Coal		Tons		15,365		8,163		6,099		25,606		4,490		8,581
	Natural Gas		MMBtus		5,483		3,161		3,297		3,858		81		97
	Heating Oil and
		Gasoline	Gallons		1,361		598		671		1,005		796		733
	Interest Rate		USD	$	11,130	$	6,394	$	6,592	$	8,293	$	652	$	899
Interest Rate and
	Foreign Currency		USD	$	200,000	$	-	$	-	$	-	$	-	$	1,319
Notional Volume of Derivative Instruments
December 31, 2009
(in thousands)
Primary Risk			Unit of
Exposure			Measure	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
Commodity:
	Power		MWHs		191,121		96,828		99,265		112,745		10		12
	Coal		Tons		11,347		5,615		5,150		23,631		5,936		6,790
	Natural Gas		MMBtus		17,867		9,051		9,129		10,539		-		-
	Heating Oil and
		Gasoline	Gallons		1,164		474		552		838		668		628
	Interest Rate		USD	$	21,054	$	10,658	$	10,716	$	13,487	$	1,137	$	1,457
Interest Rate and
	Foreign Currency		USD	$	-	$	-	$	-	$	-	$	-	$	3,798

Fair Value Hedging Strategies

AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt.  Certain interest rate derivative transactions effectively modify an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate.  Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.

Cash Flow Hedging Strategies

AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities.  Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases.  The Registrant Subsidiaries do not hedge all commodity price risk.

The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility.  AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases.  For disclosure purposes, these contracts are included with other hedging activity as “Commodity.” The Registrant Subsidiaries do not hedge all fuel price risk.

193

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

At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily because some fixed assets are purchased from foreign suppliers.  In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar.  The Registrant Subsidiaries do not hedge all foreign currency exposure.

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

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

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

According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral.  For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the September 30, 2010 and December 31, 2009 balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:

	September 30, 2010				December 31, 2009
	Cash Collateral		Cash Collateral		Cash Collateral		Cash Collateral
	Received		Paid		Received		Paid
	Netted Against		Netted Against		Netted Against		Netted Against
	Risk Management		Risk Management		Risk Management		Risk Management
Company	Assets		Liabilities		Assets		Liabilities
	(in thousands)
APCo	$	6,306	$	46,860	$	3,789	$	31,806
CSPCo		3,636		27,007		1,920		16,108
I&M		3,792		28,150		1,936		16,222
OPCo		4,438		33,098		2,235		19,512
PSO		-		55		-		194
SWEPCo		-		88		-		305

194

The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the Condensed Balance Sheets as of September 30, 2010 and December 31, 2009:

Fair Value of Derivative Instruments
September 30, 2010
APCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
		Commodity		Commodity		and Foreign
Balance Sheet Location		(a)		(a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	358,539	$	1,548	$	-	$	(298,888)	$	61,199
Long-term Risk Management Assets			164,200		14		-		(112,348)		51,866
Total Assets			522,739		1,562		-		(411,236)		113,065
Current Risk Management Liabilities			344,792		4,657		1,216		(322,472)		28,193
Long-term Risk Management Liabilities			149,635		202		-		(133,508)		16,329
Total Liabilities			494,427		4,859		1,216		(455,980)		44,522
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	28,312	$	(3,297)	$	(1,216)	$	44,744	$	68,543
Fair Value of Derivative Instruments
December 31, 2009
APCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
		Commodity		Commodity		and Foreign
Balance Sheet Location		(a)		(a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	332,764	$	3,621	$	-	$	(268,429)	$	67,956
Long-term Risk Management Assets			132,044		-		-		(84,903)		47,141
Total Assets			464,808		3,621		-		(353,332)		115,097
Current Risk Management Liabilities			309,639		5,084		-		(288,931)		25,792
Long-term Risk Management Liabilities			118,702		80		-		(98,418)		20,364
Total Liabilities			428,341		5,164		-		(387,349)		46,156
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	36,467	$	(1,543)	$	-	$	34,017	$	68,941

195

Fair Value of Derivative Instruments
September 30, 2010
CSPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
		Commodity		Commodity		and Foreign
Balance Sheet Location		(a)		(a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	205,558	$	878	$	-	$	(171,270)	$	35,166
Long-term Risk Management Assets			94,390		6		-		(64,514)		29,882
Total Assets			299,948		884		-		(235,784)		65,048
Current Risk Management Liabilities			197,685		2,676		-		(184,861)		15,500
Long-term Risk Management Liabilities			85,983		116		-		(76,710)		9,389
Total Liabilities			283,668		2,792		-		(261,571)		24,889
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	16,280	$	(1,908)	$	-	$	25,787	$	40,159
Fair Value of Derivative Instruments
December 31, 2009
CSPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
		Commodity		Commodity		and Foreign
Balance Sheet Location		(a)		(a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	168,137	$	1,805	$	-	$	(135,599)	$	34,343
Long-term Risk Management Assets			66,816		-		-		(42,934)		23,882
Total Assets			234,953		1,805		-		(178,533)		58,225
Current Risk Management Liabilities			156,463		2,574		-		(145,985)		13,052
Long-term Risk Management Liabilities			60,048		41		-		(49,776)		10,313
Total Liabilities			216,511		2,615		-		(195,761)		23,365
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	18,442	$	(810)	$	-	$	17,228	$	34,860

196

Fair Value of Derivative Instruments
September 30, 2010
I&M
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
		Commodity		Commodity		and Foreign
Balance Sheet Location		(a)		(a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	213,839	$	921	$	-	$	(175,043)	$	39,717
Long-term Risk Management Assets			107,923		7		-		(66,430)		41,500
Total Assets			321,762		928		-		(241,473)		81,217
Current Risk Management Liabilities			202,473		2,793		-		(189,211)		16,055
Long-term Risk Management Liabilities			88,732		121		-		(79,140)		9,713
Total Liabilities			291,205		2,914		-		(268,351)		25,768
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	30,557	$	(1,986)	$	-	$	26,878	$	55,449
Fair Value of Derivative Instruments
December 31, 2009
I&M
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
		Commodity		Commodity		and Foreign
Balance Sheet Location		(a)		(a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	167,847	$	1,839	$	-	$	(135,248)	$	34,438
Long-term Risk Management Assets			72,127		-		-		(42,993)		29,134
Total Assets			239,974		1,839		-		(178,241)		63,572
Current Risk Management Liabilities			156,561		2,596		-		(145,721)		13,436
Long-term Risk Management Liabilities			60,217		41		-		(49,872)		10,386
Total Liabilities			216,778		2,637		-		(195,593)		23,822
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	23,196	$	(798)	$	-	$	17,352	$	39,750

197

Fair Value of Derivative Instruments
September 30, 2010
OPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
		Commodity		Commodity		and Foreign
Balance Sheet Location		(a)		(a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	275,750	$	1,092	$	-	$	(231,993)	$	44,849
Long-term Risk Management Assets			121,042		9		-		(84,228)		36,823
Total Assets			396,792		1,101		-		(316,221)		81,672
Current Risk Management Liabilities			267,657		3,278		-		(248,642)		22,293
Long-term Risk Management Liabilities			111,022		143		-		(99,187)		11,978
Total Liabilities			378,679		3,421		-		(347,829)		34,271
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	18,113	$	(2,320)	$	-	$	31,608	$	47,401
Fair Value of Derivative Instruments
December 31, 2009
OPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
		Commodity		Commodity		and Foreign
Balance Sheet Location		(a)		(a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	255,179	$	2,199	$	-	$	(207,330)	$	50,048
Long-term Risk Management Assets			88,064		-		-		(60,061)		28,003
Total Assets			343,243		2,199		-		(267,391)		78,051
Current Risk Management Liabilities			240,877		2,998		-		(219,484)		24,391
Long-term Risk Management Liabilities			81,186		47		-		(68,723)		12,510
Total Liabilities			322,063		3,045		-		(288,207)		36,901
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	21,180	$	(846)	$	-	$	20,816	$	41,150

198

Fair Value of Derivative Instruments
September 30, 2010
PSO
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
		Commodity		Commodity		and Foreign
Balance Sheet Location		(a)		(a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	7,587	$	65	$	-	$	(4,652)	$	3,000
Long-term Risk Management Assets			1,604		4		-		(1,107)		501
Total Assets			9,191		69		-		(5,759)		3,501
Current Risk Management Liabilities			4,928		63		-		(4,683)		308
Long-term Risk Management Liabilities			1,228		6		-		(1,115)		119
Total Liabilities			6,156		69		-		(5,798)		427
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	3,035	$	-	$	-	$	39	$	3,074
Fair Value of Derivative Instruments
December 31, 2009
PSO
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
		Commodity		Commodity		and Foreign
Balance Sheet Location		(a)		(a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	14,885	$	179	$	-	$	(12,688)	$	2,376
Long-term Risk Management Assets			2,640		-		-		(2,590)		50
Total Assets			17,525		179		-		(15,278)		2,426
Current Risk Management Liabilities			14,981		301		-		(12,703)		2,579
Long-term Risk Management Liabilities			2,913		-		-		(2,769)		144
Total Liabilities			17,894		301		-		(15,472)		2,723
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(369)	$	(122)	$	-	$	194	$	(297)

199

Fair Value of Derivative Instruments
September 30, 2010
SWEPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
		Commodity		Commodity		and Foreign
Balance Sheet Location		(a)		(a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	12,973	$	48	$	2	$	(11,006)	$	2,017
Long-term Risk Management Assets			3,027		3		6		(2,617)		419
Total Assets			16,000		51		8		(13,623)		2,436
Current Risk Management Liabilities			11,431		37		87		(11,032)		523
Long-term Risk Management Liabilities			2,926		6		-		(2,660)		272
Total Liabilities			14,357		43		87		(13,692)		795
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	1,643	$	8	$	(79)	$	69	$	1,641
Fair Value of Derivative Instruments
December 31, 2009
SWEPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
		Commodity		Commodity		and Foreign
Balance Sheet Location		(a)		(a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	22,847	$	169	$	42	$	(20,009)	$	3,049
Long-term Risk Management Assets			4,145		-		5		(4,066)		84
Total Assets			26,992		169		47		(24,075)		3,133
Current Risk Management Liabilities			20,788		-		89		(20,033)		844
Long-term Risk Management Liabilities			4,568		-		-		(4,347)		221
Total Liabilities			25,356		-		89		(24,380)		1,065
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	1,636	$	169	$	(42)	$	305	$	2,068

(a)	Derivative instruments within these categories are reported gross.  These instruments are subject to master netting agreements and are presented on the Condensed Balance Sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”
(b)	Amounts represent counterparty netting of risk management and hedging contracts, associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging” and dedesignated risk management contracts.

