Indiana Michigan Power 10-Q 2011 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For The Quarterly Period Ended June 30, 2011

OR

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For The Transition Period from ____ to ____

Commission	Registrants; States of Incorporation;	I.R.S. Employer
File Number	Address and Telephone Number	Identification Nos.
1-3525	AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation)	13-4922640
1-3457	APPALACHIAN POWER COMPANY (A Virginia Corporation)	54-0124790
1-2680	COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation)	31-4154203
1-3570	INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)	35-0410455
1-6543	OHIO POWER COMPANY (An Ohio Corporation)	31-4271000
0-343	PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)	73-0410895
1-3146	SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation)	72-0323455
	1 Riverside Plaza, Columbus, Ohio 43215-2373
	Telephone (614) 716-1000

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
Yes	X	No

Indicate by check mark whether American Electric Power Company, Inc. has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes	X	No

Indicate by check mark whether Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company have submitted electronically and posted on the AEP corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes	X	No

Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of ‘large accelerated filer,’ ‘accelerated filer’ and ‘smaller reporting company’ in Rule 12b-2 of the Exchange Act.
Large accelerated filer	X	Accelerated filer
Non-accelerated filer		Smaller reporting company

Indicate by check mark whether Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers or smaller reporting companies.  See the definitions of ‘large accelerated filer,’ ‘accelerated filer’ and ‘smaller reporting company’ in Rule 12b-2 of the Exchange Act.
Large accelerated filer		Accelerated filer
Non-accelerated filer	X	Smaller reporting company

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

Columbus Southern Power Company and Indiana Michigan Power Company meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.

	Number of shares of common stock outstanding of the registrants at July 28, 2011
American Electric Power Company, Inc.	482,273,829
	($6.50 par value)
Appalachian Power Company	13,499,500
	(no par value)
Columbus Southern Power Company	16,410,426
	(no par value)
Indiana Michigan Power Company	1,400,000
	(no par value)
Ohio Power Company	27,952,473
	(no par value)
Public Service Company of Oklahoma	9,013,000
	($15 par value)
Southwestern Electric Power Company	7,536,640
	($18 par value)

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX OF QUARTERLY REPORTS ON FORM 10-Q

June 30, 2011

			Page Number
Glossary of Terms			i
Forward-Looking Information			iv
Part I. FINANCIAL INFORMATION
		Items 1, 2 and 3 - Financial Statements, Management’s Discussion and Analysis and Quantitative and Qualitative Disclosures About Market Risk:
American Electric Power Company, Inc. and Subsidiary Companies:
	Management’s Discussion and Analysis		1
	Quantitative and Qualitative Disclosures About Market Risk		22
	Condensed Consolidated Financial Statements		26
	Index of Condensed Notes to Condensed Consolidated Financial Statements		31
Appalachian Power Company and Subsidiaries:
	Management’s Discussion and Analysis		81
	Quantitative and Qualitative Disclosures About Market Risk		89
	Condensed Consolidated Financial Statements		90
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		95
Columbus Southern Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis		97
	Quantitative and Qualitative Disclosures About Market Risk		103
	Condensed Consolidated Financial Statements		104
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		109
Indiana Michigan Power Company and Subsidiaries:
	Management’s Narrative Discussion and Analysis		111
	Quantitative and Qualitative Disclosures About Market Risk		115
	Condensed Consolidated Financial Statements		116
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		121
Ohio Power Company Consolidated:
	Management’s Discussion and Analysis		123
	Quantitative and Qualitative Disclosures About Market Risk		130
	Condensed Consolidated Financial Statements		131
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		136
Public Service Company of Oklahoma:
	Management’s Discussion and Analysis		138
	Quantitative and Qualitative Disclosures About Market Risk		142
	Condensed Financial Statements		143
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		148
Southwestern Electric Power Company Consolidated:
	Management’s Discussion and Analysis		150
	Quantitative and Qualitative Disclosures About Market Risk		155
	Condensed Consolidated Financial Statements		156
	Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries		161

Index of Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries				162
Combined Management’s Discussion and Analysis of Registrant Subsidiaries				227
Controls and Procedures				238
Part II.  OTHER INFORMATION
	Item 1.	Legal Proceedings		239
	Item 1A.	Risk Factors		239
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		242
	Item 5.	Other Information		243
	Item 6.	Exhibits:		243
			Exhibit 4(d)
			Exhibit 4(e)
			Exhibit 12
			Exhibit 31(a)
			Exhibit 31(b)
			Exhibit 32(a)
			Exhibit 32(b)
SIGNATURE				244

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

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

Term Meaning

AEGCo	AEP Generating Company, an AEP electric utility subsidiary.
AEP or Parent	American Electric Power Company, Inc., a holding company.
AEP Consolidated	AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit	AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East companies	APCo, CSPCo, I&M, KPCo and OPCo.
AEP Power Pool	Members are APCo, CSPCo, I&M, KPCo and OPCo.  The AEP Power Pool shares the generation, cost of generation and resultant wholesale off-system sales of the member companies.
AEP System or the System	American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEPEP	AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, asset management and commercial and industrial sales in the deregulated Texas market.
AEPSC	American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC	Allowance for Funds Used During Construction.
AOCI	Accumulated Other Comprehensive Income.
APCo	Appalachian Power Company, an AEP electric utility subsidiary.
APSC	Arkansas Public Service Commission.
ASU	Accounting Standard Update.
BOA	Bank of America Corporation.
CAA	Clean Air Act.
CLECO	Central Louisiana Electric Company, a nonaffiliated utility company.
CO2	Carbon Dioxide and other greenhouse gases.
Cook Plant	Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M.
CSPCo	Columbus Southern Power Company, an AEP electric utility subsidiary.
CTC	Competition Transition Charge, a transition charge applied to TCC’s transmission and distribution rates for stranded costs and other true-up amounts as required by the Texas Restructuring Legislation.
DCC Fuel	DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC, variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DHLC	Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
E&R	Environmental compliance and transmission and distribution system reliability.
EIS	Energy Insurance Services, Inc., a nonaffiliated captive insurance company.
ERCOT	Electric Reliability Council of Texas, an intrastate RTO.
ESP	Electric Security Plans, filed with the PUCO, pursuant to the Ohio Amendments.
ETT	Electric Transmission Texas, LLC, an equity interest joint venture between AEP Utilities, Inc. and MidAmerican Energy Holdings Company Texas Transco, LLC formed to own and operate electric transmission facilities in ERCOT.
FAC	Fuel Adjustment Clause.
FASB	Financial Accounting Standards Board.
Federal EPA	United States Environmental Protection Agency.
FERC	Federal Energy Regulatory Commission.
FGD	Flue Gas Desulfurization or Scrubbers.
FTR	Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.

i

Term	Meaning
GAAP	Accounting Principles Generally Accepted in the United States of America.
I&M	Indiana Michigan Power Company, an AEP electric utility subsidiary.
IGCC	Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
Interconnection Agreement	Agreement, dated July 6, 1951, as amended, by and among APCo, CSPCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants.
IRS	Internal Revenue Service.
IURC	Indiana Utility Regulatory Commission.
KGPCo	Kingsport Power Company, an AEP electric utility subsidiary.
KPCo	Kentucky Power Company, an AEP electric utility subsidiary.
KWH	Kilowatthour.
LPSC	Louisiana Public Service Commission.
MISO	Midwest Independent Transmission System Operator.
MMBtu	Million British Thermal Units.
MPSC	Michigan Public Service Commission.
MTM	Mark-to-Market.
MW	Megawatt.
NEIL	Nuclear Electric Insurance Limited insures domestic and international nuclear utilities for the costs associated with interruptions, damages, decontaminations and related nuclear risks.
NOx	Nitrogen oxide.
Nonutility Money Pool	AEP’s Nonutility Money Pool is the centralized funding mechanism AEP uses to meet the short term cash requirements of pool participants.
NSR	New Source Review.
OCC	Corporation Commission of the State of Oklahoma.
OPCo	Ohio Power Company, an AEP electric utility subsidiary.
OPEB	Other Postretirement Benefit Plans.
OTC	Over the counter.
PJM	Pennsylvania – New Jersey – Maryland, a RTO.
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, responsible for moving electricity over large interstate areas.
Sabine	Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity.
SEET	Significantly Excessive Earnings Test.
SIA	System Integration Agreement, effective June 15, 2000, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SNF	Spent Nuclear Fuel.
SO2	Sulfur Dioxide.
SPP	Southwest Power Pool, a RTO.

ii

Term	Meaning
Stall Unit	J. Lamar Stall Unit at Arsenal Hill Plant.
SWEPCo	Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC	AEP Texas Central Company, an AEP electric utility subsidiary.
Texas Restructuring   Legislation	Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC	AEP Texas North Company, an AEP electric utility subsidiary.
Transition Funding	AEP Texas Central Transition Funding I LLC and AEP Texas Central Transition Funding II LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas restructuring law.
True-up Proceeding	A filing made under the Texas Restructuring Legislation to finalize the amount of stranded costs and other true-up items and the recovery of such amounts.
Turk Plant	John W. Turk, Jr. Plant.
Utility Money Pool	AEP System’s Utility Money Pool is the centralized funding mechanism AEP uses to meet the short term cash requirements of pool participants.
VIE	Variable Interest Entity.
Virginia SCC	Virginia State Corporation Commission.
WPCo	Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC	Public Service Commission of West Virginia.

iii

FORWARD-LOOKING INFORMATION

This report made by AEP and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Item 7 – Management’s Financial Discussion and Analysis” of the 2010 Annual Report, but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, we undertake no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

· The economic climate and growth in, or contraction within, our service territory and changes in market demand and demographic patterns.

· Inflationary or deflationary interest rate trends.

· Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.

· The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.

· Electric load, customer growth and the impact of retail competition, particularly in Ohio.

· Weather conditions, including storms, and our ability to recover significant storm restoration costs through applicable rate mechanisms.

· Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.

· Availability of necessary generating capacity and the performance of our generating plants.

· Our ability to resolve I&M’s Donald C. Cook Nuclear Plant Unit 1 restoration and outage-related issues through warranty, insurance and the regulatory process.

· Our ability to recover regulatory assets and stranded costs in connection with deregulation.

· Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.

· Our ability to build or acquire generating capacity, including the Turk Plant, and transmission lines and facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are cancelled) through applicable rate cases or competitive rates.

· New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation and cost recovery of our plants.

· Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.

· Resolution of litigation.

· Our ability to constrain operation and maintenance costs.

· Our ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities.

· Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.

· Actions of rating agencies, including changes in the ratings of debt.

· Volatility and changes in markets for electricity, natural gas, coal, nuclear fuel and other energy-related commodities.

· Changes in utility regulation, including the implementation of ESPs and related regulation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP.

· Accounting pronouncements periodically issued by accounting standard-setting bodies.

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· The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact on future funding requirements.

· Prices and demand for power that we generate and sell at wholesale.

· Changes in technology, particularly with respect to new, developing or alternative sources of generation.

· Our ability to recover through rates or prices any remaining unrecovered investment in generating units that may be retired before the end of their previously projected useful lives.

· Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.

· Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.

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

v

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Financial Results

Gross margins increased during the first six months of 2011 primarily due to successful rate proceedings in our various jurisdictions.  While our overall weather-related margins were slightly lower than 2010, cooling degree days and heating degree days were higher than normal throughout our service territories.

Regulatory Activity

Ohio 2009 – 2011 ESPs

In April 2011, the Supreme Court of Ohio issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged resulting in three reversals, two of which may have a prospective impact through a remand proceeding.  Pursuant to a May 2011 PUCO order, CSPCo and OPCo implemented rates subject to refund.  Certain intervenors proposed adjustments that included a reduction of deferred FAC and other regulatory assets for the period prior to June 2011 of up to $634 million, excluding carrying costs, which management believes is without merit and violates the Supreme Court of Ohio decision.  The proposed adjustments also included refunds and rate reductions of related revenues beginning in June 2011 of up to $153 million.  See “Ohio Electric Security Plan Filings” section of Note 3.

Ohio January 2012 – May 2014 ESP

In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  The SSO presents redesigned generation rates by customer class.  Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013.  Under the new ESP, management estimates CSPCo and OPCo will have base generation revenue increases, excluding riders, of $17 million and $48 million, respectively, for 2012 and $46 million and $60 million, respectively, for 2013.  The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESPs could impact the outcome of the January 2012-May 2014 ESP, though the nature and extent of that impact is not presently known.  See “Ohio Electric Security Plan Filings” section of Note 3.

Ohio Distribution Base Rate Case

In February 2011, CSPCo and OPCo filed with the PUCO for annual increases in distribution rates of $34 million and $60 million, respectively.  The requested increase is based upon an 11.15% return on common equity to be effective January 2012.  In addition to the annual increases, CSPCo and OPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets of $216 million and $159 million, respectively, including carrying costs, to be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013.  See “2011 Ohio Distribution Base Rate Case” section of Note 3.

Virginia Regulatory Activity

In March 2011, APCo filed a generation and distribution base rate request with the Virginia SCC to increase annual base rates by $126 million based upon an 11.65% return on common equity to be effective no later than February 2012.  The return on common equity includes a requested 0.5% renewable portfolio standards incentive as allowed by law.APCo proposed to mitigate the requested base rate increase by $51 million by maintaining current depreciation rates until the next biennial filing.  If approved, APCo’s net base rate increase would be $75 million.  In July 2011, an Attorney General witness recommended an $80 million reduction in APCo’s requested rate year capacity charges.  See “2011 Virginia Biennial Base Rate Case” section of Note 3.

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West Virginia Regulatory Activity

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

Michigan Base Rate Case

In July 2011, I&M filed a request with the MPSC for an annual increase in Michigan base rates of $25 million and a return on equity of 11.15%.  The request includes an increase in depreciation rates that would result in a $6 million increase in depreciation expense.  I&M plans to request an interim rate increase, subject to refund, for the portion of the $25 million that excludes the depreciation rate changes and other regulatory amortizations effective in January 2012.  See “2011 Michigan Base Rate Case” section of Note 3.

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW coal generating unit in Arkansas, which is expected to be in service in 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  SWEPCo’s share of construction costs is currently estimated to be $1.3 billion, excluding AFUDC, plus an additional $124 million for transmission, excluding AFUDC.  The APSC, LPSC and PUCT approved SWEPCo’s original application to build the Turk Plant.  In June 2010, the APSC issued an order which reversed and set aside the previously granted Certificate of Environmental Compatibility and Public Need.  Various proceedings are pending that challenge the Turk Plant’s construction and its approved wetlands and air permits.  In 2010, the motions for preliminary injunction were partially granted.  According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop.  Mitigation measures required by the permit are authorized and may be completed.  The preliminary injunction affects portions of the water intake and portions of two transmission lines.  In July 2011, the U.S. Eighth Circuit Court of Appeals affirmed the preliminary injunction.  Management is unable to predict the timing or the outcome related to this remand proceeding.

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

Ohio Customer Choice

In our Ohio service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service.  As a result, in comparison to the second quarter of 2010 and the first six months of 2010, we lost approximately $24 million and $43 million, respectively, of generation related gross margin.  We anticipate recovery of a portion of lost margins through off-system sales, including PJM capacity revenues, and our CRES provider.  Our CRES provider targets retail customers in Ohio, both within and outside of our retail service territory.

Cook Plant

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator.  Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $408 million.  Management believes that I&M should recover a significant portion of repair and replacement costs through the turbine vendor’s warranty, insurance and the regulatory process.  I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power.  The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install

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new turbine rotors.  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 “Michigan 2009 and 2010 Power Supply Cost Recovery Reconciliations” section of Note 3 and “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

As a result of the nuclear plant situation in Japan following the March 2011 earthquake, we expect the Nuclear Regulatory Commission and possibly Congress to review safety procedures and requirements for nuclear generating facilities.  This review could increase procedures and testing requirements, require physical modifications to the plant and increase future operating costs at the Cook Plant.  We are unable to predict the impact of potential future regulation of nuclear facilities.

Texas Restructuring Appeals

Pursuant to PUCT restructuring orders, TCC securitized net recoverable stranded generation costs of $2.5 billion and is recovering the principal and interest on the securitization bonds through the end of 2020.  TCC also refunded other net true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider under PUCT restructuring orders.  TCC and intervenors appealed the PUCT’s true-up related orders.  After rulings from the Texas District Court and the Texas Court of Appeals, TCC, the PUCT and intervenors filed petitions for review with the Supreme Court of Texas.  In July 2011, the Supreme Court of Texas granted review and issued its opinion.  The PUCT’s order denying recovery of approximately $420 million in capacity auction true-up amounts was reversed.  We estimate that, in the remand to the PUCT, TCC will be entitled to recover approximately $420 million, plus interest from January 1, 2002.  See “Texas Restructuring Appeals” section of Note 3.

Mountaineer Carbon Capture and Storage

Product Validation Facility (PVF)

APCo and ALSTOM Power, Inc., an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009.  APCo also constructed and owns the necessary facilities to store the CO2.  In May 2011, the PVF ended operations and decommissioning of the facility began.

In APCo’s and WPCo’s May 2010 West Virginia base rate filing, APCo and WPCo requested rate base treatment of the PVF, including recovery of the related asset retirement obligation regulatory asset amortization and accretion.  In March 2011, a WVPSC order denied the request for rate base treatment of the PVF largely due to its experimental operation.  The base rate order provided that should APCo construct a commercial scale carbon capture and sequestration (CCS) facility, only the West Virginia portion of the PVF costs, based on load sharing among certain AEP operating companies, may be considered used and useful plant in service and included in future rate base.  As a result, APCo recorded a pretax write-off of $41 million ($26 million net of tax) in the first quarter of 2011.  As of June 30, 2011, APCo has recorded a noncurrent regulatory asset of $19 million related to the PVF.  If APCo cannot recover its remaining PVF investment and related accretion expenses, it would reduce future net income and cash flows.  See “Mountaineer Carbon Capture and Storage Project” section of Note 3.

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

During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale CCS facility at the Mountaineer Plant.  AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project.  The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million.  In July 2011, management informed the DOE that it will complete a Front-End Engineering and Design study during the third quarter of 2011, but it is postponing any further CCS project activities because of the uncertainty about the regulation of CO2.  As of June 30, 2011, the project has incurred $30 million in total costs and has received $10 million of DOE eligible funding resulting in a $20 million net balance recorded in the Condensed Consolidated Balance Sheets.  Requests for recovery are in process in Michigan, Ohio and Virginia.  If the costs of the CCS project cannot be recovered, it would reduce future net income and cash flows.  See “Mountaineer Carbon Capture and Storage Project” section of Note 3.

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LITIGATION

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

ENVIRONMENTAL ISSUES

We are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements.  We will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants from fossil fuel-fired power plants, new proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.

We are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of our nuclear units.  We are also engaged in the development of possible future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change.  See a complete discussion of these matters in the “Environmental Issues” section of “Management’s Financial Discussion and Analysis” in the 2010 Annual Report.  We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  We should be able to recover these expenditures through market prices in deregulated jurisdictions.  If not, the costs of environmental compliance could adversely affect future net income, cash flows and possibly financial condition.

Update to Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  We continue to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of June 30, 2011, the AEP System had a total generating capacity of nearly 38,000 MWs, of which 23,900 MWs are coal-fired.  In the second quarter of 2011, we refined the cost estimates of complying with these rules and other impacts of the environmental proposals on our coal-fired generating facilities.  Based upon the updated estimates, investment to meet these proposed requirements ranges from approximately $6 billion to $8 billion between 2012 and 2020.  These amounts include investments to convert 1,070 MWs of coal generation to 932 MWs of natural gas capacity and build approximately 1,200 MWs of natural gas-fired generation.

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

4

Subject to the factors listed above and based upon our current evaluation, we may retire the following plants or units of plants before 2015:

	Generating
Plant Name and Unit	Capacity
	(in MWs)
Big Sandy Plant		1,078
Clinch River Plant, Unit 3		235
Conesville Plant, Unit 3		165
Glen Lyn Plant		335
Kammer Plant		630
Kanawha River Plant		400
Muskingum River Plant, Units 1-4		840
Philip Sporn Plant		1,050
Picway Plant		100
Tanners Creek Plant, Units 1-3		495
Welsh Plant, Unit 2		528
Total		5,856

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

We are also considering the conversion of some of our coal units to natural gas, installing emission control equipment on other units and completing construction of the Turk and Dresden Plants.  Recovery of the remaining investments in facilities that may be closed will be subject to regulatory approval.

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

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

In July 2011, the Federal EPA released the final rule, renamed the Cross State Air Pollution Rule (CSAP Rule).  Like the proposed Transport Rule, the CSAP Rule relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states.  Interstate trading of allowances is allowed on a restricted sub-regional basis beginning in 2012.  Arkansas, Louisiana and Oklahoma are subject only to the seasonal NOx program in the final rule.  However, Texas is now subject to the annual programs for SO2 and NOx in addition to the seasonal NOx program.  The annual SO2 allowance budgets in Indiana, Ohio and West Virginia have been reduced significantly in the final rule.

The time frames and stringency of the required emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and our electric utility customers.  The compliance plan described above was based on the requirements of the proposed Transport Rule.  The more stringent requirements included in the final CSAP Rule could further accelerate unit retirements, increase capital requirements, constrain operations, decrease reliability and unfavorably impact financial condition if the increased costs are not recovered in rates or market prices.

5

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

The Federal EPA issued the Clean Air Mercury Rule (CAMR) in 2005, setting mercury emission standards for new coal-fired power plants and requiring all states to issue new state implementation plans including mercury requirements for existing coal-fired power plants.  The CAMR was vacated by the D.C. Circuit Court of Appeals in 2008.  In response, the Federal EPA has been developing a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The Federal EPA Administrator signed a proposed HAPs rule in March 2011, but the rule has not yet been published in the Federal Register.  The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrochloric acid (as a surrogate for acid gases) for units burning coal and oil, on a site-wide 30-day rolling average basis.  In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  Compliance is required within three years of the effective date of the final rule, which is expected by November 2011 per the Federal EPA’s settlement agreement with several environmental groups.  A one-year extension may be available if the extension is necessary for the installation of controls.  We are developing comments to submit to the Federal EPA and collecting additional information regarding the performance of our coal-fired units.  Comments will be accepted for 60 days after the rule is published in the Federal Register.

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.  We have older coal units for which it may be economically inefficient to install scrubbers or other environmental controls.  Several of these units are included in our current list of potential plant closures discussed above.

Regional Haze

In March 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze state implementation plan (SIP) submitted by the State of Oklahoma through the Department of Environmental Quality.  The Federal EPA is proposing to approve all of the NOx control measures in the SIP and disapprove the SO2 control measures for six electric generating units, including two units owned by PSO.  The Federal EPA is proposing a federal implementation plan (FIP) that would require these units to install technology capable of reducing SO2 emissions to 0.06 pounds per million British thermal units within three years of the effective date of the FIP.  The proposal is open for public comment.

Coal Combustion Residual Rule

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

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

6

Clean Water Act Regulations

In April 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement.  Compliance with this standard is required within eight years of the effective date of the final rule.  The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment.  The proposed entrainment standard for new units at existing facilities requires either intake flows commensurate with closed cycle cooling or achieving entrainment reductions equivalent to 90% or greater of the reductions that could be achieved with closed cycle cooling.  Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority.  We are evaluating the proposal and engaged in the collection of additional information regarding the feasibility of implementing this proposal at our facilities.  Comments on the proposal were due in July 2011.

Global Warming

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

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

Several states have adopted programs that directly regulate CO2 emissions from power plants, but none of these programs are currently in effect in states where we have generating facilities.  Certain states, including 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.

7

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

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

RESULTS OF OPERATIONS

SEGMENTS

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

Utility Operations

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

· Electricity transmission and distribution in the U.S.

AEP River Operations

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

Generation and Marketing

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

The table below presents our consolidated Net Income (Loss) by segment for the three and six months ended June 30, 2011 and 2010.

	Three Months Ended June 30,								Six Months Ended June 30,
	2011				2010				2011				2010
	(in millions)
Utility Operations		$	356			$	132			$	734			$	476
AEP River Operations			(1	)			(1	)			6				2
Generation and Marketing			11				7				12				17
All Other (a)			(13	)			(1	)			(44	)			(12	)
Net Income		$	353			$	137			$	708			$	483

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

AEP CONSOLIDATED

Second Quarter of 2011 Compared to Second Quarter of 2010

Net Income increased from $137 million in 2010 to $353 million in 2011 primarily due to $185 million of expenses (net of tax) recorded in the second quarter of 2010 related to the cost reduction initiatives.

Average basic shares outstanding increased from 479 million in 2010 to 482 million in 2011.

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Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Net Income increased from $483 million in 2010 to $708 million in 2011 primarily due to $185 million of expenses (net of tax) recorded in the second quarter of 2010 related to the cost reduction initiatives.

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

Our results of operations are discussed below by operating segment.

UTILITY OPERATIONS

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2011		2010		2011		2010
	(in millions)
Revenues	$	3,389	$	3,211	$	6,913	$	6,637
Fuel and Purchased Power		1,230		1,110		2,527		2,357
Gross Margin		2,159		2,101		4,386		4,280
Depreciation and Amortization		398		394		791		792
Other Operating Expenses		1,053		1,314		2,113		2,354
Operating Income		708		393		1,482		1,134
Other Income, Net		48		42		91		85
Interest Expense		227		237		459		472
Income Tax Expense		173		66		380		271
Net Income	$	356	$	132	$	734	$	476

Summary of KWH Energy Sales for Utility Operations
	Three Months Ended			Six Months Ended
	June 30,			June 30,
	2011	2010		2011	2010
	(in millions of KWH)
Retail:
Residential	13,503		12,659	30,452	30,433
Commercial	12,913		13,002	24,559	24,476
Industrial	15,153		14,662	29,482	28,044
Miscellaneous	777		783	1,500	1,495
Total Retail (a)	42,346		41,106	85,993	84,448
Wholesale	10,216		7,019	19,367	15,156
Total KWHs	52,562		48,125	105,360	99,604
(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
		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2011		2010		2011		2010
		(in degree days)
Eastern Region
Actual - Heating (a)			134		75		1,989		1,975
Normal - Heating (b)			168		170		1,907		1,911
Actual - Cooling (c)			368		434		371		434
Normal - Cooling (b)			295		289		299		293
Western Region
Actual - Heating (a)			10		5		702		764
Normal - Heating (b)			21		21		600		595
Actual - Cooling (d)			1,035		866		1,144		886
Normal - Cooling (b)			762		757		820		815
(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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Second Quarter of 2011 Compared to Second Quarter of 2010
Reconciliation of Second Quarter of 2010 to Second Quarter of 2011
Net Income from Utility Operations
(in millions)
Second Quarter of 2010	$	132
Changes in Gross Margin:
Retail Margins		-
Off-system Sales		37
Transmission Revenues		13
Other Revenues		8
Total Change in Gross Margin		58
Changes in Expenses and Other:
Other Operation and Maintenance		258
Depreciation and Amortization		(4	)
Taxes Other Than Income Taxes		3
Interest and Investment Income		(1	)
Carrying Costs Income		(2	)
Allowance for Equity Funds Used During Construction		4
Interest Expense		10
Equity Earnings of Unconsolidated Subsidiaries		5
Total Change in Expenses and Other		273
Income Tax Expense		(107	)
Second Quarter of 2011	$	356

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 were unchanged primarily due to the following:
	·	Successful rate proceedings in our service territories which include:
		·	A $27 million rate increase for APCo.
		·	An $18 million rate increase for KPCo.
		·	A $7 million rate increase for SWEPCo.
		·	A $6 million rate increase in Ohio.
		·	A $6 million rate increase for I&M.
	·	An $18 million increase in weather-related usage in our western region primarily due to a 20% increase in cooling degree days.
	These increases were partially offset by:
	·	A $24 million decrease attributable to Ohio customers switching to alternative competitive retail electric service (CRES) providers.
	·	A $21 million decrease due to the expiration of E&R cost recovery in Virginia.
	·	A $20 million increase in other variable electric generation expenses.
	·	A $13 million decrease in weather-related usage in our eastern region primarily due to a 15% decrease in cooling degree days.
·	Margins from Off-system Sales increased $37 million primarily due to an increase in PJM capacity revenues and higher physical sales volumes.
·	Transmission Revenues increased $13 million primarily due to net rate increases in PJM.
·	Other Revenues increased $8 million primarily due to higher amortization of deferred gains.

11

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

·	Other Operation and Maintenance expenses decreased $258 million primarily due to:
	·	A $278 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
	·	A $54 million decrease due to the second quarter 2010 write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the Virginia SCC.
	·	A $6 million decrease in administrative and general expenses primarily due to a decrease in fringe benefit expenses.
	These decreases were partially offset by:
	·	A $27 million increase in storm-related expenses.
	·	A $25 million increase due to the second quarter 2010 deferral of 2009 storm costs as allowed by the Virginia SCC.
	·	A $17 million increase in demand side management expenses, energy efficiency program expenses and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
	·	A $15 million increase in plant operating and maintenance expenses.
·	Depreciation and Amortization expenses increased $4 millionprimarily due to higher depreciable property balances partially offset by lower amortization due to the expiration of E&R amortization of deferred carrying costs in Virginia.
·	Taxes Other Than Income Taxes decreased $3 million primarily due to the employer portion of payroll taxes recorded in the second quarter of 2010 related to the cost reduction initiatives, partially offset by higher property taxes in 2011.
·	Allowance for Equity Funds Used During Construction increased $4 million primarily due to construction of the Dresden Plant and various environmental upgrades.
·	Interest Expense decreased $10 million primarily due to a decrease in long-term debt.
·	Equity Earnings of Unconsolidated Subsidiaries increased $5 million primarily due to an increase in transmission investments for ETT.
·	Income Tax Expense increased $107 million primarily due to an increase in pretax book income.

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Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010
Reconciliation of Six Months Ended June 30, 2010 to Six Months Ended June 30, 2011
Net Income from Utility Operations
(in millions)
Six Months Ended June 30, 2010	$	476
Changes in Gross Margin:
Retail Margins		26
Off-system Sales		49
Transmission Revenues		21
Other Revenues		10
Total Change in Gross Margin		106
Changes in Expenses and Other:
Other Operation and Maintenance		244
Depreciation and Amortization		1
Taxes Other Than Income Taxes		(3)
Interest and Investment Income		(1)
Carrying Costs Income		(1)
Interest Expense		13
Equity Earnings of Unconsolidated Subsidiaries		8
Total Change in Expenses and Other		261
Income Tax Expense		(109)
Six Months Ended June 30, 2011	$	734

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 $26 million primarily due to the following:
	·	Successful rate proceedings in our service territories which include:
		·	A $41 million rate increase in Ohio.
		·	A $36 million rate increase for KPCo.
		·	A $27 million rate increase for APCo.
		·	A $20 million rate increase for SWEPCo.
		·	A $15 million rate increase for I&M.
		·	A $9 million net rate increase in our other jurisdictions.
	·	A $12 million increase in weather-related usage in our western region primarily due to a 29% increase in cooling degree days.
	These increases were partially offset by:
	·	A $43 million decrease attributable to Ohio customers switching to alternative CRES providers.
	·	A $37 million decrease in rate related margins for APCo due to the expiration of E&R cost recovery in Virginia.
	·	A $27 million decrease in weather-related usage in our eastern region primarily due to a 15% decrease in cooling degree days.
	·	An $8 million increase in other variable electric generation expenses.
·	Margins from Off-system Sales increased $49 million primarily due to an increase in PJM capacity revenues and higher physical sales volumes.
·	Transmission Revenues increased $21 million primarily due to net rate increases in PJM.
·	Other Revenues increased $10 million primarily due to higher amortization of deferred gains.

13

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

·	Other Operation and Maintenance expenses decreased $244 million primarily due to the following:
	·	A $278 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
	·	A $54 million decrease due to the second quarter 2010 write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the Virginia SCC.
	·	A $33 million decrease due to the first quarter 2011 deferral of 2010 costs related to storms and our cost reduction initiatives as allowed by the WVPSC.
	·	A $24 million decrease in administrative and general expenses primarily due to a decrease in fringe benefit expenses.
	·	An $11 million gain on the sale of land.
	These decreases were partially offset by:
	·	A $44 million increase in demand side management, energy efficiency programs and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers within Gross Margin.
	·	A $41 million increase due to the first quarter 2011 write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC.
	·	A $29 million increase in storm-related expenses.
	·	A $26 million increase in plant outage and other plant operating and maintenance expenses.
	·	A $25 million increase due to the second quarter 2010 deferral of 2009 storm costs as allowed by the Virginia SCC.
·	Depreciation and Amortization expenses decreased $1 million due to the expiration of E&R amortization of deferred carrying costs in Virginia partially offset by higher depreciable property balances.
·	Taxes Other Than Income Taxes increased $3 million primarily due to higher property taxes in 2011 partially offset by the employer portion of payroll taxes recorded in the second quarter of 2010 related to the cost reduction initiatives.
·	Interest Expense decreased $13 million primarily due to a decrease in long-term debt.
·	Equity Earnings of Unconsolidated Subsidiaries increased $8 million primarily due to an increase in transmission investments for ETT.
·	Income Tax Expense increased $109 million primarily due to an increase in pretax book income, partially offset by the 2010 tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.

AEP RIVER OPERATIONS

Second Quarter of 2011 Compared to Second Quarter of 2010

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

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Net Income from our AEP River Operations segment increased from $2 million in 2010 to $6 million in 2011 primarily due to higher grain and coal exports, increased barge fleet size and the cost reduction initiatives recorded in the second quarter of 2010 partially offset by higher fuel, maintenance and flood-related costs.

GENERATION AND MARKETING

Second Quarter of 2011 Compared to Second Quarter of 2010

Net Income from our Generation and Marketing segment increased from $7 million in 2010 to $11 million in 2011 primarily due to increased inception gains from ERCOT marketing activities and increased income from our wind farm operations partially offset by lower gross margins at the Oklaunion Plant.

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Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Net Income from our Generation and Marketing segment decreased from $17 million in 2010 to $12 million in 2011 primarily due to lower gross margins at the Oklaunion Plant partially offset by increased income from our wind farm operations.

ALL OTHER

Second Quarter of 2011 Compared to Second Quarter of 2010

Net Income from All Other decreased from a loss of $1 million in 2010 to a loss of $13 million in 2011 primarily due to $16 million in pretax gains ($10 million, net of tax) on the sale of our remaining 138,000 shares of Intercontinental Exchange, Inc. (ICE) in the second quarter of 2010.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Net Income from All Other decreased from a loss of $12 million in 2010 to a loss of $44 million in 2011 due to a $22 million net of tax loss incurred in the first quarter 2011 settlement of litigation with BOA and Enron and a $16 million pretax gain ($10 million, net of tax) on the sale of our remaining 138,000 shares of ICE in the second quarter of 2010.

AEP SYSTEM INCOME TAXES

Second Quarter of 2011 Compared to Second Quarter of 2010

Income Tax Expense increased $109 million in comparison to 2010 primarily due to an increase in pretax book income.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Income Tax Expense increased $180 million in comparison to 2010 primarily due to an increase in pretax book income and the unrealized capital loss valuation allowance related to a deferred tax asset associated with the settlement of litigation with BOA and Enron, offset in part by the 2010 tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.

FINANCIAL CONDITION

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

LIQUIDITY AND CAPITAL RESOURCES

Debt and Equity Capitalization

	June 30, 2011				December 31, 2010
	(dollars in millions)
Long-term Debt, including amounts due within one year	$	16,635	51.5	%	$	16,811	52.8	%
Short-term Debt		1,639	5.1			1,346	4.2
Total Debt		18,274	56.6			18,157	57.0
Preferred Stock of Subsidiaries		60	0.2			60	0.2
AEP Common Equity		13,939	43.2			13,622	42.8
Total Debt and Equity Capitalization	$	32,273	100.0	%	$	31,839	100.0	%

Our ratio of debt-to-total capital decreased from 57% at December 31, 2010 to 56.6% at June 30, 2011.

15

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability.  We believe we have adequate liquidity under our existing credit facilities.  At June 30, 2011, we had $3 billion in aggregate credit facility commitments to support our operations.  Additional liquidity is available from cash from operations and a receivables securitization agreement.  We are committed to maintaining adequate liquidity.  We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of long-term debt, sale-leaseback or leasing agreements or common stock.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  At June 30, 2011, our available liquidity was approximately $2.3 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
Total			2,954
Cash and Cash Equivalents			417
Total Liquidity Sources			3,371
Less:	AEP Commercial Paper Outstanding		944
	Letters of Credit Issued		132
Net Available Liquidity		$	2,295

We have credit facilities totaling $3 billion to support our commercial paper program.  The credit facilities allow us to issue letters of credit in an amount up to $1.35 billion.  In July 2011, we replaced the $1.5 billion facility due in 2012 with a new $1.75 billion facility maturing in July 2016 and extended the $1.5 billion facility due in 2013 to expire in June 2015.

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

We use our commercial paper program to meet the short-term borrowing needs of our subsidiaries.  The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries.  In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  The maximum amount of commercial paper outstanding during the first six months of 2011 was $1.2 billion.  The weighted-average interest rate for our commercial paper during 2011 was 0.38%.

Securitized Accounts Receivables

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

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Debt Covenants and Borrowing Limitations

Our revolving credit agreements contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%.  The method for calculating our outstanding debt and capitalization is contractually defined in our revolving credit agreements.  Debt as defined in the revolving credit agreements excludes junior subordinated debentures, securitization bonds and debt of AEP Credit.  At June 30, 2011,this contractually-defined percentage was 52.3%.  Nonperformance under these covenants could result in an event of default under these credit agreements.  At June 30, 2011, we complied with all of the covenants contained in these credit agreements.  In addition, the acceleration of our payment obligations, or the obligations of certain of our major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements and in a majority of our non-exchange traded commodity contracts which would permit the lenders and counterparties to declare the outstanding amounts payable.  However, a default under our non-exchange traded commodity contracts does not cause an event of default under our revolving credit agreements.

The revolving credit facilities do not permit the lenders to refuse a draw on either facility if a material adverse change occurs.

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

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

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

Credit Ratings

We do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but our access to the commercial paper market may depend on our credit ratings.  In addition, downgrades in our credit ratings by one of the rating agencies could increase our borrowing costs.  Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject us to additional collateral demands under adequate assurance clauses under our derivative and non-derivative energy contracts.

17

CASH FLOW

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

	Six Months Ended
	June 30,
	2011				2010
	(in millions)
Cash and Cash Equivalents at Beginning of Period		$	294			$	490
Net Cash Flows from Operating Activities			1,732				582
Net Cash Flows Used for Investing Activities			(1,280	)			(992	)
Net Cash Flows from (Used for) Financing Activities			(329	)			758
Net Increase in Cash and Cash Equivalents			123				348
Cash and Cash Equivalents at End of Period		$	417			$	838

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

Operating Activities
	Six Months Ended
	June 30,
	2011			2010
	(in millions)
Net Income		$	708		$	483
Depreciation and Amortization			813			813
Other			211			(714	)
Net Cash Flows from Operating Activities		$	1,732		$	582

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

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Net Cash Flows from Operating Activities were $582 million in 2010 consisting primarily of Net Income of $483 million and $813 million of noncash Depreciation and Amortization.  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.  Other changes represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Significant changes in other items include an increase in under-recovered fuel primarily due to the deferral of fuel under the FAC in Ohio and higher fuel costs in Oklahoma, accrued tax benefits and the favorable impact of a decrease in fuel inventory.  Deferred Income Taxes increased primarily due to the American Recovery and Reinvestment Act of 2009 extending bonus depreciation provisions, a change in tax accounting method and an increase in tax versus book temporary differences from operations.

Investing Activities
	Six Months Ended
	June 30,
	2011				2010
	(in millions)
Construction Expenditures		$	(1,113	)		$	(1,104	)
Acquisitions of Nuclear Fuel			(93	)			(41	)
Acquisition of Cushion Gas from BOA			(214	)			-
Proceeds from Sales of Assets			94				147
Other			46				6
Net Cash Flows Used for Investing Activities		$	(1,280	)		$	(992	)

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

Net Cash Flows Used for Investing Activities were $992 million in 2010 primarily due to Construction Expenditures for our new generation, environmental and distribution investments.  Proceeds from Sales of Assets in 2010 include $135 million for sales of transmission assets in Texas to ETT.

Financing Activities
	Six Months Ended
	June 30,
	2011				2010
	(in millions)
Issuance of Common Stock, Net		$	49			$	42
Issuance/Retirement of Debt, Net			104				1,166
Dividends Paid on Common Stock			(446	)			(399	)
Other			(36	)			(51	)
Net Cash Flows from (Used for) Financing Activities		$	(329	)		$	758

Net Cash Flows Used for Financing Activities in 2011 were $329 million.  Our net debt issuances were $104 million. The net issuances included issuances of $600 million of senior unsecured notes, $481 million of pollution control bonds and an increase in short-term borrowing of $293 million offset by retirements of $578 million of senior unsecured and debt notes, $591 million of pollution control bonds and $92 million of securitization bonds.  We paid common stock dividends of $446 million.  See Note 11 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

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Net Cash Flows from Financing Activities were $758 million in 2010.  Our net debt issuances were $1.2 billion.  The net issuances included issuances of $884 million of notes, $287 million of pollution control bonds and a $668 million increase in commercial paper outstanding partially offset by retirements of $1 billion of senior unsecured notes, $86 million of securitization bonds and $183 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 $399 million.

In July 2011, AEGCo remarketed $45 million of variable rate Pollution Control Bonds which may be tendered for purchase at the option of the holder.  The Pollution Control Bonds are supported by letters of credit which expire in 2014.