200

The tables below presents the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and nine months ended September 30, 2010 and 2009:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended September 30, 2010
Location of Gain (Loss)		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	1,938	$	6,436	$	6,374	$	5,378	$	686	$	1,123
Sales to AEP Affiliates			(522)		(704)		(571)		2,605		(204)		(486)
Regulatory Assets (a)			-		(2,013)		-		(4,064)		16		-
Regulatory Liabilities (a)			4,538		-		1,956		-		999		893
Total Gain (Loss) on Risk Management
	Contracts	$	5,954	$	3,719	$	7,759	$	3,919	$	1,497	$	1,530
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended September 30, 2009
Location of Gain (Loss)		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	2,240	$	6,551	$	7,127	$	3,155	$	(850)	$	(1,067)
Sales to AEP Affiliates			(237)		(238)		(292)		302		1,135		1,347
Regulatory Assets (a)			-		(2,616)		(1,278)		(2,922)		(617)		(20)
Regulatory Liabilities (a)			10,199		4,774		3,369		5,384		(480)		9
Total Gain (Loss) on Risk Management
	Contracts	$	12,202	$	8,471	$	8,926	$	5,919	$	(812)	$	269

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Nine Months Ended September 30, 2010
Location of Gain (Loss)		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	4,419	$	19,513	$	15,762	$	17,609	$	1,716	$	2,524
Sales to AEP Affiliates			(2,098)		(2,153)		(1,913)		5,014		(502)		(1,024)
Regulatory Assets (a)			-		(3,557)		-		(5,725)		321		73
Regulatory Liabilities (a)			19,686		-		10,418		-		3,763		1,406
Total Gain (Loss) on Risk Management
	Contracts	$	22,007	$	13,803	$	24,267	$	16,898	$	5,298	$	2,979
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Nine Months Ended September 30, 2009
Location of Gain (Loss)		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	13,211	$	26,557	$	31,333	$	27,453	$	(2)	$	151
Sales to AEP Affiliates			(7,563)		(4,707)		(4,710)		(1,191)		510		372
Regulatory Assets (a)			-		(6,243)		(3,727)		(7,231)		(283)		200
Regulatory Liabilities (a)			24,479		2,284		4,347		2,300		(1,696)		(65)
Total Gain (Loss) on Risk Management
	Contracts	$	30,127	$	17,891	$	27,243	$	21,331	$	(1,471)	$	658

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

201

Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.”  Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the Condensed Statements of Income on an accrual basis.

The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship.  Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the Condensed Statements of Income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the Condensed Statements of Income depending on the relevant facts and circumstances.  However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO, the non-Texas portion of SWEPCo generation and beginning in the second quarter of 2009 the Texas portion of SWEPCo generation) for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”  SWEPCo re-applied the accounting guidance for “Regulated Operations” for the generation portion of SWEPCo’s Texas retail jurisdiction effective the second quarter of 2009.

Accounting for Fair Value Hedging Strategies

For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the Registrant Subsidiaries recognize the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk in Net Income during the period of change.

The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the Condensed Statements of Income.  During the three and nine months ended September 30, 2010 and 2009, the Registrant Subsidiaries did not employ any fair value hedging strategies.

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets until the period the hedged item affects Net Income.  The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Realized gains and losses on derivative contracts for the purchase and sale of power, coal, natural gas, and heating oil and gasoline designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the Condensed Statements of Income, or in Regulatory Assets or Regulatory Liabilities on the Condensed Balance Sheets, depending on the specific nature of the risk being hedged.  During the three and nine months ended September 30, 2010 and 2009, APCo, CSPCo, I&M and OPCo designated commodity derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on financial fuel derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the Condensed Statements of Income.  During the three and nine months ended September 30, 2010, the Registrant Subsidiaries designated cash flow hedging strategies of forecasted fuel purchases.

202

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financing from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which hedged interest payments occur.  During the three and nine months ended September 30, 2010, APCo designated interest rate derivatives as cash flow hedges.  During the three and nine months ended September 30, 2009, OPCo designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets into Depreciation and Amortization expense on the Condensed Statements of Income over the depreciable lives of the fixed assets that were designated as the hedged items in qualifying foreign currency hedging relationships.  During the three and nine months ended September 30, 2010 and 2009, SWEPCo designated foreign currency derivatives as cash flow hedges.

During the three and nine months ended September 30, 2010 and 2009, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

203

The following tables provides details on designated, effective cash flow hedges included in AOCI on the Condensed Balance Sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2010 and 2009.  All amounts in the following tables are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended September 30, 2010
Commodity Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of June 30, 2010				$	(1,437)	$	(807)	$	(813)	$	(941)	$	(84)	$	(33)
Changes in Fair Value Recognized in AOCI					(1,212)		(729)		(776)		(914)		69		60
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		60		159		127		184		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		40		-
		Purchased Electricity for Resale			56		156		138		195		-		-
		Other Operation Expense			(7)		(5)		(5)		(6)		(7)		(7)
		Maintenance Expense			(11)		(3)		(5)		(6)		(4)		(3)
		Property, Plant and Equipment			(11)		(4)		(5)		(9)		(7)		(5)
		Regulatory Assets (a)			436		-		58		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-		-
Balance in AOCI as of September 30, 2010				$	(2,126)	$	(1,233)	$	(1,281)	$	(1,497)	$	7	$	12
Interest Rate and Foreign Currency
Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of June 30, 2010				$	(8,298)	$	-	$	(9,011)	$	11,492	$	(443)	$	(4,812)
Changes in Fair Value Recognized in AOCI					(790)		-		-		1		-		122
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		-		1		-		-
		Other Operation Expense			-		-		-		-		-		(3)
		Interest Expense			394		-		252		(341)		18		207
Balance in AOCI as of September 30, 2010				$	(8,694)	$	-	$	(8,759)	$	11,153	$	(425)	$	(4,486)
Total Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of June 30, 2010				$	(9,735)	$	(807)	$	(9,824)	$	10,551	$	(527)	$	(4,845)
Changes in Fair Value Recognized in AOCI					(2,002)		(729)		(776)		(913)		69		182
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		60		159		127		184		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		40		-
		Purchased Electricity for Resale			56		156		138		195		-		-
		Other Operation Expense			(7)		(5)		(5)		(6)		(7)		(10)
		Maintenance Expense			(11)		(3)		(5)		(6)		(4)		(3)
		Depreciation and Amortization
			Expense		-		-		-		1		-		-
		Interest Expense			394		-		252		(341)		18		207
		Property, Plant and Equipment			(11)		(4)		(5)		(9)		(7)		(5)
		Regulatory Assets (a)			436		-		58		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-		-
Balance in AOCI as of September 30, 2010				$	(10,820)	$	(1,233)	$	(10,040)	$	9,656	$	(418)	$	(4,474)

204

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended September 30, 2009
Commodity Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of June 30, 2009				$	2,296	$	1,189	$	1,170	$	1,526	$	127	$	141
Changes in Fair Value Recognized in AOCI					(451)		(232)		(227)		(346)		(377)		(45)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		(720)		(1,815)		(1,385)		(2,126)		-		-
		Fuel and Other Consumables Used for
			Electric Generation		(39)		(17)		(20)		(27)		(20)		(22)
		Purchased Electricity for Resale			444		1,116		852		1,313		-		-
		Other Operation Expense			-		-		-		-		-		-
		Maintenance Expense			-		-		-		-		-		-
		Property, Plant and Equipment			(23)		(9)		(12)		(17)		(12)		(9)
		Regulatory Assets (a)			1,664		-		226		-		-		-
		Regulatory Liabilities (a)			(2,709)		-		(369)		-		-		-
Balance in AOCI as of September 30, 2009				$	462	$	232	$	235	$	323	$	(282)	$	65
Interest Rate and Foreign Currency
Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of June 30, 2009				$	(7,285)	$	-	$	(10,017)	$	16,662	$	(613)	$	(5,497)
Changes in Fair Value Recognized in AOCI					-		-		-		(4,038)		-		82
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		(2)		1		-		-
		Interest Expense			418		-		253		(113)		46		208
Balance in AOCI as of September 30, 2009				$	(6,867)	$	-	$	(9,766)	$	12,512	$	(567)	$	(5,207)
Total Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of June 30, 2009				$	(4,989)	$	1,189	$	(8,847)	$	18,188	$	(486)	$	(5,356)
Changes in Fair Value Recognized in AOCI					(451)		(232)		(227)		(4,384)		(377)		37
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		(720)		(1,815)		(1,385)		(2,126)		-		-
		Fuel and Other Consumables Used for
			Electric Generation		(39)		(17)		(20)		(27)		(20)		(22)
		Purchased Electricity for Resale			444		1,116		852		1,313		-		-
		Other Operation Expense			-		-		-		-		-		-
		Maintenance Expense			-		-		-		-		-		-
		Depreciation and Amortization
			Expense		-		-		(2)		1		-		-
		Interest Expense			418		-		253		(113)		46		208
		Property, Plant and Equipment			(23)		(9)		(12)		(17)		(12)		(9)
		Regulatory Assets (a)			1,664		-		226		-		-		-
		Regulatory Liabilities (a)			(2,709)		-		(369)		-		-		-
Balance in AOCI as of September 30, 2009				$	(6,405)	$	232	$	(9,531)	$	12,835	$	(849)	$	(5,142)