In July 2011, I&M retired $2 million of Notes Payable related to DCC Fuel.

In July 2011, SWEPCo retired $41 million of 4.5% Pollution Control Bonds due in 2011.

OFF-BALANCE SHEET ARRANGEMENTS

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

	June 30,		December 31,
	2011		2010
	(in millions)
Rockport Plant Unit 2 Future Minimum Lease Payments	$	1,700	$	1,774
Railcars Maximum Potential Loss From Lease Agreement		25		25

For complete information on each of these off-balance sheet arrangements see the “Off-balance Sheet Arrangements” section of “Management’s Financial Discussion and Analysis” in the 2010 Annual Report.

CONTRACTUAL OBLIGATION INFORMATION

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

MINE SAFETY INFORMATION

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

20

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

		DHLC		CCPC		Conner Run
Number of Citations for Violations of Mandatory Health or
	Safety Standards under 104 *		-		-		-
Number of Orders Issued under 104(b) *			-		-		-
Number of Citations and Orders for Unwarrantable Failure
	to Comply with Mandatory Health or Safety Standards under 104(d) *		-		-		-
Number of Flagrant Violations under 110(b)(2) *			-		-		-
Number of Imminent Danger Orders Issued under 107(a) *			-		-		-
Total Dollar Value of Proposed Assessments		$	1,123	$	400	$	-
Number of Mining-related Fatalities			-		-		-
* References to sections under the Mine Act

DHLC currently has three legal actions pending before the Federal Mine Safety and Health Review Commission. Two are related to actions challenging four violations issued by Mine Safety and Health Administration following an employee fatality in March 2009 and the third legal action is challenging a citation issued in August 2010 related to a dragline boom issue.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Financial Discussion and Analysis” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.

NEW ACCOUNTING PRONOUNCEMENTS

Pronouncements Effective in the Future

The FASB issued ASU 2011-05 “Presentation of Comprehensive Income” eliminating the option to present the components of other comprehensive income as a part of the statement of shareholders’ equity.  The standard requires other comprehensive income be presented as part of a single continuous statement of comprehensive income or in a statement of other comprehensive income immediately following the statement of net income.  This standard will change the presentation of our financial statements but will not affect the calculation of net income, comprehensive income or earnings per share.  We will retrospectively adopt ASU 2011-05 effective January 1, 2012.

Future Accounting Changes

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

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

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

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

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

We employ risk management contracts including physical forward purchase and sale contracts and financial forward purchase and sale contracts.  We engage in risk management of power, coal and natural gas and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with our energy business.  As a result, we are subject to price risk.  The amount of risk taken is determined by the commercial operations group in accordance with the market risk policy approved by the Finance Committee of our Board of Directors.  Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures.  The CORC consists of our President, Chief Financial Officer, Senior Vice President of Commercial Operations and Chief Risk Officer.  When commercial activities exceed predetermined limits, we modify the positions to reduce the risk to be within the limits unless specifically approved by the CORC.

22

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

MTM Risk Management Contract Net Assets (Liabilities)
Six Months Ended June 30, 2011
				Generation
	Utility			and
	Operations			Marketing			All Other			Total
	(in millions)
Total MTM Risk Management Contract Net Assets
at December 31, 2010	$	91		$	140		$	2		$	233
(Gain) Loss from Contracts Realized/Settled During the Period and
Entered in a Prior Period		(11	)		(14	)		(1	)		(26	)
Fair Value of New Contracts at Inception When Entered During the
Period (a)		3			7			-			10
Net Option Premiums Received for Unexercised or Unexpired
Option Contracts Entered During the Period		-			-			-			-
Changes in Fair Value Due to Market Fluctuations During the
Period (b)		4			10			-			14
Changes in Fair Value Allocated to Regulated Jurisdictions (c)		3			-			-			3
Total MTM Risk Management Contract Net Assets
at June 30, 2011	$	90		$	143		$	1			234
Commodity Cash Flow HedgeContracts											19
Interest Rate and Foreign Currency Cash Flow HedgeContracts											(2	)
Fair Value HedgeContracts											8
Collateral Deposits											39
Total MTM Derivative Contract Net Assets at June 30, 2011										$	298

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

23

Credit Risk

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

We have risk management contracts with numerous counterparties.  Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily.  As of June 30, 2011, our credit exposure net of collateral to sub investment grade counterparties was approximately 7.35%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).  As of June 30, 2011, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

		Exposure						Number of		Net Exposure
		Before						Counterparties		of
		Credit		Credit		Net		>10% of		Counterparties
Counterparty Credit Quality		Collateral		Collateral		Exposure		Net Exposure		>10%
		(in millions, except number of counterparties)
Investment Grade		$	591	$	5	$	586		1	$	173
Split Rating			1		-		1		1		1
Noninvestment Grade			7		4		3		2		3
No External Ratings:
	Internal Investment Grade		207		1		206		2		90
	Internal Noninvestment Grade		72		12		60		1		31
Total as of June 30, 2011		$	878	$	22	$	856		7	$	298
Total as of December 31, 2010		$	946	$	33	$	913		7	$	347

Value at Risk (VaR) Associated with Risk Management Contracts

We use a risk measurement model, which calculates VaR, to measure our commodity price risk in the risk management portfolio.  The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, as of June 30, 2011, a near term typical change in commodity prices is not expected to have a material effect on our net income, cash flows or financial condition.

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

VaR Model

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

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

As our VaR calculation captures recent price movements, we also perform regular stress testing of the portfolio to understand our exposure to extreme price movements.  We employ a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last four years in order to ascertain which historical price movements translated into the largest potential MTM loss.  We then research the underlying positions, price movements and market events that created the most significant exposure and report the findings to the Risk Executive Committee or the CORC as appropriate.

Interest Rate Risk

We utilize an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which our interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on debt outstanding as of June 30, 2011 and December 31, 2010, the estimated EaR on our debt portfolio for the following twelve months was $27 million and $5 million, respectively.

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2011 and 2010
(in millions, except per-share and share amounts)
(Unaudited)
	Three Months Ended						Six Months Ended
	2011			2010			2011			2010
REVENUES
Utility Operations	$	3,360		$	3,186		$	6,857		$	6,592
Other Revenues		249			174			482			337
TOTAL REVENUES		3,609			3,360			7,339			6,929
EXPENSES
Fuel and Other Consumables Used for Electric Generation		980			895			2,036			1,909
Purchased Electricity for Resale		287			227			562			465
Other Operation		697			994			1,383			1,667
Maintenance		316			243			581			514
Depreciation and Amortization		410			405			813			813
Taxes Other Than Income Taxes		202			202			415			409
TOTAL EXPENSES		2,892			2,966			5,790			5,777
OPERATING INCOME		717			394			1,549			1,152
Other Income (Expense):
Interest and Investment Income		3			18			5			21
Carrying Costs Income		17			19			32			33
Allowance for Equity Funds Used During Construction		23			19			43			43
Interest Expense		(239	)		(249	)		(481	)		(499	)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS		521			201			1,148			750
Income Tax Expense		174			65			452			272
Equity Earnings of Unconsolidated Subsidiaries		6			1			12			5
NET INCOME		353			137			708			483
Less:  Net Income Attributable to Noncontrolling Interests		1			1			2			2
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS		352			136			706			481
Less: Preferred Stock Dividend Requirements of Subsidiaries		-			-			1			1
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	352		$	136		$	705		$	480
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING		481,928,494			479,050,774			481,538,549			478,741,871
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	0.73		$	0.28		$	1.46		$	1.00
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING		482,203,255			479,176,543			481,786,698			479,012,304
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$	0.73		$	0.28		$	1.46		$	1.00
CASH DIVIDENDS DECLARED PER SHARE	$	0.46		$	0.42		$	0.92		$	0.83
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 Six Months Ended June 30, 2011 and 2010
(in millions)
(Unaudited)
				AEP Common Shareholders
				Common Stock								Accumulated
												Other
								Paid-in		Retained		Comprehensive		Noncontrolling
				Shares		Amount		Capital		Earnings		Income (Loss)		Interests		Total
TOTAL EQUITY – DECEMBER 31, 2009					498	$	3,239	$	5,824	$	4,451	$	(374)	$	-	$	13,140
Issuance of Common Stock					2		9		34								43
Common Stock Dividends											(398)				(1)		(399)
Preferred Stock Dividend Requirements of
	Subsidiaries										(1)						(1)
Other Changes in Equity									2								2
SUBTOTAL – EQUITY																	12,785
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 $6											(11)				(11)
		Amortization of Pension and OPEB Deferred
			Costs, Net of Tax of $6										11				11
NET INCOME											481				2		483
TOTAL COMPREHENSIVE INCOME																	485
TOTAL EQUITY – JUNE 30, 2010					500	$	3,248	$	5,860	$	4,533	$	(372)	$	1	$	13,270
TOTAL EQUITY – DECEMBER 31, 2010					501	$	3,257	$	5,904	$	4,842	$	(381)	$	-	$	13,622
Issuance of Common Stock					1		9		40								49
Common Stock Dividends											(444)				(2)		(446)
Preferred Stock Dividend Requirements of
	Subsidiaries										(1)						(1)
Other Changes in Equity									(12)								(12)
SUBTOTAL – EQUITY																	13,212
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of
	Taxes:
		Cash Flow Hedges, Net of Tax of $3											6				6
		Securities Available for Sale, Net of Tax of $-											1				1
		Amortization of Pension and OPEB Deferred
			Costs, Net of Tax of $6										12				12
NET INCOME											706				2		708
TOTAL COMPREHENSIVE INCOME																	727
TOTAL EQUITY – JUNE 30, 2011					502	$	3,266	$	5,932	$	5,103	$	(362)	$	-	$	13,939
See Condensed Notes to Condensed Consolidated Financial Statements.

27

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2011 and December 31, 2010
(in millions)
(Unaudited)
			2011		2010
CURRENT ASSETS
Cash and Cash Equivalents			$	417	$	294
Other Temporary Investments
	(June 30, 2011 and December 31, 2010 amounts include $250 and $287, respectively, related to Transition Funding and EIS)			311		416
Accounts Receivable:
	Customers			711		683
	Accrued Unbilled Revenues			74		195
	Pledged Accounts Receivable - AEP Credit			1,023		949
	Miscellaneous			95		137
	Allowance for Uncollectible Accounts			(37)		(41)
		Total Accounts Receivable		1,866		1,923
Fuel				680		837
Materials and Supplies				625		611
Risk Management Assets				173		232
Accrued Tax Benefits				331		389
Regulatory Asset for Under-Recovered Fuel Costs				93		81
Margin Deposits				86		88
Prepayments and Other Current Assets				172		145
TOTAL CURRENT ASSETS				4,754		5,016
PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			24,841		24,352
	Transmission			8,779		8,576
	Distribution			14,465		14,208
Other Property, Plant and Equipment (including nuclear fuel and coal mining)				3,870		3,846
Construction Work in Progress				2,714		2,758
Total Property, Plant and Equipment				54,669		53,740
Accumulated Depreciation and Amortization				18,605		18,066
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET				36,064		35,674
OTHER NONCURRENT ASSETS
Regulatory Assets				5,004		4,943
Securitized Transition Assets				1,673		1,742
Spent Nuclear Fuel and Decommissioning Trusts				1,574		1,515
Goodwill				76		76
Long-term Risk Management Assets				343		410
Deferred Charges and Other Noncurrent Assets				1,264		1,079
TOTAL OTHER NONCURRENT ASSETS				9,934		9,765
TOTAL ASSETS			$	50,752	$	50,455
See Condensed Notes to Condensed Consolidated Financial Statements.

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2011 and December 31, 2010
(dollars in millions)
(Unaudited)
					2011		2010
CURRENT LIABILITIES
Accounts Payable					$	969	$	1,061
Short-term Debt:
	Securitized Debt for Receivables - AEP Credit					695		690
	Other Short-term Debt					944		656
		Total Short-term Debt				1,639		1,346
Long-term Debt Due Within One Year						1,071		1,309
Risk Management Liabilities						94		129
Customer Deposits						284		273
Accrued Taxes						597		702
Accrued Interest						282		281
Regulatory Liability for Over-Recovered Fuel Costs						9		17
Deferred Gain and Accrued Litigation Costs						-		448
Other Current Liabilities						942		952
TOTAL CURRENT LIABILITIES						5,887		6,518
NONCURRENT LIABILITIES
Long-term Debt
	(June 30, 2011 and December 31, 2010 amounts include $1,703 and $1,857, respectively, related to Transition Funding, DCC Fuel and Sabine)					15,564		15,502
Long-term Risk Management Liabilities						124		141
Deferred Income Taxes						7,716		7,359
Regulatory Liabilities and Deferred Investment Tax Credits						3,246		3,171
Asset Retirement Obligations						1,429		1,394
Employee Benefits and Pension Obligations						1,790		1,893
Deferred Credits and Other Noncurrent Liabilities						997		795
TOTAL NONCURRENT LIABILITIES						30,866		30,255
TOTAL LIABILITIES						36,753		36,773
Cumulative Preferred Stock Not Subject to Mandatory Redemption						60		60
Rate Matters (Note 3)
Commitments and Contingencies (Note 4)
EQUITY
Common Stock – Par Value – $6.50 Per Share:
			2011	2010
	Shares Authorized		600,000,000	600,000,000
	Shares Issued		502,534,747	501,114,881
(20,307,725 shares were held in treasury at June 30, 2011 and December 31, 2010)						3,266		3,257
Paid-in Capital						5,932		5,904
Retained Earnings						5,103		4,842
Accumulated Other Comprehensive Income (Loss)						(362)		(381)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY						13,939		13,622
TOTAL EQUITY						13,939		13,622
TOTAL LIABILITIES AND EQUITY					$	50,752	$	50,455
See Condensed Notes to Condensed Consolidated Financial Statements.

29

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2011 and 2010
(in millions)
(Unaudited)
			2011		2010
OPERATING ACTIVITIES
Net Income			$	708	$	483
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			813		813
	Deferred Income Taxes			525		212
	Gain on Settlement with BOA and Enron			(51)		-
	Settlement of Litigation with BOA and Enron			(211)		-
	Carrying Costs Income			(32)		(33)
	Allowance for Equity Funds Used During Construction			(43)		(43)
	Mark-to-Market of Risk Management Contracts			61		4
	Amortization of Nuclear Fuel			72		69
	Property Taxes			62		54
	Fuel Over/Under-Recovery, Net			(93)		(181)
	Change in Other Noncurrent Assets			(11)		(21)
	Change in Other Noncurrent Liabilities			83		65
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		53		(802)
		Fuel, Materials and Supplies		146		71
		Accounts Payable		(87)		(168)
		Accrued Taxes, Net		(198)		(164)
		Other Current Assets		(9)		66
		Other Current Liabilities		(56)		157
Net Cash Flows from Operating Activities				1,732		582
INVESTING ACTIVITIES
Construction Expenditures				(1,113)		(1,104)
Change in Other Temporary Investments, Net				11		31
Purchases of Investment Securities				(645)		(838)
Sales of Investment Securities				712		849
Acquisitions of Nuclear Fuel				(93)		(41)
Acquisitions of Assets				(10)		(12)
Acquisition of Cushion Gas from BOA				(214)		-
Proceeds from Sales of Assets				94		147
Other Investing Activities				(22)		(24)
Net Cash Flows Used for Investing Activities				(1,280)		(992)
FINANCING ACTIVITIES
Issuance of Common Stock, Net				49		42
Issuance of Long-term Debt				1,074		1,161
Commercial Paper and Credit Facility Borrowings				357		50
Change in Short-term Debt, Net				566		1,345
Retirement of Long-term Debt				(1,263)		(1,341)
Commercial Paper and Credit Facility Repayments				(630)		(49)
Principal Payments for Capital Lease Obligations				(35)		(49)
Dividends Paid on Common Stock				(446)		(399)
Dividends Paid on Cumulative Preferred Stock				(1)		(1)
Other Financing Activities				-		(1)
Net Cash Flows from (Used for) Financing Activities				(329)		758
Net Increase in Cash and Cash Equivalents				123		348
Cash and Cash Equivalents at Beginning of Period				294		490
Cash and Cash Equivalents at End of Period			$	417	$	838
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	442	$	487
Net Cash Paid for Income Taxes				15		174
Noncash Acquisitions Under Capital Leases				28		176
Government Grants Included in Accounts Receivable at June 30,				6		-
Construction Expenditures Included in Current Liabilities at June 30,				292		205
See Condensed Notes to Condensed Consolidated Financial Statements.

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX OF CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Variable Interest Entities

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

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

Sabine is a mining operator providing mining services to SWEPCo.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee.  In addition, SWEPCo determines how much coal will be mined each year.  Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine.  SWEPCo’s total billings from Sabine for the three months ended June 30, 2011 and 2010 were $30 million and $30 million, respectively, and for the six months ended June 30, 2011 and 2010 were $64 million and $73 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on our Condensed Consolidated Balance Sheets.

Our subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance.  EIS has multiple protected cells.  Neither AEP nor its subsidiaries have an equity investment in EIS.  The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance.  Our subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims.  Based on our control and the structure of the protected cell and EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate its assets and liabilities.  Our insurance premium expense to the protected cell for the three months ended June 30, 2011 and 2010 was $80 thousand and $254 thousand,

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respectively, and for the six months ended June 30, 2011 and 2010 was $30 million and $18 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.

I&M has a nuclear fuel lease agreement with DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC (collectively DCC Fuel).  DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions.  Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC are separate legal entities from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on the DCC Fuel LLC and DCC Fuel II LLC leases are made semi-annually and began in April 2010 and October 2010, respectively.  Payments on the DCC Fuel III LLC lease are made monthly and began in January 2011.  Payments on the DCC Fuel leases for the three months ended June 30, 2011 and 2010 were $38 million and $22 million, respectively, and for the six months ended June 30, 2011 and 2010 were $43 million and $22 million, respectively.  The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the 48, 54 and 54 month lease term, respectively.  Based on our control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The capital leases are eliminated upon consolidation.  See the tables below for the classification of DCC Fuel’s assets and liabilities on our Condensed 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 a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings.  Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing.  Based on our control of AEP Credit, management has concluded that we are the primary beneficiary and are required to consolidate its assets and liabilities.  See the tables below for the classification of AEP Credit’s assets and liabilities on our Condensed Consolidated Balance Sheets.  See “Securitized Accounts Receivable – AEP Credit” section of Note 11.

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

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

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
June 30, 2011
(in millions)
	SWEPCo			I&M			Protected Cell						Transition
	Sabine			DCC Fuel			of EIS			AEP Credit			Funding
ASSETS
Current Assets		$	42		$	85		$	125		$	1,010		$	197
Net Property, Plant and Equipment			140			127			-			-			-
Other Noncurrent Assets			34			80			7			-			1,678
Total Assets		$	216		$	292		$	132		$	1,010		$	1,875
LIABILITIES AND EQUITY
Current Liabilities		$	46		$	76		$	39		$	925		$	224
Noncurrent Liabilities			170			216			78			1			1,637
Equity			-			-			15			84			14
Total Liabilities and Equity		$	216		$	292		$	132		$	1,010		$	1,875

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2010
(in millions)
	SWEPCo			I&M			Protected Cell						Transition
	Sabine			DCC Fuel			of EIS			AEP Credit			Funding
ASSETS
Current Assets		$	50		$	92		$	131		$	924		$	214
Net Property, Plant and Equipment			139			173			-			-			-
Other Noncurrent Assets			34			112			1			10			1,746
Total Assets		$	223		$	377		$	132		$	934		$	1,960
LIABILITIES AND EQUITY
Current Liabilities		$	33		$	79		$	33		$	886		$	221
Noncurrent Liabilities			190			298			85			1			1,725
Equity			-			-			14			47			14
Total Liabilities and Equity		$	223		$	377		$	132		$	934		$	1,960

DHLC is a mining operator that sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  SWEPCo and CLECO share the executive board seats and its voting rights equally.  Each entity guarantees 50% of DHLC’s debt.  SWEPCo and CLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee.  SWEPCo’s total billings from DHLC for the three months ended June 30, 2011 and 2010 were $15 million and $13 million, respectively, and for the six months ended June 30, 2011 and 2010 were $29 million and $26 million, respectively.  We are not required to consolidate DHLC as we are not the primary beneficiary, although we hold a significant variable interest in DHLC.  Our equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on our Condensed Consolidated Balance Sheets.

34

Our investment in DHLC was:

	June 30, 2011						December 31, 2010
	As Reported on						As Reported on
	the Consolidated			Maximum			the Consolidated			Maximum
	Balance Sheet			Exposure			Balance Sheet			Exposure
	(in millions)
Capital Contribution from SWEPCo		$	8		$	8		$	6		$	6
Retained Earnings			1			1			2			2
SWEPCo's Guarantee of Debt			-			54			-			48
Total Investment in DHLC		$	9		$	63		$	8		$	56

We and Allegheny Energy Inc. (AYE) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH).  In February 2011, FirstEnergy Corp. (FirstEnergy) completed its merger with AYE, under which AYE became a wholly-owned subsidiary of FirstEnergy.  Also, in February 2011, PJM directed that work on the PATH project be suspended.  PATH is a series limited liability company and was created to construct a high-voltage transmission line project in the PJM region.  PATH consists of the “West Virginia Series (PATH-WV),” 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 “Allegheny Series” is not considered a VIE.  We are not required to consolidate PATH-WV as we are not the primary beneficiary, although we hold a significant variable interest in PATH-WV.  Our equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on our Condensed 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.  As of June 30, 2011, PATH-WV had no debt outstanding.  However, when debt is issued, the debt to equity ratio in each series should be consistent with other regulated utilities.  The entities recover costs through regulated rates.

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

Our investment in PATH-WV was:

	June 30, 2011						December 31, 2010
	As Reported on						As Reported on
	the Consolidated			Maximum			the Consolidated			Maximum
	Balance Sheet			Exposure			Balance Sheet			Exposure
				(in millions)
Capital Contribution from AEP		$	19		$	19		$	18		$	18
Retained Earnings			8			8			6			6
Total Investment in PATH-WV		$	27		$	27		$	24		$	24

Earnings Per Share (EPS)

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

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

	Three Months Ended June 30,
	2011					2010
	(in millions, except per share data)
			$/share					$/share
Earnings Applicable to AEP Common Shareholders	$	352				$	136
Weighted Average Number of Basic Shares Outstanding		481.9		$	0.73		479.1		$	0.28
Weighted Average Dilutive Effect of:
Stock Options		0.1			-		-			-
Restricted Stock Units		0.2			-		0.1			-
Weighted Average Number of Diluted Shares Outstanding		482.2		$	0.73		479.2		$	0.28

	Six Months Ended June 30,
	2011				2010
	(in millions, except per share data)
			$/share				$/share
Earnings Applicable to AEP Common Shareholders	$	705			$	480
Weighted Average Number of Basic Shares Outstanding		481.5	$	1.46		478.7	$	1.00
Weighted Average Dilutive Effect of:
Performance Share Units		-		-		0.1		-
Stock Options		0.1		-		0.1		-
Restricted Stock Units		0.2		-		0.1		-
Weighted Average Number of Diluted Shares Outstanding		481.8	$	1.46		479.0	$	1.00

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

Options to purchase 70,050 and 432,366 shares of common stock were outstanding at June 30, 2011 and 2010, respectively, but were not included in the computation of diluted earnings per share attributable to AEP common shareholders.  Since the options’ exercise prices were greater than the average market price of the common shares, the effect would have been antidilutive.

2.  NEW ACCOUNTING PRONOUNCEMENTS

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

Pronouncements Issued During 2011

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

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

In June 2011, the FASB issued ASU 2011-05 eliminating the option to present the components of other comprehensive income as a part of the statement of shareholders’ equity.  The standard requires other comprehensive income be presented as part of a single continuous statement of comprehensive income or in a statement of other comprehensive income immediately following the statement of net income.  Reclassification adjustments from other comprehensive income to net income must be presented on the face of the financial statements.  This standard must be retrospectively applied to all reporting periods presented in financial reports issued after the effective date.

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The new accounting guidance is effective for interim and annual periods beginning after December 15, 2011.  This standard will change the presentation of our financial statements but will not affect the calculation of net income, comprehensive income or earnings per share.We will adopt ASU 2011-05 effective January 1, 2012.

3.  RATE MATTERS

As discussed in the 2010 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within our 2010 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition.  The following discusses ratemaking developments in 2011 and updates the 2010 Annual Report.

Regulatory Assets Not Yet Being Recovered
	June 30,		December 31,
	2011		2010
	(in millions)
Noncurrent Regulatory Assets (excluding fuel)
Regulatory assets not yet being recovered pending future proceedings
to determine the recovery method and timing:
Regulatory Assets Currently Earning a Return
Line Extension Carrying Costs - CSPCo, OPCo (a)	$	61	$	55
Customer Choice Deferrals - CSPCo, OPCo (a)		60		59
Storm Related Costs - CSPCo, OPCo (a)		31		30
Storm Related Costs - TCC		25		25
Storm Related Costs - PSO (c)		18		-
Acquisition of Monongahela Power - CSPCo (a)		9		8
Other Regulatory Assets Not Yet Being Recovered		7		7
Regulatory Assets Currently Not Earning a Return
Environmental Rate Adjustment Clause - APCo		65		56
Storm Related Costs - APCo, KGPCo, SWEPCo		28		28
Deferred Wind Power Costs - APCo		38		29
Mountaineer Carbon Capture and Storage Product Validation Facility - APCo (b)		19		60
Special Rate Mechanism for Century Aluminum - APCo		13		13
Acquisition of Monongahela Power - CSPCo (a)		4		4
Storm Related Costs - PSO (c)		-		17
Other Regulatory Assets Not Yet Being Recovered		5		4
Total Regulatory Assets Not Yet Being Recovered	$	383	$	395

(a) Requested to be recovered in a distribution asset recovery rider.  See the "2011 Ohio Distribution Base Rate Case" section below.

(b) APCo wrote off a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC in March 2011.  See "Mountaineer Carbon Capture and Storage Project Product Validation Facility" section below.

(c) In June 2011, an order was received approving recovery of PSO storm costs and associated carrying costs with recovery to begin in August 2011.  Starting in the second quarter of 2011, and in accordance with the order received from the OCC, PSO recorded a return on its storm related costs.

CSPCo and OPCo Rate Matters

Ohio Electric Security Plan Filings

2009 – 2011 ESPs

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

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The order provided a FAC for the three-year period of the ESP.  The FAC was phased in to avoid having the resultant rate increases exceed the ordered annual caps described above.  The FAC is subject to quarterly true-ups, annual accounting audits and prudency reviews.  See the “2009 Fuel Adjustment Clause Audit” section below.  The order allowed CSPCo and OPCo to defer any unrecovered FAC costs resulting from the annual caps and to accrue associated carrying charges at their respective weighted average cost of capital.  Any deferred FAC regulatory asset balance at the end of the three-year ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018.  That recovery will include deferrals associated with the Ormet interim arrangement and is subject to the PUCO’s ultimate decision regarding the Ormet interim arrangement deferrals plus related carrying charges.  See the “Ormet Interim Arrangement” section below.  The FAC deferral as of June 30, 2011 was $27 million and $526 million for CSPCo and OPCo, respectively, excluding $388 thousand and $43 million, respectively, of unrecognized equity carrying costs.

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

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

In April 2011, the Supreme Court of Ohio (the Court) issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged which resulted in three reversals, only two of which may have a prospective impact through a remand proceeding.  First, the Court concluded that the PUCO's decision amounted to retroactive ratemaking.  Since the pertinent revenues were collected in 2009 and the Ohio Consumers’ Counsel did not successfully pursue the remedy of obtaining a stay of the order prior to the revenues being collected, there is no remand to the PUCO or refund to customers for this error.  Second, the Court held that the PUCO's conclusion that the POLR charge is cost-based conflicted with the evidence and remanded the issue to the PUCO for further consideration.  Third, the Court reversed the order’s legal basis for a carrying charge associated with certain environmental investments and remanded that issue to the PUCO to determine whether an alternative legal basis supports the charge.  Pursuant to a May 2011 PUCO order, CSPCo and OPCo implemented rates subject to refund and filed remand testimony in June 2011.  For the month ended June 30, 2011, CSPCo and OPCo recorded $14 million and $16 million, respectively, of revenues subject to refund.  In June 2011, the Ohio Consumers’ Counsel and the IEU filed testimony recommending a complete denial of collection of any POLR charges and carrying charges on certain environmental investments collected from 2009 through 2011.  They proposed unfavorable adjustments for CSPCo and OPCo of up to $370 million and $417 million, respectively, excluding carrying costs.  The proposed adjustments include a reduction of deferred FAC and other regulatory assets for the period prior to June 2011 of up to $298 million and $336 million for CSPCo and OPCo, respectively, which management believes is without merit and violates the Court’s decision.  The proposed adjustments also include refunds and rate reductions of related revenues beginning in June 2011 of $72 million and $81 million for CSPCo and OPCo, respectively.  Hearings were held in July 2011.

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

In January 2011, the PUCO issued an order on CSPCo’s and OPCo’s 2009 SEET filings and determined that OPCo’s 2009 earnings were not significantly excessive but determined relevant CSPCo earnings exceeded the PUCO determined threshold by 2.13%.  As a result, the PUCO ordered CSPCo to refund $43 million ($28 million net of tax) of its earnings to customers, which was recorded as a revenue provision on CSPCo’s December 2010 books.  The PUCO ordered that the significantly excessive earnings be applied first to CSPCo’s FAC deferral, including unrecognized equity carrying costs, as of the date of the order, with any remaining

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balance to be credited to CSPCo’s customers on a per kilowatt basis.  That credit began with the first billing cycle in February 2011 and will continue through December 2011.  Several parties, including CSPCo and OPCo, filed requests for rehearing with the PUCO, which were denied in March 2011.  In May 2011, the IEU and the Ohio Energy Group filed appeals with the Court challenging the PUCO’s SEET decisions.  CSPCo and OPCo are required to file their 2010 SEET filings with the PUCO in 2011.  Based upon the approach in the PUCO 2009 order, management does not currently believe that CSPCo or OPCo had any significantly excessive earnings in 2010.

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

January 2012 – May 2014 ESP

In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing on a combined company basis for generation.  The rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  The ESP also includes alternative energy resource requirements and addresses provisions regarding distribution service, energy efficiency requirements, economic development, job retention in Ohio, generation resources and other matters.  The SSO presents redesigned generation rates by customer class.  Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013.  The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESP could impact the outcome of the January 2012-May 2014 ESP, though the nature and extent of that impact is not presently known.  In July 2011, various intervenors filed testimony that generally asserts CSPCo's and OPCo's proposed SSO rates are higher than the market-rate offer, and objects to certain proposed riders as well as to the proposed non-bypassable nature of certain riders.  Additionally, the IEU and Ohio Consumers' Counsel object to revenues collected in the period 2009 through 2011 for POLR and carrying charges related to environmental investments and propose similar adjustments as discussed in the ESP remand proceeding.  See the "2009-2011 ESPs" section above.  A hearing for this case is scheduled for August 2011 and a decision is expected in the fourth quarter of 2011.

2011 Ohio Distribution Base Rate Case

In February 2011, CSPCo and OPCo filed with the PUCO for annual increases in distribution rates of $34 million and $60 million, respectively.  The requested increase is based upon an 11.15% return on common equity to be effective January 2012.

In addition to the annual increases, CSPCo and OPCo requested recovery of the projected December 31, 2012 balances of certain distribution regulatory assets of $216 million and $159 million, respectively, including approximately $102 million and $84 million, respectively, of unrecognized equity carrying costs.  These assets and unrecognized carrying costs would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013.  The actual balance of these distribution regulatory assets as of June 30, 2011 was $100 million and $64 million for CSPCo and OPCo, respectively, excluding $61 million and $45 million, respectively, of unrecognized equity carrying costs.  If CSPCo and OPCo are not ultimately permitted to fully recover their deferrals, it would reduce future net income and cash flows and impact financial condition.

Proposed CSPCo and OPCo Merger

In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo.  Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company.  In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo.  CSPCo and OPCo requested the reorganization transaction be effective in October 2011.  In July 2011, the FERC issued an order approving the proposed merger.  A decision is pending from the PUCO.  Management is unable to predict the outcome of this proceeding.

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Requested Sporn Unit 5 Shutdown and Proposed Distribution Rider

In October 2010, OPCo filed an application with the PUCO for the approval of a December 2010 closure of Sporn Unit 5 and the simultaneous establishment of a new non-bypassable distribution rider outside the rate caps established in the 2009 – 2011 ESP proceeding.  The proposed rider would recover the net book value of the unit as well as related materials and supplies as of December 2010, which was estimated to total $59 million, as well as future closure costs incurred after December 2010.  OPCo also requested authority to record the future closure costs as a regulatory asset or regulatory liability with a weighted average cost of capital carrying charge to be included in the proposed non-bypassable distribution rider after the costs are incurred.  Pending PUCO approval, Sporn Unit 5 continues to operate.  In April 2011, intervenors filed comments opposing OPCo’s application.  A PUCO decision is pending as to whether a hearing will be ordered.  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 CSPCo and OPCo for the period of January 2009 through December 2009.  In May 2010, the outside consultant provided its confidential audit report to the PUCO.  The audit report included a recommendation that the PUCO review whether any proceeds from a 2008 coal contract settlement agreement which totaled $72 million should reduce OPCo’s FAC under-recovery balance.  Of the total proceeds, approximately $58 million was recognized as a reduction to fuel expense prior to 2009 and $14 million was recognized as a reduction to fuel expense in 2009 and 2010.  Hearings were held in August 2010.  A decision from the PUCO is pending.  Management is unable to predict the outcome of this proceeding.  If the PUCO orders any portion of the $58 million previously recognized gains or any future adjustments be used to reduce the FAC deferral, it would reduce future net income and cash flows and impact financial condition.

2010 Fuel Adjustment Clause Audit

In May 2011, the PUCO-selected outside consultant issued their results of the 2010 FAC audit for CSPCo and OPCo.  The audit report included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balances and determine whether the carrying costs on the balances should be net of accumulated income taxes.  As of June 30, 2011, the amount of OPCo’s carrying costs that could potentially be at risk is estimated to be $13 million, excluding $16 million of unrecognized equity carrying costs. The amount of carrying costs for CSPCo that could potentially be at risk is immaterial.  A decision from the PUCO is pending.  Management is unable to predict the outcome of this proceeding.  If the PUCO order results in a reduction in the carrying charges related to the FAC deferrals, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

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

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Economic Development Rider

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

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

As of June 30, 2011, CSPCo and OPCo have incurred EDR costs of $59 million and $55 million, respectively, including carrying costs.  Of these costs, CSPCo and OPCo have collected $50 million and $39 million, respectively, through the EDR, which CSPCo and OPCo began collecting in January 2010.  The remaining $9 million and $16 million for CSPCo and OPCo, respectively, are recorded as deferred EDR regulatory assets.  If CSPCo and OPCo are not ultimately permitted to recover their deferrals or are required to refund EDR revenue collected, it would reduce future net income and cash flows and impact financial condition.

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 June 30, 2011, CSPCo and OPCo have collected $12 million and $12 million, respectively, in pre-construction costs authorized in a June 2006 PUCO order and incurred $11 million and $11 million, respectively, in pre-construction costs.  As a result, CSPCo and OPCo established net regulatory liabilities of approximately $1 million and $1 million, respectively.  The order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant before June 2011, any pre-construction costs that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest.  As of June 2011, there were no active IGCC projects at other AEP sites.  In June 2011, CSPCo and OPCo filed a recommendation with the PUCO to refund to customers $2 million and $2 million, respectively, for the over-recovered pre-construction costs including interest.  Intervenors have filed motions with the PUCO requesting all collected pre-construction costs be refunded to Ohio ratepayers with interest.

Management cannot predict the outcome of any cost recovery litigation concerning the Ohio IGCC plant or what effect, if any, such litigation would have on future net income and cash flows.  However, if CSPCo and OPCo are required to refund pre-construction costs collected in excess of the over-recovered pre-construction costs, it would reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in service in 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, plus an additional $124 million for transmission, excluding AFUDC.  SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $124 million for transmission, excluding AFUDC.  As of June 30, 2011, excluding costs attributable to its joint owners, SWEPCo has capitalized approximately $1.2 billion of expenditures (including AFUDC and capitalized interest of $175 million and related transmission costs of $79 million).  As of June 30, 2011, the joint owners and SWEPCo have contractual

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construction commitments of approximately $211 million (including related transmission costs of $11 million).  SWEPCo’s share of the contractual construction commitments is $157 million.  If the plant is cancelled, the joint owners and SWEPCo would incur contractual construction cancellation fees, based on construction status as of June 30, 2011, of approximately $101million (including related transmission cancellation fees of $1 million).  SWEPCo’s share of the contractual construction cancellation fees would be approximately $74 million.

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

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

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

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

A wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009.  In 2010, the Sierra Club, the Audubon Society and others filed a complaint in the Federal District Court for the Western District of Arkansas against the U.S. Army Corps of Engineers challenging the process used and the terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts, and sought a preliminary injunction to halt construction and for a temporary restraining order.  In July 2010, the Hempstead County Hunting Club (Hunting Club) also filed a complaint with the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of the Interior and the U.S. Fish and Wildlife Service seeking a temporary restraining order and preliminary injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws.  The plaintiffs’ federal law claims challenge the process used and terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts.  The plaintiffs’ state law claims challenge SWEPCo's ability to construct the Turk Plant without obtaining a certificate from the APSC.  In October 2010, the Federal District Court certified issues relating to the state law claims to the Arkansas Supreme Court, including whether those claims are within the primary jurisdiction of the APSC.  In May 2011, the Arkansas Supreme Court determined that these claims must first be brought before the APSC and that the federal court does not have jurisdiction to hear the state law claims.  In 2010, the motions for preliminary injunction were partially granted.  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

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affects portions of the water intake and portions of two transmission lines.  SWEPCo appealed the issuance of the preliminary injunction to the U.S. Eighth Circuit Court of Appeals, and in July 2011, the Court of Appeals affirmed the preliminary injunction.  Management is unable to predict the timing or the outcome related to this remand proceeding.

In July 2011, SWEPCo reached an agreement in principle that would resolve all pending matters between SWEPCo, the Hunting Club and several other parties.  As a result, the Hunting Club’s challenge to the U.S. Army Corps of Engineers permit in the Federal District Court for the Western District of Arkansas will be dismissed and the Hunting Club’s appeal of the air permit will be withdrawn.  Additional judicial and administrative proceedings will also be terminated.  SWEPCo was unable to resolve claims by the Sierra Club and the Audubon Society, so their challenges to the wetlands and air permits will continue.

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

TCC Rate Matters

TEXAS RESTRUCTURING

Texas Restructuring Appeals

Pursuant to PUCT restructuring orders, TCC securitized net recoverable stranded generation costs of $2.5 billion and is recovering the principal and interest on the securitization bonds through the end of 2020.  TCC also refunded other net true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider under PUCT restructuring orders.  TCC and intervenors appealed the PUCT’s true-up related orders.  After rulings from the Texas District Court and the Texas Court of Appeals, TCC, the PUCT and intervenors filed petitions for review with the Supreme Court of Texas.  In July 2011, the Supreme Court of Texas granted review and issued its opinion.  The following issues were decided by the Supreme Court:

·   The PUCT’s order denying recovery of capacity auction true-up amounts was reversed.  We estimate that, in the remand to the PUCT, TCC will be entitled to recover approximately $420 million, plus interest from January 1, 2002.

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

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

·   The Supreme Court of Texas reversed the Court of Appeal’s decision and found it was appropriate for the PUCT to take into account previously refunded excess mitigation credits to affiliate retail electricity providers.  This portion of the decision upheld the PUCT’s decision.  However, resolution of related issues will be addressed on remand.

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

No parties have filed for rehearing with the Supreme Court of Texas, and the case will be remanded to the PUCT.

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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 a reduction was an IRS normalization violation.  In order to avoid a normalization violation, the PUCT agreed to allow TCC to defer refunding the tax benefits of $103 million plus interest through the CTC refund period pending resolution of the normalization issue.  In 2008, the IRS issued final regulations, which supported the IRS’s private letter ruling which would make the refunding of or the reduction of the amount securitized by such tax benefits a normalization violation.  After the IRS issued its final regulations the Texas Court of Appeals, at the request of the PUCT, remanded the tax normalization issue to the PUCT for the consideration of additional evidence including the IRS regulations.  The issue will be considered by the PUCT when the true-up proceeding is remanded following the July 2011 Supreme Court of Texas decision.  See the “Texas Restructuring Appeals” section above.  TCC is not accruing interest on the $103 million because management believes it is not probable that the PUCT will order TCC to violate the normalization provision of the Internal Revenue Code.  If interest were accrued, management estimates interest expense would have been approximately $27 million higher for the period July 2008 through June 2011.

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

TCC Excess Earnings

In 2005, a Texas appellate court issued a decision finding that a PUCT order requiring TCC to refund to the 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.  The PUCT must determine if adjustments are required on remand based on the July 2011 decision of the Supreme Court of Texas on the impact of excess earnings in the true-up proceeding.  See the “Texas Restructuring Appeals” section above.

APCo and WPCo Rate Matters

2011 Virginia Biennial Base Rate Case

In March 2011, APCo filed a generation and distribution base rate request with the Virginia SCC to increase annual base rates by $126 million based upon an 11.65% return on common equity to be effective no later than February 2012.  The return on common equity includes a requested 0.5% renewable portfolio standards incentive as allowed by law.APCo proposed to mitigate the requested base rate increase by $51 million by maintaining current depreciation rates until the next biennial filing.  If approved, APCo’s net base rate increase would be $75 million.  In July 2011, an Attorney General witness recommended an $80 million reduction in APCo’s requested rate year capacity charges.

Rate Adjustment Clauses

In 2007, the Virginia law governing the regulation of electric utility service was amended to, among other items, provide for rate adjustment clauses (RACs) beginning in January 2009 for the timely and current recovery of costs of: (a) transmission services billed by an RTO, (b) demand side management and energy efficiency programs, (c) renewable energy programs, (d) environmental compliance projects and (e) new generation facilities, including major unit modifications.  In March 2011, APCo filed for approval of an environmental RAC, a renewable energy program RAC and a generation RAC simultaneous with the 2011 Virginia base rate filing.  The environmental RAC is requesting recovery of environmental compliance costs incurred from January 2009 through December 2010 of $38 million annually based on a two-year amortization.  The renewable energy program RAC is requesting the

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incremental portion of deferred wind power costs for the Camp Grove and Fowler Ridge projects of $6 million.  The generation RAC is requesting recovery of the Dresden Plant, currently under construction, which APCo has requested to purchase from AEGCo.      

In accordance with Virginia law, APCo is deferring incremental environmental costs incurred after December 2008 and renewable energy costs incurred after August 2009 which are not being recovered in current revenues.  As of June 30, 2011, APCo has deferred $65 million of environmental costs (excluding $15 million of unrecognized equity carrying costs) and $38 million of renewable energy costs.  APCo plans to seek recovery of non-incremental deferred wind power costs ($32 million as of June 30, 2011) in future rate proceedings.  If the Virginia SCC were to disallow a portion of APCo’s deferred costs, it would reduce future net income and cash flows.

2010 West Virginia Base Rate Case

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

Mountaineer Carbon Capture and Storage Project

Product Validation Facility (PVF)

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

In APCo’s and WPCo’s May 2010 West Virginia base rate filing, APCo and WPCo requested rate base treatment of the PVF, including recovery of the related asset retirement obligation regulatory asset amortization and accretion.  In March 2011, a WVPSC order denied the request for rate base treatment of the PVF largely due to its experimental operation.  The base rate order provided that should APCo construct a commercial scale carbon capture and sequestration (CCS) facility, only the West Virginia portion of the PVF costs, based on load sharing among certain AEP operating companies, may be considered used and useful plant in service and included in future rate base.  As a result, APCo recorded a pretax write-off of $41 million ($26 million net of tax) in the first quarter of 2011 recorded to Other Operation expense on the Condensed Consolidated Statements of Operations.  See “2010 West Virginia Base Rate Case” section above.  As of June 30, 2011, APCo has recorded a noncurrent regulatory asset of $19 million related to the PVF.  If APCo cannot recover its remaining PVF investment and related accretion expenses, it would reduce future net income and cash flows.

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

During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale CCS facility at the Mountaineer Plant.  AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project.  The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million.  In July 2011, management informed the DOE that it will complete a Front-End Engineering and Design study during the third quarter of 2011, but it is postponing any further CCS project activities because of the uncertainty about the regulation of CO2.  As of June 30, 2011, the project has incurred $30 million in total costs and has received $10 million of DOE eligible funding resulting in a $20 million net balance recorded in Deferred Charges and Other Noncurrent Assets on the Condensed Consolidated Balance Sheets.  Requests for recovery are in process in Michigan, Ohio and Virginia.  If the costs of the CCS project cannot be recovered, it would reduce future net income and cash flows.

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APCo’s Filings for an IGCC Plant

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

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

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

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

In September 2009, the WVPSC issued an order approving APCo’s and WPCo’s March 2009 ENEC request.  The approved order provided for recovery of an under-recovered balance plus a projected increase in ENEC costs over a four-year phase-in period with an overall increase of $355 million and a first-year increase of $124 million, effective October 2009.

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

In June 2011, the WVPSC issued an order approving a $98 million annual increase including $8 million of construction surcharges and $8 million of carrying charges related to APCo’s and WPCo’s third year ENEC increase.  The order also allows APCo to accrue a fixed annual carrying cost rate of 4%.  The new rates became effective in July 2011.  Additionally, the order approved APCo’s request to purchase the Dresden Plant, currently under construction, from AEGCo and approved deferral of post in-service Dresden Plant costs, including a return, for future recovery.  As of June 30, 2011, APCo’s ENEC under-recovery balance was $387 million, excluding $8 million of unrecognized equity carrying costs, which is included in noncurrent regulatory assets.  If the WVPSC were to disallow a portion of APCo’s and WPCo’s deferred ENEC costs, it could reduce future net income and cash flows and impact financial condition.

PSO Rate Matters

PSO 2008 Fuel and Purchased Power

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

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I&M Rate Matters

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

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

2011 Michigan Base Rate Case

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

FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund

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

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

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

In August 2010, the affected companies, including the AEP East companies, filed a compliance filing with the FERC.  If the compliance filing is accepted, the AEP East companies would have to pay refunds of approximately $20 million including estimated interest of $5 million.  The AEP East companies could also potentially receive payments up to approximately $10 million including estimated interest of $3 million.  A decision is pending from the FERC.

The FERC has approved settlements applicable to $112 million of SECA revenue.  The AEP East companies provided reserves for net refunds for SECA settlements applicable to the remaining $108 million of SECA revenues collected.  Based on the AEP East companies’ analysis of the May 2010 order and the compliance filing, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the 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.

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Possible Termination of the Interconnection Agreement

In December 2010, each of the AEP Power Pool members gave notice to AEPSC and each other of their decision to terminate the Interconnection Agreement effective January 2014 or such other date approved by FERC, subject to state regulatory input.  No filings have been made at the FERC.  It is unknown at this time whether the AEP Power Pool will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers or if each company will choose to operate independently.  This decision to terminate is subject to management’s ongoing evaluation.  The AEP Power Pool members may revoke their notices of termination.  If any of the AEP Power Pool members experience decreases in revenues or increases in costs as a result of the termination of the AEP Power Pool and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

PJM/MISO Market Flow Calculation Settlement Adjustments

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

4.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

We are subject to certain claims and legal actions arising in our ordinary course of business.  In addition, our business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation against us cannot be predicted.  For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on our financial statements.  The Commitments, Guarantees and Contingencies note within our 2010 Annual Report should be read in conjunction with this report.

GUARANTEES

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

Letters of Credit

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

We have two $1.5 billion credit facilities, under which we may issue up to $1.35 billion as letters of credit.  In July 2011, we replaced the $1.5 billion facility due in 2012 with a new $1.75 billion facility maturing in July 2016 and extended the $1.5 billion facility due in 2013 to expire in June 2015.  As of June 30, 2011, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $132 million with maturities ranging from September 2011 to April 2012.

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

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Guarantees of Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of approximately $65 million.  In July 2011, SWEPCo’s guarantee was increased to $100 million due to expansion of the mining area.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), a consolidated variable interest entity.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study, we estimate the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  As of June 30, 2011, SWEPCo has collected approximately $51 million through a rider for final mine closure and reclamation costs, of which $1 million is recorded in Other Current Liabilities, $30 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $20 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.

Indemnifications and Other Guarantees

Contracts

We enter into several types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, our exposure generally does not exceed the sale price.  The status of certain sale agreements is discussed in the 2010 Annual Report “Dispositions” section of Note 7.  As of June 30, 2011, there were no material liabilities recorded for any indemnifications.

Master Lease Agreements

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

For equipment under the GE master lease agreements, the lessor is guaranteed receipt of up to 78% of the unamortized balance of the equipment at the end of the lease term.  If the fair value of the leased equipment is below the unamortized balance at the end of the lease term, we are committed to pay the difference between the fair value and the unamortized balance, with the total guarantee not to exceed 78% of the unamortized balance.  For equipment under other master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, we are committed to pay the difference between the actual fair value and the residual value guarantee.  At June 30, 2011, the maximum potential loss for these lease agreements was approximately $15 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.

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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 assignments are accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $16 million for I&M and $18 million for SWEPCo for the remaining railcars as of June 30, 2011.

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

ENVIRONMENTAL CONTINGENCIES

Carbon Dioxide Public Nuisance Claims

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

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

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina.  The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims.  The court granted petitions for rehearing.  An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place. Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision.  The petition was denied in January 2011.  Plaintiffs refiled their complaint in federal district court.  We believe the claims are without merit, and in addition to other defenses, are barred by the doctrine of collateral estoppel and the applicable statute of limitations.  We intend to vigorously defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

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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.  The defendants requested that the court defer setting this case for oral argument until after the Supreme Court issues its decision in the CO2 public nuisance case discussed above.  The court entered an order deferring argument until after June 2011 and the parties requested supplemental briefing on the impact of the Supreme Court’s decision.  We believe the action is without merit and intend to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

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

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

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

Amos Plant – State and Federal Enforcement Proceedings

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

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

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NUCLEAR CONTINGENCIES

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

Cook Plant Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in significant turbine damage and a small fire on the electric generator.  This equipment, located in the turbine building, is separate and isolated from the nuclear reactor.  The turbine rotors that caused the vibration were installed in 2006 and are within the vendor’s warranty period.  The warranty provides for the repair or replacement of the turbine rotors if the damage was caused by a defect in materials or workmanship.  Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $408 million.  Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process.  I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power.  The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors.  The 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 insurance through NEIL.  As of June 30, 2011, we recorded $60 million in Prepayments and Other Current Assets on our Condensed Consolidated Balance Sheets representing amounts under NEIL insurance policies.  Through June 30, 2011, I&M received partial payments of $203 million from NEIL for the cost incurred to date to repair the property damage.

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

OPERATIONAL CONTINGENCIES

Fort Wayne Lease

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

I&M and Fort Wayne reached a settlement agreement.  The agreement, signed in October 2010, is subject to approval by the IURC.  I&M filed a petition with the IURC seeking approval of the agreement, including recovery in rates of payments made to Fort Wayne.  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.  In April 2011, the Indiana Office of Utility Consumer Counselor (OUCC) filed comments opposing portions of the settlement agreement.  An agreement with the OUCC was reached and hearing before the IURC occurred in June 2011.  IURC approval of the agreement is expected during the third quarter of 2011.  If the agreement is not approved by the IURC, the parties have the right to terminate the agreement and pursue other relief.

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Enron Bankruptcy

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

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

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

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

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

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

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

	(in millions)
Income Statement:
Other Operation Expense - Pretax Gain on Settlement	$	51
Income Tax Expense		73
Net Loss After Tax	$	(22	)
Cash Flow Statement:
Net Income - Loss on Settlement with BOA and Enron	$	(22	)
Deferred Income Taxes		91
Gain on Settlement with BOA and Enron		(51	)
Settlement of Litigation with BOA and Enron		(211	)
Accrued Taxes, Net		(18	)
Acquisition of Cushion Gas from BOA		(214	)
Cash Paid	$	(425	)
Balance Sheet:
Deferred Charges and Other Noncurrent Assets - Gas Acquired	$	214
Deferred Credits and Other Noncurrent Liabilities - Gas Service Liability		187
Accrued Taxes - Tax Benefit on Settlement with BOA and Enron		18
Deferred Income Taxes - Deferred Tax Benefit on Gas Service Liability		66

Natural Gas Markets Lawsuits

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

5.  ACQUISITION AND DISPOSITIONS

ACQUISITION

2010

Valley Electric Membership Corporation (Utility Operations segment)

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

DISPOSITIONS

2010

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

During the six months ended June 30, 2010, TCC and TNC sold, at cost, $64 million and $71 million, respectively, of transmission facilities to ETT.

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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 three months ended June 30, 2010.

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 six months ended June 30, 2011 and 2010:

									Other Postretirement
	Pension Plans								Benefit Plans
	Three Months Ended June 30,								Three Months Ended June 30,
	2011				2010				2011				2010
	(in millions)
Service Cost		$	18			$	27			$	10			$	11
Interest Cost			60				64				27				28
Expected Return on Plan Assets			(78	)			(78	)			(27	)			(26	)
Amortization of Transition Obligation			-				-				-				7
Amortization of Net Actuarial Loss			31				23				8				7
Net Periodic Benefit Cost		$	31			$	36			$	18			$	27

									Other Postretirement
	Pension Plans								Benefit Plans
	Six Months Ended June 30,								Six Months Ended June 30,
	2011				2010				2011				2010
	(in millions)
Service Cost		$	36			$	55			$	21			$	23
Interest Cost			119				127				54				56
Expected Return on Plan Assets			(157	)			(156	)			(54	)			(52	)
Amortization of Transition Obligation			-				-				-				14
Amortization of Net Actuarial Loss			61				45				15				14
Net Periodic Benefit Cost		$	59			$	71			$	36			$	55

7.  BUSINESS SEGMENTS

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

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

Utility Operations

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

·Electricity transmission and distribution in the U.S.

AEP River Operations

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

Generation and Marketing

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

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

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

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

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

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

			Nonutility Operations
					Generation
	Utility		AEP River		and		All Other		Reconciling
	Operations		Operations		Marketing		(a)		Adjustments		Consolidated
	(in millions)
Three Months Ended June 30, 2011
Revenues from:
External Customers	$	3,360	$	162	$	79	$	8	$	-	$	3,609
Other Operating Segments		29		4		-		2		(35)		-
Total Revenues	$	3,389	$	166	$	79	$	10	$	(35)	$	3,609
Net Income (Loss)	$	356	$	(1)	$	11	$	(13)	$	-	$	353
			Nonutility Operations
					Generation
	Utility		AEP River		and		All Other		Reconciling
	Operations		Operations		Marketing		(a)		Adjustments		Consolidated
	(in millions)
Three Months Ended June 30, 2010
Revenues from:
External Customers	$	3,186	$	127	$	42	$	5	$	-	$	3,360
Other Operating Segments		25		5		-		(1)		(29)		-
Total Revenues	$	3,211	$	132	$	42	$	4	$	(29)	$	3,360
Net Income (Loss)	$	132	$	(1)	$	7	$	(1)	$	-	$	137

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			Nonutility Operations
					Generation
	Utility		AEP River		and		All Other		Reconciling
	Operations		Operations		Marketing		(a)		Adjustments		Consolidated
	(in millions)
Six Months Ended June 30, 2011
Revenues from:
External Customers	$	6,857	$	329	$	141	$	12	$	-	$	7,339
Other Operating Segments		56		9		1		3		(69)		-
Total Revenues	$	6,913	$	338	$	142	$	15	$	(69)	$	7,339
Net Income (Loss)	$	734	$	6	$	12	$	(44)	$	-	$	708
			Nonutility Operations
					Generation
	Utility		AEP River		and		All Other		Reconciling
	Operations		Operations		Marketing		(a)		Adjustments		Consolidated
	(in millions)
Six Months Ended June 30, 2010
Revenues from:
External Customers	$	6,592	$	248	$	89	$	-	$	-	$	6,929
Other Operating Segments		45		10		-		7		(62)		-
Total Revenues	$	6,637	$	258	$	89	$	7	$	(62)	$	6,929
Net Income (Loss)	$	476	$	2	$	17	$	(12)	$	-	$	483

				Nonutility Operations
						Generation				Reconciling
	Utility			AEP River		and		All Other		Adjustments
	Operations			Operations		Marketing		(a)		(b)					Consolidated
	(in millions)
June 30, 2011
Total Property, Plant and Equipment		$	53,735	$	590	$	591	$	11		$	(258	)		$	54,669
Accumulated Depreciation and Amortization			18,315		124		209		9			(52	)			18,605
Total Property, Plant and Equipment - Net		$	35,420	$	466	$	382	$	2		$	(206	)		$	36,064
Total Assets		$	48,858	$	647	$	864	$	15,974		$	(15,591	)	(c)	$	50,752
				Nonutility Operations
						Generation				Reconciling
	Utility			AEP River		and		All Other		Adjustments
	Operations			Operations		Marketing		(a)		(b)					Consolidated
	(in millions)
December 31, 2010
Total Property, Plant and Equipment		$	52,822	$	574	$	584	$	11		$	(251	)		$	53,740
Accumulated Depreciation and Amortization			17,795		110		198		9			(46	)			18,066
Total Property, Plant and Equipment - Net		$	35,027	$	464	$	386	$	2		$	(205	)		$	35,674
Total Assets		$	48,780	$	621	$	881	$	15,942		$	(15,769	)	(c)	$	50,455

(a) All Other includes:

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

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

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

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

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

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8.  DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

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

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Trading Strategies

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

Risk Management Strategies

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

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

The following table represents the gross notional volume of our outstanding derivative contracts as of June 30, 2011 and December 31, 2010:

Notional Volume of Derivative Instruments
	Volume
	June 30,			December 31,			Unit of
	2011			2010			Measure
	(in millions)
Commodity:
Power			875			652	MWHs
Coal			48			63	Tons
Natural Gas			91			94	MMBtus
Heating Oil and Gasoline			7			6	Gallons
Interest Rate		$	267		$	171	USD
Interest Rate and Foreign Currency		$	597		$	907	USD

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Fair Value Hedging Strategies

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

Cash Flow Hedging Strategies

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

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

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

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

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities 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 June 30, 2011 and December 31, 2010 balance sheets, we netted $16 million and $8 million,

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respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $55 million and $109 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.

The following tables represent the gross fair value impact of our derivative activity on our Condensed Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010:

Fair Value of Derivative Instruments
June 30, 2011
	Risk Management
	Contracts		Hedging Contracts
					Interest Rate
					and Foreign
Balance Sheet Location	Commodity (a)		Commodity (a)		Currency (a)		Other (a)(b)			Total
	(in millions)
Current Risk Management Assets	$	669	$	26	$	6	$	(528	)		$	173
Long-term Risk Management Assets		482		13		3		(155	)			343
Total Assets		1,151		39		9		(683	)			516
Current Risk Management Liabilities		636		14		2		(558	)			94
Long-term Risk Management Liabilities		317		6		1		(200	)			124
Total Liabilities		953		20		3		(758	)			218
Total MTM Derivative Contract Net Assets
(Liabilities)	$	198	$	19	$	6	$	75			$	298
Fair Value of Derivative Instruments
December 31, 2010
	Risk Management
	Contracts		Hedging Contracts
					Interest Rate
					and Foreign
Balance Sheet Location	Commodity (a)		Commodity (a)		Currency (a)		Other (a)(b)			Total
	(in millions)
Current Risk Management Assets	$	1,023	$	18	$	30	$	(839	)		$	232
Long-term Risk Management Assets		546		12		2		(150	)			410
Total Assets		1,569		30		32		(989	)			642
Current Risk Management Liabilities		995		13		2		(881	)			129
Long-term Risk Management Liabilities		387		6		3		(255	)			141
Total Liabilities		1,382		19		5		(1,136	)			270
Total MTM Derivative Contract Net Assets
(Liabilities)	$	187	$	11	$	27	$	147			$	372

(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 Sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."

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

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The tables below present our activity of derivative risk management contracts for the three and six months ended June 30, 2011 and 2010:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended June 30, 2011 and 2010
Location of Gain (Loss)	2011		2010
	(in millions)
Utility Operations Revenue	$	18	$	7
Other Revenue		13		8
Regulatory Assets (a)		(5)		(14)
Regulatory Liabilities (a)		5		(4)
Total Gain (Loss) on Risk Management Contracts	$	31	$	(3)

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Six Months Ended June 30, 2011 and 2010
Location of Gain (Loss)	2011		2010
	(in millions)
Utility Operations Revenue	$	38	$	45
Other Revenue		15		9
Regulatory Assets (a)		(1)		(3)
Regulatory Liabilities (a)		11		27
Total Gain (Loss) on Risk Management Contracts	$	63	$	78

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

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

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.

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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 six months ended June 30, 2011, we recognized gains of $4 million and $8 million, respectively, on our outstanding hedging instruments and offsetting losses of $5 million and $9 million, respectively,on our long-term debt.  Hedge ineffectiveness was immaterial.  During the three and six months ended June 30, 2010, we recognized gains of $4 million and $4 million, respectively, on our outstanding hedging instruments and offsetting losses of $4 million and $4 million, respectively, on our long-term debt.  No hedge ineffectiveness was recognized.

Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on our Condensed 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 six months ended June 30, 2011 and 2010, we designated commodity derivatives as cash flow hedges.

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

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

The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our Condensed 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 six months ended June 30, 2011 and 2010, we designated foreign currency derivatives as cash flow hedges.

During the three and six months ended June 30, 2011 and 2010, 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 Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets and the reasons for changes in cash flow hedges for the three and six months ended June 30, 2011 and 2010.  All amounts in the following tables are presented net of related income taxes.

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

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended June 30, 2010
					Interest Rate
					and Foreign
	Commodity				Currency				Total
	(in millions)
Balance in AOCI as of March 31, 2010		$	2			$	(13	)		$	(11	)
Changes in Fair Value Recognized in AOCI			1				(3	)			(2	)
Amount of (Gain) or Loss Reclassified from AOCI
to Income Statement/within Balance Sheet:
Utility Operations Revenue			-				-				-
Other Revenue			(2	)			-				(2	)
Purchased Electricity for Resale			1				-				1
Interest Expense			-				1				1
Regulatory Assets (a)			-				-				-
Regulatory Liabilities (a)			-				-				-
Balance in AOCI as of June 30, 2010		$	2			$	(15	)		$	(13	)

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

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Six Months Ended June 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			4				(4	)			-
Amount of (Gain) or Loss Reclassified from AOCI
to Income Statement/within Balance Sheet:
Utility Operations Revenue			-				-				-
Other Revenue			(3	)			-				(3	)
Purchased Electricity for Resale			2				-				2
Interest Expense			-				2				2
Regulatory Assets (a)			1				-				1
Regulatory Liabilities (a)			-				-				-
Balance in AOCI as of June 30, 2010		$	2			$	(15	)		$	(13	)

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

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Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets at June 30, 2011 and December 31, 2010 were:

Impact of Cash Flow Hedges on our Condensed Consolidated Balance Sheet
June 30, 2011
				Interest Rate
				and Foreign
	Commodity			Currency				Total
	(in millions)
Hedging Assets (a)		$	21		$	1			$	22
Hedging Liabilities (a)			2			3				5
AOCI Gain (Loss) Net of Tax			12			5				17
Portion Expected to be Reclassified to Net
Income During the Next Twelve Months			7			(2	)			5
Impact of Cash Flow Hedges on our Condensed Consolidated Balance Sheet
December 31, 2010
				Interest Rate
				and Foreign
	Commodity			Currency				Total
	(in millions)
Hedging Assets (a)		$	13		$	25			$	38
Hedging Liabilities (a)			2			4				6
AOCI Gain (Loss) Net of Tax			7			4				11
Portion Expected to be Reclassified to Net
Income During the Next Twelve Months			3			(2	)			1

(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 June 30, 2011, the maximum length of time that we are hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) our exposure to variability in future cash flows related to forecasted transactions is 36 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 the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, we are obligated to post an additional amount of collateral if our credit ratings decline below investment grade.The amount of collateral required fluctuates based on market prices and our total exposure.  On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts.  We do not anticipate a downgrade below investment grade.  The following table represents: (a) our aggregate fair value of such derivative contracts, (b) the amount of collateral we would have been required to post for all derivative and non-derivative contracts if our credit ratings had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of June 30, 2011 and December 31, 2010:

	June 30,		December 31,
	2011		2010
	(in millions)
Liabilities for Derivative Contracts with Credit Downgrade Triggers	$	29	$	20
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post		34		45
Amount Attributable to RTO and ISO Activities		34		44

In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable.  These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million.  On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts.  We do not anticipate a non-performance event under these provisions.  The following table represents: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral we have posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering our contractual netting arrangements as of June 30, 2011 and December 31, 2010:

	June 30,		December 31,
	2011		2010
	(in millions)
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements	$	344	$	401
Amount of Cash Collateral Posted		35		81
Additional Settlement Liability if Cross Default Provision is Triggered		179		213

9.  FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

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

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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.  If the points are highly correlated, we include these locations within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Long-dated and illiquid complex or structured transactions and FTRs can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.

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

Assets in the nuclear trusts, Cash and Cash Equivalents and Other Temporary Investments are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities.  They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.  Fixed income securities do not trade on an exchange and do not have an official closing price.  Pricing vendors calculate bond valuations using financial models and matrices.  Fixed income securities are typically classified as Level 2 holdings because their valuation inputs are based on observable market data.  Observable inputs used for valuing fixed income securities are benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, bids, offers, reference data and economic events.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.

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

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

Fair Value Measurements of Long-term Debt

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

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

	June 30, 2011				December 31, 2010
	Book Value		Fair Value		Book Value		Fair Value
	(in millions)
Long-term Debt	$	16,635	$	18,251	$	16,811	$	18,285

Fair Value Measurements of Other Temporary Investments

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

The following is a summary of Other Temporary Investments:

	June 30, 2011
			Gross		Gross		Estimated
			Unrealized		Unrealized		Fair
Other Temporary Investments	Cost		Gains		Losses		Value
	(in millions)
Restricted Cash (a)	$	212	$	-	$	-	$	212
Fixed Income Securities:
Mutual Funds		63		-		-		63
Variable Rate Demand Notes		21		-		-		21
Equity Securities - Mutual Funds		7		8		-		15
Total Other Temporary Investments	$	303	$	8	$	-	$	311

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

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

The following table provides the activity for our debt and equity securities within Other Temporary Investments for the three and six months ended June 30, 2011 and 2010:

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(in millions)
Proceeds from Investment Sales	$	51	$	16	$	247	$	257
Purchases of Investments		5		24		153		221
Gross Realized Gains on Investment Sales		-		16		-		16
Gross Realized Losses on Investment Sales		-		-		-		-

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

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Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

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

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

·   Maximum percentage invested in a specific type of investment.

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

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

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

I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value.  I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose.  Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the equity and debt investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment.  I&M records unrealized gains and other-than-temporary impairments from securities in the trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  Consequently, changes in fair value of trust assets do not affect earnings or AOCI.  The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities.  Regulatory approval is required to withdraw decommissioning funds.

The following is a summary of nuclear trust fund investments at June 30, 2011 and December 31, 2010:

	June 30, 2011							December 31, 2010
	Estimated		Gross		Other-Than-			Estimated		Gross			Other-Than-
	Fair		Unrealized		Temporary			Fair		Unrealized			Temporary
	Value		Gains		Impairments			Value		Gains			Impairments
	(in millions)
Cash and Cash Equivalents	$	17	$	-	$	-		$	20	$	-		$	-
Fixed Income Securities:
United States Government		484		27		(1	)		461		23			(1	)
Corporate Debt		57		3		(1	)		59		4			(2	)
State and Local Government		338		1		(1	)		341		(1	)		-
Subtotal Fixed Income Securities		879		31		(3	)		861		26			(3	)
Equity Securities - Domestic		678		231		(105	)		634		183			(123	)
Spent Nuclear Fuel and
Decommissioning Trusts	$	1,574	$	262	$	(108	)	$	1,515	$	209		$	(126	)

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(in millions)
Proceeds from Investment Sales	$	177	$	360	$	465	$	592
Purchases of Investments		186		369		492		617
Gross Realized Gains on Investment Sales		7		1		12		6
Gross Realized Losses on Investment Sales		4		-		9		-

The adjusted cost of debt securities was $848 million and $835 million as of June 30, 2011 and December 31, 2010, respectively.  The adjusted cost of equity securities was $447 million and $451 million as of June 30, 2011 and December 31, 2010, respectively.

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

	Fair Value
	of Debt
	Securities
	(in millions)
Within 1 year		$	77
1 year – 5 years			256
5 years – 10 years			281
After 10 years			265
Total		$	879

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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 June 30, 2011 and December 31, 2010.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in our valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2011
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Cash and Cash Equivalents (a)	$	208	$	-	$	-	$	209		$	417
Other Temporary Investments
Restricted Cash (a)		160		-		-		52			212
Fixed Income Securities:
Mutual Funds		63		-		-		-			63
Variable Rate Demand Notes		-		21		-		-			21
Equity Securities - Mutual Funds (b)		15		-		-		-			15
Total Other Temporary Investments		238		21		-		52			311
Risk Management Assets
Risk Management Commodity Contracts (c) (f)		17		1,006		113		(686	)		450
Cash Flow Hedges:
Commodity Hedges (c)		8		30		-		(17	)		21
Interest Rate/Foreign Currency Hedges		-		1		-		-			1
Fair Value Hedges		-		8		-		-			8
Dedesignated Risk Management Contracts (d)		-		-		-		36			36
Total Risk Management Assets		25		1,045		113		(667	)		516
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)		-		5		-		12			17
Fixed Income Securities:
United States Government		-		484		-		-			484
Corporate Debt		-		57		-		-			57
State and Local Government		-		338		-		-			338
Subtotal Fixed Income Securities		-		879		-		-			879
Equity Securities - Domestic (b)		678		-		-		-			678
Total Spent Nuclear Fuel and Decommissioning Trusts		678		884		-		12			1,574
Total Assets	$	1,149	$	1,950	$	113	$	(394	)	$	2,818
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (f)	$	20	$	882	$	36	$	(725	)	$	213
Cash Flow Hedges:
Commodity Hedges (c)		2		17		-		(17	)		2
Interest Rate/Foreign Currency Hedges		-		3		-		-			3
Total Risk Management Liabilities	$	22	$	902	$	36	$	(742	)	$	218

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Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2010
	Level 1		Level 2		Level 3		Other			Total
Assets:	(in millions)
Cash and Cash Equivalents (a)	$	170	$	-	$	-	$	124		$	294
Other Temporary Investments
Restricted Cash (a)		184		-		-		41			225
Fixed Income Securities:
Mutual Funds		69		-		-		-			69
Variable Rate Demand Notes		-		97		-		-			97
Equity Securities - Mutual Funds (b)		25		-		-		-			25
Total Other Temporary Investments		278		97		-		41			416
Risk Management Assets
Risk Management Commodity Contracts (c) (g)		20		1,432		112		(1,013	)		551
Cash Flow Hedges:
Commodity Hedges (c)		11		17		-		(15	)		13
Interest Rate/Foreign Currency Hedges		-		25		-		-			25
Fair Value Hedges		-		7		-		-			7
Dedesignated Risk Management Contracts (d)		-		-		-		46			46
Total Risk Management Assets		31		1,481		112		(982	)		642
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (e)		-		8		-		12			20
Fixed Income Securities:
United States Government		-		461		-		-			461
Corporate Debt		-		59		-		-			59
State and Local Government		-		341		-		-			341
Subtotal Fixed Income Securities		-		861		-		-			861
Equity Securities - Domestic (b)		634		-		-		-			634
Total Spent Nuclear Fuel and Decommissioning Trusts		634		869		-		12			1,515
Total Assets	$	1,113	$	2,447	$	112	$	(805	)	$	2,867
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)	$	25	$	1,325	$	27	$	(1,114	)	$	263
Cash Flow Hedges:
Commodity Hedges (c)		4		13		-		(15	)		2
Interest Rate/Foreign Currency Hedges		-		4		-		-			4
Fair Value Hedges		-		1		-		-			1
Total Risk Management Liabilities	$	29	$	1,343	$	27	$	(1,129	)	$	270

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

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

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

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

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

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(f) The June 30, 2011 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 2011, $3 million in periods 2012-2014 and ($5) million in periods 2015-2018;  Level 2 matures $13 million in 2011, $75 million in periods 2012-2014, $18 million in periods 2015-2016 and $18 million in periods 2017-2028;  Level 3 matures $11 million in 2011, $25 million in periods 2012-2014, $15 million in periods 2015-2016 and $26 million in periods 2017-2028.  Risk management commodity contracts are substantially comprised of power contracts.

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

There were no transfers between Level 1 and Level 2 during the six months ended June 30, 2011 and 2010.

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

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

	Net Risk Management
Three Months Ended June 30, 2010	Assets (Liabilities)
	(in millions)
Balance as of March 31, 2010	$	116
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)		(25	)
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
Relating to Assets Still Held at the Reporting Date (a)		10
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		-
Purchases, Issuances and Settlements (c)		14
Transfers into Level 3 (d) (f)		1
Transfers out of Level 3 (e) (f)		(6	)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)		(10	)
Balance as of June 30, 2010	$	100

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

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	Net Risk Management
Six Months Ended June 30, 2010	Assets (Liabilities)
	(in millions)
Balance as of December 31, 2009	$	62
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)		4
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
Relating to Assets Still Held at the Reporting Date (a)		33
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		-
Purchases, Issuances and Settlements (c)		(13	)
Transfers into Level 3 (d) (f)		12
Transfers out of Level 3 (e) (f)		(5	)
Changes in Fair Value Allocated to Regulated Jurisdictions (g)		7
Balance as of June 30, 2010	$	100

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

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

10.  INCOME TAXES

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

We are no longer subject to U.S. federal examination for years before 2001.  We have completed the exam for the years 2001 through 2006 and have issues that we are pursuing at the appeals level.  In April 2011, the IRS’s examination of the years 2007 and 2008 was concluded with a settlement of all outstanding issues.  The settlement will not have a material impact on net income, cash flows or financial condition.  Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters.  In addition, we accrue interest on these uncertain tax positions.  We are not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on net income.

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

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

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Federal Tax Legislation

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

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

State Tax Legislation

Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rates from 8.5% to 6.5%.  The current 8.5% Indiana corporate income tax rate is scheduled for a 0.5% reduction each year beginning after June 30, 2012 with the final reduction occurring in years beginning after June 30, 2015.  In addition, Michigan repealed its Business Tax regime in May 2011 and replaced it with a traditional corporate net income tax with a rate of 6%.  The enacted provisions will not have a material impact on net income, cash flows or financial condition.

11.  FINANCING ACTIVITIES

Long-term Debt

Type of Debt	June 30, 2011			December 31, 2010
	(in millions)
Senior Unsecured Notes	$	11,750		$	11,669
Pollution Control Bonds		2,153			2,263
Notes Payable		347			396
Securitization Bonds		1,755			1,847
Junior Subordinated Debentures		315			315
Spent Nuclear Fuel Obligation (a)		265			265
Other Long-term Debt		92			91
Unamortized Discount (net)		(42	)		(35	)
Total Long-term Debt Outstanding		16,635			16,811
Less Portion Due Within One Year		1,071			1,309
Long-term Portion	$	15,564		$	15,502

(a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal.  The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983.  Trust fund assets related to this obligation were $307 million at June 30, 2011 and December 31, 2010, and 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 six months of 2011 are shown in the tables below:

			Principal			Interest
Company	Type of Debt		Amount			Rate	Due Date
Issuances:		(in millions)				(%)
APCo	Senior Unsecured Notes		$	350		4.60	2021
APCo	Pollution Control Bonds			65		2.00	2012
APCo	Pollution Control Bonds			75	(a)	Variable	2036
APCo	Pollution Control Bonds			54	(a)	Variable	2042
APCo	Pollution Control Bonds			50	(a)	Variable	2036
APCo	Pollution Control Bonds			50	(a)	Variable	2042
I&M	Pollution Control Bonds			52	(a)	Variable	2021
I&M	Pollution Control Bonds			25	(a)	Variable	2019
OPCo	Pollution Control Bonds			50	(a)	Variable	2014
PSO	Senior Unsecured Notes			250		4.40	2021
PSO	Notes Payable			2		3.00	2026
TCC	Pollution Control Bonds			60	(a)	1.125	2012
Total Issuances			$	1,083	(b)

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

(b) Amount indicated on the statement of cash flows of $1,074 million is net of issuance costs and premium or discount.

			Principal		Interest
Company	Type of Debt		Amount Paid		Rate	Due Date
Retirements and		(in millions)			(%)
Principal Payments:
APCo	Pollution Control Bonds		$	75	Variable	2036
APCo	Pollution Control Bonds			54	Variable	2042
APCo	Pollution Control Bonds			50	Variable	2042
APCo	Pollution Control Bonds			50	Variable	2036
APCo	Senior Unsecured Notes			250	5.55	2011
I&M	Pollution Control Bonds			52	Variable	2021
I&M	Pollution Control Bonds			25	Variable	2019
I&M	Notes Payable			13	5.16	2014
I&M	Notes Payable			15	5.44	2013
I&M	Notes Payable			11	Variable	2015
OPCo	Pollution Control Bonds			65	Variable	2036
OPCo	Pollution Control Bonds			50	Variable	2014
OPCo	Pollution Control Bonds			50	Variable	2014
PSO	Senior Unsecured Notes			200	6.00	2032
PSO	Senior Unsecured Notes			75	4.70	2011
Non-Registrant:
AEP Subsidiaries	Notes Payable			5	Variable	2017
AEP Subsidiaries	Notes Payable			6	Variable	2011
AEGCo	Senior Unsecured Notes			4	6.33	2037
TCC	Securitization Bonds			34	5.96	2013
TCC	Securitization Bonds			58	4.98	2013
TCC	Pollution Control Bonds			121	5.125	2011
Total Retirements and
Principal Payments			$	1,263

In July 2011, SWEPCo retired $41 million of 4.5% Pollution Control Bonds due in 2011.

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In July 2011, AEGCo remarketed $45 million of variable rate Pollution Control Bonds which may be tendered for purchase at the option of the holder.  The Pollution Control Bonds are supported by letters of credit, which expire in 2014.

In July 2011, I&M retired $2 million of Notes Payable related to DCC Fuel.

As of June 30, 2011, trustees held, on our behalf, $478 million of our reacquired Pollution Control Bonds.

Dividend Restrictions

Parent Restrictions

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

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

We have issued $315 million of Junior Subordinated Debentures.  The debentures will mature on March 1, 2063, subject to extensions to no later than March 1, 2068, and are callable at par any time on or after March 1, 2013.  We have the option to defer interest payments on the debentures for one or more periods of up to 10 consecutive years per period.  During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire our common stock.  We do not anticipate any deferral of those interest payments in the foreseeable future.

Utility Subsidiaries’ Restrictions

Various charter provisions and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.

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

Short-term Debt
Our outstanding short-term debt was as follows:
	June 30, 2011					December 31, 2010
	Outstanding		Interest			Outstanding		Interest
Type of Debt	Amount		Rate (a)			Amount		Rate (a)
	(in millions)					(in millions)
Securitized Debt for Receivables (b)	$	695		0.23	%	$	690		0.31	%
Commercial Paper		944		0.41	%		650		0.52	%
Line of Credit – Sabine Mining Company (c)		-		-	%		6		2.15	%
Total Short-term Debt	$	1,639				$	1,346

(a) Weighted average rate.

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

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

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Credit Facilities

We have two $1.5 billion credit facilities, under which we may issue up to $1.35 billion as letters of credit.  In July 2011, we replaced the $1.5 billion facility due in 2012 with a new $1.75 billion facility maturing in July 2016 and extended the $1.5 billion facility due in 2013 to expire in June 2015.  As of June 30, 2011, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $132 million.

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

Securitized Accounts Receivable – AEP Credit

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

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

Accounts receivable information for AEP Credit is as follows:

	Three Months Ended								Six Months Ended
	June 30,								June 30,
	2011				2010				2011				2010
	(dollars in millions)
Effective Interest Rates on Securitization of
Accounts Receivable			0.26	%			0.31	%			0.28	%			0.27	%
Net Uncollectible Accounts Receivable
Written Off		$	6			$	4			$	17			$	12

	June 30,		December 31,
	2011		2010
	(in millions)
Accounts Receivable Retained Interest and Pledged as Collateral
Less Uncollectible Accounts	$	1,001	$	923
Total Principal Outstanding		695		690
Delinquent Securitized Accounts Receivable		39		50
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable		22		26
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable		413		354

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

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12.  COST REDUCTION INITIATIVES

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

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

The following table shows the cost reduction activity for the six months ended June 30, 2011:

	Total
	(in millions)
Balance as of December 31, 2010	$	17
Incurred		-
Settled		(9	)
Adjustments		(2	)
Balance as of June 30, 2011	$	6

The remaining accruals are included primarily in Other Current Liabilities on the Condensed Consolidated Balance Sheets.

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APPALACHIAN POWER COMPANY

AND SUBSIDIARIES

80

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Regulatory Activity

Virginia Regulatory Activity

In March 2011, APCo filed a generation and distribution base rate request with the Virginia SCC to increase annual base rates by $126 million based upon an 11.65% return on common equity to be effective no later than February 2012.  The return on common equity includes a requested 0.5% renewable portfolio standards incentive as allowed by law.APCo proposed to mitigate the requested base rate increase by $51 million by maintaining current depreciation rates until the next biennial filing.  If approved, APCo’s net base rate increase would be $75 million.  In July 2011, an Attorney General witness recommended an $80 million reduction in APCo’s requested rate year capacity charges.    See “2011 Virginia Biennial Base Rate Case” section of Note 3.

West Virginia Regulatory Activity

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

In a November 2009 proceeding established by the WVPSC to explore options to meet WPCo's future power supply requirements, the WVPSC issued an order approving a joint stipulation among APCo, WPCo, the WVPSC staff and the Consumer Advocate Division.  The order approved the recommendation of the signatories to the stipulation that WPCo merge into APCo and be supplied from APCo's existing power resources.  Merger approvals from the WVPSC, 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 Product Validation Facility (PVF)

APCo and ALSTOM Power, Inc., an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009.  APCo also constructed and owns the necessary facilities to store the CO2.  In May 2011, the PVF ended operations and decommissioning of the facility began.