205

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Nine Months Ended September 30, 2010
Commodity Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2009				$	(743)	$	(376)	$	(382)	$	(366)	$	(78)	$	112
Changes in Fair Value Recognized in AOCI					(3,069)		(1,806)		(1,859)		(2,214)		(36)		(36)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		117		303		247		351		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		(13)		190		-
		Purchased Electricity for Resale			267		706		593		828		-		-
		Other Operation Expense			(31)		(24)		(22)		(26)		(26)		(30)
		Maintenance Expense			(47)		(15)		(19)		(21)		(16)		(15)
		Property, Plant and Equipment			(44)		(21)		(22)		(31)		(27)		(19)
		Regulatory Assets (a)			1,424		-		183		-		-		-
		Regulatory Liabilities (a)			-		-		-		(5)		-		-
Balance in AOCI as of September 30, 2010				$	(2,126)	$	(1,233)	$	(1,281)	$	(1,497)	$	7	$	12
Interest Rate and Foreign Currency
Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2009				$	(6,450)	$	-	$	(9,514)	$	12,172	$	(521)	$	(5,047)
Changes in Fair Value Recognized in AOCI					(3,475)		-		-		1		-		(81)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		-		3		-		-
		Other Operation Expense			-		-		-		-		-		21
		Interest Expense			1,231		-		755		(1,023)		96		621
Balance in AOCI as of September 30, 2010				$	(8,694)	$	-	$	(8,759)	$	11,153	$	(425)	$	(4,486)
Total Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2009				$	(7,193)	$	(376)	$	(9,896)	$	11,806	$	(599)	$	(4,935)
Changes in Fair Value Recognized in AOCI					(6,544)		(1,806)		(1,859)		(2,213)		(36)		(117)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		117		303		247		351		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		(13)		190		-
		Purchased Electricity for Resale			267		706		593		828		-		-
		Other Operation Expense			(31)		(24)		(22)		(26)		(26)		(9)
		Maintenance Expense			(47)		(15)		(19)		(21)		(16)		(15)
		Depreciation and Amortization
			Expense		-		-		-		3		-		-
		Interest Expense			1,231		-		755		(1,023)		96		621
		Property, Plant and Equipment			(44)		(21)		(22)		(31)		(27)		(19)
		Regulatory Assets (a)			1,424		-		183		-		-		-
		Regulatory Liabilities (a)			-		-		-		(5)		-		-
Balance in AOCI as of September 30, 2010				$	(10,820)	$	(1,233)	$	(10,040)	$	9,656	$	(418)	$	(4,474)

206

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Nine Months Ended September 30, 2009
Commodity Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2008				$	2,726	$	1,531	$	1,482	$	1,898	$	-	$	-
Changes in Fair Value Recognized in AOCI					(278)		(257)		(233)		(325)		(246)		100
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		(1,429)		(3,586)		(2,774)		(4,319)		-		-
		Fuel and Other Consumables Used for
			Electric Generation		(45)		(21)		(24)		(32)		(23)		(25)
		Purchased Electricity for Resale			1,038		2,576		2,033		3,120		-		-
		Other Operation Expense			-		-		-		-		-		-
		Maintenance Expense			-		-		-		-		-		-
		Property, Plant and Equipment			(26)		(11)		(13)		(19)		(13)		(10)
		Regulatory Assets (a)			3,800		-		457		-		-		-
		Regulatory Liabilities (a)			(5,324)		-		(693)		-		-		-
Balance in AOCI as of September 30, 2009				$	462	$	232	$	235	$	323	$	(282)	$	65
Interest Rate and Foreign Currency
Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2008				$	(8,118)	$	-	$	(10,521)	$	1,752	$	(704)	$	(5,924)
Changes in Fair Value Recognized in AOCI					-		-		-		10,915		-		95
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		(4)		3		-		-
		Interest Expense			1,251		-		759		(158)		137		622
Balance in AOCI as of September 30, 2009				$	(6,867)	$	-	$	(9,766)	$	12,512	$	(567)	$	(5,207)
Total Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2008				$	(5,392)	$	1,531	$	(9,039)	$	3,650	$	(704)	$	(5,924)
Changes in Fair Value Recognized in AOCI					(278)		(257)		(233)		10,590		(246)		195
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		(1,429)		(3,586)		(2,774)		(4,319)		-		-
		Fuel and Other Consumables Used for
			Electric Generation		(45)		(21)		(24)		(32)		(23)		(25)
		Purchased Electricity for Resale			1,038		2,576		2,033		3,120		-		-
		Other Operation Expense			-		-		-		-		-		-
		Maintenance Expense			-		-		-		-		-		-
		Depreciation and Amortization
			Expense		-		-		(4)		3		-		-
		Interest Expense			1,251		-		759		(158)		137		622
		Property, Plant and Equipment			(26)		(11)		(13)		(19)		(13)		(10)
		Regulatory Assets (a)			3,800		-		457		-		-		-
		Regulatory Liabilities (a)			(5,324)		-		(693)		-		-		-
Balance in AOCI as of September 30, 2009				$	(6,405)	$	232	$	(9,531)	$	12,835	$	(849)	$	(5,142)

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

207

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets at September 30, 2010 and December 31, 2009 were:

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
September 30, 2010
	Hedging Assets (a)				Hedging Liabilities (a)				AOCI Gain (Loss) Net of Tax
			Interest Rate				Interest Rate				Interest Rate
			and Foreign				and Foreign				and Foreign
Company	Commodity		Currency		Commodity		Currency		Commodity		Currency
	(in thousands)
APCo	$	70	$	-	$	(3,367)	$	(1,216)	$	(2,126)	$	(8,694)
CSPCo		32		-		(1,940)		-		(1,233)		-
I&M		37		-		(2,023)		-		(1,281)		(8,759)
OPCo		50		-		(2,370)		-		(1,497)		11,153
PSO		21		-		(21)		-		7		(425)
SWEPCo		19		8		(11)		(87)		12		(4,486)

	Expected to be Reclassified to
	Net Income During the Next
	Twelve Months
					Maximum Term for
			Interest Rate		Exposure to
			and Foreign		Variability of Future
Company	Commodity		Currency		Cash Flows
	(in thousands)				(in months)
APCo	$	(2,002)	$	(1,733)		15
CSPCo		(1,161)		-		15
I&M		(1,208)		(1,007)		15
OPCo		(1,410)		1,359		15
PSO		9		(73)		15
SWEPCo		13		(829)		26

208

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
December 31, 2009
	Hedging Assets (a)				Hedging Liabilities (a)				AOCI Gain (Loss) Net of Tax
			Interest Rate				Interest Rate				Interest Rate
			and Foreign				and Foreign				and Foreign
Company	Commodity		Currency		Commodity		Currency		Commodity		Currency
	(in thousands)
APCo	$	1,999	$	-	$	(3,542)	$	-	$	(743)	$	(6,450)
CSPCo		984		-		(1,794)		-		(376)		-
I&M		1,011		-		(1,809)		-		(382)		(9,514)
OPCo		1,242		-		(2,088)		-		(366)		12,172
PSO		178		-		(300)		-		(78)		(521)
SWEPCo		168		5		-		(46)		112		(5,047)

	Expected to be Reclassified to
	Net Income During the Next
	Twelve Months
			Interest Rate
			and Foreign
Company	Commodity		Currency
	(in thousands)
APCo	$	(691)	$	(1,301)
CSPCo		(349)		-
I&M		(358)		(1,007)
OPCo		(335)		1,359
PSO		(79)		(114)
SWEPCo		111		(829)

(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the Condensed Balance Sheets.

The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.

Credit Risk

AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.  AEPSC, on behalf of the Registrant Subsidiaries, uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements which may include collateral requirements.  These master agreements facilitate the netting of cash flows associated with a single counterparty.  Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk.  The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold.  The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy.  In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.

209

Collateral Triggering Events

Under a limited number of derivative and non-derivative counterparty contracts primarily related to pre-2002 risk management activities and under the tariffs of the RTOs and Independent System Operators (ISOs), the Registrant Subsidiaries are obligated to post an amount of collateral if certain credit ratings decline below investment grade.  The amount of collateral required fluctuates based on market prices and total exposure.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts.  Management does not anticipate a downgrade below investment grade.  The following tables represent the Registrant Subsidiaries’ aggregate fair value of such derivative contracts, the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if the credit ratings had declined below investment grade and how much was attributable to RTO and ISO activities as of September 30, 2010 and December 31, 2009:

	September 30, 2010
	Liabilities for		Amount of Collateral the		Amount
	Derivative Contracts		Registrant Subsidiaries		Attributable to
	with Credit		Would Have Been		RTO and ISO
Company	Downgrade Triggers		Required to Post		Activities
	(in thousands)
APCo	$	7,600	$	9,459	$	9,261
CSPCo		4,381		5,453		5,339
I&M		4,570		5,688		5,569
OPCo		5,347		6,656		6,517
PSO		10		1,809		1,694
SWEPCo		12		2,167		2,029

As of September 30, 2010, the Registrant Subsidiaries were not required to post any cash collateral.

	December 31, 2009
	Liabilities for		Amount of Collateral the		Amount
	Derivative Contracts		Registrant Subsidiaries		Attributable to
	with Credit		Would Have Been		RTO and ISO
Company	Downgrade Triggers		Required to Post		Activities
	(in thousands)
APCo	$	2,229	$	8,433	$	7,947
CSPCo		1,129		4,272		4,026
I&M		1,139		4,309		4,060
OPCo		1,315		4,975		4,688
PSO		689		2,772		2,083
SWEPCo		819		3,297		2,477

As of December 31, 2009, the Registrant Subsidiaries were not required to post any collateral.

210

In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable.  These cross-default provisions could be triggered if there was a non-performance event under outstanding debt in excess of $50 million.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts.  Management does not anticipate a non-performance event under these provisions.  The following tables represent the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries’ contractual netting arrangements as of September 30, 2010 and December 31, 2009:

	September 30, 2010
	Liabilities for				Additional
	Contracts with Cross				Settlement
	Default Provisions				Liability if Cross
	Prior to Contractual		Amount of Cash		Default Provision
Company	Netting Arrangements		Collateral Posted		is Triggered
	(in thousands)
APCo	$	128,044	$	19,328	$	30,372
CSPCo		73,111		11,142		16,807
I&M		76,260		11,622		17,528
OPCo		89,264		13,600		20,540
PSO		117		-		40
SWEPCo		233		-		133
	December 31, 2009
	Liabilities for				Additional
	Contracts with Cross				Settlement
	Default Provisions				Liability if Cross
	Prior to Contractual		Amount of Cash		Default Provision
Company	Netting Arrangements		Collateral Posted		is Triggered
	(in thousands)
APCo	$	154,924	$	3,115	$	33,186
CSPCo		78,489		1,578		16,813
I&M		79,158		1,592		16,955
OPCo		91,430		1,838		19,615
PSO		40		-		40
SWEPCo		139		-		93

9.  FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

211

For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1.  Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated.  Management typically obtains multiple broker quotes, which are non-binding in nature but are based on recent trades in the marketplace.  When multiple broker quotes are obtained, the quoted bid and ask prices are averaged.  In certain circumstances, a broker quote may be discarded if it is a clear outlier.  Management uses a historical correlation analysis between the broker quoted location and the illiquid locations and if the points are highly correlated, these locations are included within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Long-dated and illiquid complex or structured transactions and FTRs can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.