In APCo’s May 2010 West Virginia base rate filing, APCo requested rate base treatment of the PVF including recovery of the related asset retirement obligation regulatory asset amortization and accretion.  In March 2011, a WVPSC order denied the request for rate base treatment of the PVF largely due to its experimental operation.  The base rate order provided that should APCo construct a commercial scale carbon capture and sequestration (CCS) facility, only the West Virginia portion of the PVF costs, based on load sharing among certain AEP operating companies, may be considered used and useful plant in service and included in future rate base.  As a result, APCo recorded a pretax write-off of $41 million ($26 million net of tax) in the first quarter of 2011.  As of June 30, 2011, APCo has recorded a noncurrent regulatory asset of $19 million related to the PVF.  If APCo cannot recover its remaining PVF investment and related accretion expenses, it would reduce future net income and cash flows.  See “Mountaineer Carbon Capture and Storage Project” section of Note 3.

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

During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale CCS facility at the Mountaineer Plant.  AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project.  The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million.  In July 2011, management informed the DOE that it will complete

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a Front-End Engineering and Design study during the third quarter of 2011, but it is postponing any further CCS project activities because of the uncertainty about the regulation of CO2.  As of June 30, 2011, the project has incurred $30 million in total costs and has received $10 million of DOE eligible funding resulting in a $20 million net balance recorded in the Condensed Consolidated Balance Sheets.  Requests for recovery are in process in Michigan, Ohio and Virginia.  If the allocated costs of the CCS project cannot be recovered, it would reduce future net income and cash flows.  See “Mountaineer Carbon Capture and Storage Project” section of Note 3.

Proposed Acquisition of Dresden Plant

During the first quarter of 2011, APCo and AEGCo filed with the Virginia and West Virginia regulatory commissions seeking approval for APCo’s purchase of the partially completed Dresden Plant from AEGCo at cost.    In June 2011 and July 2011, the WVPSC and the Virginia SCC, respectively, issued orders approving the acquisition.  The transfer must also be approved by the Ohio Power Siting Board.  Management expects approval from the Ohio Power Siting Board allowing the transfer to occur in the third quarter of 2011.  The Dresden Plant is located near Dresden, Ohio and is a natural gas, combined cycle power plant.  AEGCo resumed construction in the first quarter of 2011 following a suspension in 2009 due to economic conditions.  When completed, the Dresden Plant will have a generating capacity of 580 MW.

Litigation and Environmental Issues

In the ordinary course of business, APCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2010 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 162.  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 227 for additional discussion of relevant factors.

RESULTS OF OPERATIONS
KWH Sales/Degree Days
Summary of KWH Energy Sales
		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2011		2010		2011		2010
		(in millions of KWH)
Retail:
	Residential		2,367		2,291		6,326		6,820
	Commercial		1,696		1,750		3,394		3,536
	Industrial		2,699		2,722		5,318		5,186
	Miscellaneous		204		213		414		435
Total Retail			6,966		6,976		15,452		15,977
Wholesale			2,336		1,416		4,163		3,119
Total KWHs			9,302		8,392		19,615		19,096

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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.

Summary of Heating and Cooling Degree Days
		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2011		2010		2011		2010
		(in degree days)
Actual - Heating (a)			56		34		1,387		1,611
Normal - Heating (b)			100		101		1,437		1,440
Actual - Cooling (c)			464		540		470		540
Normal - Cooling (b)			348		342		354		348
(a)	Eastern Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.
(c)	Eastern Region cooling degree days are calculated on a 65 degree temperature base.

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Second Quarter of 2011 Compared to Second Quarter of 2010

Reconciliation of Second Quarter of 2010 to Second Quarter of 2011
Net Income (Loss)
(in millions)
Second Quarter of 2010	$	(20	)
Changes in Gross Margin:
Retail Margins		10
Off-system Sales		3
Transmission Revenue		4
Total Change in Gross Margin		17
Changes in Expenses and Other:
Other Operation and Maintenance		53
Depreciation and Amortization		6
Taxes Other Than Income Taxes		4
Carrying Costs Income		(4	)
Other Income		1
Interest Expense		(1	)
Total Change in Expenses and Other		59
Income Tax Expense		(24	)
Second Quarter of 2011	$	32

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 $10 million primarily due to the following:
	·	A $27 million increase due to higher base rates in Virginia and West Virginia.
	·	A $6 million increase due to lower capacity settlement expenses under the Interconnection Agreement net of recovery in West Virginia and environmental deferrals in Virginia.
	These increases were partially offset by:
	·	A $21 million decrease due to the expiration of E&R cost recovery in Virginia.
	·	A $3 million decrease in weather-related usage primarily due to a 14% decrease in cooling degree days.
·	Margins from Off-system Sales increased $3 million primarily due to higher physical sales volumes.
·	Transmission Revenue increased $4 million primarily due to the Transmission Agreement modification effective November 2010.

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

·	Other Operation and Maintenance expenses decreased $53 million primarily due to the following:
	·	A $55 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
	·	A $54 million decrease due to the second quarter 2010 write-off of the Virginia share of the Mountaineer Carbon Capture and Storage Project Product Validation Facility as denied for recovery by the Virginia SCC.
	These decreases were partially offset by:
	·	A $25 million increase due to the second quarter 2010 deferral of 2009 storm costs as allowed by the Virginia SCC.
	·	An $18 million increase in storm-related expenses.
	·	A $5 million increase in transmission expenses primarily due to the Transmission Agreement modification effective November 2010.
·	Depreciation and Amortization expenses decreased $6 million primarily due to the expiration of E&R amortization of deferred carrying costs in Virginia, partially offset by an increased depreciation base resulting from environmental upgrades at the Amos Plant.
·	Taxes Other Than Income Taxes decreased $4 million primarily due to recording a West Virginia franchise tax audit settlement and additional employer payroll taxes incurred related to the cost reduction initiatives in the second quarter of 2010.
·	Carrying Costs Income decreased $4 million primarily due to decreased environmental deferrals in Virginia.
·	Income Tax Expense increased $24 million primarily due to an increase in pretax book income.

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Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Reconciliation of Six Months Ended June 30, 2010 to Six Months Ended June 30, 2011
Net Income (Loss)
(in millions)
Six Months Ended June 30, 2010	$	51
Changes in Gross Margin:
Retail Margins		(50)
Off-system Sales		5
Transmission Revenue		6
Other Revenues		(1)
Total Change in Gross Margin		(40)
Changes in Expenses and Other:
Other Operation and Maintenance		61
Depreciation and Amortization		14
Taxes Other Than Income Taxes		3
Carrying Costs Income		(6)
Other Income		1
Interest Expense		(3)
Total Change in Expenses and Other		70
Income Tax Expense		(10)
Six Months Ended June 30, 2011	$	71

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

·	Retail Margins decreased $50 million primarily due to the following:
	·	A $37 million decrease due to the expiration of E&R cost recovery in Virginia.
	·	A $22 million decrease in variable electric generation expenses.
	·	A $19 million decrease in weather-related usage primarily due to a 14% decrease in heating degree days and a 13% decrease in cooling degree days.
	·	A $10 million decrease in residential and commercial margins primarily due to lower non-weather related usage.
	These decreases were partially offset by:
	·	A $27 million increase due to lower capacity settlement expenses under the Interconnection Agreement net of recovery in West Virginia and environmental deferrals in Virginia.
	·	A $27 million increase due to higher base rates in Virginia and West Virginia.
·	Margins from Off-system Sales increased $5 million primarily due to higher physical sales volumes and higher trading and marketing margins.
·	Transmission Revenue increased $6 million primarily due to the Transmission Agreement modification effective November 2010.

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

·	Other Operation and Maintenance expenses decreased $61 million primarily due to the following:
	·	A $55 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
	·	A $54 million decrease due to the second quarter 2010 write-off of the Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the Virginia SCC.
	·	A $32 million decrease due to the first quarter 2011 deferral of 2010 storm costs and costs related to 2010 cost reduction initiatives.  These costs were deferred as a result of the approved modified settlement agreement of APCo’s West Virginia base rate case in March 2011.
	These decreases were partially offset by:
	·	A $41 million increase due to the first quarter 2011 write-off of a portion of the West Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC.
	·	A $25 million increase due to the second quarter 2010 deferral of 2009 storm costs as allowed by the Virginia SCC.
	·	A $15 million increase in storm-related expenses.
	·	An $8 million increase in transmission expenses primarily due to the Transmission Agreement modification effective November 2010.
·	Depreciation and Amortization expenses decreased $14 million primarily due to the expiration of E&R amortization of deferred carrying costs in Virginia, partially offset by an increased depreciation base resulting from environmental upgrades at the Amos Plant.
·	Taxes Other Than Income Taxes decreased $3 million primarily due to recording a West Virginia franchise tax audit settlement and additional employer payroll taxes incurred related to the cost reduction initiatives in the second quarter of 2010.
·	Carrying Costs Income decreased $6 million primarily due to decreased environmental deferrals in Virginia.
·	Income Tax Expense increased $10 million primarily due to an increase in pretax book income.

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 227 for additional discussion of liquidity.

Credit Ratings

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

87

CASH FLOW

Cash flows for the six months ended June 30, 2011 and 2010 were as follows:

	2011			2010
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	951		$	2,006
Net Cash Flows from Operating Activities		386,198			252,172
Net Cash Flows Used for Investing Activities		(346,080	)		(252,171	)
Net Cash Flows Used for Financing Activities		(39,437	)		(181	)
Net Increase (Decrease) in Cash and Cash Equivalents		681			(180	)
Cash and Cash Equivalents at End of Period	$	1,632		$	1,826

Operating Activities

Net Cash Flows from Operating Activities were $386 million in 2011.  APCo produced Net Income of $71 million during the period and had noncash expense items of $137 million for Depreciation and Amortization and $128 million for Deferred Income Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a number of items.  The $85 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 $85 million inflow from Fuel, Materials and Supplies was primarily due to a reduction in fuel.  The $63 million outflow from Accounts Payable was primarily due to decreased energy purchases and reduced operation and maintenance expenses.  The $56 million outflow from Accrued Taxes, Net was primarily due to decreased accruals related to federal income taxes.

Net Cash Flows from Operating Activities were $252 million in 2010.  APCo produced Net Income of $51 million during the period and had noncash expense items of $151 million for Depreciation and Amortization and $32 million for Deferred Income Taxes.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a number of items.  The $100 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 $76 million inflow from Accounts Receivable, Net was primarily due to a decrease in accrued revenues due to usual seasonal fluctuations and timing of settlements of receivables from affiliated companies.  The $69 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 $39 million outflow from Accrued Taxes, Net was primarily due to decreased accruals related to federal income taxes.  The $32 million outflow from Fuel Over/Under-Recovery, Net was primarily due to a net under-recovery of fuel costs in West Virginia.

Investing Activities

Net Cash Flows Used for Investing Activities during 2011 and 2010 were $346 million and $252 million, respectively.  Construction Expenditures of $191 million and $255 million in 2011 and 2010, respectively, were primarily for environmental upgrades, as well as projects to improve generation and service reliability for transmission and distribution.  Environmental upgrades include FGD projects at the Amos Plant.  During 2011, APCo had a net increase of $163 million in loans to the Utility Money Pool.

Financing Activities

Net Cash Flows Used for Financing Activities were $39 million in 2011.  APCo issued $350 million of Senior Unsecured Notes and $295 million of Pollution Control Bonds, partially offset by the retirement of $250 million of Senior Unsecured Notes and $230 million of Pollution Control Bonds.  APCo had a net decrease of $128 million in borrowings from the Utility Money Pool.  In addition, APCo paid $68 million in common stock dividends.

88

Net Cash Flows Used for Financing Activities were $181 thousand in 2010.  APCo issued $300 million of Senior Unsecured Notes and $68 million of Pollution Control Bonds, partially offset by the retirement of $150 million of Senior Unsecured Notes, $100 million of Notes Payable – Affiliated and $50 million of Pollution Control Bonds. APCo had a net increase of $17 million in borrowings from the Utility Money Pool.  In addition, APCo paid $78 million in common stock dividends.

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

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

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

Retirements and Principal Payments
		Principal		Interest	Due
	Type of Debt	Amount Paid		Rate	Date
		(in thousands)		(%)
	Pollution Control Bonds	$	75,000	Variable	2036
	Pollution Control Bonds		50,275	Variable	2036
	Pollution Control Bonds		54,375	Variable	2042
	Pollution Control Bonds		50,000	Variable	2042
	Senior Unsecured Notes		250,000	5.55	2011
	Land Note		11	13.718	2026

CONTRACTUAL OBLIGATION INFORMATION

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of market risk.

89

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three and Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
	Three Months Ended						Six Months Ended
	2011			2010			2011			2010
REVENUES
Electric Generation, Transmission and Distribution	$	666,785		$	633,140		$	1,417,797		$	1,479,130
Sales to AEP Affiliates		82,531			67,365			161,222			146,136
Other Revenues		2,129			2,769			4,246			4,631
TOTAL REVENUES		751,445			703,274			1,583,265			1,629,897
EXPENSES
Fuel and Other Consumables Used for Electric Generation		184,698			169,616			365,279			350,256
Purchased Electricity for Resale		69,127			56,936			138,345			120,619
Purchased Electricity from AEP Affiliates		183,661			179,607			407,850			447,109
Other Operation		74,617			170,907			187,893			260,947
Maintenance		57,163			14,060			89,456			77,170
Depreciation and Amortization		67,644			73,160			136,743			150,590
Taxes Other Than Income Taxes		25,968			29,955			53,071			56,235
TOTAL EXPENSES		662,878			694,241			1,378,637			1,462,926
OPERATING INCOME		88,567			9,033			204,628			166,971
Other Income (Expense):
Interest Income		762			662			1,082			953
Carrying Costs Income		6,542			10,298			9,981			16,062
Allowance for Equity Funds Used During Construction		1,212			128			2,095			1,291
Interest Expense		(53,188	)		(51,831	)		(106,127	)		(103,558	)
INCOME (LOSS) BEFORE INCOME TAX EXPENSE
(CREDIT)		43,895			(31,710	)		111,659			81,719
Income Tax Expense (Credit)		12,268			(12,091	)		41,052			31,056
NET INCOME (LOSS)		31,627			(19,619	)		70,607			50,663
Preferred Stock Dividend Requirements Including Capital
StockExpense		200			225			400			450
EARNINGS (LOSS) ATTRIBUTABLE TO COMMON
STOCK	$	31,427		$	(19,844	)	$	70,207		$	50,213
The common stock of APCo is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

90

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
										Accumulated
										Other
				Common		Paid-in		Retained		Comprehensive
				Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2009			$	260,458	$	1,475,393	$	1,085,980	$	(50,254)	$	2,771,577
Common Stock Dividends									(78,000)				(78,000)
Preferred Stock Dividends									(399)				(399)
Capital Stock Expense							52		(51)				1
SUBTOTAL – COMMON
	SHAREHOLDER'S EQUITY												2,693,179
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
	Taxes:
		Cash Flow Hedges, Net of Tax of $1,369									(2,542)		(2,542)
		Amortization of Pension and OPEB Deferred
			Costs, Net of Tax of $1,124								2,087		2,087
NET INCOME									50,663				50,663
TOTAL COMPREHENSIVE INCOME													50,208
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2010			$	260,458	$	1,475,445	$	1,058,193	$	(50,709)	$	2,743,387
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2010			$	260,458	$	1,475,496	$	1,133,748	$	(48,023)	$	2,821,679
Common Stock Dividends									(67,500)				(67,500)
Preferred Stock Dividends									(400)				(400)
Gain on Reacquired Preferred Stock							3						3
SUBTOTAL – COMMON
	SHAREHOLDER'S EQUITY												2,753,782
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
		Cash Flow Hedges, Net of Tax of $652									1,211		1,211
		Amortization of Pension and OPEB Deferred
			Costs, Net of Tax of $837								1,554		1,554
NET INCOME									70,607				70,607
TOTAL COMPREHENSIVE INCOME													73,372
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2011			$	260,458	$	1,475,499	$	1,136,455	$	(45,258)	$	2,827,154
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

91

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2011 and December 31, 2010
(in thousands)
(Unaudited)
			2011		2010
CURRENT ASSETS
Cash and Cash Equivalents			$	1,632	$	951
Advances to Affiliates				162,787		-
Accounts Receivable:
	Customers			179,695		166,878
	Affiliated Companies			107,225		145,972
	Accrued Unbilled Revenues			52,705		108,210
	Miscellaneous			2,961		3,090
	Allowance for Uncollectible Accounts			(6,839)		(6,667)
		Total Accounts Receivable		335,747		417,483
Fuel				142,478		230,697
Materials and Supplies				92,140		89,370
Risk Management Assets				31,814		53,242
Accrued Tax Benefits				127,008		104,435
Regulatory Asset for Under-Recovered Fuel Costs				19,287		18,300
Prepayments and Other Current Assets				29,672		35,811
TOTAL CURRENT ASSETS				942,565		950,289
PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			5,103,051		4,736,150
	Transmission			1,889,841		1,852,415
	Distribution			2,779,289		2,740,752
Other Property, Plant and Equipment				351,076		348,013
Construction Work in Progress				241,339		562,280
Total Property, Plant and Equipment				10,364,596		10,239,610
Accumulated Depreciation and Amortization				2,927,174		2,843,087
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				7,437,422		7,396,523
OTHER NONCURRENT ASSETS
Regulatory Assets				1,506,936		1,486,625
Long-term Risk Management Assets				32,146		38,420
Deferred Charges and Other Noncurrent Assets				119,618		125,296
TOTAL OTHER NONCURRENT ASSETS				1,658,700		1,650,341
TOTAL ASSETS			$	10,038,687	$	9,997,153
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

92

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
June 30, 2011 and December 31, 2010
(Unaudited)
		2011		2010
			(in thousands)
CURRENT LIABILITIES
Advances from Affiliates		$	-	$	128,331
Accounts Payable:
	General		173,512		223,144
	Affiliated Companies		134,238		166,884
Long-term Debt Due Within One Year – Nonaffiliated			229,673		479,672
Risk Management Liabilities			18,502		27,993
Customer Deposits			60,488		58,451
Deferred Income Taxes			36,934		44,180
Accrued Taxes			70,043		75,619
Accrued Interest			59,130		57,871
Other Current Liabilities			96,315		93,286
TOTAL CURRENT LIABILITIES			878,835		1,355,431
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			3,496,213		3,081,469
Long-term Risk Management Liabilities			10,328		10,873
Deferred Income Taxes			1,756,479		1,642,072
Regulatory Liabilities and Deferred Investment Tax Credits			566,314		562,381
Employee Benefits and Pension Obligations			284,578		306,460
Deferred Credits and Other Noncurrent Liabilities			201,050		199,041
TOTAL NONCURRENT LIABILITIES			6,314,962		5,802,296
TOTAL LIABILITIES			7,193,797		7,157,727
Cumulative Preferred Stock Not Subject to Mandatory Redemption			17,736		17,747
Rate Matters (Note 3)
Commitments and Contingencies (Note 4)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
	Authorized – 30,000,000 Shares
	Outstanding  – 13,499,500 Shares		260,458		260,458
Paid-in Capital			1,475,499		1,475,496
Retained Earnings			1,136,455		1,133,748
Accumulated Other Comprehensive Income (Loss)			(45,258)		(48,023)
TOTAL COMMON SHAREHOLDER’S EQUITY			2,827,154		2,821,679
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$	10,038,687	$	9,997,153
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

93

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
				2011		2010
OPERATING ACTIVITIES
Net Income				$	70,607	$	50,663
Adjustments to Reconcile Net Income to Net Cash Flows from
	Operating Activities:
		Depreciation and Amortization			136,743		150,590
		Deferred Income Taxes			127,525		32,037
		Carrying Costs Income			(9,981)		(16,062)
		Allowance for Equity Funds Used During Construction			(2,095)		(1,291)
		Mark-to-Market of Risk Management Contracts			7,343		9,975
		Fuel Over/Under-Recovery, Net			(21,132)		(32,329)
		Change in Other Noncurrent Assets			11,361		42,141
		Change in Other Noncurrent Liabilities			5,239		(5,225)
		Changes in Certain Components of Working Capital:
			Accounts Receivable, Net		84,748		75,903
			Fuel, Materials and Supplies		85,449		69,469
			Accounts Payable		(62,795)		(100,171)
			Accrued Taxes, Net		(56,411)		(38,806)
			Other Current Assets		6,281		5,421
			Other Current Liabilities		3,316		9,857
Net Cash Flows from Operating Activities					386,198		252,172
INVESTING ACTIVITIES
Construction Expenditures					(191,125)		(254,663)
Change in Advances to Affiliates, Net					(162,787)		-
Other Investing Activities					7,832		2,492
Net Cash Flows Used for Investing Activities					(346,080)		(252,171)
FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated					640,164		363,913
Change in Advances from Affiliates, Net					(128,331)		17,327
Retirement of Long-term Debt – Nonaffiliated					(479,661)		(200,009)
Retirement of Long-term Debt – Affiliated					-		(100,000)
Retirement of Cumulative Preferred Stock					(8)		(4)
Principal Payments for Capital Lease Obligations					(3,720)		(3,600)
Dividends Paid on Common Stock					(67,500)		(78,000)
Dividends Paid on Cumulative Preferred Stock					(400)		(399)
Other Financing Activities					19		591
Net Cash Flows Used for Financing Activities					(39,437)		(181)
Net Increase (Decrease) in Cash and Cash Equivalents					681		(180)
Cash and Cash Equivalents at Beginning of Period					951		2,006
Cash and Cash Equivalents at End of Period				$	1,632	$	1,826
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts				$	100,127	$	103,271
Net Cash Paid (Received) for Income Taxes					(33,371)		30,259
Noncash Acquisitions Under Capital Leases					565		22,344
Government Grants Included in Accounts Receivable at June 30,					4,061		-
Construction Expenditures Included in Current Liabilities at June 30,					52,421		42,890
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

94

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

INDEX OF 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 162.

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

95

COLUMBUS SOUTHERN POWER COMPANY

AND SUBSIDIARIES

96

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Ohio Customer Choice

In CSPCo’s service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service.  As a result, in comparison to the second quarter of 2010 and the first six months of 2010, CSPCo lost approximately $22 million and $40 million, respectively, of generation related gross margin.  Management anticipates recovery of a portion of lost margins through off-system sales, including PJM capacity revenues.

Regulatory Activity

2009 – 2011 ESPs

In April 2011, the Supreme Court of Ohio issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged which resulted in three reversals, only two of which may have a prospective impact through a remand proceeding.  Pursuant to a May 2011 PUCO order, CSPCo implemented rates subject to refund.  Certain intervenors proposed adjustments that included a reduction of deferred FAC and other regulatory assets for the period prior to June 2011 of up to $298 million, excluding carrying costs, which CSPCo believes is without merit and violates the Supreme Court of Ohio decision.  The proposed adjustments also included refunds and rate reductions of related revenues beginning in June 2011 of up to $72 million.  See “Ohio Electric Security Plan Filings” section of Note 3.

January 2012 – May 2014 ESP

In January 2011, CSPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation.  The rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  The SSO presents redesigned generation rates by customer class.  Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013.  Under the new ESP, management estimates CSPCo will have base generation revenue increases, excluding riders, of $17 million for 2012 and $46 million for 2013.  The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESPs could impact the outcome of the January 2012-May 2014 ESP, though the nature and extent of that impact is not presently known.  See “Ohio Electric Security Plan Filings” section of Note 3.

Ohio Distribution Base Rate Case

In February 2011, CSPCo filed with the PUCO for annual increases in distribution rates of $34 million.  The requested increase is based upon an 11.15% return on common equity to be effective January 2012.  In addition to the annual increase, CSPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets of $216 million, including approximately $102 million of unrecognized equity carrying costs.  These assets and unrecognized carrying costs would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013.  The actual balance of these distribution regulatory assets as of June 30, 2011 was $100 million, excluding $61 million of unrecognized equity carrying costs.  If CSPCo is not ultimately permitted to fully recover its deferrals, it would reduce future net income and cash flows and impact financial condition.  See “2011 Ohio Distribution Base Rate Case” section of Note 3.

97

Proposed CSPCo and OPCo Merger

In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo.  Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company.  In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo.  CSPCo and OPCo requested the reorganization transaction be effective in October 2011.  In July 2011, the FERC issued an order approving the proposed merger.  A decision is pending from the PUCO.  See “Proposed CSPCo and OPCo Merger” section of Note 3.

Litigation and Environmental Issues

In the ordinary course of business, CSPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2010 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 162.  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 227 for additional discussion of relevant factors.

RESULTS OF OPERATIONS
KWH Sales/Degree Days
Summary of KWH Energy Sales
		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2011		2010		2011		2010
		(in millions of KWH)
Retail:
	Residential		1,594		1,567		3,722		3,793
	Commercial		2,118		2,213		4,113		4,214
	Industrial		1,359		1,157		2,629		2,268
	Miscellaneous		13		14		28		27
Total Retail			5,084		4,951		10,492		10,302
Wholesale			1,178		637		2,041		1,356
Total KWHs			6,262		5,588		12,533		11,658

98

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.

Summary of Heating and Cooling Degree Days
		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2011		2010		2011		2010
		(in degree days)
Actual - Heating (a)			122		70		2,050		2,035
Normal - Heating (b)			164		165		1,947		1,950
Actual - Cooling (c)			369		430		370		430
Normal - Cooling (b)			299		293		302		296
(a)	Eastern Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.
(c)	Eastern Region cooling degree days are calculated on a 65 degree temperature base.

99

Second Quarter of 2011 Compared to Second Quarter of 2010

Reconciliation of Second Quarter of 2010 to Second Quarter of 2011
Net Income
(in millions)
Second Quarter of 2010	$	52
Changes in Gross Margin:
Retail Margins		(30	)
Off-system Sales		19
Transmission Revenues		1
Total Change in Gross Margin		(10	)
Changes in Expenses and Other:
Other Operation and Maintenance		31
Other Income		1
Interest Expense		1
Total Change in Expenses and Other		33
Income Tax Expense		(8	)
Second Quarter of 2011	$	67

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

·	Retail Margins decreased $30 million due to the following:
	·	A $22 million decrease attributable to customers switching to alternative competitive retail electric service (CRES) providers.
	·	A $6 million decrease in residential and industrial margins primarily due to a change in the customer mix resulting in lower realizations.
	·	A $5 million decrease in weather-related usage due to a 14% decrease in cooling degree days.
	These decreases were partially offset by:
	·	A $7 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Energy Efficiency & Peak Demand Reduction (EE/PDR) Programs.  This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
·	Margins from Off-system Sales increased $19 million primarily due to an increase in PJM capacity revenues and higher physical sales volumes.

100

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

·	Other Operation and Maintenance expenses decreased $31 million primarily due to:
	·	A $31 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
	·	An $8 million decrease in transmission expense primarily due to the Transmission Agreement modification effective November 2010, a portion of which is included in the Ohio Transmission Cost Recovery Rider.
	These decreases were partially offset by:
	·	A $7 million increase in expenses due to the implementation of PUCO approved EE/PDR programs.  This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
	·	A $7 million increase in plant maintenance expenses primarily related to work performed at the Stuart, Waterford and Conesville plants.
·	Income Tax Expense increased $8 million primarily due to an increase in pretax book income.

101

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Reconciliation of Six Months Ended June 30, 2010 to Six Months Ended June 30, 2011
Net Income
(in millions)
Six Months Ended June 30, 2010	$	104
Changes in Gross Margin:
Retail Margins		(20)
Off-system Sales		32
Transmission Revenues		1
Other Revenues		(1)
Total Change in Gross Margin		12
Changes in Expenses and Other:
Other Operation and Maintenance		32
Depreciation and Amortization		(4)
Taxes Other Than Income Taxes		(3)
Other Income		2
Interest Expense		3
Total Change in Expenses and Other		30
Income Tax Expense		(14)
Six Months Ended June 30, 2011	$	132

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 decreased $20 million primarily due to:
	·	A $40 million decrease attributable to customers switching to alternative competitive retail electric service (CRES) providers.
	·	A $6 million decrease in weather-related usage due to a 14% decrease in cooling degree days.
	·	A $3 million decrease in capacity settlements under the Interconnection Agreement.
	These decreases were partially offset by:
	·	A $19 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Energy Efficiency & Peak Demand Reduction (EE/PDR) Programs.  This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
	·	A $10 million increase associated with the final 2009 SEET order.
·	Margins from Off-system Sales increased $32 million primarily due to an increase in PJM capacity revenues and higher physical sales volumes.

102

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

  · Other Operation and Maintenance expenses decreased $32 million primarily due to:

· A $31 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.

· A $15 million decrease in transmission expense primarily due to the Transmission Agreement modification effective November 2010, a portion of which is included in the Ohio Transmission Cost Recovery Rider.

· A $15 million decrease in recoverable PJM expenses.

	These decreases were partially offset by:
	·	A $19 million increase in expenses due to the implementation of PUCO approved EE/PDR programs.  This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
	·	A $14 million increase in plant maintenance and operation expenses primarily related to work performed at the Stuart, Waterford and Conesville plants.
·	Depreciation and Amortization increased $4 million as a result of recognizing deferred debt and equity carrying charges on deferred fuel as permitted under the final 2009 SEET order.
·	Taxes Other Than Income Taxes increased $3 million primarily due to an increase in property taxes.
·	Interest Expense decreased $3 million primarily as a result of a long-term debt retirement in December 2010.
·	Income Tax Expense increased $14 million primarily due to an increase in pretax book income.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of market risk.

103

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
	Three Months Ended				Six Months Ended
	2011		2010		2011		2010
REVENUES
Electric Generation, Transmission and Distribution	$	482,655	$	503,270	$	986,026	$	1,004,289
Sales to AEP Affiliates		38,421		20,090		79,146		35,922
Other Revenues		383		744		889		1,332
TOTAL REVENUES		521,459		524,104		1,066,061		1,041,543
EXPENSES
Fuel and Other Consumables Used for Electric Generation		93,760		105,290		206,673		219,731
Purchased Electricity for Resale		24,885		20,138		48,402		39,783
Purchased Electricity from AEP Affiliates		105,369		91,287		206,980		190,086
Other Operation		65,113		103,229		136,180		180,555
Maintenance		32,423		25,114		61,523		49,397
Depreciation and Amortization		37,531		37,602		78,957		75,089
Taxes Other Than Income Taxes		44,128		44,294		94,277		91,351
TOTAL EXPENSES		403,209		426,954		832,992		845,992
OPERATING INCOME		118,250		97,150		233,069		195,551
Other Income (Expense):
Interest Income		183		167		350		309
Carrying Costs Income		2,268		1,963		5,922		4,184
Allowance for Equity Funds Used During Construction		547		314		1,318		1,235
Interest Expense		(20,201)		(21,091)		(39,949)		(42,875)
INCOME BEFORE INCOME TAX EXPENSE		101,047		78,503		200,710		158,404
Income Tax Expense		34,519		26,387		68,624		54,638
NET INCOME		66,528		52,116		132,086		103,766
Capital Stock Expense		25		40		50		79
EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	66,503	$	52,076	$	132,036	$	103,687
The common stock of CSPCo is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

104

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
										Accumulated
										Other
				Common		Paid-in		Retained		Comprehensive
				Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2009			$	41,026	$	580,663	$	788,139	$	(49,993)	$	1,359,835
Common Stock Dividends									(52,500)				(52,500)
Capital Stock Expense							79		(79)				-
SUBTOTAL – COMMON
	SHAREHOLDER'S EQUITY												1,307,335
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of
	Taxes:
		Cash Flow Hedges, Net of Tax of $232									(431)		(431)
		Amortization of Pension and OPEB Deferred
			Costs, Net of Tax of $667								1,238		1,238
NET INCOME									103,766				103,766
TOTAL COMPREHENSIVE INCOME													104,573
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2010			$	41,026	$	580,742	$	839,326	$	(49,186)	$	1,411,908
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2010			$	41,026	$	580,812	$	915,713	$	(51,336)	$	1,486,215
Common Stock Dividends									(125,000)				(125,000)
Capital Stock Expense							50		(50)				-
SUBTOTAL – COMMON
	SHAREHOLDER'S EQUITY												1,361,215
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
		Cash Flow Hedges, Net of Tax of $265									492		492
		Amortization of Pension and OPEB Deferred
			Costs, Net of Tax of $688								1,278		1,278
NET INCOME									132,086				132,086
TOTAL COMPREHENSIVE INCOME													133,856
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2011			$	41,026	$	580,862	$	922,749	$	(49,566)	$	1,495,071
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

105

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2011 and December 31, 2010
(in thousands)
(Unaudited)
			2011		2010
CURRENT ASSETS
Cash and Cash Equivalents			$	1,295	$	509
Other Cash Deposits				2,260		2,260
Advances to Affiliates				71,323		54,202
Accounts Receivable:
	Customers			51,282		50,187
	Affiliated Companies			42,371		66,788
	Accrued Unbilled Revenues			5,657		32,821
	Miscellaneous			5,736		14,374
	Allowance for Uncollectible Accounts			(1,638)		(1,584)
		Total Accounts Receivable		103,408		162,586
Fuel				59,842		72,882
Materials and Supplies				41,409		42,033
Emission Allowances				25,272		28,486
Risk Management Assets				18,351		23,774
Accrued Tax Benefits				22,014		8,797
Regulatory Asset for Under-Recovered Fuel Costs				26,672		-
Margin Deposits				12,986		14,762
Prepayments and Other Current Assets				8,104		26,864
TOTAL CURRENT ASSETS				392,936		437,155
PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			2,725,375		2,686,294
	Transmission			676,863		662,312
	Distribution			1,820,031		1,796,023
Other Property, Plant and Equipment				204,858		203,593
Construction Work in Progress				149,955		172,793
Total Property, Plant and Equipment				5,577,082		5,521,015
Accumulated Depreciation and Amortization				1,989,614		1,927,112
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				3,587,468		3,593,903
OTHER NONCURRENT ASSETS
Regulatory Assets				313,651		298,111
Long-term Risk Management Assets				18,578		22,089
Deferred Charges and Other Noncurrent Assets				98,461		152,932
TOTAL OTHER NONCURRENT ASSETS				430,690		473,132
TOTAL ASSETS			$	4,411,094	$	4,504,190
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

106

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER'S EQUITY
June 30, 2011 and December 31, 2010
(Unaudited)
		2011		2010
			(in thousands)
CURRENT LIABILITIES
Accounts Payable:
	General	$	80,339	$	98,925
	Affiliated Companies		70,165		78,617
Long-term Debt Due Within One Year – Nonaffiliated			194,500		-
Risk Management Liabilities			10,668		15,967
Customer Deposits			30,652		29,441
Accrued Taxes			137,197		226,572
Accrued Interest			22,580		22,533
Other Current Liabilities			88,576		111,868
TOTAL CURRENT LIABILITIES			634,677		583,923
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			1,244,469		1,438,830
Long-term Risk Management Liabilities			5,964		6,223
Deferred Income Taxes			642,748		604,828
Regulatory Liabilities and Deferred Investment Tax Credits			168,346		163,888
Employee Benefits and Pension Obligations			133,149		136,643
Deferred Credits and Other Noncurrent Liabilities			86,670		83,640
TOTAL NONCURRENT LIABILITIES			2,281,346		2,434,052
TOTAL LIABILITIES			2,916,023		3,017,975
Rate Matters (Note 3)
Commitments and Contingencies (Note 4)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
	Authorized – 24,000,000 Shares
	Outstanding  – 16,410,426 Shares		41,026		41,026
Paid-in Capital			580,862		580,812
Retained Earnings			922,749		915,713
Accumulated Other Comprehensive Income (Loss)			(49,566)		(51,336)
TOTAL COMMON SHAREHOLDER’S EQUITY			1,495,071		1,486,215
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY		$	4,411,094	$	4,504,190
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

107

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
			2011		2010
OPERATING ACTIVITIES
Net Income			$	132,086	$	103,766
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			78,957		75,089
	Deferred Income Taxes			58,594		19,833
	Allowance for Equity Funds Used During Construction			(1,318)		(1,235)
	Mark-to-Market of Risk Management Contracts			4,206		1,466
	Property Taxes			57,078		48,526
	Fuel Over/Under-Recovery, Net			(12,072)		32,120
	Change in Other Noncurrent Assets			(24,713)		(17,051)
	Change in Other Noncurrent Liabilities			8,023		(2,458)
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		51,840		(17,458)
		Fuel, Materials and Supplies		16,424		(3,512)
		Accounts Payable		(19,262)		(12,744)
		Accrued Taxes, Net		(107,239)		(89,647)
		Other Current Assets		5,200		8,582
		Other Current Liabilities		(34,703)		12,262
Net Cash Flows from Operating Activities				213,101		157,539
INVESTING ACTIVITIES
Construction Expenditures				(92,578)		(84,208)
Change in Other Cash Deposits				-		10,289
Change in Advances to Affiliates, Net				(17,121)		(57,069)
Acquisitions of Assets				(527)		(463)
Proceeds from Sales of Assets				6,280		3,410
Other Investing Activities				18,286		-
Net Cash Flows Used for Investing Activities				(85,660)		(128,041)
FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated				-		149,443
Change in Advances from Affiliates, Net				-		(24,202)
Retirement of Long-term Debt – Affiliated				-		(100,000)
Principal Payments for Capital Lease Obligations				(1,674)		(2,237)
Dividends Paid on Common Stock				(125,000)		(52,500)
Other Financing Activities				19		95
Net Cash Flows Used for Financing Activities				(126,655)		(29,401)
Net Increase in Cash and Cash Equivalents				786		97
Cash and Cash Equivalents at Beginning of Period				509		1,096
Cash and Cash Equivalents at End of Period			$	1,295	$	1,193
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	38,250	$	43,615
Net Cash Paid for Income Taxes				26,797		54,032
Noncash Acquisitions Under Capital Leases				580		9,196
Government Grants Included in Accounts Receivable at June 30,				2,000		-
Construction Expenditures Included in Current Liabilities at June 30,				8,811		14,594
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

108

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

INDEX OF 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 162.

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

109

INDIANA MICHIGAN POWER COMPANY

AND SUBSIDIARIES

110

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Regulatory Activity

Michigan Base Rate Case

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

Cook Plant

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator.  Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $408 million.  Management believes that I&M should recover a significant portion of repair and replacement costs through the turbine vendor’s warranty, insurance and the regulatory process.  I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power.  The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors.  The 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 “Michigan 2009 and 2010 Power Supply Cost Recovery Reconciliations” section of Note 3 and “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

As a result of the nuclear plant situation in Japan following an earthquake, management expects the Nuclear Regulatory Commission and possibly Congress to review safety procedures and requirements for nuclear generating facilities.  This review could increase procedures and testing requirements, require physical modifications to the plant and increase future operating costs at the Cook Plant.  Management is unable to predict the impact of potential future regulation of nuclear facilities.

Litigation and Environmental Issues

In the ordinary course of business, I&M is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2010 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 162.  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 227 for additional discussion of relevant factors.

111

RESULTS OF OPERATIONS
KWH Sales/Degree Days
Summary of KWH Energy Sales
		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2011		2010		2011		2010
		(in millions of KWH)
Retail:
	Residential		1,170		1,210		3,006		2,975
	Commercial		1,188		1,279		2,452		2,487
	Industrial		1,871		1,895		3,715		3,695
	Miscellaneous		15		18		38		36
Total Retail			4,244		4,402		9,211		9,193
Wholesale			2,408		1,793		4,504		3,700
Total KWHs			6,652		6,195		13,715		12,893

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.

Summary of Heating and Cooling Degree Days
		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2011		2010		2011		2010
		(in degree days)
Actual - Heating (a)			228		95		2,620		2,278
Normal - Heating (b)			238		243		2,414		2,422
Actual - Cooling (c)			304		379		304		379
Normal - Cooling (b)			252		245		253		246
(a)	Eastern Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.
(c)	Eastern Region cooling degree days are calculated on a 65 degree temperature base.

112

Second Quarter of 2011 Compared to Second Quarter of 2010

Reconciliation of Second Quarter of 2010 to Second Quarter of 2011
Net Income
(in millions)
Second Quarter of 2010	$	15
Changes in Gross Margin:
Retail Margins		(9	)
FERC Municipals and Cooperatives		(2	)
Off-system Sales		4
Other Revenues		(2	)
Total Change in Gross Margin		(9	)
Changes in Expenses and Other:
Other Operation and Maintenance		32
Depreciation and Amortization		1
Taxes Other Than Income Taxes		(2	)
Other Income		(2	)
Interest Expense		2
Total Change in Expenses and Other		31
Income Tax Expense		(6	)
Second Quarter of 2011	$	31

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

·	Retail Margins decreased $9 million primarily due to the following:
	·	A $6 million decrease due to customer credits for a settlement relating to the Cook Plant Unit 1 (Unit 1) fire outage.  This decrease was offset by a decrease in Other Operation and Maintenance expenses.
	·	A $5 million decrease in margins from commercial sales primarily due to lower usage.
	·	A $3 million decrease in capacity settlements under the Interconnection Agreement.
	These decreases were partially offset by:
	·	A $7 million increase due to a Michigan rate settlement effective in December 2010.
·	Margins from Off-system Sales increased $4 million primarily due to higher physical sales volume.

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

·	Other Operation and Maintenance expenses decreased $32 million primarily due to the following:
	·	A $40 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
	·	A $6 million decrease in steam power expenses relating to the Unit 1 fire outage.  This decrease was offset by a decrease in Retail Margins.
	These decreases were partially offset by:
	·	A $9 million increase in transmission expense primarily due to the Transmission Agreement modification effective November 2010.
	·	A $3 million increase in steam generation maintenance costs.
·	Income Tax Expense increased $6 million primarily due to an increase in pre-tax book income and the regulatory accounting treatment of state income taxes, partially offset by other book/tax differences which are accounted for on a flow-through basis.

113

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Reconciliation of Six Months Ended June 30, 2010 to Six Months Ended June 30, 2011
Net Income
(in millions)
Six Months Ended June 30, 2010	$	60
Changes in Gross Margin:
Retail Margins		2
Off-system Sales		6
Other Revenues		(3)
Total Change in Gross Margin		5
Changes in Expenses and Other:
Other Operation and Maintenance		27
Depreciation and Amortization		1
Taxes Other Than Income Taxes		(3)
Other Income		(3)
Interest Expense		3
Total Change in Expenses and Other		25
Income Tax Expense		(13)
Six Months Ended June 30, 2011	$	77

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 $2 million primarily due to the following:
	·	A $23 million increase due to the Michigan rate settlement effective in December 2010 and recovery of costs through trackers.
	This increase was offset by:
	·	A $17 million decrease in capacity settlements under the Interconnection Agreement.
	·	A $6 million decrease due to customer credits for a settlement relating to the Unit 1 fire outage.  This decrease was offset by a decrease in Other Operation and Maintenance expenses.
·	Margins from Off-system Sales increased $6 million primarily due to higher physical sales volume.

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

·	Other Operation and Maintenance expenses decreased $27 million primarily due to the following:
	·	A $40 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
	·	A $6 million decrease in steam power expenses relating to the Unit 1 fire outage.  This decrease was offset by a decrease in Retail Margins.
	These decreases were partially offset by:
	·	A $19 million increase in transmission expense primarily due to the Transmission Agreement modification effective November 2010.
·	Income Tax Expense increased $13 million primarily due to an increase in pre-tax book income, the regulatory accounting treatment of state income taxes and federal income tax adjustments related to prior year tax returns.

114

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of market risk.

115

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
	Three Months Ended				Six Months Ended
	2011		2010		2011		2010
REVENUES
Electric Generation, Transmission and Distribution	$	419,627	$	408,702	$	876,489	$	846,726
Sales to AEP Affiliates		70,902		67,473		145,770		151,690
Other Revenues - Affiliated		28,133		30,685		52,464		58,651
Other Revenues - Nonaffiliated		2,816		3,055		7,247		5,904
TOTAL REVENUES		521,478		509,915		1,081,970		1,062,971
EXPENSES
Fuel and Other Consumables Used for Electric Generation		108,322		102,258		223,384		221,439
Purchased Electricity for Resale		31,796		31,444		61,088		61,211
Purchased Electricity from AEP Affiliates		82,967		68,496		162,551		150,746
Other Operation		132,846		162,978		266,057		293,659
Maintenance		47,536		49,633		98,536		98,077
Depreciation and Amortization		33,263		33,971		67,350		67,802
Taxes Other Than Income Taxes		20,397		18,995		42,659		40,027
TOTAL EXPENSES		457,127		467,775		921,625		932,961
OPERATING INCOME		64,351		42,140		160,345		130,010
Other Income (Expense):
Other Income		3,467		5,601		7,362		10,521
Interest Expense		(24,193)		(26,410)		(49,384)		(52,511)
INCOME BEFORE INCOME TAX EXPENSE		43,625		21,331		118,323		88,020
Income Tax Expense		12,239		6,729		41,510		28,360
NET INCOME		31,386		14,602		76,813		59,660
Preferred Stock Dividend Requirements		85		85		170		170
EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	31,301	$	14,517	$	76,643	$	59,490
The common stock of I&M is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

116

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
											Accumulated
											Other
				Common		Paid-in			Retained		Comprehensive
				Stock		Capital			Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2009			$	56,584	$	981,292		$	656,608	$	(21,701)	$	1,672,783
Common Stock Dividends										(51,500)				(51,500)
Preferred Stock Dividends										(170)				(170)
SUBTOTAL – COMMON
	SHAREHOLDER'S EQUITY													1,621,113
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
		Cash Flow Hedges, Net of Tax of $39										72		72
		Amortization of Pension and OPEB Deferred
			Costs, Net of Tax of $235									436		436
NET INCOME										59,660				59,660
TOTAL COMPREHENSIVE INCOME														60,168
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2010			$	56,584	$	981,292		$	664,598	$	(21,193)	$	1,681,281
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2010			$	56,584	$	981,294		$	677,360	$	(20,889)	$	1,694,349
Common Stock Dividends										(37,500)				(37,500)
Preferred Stock Dividends										(170)				(170)
SUBTOTAL – COMMON
	SHAREHOLDER'S EQUITY													1,656,679
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
		Cash Flow Hedges, Net of Tax of $570										1,059		1,059
		Amortization of Pension and OPEB Deferred
			Costs, Net of Tax of $255									473		473
NET INCOME								��		76,813				76,813
TOTAL COMPREHENSIVE INCOME														78,345
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2011			$	56,584	$	981,294		$	716,503	$	(19,357)	$	1,735,024
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

117

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2011 and December 31, 2010
(in thousands)
(Unaudited)
			2011		2010
CURRENT ASSETS
Cash and Cash Equivalents			$	554	$	361
Accounts Receivable:
	Customers			78,902		76,193
	Affiliated Companies			81,812		149,169
	Accrued Unbilled Revenues			10,189		19,449
	Miscellaneous			10,930		10,968
	Allowance for Uncollectible Accounts			(1,986)		(1,692)
		Total Accounts Receivable		179,847		254,087
Fuel				66,889		87,551
Materials and Supplies				172,890		178,331
Risk Management Assets				22,341		27,526
Accrued Tax Benefits				55,784		71,113
Deferred Cook Plant Fire Costs				60,207		45,752
Prepayments and Other Current Assets				34,198		33,713
TOTAL CURRENT ASSETS				592,710		698,434
PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			3,803,820		3,774,262
	Transmission			1,201,822		1,188,665
	Distribution			1,435,632		1,411,095
Other Property, Plant and Equipment (including nuclear fuel and coal mining)				747,303		719,708
Construction Work in Progress				338,627		301,534
Total Property, Plant and Equipment				7,527,204		7,395,264
Accumulated Depreciation, Depletion and Amortization				3,180,526		3,124,998
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				4,346,678		4,270,266
OTHER NONCURRENT ASSETS
Regulatory Assets				519,181		556,254
Spent Nuclear Fuel and Decommissioning Trusts				1,574,142		1,515,227
Long-term Risk Management Assets				25,069		31,485
Deferred Charges and Other Noncurrent Assets				73,782		77,229
TOTAL OTHER NONCURRENT ASSETS				2,192,174		2,180,195
TOTAL ASSETS			$	7,131,562	$	7,148,895
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

118

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
June 30, 2011 and December 31, 2010
(dollars in thousands)
(Unaudited)
		2011		2010
CURRENT LIABILITIES
Advances from Affiliates		$	24,537	$	42,769
Accounts Payable:
	General		82,179		121,665
	Affiliated Companies		78,368		105,221
Long-term Debt Due Within One Year - Nonaffiliated
	(June 30, 2011 and December 31, 2010 amounts include $74,100 and $77,457,
	respectively, related to DCC Fuel)		151,100		154,457
Risk Management Liabilities			10,877		16,785
Customer Deposits			29,791		29,264
Accrued Taxes			65,150		62,637
Accrued Interest			27,425		27,444
Other Current Liabilities			129,028		140,710
TOTAL CURRENT LIABILITIES			598,455		700,952
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			1,813,994		1,849,769
Long-term Risk Management Liabilities			6,092		6,530
Deferred Income Taxes			808,287		760,105
Regulatory Liabilities and Deferred Investment Tax Credits			868,919		852,197
Asset Retirement Obligations			987,400		963,029
Deferred Credits and Other Noncurrent Liabilities			305,319		313,892
TOTAL NONCURRENT LIABILITIES			4,790,011		4,745,522
TOTAL LIABILITIES			5,388,466		5,446,474
Cumulative Preferred Stock Not Subject to Mandatory Redemption			8,072		8,072
Rate Matters (Note 3)
Commitments and Contingencies (Note 4)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
	Authorized – 2,500,000 Shares
	Outstanding  – 1,400,000 Shares		56,584		56,584
Paid-in Capital			981,294		981,294
Retained Earnings			716,503		677,360
Accumulated Other Comprehensive Income (Loss)			(19,357)		(20,889)
TOTAL COMMON SHAREHOLDER’S EQUITY			1,735,024		1,694,349
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$	7,131,562	$	7,148,895
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

119

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
			2011		2010
OPERATING ACTIVITIES
Net Income			$	76,813	$	59,660
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			67,350		67,802
	Deferred Income Taxes			42,561		23,213
	Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net			23,086		(16,103)
	Allowance for Equity Funds Used During Construction			(7,440)		(9,002)
	Mark-to-Market of Risk Management Contracts			6,183		(4,314)
	Amortization of Nuclear Fuel			72,474		69,478
	Fuel Over/Under-Recovery, Net			2,947		11,389
	Change in Other Noncurrent Assets			4,433		7,224
	Change in Other Noncurrent Liabilities			12,055		33,814
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		74,240		(2,965)
		Fuel, Materials and Supplies		26,103		(26,832)
		Accounts Payable		(76,440)		(31,079)
		Accrued Taxes, Net		13,775		4,470
		Received (Deferred) Cook Plant Fire Costs		-		61,906
		Other Current Assets		(887)		(284)
		Other Current Liabilities		(321)		20,087
Net Cash Flows from Operating Activities				336,932		268,464
INVESTING ACTIVITIES
Construction Expenditures				(133,064)		(160,797)
Change in Advances to Affiliates, Net				-		(12,503)
Purchases of Investment Securities				(492,162)		(617,059)
Sales of Investment Securities				464,688		592,263
Acquisitions of Nuclear Fuel				(93,230)		(41,357)
Other Investing Activities				17,125		(345)
Net Cash Flows Used for Investing Activities				(236,643)		(239,798)
FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated				76,624		84,564
Change in Advances from Affiliates, Net				(18,232)		-
Retirement of Long-term Debt – Nonaffiliated				(116,526)		(19,208)
Retirement of Long-term Debt – Affiliated				-		(25,000)
Principal Payments for Capital Lease Obligations				(4,317)		(17,669)
Dividends Paid on Common Stock				(37,500)		(51,500)
Dividends Paid on Cumulative Preferred Stock				(170)		(170)
Other Financing Activities				25		270
Net Cash Flows Used for Financing Activities				(100,096)		(28,713)
Net Increase (Decrease) in Cash and Cash Equivalents				193		(47)
Cash and Cash Equivalents at Beginning of Period				361		779
Cash and Cash Equivalents at End of Period			$	554	$	732
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	47,401	$	50,759
Net Cash Paid (Received) for Income Taxes				(19,847)		8,092
Noncash Acquisitions Under Capital Leases				1,218		8,844
Construction Expenditures Included in Current Liabilities at June 30,				36,109		19,220
Acquisition of Nuclear Fuel Included in Current Liabilities at June 30,				-		123
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

120

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to I&M’s condensed 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 162.

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

121

OHIO POWER COMPANY CONSOLIDATED

122

OHIO POWER COMPANY CONSOLIDATED

MANAGEMENT’S DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Ohio Customer Choice

In OPCo’s service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service.  As a result, in comparison to the second quarter of 2010 and the first six months of 2010, OPCo lost approximately $2 million and $3 million, respectively, of generation related gross margin.  Management anticipates recovery of a portion of lost margins through off-system sales, including PJM capacity revenues.

Regulatory Activity

2009 – 2011 ESPs

In April 2011, the Supreme Court of Ohio issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged which resulted in three reversals, only two of which may have a prospective impact through a remand proceeding.  Pursuant to a May 2011 PUCO order, OPCo implemented rates subject to refund.  Certain intervenors proposed adjustments that included a reduction of deferred FAC and other regulatory assets for the period prior to June 2011 of up to $336 million, excluding carrying costs, which OPCo believes is without merit and violates the Supreme Court of Ohio decision.  The proposed adjustments also include refunds and rate reductions of related revenues beginning in June 2011 of up to $81 million.    See “Ohio Electric Security Plan Filings” section of Note 3.

January 2012 – May 2014 ESP

In January 2011, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  The SSO presents redesigned generation rates by customer class.  Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013.  Under the new ESP, management estimates OPCo will have base generation revenue increases, excluding riders, of $48 million for 2012 and $60 million for 2013.  The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESP could impact the outcome of the January 2012-May 2014 ESP, though the nature and extent of that impact is not presently known.  See “Ohio Electric Security Plan Filings” section of Note 3.

Ohio Distribution Base Rate Case

In February 2011, OPCo filed with the PUCO for annual increases in distribution rates of $60 million.  The requested increase is based upon an 11.15% return on common equity to be effective January 2012.  In addition to the annual increase, OPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets of $159 million including approximately $84 million of unrecognized equity carrying costs.  These assets and unrecognized carrying costs would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013.  The actual balance of these distribution regulatory assets as of June 30, 2011 was $64 million excluding $45 million of unrecognized equity carrying costs.  If OPCo is not ultimately permitted to fully recover its deferrals, it would reduce future net income and cash flows and impact financial condition.  See “2011 Ohio Distribution Base Rate Case” 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.  In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo.  CSPCo and OPCo requested the reorganization transaction be effective in October 2011.  In July 2011, the FERC issued an order approving the proposed merger.  A decision is pending from the PUCO.  See “Proposed CSPCo and OPCo Merger” section of Note 3.

123

Litigation and Environmental Issues

In the ordinary course of business, OPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2010 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 162.  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 227 for additional discussion of relevant factors.

RESULTS OF OPERATIONS
KWH Sales/Degree Days
Summary of KWH Energy Sales
		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2011		2010		2011		2010
		(in millions of KWH)
Retail:
	Residential		1,547		1,471		3,871		3,755
	Commercial		1,395		1,439		2,788		2,797
	Industrial		3,458		3,236		6,734		6,294
	Miscellaneous		15		16		35		36
Total Retail			6,415		6,162		13,428		12,882
Wholesale			1,733		982		3,641		2,324
Total KWHs			8,148		7,144		17,069		15,206

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.

Summary of Heating and Cooling Degree Days
		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2011		2010		2011		2010
		(in degree days)
Actual - Heating (a)			207		136		2,449		2,293
Normal - Heating (b)			239		240		2,281		2,284
Actual - Cooling (c)			270		309		270		309
Normal - Cooling (b)			227		224		229		225
(a)	Eastern Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.
(c)	Eastern Region cooling degree days are calculated on a 65 degree temperature base.

124

Second Quarter of 2011 Compared to Second Quarter of 2010

Reconciliation of Second Quarter of 2010 to Second Quarter of 2011
Net Income
(in millions)
Second Quarter of 2010	$	38
Changes in Gross Margin:
Retail Margins		(5	)
Off-system Sales		13
Transmission Revenues		4
Other Revenues		(3	)
Total Change in Gross Margin		9
Changes in Expenses and Other:
Other Operation and Maintenance		45
Depreciation and Amortization		(2	)
Taxes Other Than Income Taxes		1
Carrying Costs Income		2
Interest Expense		3
Total Change in Expenses and Other		49
Income Tax Expense		(20	)
Second Quarter of 2011	$	76

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

·	Retail Margins decreased $5 million primarily due to the following:
	·	A $7 million decrease in capacity settlements under the Interconnection Agreement.
	·	A $7 million decrease in transmission rider revenues.
	·	A $3 million decrease in commercial revenues mainly due to reduced usage.
	·	A $2 million decrease attributable to customers switching to alternative competitive retail electric service (CRES) providers.
	·	A $2 million decrease related to increased consumable and allowance expenses not recovered through the FAC.
	These decreases were partially offset by:
	·	A $7 million increase in revenues due to the implementation of PUCO approved rider rates in June 2010 related to the Energy Efficiency & Peak Demand Reduction (EE/PDR) Programs.  This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
	·	A $6 million increase in revenues due to the implementation of PUCO approved rider rates in September 2010 related to the Environmental Investment Carrying Cost Rider.
	·	A $4 million increase in revenues due to a January 2011 Universal Service Fund surcharge rate increase.  This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
·	Margins from Off-system Sales increased $13 million primarily due to higher physical sales volumes.
·	Transmission Revenues increased $4 million primarily due to the Transmission Agreement modification effective November 2010, a portion of which is included in the Ohio Transmission Cost Recovery Rider.

125

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

·	Other Operation and Maintenance expenses decreased $45 million primarily due to the following:
	·	A $49 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
	·	A $7 million decrease in recoverable PJM expenses.
	These decreases were partially offset by:
	·	A $7 million increase in expenses due to the implementation of PUCO approved EE/PDR programs.  This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
	·	A $4 million reserve recorded in second quarter 2011 as a result of a legal proceeding.
	·	A $4 million increase in remitted Universal Service Fund surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.  This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
·	Depreciation and Amortization increased $2 million primarily due to higher depreciable property balances as a result of environmental and various other property additions.
·	Interest Expense decreased $3 million primarily as a result of the retirement of long-term debt in November 2010.
·	Income Tax Expense increased $20 million primarily due to an increase in pretax book income.

126

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Reconciliation of Six Months Ended June 30, 2010 to Six Months Ended June 30, 2011
Net Income
(in millions)
Six Months Ended June 30, 2010	$	129
Changes in Gross Margin:
Retail Margins		15
Off-system Sales		13
Transmission Revenues		8
Total Change in Gross Margin		36
Changes in Expenses and Other:
Other Operation and Maintenance		27
Depreciation and Amortization		(5)
Taxes Other Than Income Taxes		(1)
Carrying Costs Income		4
Interest Expense		5
Total Change in Expenses and Other		30
Income Tax Expense		(19)
Six Months Ended June 30, 2011	$	176

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 $15 million primarily due to the following:
	·	A $21 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Energy Efficiency & Peak Demand Reduction (EE/PDR) Programs.  This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below.
	·	A $13 million increase in revenues due to the implementation of PUCO approved rider rates in September 2010 related to the Environmental Investment Carrying Cost Rider.
	·	A $10 million increase in margins due to increases in residential and industrial customer usage.  The industrial increase was driven primarily by increased load for Ormet, a major industrial customer.
	·	A $9 million increase in revenues due to a January 2011 Universal Service Fund surcharge rate increase.  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 $19 million decrease in capacity settlements under the Interconnection Agreement.
	·	An $8 million decrease in transmission rider revenues.
	·	A $5 million decrease related to increased consumable and allowance expenses not recovered through the FAC.
	·	A $3 million decrease attributable to customers switching to alternative competitive retail electric service (CRES) providers.
·	Margins from Off-system Sales increased $13 million primarily due to higher physical sales volumes.
·	Transmission Revenues increased $8 million primarily due to the Transmission Agreement modification effective November 2010, a portion of which is included in the Ohio Transmission Cost Recovery Rider.

127

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

·	Other Operation and Maintenance expenses decreased $27 million primarily due to the following:
	·	A $49 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
	·	An $11 million gain from the sale of land in January 2011.
	·	A $9 million decrease in recoverable PJM expenses.
	These decreases were partially offset by:
	·	A $21 million increase in expenses due to the implementation of PUCO approved EE/PDR programs.  This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
	·	A $9 million increase in remitted Universal Service Fund surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.  This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above.
	·	A $7 million increase due to a favorable 2010 employee benefit adjustment.
	·	A $4 million reserve recorded in second quarter 2011 as a result of a legal proceeding.
·	Depreciation and Amortization increased $5 million primarily due to higher depreciable property balances as a result of environmental and various other property additions.
·	Carrying Costs Income increased $4 million primarily due to a higher under-recovered fuel balance in 2011.
·	Interest Expense decreased $5 million primarily due to the retirement of long-term debt in November 2010.
·	Income Tax Expense increased $19 million primarily due to an increase in pretax book income, partially offset by the 2010 tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.

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 227 for additional discussion of liquidity.

Credit Ratings

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

CASH FLOW

Cash flows for the six months ended June 30, 2011 and 2010 were as follows:

	2011			2010
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	440		$	1,984
Net Cash Flows from Operating Activities		427,160			352,278
Net Cash Flows from (Used for) Investing Activities		(106,529	)		119,588
Net Cash Flows Used for Financing Activities		(319,919	)		(472,912	)
Net Increase (Decrease) in Cash and Cash Equivalents		712			(1,046	)
Cash and Cash Equivalents at End of Period	$	1,152		$	938

128

Operating Activities

Net Cash Flows from Operating Activities were $427 million in 2011.  OPCo produced Net Income of $176 million during the period and noncash expense items of $184 million for Depreciation and Amortization, $57 million for Deferred Income Taxes and $51 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 current period activity in working capital relates to a number of items.  Accounts Receivable, Net had a $71 million inflow primarily due to a settlement with AEP Ohio Transmission Company, a decrease in estimated accounts receivable balances and settlements of backup power sales.  Accounts Payable had a $51 million outflow primarily due to payments to affiliates for allowance settlements and timing differences of payments.  Fuel, Materials and Supplies had a $50 million inflow primarily due to a decrease in coal inventory reflecting increased customer usage for electricity.  The $49 million outflow from Accrued Taxes, Net is primarily due to temporary timing differences of payments for property taxes partially offset by an increase of federal income tax related accruals.

Net Cash Flows from Operating Activities were $352 million in 2010.  OPCo produced Net Income of $129 million during the period and noncash expense items of $179 million for Depreciation and Amortization and $73 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 primarily relates to a number of items.  Accrued Taxes, Net had a $71 million outflow due to temporary timing differences of payments for property taxes and an increase of federal income tax related accruals.  Accounts Receivable, Net had a $44 million inflow primarily due to decreased sales to affiliates and settlement of allowance sales to affiliated companies.  Fuel, Materials and Supplies had a $26 million inflow primarily due to price decreases.  The $76 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.

Investing Activities

Net Cash Flows Used for Investing Activities were $107 million in 2011.  OPCo had Construction Expenditures of $112 million and a net increase of $36 million in loans to the Utility Money Pool.  Construction Expenditures were primarily related to environmental upgrades, as well as projects to improve generation and service reliability for transmission and distribution. These decreases were partially offset by $42 million in Proceeds from Sales of Assets.

Net Cash Flows from Investing Activities were $120 million in 2010.  OPCo had a net decrease of $266 million in loans to the Utility Money Pool.  This inflow was partially offset by Construction Expenditures of $148 million.  The Construction Expenditures primarily related to environmental upgrades, as well as projects to improve generation and service reliability for transmission and distribution.  Environmental upgrades include FGD projects at the Amos Plant.

Financing Activities

Net Cash Flows Used for Financing Activities were $320 million in 2011.  OPCo retired $165 million of Pollution Control Bonds in March 2011.  In addition, OPCo paid $200 million of dividends on common stock.  These decreases were partially offset by the issuance of $50 million of Pollution Control Bonds in March 2011.

Net Cash Flows Used for Financing Activities were $473 million during 2010.  OPCo retired $400 million of Senior Unsecured Notes in April 2010 and $79 million of Pollution Control Bonds in June 2010.  In addition, OPCo paid $151 million of dividends on common stock.  These decreases were partially offset by an $86 million issuance of Pollution Control Bonds in March 2010 and a $79 million issuance in May 2010.

129

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

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

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

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

CONTRACTUAL OBLIGATION INFORMATION

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of market risk.

130

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
	Three Months Ended				Six Months Ended
	2011		2010		2011		2010
REVENUES
Electric Generation, Transmission and Distribution	$	558,873	$	490,422	$	1,185,679	$	1,034,122
Sales to AEP Affiliates		213,076		222,561		438,125		529,329
Other Revenues - Affiliated		4,507		5,155		11,525		11,729
Other Revenues - Nonaffiliated		3,515		3,826		7,470		8,057
TOTAL REVENUES		779,971		721,964		1,642,799		1,583,237
EXPENSES
Fuel and Other Consumables Used for Electric Generation		246,973		220,174		541,456		551,191
Purchased Electricity for Resale		44,098		38,746		88,995		77,636
Purchased Electricity from AEP Affiliates		38,168		21,583		65,862		43,774
Other Operation		94,669		146,417		194,387		235,573
Maintenance		69,607		63,472		133,919		119,703
Depreciation and Amortization		92,167		89,861		184,153		179,222
Taxes Other Than Income Taxes		51,005		52,088		106,166		105,172
TOTAL EXPENSES		636,687		632,341		1,314,938		1,312,271
OPERATING INCOME		143,284		89,623		327,861		270,966
Other Income (Expense):
Interest Income		254		334		545		739
Carrying Costs Income		7,579		5,681		14,656		10,555
Allowance for Equity Funds Used During Construction		961		986		1,393		2,017
Interest Expense		(36,430)		(39,077)		(73,702)		(79,052)
INCOME BEFORE INCOME TAX EXPENSE		115,648		57,547		270,753		205,225
Income Tax Expense		39,982		19,999		94,675		75,774
NET INCOME		75,666		37,548		176,078		129,451
Less: Preferred Stock Dividend Requirements		183		183		366		366
EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	75,483	$	37,365	$	175,712	$	129,085
The common stock of OPCo is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

131

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
										Accumulated
										Other
				Common		Paid-in		Retained		Comprehensive
				Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S
		EQUITY – DECEMBER 31, 2009		$	321,201	$	1,123,149	$	1,908,803	$	(118,458)	$	3,234,695
Common Stock Dividends									(150,575)				(150,575)
Preferred Stock Dividends									(366)				(366)
SUBTOTAL – COMMON
		SHAREHOLDER'S EQUITY											3,083,754
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss),
	Net of Taxes:
		Cash Flow Hedges, Net of Tax of $676									(1,255)		(1,255)
		Amortization of Pension and OPEB Deferred Costs,
			Net of Tax of $1,897								3,523		3,523
NET INCOME									129,451				129,451
TOTAL COMPREHENSIVE INCOME													131,719
TOTAL COMMON SHAREHOLDER'S
		EQUITY –  JUNE 30, 2010		$	321,201	$	1,123,149	$	1,887,313	$	(116,190)	$	3,215,473
TOTAL COMMON SHAREHOLDER'S
		EQUITY – DECEMBER 31, 2010		$	321,201	$	1,123,153	$	1,852,889	$	(128,819)	$	3,168,424
Common Stock Dividends									(200,000)				(200,000)
Preferred Stock Dividends									(366)				(366)
SUBTOTAL – COMMON
		SHAREHOLDER'S EQUITY											2,968,058
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
		Cash Flow Hedges, Net of Tax of $15									29		29
		Amortization of Pension and OPEB Deferred Costs,
			Net of Tax of $2,156								4,003		4,003
NET INCOME									176,078				176,078
TOTAL COMPREHENSIVE INCOME													180,110
TOTAL COMMON SHAREHOLDER'S
		EQUITY –  JUNE 30, 2011		$	321,201	$	1,123,153	$	1,828,601	$	(124,787)	$	3,148,168
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

132

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2011 and December 31, 2010
(in thousands)
(Unaudited)
			2011		2010
CURRENT ASSETS
Cash and Cash Equivalents			$	1,152	$	440
Advances to Affiliates				136,965		100,500
Accounts Receivable:
	Customers			76,517		86,186
	Affiliated Companies			161,076		198,845
	Accrued Unbilled Revenues			6,626		27,928
	Miscellaneous			350		2,368
	Allowance for Uncollectible Accounts			(2,151)		(2,184)
		Total Accounts Receivable		242,418		313,143
Fuel				219,150		257,289
Materials and Supplies				122,510		134,181
Risk Management Assets				22,515		30,773
Accrued Tax Benefits				22,291		69,021
Prepayments and Other Current Assets				31,081		33,998
TOTAL CURRENT ASSETS				798,082		939,345
PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			6,909,563		6,890,110
	Transmission			1,254,300		1,234,677
	Distribution			1,651,878		1,626,390
Other Property, Plant and Equipment				357,456		359,254
Construction Work in Progress				139,690		153,110
Total Property, Plant and Equipment				10,312,887		10,263,541
Accumulated Depreciation and Amortization				3,764,752		3,606,777
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				6,548,135		6,656,764
OTHER NONCURRENT ASSETS
Regulatory Assets				1,004,684		934,011
Long-term Risk Management Assets				22,980		28,012
Deferred Charges and Other Noncurrent Assets				142,814		189,195
TOTAL OTHER NONCURRENT ASSETS				1,170,478		1,151,218
TOTAL ASSETS			$	8,516,695	$	8,747,327
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

133

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
June 30, 2011 and December 31, 2010
(Unaudited)
		2011		2010
			(in thousands)
CURRENT LIABILITIES
Accounts Payable:
	General	$	139,506	$	170,240
	Affiliated Companies		111,042		136,215
Long-term Debt Due Within One Year – Nonaffiliated			50,000		165,000
Risk Management Liabilities			13,859		22,166
Customer Deposits			24,677		28,228
Accrued Taxes			172,622		229,253
Accrued Interest			46,444		46,184
Other Current Liabilities			98,589		98,687
TOTAL CURRENT LIABILITIES			656,739		895,973
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			2,364,781		2,364,522
Long-term Debt – Affiliated			200,000		200,000
Long-term Risk Management Liabilities			7,540		8,403
Deferred Income Taxes			1,558,892		1,531,639
Regulatory Liabilities and Deferred Investment Tax Credits			131,188		126,403
Employee Benefits and Pension Obligations			237,579		246,517
Deferred Credits and Other Noncurrent Liabilities			195,194		188,830
TOTAL NONCURRENT LIABILITIES			4,695,174		4,666,314
TOTAL LIABILITIES			5,351,913		5,562,287
Cumulative Preferred Stock Not Subject to Mandatory Redemption			16,614		16,616
Rate Matters (Note 3)
Commitments and Contingencies (Note 4)
COMMON SHAREHOLDER’S EQUITY
Common Stock – No Par Value:
	Authorized – 40,000,000 Shares
	Outstanding  – 27,952,473 Shares		321,201		321,201
Paid-in Capital			1,123,153		1,123,153
Retained Earnings			1,828,601		1,852,889
Accumulated Other Comprehensive Income (Loss)			(124,787)		(128,819)
TOTAL COMMON SHAREHOLDER’S EQUITY			3,148,168		3,168,424
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY		$	8,516,695	$	8,747,327
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

134

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
			2011		2010
OPERATING ACTIVITIES
Net Income			$	176,078	$	129,451
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
	Depreciation and Amortization			184,153		179,222
	Deferred Income Taxes			57,132		72,638
	Carrying Costs Income			(14,656)		(10,555)
	Allowance for Equity Funds Used During Construction			(1,393)		(2,017)
	Mark-to-Market of Risk Management Contracts			5,285		2,359
	Property Taxes			50,997		48,578
	Fuel Over/Under-Recovery, Net			(38,041)		(75,987)
	Change in Other Noncurrent Assets			(35,326)		(7,571)
	Change in Other Noncurrent Liabilities			16,911		(2,326)
	Changes in Certain Components of Working Capital:
		Accounts Receivable, Net		70,725		44,027
		Fuel, Materials and Supplies		49,810		25,508
		Accounts Payable		(51,175)		(23,991)
		Accrued Taxes, Net		(49,177)		(71,199)
		Other Current Assets		1,672		2,680
		Other Current Liabilities		4,165		41,461
Net Cash Flows from Operating Activities				427,160		352,278
INVESTING ACTIVITIES
Construction Expenditures				(111,851)		(147,831)
Change in Advances to Affiliates, Net				(36,465)		265,601
Acquisitions of Assets				(1,187)		(2,113)
Proceeds from Sales of Assets				41,766		4,245
Other Investing Activities				1,208		(314)
Net Cash Flows from (Used for) Investing Activities				(106,529)		119,588
FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated				49,768		163,944
Retirement of Long-term Debt – Nonaffiliated				(165,000)		(479,450)
Retirement of Cumulative Preferred Stock				(1)		-
Principal Payments for Capital Lease Obligations				(4,180)		(3,903)
Dividends Paid on Common Stock				(200,000)		(150,575)
Dividends Paid on Cumulative Preferred Stock				(366)		(366)
Other Financing Activities				(140)		(2,562)
Net Cash Flows Used for Financing Activities				(319,919)		(472,912)
Net Increase (Decrease) in Cash and Cash Equivalents				712		(1,046)
Cash and Cash Equivalents at Beginning of Period				440		1,984
Cash and Cash Equivalents at End of Period			$	1,152	$	938
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts			$	70,886	$	78,747
Net Cash Paid for Income Taxes				25,679		27,206
Noncash Acquisitions Under Capital Leases				422		23,489
Construction Expenditures Included in Current Liabilities at June 30,				17,908		10,567
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

135

OHIO POWER COMPANY CONSOLIDATED

INDEX OF 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 162.

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

136

PUBLIC SERVICE COMPANY OF OKLAHOMA

137

PUBLIC SERVICE COMPANY OF OKLAHOMA

MANAGEMENT’S DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Litigation and Environmental Issues

In the ordinary course of business, PSO is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2010 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 162.  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 227 for additional discussion of relevant factors.

RESULTS OF OPERATIONS

KWH Sales/Degree Days
Summary of KWH Energy Sales
		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2011		2010		2011		2010
		(in millions of KWH)
Retail:
	Residential		1,537		1,505		3,077		3,061
	Commercial		1,389		1,374		2,520		2,443
	Industrial		1,243		1,249		2,366		2,394
	Miscellaneous		339		328		617		597
Total Retail			4,508		4,456		8,580		8,495
Wholesale			317		205		552		554
Total KWHs			4,825		4,661		9,132		9,049

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.

Summary of Heating and Cooling Degree Days
		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2011		2010		2011		2010
		(in degree days)
Actual - Heating (a)			19		14		1,276		1,344
Normal - Heating (b)			42		41		1,100		1,088
Actual - Cooling (c)			912		769		945		777
Normal - Cooling (b)			624		621		637		634
(a)	Western Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.
(c)	Western Region cooling degree days are calculated on a 65 degree temperature base.

138

Second Quarter of 2011 Compared to Second Quarter of 2010

Reconciliation of Second Quarter of 2010 to Second Quarter of 2011
Net Income
(in millions)
Second Quarter of 2010	$	15
Changes in Gross Margin:
Retail Margins (a)		(2	)
Total Change in Gross Margin		(2	)
Changes in Expenses and Other:
Other Operation and Maintenance		24
Depreciation and Amortization		3
Taxes Other Than Income Taxes		1
Other Income		1
Interest Expense		2
Total Change in Expenses and Other		31
Income Tax Expense		(12	)
Second Quarter of 2011	$	32

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

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

·	Retail Margins decreased $2 million primarily due to the following:
	·	A $5 million decrease primarily due to revenue decreases from rate riders.  This decrease in retail margins had corresponding decreases to riders/trackers recognized in other expense items.
	·	A $4 million decrease in residential and commercial margins primarily due to lower non-weather related usage.
	These decreases were partially offset by:
	·	A $5 million increase in residential weather-related usage primarily due to a 19% increase in cooling degree days.
	·	A $3 million increase primarily due to decreased capacity and fuel costs.

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

· Other Operation and Maintenance expenses decreased $24 million primarily due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.

· Depreciation and Amortization expenses decreased $3 million primarily due to a decrease in amortization of regulatory assets related to the Lawton settlement which was fully recovered in August 2010.

· Income Tax Expense increased $12 million primarily due to an increase in pretax book income.  

139

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Reconciliation of Six Months Ended June 30, 2010 to Six Months Ended June 30, 2011
Net Income
(in millions)
Six Months Ended June 30, 2010	$	20
Changes in Gross Margin:
Retail Margins (a)		(2)
Off-system Sales		(1)
Other Revenues		(2)
Total Change in Gross Margin		(5)
Changes in Expenses and Other:
Other Operation and Maintenance		40
Depreciation and Amortization		6
Other Income		1
Interest Expense		3
Total Change in Expenses and Other		50
Income Tax Expense		(18)
Six Months Ended June 30, 2011	$	47

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

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

·	Retail Margins decreased $2 million primarily due to the following:
	·	A $10 million decrease primarily due to revenue decreases from rate riders.  This decrease in retail margins had corresponding decreases to riders/trackers recognized in other expense items.
	This decrease was partially offset by:
	·	A $6 million increase primarily due to decreased capacity and fuel costs.
	·	A $4 million increase in weather-related usage primarily due to a 21% increase in cooling degree days, partially offset by lower industrial rates.
·	Other Revenues decreased $2 million primarily due to lower gains on the sale of emission allowances.

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

· Other Operation and Maintenance expenses decreased $40 million primarily due to the following:

· A $23 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.

· A $7 million decrease in maintenance of overhead lines primarily due to a decrease in vegetation management activities.

· A $5 million decrease in operation expenses due to lower employee-related expenses.

· A $4 million decrease in plant maintenance expenses resulting primarily from the 2011 deferral of generation maintenance expenses as a result of PSO’s base rate case.

· Depreciation and Amortization expenses decreased $6 million primarily due to a decrease in amortization of regulatory assets related to the Lawton settlement which was fully recovered in August 2010.

· Interest Expense decreased $3 million primarily due to 2010 Oklahoma income tax settlements and lower interest on long-term debt in 2011.

· Income Tax Expense increased $18 million primarily due to an increase in pretax book income.

140

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 227 for additional discussion of liquidity.

Credit Ratings

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

CASH FLOW

Cash flows for the six months ended June 30, 2011 and 2010 were as follows:

	2011		2010
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	470	$	796
Net Cash Flows from Operating Activities		218,684		8,473
Net Cash Flows Used for Investing Activities		(64,693)		(46,697)
Net Cash Flows from (Used for) Financing Activities		(153,488)		38,517
Net Increase in Cash and Cash Equivalents		503		293
Cash and Cash Equivalents at End of Period	$	973	$	1,089

Operating Activities

Net Cash Flows from Operating Activities were $219 million in 2011.  PSO produced Net Income of $47 million during the period and had noncash expense items of $48 million for Depreciation and Amortization and $34 million for Deferred Income Taxes, partially offset by a $19 million increase in the deferral of 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 relates to a number of items.  The $33 million inflow from Accounts Receivable, Net was primarily due to decreases in affiliated receivables.  The $30 million inflow from Accounts Payable was primarily due to increases related to fuel, purchased power and affiliated payables.The $16 million inflow from Accrued Taxes, Net was the result of an increase in property tax accruals.

Net Cash Flows from Operating Activities were $8 million in 2010.  PSO produced Net Income of $20 million during the period and had noncash expense items of $54 million for Depreciation and Amortization and $33 million for Deferred Income Taxes, partially offset by a $19 million increase in the deferral of 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 relates to a $38 million inflow from Accounts Payable primarily due to increases related to purchased power and affiliated payables.  The $100 million outflow from Fuel Over/Under-Recovery, Net was the result of higher fuel costs in relation to commission-approved fuel recovery rates.

141

Investing Activities

Net Cash Flows Used for Investing Activities during 2011 and 2010 were $65 million and $47 million, respectively.  Construction Expenditures of $65 million and $107 million in 2011 and 2010, respectively, were primarily for  projects to improve generation and service reliability for transmission and distribution in addition to customer service work.  Construction Expenditures in 2010 also included storm restoration work.  During 2010, PSO had a net decrease of $63 million in loans to the Utility Money Pool.

Financing Activities

Net Cash Flows Used for Financing Activities were $153 million during 2011.  PSO retired $275 million of Senior Unsecured Notes.  PSO had a net decrease of $91 million in borrowings from the Utility Money Pool.  In addition, PSO paid $33 million in common stock dividends.  These decreases were partially offset by the issuance of $250 million of Senior Unsecured Notes.

Net Cash Flows from Financing Activities were $39 million during 2010.  PSO had a net increase of $66 million in borrowings from the Utility Money Pool.  This increase was partially offset by $25 million paid in common stock dividends.

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

Issuances
		Principal		Interest	Due
	Type of Debt	Amount		Rate	Date
		(in thousands)		(%)
	Senior Unsecured Notes	$	250,000	4.40	2021
	Notes Payable		1,187	3.00	2026

Retirements
		Principal		Interest	Due
	Type of Debt	Amount Paid		Rate	Date
		(in thousands)		(%)
	Senior Unsecured Notes	$	200,000	6.00	2032
	Senior Unsecured Notes		75,000	4.70	2011

CONTRACTUAL OBLIGATION INFORMATION

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of market risk.