AEP utilizes its trustee’s external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts.  AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value.  AEP’s investment managers perform their own valuation testing to verify the fair values of the securities.  AEP receives audit reports of the trustee’s operating controls and valuation processes.  The trustee uses multiple pricing vendors for the assets held in the trusts.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Fixed income securities do not trade on an exchange and do not have an official closing price.  Pricing vendors calculate bond valuations using financial models and matrices.  Fixed income securities are typically classified as Level 2 holdings because their valuation inputs are based on observable market data.  Observable inputs used for valuing fixed income securities are benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, bids, offers, reference data and economic events.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.

Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equities.  They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.

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

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

212

Fair Value Measurements of Long-term Debt

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

The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of September 30, 2010 and December 31, 2009 are summarized in the following table:

	September 30, 2010				December 31, 2009
Company	Book Value		Fair Value		Book Value		Fair Value
	(in thousands)
APCo	$	3,560,959	$	4,075,531	$	3,477,306	$	3,699,373
CSPCo		1,588,753		1,791,795		1,536,393		1,616,857
I&M		2,118,911		2,399,239		2,077,906		2,192,854
OPCo		2,929,386		3,249,304		3,242,505		3,380,084
PSO		970,643		1,095,500		968,121		1,007,183
SWEPCo		1,769,457		2,050,992		1,474,153		1,554,165

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

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

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

· Maximum percentage invested in a specific type of investment.

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

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

· Target asset allocation is 50% fixed income and 50% equity securities.

I&M maintains trust records for each regulatory jurisdiction.  These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities.  The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.

I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value.  I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose.  The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether the investor has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs.  The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment, among other things, is based on whether the investor has the ability and intent to hold the investment to recover its value.  Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the equity and debt investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  The gains, losses or other-than-temporary impairments shown below did not affect earnings or AOCI.  The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities.  Regulatory approval is required to withdraw decommissioning funds.

213

The following is a summary of nuclear trust fund investments at September 30, 2010 and December 31, 2009:

		September 30, 2010						December 31, 2009
		Estimated		Gross		Other-Than-		Estimated		Gross		Other-Than-
		Fair		Unrealized		Temporary		Fair		Unrealized		Temporary
		Value		Gains		Impairments		Value		Gains		Impairments
		(in thousands)
Cash and Cash Equivalents		$	30,217	$	-	$	-	$	14,412	$	-	$	-
Fixed Income Securities:
	United States Government		489,026		40,901		(1,036)		400,565		12,708		(3,472)
	Corporate Debt		64,744		5,039		(1,988)		57,291		4,636		(2,177)
	State and Local Government		307,660		(6,991)		(527)		368,930		7,924		991
	Subtotal Fixed Income Securities		861,430		38,949		(3,551)		826,786		25,268		(4,658)
Equity Securities - Domestic			574,052		124,051		(122,769)		550,721		234,437		(119,379)
Spent Nuclear Fuel and
	Decommissioning Trusts	$	1,465,699	$	163,000	$	(126,320)	$	1,391,919	$	259,705	$	(124,037)

The following table provides the securities activity within the decommissioning and SNF trusts 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 thousands)
Proceeds From Investment Sales	$	495,221	$	112,900	$	1,087,484	$	523,927
Purchases of Investments		511,688		129,239		1,128,747		571,167
Gross Realized Gains on Investment Sales		1,168		1,137		7,518		10,490
Gross Realized Losses on Investment Sales		33		196		450		1,004

The adjusted cost of debt securities was $823 million and $801 million as of September 30, 2010 and December 31, 2009, respectively.

The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at September 30, 2010 was as follows:

	Fair Value
	of Debt
	Securities
	(in thousands)
Within 1 year		$	13,134
1 year – 5 years			346,079
5 years – 10 years			266,801
After 10 years			235,416
Total		$	861,430

Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2010 and December 31, 2009.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in management’s valuation techniques.

214

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2010
APCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (g)		$	2,786	$	489,714	$	27,711	$	(412,038)	$	108,173
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,548		-		(1,478)		70
Dedesignated Risk Management Contracts (b)			-		-		-		4,822		4,822
Total Risk Management Assets		$	2,786	$	491,262	$	27,711	$	(408,694)	$	113,065
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (g)		$	2,725	$	478,028	$	11,146	$	(452,592)	$	39,307
Cash Flow Hedges:
	Commodity Hedges (a)		-		4,845		-		(1,478)		3,367
	Interest Rate/Foreign Currency Hedges		-		1,216		-		-		1,216
DETM Assignment (c)			-		-		-		632		632
Total Risk Management Liabilities		$	2,725	$	484,089	$	11,146	$	(453,438)	$	44,522

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2009
APCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Other Cash Deposits (d)		$	421	$	-	$	-	$	51	$	472
Risk Management Assets
Risk Management Commodity Contracts (a)			2,344		449,406		12,866		(360,248)		104,368
Cash Flow Hedges:
	Commodity Hedges (a)		-		3,620		-		(1,621)		1,999
Dedesignated Risk Management Contracts (b)			-		-		-		8,730		8,730
Total Risk Management Assets			2,344		453,026		12,866		(353,139)		115,097
Total Assets		$	2,765	$	453,026	$	12,866	$	(353,088)	$	115,569
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a)		$	2,648	$	422,063	$	3,438	$	(388,265)	$	39,884
Cash Flow Hedges:
	Commodity Hedges (a)		-		5,163		-		(1,621)		3,542
DETM Assignment (c)			-		-		-		2,730		2,730
Total Risk Management Liabilities		$	2,648	$	427,226	$	3,438	$	(387,156)	$	46,156

215

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2010
CSPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (g)		$	1,606	$	280,931	$	15,972	$	(236,273)	$	62,236
Cash Flow Hedges:
	Commodity Hedges (a)		-		876		-		(844)		32
Dedesignated Risk Management Contracts (b)			-		-		-		2,780		2,780
Total Risk Management Assets		$	1,606	$	281,807	$	15,972	$	(234,337)	$	65,048
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (g)		$	1,571	$	274,233	$	6,425	$	(259,644)	$	22,585
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,784		-		(844)		1,940
DETM Assignment (c)			-		-		-		364		364
Total Risk Management Liabilities		$	1,571	$	277,017	$	6,425	$	(260,124)	$	24,889

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2009
CSPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Other Cash Deposits (d)		$	16,129	$	-	$	-	$	21	$	16,150
Risk Management Assets
Risk Management Commodity Contracts (a)			1,188		227,150		6,518		(182,038)		52,818
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,805		-		(821)		984
Dedesignated Risk Management Contracts (b)			-		-		-		4,423		4,423
Total Risk Management Assets			1,188		228,955		6,518		(178,436)		58,225
Total Assets		$	17,317	$	228,955	$	6,518	$	(178,415)	$	74,375
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a)		$	1,342	$	213,330	$	1,742	$	(196,226)	$	20,188
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,615		-		(821)		1,794
DETM Assignment (c)			-		-		-		1,383		1,383
Total Risk Management Liabilities		$	1,342	$	215,945	$	1,742	$	(195,664)	$	23,365

216

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2010
I&M
			Level 1		Level 2		Level 3		Other		Total
Assets:			(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (g)			$	1,676	$	301,988	$	16,655	$	(242,039)	$	78,280
Cash Flow Hedges:
	Commodity Hedges (a)			-		919		-		(882)		37
Dedesignated Risk Management Contracts (b)				-		-		-		2,900		2,900
Total Risk Management Assets				1,676		302,907		16,655		(240,021)		81,217
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)				-		20,776		-		9,441		30,217
Fixed Income Securities:
	United States Government			-		489,026		-		-		489,026
	Corporate Debt			-		64,744		-		-		64,744
	State and Local Government			-		307,660		-		-		307,660
		Subtotal Fixed Income Securities		-		861,430		-		-		861,430
Equity Securities - Domestic (f)				574,052		-		-		-		574,052
Total Spent Nuclear Fuel and Decommissioning Trusts				574,052		882,206		-		9,441		1,465,699
Total Assets			$	575,728	$	1,185,113	$	16,655	$	(230,580)	$	1,546,916
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (g)			$	1,639	$	281,426	$	6,697	$	(266,397)	$	23,365
Cash Flow Hedges:
	Commodity Hedges (a)			-		2,905		-		(882)		2,023
DETM Assignment (c)				-		-		-		380		380
Total Risk Management Liabilities			$	1,639	$	284,331	$	6,697	$	(266,899)	$	25,768

217

		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		December 31, 2009
I&M
			Level 1		Level 2		Level 3		Other		Total
Assets:			(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a)			$	1,198	$	231,777	$	6,571	$	(181,446)	$	58,100
Cash Flow Hedges:
	Commodity Hedges (a)			-		1,839		-		(828)		1,011
Dedesignated Risk Management Contracts (b)				-		-		-		4,461		4,461
Total Risk Management Assets				1,198		233,616		6,571		(177,813)		63,572
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)				-		3,562		-		10,850		14,412
Fixed Income Securities:
	United States Government			-		400,565		-		-		400,565
	Corporate Debt			-		57,291		-		-		57,291
	State and Local Government			-		368,930		-		-		368,930
		Subtotal Fixed Income Securities		-		826,786		-		-		826,786
Equity Securities - Domestic (f)				550,721		-		-		-		550,721
Total Spent Nuclear Fuel and Decommissioning Trusts				550,721		830,348		-		10,850		1,391,919
Total Assets			$	551,919	$	1,063,964	$	6,571	$	(166,963)	$	1,455,491
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a)			$	1,353	$	213,242	$	1,755	$	(195,732)	$	20,618
Cash Flow Hedges:
	Commodity Hedges (a)			-		2,637		-		(828)		1,809
DETM Assignment (c)				-		-		-		1,395		1,395
Total Risk Management Liabilities			$	1,353	$	215,879	$	1,755	$	(195,165)	$	23,822

218

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	September 30, 2010
OPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Other Cash Deposits (d)		$	26	$	-	$	-	$	-	$	26
Risk Management Assets
Risk Management Commodity Contracts (a) (g)			1,961		373,224		19,540		(316,496)		78,229
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,092		-		(1,042)		50
Dedesignated Risk Management Contracts (b)			-		-		-		3,393		3,393
Total Risk Management Assets			1,961		374,316		19,540		(314,145)		81,672
Total Assets		$	1,987	$	374,316	$	19,540	$	(314,145)	$	81,698
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (g)		$	1,917	$	366,812	$	7,883	$	(345,156)	$	31,456
Cash Flow Hedges:
	Commodity Hedges (a)		-		3,412		-		(1,042)		2,370
DETM Assignment (c)			-		-		-		445		445
Total Risk Management Liabilities		$	1,917	$	370,224	$	7,883	$	(345,753)	$	34,271