142

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
	Three Months Ended				Six Months Ended
	2011		2010		2011		2010
REVENUES
Electric Generation, Transmission and Distribution	$	322,028	$	322,394	$	606,615	$	550,945
Sales to AEP Affiliates		5,785		4,481		8,581		13,151
Other Revenues		775		811		1,395		1,345
TOTAL REVENUES		328,588		327,686		616,591		565,441
EXPENSES
Fuel and Other Consumables Used for Electric Generation		100,796		88,615		192,544		129,587
Purchased Electricity for Resale		46,018		53,555		87,197		98,535
Purchased Electricity from AEP Affiliates		9,111		10,471		25,722		21,463
Other Operation		48,736		70,837		93,140		120,499
Maintenance		25,152		27,038		45,873		57,977
Depreciation and Amortization		24,096		26,920		47,959		54,208
Taxes Other Than Income Taxes		10,494		10,985		21,090		21,285
TOTAL EXPENSES		264,403		288,421		513,525		503,554
OPERATING INCOME		64,185		39,265		103,066		61,887
Other Income (Expense):
Interest Income		28		93		80		275
Carrying Costs Income		1,876		819		2,523		1,686
Allowance for Equity Funds Used During Construction		284		119		650		366
Interest Expense		(14,258)		(15,765)		(30,196)		(33,128)
INCOME BEFORE INCOME TAX EXPENSE		52,115		24,531		76,123		31,086
Income Tax Expense		20,555		9,042		29,174		11,458
NET INCOME		31,560		15,489		46,949		19,628
Preferred Stock Dividend Requirements		49		49		98		103
EARNINGS ATTRIBUTABLE TO COMMON STOCK	$	31,511	$	15,440	$	46,851	$	19,525
The common stock of PSO is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

143

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
									Accumulated
									Other
			Common		Paid-in		Retained		Comprehensive
			Stock		Capital		Earnings		Income (Loss)		Total
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2009		$	157,230	$	364,231	$	290,880	$	(599)	$	811,742
Common Stock Dividends								(25,375)				(25,375)
Preferred Stock Dividends								(103)				(103)
Gain on Reacquired Preferred Stock						76						76
SUBTOTAL – COMMON
	SHAREHOLDER'S EQUITY											786,340
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
		Cash Flow Hedges, Net of Tax of $39								72		72
NET INCOME								19,628				19,628
TOTAL COMPREHENSIVE INCOME												19,700
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2010		$	157,230	$	364,307	$	285,030	$	(527)	$	806,040
TOTAL COMMON SHAREHOLDER'S
	EQUITY – DECEMBER 31, 2010		$	157,230	$	364,307	$	312,441	$	8,494	$	842,472
Common Stock Dividends								(32,500)				(32,500)
Preferred Stock Dividends								(98)				(98)
SUBTOTAL – COMMON
	SHAREHOLDER'S EQUITY											809,874
COMPREHENSIVE INCOME
Other Comprehensive Loss, Net of Taxes:
		Cash Flow Hedges, Net of Tax of $407								(756)		(756)
NET INCOME								46,949				46,949
TOTAL COMPREHENSIVE INCOME												46,193
TOTAL COMMON SHAREHOLDER'S
	EQUITY – JUNE 30, 2011		$	157,230	$	364,307	$	326,792	$	7,738	$	856,067
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

144

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
June 30, 2011 and December 31, 2010
(in thousands)
(Unaudited)
			2011		2010
CURRENT ASSETS
Cash and Cash Equivalents			$	973	$	470
Advances to Affiliates				110		-
Accounts Receivable:
	Customers			41,221		43,049
	Affiliated Companies			34,822		65,070
	Miscellaneous			4,353		5,497
	Allowance for Uncollectible Accounts			(354)		(971)
		Total Accounts Receivable		80,042		112,645
Fuel				21,806		20,176
Materials and Supplies				48,361		46,247
Risk Management Assets				490		14,225
Accrued Tax Benefits				31,824		38,589
Regulatory Asset for Under-Recovered Fuel Costs				37,317		37,262
Prepayments and Other Current Assets				14,564		9,416
TOTAL CURRENT ASSETS				235,487		279,030
PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			1,336,982		1,330,368
	Transmission			680,619		663,994
	Distribution			1,728,067		1,686,470
Other Property, Plant and Equipment				237,963		235,406
Construction Work in Progress				43,372		59,091
Total Property, Plant and Equipment				4,027,003		3,975,329
Accumulated Depreciation and Amortization				1,290,500		1,255,064
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				2,736,503		2,720,265
OTHER NONCURRENT ASSETS
Regulatory Assets				261,716		263,545
Long-term Risk Management Assets				685		252
Deferred Charges and Other Noncurrent Assets				30,431		20,979
TOTAL OTHER NONCURRENT ASSETS				292,832		284,776
TOTAL ASSETS			$	3,264,822	$	3,284,071
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

145

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
June 30, 2011 and December 31, 2010
(Unaudited)
		2011		2010
			(in thousands)
CURRENT LIABILITIES
Advances from Affiliates		$	-	$	91,382
Accounts Payable:
	General		93,693		69,155
	Affiliated Companies		57,990		53,179
Long-term Debt Due Within One Year – Nonaffiliated			233		25,000
Risk Management Liabilities			876		922
Customer Deposits			44,161		41,217
Accrued Taxes			43,701		25,390
Accrued Interest			13,124		9,238
Other Current Liabilities			43,262		38,095
TOTAL CURRENT LIABILITIES			297,040		353,578
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			945,417		946,186
Long-term Risk Management Liabilities			159		197
Deferred Income Taxes			686,476		660,783
Regulatory Liabilities and Deferred Investment Tax Credits			329,669		336,961
Employee Benefits and Pension Obligations			95,247		98,107
Deferred Credits and Other Noncurrent Liabilities			49,865		40,905
TOTAL NONCURRENT LIABILITIES			2,106,833		2,083,139
TOTAL LIABILITIES			2,403,873		2,436,717
Cumulative Preferred Stock Not Subject to Mandatory Redemption			4,882		4,882
Rate Matters (Note 3)
Commitments and Contingencies (Note 4)
COMMON SHAREHOLDER’S EQUITY
Common Stock – Par Value – $15 Per Share:
	Authorized – 11,000,000 Shares
	Issued – 10,482,000 Shares
	Outstanding – 9,013,000 Shares		157,230		157,230
Paid-in Capital			364,307		364,307
Retained Earnings			326,792		312,441
Accumulated Other Comprehensive Income (Loss)			7,738		8,494
TOTAL COMMON SHAREHOLDER’S EQUITY			856,067		842,472
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$	3,264,822	$	3,284,071
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

146

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
				2011		2010
OPERATING ACTIVITIES
Net Income				$	46,949	$	19,628
Adjustments to Reconcile Net Income to Net Cash Flows from Operating
	Activities:
		Depreciation and Amortization			47,959		54,208
		Deferred Income Taxes			33,821		33,402
		Carrying Costs Income			(2,523)		(1,686)
		Allowance for Equity Funds Used During Construction			(650)		(366)
		Mark-to-Market of Risk Management Contracts			(292)		(2,448)
		Property Taxes			(18,742)		(18,532)
		Fuel Over/Under-Recovery, Net			(55)		(99,776)
		Change in Other Noncurrent Assets			8,705		(13,891)
		Change in Other Noncurrent Liabilities			21,377		2,900
		Changes in Certain Components of Working Capital:
			Accounts Receivable, Net		32,603		(1,789)
			Fuel, Materials and Supplies		(3,744)		(3,280)
			Accounts Payable		29,830		37,817
			Accrued Taxes, Net		16,468		4,838
			Other Current Assets		(3,070)		2,760
			Other Current Liabilities		10,048		(5,312)
Net Cash Flows from Operating Activities					218,684		8,473
INVESTING ACTIVITIES
Construction Expenditures					(65,343)		(107,213)
Change in Advances to Affiliates, Net					(110)		62,695
Other Investing Activities					760		(2,179)
Net Cash Flows Used for Investing Activities					(64,693)		(46,697)
FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated					247,554		-
Change in Advances from Affiliates, Net					(91,382)		66,229
Retirement of Long-term Debt – Nonaffiliated					(275,000)		-
Retirement of Cumulative Preferred Stock					-		(301)
Principal Payments for Capital Lease Obligations					(2,068)		(2,040)
Dividends Paid on Common Stock					(32,500)		(25,375)
Dividends Paid on Cumulative Preferred Stock					(98)		(103)
Other Financing Activities					6		107
Net Cash Flows from (Used for) Financing Activities					(153,488)		38,517
Net Increase in Cash and Cash Equivalents					503		293
Cash and Cash Equivalents at Beginning of Period					470		796
Cash and Cash Equivalents at End of Period				$	973	$	1,089
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts				$	12,293	$	30,152
Net Cash Paid (Received) for Income Taxes					383		(8,073)
Noncash Acquisitions Under Capital Leases					415		13,434
Construction Expenditures Included in Current Liabilities at June 30,					8,319		13,534
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

147

PUBLIC SERVICE COMPANY OF OKLAHOMA

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to PSO’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries.  Listed below are the notes that apply to PSO.  The footnotes begin on page 162.

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

148

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

149

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

MANAGEMENT’S DISCUSSION AND ANALYSIS

EXECUTIVE OVERVIEW

Regulatory Activity

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW coal generating unit in Arkansas, which is expected to be in service in 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  SWEPCo’s share of construction costs is currently estimated to be $1.3 billion, excluding AFUDC, plus an additional $124 million for transmission, excluding AFUDC.  The APSC, LPSC and PUCT approved SWEPCo’s original application to build the Turk Plant.  In June 2010, the APSC issued an order which reversed and set aside the previously granted Certificate of Environmental Compatibility and Public Need.  Various proceedings are pending that challenge the Turk Plant’s construction and its approved wetlands and air permits.  In 2010, the motions for preliminary injunction were partially granted.  According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop.  Mitigation measures required by the permit are authorized and may be completed.  The preliminary injunction affects portions of the water intake and portions of two transmission lines.  In July 2011, the U.S. Eighth Circuit Court of Appeals affirmed the preliminary injunction.  Management is unable to predict the timing or the outcome related to this remand proceeding.

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

Litigation and Environmental Issues

In the ordinary course of business, SWEPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2010 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 162.  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 227 for additional discussion of relevant factors.

150

RESULTS OF OPERATIONS
KWH Sales/Degree Days
Summary of KWH Energy Sales
		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2011		2010		2011		2010
		(in millions of KWH)
Retail:
	Residential		1,645		1,390		3,249		2,989
	Commercial		1,664		1,598		3,029		2,912
	Industrial		1,425		1,383		2,676		2,529
	Miscellaneous		22		21		41		40
Total Retail			4,756		4,392		8,995		8,470
Wholesale			1,787		1,738		3,665		3,551
Total KWHs			6,543		6,130		12,660		12,021

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.

Summary of Heating and Cooling Degree Days
		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2011		2010		2011		2010
		(in degree days)
Actual - Heating (a)			17		5		866		1,043
Normal - Heating (b)			28		28		773		766
Actual - Cooling (c)			934		893		985		898
Normal - Cooling (b)			700		692		731		723
(a)	Western Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the thirty-year average of degree days.
(c)	Western Region cooling degree days are calculated on a 65 degree temperature base.

151

Second Quarter of 2011 Compared to Second Quarter of 2010

Reconciliation of Second Quarter of 2010 to Second Quarter of 2011
Net Income
(in millions)
Second Quarter of 2010	$	27
Changes in Gross Margin:
Retail Margins (a)		16
Transmission Revenues		(1	)
Total Change in Gross Margin		15
Changes in Expenses and Other:
Other Operation and Maintenance		25
Depreciation and Amortization		(3	)
Taxes Other Than Income Taxes		(1	)
Other Income		(1	)
Interest Expense		1
Total Change in Expenses and Other		21
Income Tax Expense		(12	)
Second Quarter of 2011	$	51

(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 $16 million primarily due to:
	·	An $11 million increase in retail sales primarily due to increases in residential and commercial customers.
	·	A $7 million increase due to rate increases, including revenue increases from base rates in Texas and rate riders in Arkansas.
	These increases were partially offset by:
	·	A $2 million decrease in wholesale fuel recovery.

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

·	Other Operation and Maintenance expenses decreased $25 million primarily due to:
	·	A $29 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
	·	A $3 million decrease in operation expenses due to lower employee-related expenses.
	These decreases were partially offset by:
	·	A $5 million increase related to scheduled generation plant maintenance.
·	Depreciation and Amortization expenses increased $3 million primarily due to a greater depreciation base, including the addition of the Stall Unit which was placed into service in June 2010.
·	Income Tax Expense increased $12 million primarily due to an increase in pretax book income.

152

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

Reconciliation of Six Months Ended June 30, 2010 to Six Months Ended June 30, 2011
Net Income
(in millions)
Six Months Ended June 30, 2010	$	58
Changes in Gross Margin:
Retail Margins (a)		38
Off-system Sales		(1)
Transmission Revenues		(3)
Other Revenues		1
Total Change in Gross Margin		35
Changes in Expenses and Other:
Other Operation and Maintenance		17
Depreciation and Amortization		(3)
Taxes Other Than Income Taxes		(2)
Allowance for Equity Funds Used During Construction		(6)
Interest Expense		(3)
Total Change in Expenses and Other		3
Income Tax Expense		(15)
Six Months Ended June 30, 2011	$	81

(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 $38 million primarily due to:

· A $20 million increase due to rate increases, including revenue increases from base rates in Texas and rate riders in Arkansas.

· A $16 million increase in retail sales primarily due to increases in residential and commercial customers.

· Transmission Revenues decreased $3 million due to lower rates in the SPP region.

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

·	Other Operation and Maintenance expenses decreased $17 million primarily due to:
	·	A $29 million decrease due to expenses related to the cost reduction initiatives recorded in the second quarter of 2010.
	·	A $5 million decrease in operation expenses due to lower employee-related expenses.
	These decreases were partially offset by:
	·	A $10 million increase in distribution maintenance resulting from increased storm-related expenses.
	·	An $8 million increase related to scheduled generation plant maintenance.
·	Depreciation and Amortization expenses increased $3 million primarily due to a greater depreciation base, including the addition of the Stall Unit which was placed into service in June 2010.
·	Allowance for Equity Funds Used During Construction decreased $6 million primarily due to the completed construction of the Stall Unit in June 2010.
·	Interest Expense increased $3 million primarily due to increased long-term debt outstanding.
·	Income Tax Expense increased $15 million primarily due an increase in pretax book income and other book/tax differences which are accounted for on a flow-through basis.

153

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 227 for additional discussion of liquidity.

Credit Ratings

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

CASH FLOW

Cash flows for the six months ended June 30, 2011 and 2010 were as follows:

	2011		2010
	(in thousands)
Cash and Cash Equivalents at Beginning of Period	$	1,514	$	1,661
Net Cash Flows from Operating Activities		209,863		80,809
Net Cash Flows Used for Investing Activities		(194,249)		(371,560)
Net Cash Flows from (Used for) Financing Activities		(15,039)		290,652
Net Increase (Decrease) in Cash and Cash Equivalents		575		(99)
Cash and Cash Equivalents at End of Period	$	2,089	$	1,562

Operating Activities

Net Cash Flows from Operating Activities were $210 million in 2011.  SWEPCo produced Net Income of $81 million during the period and had noncash items of $66 million for Depreciation and Amortization and $24 million for Deferred Income Taxes, partially offset by $22 million in Allowance for Equity Funds Used During Construction and a $20 million increase in the deferral of 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 relates to a number of items.  The $38 million inflow from Accounts Payable was primarily due to increases related to fuel and affiliated payables. The $25 million inflow from Accrued Taxes, Net was the result of an increase in property tax accruals.  The $25 million outflow from Fuel Over/Under-Recovery, Net was primarily due to lower fuel cost recovery and SIA refunds in Arkansas and Louisiana.

Net Cash Flows from Operating Activities were $81 million in 2010.  SWEPCo produced Net Income of $58 million during the period and had a noncash item of $63 million for Depreciation and Amortization, partially offset by $28 million in Allowance for Equity Funds Used During Construction and an $18 million increase in the deferral of 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 relates to a number of items.  The $32 million inflow from Accrued Taxes, Net was the result of an increase in property tax accruals.  The $25 million outflow from Accounts Receivable, Net was primarily due to increased affiliated and jointly owned receivables, partially offset by lower construction-related receivables.  The $20 million inflow from Fuel, Materials and Supplies was primarily due to a decrease in coal and lignite inventories.  The $16 million outflow from Fuel Over/Under-Recovery, Net was the result of higher fuel costs in relation to commission-approved fuel recovery rates in Texas.

154

Investing Activities

Net Cash Flows Used for Investing Activities during 2011 and 2010 were $194 million and $372 million, respectively.  Construction Expenditures of $238 million and $176 million in 2011 and 2010, respectively, were primarily for generation projects at the Turk Plant and Stall Unit, as well as projects to improve service reliability for distribution and transmission.  The Stall Unit was placed in service in the second quarter of 2010.  During 2011, SWEPCo decreased loans to the Utility Money Pool by $52 million.  During 2010, SWEPCo increased loans to the Utility Money Pool by $193 million.

Financing Activities

Net Cash Flows Used for Financing Activities were $15 million during 2011.  SWEPCo paid $7 million in principal payments for capital lease obligations.  SWEPCo had a $6 million net decrease in revolving credit facility balances.

Net Cash Flows from Financing Activities were $291 million during 2010.  SWEPCo issued $350 million of Senior Unsecured Notes and $54 million of Pollution Control Bonds.  These increases were partially offset by a $54 million retirement of Pollution Control Bonds and a $50 million retirement of Notes Payable – Affiliated.

In July 2011, SWEPCo retired $41 million of 4.5% Pollution Control Bonds due in 2011.

CONTRACTUAL OBLIGATION INFORMATION

A summary of contractual obligations is included in the 2010 Annual Report and has not changed significantly from year-end.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.

See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 227 for a discussion of market risk.

155

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
		Three Months Ended				Six Months Ended
		2011		2010		2011		2010
REVENUES
Electric Generation, Transmission and Distribution		$	388,197	$	347,657	$	735,264	$	680,735
Sales to AEP Affiliates			10,671		13,231		26,250		22,564
Other Revenues			666		579		975		972
TOTAL REVENUES			399,534		361,467		762,489		704,271
EXPENSES
Fuel and Other Consumables Used for Electric Generation			139,713		135,051		273,725		257,939
Purchased Electricity for Resale			39,691		22,841		78,280		64,727
Purchased Electricity from AEP Affiliates			5,116		4,211		7,227		13,963
Other Operation			50,722		82,265		104,790		140,518
Maintenance			34,790		28,133		64,181		45,552
Depreciation and Amortization			32,718		29,868		66,008		63,111
Taxes Other Than Income Taxes			16,730		15,580		33,696		31,475
TOTAL EXPENSES			319,480		317,949		627,907		617,285
OPERATING INCOME			80,054		43,518		134,582		86,986
Other Income (Expense):
Interest Income			167		169		111		248
Allowance for Equity Funds Used During Construction			11,573		12,462		22,169		27,979
Interest Expense			(20,835)		(21,475)		(43,260)		(40,019)
INCOME BEFORE INCOME TAX EXPENSE AND
	EQUITY EARNINGS		70,959		34,674		113,602		75,194
Income Tax Expense			20,571		8,707		33,967		18,863
Equity Earnings of Unconsolidated Subsidiary			683		738		1,263		1,457
NET INCOME			51,071		26,705		80,898		57,788
Less: Net Income Attributable to Noncontrolling Interest			1,036		1,273		2,118		2,424
NET INCOME ATTRIBUTABLE TO SWEPCo
	SHAREHOLDERS		50,035		25,432		78,780		55,364
Less: Preferred Stock Dividend Requirements			57		57		114		114
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON
	SHAREHOLDER	$	49,978	$	25,375	$	78,666	$	55,250
The common stock of SWEPCo is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

156

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
			SWEPCo Common Shareholder
									Accumulated
									Other
			Common		Paid-in		Retained		Comprehensive		Noncontrolling
			Stock		Capital		Earnings		Income (Loss)		Interest		Total
TOTAL EQUITY – DECEMBER 31, 2009			$	135,660	$	674,979	$	726,478	$	(12,991)	$	31	$	1,524,157
Common Stock Dividends – Nonaffiliated												(1,892)		(1,892)
Preferred Stock Dividends								(114)						(114)
SUBTOTAL – EQUITY														1,522,151
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
	Cash Flow Hedges, Net of Tax of $48									90				90
	Amortization of Pension and OPEB Deferred Costs,
		Net of Tax of $253								469				469
NET INCOME								55,364				2,424		57,788
TOTAL COMPREHENSIVE INCOME														58,347
TOTAL EQUITY – JUNE 30, 2010			$	135,660	$	674,979	$	781,728	$	(12,432)	$	563	$	1,580,498
TOTAL EQUITY – DECEMBER 31, 2010			$	135,660	$	674,979	$	868,840	$	(12,491)	$	361	$	1,667,349
Common Stock Dividends – Nonaffiliated												(2,126)		(2,126)
Preferred Stock Dividends								(114)						(114)
SUBTOTAL – EQUITY														1,665,109
COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Taxes:
	Cash Flow Hedges, Net of Tax of $137									255				255
	Amortization of Pension and OPEB Deferred Costs,
		Net of Tax of $681								1,265				1,265
NET INCOME								78,780				2,118		80,898
TOTAL COMPREHENSIVE INCOME														82,418
TOTAL EQUITY – JUNE 30, 2011			$	135,660	$	674,979	$	947,506	$	(10,971)	$	353	$	1,747,527
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

157

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2011 and December 31, 2010
(in thousands)
(Unaudited)
			2011		2010
CURRENT ASSETS
Cash and Cash Equivalents			$	2,089	$	1,514
Advances to Affiliates				34,684		86,222
Accounts Receivable:
	Customers			35,361		34,434
	Affiliated Companies			31,179		43,219
	Miscellaneous			19,953		17,739
	Allowance for Uncollectible Accounts			(666)		(588)
		Total Accounts Receivable		85,827		94,804
Fuel
	(June 30, 2011 and December 31, 2010 amounts include $30,966 and
	$35,055, respectively, related to Sabine)			96,458		91,777
Materials and Supplies				54,643		50,395
Risk Management Assets				1,613		1,209
Deferred Income Tax Benefits				11,719		15,529
Accrued Tax Benefits				39,235		37,900
Regulatory Asset for Under-Recovered Fuel Costs				9,470		758
Prepayments and Other Current Assets				24,451		24,270
TOTAL CURRENT ASSETS				360,189		404,378
PROPERTY, PLANT AND EQUIPMENT
Electric:
	Generation			2,302,981		2,297,463
	Transmission			957,937		943,724
	Distribution			1,635,200		1,611,129
Other Property, Plant and Equipment
	(June 30, 2011 and December 31, 2010 amounts include $229,068 and
	$224,857, respectively, related to Sabine)			636,532		632,158
Construction Work in Progress				1,268,429		1,071,603
Total Property, Plant and Equipment				6,801,079		6,556,077
Accumulated Depreciation and Amortization
	(June 30, 2011 and December 31, 2010 amounts include $96,217 and
	$91,840, respectively, related to Sabine)			2,183,940		2,130,351
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET				4,617,139		4,425,726
OTHER NONCURRENT ASSETS
Regulatory Assets				349,174		332,698
Long-term Risk Management Assets				296		438
Deferred Charges and Other Noncurrent Assets				102,471		80,327
TOTAL OTHER NONCURRENT ASSETS				451,941		413,463
TOTAL ASSETS			$	5,429,269	$	5,243,567
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

158

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
June 30, 2011 and December 31, 2010
(Unaudited)
		2011		2010
			(in thousands)
CURRENT LIABILITIES
Accounts Payable:
	General	$	172,556	$	162,271
	Affiliated Companies		90,178		64,474
Short-term Debt – Nonaffiliated			-		6,217
Long-term Debt Due Within One Year – Nonaffiliated			61,135		41,135
Risk Management Liabilities			1,378		4,067
Customer Deposits			54,411		48,245
Accrued Taxes			62,715		30,516
Accrued Interest			40,034		39,856
Obligations Under Capital Leases			13,921		13,265
Regulatory Liability for Over-Recovered Fuel Costs			-		16,432
Other Current Liabilities			66,334		67,118
TOTAL CURRENT LIABILITIES			562,662		493,596
NONCURRENT LIABILITIES
Long-term Debt – Nonaffiliated			1,708,511		1,728,385
Long-term Risk Management Liabilities			156		338
Deferred Income Taxes			645,390		624,333
Regulatory Liabilities and Deferred Investment Tax Credits			417,571		393,673
Asset Retirement Obligations			55,217		56,632
Employee Benefits and Pension Obligations			92,697		96,314
Obligations Under Capital Leases			112,632		115,399
Deferred Credits and Other Noncurrent Liabilities			82,211		62,852
TOTAL NONCURRENT LIABILITIES			3,114,385		3,077,926
TOTAL LIABILITIES			3,677,047		3,571,522
Cumulative Preferred Stock Not Subject to Mandatory Redemption			4,695		4,696
Rate Matters (Note 3)
Commitments and Contingencies (Note 4)
EQUITY
Common Stock – Par Value – $18 Per Share:
	Authorized –  7,600,000 Shares
	Outstanding  – 7,536,640 Shares		135,660		135,660
Paid-in Capital			674,979		674,979
Retained Earnings			947,506		868,840
Accumulated Other Comprehensive Income (Loss)			(10,971)		(12,491)
TOTAL COMMON SHAREHOLDER’S EQUITY			1,747,174		1,666,988
Noncontrolling Interest			353		361
TOTAL EQUITY			1,747,527		1,667,349
TOTAL LIABILITIES AND EQUITY		$	5,429,269	$	5,243,567
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

159

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2011 and 2010
(in thousands)
(Unaudited)
				2011		2010
OPERATING ACTIVITIES
Net Income				$	80,898	$	57,788
Adjustments to Reconcile Net Income to Net Cash Flows from
	Operating Activities:
		Depreciation and Amortization			66,008		63,111
		Deferred Income Taxes			23,562		(5,742)
		Allowance for Equity Funds Used During Construction			(22,169)		(27,979)
		Mark-to-Market of Risk Management Contracts			(1,863)		715
		Property Taxes			(20,356)		(18,105)
		Fuel Over/Under-Recovery, Net			(25,144)		(15,619)
		Change in Other Noncurrent Assets			17,791		(11,364)
		Change in Other Noncurrent Liabilities			27,255		17,928
		Changes in Certain Components of Working Capital:
			Accounts Receivable, Net		9,062		(24,733)
			Fuel, Materials and Supplies		(8,929)		20,096
			Accounts Payable		37,823		(10,505)
			Accrued Taxes, Net		24,753		32,339
			Other Current Assets		(1,485)		(825)
			Other Current Liabilities		2,657		3,704
Net Cash Flows from Operating Activities					209,863		80,809
INVESTING ACTIVITIES
Construction Expenditures					(237,834)		(176,107)
Change in Advances to Affiliates, Net					51,538		(193,437)
Other Investing Activities					(7,953)		(2,016)
Net Cash Flows Used for Investing Activities					(194,249)		(371,560)
FINANCING ACTIVITIES
Issuance of Long-term Debt – Nonaffiliated					-		399,411
Credit Facility Borrowings					27,413		50,339
Retirement of Long-term Debt – Nonaffiliated					-		(53,500)
Retirement of Long-term Debt – Affiliated					-		(50,000)
Retirement of Cumulative Preferred Stock					(1)		-
Credit Facility Repayments					(33,630)		(48,512)
Principal Payments for Capital Lease Obligations					(6,655)		(5,944)
Dividends Paid on Common Stock – Nonaffiliated					(2,126)		(1,892)
Dividends Paid on Cumulative Preferred Stock					(114)		(114)
Other Financing Activities					74		864
Net Cash Flows from (Used for) Financing Activities					(15,039)		290,652
Net Increase (Decrease) in Cash and Cash Equivalents					575		(99)
Cash and Cash Equivalents at Beginning of Period					1,514		1,661
Cash and Cash Equivalents at End of Period				$	2,089	$	1,562
SUPPLEMENTARY INFORMATION
Cash Paid for Interest, Net of Capitalized Amounts				$	37,681	$	29,649
Net Cash Paid for Income Taxes					8,026		19,663
Noncash Acquisitions Under Capital Leases					4,378		380
Construction Expenditures Included in Current Liabilities at June 30,					96,959		85,870
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 162.

160

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

INDEX OF 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 162.

	Footnote Reference
Significant Accounting Matters	Note 1
New Accounting Pronouncements	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

161

INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF

REGISTRANT SUBSIDIARIES

The condensed notes to condensed financial statements that follow are a combined presentation for the Registrant Subsidiaries.  The following list indicates the registrants to which the footnotes apply:
1.	Significant Accounting Matters	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
2.	New Accounting Pronouncements	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
3.	Rate Matters	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
4.	Commitments, Guarantees and Contingencies	APCo, CSPCo, I&M, OPCo, PSO, SWEPCo
5.	Acquisition	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

162

1.  SIGNIFICANT ACCOUNTING MATTERS

General

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

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary.  Net income for the three and six months ended June 30, 2011 is not necessarily indicative of results that may be expected for the year ending December 31, 2011.  The condensed financial statements are unaudited and should be read in conjunction with the audited 2010 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2010 as filed with the SEC on February 25, 2011.

Variable Interest Entities

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

SWEPCo is the primary beneficiary of Sabine.  I&M is the primary beneficiary of DCC Fuel.  APCo, CSPCo, I&M, OPCo, PSO and SWEPCo each hold a significant variable interest in AEPSC.  I&M and CSPCo each hold a significant variable interest in AEGCo.  SWEPCo holds a significant variable interest in DHLC.

Sabine is a mining operator providing mining services to SWEPCo.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee.  In addition, SWEPCo determines how much coal will be mined 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 June 30, 2011 and 2010 were $30 million and $30 million, respectively, and for the six months ended June 30, 2011 and 2010 were $64 million and $73 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on SWEPCo’s Condensed Consolidated Balance Sheets.

163

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

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
June 30, 2011 and December 31, 2010
(in millions)
	Sabine
ASSETS	2011		2010
Current Assets	$	42	$	50
Net Property, Plant and Equipment		140		139
Other Noncurrent Assets		34		34
Total Assets	$	216	$	223
LIABILITIES AND EQUITY
Current Liabilities	$	46	$	33
Noncurrent Liabilities		170		190
Total Liabilities and Equity	$	216	$	223

I&M has a nuclear fuel lease agreement with DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC (collectively DCC Fuel).  DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions.  Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC are separate legal entities from I&M, the assets of which are not available to satisfy the debts of I&M.  Payments on DCC Fuel LLC and DCC Fuel II LLC leases are made semi-annually and began in April 2010 and October 2010, respectively.  Payments on the DCC Fuel III LLC lease are made monthly and began in January 2011.  Payments on the DCC Fuel leases for the three months ended June 30, 2011 and 2010 were $38 million and $22 million, respectively, and for the six months ended June 30, 2011 and 2010 were $43 million and $22 million, respectively.  The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the 48, 54 and 54 month lease term, respectively.  Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The capital leases are eliminated upon consolidation.  See the 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 DCC Fuel that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
VARIABLE INTEREST ENTITIES
June 30, 2011 and December 31, 2010
(in millions)
	DCC Fuel
ASSETS	2011		2010
Current Assets	$	85	$	92
Net Property, Plant and Equipment		127		173
Other Noncurrent Assets		80		112
Total Assets	$	292	$	377
LIABILITIES AND EQUITY
Current Liabilities	$	76	$	79
Noncurrent Liabilities		216		298
Total Liabilities and Equity	$	292	$	377

164

DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  SWEPCo and CLECO share the executive board seats and its voting rights equally.  Each entity guarantees a 50% share of DHLC’s debt.  SWEPCo and CLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee.  SWEPCo’s total billings from DHLC for the three months ended June 30, 2011 and 2010 were $15 million and $13 million, respectively, and for the six months ended June 30, 2011 and 2010 were $29 million and $26 million, respectively.  SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC.  SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s Condensed Consolidated Balance Sheets.

SWEPCo’s investment in DHLC was:

	June 30, 2011				December 31, 2010
	As Reported on				As Reported on
	the Consolidated		Maximum		the Consolidated		Maximum
	Balance Sheet		Exposure		Balance Sheet		Exposure
	(in millions)
Capital Contribution from SWEPCo	$	8	$	8	$	6	$	6
Retained Earnings		1		1		2		2
SWEPCo's Guarantee of Debt		-		54		-		48
Total Investment in DHLC	$	9	$	63	$	8	$	56

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

Total AEPSC billings to the Registrant Subsidiaries were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
Company	2011		2010		2011		2010
	(in thousands)
APCo	$	47,352	$	66,769	$	92,293	$	126,158
CSPCo		28,456		39,883		54,501		74,494
I&M		31,006		40,932		62,834		75,180
OPCo		44,536		62,675		82,368		��111,779
PSO		21,130		31,443		40,548		55,179
SWEPCo		31,560		43,636		61,393		78,537

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

	June 30, 2011				December 31, 2010
	As Reported on the		Maximum		As Reported on the		Maximum
Company	Balance Sheet		Exposure		Balance Sheet		Exposure
	(in thousands)
APCo	$	17,942	$	17,942	$	23,230	$	23,230
CSPCo		11,581		11,581		12,676		12,676
I&M		11,674		11,674		12,980		12,980
OPCo		17,010		17,010		16,927		16,927
PSO		8,119		8,119		9,384		9,384
SWEPCo		11,932		11,932		14,465		14,465

AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP.  AEGCo owns a 50% ownership interest in Rockport Plant Unit 1, leases a 50% interest in Rockport Plant Unit 2 and owns 100% of the Lawrenceburg Generating Station.  AEGCo sells all the output from the Rockport Plant to I&M and KPCo.   AEGCo leases the Lawrenceburg Generating Station to CSPCo.  AEP guarantees all the debt obligations of AEGCo.  I&M and CSPCo are considered to have a significant interest in AEGCo due to these transactions.  I&M and CSPCo are exposed to losses to the extent they cannot recover the costs of AEGCo through their normal business operations.  In the event AEGCo would require financing or other support outside the billings to I&M, CSPCo and KPCo, this financing would be provided by AEP.  For additional information regarding AEGCo’s lease, see the “Rockport Lease” section of Note 13 in the 2010 Annual Report.

Total billings from AEGCo were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
Company	2011		2010		2011		2010
	(in thousands)
CSPCo	$	40,983	$	21,474	$	92,017	$	36,701
I&M		49,852		48,502		102,673		104,651

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

	June 30, 2011				December 31, 2010
	As Reported in				As Reported in
	the Consolidated		Maximum		the Consolidated		Maximum
Company	Balance Sheet		Exposure		Balance Sheet		Exposure
	(in thousands)
CSPCo	$	13,392	$	13,392	$	18,165	$	18,165
I&M		26,956		26,956		27,899		27,899

2.  NEW ACCOUNTING PRONOUNCEMENTS

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

Pronouncements Issued During 2011

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

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

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

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adjustments from other comprehensive income to net income must be presented on the face of the financial statements.  This standard must be retrospectively applied to all reporting periods presented in financial reports issued after the effective date.

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2011.  This standard will change the presentation of the financial statements but will not affect the calculation of net income or comprehensive income.  The Registrant Subsidiaries will adopt ASU 2011-05 effective January 1, 2012.

3.  RATE MATTERS

As discussed in the 2010 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within the 2010 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition.  The following discusses ratemaking developments in 2011 and updates the 2010 Annual Report.

Regulatory Assets Not Yet Being Recovered

			APCo				I&M
			June 30,		December 31,		June 30,		December 31,
			2011		2010		2011		2010
Noncurrent Regulatory Assets (excluding fuel)			(in thousands)				(in thousands)
Regulatory assets not yet being recovered
	pending future proceedings to determine
	the recovery method and timing:
Regulatory Assets Currently Not Earning a Return
	Virginia Environmental Rate Adjustment Clause		$	65,348	$	55,724	$	-	$	-
	Deferred Wind Power Costs			37,839		28,584		-		-
	Storm Related Costs			25,225		25,225		-		-
	Mountaineer Carbon Capture and Storage
		Product Validation Facility (a)		19,254		59,866		-		-
	Special Rate Mechanism for Century Aluminum			12,708		12,628		-		-
	Other Regulatory Assets Not Yet Being Recovered			1,469		604		-		-
Total Regulatory Assets Not Yet Being Recovered			$	161,843	$	182,631	$	-	$	-
			CSPCo				OPCo
			June 30,		December 31,		June 30,		December 31,
			2011		2010		2011		2010
Noncurrent Regulatory Assets (excluding fuel)			(in thousands)				(in thousands)
Regulatory assets not yet being recovered
	pending future proceedings to determine
	the recovery method and timing:
Regulatory Assets Currently Earning a Return
	Line Extension Carrying Costs (b)		$	37,240	$	33,709	$	23,709	$	21,246
	Customer Choice Deferrals (b)			30,108		29,716		29,492		29,141
	Storm Related Costs (b)			19,609		19,122		11,301		11,021
	Acquisition of Monongahela Power (b)			8,592		7,929		-		-
	Economic Development Rider			3,143		3,057		3,143		3,057
	Other Regulatory Assets Not Yet Being Recovered			291		287		396		391
Regulatory Assets Currently Not Earning a Return
	Acquisition of Monongahela Power (b)			4,052		4,052		-		-
	Other Regulatory Assets Not Yet Being Recovered			48		43		65		58
Total Regulatory Assets Not Yet Being Recovered			$	103,083	$	97,915	$	68,106	$	64,914

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		PSO				SWEPCo
		June 30,		December 31,		June 30,		December 31,
		2011		2010		2011		2010
Noncurrent Regulatory Assets (excluding fuel)		(in thousands)				(in thousands)
Regulatory assets not yet being recovered
	pending future proceedings to determine
	the recovery method and timing:
Regulatory Assets Currently Earning a Return
	Storm Related Costs (c)	$	18,426	$	-	$	-	$	-
Regulatory Assets Currently Not Earning a Return
	Storm Related Costs (c)		-		17,256		1,239		1,239
	Other Regulatory Assets Not Yet Being Recovered		-		574		740		613
Total Regulatory Assets Not Yet Being Recovered		$	18,426	$	17,830	$	1,979	$	1,852

(a) APCo wrote off a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC in March 2011.  See "Mountaineer Carbon Capture and Storage Project Product Validation Facility" section below.

(b) Requested to be recovered in a distribution asset recovery rider.  See the "2011 Ohio Distribution Base Rate Case" section below.

(c) In June 2011, an order was received approving recovery of PSO storm costs and associated carrying costs with recovery to begin in August 2011.  Starting in the second quarter of 2011, and in accordance with the order received from the OCC, PSO recorded a return on its storm related costs.

CSPCo and OPCo Rate Matters

Ohio Electric Security Plan Filings

2009 – 2011 ESPs

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

The order provided a FAC for the three-year period of the ESP.  The FAC was phased in to avoid having the resultant rate increases exceed the ordered annual caps described above.  The FAC is subject to quarterly true-ups, annual accounting audits and prudency reviews.  See the “2009 Fuel Adjustment Clause Audit” section below.  The order allowed CSPCo and OPCo to defer any unrecovered FAC costs resulting from the annual caps and to accrue associated carrying charges at their respective weighted average cost of capital.  Any deferred FAC regulatory asset balance at the end of the three-year ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018.  That recovery will include deferrals associated with the Ormet interim arrangement and is subject to the PUCO’s ultimate decision regarding the Ormet interim arrangement deferrals plus related carrying charges.  See the “Ormet Interim Arrangement” section below.  The FAC deferral as of June 30, 2011 was $27 million and $526 million for CSPCo and OPCo, respectively, excluding $388 thousand and $43 million, respectively, of unrecognized equity carrying costs.

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

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

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In April 2011, the Supreme Court of Ohio (the Court) issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged which resulted in three reversals, only two of which may have a prospective impact through a remand proceeding.  First, the Court concluded that the PUCO's decision amounted to retroactive ratemaking.  Since the pertinent revenues were collected in 2009 and the Ohio Consumers’ Counsel did not successfully pursue the remedy of obtaining a stay of the order prior to the revenues being collected, there is no remand to the PUCO or refund to customers for this error.  Second, the Court held that the PUCO's conclusion that the POLR charge is cost-based conflicted with the evidence and remanded the issue to the PUCO for further consideration.  Third, the Court reversed the order’s legal basis for a carrying charge associated with certain environmental investments and remanded that issue to the PUCO to determine whether an alternative legal basis supports the charge.  Pursuant to a May 2011 PUCO order, CSPCo and OPCo implemented rates subject to refund and filed remand testimony in June 2011.  For the month ended June 30, 2011, CSPCo and OPCo recorded $14 million and $16 million, respectively, of revenues subject to refund.  In June 2011, the Ohio Consumers’ Counsel and the IEU filed testimony recommending a complete denial of collection of any POLR charges and carrying charges on certain environmental investments collected from 2009 through 2011.  They proposed unfavorable adjustments for CSPCo and OPCo of up to $370 million and $417 million, respectively, excluding carrying costs.  The proposed adjustments include a reduction of deferred FAC and other regulatory assets for the period prior to June 2011 of up to $298 million and $336 million for CSPCo and OPCo, respectively, which management believes is without merit and violates the Court’s decision.  The proposed adjustments also include refunds and rate reductions of related revenues beginning in June 2011 of $72 million and $81 million for CSPCo and OPCo, respectively.  Hearings were held in July 2011.

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

In January 2011, the PUCO issued an order on CSPCo’s and OPCo’s 2009 SEET filings and determined that OPCo’s 2009 earnings were not significantly excessive but determined relevant CSPCo earnings exceeded the PUCO determined threshold by 2.13%.  As a result, the PUCO ordered CSPCo to refund $43 million ($28 million net of tax) of its earnings to customers, which was recorded as a revenue provision on CSPCo’s December 2010 books.  The PUCO ordered that the significantly excessive earnings be applied first to CSPCo’s FAC deferral, including unrecognized equity carrying costs, as of the date of the order, with any remaining balance to be credited to CSPCo’s customers on a per kilowatt basis.  That credit began with the first billing cycle in February 2011 and will continue through December 2011.  Several parties, including CSPCo and OPCo, filed requests for rehearing with the PUCO, which were denied in March 2011.  In May 2011, the IEU and the Ohio Energy Group filed appeals with the Court challenging the PUCO’s SEET decisions.  CSPCo and OPCo are required to file their 2010 SEET filings with the PUCO in 2011.  Based upon the approach in the PUCO 2009 order, management does not currently believe that CSPCo or OPCo had any significantly excessive earnings in 2010.

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

January 2012 – May 2014 ESP

In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing on a combined company basis for generation.  The rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  The ESP also includes alternative energy resource requirements and addresses provisions regarding distribution service, energy efficiency requirements, economic development, job retention in Ohio, generation resources and other matters.  The SSO presents redesigned generation rates by customer class.  Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013.  The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESP could impact the outcome of the January 2012-May 2014 ESP, though the nature and extent of that impact is not presently known.  In July 2011, various intervenors filed testimony that generally asserts CSPCo's and OPCo's proposed SSO rates are higher than the

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market-rate offer, and objects to certain proposed riders as well as to the proposed non-bypassable nature of certain riders.  Additionally, the IEU and Ohio Consumers' Counsel object to revenues collected in the period 2009 through 2011 for POLR and carrying charges related to environmental investments and propose similar adjustments as discussed in the ESP remand proceeding.  See the "2009-2011 ESPs" section above.  A hearing for this case is scheduled for August 2011 and a decision is expected in the fourth quarter of 2011.

2011 Ohio Distribution Base Rate Case

In February 2011, CSPCo and OPCo filed with the PUCO for annual increases in distribution rates of $34 million and $60 million, respectively.  The requested increase is based upon an 11.15% return on common equity to be effective January 2012.

In addition to the annual increases, CSPCo and OPCo requested recovery of the projected December 31, 2012 balances of certain distribution regulatory assets of $216 million and $159 million, respectively, including approximately $102 million and $84 million, respectively, of unrecognized equity carrying costs.  These assets and unrecognized carrying costs would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013.  The actual balance of these distribution regulatory assets as of June 30, 2011 was $100 million and $64 million for CSPCo and OPCo, respectively, excluding $61 million and $45 million, respectively, of unrecognized equity carrying costs.  If CSPCo and OPCo are not ultimately permitted to fully recover their deferrals, it would reduce future net income and cash flows and impact financial condition.

Proposed CSPCo and OPCo Merger

In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo.  Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company.  In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo.  CSPCo and OPCo requested the reorganization transaction be effective in October 2011.  In July 2011, the FERC issued an order approving the proposed merger.  A decision is pending from the PUCO.  Management is unable to predict the outcome of this proceeding.

Requested Sporn Unit 5 Shutdown and Proposed Distribution Rider

In October 2010, OPCo filed an application with the PUCO for the approval of a December 2010 closure of Sporn Unit 5 and the simultaneous establishment of a new non-bypassable distribution rider outside the rate caps established in the 2009 – 2011 ESP proceeding.  The proposed rider would recover the net book value of the unit as well as related materials and supplies as of December 2010, which was estimated to total $59 million, as well as future closure costs incurred after December 2010.  OPCo also requested authority to record the future closure costs as a regulatory asset or regulatory liability with a weighted average cost of capital carrying charge to be included in the proposed non-bypassable distribution rider after the costs are incurred.  Pending PUCO approval, Sporn Unit 5 continues to operate.  In April 2011, intervenors filed comments opposing OPCo’s application.  A PUCO decision is pending as to whether a hearing will be ordered.  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 CSPCo and OPCo for the period of January 2009 through December 2009.  In May 2010, the outside consultant provided its confidential audit report to the PUCO.  The audit report included a recommendation that the PUCO review whether any proceeds from a 2008 coal contract settlement agreement which totaled $72 million should reduce OPCo’s FAC under-recovery balance.  Of the total proceeds, approximately $58 million was recognized as a reduction to fuel expense prior to 2009 and $14 million was recognized as a reduction to fuel expense in 2009 and 2010.  Hearings were held in August 2010.  A decision from the PUCO is pending.  Management is unable to predict the outcome of this proceeding.  If the PUCO orders any portion of the $58 million previously recognized gains or any future adjustments be used to reduce the FAC deferral, it would reduce future net income and cash flows and impact financial condition.

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2010 Fuel Adjustment Clause Audit

In May 2011, the PUCO-selected outside consultant issued their results of the 2010 FAC audit for CSPCo and OPCo.  The audit report included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balances and determine whether the carrying costs on the balances should be net of accumulated income taxes.  As of June 30, 2011, the amount of OPCo’s carrying costs that could potentially be at risk is estimated to be $13 million, excluding $16 million of unrecognized equity carrying costs. The amount of carrying costs for CSPCo that could potentially be at risk is immaterial.  A decision from the PUCO is pending.  Management is unable to predict the outcome of this proceeding.  If the PUCO order results in a reduction in the carrying charges related to the FAC deferrals, it would reduce future net income and cash flows and impact financial condition.

Ormet Interim Arrangement

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

Economic Development Rider

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

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

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As of June 30, 2011, CSPCo and OPCo have incurred EDR costs of $59 million and $55 million, respectively, including carrying costs.  Of these costs, CSPCo and OPCo have collected $50 million and $39 million, respectively, through the EDR, which CSPCo and OPCo began collecting in January 2010.  The remaining $9 million and $16 million for CSPCo and OPCo, respectively, are recorded as deferred EDR regulatory assets.  If CSPCo and OPCo are not ultimately permitted to recover their deferrals or are required to refund EDR revenue collected, it would reduce future net income and cash flows and impact financial condition.

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 June 30, 2011, CSPCo and OPCo have collected $12 million and $12 million, respectively, in pre-construction costs authorized in a June 2006 PUCO order and incurred $11 million and $11 million, respectively, in pre-construction costs.  As a result, CSPCo and OPCo established net regulatory liabilities of approximately $1 million and $1 million, respectively.  The order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant before June 2011, any pre-construction costs that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest.  As of June 2011, there were no active IGCC projects at other AEP sites.  In June 2011, CSPCo and OPCo filed a recommendation with the PUCO to refund to customers $2 million and $2 million, respectively, for the over-recovered pre-construction costs including interest.  Intervenors have filed motions with the PUCO requesting all collected pre-construction costs be refunded to Ohio ratepayers with interest.

Management cannot predict the outcome of any cost recovery litigation concerning the Ohio IGCC plant or what effect, if any, such litigation would have on future net income and cash flows.  However, if CSPCo and OPCo are required to refund pre-construction costs collected in excess of the over-recovered pre-construction costs, it would reduce future net income and cash flows and impact financial condition.

SWEPCo Rate Matters

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in service in 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, plus an additional $124 million for transmission, excluding AFUDC.  SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $124 million for transmission, excluding AFUDC.  As of June 30, 2011, excluding costs attributable to its joint owners, SWEPCo has capitalized approximately $1.2 billion of expenditures (including AFUDC and capitalized interest of $175 million and related transmission costs of $79 million).  As of June 30, 2011, the joint owners and SWEPCo have contractual construction commitments of approximately $211 million (including related transmission costs of $11 million).  SWEPCo’s share of the contractual construction commitments is $157 million.  If the plant is cancelled, the joint owners and SWEPCo would incur contractual construction cancellation fees, based on construction status as of June 30, 2011, of approximately $101million (including related transmission cancellation fees of $1 million).  SWEPCo’s share of the contractual construction cancellation fees would be approximately $74 million.

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

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

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

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

A wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009.  In 2010, the Sierra Club, the Audubon Society and others filed a complaint in the Federal District Court for the Western District of Arkansas against the U.S. Army Corps of Engineers challenging the process used and the terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts, and sought a preliminary injunction to halt construction and for a temporary restraining order.  In July 2010, the Hempstead County Hunting Club (Hunting Club) also filed a complaint with the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of the Interior and the U.S. Fish and Wildlife Service seeking a temporary restraining order and preliminary injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws.  The plaintiffs’ federal law claims challenge the process used and terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts.  The plaintiffs’ state law claims challenge SWEPCo's ability to construct the Turk Plant without obtaining a certificate from the APSC.  In October 2010, the Federal District Court certified issues relating to the state law claims to the Arkansas Supreme Court, including whether those claims are within the primary jurisdiction of the APSC.  In May 2011, the Arkansas Supreme Court determined that these claims must first be brought before the APSC and that the federal court does not have jurisdiction to hear the state law claims.  In 2010, the motions for preliminary injunction were partially granted.  According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop.  Mitigation measures required by the permit are authorized and may be completed.  The preliminary injunction affects portions of the water intake and portions of two transmission lines.  SWEPCo appealed the issuance of the preliminary injunction to the U.S. Eighth Circuit Court of Appeals, and in July 2011, the Court of Appeals affirmed the preliminary injunction.  Management is unable to predict the timing or the outcome related to this remand proceeding.

In July 2011, SWEPCo reached an agreement in principle that would resolve all pending matters between SWEPCo, the Hunting Club and several other parties.  As a result, the Hunting Club’s challenge to the U.S. Army Corps of Engineers permit in the Federal District Court for the Western District of Arkansas will be dismissed and the Hunting Club’s appeal of the air permit will be withdrawn.  Additional judicial and administrative proceedings will also be terminated.  SWEPCo was unable to resolve claims by the Sierra Club and the Audubon Society, so their challenges to the wetlands and air permits will continue.

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

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Louisiana Fuel Adjustment Clause Audit

Consultants for the LPSC issued their audit report of SWEPCo’s Louisiana retail FAC recommending that the LPSC discontinue SWEPCo’s tiered sharing mechanism related to the off-system sales margins and reduce the FAC.  In April 2011, a settlement agreement was filed with the LPSC which resulted in an immaterial impact for SWEPCo.  The settlement agreement deferred the off-system sales issue to SWEPCo’s upcoming formula rate plan (FRP) extension filing, which is expected to be filed in the second half of 2011.  In June 2011, the LPSC approved the settlement agreement.

Louisiana 2008 Formula Rate Filing

In April 2008, SWEPCo filed its first formula rate filing under an approved three-year FRP.  SWEPCo requested an increase in its annual Louisiana retail rates of $11 million to be effective in August 2008 in order to earn the approved formula return on common equity of 10.565%.  In August 2008, as provided by the FRP, SWEPCo implemented the FRP rates, subject to refund.  During 2009, SWEPCo recorded a provision for refund of approximately $1 million after reaching a settlement in principle with intervenors.  SWEPCo began refunding customers in August 2010.  In March 2011, the LPSC approved the settlement stipulation.

Louisiana 2009 Formula Rate Filing

In April 2009, SWEPCo filed the second FRP which would increase its annual Louisiana retail rates by an additional $4 million effective in August 2009.  SWEPCo implemented the FRP rate increase as filed in August 2009, subject to refund.  Consultants for the LPSC objected to certain components of SWEPCo’s FRP calculation.  A settlement stipulation was reached by the parties and approved by the LPSC in March 2011.  The settlement stipulation provided for a $2 million refund, which was recorded in 2010 as a provision in Other Current Liabilities on SWEPCo's Condensed Consolidated Balance Sheets.  The refund to customers, with interest, will begin in August 2011.

Louisiana 2010 Formula Rate Filing

In April 2010, SWEPCo filed the third FRP which would decrease its annual Louisiana retail rates by $3 million effective in August 2010 pursuant to the approved FRP, subject to refund.  In October 2010, consultants for the LPSC objected to certain components of SWEPCo’s FRP calculations.  Hearings are scheduled for November 2011.  SWEPCo believes the rates as filed are in compliance with the FRP methodology previously approved by the LPSC.  If the LPSC disagrees with SWEPCo, it could result in refunds which could reduce future net income and cash flows.

APCo Rate Matters

2011 Virginia Biennial Base Rate Case

In March 2011, APCo filed a generation and distribution base rate request with the Virginia SCC to increase annual base rates by $126 million based upon an 11.65% return on common equity to be effective no later than February 2012.  The return on common equity includes a requested 0.5% renewable portfolio standards incentive as allowed by law.APCo proposed to mitigate the requested base rate increase by $51 million by maintaining current depreciation rates until the next biennial filing.  If approved, APCo’s net base rate increase would be $75 million.  In July 2011, an Attorney General witness recommended an $80 million reduction in APCo’s requested rate year capacity charges.

Rate Adjustment Clauses

In 2007, the Virginia law governing the regulation of electric utility service was amended to, among other items, provide for rate adjustment clauses (RACs) beginning in January 2009 for the timely and current recovery of costs of: (a) transmission services billed by an RTO, (b) demand side management and energy efficiency programs, (c) renewable energy programs, (d) environmental compliance projects and (e) new generation facilities, including major unit modifications.  In March 2011, APCo filed for approval of an environmental RAC, a renewable energy program RAC and a generation RAC simultaneous with the 2011 Virginia base rate filing.  The environmental RAC

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is requesting recovery of environmental compliance costs incurred from January 2009 through December 2010 of $38 million annually based on a two-year amortization.  The renewable energy program RAC is requesting the incremental portion of deferred wind power costs for the Camp Grove and Fowler Ridge projects of $6 million.  The generation RAC is requesting recovery of the Dresden Plant, currently under construction, which APCo has requested to purchase from AEGCo.

In accordance with Virginia law, APCo is deferring incremental environmental costs incurred after December 2008 and renewable energy costs incurred after August 2009 which are not being recovered in current revenues.  As of June 30, 2011, APCo has deferred $65 million of environmental costs (excluding $15 million of unrecognized equity carrying costs) and $38 million of renewable energy costs.  APCo plans to seek recovery of non-incremental deferred wind power costs ($32 million as of June 30, 2011) in future rate proceedings.  If the Virginia SCC were to disallow a portion of APCo’s deferred costs, it would reduce future net income and cash flows.

2010 West Virginia Base Rate Case

In May 2010, APCo filed a request with the WVPSC to increase APCo’s annual base rates by $140 million based upon an 11.75% return on common equity to be effective March 2011.  In March 2011, the WVPSC modified and approved a settlement agreement which increased annual base rates by approximately $46 million based upon a 10% return on common equity.  The settlement agreement also resulted in a pretax write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility in the first quarter of 2011.  See “Mountaineer Carbon Capture and Storage Project” section below.  In addition, the WVPSC allowed APCo to defer and amortize $18 million of previously expensed 2009 incremental storm expenses and $14 million of previously expensed costs related to the 2010 cost reduction initiatives, each over a period of seven years.

Mountaineer Carbon Capture and Storage Project

Product Validation Facility (PVF)

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

In APCo’s May 2010 West Virginia base rate filing, APCo requested rate base treatment of the PVF, including recovery of the related asset retirement obligation regulatory asset amortization and accretion.  In March 2011, a WVPSC order denied the request for rate base treatment of the PVF largely due to its experimental operation.  The base rate order provided that should APCo construct a commercial scale carbon capture and sequestration (CCS) facility, only the West Virginia portion of the PVF costs, based on load sharing among certain AEP operating companies, may be considered used and useful plant in service and included in future rate base.  As a result, APCo recorded a pretax write-off of $41 million ($26 million net of tax) in the first quarter of 2011 recorded to Other Operation expense on the Condensed Consolidated Statements of Operations.  See “2010 West Virginia Base Rate Case” section above.  As of June 30, 2011, APCo has recorded a noncurrent regulatory asset of $19 million related to the PVF.  If APCo cannot recover its remaining PVF investment and related accretion expenses, it would reduce future net income and cash flows.

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

During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale CCS facility at the Mountaineer Plant.  AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project.  The DOE agreed to fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million.  In July 2011, management informed the DOE that it will complete a Front-End Engineering and Design (FEED) study during the third quarter of 2011, but it is postponing any further CCS project activities because of the uncertainty about the regulation of CO2.  As of June 30, 2011, the project has incurred $30 million in total costs and has received $10 million of DOE eligible funding resulting in a $20 million net balance recorded in Deferred Charges and Other Noncurrent Assets on the Condensed Consolidated Balance

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Sheets.  In June 2011, FEED study costs were allocated among the Registrant Subsidiaries and KPCo.  Requests for recovery are in process in Michigan, Ohio and Virginia.  If the Registrant Subsidiaries are unable to recover the allocated costs of the CCS project, it would reduce future net income and cash flows.

APCo’s Filings for an IGCC Plant

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

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

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

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

In September 2009, the WVPSC issued an order approving APCo’s March 2009 ENEC request.  The approved order provided for recovery of an under-recovered balance plus a projected increase in ENEC costs over a four-year phase-in period with an overall increase of $320 million and a first-year increase of $112 million, effective October 2009.

In June 2010, the WVPSC approved a settlement agreement for $86 million, including $9 million of construction surcharges related to APCo’s second year ENEC increase.  The settlement agreement allows APCo to accrue a weighted average cost of capital carrying charge on the excess under-recovery balance due to the ENEC phase-in as adjusted for the impacts of Accumulated Deferred Income Taxes.  The new rates became effective in July 2010.

In June 2011, the WVPSC issued an order approving an $88 million annual increase including $7 million of construction surcharges and $7 million of carrying charges related to APCo’s third year ENEC increase.  The order also allows APCo to accrue a fixed annual carrying cost rate of 4%.  The new rates became effective in July 2011.  Additionally, the order approved APCo’s request to purchase the Dresden Plant, currently under construction, from AEGCo and approved deferral of post in-service Dresden Plant costs, including a return, for future recovery.  As of June 30, 2011, APCo’s ENEC under-recovery balance was $387 million, excluding $8 million of unrecognized equity carrying costs, which is included in noncurrent regulatory assets.  If the WVPSC were to disallow a portion of APCo’s deferred ENEC costs, it could reduce future net income and cash flows and impact financial condition.

WPCo Merger with APCo

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

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PSO Rate Matters

PSO 2008 Fuel and Purchased Power

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

I&M Rate Matters

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

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

2011 Michigan Base Rate Case

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

FERC Rate Matters

Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund – Affecting APCo, CSPCo, I&M and OPCo

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

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

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

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

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

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

Settlements approved by the FERC consumed $10 million of the reserve for refunds applicable to $112 million of SECA revenue.  In December 2010, the FERC issued an order approving a settlement agreement resulting in the collection of $2 million of previously deemed uncollectible SECA revenue.  Therefore, the AEP East companies reduced their reserves for net refunds for SECA settlements by $2 million.  The balance in the reserve for future settlements as of June 30, 2011 was $32 million.  APCo’s, CSPCo’s, I&M’s and OPCo’s reserve balances as of June 30, 2011 were:

Company	June 30, 2011
	(in millions)
APCo	$	10.0
CSPCo		5.6
I&M		5.9
OPCo		7.6

In August 2010, the affected companies, including the AEP East companies, filed a compliance filing with the FERC.  If the compliance filing is accepted, the AEP East companies would have to pay refunds of approximately $20 million including estimated interest of $5 million.  The AEP East companies could also potentially receive payments up to approximately $10 million including estimated interest of $3 million.  A decision is pending from the FERC.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of potential refund payments and potential payments to be received are as follows:

	Potential		Potential
	Refund		Payments to
Company	Payments		be Received
	(in millions)
APCo	$	6.4	$	3.2
CSPCo		3.5		1.8
I&M		3.7		1.9
OPCo		4.8		2.4

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

Possible Termination of the Interconnection Agreement – Affecting APCo, CSPCo, I&M and OPCo

In December 2010, each of the AEP Power Pool members gave notice to AEPSC and each other of their decision to terminate the Interconnection Agreement effective January 2014 or such other date approved by FERC, subject to state regulatory input.  No filings have been made at the FERC.  It is unknown at this time whether the AEP Power Pool will be replaced by a new agreement among some or all of the members, whether individual companies will

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enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers or if each company will choose to operate independently.  This decision to terminate is subject to management’s ongoing evaluation.  The AEP Power Pool members may revoke their notices of termination.  If any of the AEP Power Pool members experience decreases in revenues or increases in costs as a result of the termination of the AEP Power Pool and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows.

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

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

Modification of the Transmission Coordination Agreement (TCA) – Affecting PSO and SWEPCo

PSO, SWEPCo and TNC are parties to the TCA, originally dated January 1, 1997, as amended.  The TCA provides for the allocation among the parties of revenues collected for transmission and ancillary services provided under the Open Access Transmission Tariff (OATT).

In April 2011, the FERC accepted proposed revisions to the TCA.  Under this amendment, TNC was removed from the TCA.  In addition, the amended TCA provides for the allocation of SPP OATT revenues between PSO and SWEPCo based on the SPP formula rate revenue requirements for transmission investment and related expenses of each company.  The amended TCA is effective May 1, 2011.

4.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business.  In addition, their business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation cannot be predicted.  For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on the financial statements.  The Commitments, Guarantees and Contingencies note within the 2010 Annual Report should be read in conjunction with this report.

GUARANTEES

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

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

Certain Registrant Subsidiaries enter into standby letters of credit with third parties.  These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves.

AEP has two $1.5 billion credit facilities, under which up to $1.35 billion may be issued as letters of credit.  In July 2011, AEP replaced the $1.5 billion facility due in 2012 with a new $1.75 billion facility maturing in July 2016 and extended the $1.5 billion facility due in 2013 to expire in June 2015.  As of June 30, 2011, the maximum future payments of the letters of credit were as follows:

Company	Amount		Maturity
	(in thousands)
I&M	$	150	March 2012
SWEPCo		4,448	March 2012

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In March 2011, the Registrant Subsidiaries and certain other companies in the AEP System terminated a $478 million credit agreement that was scheduled to mature in April 2011 and was used to support variable rate Pollution Control Bonds.  In March 2011, certain variable rate Pollution Control Bonds were remarketed and supported by bilateral letters of credit for $361 million while others were reacquired and are being held in trust.  As of June 30, 2011, $472 million of variable rate Pollution Control Bonds were remarketed or reacquired as follows:

	June 30, 2011
			Reacquired		Bilateral		Maturity of
			and Held		Letters of		Bilateral Letters
Company	Remarketed		in Trust		Credit Issued		of Credit
	(in thousands)
APCo	$	229,650	$	-	$	232,293	March 2013 to March 2014
I&M		77,000		-		77,886	March 2013
OPCo		50,000		115,000		50,575	March 2013

Guarantees of Third-Party Obligations – Affecting SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of approximately $65 million.  In July 2011, SWEPCo’s guarantee was increased to $100 million due to expansion of the mining area.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), a consolidated variable interest entity.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million.  As of June 30, 2011, SWEPCo has collected approximately $51 million through a rider for final mine closure and reclamation costs, of which $1 million is recorded in Other Current Liabilities, $30 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $20 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.

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

Contracts

The Registrant Subsidiaries enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of June 30, 2011, there were no material liabilities recorded for any indemnifications.

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

Master Lease Agreements

The Registrant Subsidiaries lease certain equipment under master lease agreements.  In December 2010, management signed a new master lease agreement with GE Capital Commercial Inc. (GE) to replace existing operating and capital leases with GE.  These assets were included in existing master lease agreements that were to be terminated in 2011 since GE exercised the termination provision related to these leases in 2008.  Certain previously leased assets were not included in the 2010 refinancing, but were purchased in January 2011.

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For equipment under the GE master lease agreements, the lessor is guaranteed receipt of up to 78% of the unamortized balance of the equipment at the end of the lease term.  If the fair value of the leased equipment is below the unamortized balance at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the fair value and the unamortized balance, with the total guarantee not to exceed 78% of the unamortized balance.  For equipment under other master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term.  If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee.  At June 30, 2011, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:

	Maximum
Company	Potential Loss
	(in thousands)
APCo	$	1,450
CSPCo		986
I&M		1,867
OPCo		1,381
PSO		768
SWEPCo		2,727

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

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease is accounted for as an operating lease.  In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignments are accounted for as operating leases for I&M and SWEPCo.  The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years.  I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options.  The future minimum lease obligations are $16 million for I&M and $18 million for SWEPCo for the remaining railcars as of June 30, 2011.

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

ENVIRONMENTAL CONTINGENCIES

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

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

In September 2009, the Second Circuit Court of Appeals issued a ruling on appeal remanding the cases to the Federal District Court for the Southern District of New York.  The Second Circuit held that the issues of climate change and global warming do not raise political questions and that Congress’ refusal to regulate CO2 emissions does not mean that plaintiffs must wait for an initial policy determination by Congress or the President’s

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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.  In 2010, the U.S. Supreme Court granted the defendants’ petition for review.  In June 2011, the U.S. Supreme Court reversed and remanded the case to the Court of Appeals, finding that plaintiffs’ federal common law claims are displaced by the regulatory authority granted to the Federal EPA under the CAA.

In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina.  The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims.  The court granted petitions for rehearing.  An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court’s decision in place.  Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision.  The petition was denied in January 2011.  Plaintiffs refiled their complaint in federal district court.  Management believes the claims are without merit, and in addition to other defenses, are barred by the doctrine of collateral estoppel and the applicable statute of limitations.  Management intends to vigorously defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.

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

In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies.  The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together.  The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance.  The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million.  In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim.  The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court.  The plaintiffs appealed the decision.  Briefing is complete and no date has been set for oral argument.  The defendants requested that the court defer setting this case for oral argument until after the Supreme Court issues its decision in the CO2 public nuisance case discussed above.  The court entered an order deferring argument until after June 2011 and the parties requested supplemental briefing on the impact of the Supreme Court’s decision.   Management believes the action is without merit and intends to defend against the claims.  Management is unable to determine a range of potential losses that are reasonably possible of occurring.

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

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

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

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

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

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

NUCLEAR CONTINGENCIES – AFFECTING I&M

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

Cook Plant Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in significant turbine damage and a small fire on the electric generator.  This equipment, located in the turbine building, is separate and isolated from the nuclear reactor.  The turbine rotors that caused the vibration were installed in 2006 and are within the vendor’s warranty period.  The warranty provides for the repair or replacement of the turbine rotors if the damage was caused by a defect in materials or workmanship.  Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $408 million.  Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process.  I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power.  The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors.  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 insurance through NEIL.  As of June 30, 2011, I&M recorded $60 million on its Condensed Consolidated Balance Sheet representing amounts under NEIL insurance policies.  Through June 30, 2011, I&M received partial payments of $203 million from NEIL for the cost incurred to date to repair the property damage.

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

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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.

I&M and Fort Wayne reached a settlement agreement.  The agreement, signed in October 2010, is subject to approval by the IURC.  I&M filed a petition with the IURC seeking approval of the agreement, including recovery in rates of payments made to Fort Wayne.  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.  In April 2011, the Indiana Office of Utility Consumer Counselor (OUCC) filed comments opposing portions of the settlement agreement.  An agreement with the OUCC was reached and hearing before the IURC occurred in June 2011.  IURC approval of the agreement is expected during the third quarter of 2011.  If the agreement is not approved by the IURC, the parties have the right to terminate the agreement and pursue other relief.

Coal Transportation Rate Dispute – Affecting PSO

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

This matter was submitted to an arbitration board.  In April 2006, the arbitration board filed its decision, denying BNSF’s underpayments claim.  PSO filed a request for an order confirming the arbitration award and a request for entry of judgment on the award with the U.S. District Court for the Northern District of Oklahoma.  On July 14, 2006, the U.S. District Court issued an order confirming the arbitration award.  BNSF pursued the matter by filing a Motion to Reconsider, which was granted, but in August 2009, the U.S. District Court upheld the arbitration board’s decision.  BNSF further pursued the decision by appealing to the U.S. Court of Appeals, where in December 2010, the Tenth Circuit Court of Appeals affirmed the U.S. District Court’s order confirming the arbitration award.  PSO then sought and received approval for reimbursement for attorneys’ fees and expenses related to the proceedings at the district court.  In July 2011, the Magistrate for the U.S. District Court also recommended for PSO to be awarded the full amount of its requested appellate attorneys’ fees.

5.  ACQUISITION

2010

Valley Electric Membership Corporation – Affecting SWEPCo

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

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6.  BENEFIT PLANS

The Registrant Subsidiaries participate in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans.  Substantially all employees are covered by the qualified plan or both the qualified and a nonqualified pension plan.  The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide medical and life insurance benefits for retired employees.

Components of Net Periodic Benefit Cost

The following tables provide the components of net periodic benefit cost by Registrant Subsidiary for the plans for the three and six months ended June 30, 2011 and 2010:

APCo					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended June 30,				Three Months Ended June 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	1,800	$	3,227	$	1,246	$	1,430
Interest Cost		8,076		8,489		4,867		5,075
Expected Return on Plan Assets		(10,458)		(10,951)		(4,496)		(4,407)
Amortization of Transition Obligation		-		-		287		1,311
Amortization of Prior Service Cost (Credit)		229		229		(43)		-
Amortization of Net Actuarial Loss		4,144		2,961		1,459		1,353
Net Periodic Benefit Cost	$	3,791	$	3,955	$	3,320	$	4,762

					Other Postretirement
	Pension Plans				Benefit Plans
	Six Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	3,600	$	6,454	$	2,492	$	2,860
Interest Cost		16,146		16,978		9,734		10,150
Expected Return on Plan Assets		(20,916)		(21,902)		(8,992)		(8,813)
Amortization of Transition Obligation		-		-		573		2,622
Amortization of Prior Service Cost (Credit)		458		458		(86)		-
Amortization of Net Actuarial Loss		8,285		5,921		2,914		2,705
Net Periodic Benefit Cost	$	7,573	$	7,909	$	6,635	$	9,524

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CSPCo					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended June 30,				Three Months Ended June 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	850	$	1,468	$	608	$	690
Interest Cost		4,302		4,789		2,039		2,179
Expected Return on Plan Assets		(5,725)		(6,589)		(1,986)		(1,979)
Amortization of Transition Obligation		-		-		11		608
Amortization of Prior Service Cost (Credit)		141		141		(19)		-
Amortization of Net Actuarial Loss		2,210		1,677		578		565
Net Periodic Benefit Cost	$	1,778	$	1,486	$	1,231	$	2,063

					Other Postretirement
	Pension Plans				Benefit Plans
	Six Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	1,699	$	2,936	$	1,217	$	1,380
Interest Cost		8,604		9,578		4,079		4,357
Expected Return on Plan Assets		(11,449)		(13,178)		(3,973)		(3,958)
Amortization of Transition Obligation		-		-		22		1,216
Amortization of Prior Service Cost (Credit)		282		282		(37)		-
Amortization of Net Actuarial Loss		4,420		3,354		1,155		1,130
Net Periodic Benefit Cost	$	3,556	$	2,972	$	2,463	$	4,125

I&M					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended June 30,				Three Months Ended June 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	2,365	$	3,821	$	1,529	$	1,688
Interest Cost		6,934		7,271		3,402		3,541
Expected Return on Plan Assets		(9,214)		(8,760)		(3,471)		(3,349)
Amortization of Transition Obligation		-		-		47		704
Amortization of Prior Service Cost (Credit)		186		186		(59)		-
Amortization of Net Actuarial Loss		3,538		2,516		892		881
Net Periodic Benefit Cost	$	3,809	$	5,034	$	2,340	$	3,465

					Other Postretirement
	Pension Plans				Benefit Plans
	Six Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	4,723	$	7,642	$	3,059	$	3,375
Interest Cost		13,863		14,543		6,805		7,082
Expected Return on Plan Assets		(18,428)		(17,520)		(6,943)		(6,698)
Amortization of Transition Obligation		-		-		94		1,407
Amortization of Prior Service Cost (Credit)		372		372		(118)		-
Amortization of Net Actuarial Loss		7,072		5,032		1,783		1,763
Net Periodic Benefit Cost	$	7,602	$	10,069	$	4,680	$	6,929

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OPCo					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended June 30,				Three Months Ended June 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	1,708	$	2,845	$	1,348	$	1,357
Interest Cost		7,796		8,186		4,334		4,446
Expected Return on Plan Assets		(10,642)		(10,680)		(4,141)		(4,044)
Amortization of Transition Obligation		-		-		27		1,053
Amortization of Prior Service Cost (Credit)		227		227		(35)		-
Amortization of Net Actuarial Loss		4,004		2,861		1,267		1,154
Net Periodic Benefit Cost	$	3,093	$	3,439	$	2,800	$	3,966

					Other Postretirement
	Pension Plans				Benefit Plans
	Six Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	3,416	$	5,691	$	2,696	$	2,713
Interest Cost		15,572		16,372		8,669		8,893
Expected Return on Plan Assets		(21,284)		(21,360)		(8,283)		(8,089)
Amortization of Transition Obligation		-		-		53		2,106
Amortization of Prior Service Cost (Credit)		454		454		(70)		-
Amortization of Net Actuarial Loss		7,994		5,721		2,494		2,308
Net Periodic Benefit Cost	$	6,152	$	6,878	$	5,559	$	7,931

PSO					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended June 30,				Three Months Ended June 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	1,442	$	1,513	$	656	$	704
Interest Cost		3,338		3,722		1,511		1,590
Expected Return on Plan Assets		(4,366)		(4,935)		(1,566)		(1,528)
Amortization of Transition Obligation		-		-		-		701
Amortization of Prior Service Credit		(239)		(238)		(19)		-
Amortization of Net Actuarial Loss		1,700		1,297		388		393
Net Periodic Benefit Cost	$	1,875	$	1,359	$	970	$	1,860

					Other Postretirement
	Pension Plans				Benefit Plans
	Six Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	2,880	$	3,026	$	1,311	$	1,407
Interest Cost		6,643		7,444		3,023		3,180
Expected Return on Plan Assets		(8,732)		(9,870)		(3,132)		(3,055)
Amortization of Transition Obligation		-		-		-		1,403
Amortization of Prior Service Credit		(475)		(475)		(38)		-
Amortization of Net Actuarial Loss		3,378		2,594		776		786
Net Periodic Benefit Cost	$	3,694	$	2,719	$	1,940	$	3,721

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SWEPCo					Other Postretirement
	Pension Plans				Benefit Plans
	Three Months Ended June 30,				Three Months Ended June 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	1,644	$	1,761	$	757	$	777
Interest Cost		3,348		3,773		1,743		1,735
Expected Return on Plan Assets		(4,595)		(4,872)		(1,800)		(1,661)
Amortization of Transition Obligation		-		-		-		615
Amortization of Prior Service Cost (Credit)		(200)		(199)		64		-
Amortization of Net Actuarial Loss		1,700		1,311		446		428
Net Periodic Benefit Cost	$	1,897	$	1,774	$	1,210	$	1,894

					Other Postretirement
	Pension Plans				Benefit Plans
	Six Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(in thousands)
Service Cost	$	3,286	$	3,523	$	1,514	$	1,554
Interest Cost		6,666		7,547		3,485		3,470
Expected Return on Plan Assets		(9,190)		(9,745)		(3,600)		(3,323)
Amortization of Transition Obligation		-		-		-		1,230
Amortization of Prior Service Cost (Credit)		(398)		(398)		129		-
Amortization of Net Actuarial Loss		3,380		2,621		892		856
Net Periodic Benefit Cost	$	3,744	$	3,548	$	2,420	$	3,787

7.  BUSINESS SEGMENTS

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

8.  DERIVATIVES AND HEDGING

OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

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

STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

Trading Strategies

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

Risk Management Strategies

The strategy surrounding the use of derivative instruments focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies.  To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical forward purchase and sale contracts, financial forward purchase and sale contracts and financial swap instruments.  Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and

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Hedging.”  Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.

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

The following tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of June 30, 2011 and December 31, 2010:

Notional Volume of Derivative Instruments
June 30, 2011
Primary Risk			Unit of
Exposure			Measure	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Commodity:
	Power		MWHs		265,492		153,624		158,358		184,179		14		17
	Coal		Tons		8,572		4,602		4,071		16,841		6,473		5,204
	Natural Gas		MMBtus		2,736		1,583		1,623		1,898		24		28
	Heating Oil and
		Gasoline	Gallons		1,248		556		620		926		731		673
	Interest Rate		USD	$	41,997	$	24,295	$	24,896	$	29,320	$	283	$	322
Interest Rate and
	Foreign Currency		USD	$	-	$	-	$	-	$	-	$	-	$	100,069
Notional Volume of Derivative Instruments
December 31, 2010
Primary Risk			Unit of
Exposure			Measure	APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Commodity:
	Power		MWHs		194,217		111,959		117,862		136,657		21		34
	Coal		Tons		11,195		5,550		6,571		23,033		4,936		8,777
	Natural Gas		MMBtus		2,166		1,248		1,302		1,524		15		19
	Heating Oil and
		Gasoline	Gallons		1,054		467		521		776		616		564
	Interest Rate		USD	$	9,541	$	5,471	$	5,732	$	7,185	$	609	$	793
Interest Rate and
	Foreign Currency		USD	$	200,000	$	-	$	-	$	-	$	200,000	$	189

Fair Value Hedging Strategies

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

189

Cash Flow Hedging Strategies

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

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

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

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

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the 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.

190

According to the accounting guidance for “Derivatives and Hedging,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral.  For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the June 30, 2011 and December 31, 2010 balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:

	June 30, 2011				December 31, 2010
	Cash Collateral		Cash Collateral		Cash Collateral		Cash Collateral
	Received		Paid		Received		Paid
	Netted Against		Netted Against		Netted Against		Netted Against
	Risk Management		Risk Management		Risk Management		Risk Management
Company	Assets		Liabilities		Assets		Liabilities
	(in thousands)
APCo	$	2,825	$	10,214	$	1,809	$	16,229
CSPCo		1,635		5,906		1,042		9,347
I&M		1,676		6,050		1,087		9,757
OPCo		1,960		7,180		1,272		11,561
PSO		1		45		-		44
SWEPCo		1		44		-		72

191

The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the Condensed Balance Sheets as of June 30, 2011 and December 31, 2010:

Fair Value of Derivative Instruments
June 30, 2011
APCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	178,531	$	3,663	$	-	$	(150,380)	$	31,814
Long-term Risk Management Assets			73,791		672		-		(42,317)		32,146
Total Assets			252,322		4,335		-		(192,697)		63,960
Current Risk Management Liabilities			173,214		2,724		-		(157,436)		18,502
Long-term Risk Management Liabilities			55,201		439		-		(45,312)		10,328
Total Liabilities			228,415		3,163		-		(202,748)		28,830
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	23,907	$	1,172	$	-	$	10,051	$	35,130

Fair Value of Derivative Instruments
December 31, 2010
APCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	267,702	$	1,956	$	11,888	$	(228,304)	$	53,242
Long-term Risk Management Assets			79,560		714		-		(41,854)		38,420
Total Assets			347,262		2,670		11,888		(270,158)		91,662
Current Risk Management Liabilities			262,027		2,363		-		(236,397)		27,993
Long-term Risk Management Liabilities			61,724		701		-		(51,552)		10,873
Total Liabilities			323,751		3,064		-		(287,949)		38,866
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	23,511	$	(394)	$	11,888	$	17,791	$	52,796

192

Fair Value of Derivative Instruments
June 30, 2011
CSPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	102,340	$	2,076	$	-	$	(86,065)	$	18,351
Long-term Risk Management Assets			42,560		388		-		(24,370)		18,578
Total Assets			144,900		2,464		-		(110,435)		36,929
Current Risk Management Liabilities			99,241		1,572		-		(90,145)		10,668
Long-term Risk Management Liabilities			31,814		251		-		(26,101)		5,964
Total Liabilities			131,055		1,823		-		(116,246)		16,632
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	13,845	$	641	$	-	$	5,811	$	20,297

Fair Value of Derivative Instruments
December 31, 2010
CSPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	149,886	$	1,164	$	-	$	(127,276)	$	23,774
Long-term Risk Management Assets			45,413		412		-		(23,736)		22,089
Total Assets			195,299		1,576		-		(151,012)		45,863
Current Risk Management Liabilities			146,540		1,362		-		(131,935)		15,967
Long-term Risk Management Liabilities			35,144		404		-		(29,325)		6,223
Total Liabilities			181,684		1,766		-		(161,260)		22,190
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	13,615	$	(190)	$	-	$	10,248	$	23,673

193

Fair Value of Derivative Instruments
June 30, 2011
I&M
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	106,718	$	2,142	$	-	$	(86,519)	$	22,341
Long-term Risk Management Assets			49,448		398		-		(24,777)		25,069
Total Assets			156,166		2,540		-		(111,296)		47,410
Current Risk Management Liabilities			99,960		1,614		-		(90,697)		10,877
Long-term Risk Management Liabilities			32,385		259		-		(26,552)		6,092
Total Liabilities			132,345		1,873		-		(117,249)		16,969
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	23,821	$	667	$	-	$	5,953	$	30,441

Fair Value of Derivative Instruments
December 31, 2010
I&M
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	162,896	$	1,151	$	-	$	(136,521)	$	27,526
Long-term Risk Management Assets			56,154		429		-		(25,098)		31,485
Total Assets			219,050		1,580		-		(161,619)		59,011
Current Risk Management Liabilities			156,750		1,421		-		(141,386)		16,785
Long-term Risk Management Liabilities			37,039		421		-		(30,930)		6,530
Total Liabilities			193,789		1,842		-		(172,316)		23,315
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	25,261	$	(262)	$	-	$	10,697	$	35,696

194

Fair Value of Derivative Instruments
June 30, 2011
OPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	153,202	$	2,558	$	-	$	(133,245)	$	22,515
Long-term Risk Management Assets			55,377		467		-		(32,864)		22,980
Total Assets			208,579		3,025		-		(166,109)		45,495
Current Risk Management Liabilities			150,203		1,890		-		(138,234)		13,859
Long-term Risk Management Liabilities			42,177		305		-		(34,942)		7,540
Total Liabilities			192,380		2,195		-		(173,176)		21,399
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	16,199	$	830	$	-	$	7,067	$	24,096

Fair Value of Derivative Instruments
December 31, 2010
OPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	262,751	$	1,316	$	-	$	(233,294)	$	30,773
Long-term Risk Management Assets			63,533		503		-		(36,024)		28,012
Total Assets			326,284		1,819		-		(269,318)		58,785
Current Risk Management Liabilities			259,635		1,663		-		(239,132)		22,166
Long-term Risk Management Liabilities			50,757		493		-		(42,847)		8,403
Total Liabilities			310,392		2,156		-		(281,979)		30,569
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	15,892	$	(337)	$	-	$	12,661	$	28,216

195

Fair Value of Derivative Instruments
June 30, 2011
PSO
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	12,380	$	193	$	-	$	(12,083)	$	490
Long-term Risk Management Assets			2,155		9		-		(1,479)		685
Total Assets			14,535		202		-		(13,562)		1,175
Current Risk Management Liabilities			12,989		11		-		(12,124)		876
Long-term Risk Management Liabilities			1,633		8		-		(1,482)		159
Total Liabilities			14,622		19		-		(13,606)		1,035
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(87)	$	183	$	-	$	44	$	140

Fair Value of Derivative Instruments
December 31, 2010
PSO
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	19,174	$	134	$	13,558	$	(18,641)	$	14,225
Long-term Risk Management Assets			1,944		-		-		(1,692)		252
Total Assets			21,118		134		13,558		(20,333)		14,477
Current Risk Management Liabilities			19,607		-		-		(18,685)		922
Long-term Risk Management Liabilities			1,889		-		-		(1,692)		197
Total Liabilities			21,496		-		-		(20,377)		1,119
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(378)	$	134	$	13,558	$	44	$	13,358

196

Fair Value of Derivative Instruments
June 30, 2011
SWEPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	12,172	$	178	$	1,217	$	(11,954)	$	1,613
Long-term Risk Management Assets			1,730		8		10		(1,452)		296
Total Assets			13,902		186		1,227		(13,406)		1,909
Current Risk Management Liabilities			13,362		9		-		(11,993)		1,378
Long-term Risk Management Liabilities			1,605		7		-		(1,456)		156
Total Liabilities			14,967		16		-		(13,449)		1,534
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(1,065)	$	170	$	1,227	$	43	$	375

Fair Value of Derivative Instruments
December 31, 2010
SWEPCo
		Risk
		Management
		Contracts		Hedging Contracts
						Interest Rate
						and Foreign
Balance Sheet Location		Commodity (a)		Commodity (a)		Currency (a)		Other (a) (b)		Total
		(in thousands)
Current Risk Management Assets		$	33,284	$	123	$	-	$	(32,198)	$	1,209
Long-term Risk Management Assets			3,346		-		5		(2,913)		438
Total Assets			36,630		123		5		(35,111)		1,647
Current Risk Management Liabilities			36,338		-		-		(32,271)		4,067
Long-term Risk Management Liabilities			3,250		-		-		(2,912)		338
Total Liabilities			39,588		-		-		(35,183)		4,405
Total MTM Derivative Contract Net
	Assets (Liabilities)	$	(2,958)	$	123	$	5	$	72	$	(2,758)

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

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

197

The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and six months ended June 30, 2011 and 2010:

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended June 30, 2011
Location of Gain (Loss)		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	883	$	5,134	$	3,702	$	6,430	$	539	$	403
Sales to AEP Affiliates			13		6		6		7		(1)		(1)
Regulatory Assets (a)			(150)		(2,183)		(1,018)		(2,420)		644		404
Regulatory Liabilities (a)			4,142		-		(1,077)		-		461		692
Total Gain (Loss) on Risk Management
	Contracts	$	4,888	$	2,957	$	1,613	$	4,017	$	1,643	$	1,498
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Three Months Ended June 30, 2010
Location of Gain (Loss)		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	(1,693)	$	3,469	$	2,503	$	2,010	$	347	$	613
Sales to AEP Affiliates			786		113		102		2,156		(121)		(229)
Regulatory Assets (a)			(1,046)		(5,225)		(2,238)		(5,754)		(25)		120
Regulatory Liabilities (a)			(834)		-		(4,393)		-		126		1,524
Total Gain (Loss) on Risk Management
	Contracts	$	(2,787)	$	(1,643)	$	(4,026)	$	(1,588)	$	327	$	2,028

Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Six Months Ended June 30, 2011
Location of Gain (Loss)		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	2,699	$	9,924	$	9,117	$	12,230	$	658	$	526
Sales to AEP Affiliates			33		19		23		26		-		-
Regulatory Assets (a)			223		(2,095)		115		(2,113)		276		2,046
Regulatory Liabilities (a)			10,896		-		(1,664)		(105)		853		1,032
Total Gain (Loss) on Risk Management
	Contracts	$	13,851	$	7,848	$	7,591	$	10,038	$	1,787	$	3,604
Amount of Gain (Loss) Recognized on
Risk Management Contracts
For the Six Months Ended June 30, 2010
Location of Gain (Loss)		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Electric Generation, Transmission and
	Distribution Revenues	$	2,480	$	13,076	$	9,388	$	12,231	$	1,030	$	1,402
Sales to AEP Affiliates			(1,575)		(1,449)		(1,341)		2,409		(297)		(538)
Regulatory Assets (a)			-		(1,544)		-		(1,690)		306		73
Regulatory Liabilities (a)			15,147		-		8,461		29		2,764		513
Total Gain (Loss) on Risk Management
	Contracts	$	16,052	$	10,083	$	16,508	$	12,979	$	3,803	$	1,450
(a)  Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current  or noncurrent on the balance sheet.