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2009
OPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Other Cash Deposits (d)		$	1,075	$	-	$	-	$	24	$	1,099
Risk Management Assets
Risk Management Commodity Contracts (a)			1,383		332,904		7,644		(270,272)		71,659
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,199		-		(957)		1,242
Dedesignated Risk Management Contracts (b)			-		-		-		5,150		5,150
Total Risk Management Assets			1,383		335,103		7,644		(266,079)		78,051
Total Assets		$	2,458	$	335,103	$	7,644	$	(266,055)	$	79,150
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a)		$	1,562	$	317,114	$	2,075	$	(287,549)	$	33,202
Cash Flow Hedges:
	Commodity Hedges (a)		-		3,045		-		(957)		2,088
DETM Assignment (c)			-		-		-		1,611		1,611
Total Risk Management Liabilities		$	1,562	$	320,159	$	2,075	$	(286,895)	$	36,901

219

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	September 30, 2010
PSO
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (g)		$	9	$	9,098	$	11	$	(5,638)	$	3,480
Cash Flow Hedges:
	Commodity Hedges (a)		-		69		-		(48)		21
Total Risk Management Assets		$	9	$	9,167	$	11	$	(5,686)	$	3,501
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (g)		$	8	$	6,066	$	9	$	(5,693)	$	390
Cash Flow Hedges:
	Commodity Hedges (a)		-		69		-		(48)		21
DETM Assignment (c)			-		-		-		16		16
Total Risk Management Liabilities		$	8	$	6,135	$	9	$	(5,725)	$	427

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2009
PSO
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a)		$	-	$	17,494	$	14	$	(15,260)	$	2,248
Cash Flow Hedges:
	Commodity Hedges (a)		-		179		-		(1)		178
Total Risk Management Assets		$	-	$	17,673	$	14	$	(15,261)	$	2,426
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a)		$	-	$	17,865	$	12	$	(15,454)	$	2,423
Cash Flow Hedges:
	Commodity Hedges (a)		-		301		-		(1)		300
Total Risk Management Liabilities		$	-	$	18,166	$	12	$	(15,455)	$	2,723

220

Assets and Liabilities Measured at Fair Value on a Recurring Basis
September 30, 2010
SWEPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (g)		$	11	$	15,793	$	21	$	(13,416)	$	2,409
Cash Flow Hedges:
	Commodity Hedges (a)		-		51		-		(32)		19
	Interest Rate/Foreign Currency Hedges (a)		-		8		-		-		8
Total Risk Management Assets		$	11	$	15,852	$	21	$	(13,448)	$	2,436
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (g)		$	10	$	14,153	$	19	$	(13,504)	$	678
Cash Flow Hedges:
	Commodity Hedges (a)		-		43		-		(32)		11
	Interest Rate/Foreign Currency Hedges (a)		-		87		-		-		87
DETM Assignment (c)			-		-		-		19		19
Total Risk Management Liabilities		$	10	$	14,283	$	19	$	(13,517)	$	795

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2009
SWEPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a)		$	-	$	26,945	$	22	$	(24,007)	$	2,960
Cash Flow Hedges:
	Commodity Hedges (a)		-		216		-		(43)		173
Total Risk Management Assets		$	-	$	27,161	$	22	$	(24,050)	$	3,133
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a)		$	-	$	25,312	$	19	$	(24,312)	$	1,019
Cash Flow Hedges:
	Commodity Hedges (a)		-		89		-		(43)		46
Total Risk Management Liabilities		$	-	$	25,401	$	19	$	(24,355)	$	1,065

(a)	Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”
(b)	Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for “Derivatives and Hedging.”  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This MTM value will be amortized into revenues over the remaining life of the contracts.
(c)	See “Natural Gas Contracts with DETM” section of Note 15 in the 2009 Annual Report.
(d)	Amounts in “Other” column primarily represent cash deposits with third parties.  Level 1 amounts primarily represent investments in money market funds.
(e)	Amounts in “Other” column primarily represent accrued interest receivables from financial institutions.  Level 2 amounts primarily represent investments in money market funds.
(f)	Amounts represent publicly traded equity securities and equity-based mutual funds.
(g)	Substantially comprised of power contracts for APCo, CSPCo, I&M and OPCo and coal contracts for PSO and SWEPCo.

There have been no transfers between Level 1 and Level 2 during the nine months ended September 30, 2010.

221

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

Three Months Ended September 30, 2010		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of June 30, 2010		$	10,874	$	6,153	$	6,209	$	7,069	$	(2)	$	(2)
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		(1,680)		(845)		(850)		(981)		2		2
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		5,941		-		9,258		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		-		-		-		-		-		-
Purchases, Issuances and Settlements (c)			195		118		133		157		2		3
Transfers into Level 3 (d) (h)			380		215		217		247		-		-
Transfers out of Level 3 (e) (h)			(890)		(503)		(508)		(579)		(1)		(2)
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		7,686		(1,532)		4,757		(3,514)		1		1
Balance as of September 30, 2010		$	16,565	$	9,547	$	9,958	$	11,657	$	2	$	2

Nine Months Ended September 30, 2010		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of December 31, 2009		$	9,428	$	4,776	$	4,816	$	5,569	$	2	$	3
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		1,269		713		721		825		1		3
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		10,670		-		14,651		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		-		-		-		-		-		-
Purchases, Issuances and Settlements (c)			(5,463)		(3,059)		(3,100)		(3,565)		(1)		(2)
Transfers into Level 3 (d) (h)			986		530		528		615		-		-
Transfers out of Level 3 (e) (h)			(2,088)		(1,195)		(1,199)		(1,376)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		12,433		(2,888)		8,192		(5,062)		-		(2)
Balance as of September 30, 2010		$	16,565	$	9,547	$	9,958	$	11,657	$	2	$	2

222

Three Months Ended September 30, 2009		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of June 30, 2009		$	13,900	$	7,372	$	7,135	$	9,410	$	12	$	15
Realized (Gain) Loss Included in Net Income
	(or Changes in Net Assets) (a)		(2,762)		(1,465)		(1,418)		(2,087)		(11)		(13)
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		347		-		(185)		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		-		-		-		-		-		-
Purchases, Issuances and Settlements			-		-		-		-		-		-
Transfers in and/or out of Level 3 (f)			2,322		1,231		1,192		1,525		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		10,188		5,047		5,176		5,723		4		4
Balance as of September 30, 2009		$	23,648	$	12,532	$	12,085	$	14,386	$	5	$	6

Nine Months Ended September 30, 2009		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of December 31, 2008		$	8,009	$	4,497	$	4,352	$	5,563	$	(2)	$	(3)
Realized (Gain) Loss Included in Net Income
	(or Changes in Net Assets) (a)		(6,448)		(3,621)		(3,504)		(4,473)		3		5
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		6,069		-		6,906		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		-		-		-		-		-		-
Purchases, Issuances and Settlements			-		-		-		-		-		-
Transfers in and/or out of Level 3 (f)			(328)		(184)		(178)		(228)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		22,415		5,771		11,415		6,618		4		4
Balance as of September 30, 2009		$	23,648	$	12,532	$	12,085	$	14,386	$	5	$	6

(a)	Included in revenues on the Condensed Statements of Income.
(b)	Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c)	Represents the settlement of risk management commodity contracts for the reporting period.
(d)	Represents existing assets or liabilities that were previously categorized as Level 2.
(e)	Represents existing assets or liabilities that were previously categorized as Level 3.
(f)	Represents existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period.
(g)	Relates to the net gains (losses) of those contracts that are not reflected on the Condensed Statements of Income.  These net gains (losses) are recorded as regulatory assets/liabilities.
(h)	Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.

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10.  INCOME TAXES

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

The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2001.  The Registrant Subsidiaries have completed the exam for the years 2001 through 2006 and have issues that are being pursued at the appeals level.  The years 2007 and 2008 are currently under examination.  Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for income taxes have been made for potential liabilities resulting from such matters.  In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions.  Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on net income.

The Registrant Subsidiaries file income tax returns in various state and local jurisdictions.  These taxing authorities routinely examine their tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions.  Management believes that previously filed tax returns have positions that may be challenged by these tax authorities.  However, management believes that the ultimate resolution of these audits will not materially impact net income.  With few exceptions, the Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2000.

Federal Legislation – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

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

	Net Reduction		Tax
	to Deferred		Regulatory		Decrease in
Company	Tax Assets		Assets, Net		Net Income
	(in thousands)
APCo	$	9,397	$	8,831	$	566
CSPCo		4,386		2,970		1,416
I&M		7,212		6,528		684
OPCo		8,385		4,020		4,365
PSO		3,172		3,172		-
SWEPCo		3,412		3,412		-

The Small Business Jobs Act was enacted in September 2010.  Included in this act was a one-year extension of the 50% bonus depreciation provision.  The enacted provision will not have a material impact on the Registrant Subsidiaries’ net income or financial condition but will have a material favorable impact on cash flows.

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11.  FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2010 were:

		Principal		Interest	Due
Company	Type of Debt	Amount		Rate	Date
		(in thousands)		(%)
Issuances:
APCo	Senior Unsecured Notes	$	300,000	3.40	2015
APCo	Pollution Control Bonds		17,500	4.625	2021
APCo	Pollution Control Bonds		50,000	5.375	2038
CSPCo	Floating Rate Notes		150,000	Variable	2012
I&M	Notes Payable		84,500	4.00	2014
OPCo	Pollution Control Bonds		79,450	3.25	2014
OPCo	Pollution Control Bonds		86,000	3.125	2015
OPCo	Pollution Control Bonds		39,130	2.875	2014
SWEPCo	Senior Unsecured Notes		350,000	6.20	2040
SWEPCo	Pollution Control Bonds		53,500	3.25	2015
PSO	Notes Payable		1,750	3.00	2025

			Principal		Interest	Due
Company		Type of Debt	Amount Paid		Rate	Date
			(in thousands)		(%)
Retirements and
	Principal Payments:
APCo		Land Note	$	14	13.718	2026
APCo		Notes Payable - Affiliated		100,000	4.708	2010
APCo		Senior Unsecured Notes		150,000	4.40	2010
APCo		Pollution Control Bonds		50,000	7.125	2010
CSPCo		Notes Payable - Affiliated		100,000	4.64	2010
I&M		Notes Payable - Affiliated		25,000	5.375	2010
I&M		Notes Payable		19,200	5.44	2013
OPCo		Senior Unsecured Notes		400,000	Variable	2010
OPCo		Pollution Control Bonds		79,450	7.125	2010
OPCo		Pollution Control Bonds		19,565	5.625	2022
OPCo		Pollution Control Bonds		19,565	5.625	2023
SWEPCo		Notes Payable - Affiliated		50,000	4.45	2010
SWEPCo		Pollution Control Bonds		53,500	Variable	2019

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

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

On behalf of OPCo, trustees held $303 million of reacquired auction-rate tax-exempt long-term debt as of September 30, 2010.

Dividend Restrictions

The Registrant Subsidiaries pay dividends to the Parent provided funds are legally available.  Various financing arrangements, charter provisions and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to the Parent in the form of dividends.

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Federal Power Act

The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.”  The term “capital account” is not defined in the Federal Power Act or its regulations.  As applicable, the Registrant Subsidiaries understand “capital account” to mean the par value of the common stock multiplied by the number of shares outstanding.

Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generating plants.  Because of their respective ownership of such plants, this reserve applies to APCo, I&M and OPCo.

None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.

Charter and Leverage Restrictions

Provisions within the articles or certificates of incorporation of the Registrant Subsidiaries relating to preferred stock or shares restrict the payment of cash dividends on common and preferred stock or shares.  Pursuant to the credit agreement leverage restrictions, the Registrant Subsidiaries must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%.

At September 30, 2010, approximately $111 million of the retained earnings of APCo, $148 million of the retained earnings of CSPCo, $29 million of the retained earnings of I&M, $49 million of the retained earnings of OPCo, $100 million of the retained earnings of SWEPCo and none of the retained earnings of PSO have restrictions related to the payment of dividends to Parent.

Utility Money Pool – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of its subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries.  The AEP System Utility Money Pool operates in accordance with the terms and conditions approved in a regulatory order.  The amount of outstanding loans (borrowings) to/from the Utility Money Pool as of September 30, 2010 and December 31, 2009 is included in Advances to/from Affiliates on each of the Registrant Subsidiaries’ balance sheets.  The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2010 are described in the following table:

									Loans
	Maximum		Maximum		Average		Average		(Borrowings)		Authorized
	Borrowings		Loans		Borrowings		Loans		to/from Utility		Short-term
	from Utility		to Utility		from Utility		to Utility		Money Pool as of		Borrowing
Company	Money Pool		Money Pool		Money Pool		Money Pool		September 30, 2010		Limit
	(in thousands)
APCo	$	438,039	$	-	$	275,422	$	-	$	(55,113)	$	600,000
CSPCo		134,592		201,486		32,368		71,571		182,225		350,000
I&M		-		223,111		-		110,696		192,779		500,000
OPCo		-		618,559		-		256,426		290,714		600,000
PSO		107,320		74,751		50,927		41,836		(23,024)		300,000
SWEPCo		78,616		274,958		39,458		218,555		213,689		350,000

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:

	Nine Months Ended September 30,
	2010			2009
Maximum Interest Rate		0.55	%		2.28	%
Minimum Interest Rate		0.09	%		0.27	%

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The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2010 and 2009 are summarized for all Registrant Subsidiaries in the following table:

	Average Interest Rate for Funds				Average Interest Rate for Funds
	Borrowed from				Loaned to
	the Utility Money Pool for the				the Utility Money Pool for the
	Nine Months Ended September 30,				Nine Months Ended September 30,
Company	2010		2009		2010		2009
APCo	0.25	%	1.14	%	-	%	-	%
CSPCo	0.18	%	1.13	%	0.27	%	0.57	%
I&M	-	%	1.46	%	0.24	%	0.49	%
OPCo	-	%	1.21	%	0.20	%	0.38	%
PSO	0.29	%	2.01	%	0.16	%	1.04	%
SWEPCo	0.19	%	1.66	%	0.27	%	0.77	%

Short-term Debt

The Registrant Subsidiaries’ outstanding short-term debt was as follows:

			September 30, 2010				December 31, 2009
			Outstanding		Interest		Outstanding		Interest
Company		Type of Debt	Amount		Rate (b)		Amount		Rate (b)
			(in thousands)				(in thousands)
SWEPCo		Line of Credit – Sabine (a)	$	3,170	2.20	%	$	6,890	2.06	%
(a)	Sabine Mining Company is a consolidated variable interest entity.
(b)	Weighted average rate.

Credit Facilities

AEP has credit facilities totaling $3 billion to support the commercial paper program.  The facilities are structured as two $1.5 billion credit facilities, of which $750 million may be issued under one credit facility as letters of credit.  In June 2010, AEP terminated one of the $1.5 billion facilities that was scheduled to mature in March 2011 and replaced it with a new $1.5 billion credit facility which matures in 2013 and allows for the issuance of up to $600 million as letters of credit.  As of September 30, 2010, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $300 thousand for I&M and $4 million for SWEPCo.

In June 2010, the Registrant Subsidiaries and certain other companies in the AEP System reduced the $627 million credit agreement to $478 million.  Under the facility, letters of credit may be issued.  As of September 30, 2010, $477 million of letters of credit were issued to support variable rate Pollution Control Bonds as follows:

Company	Amount
	(in thousands)
APCo		$	232,292
I&M			77,886
OPCo			166,899

Sale of Receivables – AEP Credit

Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables.  APCo does not have regulatory authority to sell its West Virginia accounts receivable.  The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ income statements.  The Registrant Subsidiaries manage and service their customer accounts receivable sold.

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

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of September 30, 2010 and December 31, 2009 was as follows:

	September 30,		December 31,
Company	2010		2009
	(in thousands)
APCo	$	142,747	$	143,938
CSPCo		196,949		169,095
I&M		138,134		130,193
OPCo		168,306		160,977
PSO		161,179		73,518
SWEPCo		169,235		117,297

The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:

	Three Months Ended September 30,				Nine Months Ended September 30,
Company	2010		2009		2010		2009
	(in thousands)
APCo	$	2,949	$	1,186	$	6,725	$	3,711
CSPCo		3,300		2,956		8,990		8,481
I&M		1,832		1,617		5,276		4,507
OPCo		2,345		2,340		7,494		6,351
PSO		1,537		1,738		4,287		5,397
SWEPCo		1,441		1,747		4,574		4,569

The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:

	Three Months Ended September 30,				Nine Months Ended September 30,
Company	2010		2009		2010		2009
	(in thousands)
APCo	$	338,446	$	298,997	$	1,097,276	$	923,408
CSPCo		521,030		442,079		1,368,343		1,243,325
I&M		348,039		319,932		984,631		908,007
OPCo		473,773		394,335		1,325,613		1,184,744
PSO		398,177		265,622		924,707		812,264
SWEPCo		430,270		373,805		1,087,515		1,009,124

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12.  COST REDUCTION INITIATIVES

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

Management recorded a charge to expense in the second quarter of 2010 primarily related to the headcount reduction initiatives.

	Expense		Incurred for						Remaining
	Allocation from		Registrant						Balance at
	AEPSC		Subsidiaries		Settled		Adjustments		September 30, 2010
	(in thousands)
APCo	$	20,526	$	36,399	$	48,431	$	(3,621)	$	4,873
CSPCo		11,048		21,244		28,542		(557)		3,193
I&M		12,051		32,985		39,192		(2,135)		3,709
OPCo		19,427		33,681		50,923		2,175		4,360
PSO		10,681		13,324		20,908		(651)		2,446
SWEPCo		12,588		17,074		26,430		(522)		2,710

These costs relate primarily to severance benefits.  They are included primarily in Other Operation on the income statement and Other Current Liabilities on the balance sheet.

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COMBINED MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the Registrant Subsidiaries’ management’s discussion and analysis.  The information in this section completes the information necessary for management’s discussion and analysis of financial condition and net income and is meant to be read with (i) Management’s Financial Discussion and Analysis, (ii) financial statements, (iii) footnotes and (iv) the schedules of each individual registrant.  The combined Management’s Discussion and Analysis of Registrant Subsidiaries section of the 2009 Annual Report should also be read in conjunction with this report.

EXECUTIVE OVERVIEW

Economic Conditions

The Registrant Subsidiaries’ retail margins increased primarily due to successful rate proceedings in Indiana, Ohio, Oklahoma and Virginia and higher residential and commercial demand for electricity as a result of favorable weather.  In comparison to the recessionary lows of 2009, industrial sales increased 6% in the third quarter and 5% during the first nine months of 2010 for the AEP System.  During 2009, the Registrant Subsidiaries’ operations were impacted by difficult economic conditions especially their industrial sales reflecting customers’ curtailments or closures of facilities.  In 2009, CSPCo’s and OPCo’s largest customer, Ormet, a major industrial customer, currently operating at a reduced load of approximately 330 MW, (Ormet operated at an approximate 500 MW load in 2008), announced that it will continue operations at this reduced level.  In February 2009, Century Aluminum, a major industrial customer (325 MW load) of APCo, announced the curtailment of operations at its Ravenswood, WV facility.

Capital Expenditures

In October 2010, management announced capital expenditures budgets by Registrant Subsidiaries for 2011 as follows:

	Budgeted
	Construction
Company	Expenditures
	(in millions)
APCo		$	466
CSPCo			178
I&M			307
OPCo			271
PSO			171
SWEPCo			457

ENVIRONMENTAL ISSUES

The Registrant Subsidiaries are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements. The Registrant Subsidiaries will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants from fossil fuel-fired power plants and new proposals governing the beneficial use and disposal of coal combustion products.

The Registrant Subsidiaries are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of I&M’s nuclear units.  Management is also involved in development of possible future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change.  See a complete discussion of these matters in the “Environmental Matters” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2009 Annual Report.

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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.  PSO’s and SWEPCo’s 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 the AEP System operates would be subject to seasonal and annual NOx programs and an annual SO2 emissions reduction program that takes effect in two phases.  The first phase 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 stringency of the additional emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and its electric utility customers, as these features could accelerate unit retirements, increase capital requirements, constrain operations, decrease reliability and unfavorably impact financial condition if the increased costs are suspended during the early development stages not recovered in rates or market prices.  Comments on the proposed rule were due on October 1, 2010.  The AEP System’s 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.  Management believes that the Federal EPA made erroneous assumptions about the existence and/or capabilities of current control equipment at certain of the AEP System’s units, used timeframes for installation of new controls that are inconsistent with 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.  Management will urge the Federal EPA to carefully consider all of the options available so that costly and inefficient control requirements are not imposed regardless of unit size, age or other operating characteristics.  However, the AEP System has approximately 5,000 MW of older coal units, including 2,000 MW of older coal-fired capacity already subject to control requirements under the NSR consent decree, for which it may be economically inefficient to install scrubbers or other environmental controls.  The timing and ultimate disposition of those units will be affected by: a) the MACT standards and other environmental regulations, b) the economics of maintaining the units, c) demand for electricity, d) availability and cost of replacement power and e) regulatory decisions about cost recovery of the remaining investment in those units.

Coal Combustion Residual Rule

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

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Currently, approximately 40% of the coal ash and other residual products from the AEP System’s generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses.  Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes.  In addition,   surface impoundments and landfills to manage these materials are currently used at the generating facilities. The Registrant Subsidiaries will incur significant costs to upgrade or close and replace their existing facilities.  Management estimates that the potential compliance costs associated with the proposed solid waste management alternative could be as high as a total of $3.9 billion for units across the AEP System.  Regulation of these materials as hazardous wastes would significantly increase these costs.  The Registrant Subsidiaries will seek recovery of expenditures for pollution control technologies and associated costs from customers through regulated rates or market prices for electricity.  If these costs are not recovered, it will have a material adverse impact on net income, cash flows and financial condition.

Global Warming

While comprehensive economy-wide regulation of CO2 emissions might be achieved through new legislation, Congress has yet to enact such legislation.  The Federal EPA continues to take action to regulate CO2 emissions under the existing requirements of the CAA.  The Federal EPA issued a final endangerment finding for CO2 emissions from new motor vehicles in December 2009 and final rules for new motor vehicles in May 2010.  The Federal EPA determined that CO2 emissions from stationary sources will be subject to regulation under the CAA 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.

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

Several states have adopted programs that directly regulate CO2 emissions from power plants, but none of these programs are currently in effect in states where the Registrant Subsidiaries have generating facilities.  Certain states, including Ohio, Michigan, Texas and Virginia, passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements.  The Registrant Subsidiaries 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.  The Registrant Subsidiaries have been named in pending lawsuits, which management is vigorously defending.  It is not possible to predict the outcome of these lawsuits or their impact on operations or financial condition.  See “Carbon Dioxide Public Nuisance Claims” and “Alaskan Villages’ Claims” sections of Note 4.

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

For detailed information on global warming and the actions the AEP System is taking 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 “Combined Management Discussion and Analysis of Registrant Subsidiaries.”

FINANCIAL CONDITION

LIQUIDITY

Sources of Funding

Short-term funding for the Registrant Subsidiaries comes from AEP’s commercial paper program and revolving credit facilities through the Utility Money Pool.  AEP and its Registrant Subsidiaries operate a money pool to minimize the AEP System’s external short-term funding requirements and sell accounts receivable to provide liquidity.  Under credit facilities, $1.35 billion may be issued as letters of credit (LOC).  The Registrant Subsidiaries generally use short-term funding sources (the Utility Money Pool or receivables sales) to provide for interim financing of capital expenditures that exceed internally generated funds and periodically reduce their outstanding short-term debt through issuances of long-term debt, sale-leasebacks, leasing arrangements and additional capital contributions from Parent.

The Registrant Subsidiaries and certain other companies in the AEP System entered into a 3-year credit agreement which matures in April 2011.  In June 2010, the credit facility was reduced from $627 million to $478 million.  The Registrant Subsidiaries may issue LOCs under the credit facility.  Each subsidiary has a borrowing/LOC limit under the credit facility.  As of September 30, 2010, a total of $477 million of LOCs were issued under the credit agreement to support variable rate demand notes.  The following table shows each Registrant Subsidiaries’ borrowing/LOC limit under the credit facility and the outstanding amount of LOCs.

			LOC Amount
			Outstanding
	Credit Facility		Against the
	Borrowing/LOC		Agreement at
Company	Limit		September 30, 2010
	(in millions)
APCo	$	300	$	232
CSPCo		230		-
I&M		230		78
OPCo		400		167
PSO		65		-
SWEPCo		230		-

Dividend Restrictions

Under the Federal Power Act, the Registrant Subsidiaries are restricted from paying dividends out of stated capital.  Various financing arrangements, charter provisions and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

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Sales of Receivables

In July 2010, AEP Credit renewed its receivables securitization agreement.  The agreement provides a commitment of $750 million from bank conduits to purchase receivables.  A commitment of $375 million expires in July 2011 and the remaining commitment of $375 million expires in July 2013. AEP Credit purchases accounts receivable from the Registrant Subsidiaries.

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.

NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Pronouncement Adopted During  2010

The Registrant Subsidiaries prospectively adopted ASU 2009-17 “Consolidation” effective January 1, 2010.  SWEPCo no longer consolidates DHLC effective with the adoption of this standard.

See Note 2 for further discussion of accounting pronouncements.

Future Accounting Changes

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

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

The Registrant Subsidiaries’ risk management assets and liabilities are managed by AEPSC as agent.  The related risk management policies and procedures are instituted and administered by AEPSC.  See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section.  Also, see Note 8 – Derivatives and Hedging and Note 9 – Fair Value Measurements for additional information related to the Registrant Subsidiaries’ risk management contracts.

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

	MTM Risk Management Contract Net Assets (Liabilities)
	Nine Months Ended September 30, 2010
	(in thousands)
APCo
Total MTM Risk Management Contract Net Assets at December 31, 2009		$	45,197
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period			(21,694)
Fair Value of New Contracts at Inception When Entered During the Period (a)			-
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
	During the Period		(245)
Changes in Fair Value Due to Market Fluctuations During the Period (c)			61
Changes in Fair Value Allocated to Regulated Jurisdictions (d)			9,815
Total MTM Risk Management Contract Net Assets			33,134
Cash Flow Hedge Contracts			(4,513)
DETM Assignment (e)			(632)
Collateral Deposits			40,554
Total MTM Derivative Contract Net Assets at September 30, 2010		$	68,543
OPCo
Total MTM Risk Management Contract Net Assets at December 31, 2009		$	26,330
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period			(12,940)
Fair Value of New Contracts at Inception When Entered During the Period (a)			7,641
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b)			(715)
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
	During the Period		(363)
Changes in Fair Value Due to Market Fluctuations During the Period (c)			6,615
Changes in Fair Value Allocated to Regulated Jurisdictions (d)			(5,062)
Total MTM Risk Management Contract Net Assets			21,506
Cash Flow Hedge Contracts			(2,320)
DETM Assignment (e)			(445)
Collateral Deposits			28,660
Total MTM Derivative Contract Net Assets at September 30, 2010		$	47,401

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PSO
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2009		$	(369)
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period			263
Fair Value of New Contracts at Inception When Entered During the Period (a)			-
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
	During the Period		(42)
Changes in Fair Value Due to Market Fluctuations During the Period (c)			(7)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)			3,190
Total MTM Risk Management Contract Net Assets			3,035
Cash Flow Hedge Contracts			-
DETM Assignment (e)			(16)
Collateral Deposits			55
Total MTM Derivative Contract Net Assets at September 30, 2010		$	3,074
SWEPCo
Total MTM Risk Management Contract Net Assets at December 31, 2009		$	1,636
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period			(1,422)
Fair Value of New Contracts at Inception When Entered During the Period (a)			-
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
	During the Period		(101)
Changes in Fair Value Due to Market Fluctuations During the Period (c)			-
Changes in Fair Value Allocated to Regulated Jurisdictions (d)			1,530
Total MTM Risk Management Contract Net Assets			1,643
Cash Flow Hedge Contracts			(71)
DETM Assignment (e)			(19)
Collateral Deposits			88
Total MTM Derivative Contract Net Assets at September 30, 2010		$	1,641

(a)	Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  The contract prices are valued against market curves associated with the delivery location and delivery term.  A significant portion of the total volumetric position has been economically hedged.
(b)	Reflects changes in methodology in calculating the credit and discounting liability fair value adjustments.
(c)	Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(d)	Relates to the net gains (losses) of those contracts that are not reflected on the Condensed Statements of Income.  These net gains (losses) are recorded as regulatory liabilities/assets.
(e)	See “Natural Gas Contracts with DETM” section of Note 15 of the 2009 Annual Report.

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The following tables present the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate or (require) cash:

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets (Liabilities)
September 30, 2010
(in thousands)
		Remainder
APCo		2010		2011-2013		2014+		Total
Level 1 (a)		$	25	$	36	$	-	$	61
Level 2 (b)			3,183		7,092		1,411		11,686
Level 3 (c)			1,497		11,391		3,677		16,565
Total			4,705		18,519		5,088		28,312
Dedesignated Risk Management
	Contracts (d)		1,451		3,371		-		4,822
Total MTM Risk Management
	Contract Net Assets	$	6,156	$	21,890	$	5,088	$	33,134
		Remainder
OPCo		2010		2011-2013		2014+		Total
Level 1 (a)		$	18	$	26	$	-	$	44
Level 2 (b)			1,017		4,402		993		6,412
Level 3 (c)			1,054		8,016		2,587		11,657
Total			2,089		12,444		3,580		18,113
Dedesignated Risk Management
	Contracts (d)		1,021		2,372		-		3,393
Total MTM Risk Management
	Contract Net Assets	$	3,110	$	14,816	$	3,580	$	21,506

		Remainder
PSO		2010		2011-2013		Total
Level 1 (a)		$	1	$	-	$	1
Level 2 (b)			1,731		1,301		3,032
Level 3 (c)			2		-		2
Total MTM Risk Management
	Contract Net Assets	$	1,734	$	1,301	$	3,035
		Remainder
SWEPCo		2010		2011-2013		Total
Level 1 (a)		$	1	$	-	$	1
Level 2 (b)			992		648		1,640
Level 3 (c)			2		-		2
Total MTM Risk Management
	Contract Net Assets	$	995	$	648	$	1,643

(a)	Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.  Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.
(b)	Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.  If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1 and OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market.
(c)	Level 3 inputs are unobservable inputs for the asset or liability.  Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.
(d)	Dedesignated Risk Management Contracts are contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for “Derivatives and Hedging.”  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This will be amortized into Revenues over the remaining life of the contracts.

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Credit Risk

Counterparty credit quality and exposure is generally consistent with that of AEP.

Value at Risk (VaR) Associated with Risk Management Contracts

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

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

	Nine Months Ended									Twelve Months Ended
	September 30, 2010									December 31, 2009
Company		End		High		Average		Low		End		High		Average		Low
	(in thousands)									(in thousands)
APCo		$	96	$	659	$	216	$	71	$	275	$	699	$	333	$	151
OPCo			82		545		180		54		201		530		244		113
PSO			14		70		17		1		10		34		12		4
SWEPCo			20		93		24		2		16		49		18		6

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

As the VaR calculations capture recent price movements, management also performs regular stress testing of the portfolio to understand the exposure to extreme price movements.  Management employs a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last four years in order to ascertain which historical price movements translated into the largest potential MTM loss.  Management then researches the underlying positions, price movements and market events that created the most significant exposure and report the findings to the Risk Executive Committee or the Commercial Operations Risk Committee as appropriate.

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on the Registrant Subsidiaries’ outstanding debt as of September 30, 2010 and December 31, 2009, the estimated EaR on the Registrant Subsidiaries’ debt portfolio was as follows:

	September 30,		December 31,
Company	2010		2009
	(in thousands)
APCo	$	1,301	$	1,837
CSPCo		202		216
I&M		337		227
OPCo		1,058		1,373
PSO		43		119
SWEPCo		666		305

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CONTROLS AND PROCEDURES

During the third quarter of 2010, management, including the principal executive officer and principal financial officer of each of AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo (collectively, the Registrants), evaluated the Registrants’ disclosure controls and procedures.  Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of September 30, 2010, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.  The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the third quarter of 2010 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

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PART II.  OTHER INFORMATION

Item 1.     Legal Proceedings

For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 4incorporated herein by reference.

Item 1A.  Risk Factors

Our Annual Report on Form 10-K for the year ended December 31, 2009 includes a detailed discussion of our risk factors.  The information presented below amends and restates in their entirety certain of those risk factors that have been updated and should be read in conjunction with the risk factors and information disclosed in our 2009 Annual Report on Form 10-K.

General Risks of Our Regulated Operations

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

In June 2010, the APSC issued an order which reversed and set aside the previously granted CECPN.  SWEPCo filed a notice with the APSC of its intent to proceed with construction of the Turk Plant but that SWEPCo no longer intends to pursue a CECPN to seek recovery of the originally approved 88 MW portion of Turk Plant costs in Arkansas retail rates.

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

The wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009.  In February 2010, the Sierra Club, the Audubon Society and others filed a complaint in the Federal District Court for the Western District of Arkansas against the U.S. Army Corps of Engineers challenging the process used and the terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts.  In May 2010, plaintiffs filed with the Federal District Court for the Western District of Arkansas seeking a preliminary injunction to halt construction and for a temporary restraining order.  

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 a temporary restraining order and preliminary injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws.  This motion for preliminary injunction was heard simultaneously with the motion filed by the Sierra Club.  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.

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In January 2009, SWEPCO was granted CECPNs by the APSC to build three transmission lines and facilities authorized by the SPP and needed to transmit power from the Turk Plant.  Intervenors appealed the CECPN decisions in April 2009 to the Arkansas Court of Appeals.  In July 2010, the Hempsted County Hunting Club and other appellants filed with the Arkansas Court of Appeals emergency motions to stay the transmission CECPNs to prohibit SWEPCo from taking ownership of private property and undertaking construction of the transmission lines.  In July 2010, the Arkansas Court of Appeals issued a decision remanding all transmission line CECPN appeals to the APSC.  As a result, a stay was not ordered and construction continues on the affected transmission lines.

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 impact financial condition.

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

Ohio law requires that the PUCO determine, following the end of each year of the ESP, if rate adjustments included in the ESP resulted in significantly excessive earnings.  If the rate adjustments, in the aggregate, result in significantly excessive earnings, the excess amount could be returned to customers.  In September 2010, CSPCo and OPCo filed their 2009 SEET filings with the PUCO.  CSPCo’s and OPCo’s returns on common equity were 20.84% and 10.81%, respectively, including off-system sales margins and 18.31% and 9.42%, respectively, excluding off-system sales margins.  Included in the filings was CSPCo’s and OPCo’s determination that the level at which their earned return on common equity may become significantly in excess of the average earned return on common equity of the comparable risk group of publicly traded firms was 22.51%.  Based upon the methodology proposed by CSPCo and OPCo in the SEET filings, neither CSPCo’s nor OPCo’s 2009 return on common 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 common equity was significantly excessive, CSPCo and/or OPCo may be required to return a portion of their ESP revenues to customers.

Ohio may require us to refund fuel costs that we have collected. (Applies to OPCo)

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

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

The Industrial Energy Users-Ohio filed a notice of appeal of the 2009 and 2010 PUCO-approved Economic Development Rider (EDR) with the Supreme Court of Ohio.  As of September 30, 2010, CSPCo and OPCo have incurred $39 million and $30 million, respectively, in EDR costs including carrying costs.  Of these costs, CSPCo and OPCo have collected $27 million and $20 million, respectively, through the EDR, which CSPCo and OPCo began collecting in January 2010.  The remaining $12 million and $10 million for CSPCo and OPCo, respectively, are recorded as EDR regulatory assets.  If CSPCo and OPCo are not ultimately permitted to recover their deferrals or are required to refund revenue collected, it would reduce future net income and cash flows and impact financial condition.

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Texas may require us to refund fuel costs that we have collected. (Applies to SWEPCo)

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

In September 2010, the Administrative Law Judges issued a Proposal for Decision (PFD) that recommended a disallowance of a significant portion of the charges to a ten-year gas transportation agreement that began in 2009 for the Mattison Plant located in Northwest Arkansas.  The PFD stated that SWEPCo should have pursued other transportation options or sought the supplier’s recourse rate from the FERC.  The estimated recommended disallowance over the ten-year period through December 2018 is $107 million for which the estimated Texas jurisdictional portion is $37 million.  In addition, the PFD also contained recommendations to disallow risk premiums related to the ERCOT trading contracts transferred to AEPEP which are estimated to be $1.5 million on a Texas retail jurisdictional basis.  Through September 30, 2010, SWEPCo’s management estimated the impact of this PFD, if adopted by the PUCT, to be $7 million.  In October 2010, SWEPCo filed exceptions on these issues with the PUCT.  An order may be issued in the fourth quarter of 2010.  Management is unable to predict the outcome of this reconciliation.  If the PUCT disallows any portion of SWEPCo’s fuel and purchase power costs, it could reduce future net income and cash flows and possibly impact financial condition.

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

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

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

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

Our request for rate recovery in Oklahoma may not be approved in its entirety.  (Applies to AEP and PSO)

In July 2010, PSO filed a request with the OCC to increase annual base rates by $82 million, including $30 million that is currently being recovered through a rider.  The requested increase includes a $24 million increase in depreciation and an 11.5% return on common equity.  In October 2010, various parties filed testimony.  The parties’ net annual rate recommendations ranged from a rate reduction of $18 million to an increase of less than $1 million.  If the OCC denies all or part of the requested rate recovery, it could reduce future net income and cash flows.

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Risks Related to State Restructuring

Our customers have recently begun to select alternative electric generation service providers, as allowed by Ohio legislation. (Applies to AEP and CSPCo)

Under current Ohio legislation, electric generation is sold in a competitive market in Ohio, and our native load customers in Ohio have the ability to switch to alternative suppliers for their electric generation service.  Competitive power suppliers are targeting retail customers by offering alternative generation service.   A growing number of CSPCo's commercial retail customers have switched to alternative generation providers while additional Ohio customers have provided notice of their intent to switch.  These evolving market conditions may continue to impact CSPCo's results of operations and its ability to apply regulatory accounting treatment to certain portions of its operations.

Risks Related to Owning and Operating Generation Assets and Selling Power

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

Cook Plant Unit 1 is a 1,084 MW nuclear generating unit located in Bridgman, Michigan.  In September 2008, I&M shut down Unit 1 due to turbine vibrations, caused by blade failure, which resulted in significant turbine damage and a small fire on the electric generator.  Unit 1 resumed operations in December 2009 at slightly reduced power, but repair of the property damage and replacement of the turbine rotors and other equipment are estimated to cost approximately $395 million.  Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process.

In March 2009, the IURC approved a settlement agreement with intervenors to collect a prior under-recovered fuel balance. Under the settlement agreement, a subdocket was established to consider issues relating to the Unit 1 shutdown including the treatment of the accidental outage insurance proceeds.  Separately, in March 2010, I&M filed its 2009 PSCR reconciliation with the MPSC.  The filing included an adjustment related to the incremental fuel cost of replacement power due to the Cook Plant Unit 1 outage.  If any fuel clause revenues or accidental outage insurance proceeds have to be refunded, it would reduce future net income and cash flows and impact financial condition.

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

In July 2010, federal legislation was enacted to reform financial markets that significantly alter how over-the-counter (OTC) derivatives are regulated.  The law increased regulatory oversight of OTC energy derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the Commodity Futures Trading Commission (CFTC), (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits.  The law gives the CFTC authority to exempt end users of energy commodities which could reduce, but not eliminate, the applicability of these measures to us and other end users.  These requirements could cause our OTC transactions to be more costly and have an adverse effect on our liquidity due to additional capital requirements.  In addition, as these reforms aim to standardize OTC products it could limit the effectiveness of our hedging programs because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to protect.

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Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information about purchases by AEP or its publicly-traded subsidiaries during the quarter ended September 30, 2010 of equity securities that are registered by AEP or its publicly-traded subsidiaries pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASES OF EQUITY SECURITIES

Period	Total Number of Shares Purchased			Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
07/01/10 – 07/31/10		-		$	-		-	$	-
08/01/10 – 08/31/10		6	(a)		71.50		-		-
09/01/10 – 09/30/10		-			-		-		-

(a) APCo purchased 3 shares of its 4.50% cumulative preferred stock and I&M purchased 3 shares of its 4.125% cumulative preferred stock in privately-negotiated transactions outside of an announced program.

Item 5.  Other Information

NONE

Item 6.  Exhibits

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

12 – Computation of Consolidated Ratio of Earnings to Fixed Charges.

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

31(a) – Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31(b) – Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

32(a) – Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

32(b) – Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

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SIGNATURE

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

AMERICAN ELECTRIC POWER COMPANY, INC.

 By: /s/Joseph M. Buonaiuto

 Joseph M. Buonaiuto

 Controller and Chief Accounting Officer

APPALACHIAN POWER COMPANY

COLUMBUS SOUTHERN POWER COMPANY

INDIANA MICHIGAN POWER COMPANY

OHIO POWER COMPANY

PUBLIC SERVICE COMPANY OF OKLAHOMA

SOUTHWESTERN ELECTRIC POWER COMPANY

 By: /s/Joseph M. Buonaiuto

 Joseph M. Buonaiuto

 Controller and Chief Accounting Officer

Date:  November 1, 2010

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