198

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 and SWEPCo) for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

Accounting for Fair Value Hedging Strategies

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

The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the Condensed Statements of Income.  During the three and six months ended June 30, 2011 and 2010, the Registrant Subsidiaries did not employ any fair value hedging strategies.

Accounting for Cash Flow Hedging Strategies

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

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 six months ended June 30, 2011 and 2010, APCo, CSPCo, I&M and OPCo designated commodity derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on financial fuel derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the Condensed Statements of Income.  During the three and six months ended June 30, 2011 and 2010, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges.

199

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which hedged interest payments occur.  During the three and six months ended June 30, 2011, SWEPCo designated interest rate derivatives as cash flow hedges.  During the six months ended June 30, 2011, APCo and PSO designated interest rate derivatives as cash flow hedges.  During the three and six months ended June 30, 2010, APCo designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets into Depreciation and Amortization expense on the Condensed Statements of Income over the depreciable lives of the fixed assets that were designated as the hedged items in qualifying foreign currency hedging relationships.  During the three and six months ended June 30, 2011 and 2010, SWEPCo designated foreign currency derivatives as cash flow hedges.

During the three and six months ended June 30, 2011 and 2010, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

200

The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets and the reasons for changes in cash flow hedges for the three and six months ended June 30, 2011 and 2010.  All amounts in the following tables are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended June 30, 2011
Commodity Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2011				$	238	$	79	$	101	$	190	$	264	$	244
Changes in Fair Value Recognized in AOCI					(55)		(24)		(25)		(40)		(32)		(26)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		175		482		396		578		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		-		-
		Purchased Electricity for Resale			(41)		(112)		(92)		(134)		-		-
		Other Operation Expense			(31)		(26)		(28)		(34)		(34)		(33)
		Maintenance Expense			(65)		(18)		(22)		(33)		(22)		(24)
		Property, Plant and Equipment			(57)		(23)		(28)		(48)		(36)		(29)
		Regulatory Assets (a)			505		-		76		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-		-
Balance in AOCI as of June 30, 2011				$	669	$	358	$	378	$	479	$	140	$	132
Interest Rate and Foreign Currency
Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2011				$	217	$	-	$	(8,255)	$	10,473	$	7,787	$	(4,058)
Changes in Fair Value Recognized in AOCI					-		-		-		-		-		794
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		-		1		-		-
		Other Operation Expense			-		-		-		-		-		-
		Interest Expense			269		-		251		(341)		(189)		207
Balance in AOCI as of June 30, 2011				$	486	$	-	$	(8,004)	$	10,133	$	7,598	$	(3,057)
Total Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2011				$	455	$	79	$	(8,154)	$	10,663	$	8,051	$	(3,814)
Changes in Fair Value Recognized in AOCI					(55)		(24)		(25)		(40)		(32)		768
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		175		482		396		578		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		-		-
		Purchased Electricity for Resale			(41)		(112)		(92)		(134)		-		-
		Other Operation Expense			(31)		(26)		(28)		(34)		(34)		(33)
		Maintenance Expense			(65)		(18)		(22)		(33)		(22)		(24)
		Depreciation and Amortization
			Expense		-		-		-		1		-		-
		Interest Expense			269		-		251		(341)		(189)		207
		Property, Plant and Equipment			(57)		(23)		(28)		(48)		(36)		(29)
		Regulatory Assets (a)			505		-		76		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-		-
Balance in AOCI as of June 30, 2011				$	1,155	$	358	$	(7,626)	$	10,612	$	7,738	$	(2,925)

201

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Three Months Ended June 30, 2010
Commodity Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2010				$	(2,451)	$	(1,407)	$	(1,418)	$	(1,543)	$	(8)	$	100
Changes in Fair Value Recognized in AOCI					642		380		388		370		(191)		(99)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		31		79		66		91		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		(4)		150		-
		Purchased Electricity for Resale			65		168		139		193		-		-
		Other Operation Expense			(18)		(11)		(11)		(15)		(13)		(16)
		Maintenance Expense			(22)		(6)		(9)		(11)		(8)		(8)
		Property, Plant and Equipment			(24)		(10)		(12)		(17)		(14)		(10)
		Regulatory Assets (a)			340		-		44		-		-		-
		Regulatory Liabilities (a)			-		-		-		(5)		-		-
Balance in AOCI as of June 30, 2010				$	(1,437)	$	(807)	$	(813)	$	(941)	$	(84)	$	(33)
Interest Rate and Foreign Currency
Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2010				$	(6,488)	$	-	$	(9,262)	$	11,832	$	(475)	$	(4,947)
Changes in Fair Value Recognized in AOCI					(2,229)		-		-		-		-		(96)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		-		1		-		-
		Other Operation Expense			-		-		-		-		-		24
		Interest Expense			419		-		251		(341)		32		207
Balance in AOCI as of June 30, 2010				$	(8,298)	$	-	$	(9,011)	$	11,492	$	(443)	$	(4,812)
Total Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of March 31, 2010				$	(8,939)	$	(1,407)	$	(10,680)	$	10,289	$	(483)	$	(4,847)
Changes in Fair Value Recognized in AOCI					(1,587)		380		388		370		(191)		(195)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		31		79		66		91		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		(4)		150		-
		Purchased Electricity for Resale			65		168		139		193		-		-
		Other Operation Expense			(18)		(11)		(11)		(15)		(13)		8
		Maintenance Expense			(22)		(6)		(9)		(11)		(8)		(8)
		Depreciation and Amortization
			Expense		-		-		-		1		-		-
		Interest Expense			419		-		251		(341)		32		207
		Property, Plant and Equipment			(24)		(10)		(12)		(17)		(14)		(10)
		Regulatory Assets (a)			340		-		44		-		-		-
		Regulatory Liabilities (a)			-		-		-		(5)		-		-
Balance in AOCI as of June 30, 2010				$	(9,735)	$	(807)	$	(9,824)	$	10,551	$	(527)	$	(4,845)

202

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Six Months Ended June 30, 2011
Commodity Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2010				$	(273)	$	(134)	$	(178)	$	(230)	$	88	$	82
Changes in Fair Value Recognized in AOCI					123		(12)		53		155		180		168
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		171		470		386		564		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		-		-
		Purchased Electricity for Resale			46		125		102		150		-		-
		Other Operation Expense			(44)		(35)		(37)		(48)		(47)		(46)
		Maintenance Expense			(90)		(24)		(32)		(46)		(29)		(32)
		Property, Plant and Equipment			(80)		(32)		(39)		(66)		(52)		(40)
		Regulatory Assets (a)			816		-		123		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-		-
Balance in AOCI as of June 30, 2011				$	669	$	358	$	378	$	479	$	140	$	132
Interest Rate and Foreign Currency
Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2010				$	217	$	-	$	(8,507)	$	10,813	$	8,406	$	(4,272)
Changes in Fair Value Recognized in AOCI					(373)		-		-		-		(476)		801
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		-		2		-		-
		Other Operation Expense			-		-		-		-		-		-
		Interest Expense			642		-		503		(682)		(332)		414
Balance in AOCI as of June 30, 2011				$	486	$	-	$	(8,004)	$	10,133	$	7,598	$	(3,057)
Total Contracts				APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
				(in thousands)
Balance in AOCI as of December 31, 2010				$	(56)	$	(134)	$	(8,685)	$	10,583	$	8,494	$	(4,190)
Changes in Fair Value Recognized in AOCI					(250)		(12)		53		155		(296)		969
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		171		470		386		564		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		-		-		-
		Purchased Electricity for Resale			46		125		102		150		-		-
		Other Operation Expense			(44)		(35)		(37)		(48)		(47)		(46)
		Maintenance Expense			(90)		(24)		(32)		(46)		(29)		(32)
		Depreciation and Amortization
			Expense		-		-		-		2		-		-
		Interest Expense			642		-		503		(682)		(332)		414
		Property, Plant and Equipment			(80)		(32)		(39)		(66)		(52)		(40)
		Regulatory Assets (a)			816		-		123		-		-		-
		Regulatory Liabilities (a)			-		-		-		-		-		-
Balance in AOCI as of June 30, 2011				$	1,155	$	358	$	(7,626)	$	10,612	$	7,738	$	(2,925)

203

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
For the Six Months Ended June 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					(1,857)		(1,077)		(1,083)		(1,300)		(105)		(96)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		57		144		120		167		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		(13)		150		-
		Purchased Electricity for Resale			211		550		455		633		-		-
		Other Operation Expense			(24)		(19)		(17)		(20)		(19)		(23)
		Maintenance Expense			(36)		(12)		(14)		(15)		(12)		(12)
		Property, Plant and Equipment			(33)		(17)		(17)		(22)		(20)		(14)
		Regulatory Assets (a)			988		-		125		-		-		-
		Regulatory Liabilities (a)			-		-		-		(5)		-		-
Balance in AOCI as of June 30, 2010				$	(1,437)	$	(807)	$	(813)	$	(941)	$	(84)	$	(33)
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					(2,685)		-		-		-		-		(203)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Depreciation and Amortization
			Expense		-		-		-		2		-		-
		Other Operation Expense			-		-		-		-		-		24
		Interest Expense			837		-		503		(682)		78		414
Balance in AOCI as of June 30, 2010				$	(8,298)	$	-	$	(9,011)	$	11,492	$	(443)	$	(4,812)
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					(4,542)		(1,077)		(1,083)		(1,300)		(105)		(299)
Amount of (Gain) or Loss Reclassified
	from AOCI to Income Statement/within
	Balance Sheet:
		Electric Generation, Transmission, and
			Distribution Revenues		57		144		120		167		-		-
		Fuel and Other Consumables Used for
			Electric Generation		-		-		-		(13)		150		-
		Purchased Electricity for Resale			211		550		455		633		-		-
		Other Operation Expense			(24)		(19)		(17)		(20)		(19)		1
		Maintenance Expense			(36)		(12)		(14)		(15)		(12)		(12)
		Depreciation and Amortization
			Expense		-		-		-		2		-		-
		Interest Expense			837		-		503		(682)		78		414
		Property, Plant and Equipment			(33)		(17)		(17)		(22)		(20)		(14)
		Regulatory Assets (a)			988		-		125		-		-		-
		Regulatory Liabilities (a)			-		-		-		(5)		-		-
Balance in AOCI as of June 30, 2010				$	(9,735)	$	(807)	$	(9,824)	$	10,551	$	(527)	$	(4,845)
(a)			Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the Condensed Balance Sheets.

204

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets at June 30, 2011 and December 31, 2010 were:

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
June 30, 2011
	Hedging Assets (a)				Hedging Liabilities (a)				AOCI Gain (Loss) Net of Tax
			Interest Rate				Interest Rate				Interest Rate
			and Foreign				and Foreign				and Foreign
Company	Commodity		Currency		Commodity		Currency		Commodity		Currency
	(in thousands)
APCo	$	1,693	$	-	$	521	$	-	$	669	$	486
CSPCo		938		-		297		-		358		-
I&M		974		-		307		-		378		(8,004)
OPCo		1,192		-		362		-		479		10,133
PSO		195		-		12		-		140		7,598
SWEPCo		181		1,227		11		-		132		(3,057)

	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	$	507	$	(1,076)		35
CSPCo		264		-		35
I&M		280		(750)		35
OPCo		365		1,359		35
PSO		140		759		18
SWEPCo		129		(766)		18

205

Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
December 31, 2010
	Hedging Assets (a)				Hedging Liabilities (a)				AOCI Gain (Loss) Net of Tax
			Interest Rate				Interest Rate				Interest Rate
			and Foreign				and Foreign				and Foreign
Company	Commodity		Currency		Commodity		Currency		Commodity		Currency
	(in thousands)
APCo	$	333	$	11,888	$	727	$	-	$	(273)	$	217
CSPCo		229		-		419		-		(134)		-
I&M		175		-		437		-		(178)		(8,507)
OPCo		174		-		511		-		(230)		10,813
PSO		134		13,558		-		-		88		8,406
SWEPCo		123		5		-		-		82		(4,272)

	Expected to be Reclassified to
	Net Income During the Next
	Twelve Months
			Interest Rate
			and Foreign
Company	Commodity		Currency
	(in thousands)
APCo	$	(280)	$	(1,173)
CSPCo		(137)		-
I&M		(184)		(955)
OPCo		(236)		1,359
PSO		88		735
SWEPCo		82		(829)

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

The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.

Credit Risk

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

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

206

Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade.  The amount of collateral required fluctuates based on market prices and total exposure.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts.  Management does not anticipate a downgrade below investment grade.  The following tables represent: (a) the Registrant Subsidiaries’ aggregate fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of June 30, 2011 and December 31, 2010:

	June 30, 2011
	Liabilities for		Amount of Collateral the		Amount
	Derivative Contracts		Registrant Subsidiaries		Attributable to
	with Credit		Would Have Been		RTO and ISO
Company	Downgrade Triggers		Required to Post		Activities
	(in thousands)
APCo	$	9,515	$	7,366	$	7,366
CSPCo		5,506		4,262		4,262
I&M		5,644		4,370		4,370
OPCo		6,601		5,110		5,110
PSO		-		3,196		2,913
SWEPCo		-		3,830		3,490

	December 31, 2010
	Liabilities for		Amount of Collateral the		Amount
	Derivative Contracts		Registrant Subsidiaries		Attributable to
	with Credit		Would Have Been		RTO and ISO
Company	Downgrade Triggers		Required to Post		Activities
	(in thousands)
APCo	$	6,594	$	12,607	$	12,574
CSPCo		3,801		7,267		7,248
I&M		3,965		7,581		7,561
OPCo		4,640		8,871		8,847
PSO		16		1,785		1,385
SWEPCo		19		2,139		1,659

As of June 30, 2011 and December 31, 2010, the Registrant Subsidiaries were not required to post any collateral.

207

In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable.  These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million.  On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts.  Management does not anticipate a non-performance event under these provisions.  The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries’ contractual netting arrangements as of June 30, 2011 and December 31, 2010:

	June 30, 2011
	Liabilities for				Additional
	Contracts with Cross				Settlement
	Default Provisions				Liability if Cross
	Prior to Contractual		Amount of Cash		Default Provision
Company	Netting Arrangements		Collateral Posted		is Triggered
	(in thousands)
APCo	$	63,340	$	3,006	$	18,543
CSPCo		36,650		1,739		10,729
I&M		37,574		1,783		10,999
OPCo		43,952		2,085		12,875
PSO		31		-		19
SWEPCo		36		-		21
	December 31, 2010
	Liabilities for				Additional
	Contracts with Cross				Settlement
	Default Provisions				Liability if Cross
	Prior to Contractual		Amount of Cash		Default Provision
Company	Netting Arrangements		Collateral Posted		is Triggered
	(in thousands)
APCo	$	76,810	$	6,637	$	23,748
CSPCo		44,277		3,826		13,689
I&M		46,188		3,991		14,280
OPCo		54,066		4,670		16,731
PSO		60		-		28
SWEPCo		75		-		37

9.  FAIR VALUE MEASUREMENTS

Fair Value Hierarchy and Valuation Techniques

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.

208

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.  If the points are highly correlated, these locations are included within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Long-dated and illiquid complex or structured transactions and FTRs can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.

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

Assets in the nuclear trusts and Other Cash Deposits are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equities.  They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.  Fixed income securities do not trade on an exchange and do not have an official closing price.  Pricing vendors calculate bond valuations using financial models and matrices.  Fixed income securities are typically classified as Level 2 holdings because their valuation inputs are based on observable market data.  Observable inputs used for valuing fixed income securities are benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, bids, offers, reference data and economic events.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.

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

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

209

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 June 30, 2011 and December 31, 2010 are summarized in the following table:

	June 30, 2011				December 31, 2010
Company	Book Value		Fair Value		Book Value		Fair Value
	(in thousands)
APCo	$	3,725,886	$	4,075,642	$	3,561,141	$	3,878,557
CSPCo		1,438,969		1,581,261		1,438,830		1,571,219
I&M		1,965,094		2,141,768		2,004,226		2,169,520
OPCo		2,614,781		2,855,349		2,729,522		2,945,280
PSO		945,650		1,035,124		971,186		1,040,656
SWEPCo		1,769,646		1,941,357		1,769,520		1,931,516

Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

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

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

·   Maximum percentage invested in a specific type of investment.

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

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

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

I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value.  I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose.  Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm.  The external investment management firm makes specific investment decisions regarding the equity and debt investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy.  Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment.  I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates.  Consequently, changes in fair value of trust assets do not affect earnings or AOCI.  The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities.  Regulatory approval is required to withdraw decommissioning funds.

210

The following is a summary of nuclear trust fund investments at June 30, 2011 and December 31, 2010:

		June 30, 2011						December 31, 2010
		Estimated		Gross		Other-Than-		Estimated		Gross		Other-Than-
		Fair		Unrealized		Temporary		Fair		Unrealized		Temporary
		Value		Gains		Impairments		Value		Gains		Impairments
		(in thousands)
Cash and Cash Equivalents		$	17,114	$	-	$	-	$	20,039	$	-	$	-
Fixed Income Securities:
	United States Government		483,677		27,160		(1,269)		461,084		22,582		(1,489)
	Corporate Debt		56,617		3,495		(785)		59,463		3,716		(1,905)
	State and Local Government		338,145		1,031		(1,169)		340,786		(975)		(340)
	Subtotal Fixed Income Securities		878,439		31,686		(3,223)		861,333		25,323		(3,734)
Equity Securities - Domestic			678,589		231,186		(104,828)		633,855		183,447		(122,889)
Spent Nuclear Fuel and
	Decommissioning Trusts	$	1,574,142	$	262,872	$	(108,051)	$	1,515,227	$	208,770	$	(126,623)

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(in thousands)
Proceeds from Investment Sales	$	176,927	$	360,185	$	464,688	$	592,263
Purchases of Investments		186,217		369,427		492,162		617,059
Gross Realized Gains on Investment Sales		7,392		1,022		12,405		6,350
Gross Realized Losses on Investment Sales		4,043		236		9,290		417

The adjusted cost of debt securities was $848 million and $835 million as of June 30, 2011 and December 31, 2010, respectively.  The adjusted cost of equity securities was $447 million and $451 million as of June 30, 2011 and December 31, 2010, respectively.

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

	Fair Value
	of Debt
	Securities
	(in thousands)
Within 1 year	$	77,143
1 year – 5 years		256,056
5 years – 10 years		281,130
After 10 years		264,110
Total	$	878,439

211

Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2011 and December 31, 2010.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in management’s valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2011
APCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	935	$	230,136	$	16,634	$	(188,100)	$	59,605
Cash Flow Hedges:
	Commodity Hedges (a)		-		4,289		-		(2,596)		1,693
Dedesignated Risk Management Contracts (b)			-		-		-		2,662		2,662
Total Risk Management Assets		$	935	$	234,425	$	16,634	$	(188,034)	$	63,960
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	901	$	211,634	$	11,263	$	(195,489)	$	28,309
Cash Flow Hedges:
	Commodity Hedges (a)		-		3,067		50		(2,596)		521
Total Risk Management Liabilities		$	901	$	214,701	$	11,313	$	(198,085)	$	28,830

Assets and Liabilities Measured at Fair Value on a Recurring Basis
December 31, 2010
APCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	1,686	$	330,605	$	13,791	$	(270,012)	$	76,070
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,591		-		(2,258)		333
	Interest Rate/Foreign Currency Hedges		-		11,888		-		-		11,888
Dedesignated Risk Management Contracts (b)			-		-		-		3,371		3,371
Total Risk Management Assets		$	1,686	$	345,084	$	13,791	$	(268,899)	$	91,662
Liabilities:
Risk Management Liabilities			��
Risk Management Commodity Contracts (a) (f)		$	1,653	$	312,258	$	8,660	$	(284,432)	$	38,139
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,985		-		(2,258)		727
Total Risk Management Liabilities		$	1,653	$	315,243	$	8,660	$	(286,690)	$	38,866

212

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2011
CSPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	542	$	132,069	$	9,623	$	(107,783)	$	34,451
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,438		-		(1,500)		938
Dedesignated Risk Management Contracts (b)			-		-		-		1,540		1,540
Total Risk Management Assets		$	542	$	134,507	$	9,623	$	(107,743)	$	36,929
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	521	$	121,351	$	6,517	$	(112,054)	$	16,335
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,768		29		(1,500)		297
Total Risk Management Liabilities		$	521	$	123,119	$	6,546	$	(113,554)	$	16,632

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2010
CSPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	972	$	185,699	$	7,950	$	(150,930)	$	43,691
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,531		-		(1,302)		229
Dedesignated Risk Management Contracts (b)			-		-		-		1,943		1,943
Total Risk Management Assets		$	972	$	187,230	$	7,950	$	(150,289)	$	45,863
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	953	$	175,078	$	4,975	$	(159,235)	$	21,771
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,721		-		(1,302)		419
Total Risk Management Liabilities		$	953	$	176,799	$	4,975	$	(160,537)	$	22,190

213

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2011
I&M
			Level 1		Level 2		Level 3		Other		Total
Assets:			(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (f)			$	555	$	143,023	$	9,864	$	(108,585)	$	44,857
Cash Flow Hedges:
	Commodity Hedges (a)			-		2,512		-		(1,538)		974
Dedesignated Risk Management Contracts (b)				-		-		-		1,579		1,579
Total Risk Management Assets				555		145,535		9,864		(108,544)		47,410
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (d)				-		4,699		-		12,415		17,114
Fixed Income Securities:
	United States Government			-		483,677		-		-		483,677
	Corporate Debt			-		56,617		-		-		56,617
	State and Local Government			-		338,145		-		-		338,145
		Subtotal Fixed Income Securities		-		878,439		-		-		878,439
Equity Securities - Domestic (e)				678,589		-		-		-		678,589
Total Spent Nuclear Fuel and Decommissioning Trusts				678,589		883,138		-		12,415		1,574,142
Total Assets			$	679,144	$	1,028,673	$	9,864	$	(96,129)	$	1,621,552
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)			$	534	$	122,403	$	6,684	$	(112,959)	$	16,662
Cash Flow Hedges:
	Commodity Hedges (a)			-		1,815		30		(1,538)		307
Total Risk Management Liabilities			$	534	$	124,218	$	6,714	$	(114,497)	$	16,969

214

		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		December 31, 2010
I&M
			Level 1		Level 2		Level 3		Other		Total
Assets:			(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (f)			$	1,014	$	209,031	$	8,295	$	(161,531)	$	56,809
Cash Flow Hedges:
	Commodity Hedges (a)			-		1,533		-		(1,358)		175
Dedesignated Risk Management Contracts (b)				-		-		-		2,027		2,027
Total Risk Management Assets				1,014		210,564		8,295		(160,862)		59,011
Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (d)				-		7,898		-		12,141		20,039
Fixed Income Securities:
	United States Government			-		461,084		-		-		461,084
	Corporate Debt			-		59,463		-		-		59,463
	State and Local Government			-		340,786		-		-		340,786
		Subtotal Fixed Income Securities		-		861,333		-		-		861,333
Equity Securities - Domestic (e)				633,855		-		-		-		633,855
Total Spent Nuclear Fuel and Decommissioning Trusts				633,855		869,231		-		12,141		1,515,227
Total Assets			$	634,869	$	1,079,795	$	8,295	$	(148,721)	$	1,574,238
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)			$	994	$	186,898	$	5,187	$	(170,201)	$	22,878
Cash Flow Hedges:
	Commodity Hedges (a)			-		1,795		-		(1,358)		437
Total Risk Management Liabilities			$	994	$	188,693	$	5,187	$	(171,559)	$	23,315

215

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	June 30, 2011
OPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Other Cash Deposits (c)		$	26	$	-	$	-	$	22	$	48
Risk Management Assets
Risk Management Commodity Contracts (a) (f)			649		193,046		11,535		(162,774)		42,456
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,993		-		(1,801)		1,192
Dedesignated Risk Management Contracts (b)			-		-		-		1,847		1,847
Total Risk Management Assets			649		196,039		11,535		(162,728)		45,495
Total Assets		$	675	$	196,039	$	11,535	$	(162,706)	$	45,543
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	625	$	180,588	$	7,818	$	(167,994)	$	21,037
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,128		35		(1,801)		362
Total Risk Management Liabilities		$	625	$	182,716	$	7,853	$	(169,795)	$	21,399

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2010
OPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Other Cash Deposits (c)		$	26	$	-	$	-	$	-	$	26
Risk Management Assets
Risk Management Commodity Contracts (a) (f)			1,186		314,560		9,709		(269,216)		56,239
Cash Flow Hedges:
	Commodity Hedges (a)		-		1,764		-		(1,590)		174
Dedesignated Risk Management Contracts (b)			-		-		-		2,372		2,372
Total Risk Management Assets			1,186		316,324		9,709		(268,434)		58,785
Total Assets		$	1,212	$	316,324	$	9,709	$	(268,434)	$	58,811
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	1,163	$	302,299	$	6,101	$	(279,505)	$	30,058
Cash Flow Hedges:
	Commodity Hedges (a)		-		2,101		-		(1,590)		511
Total Risk Management Liabilities		$	1,163	$	304,400	$	6,101	$	(281,095)	$	30,569

216

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	June 30, 2011
PSO
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	2	$	14,471	$	-	$	(13,493)	$	980
Cash Flow Hedges:
	Commodity Hedges (a)		-		202		-		(7)		195
Total Risk Management Assets		$	2	$	14,673	$	-	$	(13,500)	$	1,175
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	1	$	14,559	$	-	$	(13,537)	$	1,023
Cash Flow Hedges:
	Commodity Hedges (a)		-		19		-		(7)		12
Total Risk Management Liabilities		$	1	$	14,578	$	-	$	(13,544)	$	1,035

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2010
PSO
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	-	$	21,119	$	1	$	(20,335)	$	785
Cash Flow Hedges:
	Commodity Hedges		-		134		-		-		134
	Interest Rate/Foreign Currency Hedges		-		13,558		-		-		13,558
Total Risk Management Assets		$	-	$	34,811	$	1	$	(20,335)	$	14,477
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	-	$	21,498	$	-	$	(20,379)	$	1,119

217

Assets and Liabilities Measured at Fair Value on a Recurring Basis
June 30, 2011
SWEPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	2	$	13,840	$	-	$	(13,341)	$	501
Cash Flow Hedges:
	Commodity Hedges (a)		-		186		-		(5)		181
	Interest Rate/Foreign Currency Hedges		-		1,227		-		-		1,227
Total Risk Management Assets		$	2	$	15,253	$	-	$	(13,346)	$	1,909
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	1	$	14,906	$	-	$	(13,384)	$	1,523
Cash Flow Hedges:
	Commodity Hedges (a)		-		16		-		(5)		11
Total Risk Management Liabilities		$	1	$	14,922	$	-	$	(13,389)	$	1,534

	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	December 31, 2010
SWEPCo
		Level 1		Level 2		Level 3		Other		Total
Assets:		(in thousands)
Risk Management Assets
Risk Management Commodity Contracts (a) (f)		$	-	$	36,632	$	2	$	(35,115)	$	1,519
Cash Flow Hedges:
	Commodity Hedges		-		123		-		-		123
	Interest Rate/Foreign Currency Hedges		-		5		-		-		5
Total Risk Management Assets		$	-	$	36,760	$	2	$	(35,115)	$	1,647
Liabilities:
Risk Management Liabilities
Risk Management Commodity Contracts (a) (f)		$	-	$	39,592	$	-	$	(35,187)	$	4,405

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

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

(c) Level 1 amounts primarily represent investments in money market funds.

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

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

(f) Substantially comprised of power contracts for APCo, CSPCo, I&M and OPCo and coal contracts for PSO and SWEPCo.

There were no transfers between Level 1 and Level 2 during the six months ended June 30, 2011 and 2010.

218

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

Three Months Ended June 30, 2011		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of March 31, 2011		$	5,472	$	3,134	$	3,209	$	3,759	$	-	$	-
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		(3,219)		(1,863)		(1,910)		(2,233)		-		-
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		527		-		622		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		(50)		(29)		(30)		(35)		-		-
Purchases, Issuances and Settlements (c)			4,814		2,786		2,856		3,340		-		-
Transfers into Level 3 (d) (f)			1,125		644		661		773		-		-
Transfers out of Level 3 (e) (f)			(213)		(122)		(125)		(147)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		(2,608)		(2,000)		(1,511)		(2,397)		-		-
Balance as of June 30, 2011		$	5,321	$	3,077	$	3,150	$	3,682	$	-	$	-

Three Months Ended June 30, 2010		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of March 31, 2010		$	18,687	$	10,570	$	10,662	$	12,180	$	2	$	4
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		(8,409)		(4,753)		(4,794)		(5,471)		(1)		(1)
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		(556)		-		(667)		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		-		-		-		-		-		-
Purchases, Issuances and Settlements (c)			4,845		2,741		2,764		3,154		(4)		(5)
Transfers into Level 3 (d) (f)			1,332		753		760		867		-		-
Transfers out of Level 3 (e) (f)			(2,006)		(1,135)		(1,145)		(1,306)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		(3,575)		(1,467)		(2,038)		(1,688)		1		-
Balance as of June 30, 2010		$	10,874	$	6,153	$	6,209	$	7,069	$	(2)	$	(2)

Six Months Ended June 30, 2011		APCo		CSPCo		I&M		OPCo		PSO		SWEPCo
		(in thousands)
Balance as of December 31, 2010		$	5,131	$	2,975	$	3,108	$	3,608	$	1	$	2
Realized Gain (Loss) Included in Net Income
	(or Changes in Net Assets) (a) (b)		(2,489)		(1,436)		(1,473)		(1,722)		-		-
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		2,258		-		2,691		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		(50)		(29)		(30)		(35)		-		-
Purchases, Issuances and Settlements (c)			3,881		2,254		2,311		2,701		-		-
Transfers into Level 3 (d) (f)			1,221		699		718		840		-		-
Transfers out of Level 3 (e) (f)			(2,853)		(1,644)		(1,713)		(2,004)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		480		(2,000)		229		(2,397)		(1)		(2)
Balance as of June 30, 2011		$	5,321	$	3,077	$	3,150	$	3,682	$	-	$	-

219

Six Months Ended June 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)		1,232		693		698		797		7		9
Unrealized Gain (Loss) Included in Net
	Income (or Changes in Net Assets) Relating
	to Assets Still Held at the Reporting Date (a)		-		5,157		-		5,849		-		-
Realized and Unrealized Gains (Losses)
	Included in Other Comprehensive Income		-		-		-		-		-		-
Purchases, Issuances and Settlements (c)			(4,173)		(2,321)		(2,341)		(2,675)		(6)		(7)
Transfers into Level 3 (d) (f)			603		315		318		366		-		-
Transfers out of Level 3 (e) (f)			(1,738)		(999)		(1,008)		(1,148)		-		-
Changes in Fair Value Allocated to Regulated
	Jurisdictions (g)		5,522		(1,468)		3,726		(1,689)		(5)		(7)
Balance as of June 30, 2010		$	10,874	$	6,153	$	6,209	$	7,069	$	(2)	$	(2)

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

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

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

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

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

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

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

10.  INCOME TAXES

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

The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 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.  In April 2011, the IRS’s examination of the years 2007 and 2008 was concluded with a settlement of all outstanding issues.  The settlement will not have a material impact on net income, cash flows or financial condition.  Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters.  In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions.  Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on net income.

The Registrant Subsidiaries file income tax returns in various state and local jurisdictions.  These taxing authorities routinely examine their tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions.  Management believes that previously filed tax returns have positions that may be challenged by these tax authorities.  However, management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income.  With few exceptions, the Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2000.

220

Federal Tax Legislation

The Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act (Health Care Acts) were enacted in March 2010.  The Health Care Acts amend tax rules so that the portion of employer health care costs that are reimbursed by the Medicare Part D prescription drug subsidy will no longer be deductible by the employer for federal income tax purposes effective for years beginning after December 31, 2012.  Because of the loss of the future tax deduction, a reduction in the deferred tax asset related to the nondeductible OPEB liabilities accrued to date was recorded by the Registrant Subsidiaries in March 2010.  This reduction did not materially affect the Registrant Subsidiaries' cash flows or financial condition.  For the six months ended June 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 (the Act) was enacted in September 2010.  Included in the Act was a one-year extension of the 50% bonus depreciation provision.  The Tax Relief, Unemployment Insurance Reauthorization and the Job Creation Act of 2010 extended the life of research and development, employment and several energy tax credits originally scheduled to expire at the end of 2010.  In addition, the Act extended the time for claiming bonus depreciation and increased the deduction to 100% for part of 2010 and 2011.  The enacted provisions will not have a material impact on the Registrant Subsidiaries’ net income or financial condition.

State Tax Legislation

Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rates from 8.5% to 6.5%.  The current 8.5% Indiana corporate income tax rate is scheduled for a 0.5% reduction each year beginning after June 30, 2012 with the final reduction occurring in years beginning after June 30, 2015.  In addition, Michigan repealed its Business Tax regime in May 2011 and replaced it with a traditional corporate net income tax with a rate of 6%.  The enacted provisions will not have a material impact on the Registrant Subsidiaries’ net income, cash flows or financial condition.

221

11.  FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first six months of 2011 are shown in the tables below:

		Principal			Interest	Due
Company	Type of Debt	Amount			Rate	Date
Issuances:		(in thousands)			(%)
APCo	Senior Unsecured Notes	$	350,000		4.60	2021
APCo	Pollution Control Bonds		65,350		2.00	2012
APCo	Pollution Control Bonds		75,000	(a)	Variable	2036
APCo	Pollution Control Bonds		54,375	(a)	Variable	2042
APCo	Pollution Control Bonds		50,275	(a)	Variable	2036
APCo	Pollution Control Bonds		50,000	(a)	Variable	2042
I&M	Pollution Control Bonds		52,000	(a)	Variable	2021
I&M	Pollution Control Bonds		25,000	(a)	Variable	2019
OPCo	Pollution Control Bonds		50,000	(a)	Variable	2014
PSO	Senior Unsecured Notes		250,000		4.40	2021
PSO	Notes Payable		1,187		3.00	2026

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

			Principal		Interest	Due
Company		Type of Debt	Amount Paid		Rate	Date
Retirements and			(in thousands)		(%)
	Principal Payments:
APCo		Pollution Control Bonds	$	75,000	Variable	2036
APCo		Pollution Control Bonds		54,375	Variable	2042
APCo		Pollution Control Bonds		50,000	Variable	2042
APCo		Pollution Control Bonds		50,275	Variable	2036
APCo		Senior Unsecured Notes		250,000	5.55	2011
APCo		Land Note		11	13.718	2026
I&M		Pollution Control Bonds		52,000	Variable	2021
I&M		Pollution Control Bonds		25,000	Variable	2019
I&M		Notes Payable		10,894	Variable	2015
I&M		Notes Payable		13,150	5.16	2014
I&M		Notes Payable		15,482	5.44	2013
OPCo		Pollution Control Bonds		65,000	Variable	2036
OPCo		Pollution Control Bonds		50,000	Variable	2014
OPCo		Pollution Control Bonds		50,000	Variable	2014
PSO		Senior Unsecured Notes		200,000	6.00	2032
PSO		Senior Unsecured Notes		75,000	4.70	2011

In July 2011, SWEPCo retired $41 million of 4.5% Pollution Control Bonds due in 2011.

In July 2011, I&M retired $2 million of Notes Payable related to DCC Fuel.

As of June 30, 2011, trustees held, on behalf of OPCo, $418 million of its reacquired Pollution Control Bonds.

222

Dividend Restrictions

The Registrant Subsidiaries pay dividends to Parent provided funds are legally available.  Various charter provisions and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

Federal Power Act

The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.”  The term “capital account” is not defined in the Federal Power Act or its regulations.  As applicable, the Registrant Subsidiaries understand “capital account” to mean the par value of the common stock multiplied by the number of shares outstanding.

Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generating plants.  Because of their respective ownership of such plants, this reserve applies to APCo, I&M and OPCo.

None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.

Charter and Leverage Restrictions

Provisions within the articles or certificates of incorporation of the Registrant Subsidiaries relating to preferred stock or shares restrict the payment of cash dividends on common and preferred stock or shares.

Utility Money Pool – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of its subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries.  The AEP System Utility Money Pool operates in accordance with the terms and conditions approved in a regulatory order.  The amount of outstanding loans (borrowings) to/from the Utility Money Pool as of June 30, 2011 and December 31, 2010 is included in Advances to/from Affiliates on each of the Registrant Subsidiaries’ balance sheets.  The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the six months ended June 30, 2011 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		June 30, 2011		Limit
	(in thousands)
APCo	$	195,945	$	393,811	$	102,608	$	154,349	$	162,787	$	600,000
CSPCo		17,256		130,250		10,098		78,172		71,323		350,000
I&M		52,098		89,276		22,098		32,773		(24,537)		500,000
OPCo		51,169		237,196		17,873		116,937		136,965		600,000
PSO		96,034		255,611		45,042		95,323		110		300,000
SWEPCo		26,424		105,184		11,178		38,798		34,684		350,000

223

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:

	Six Months Ended June 30,
	2011			2010
Maximum Interest Rate		0.56	%		0.51	%
Minimum Interest Rate		0.06	%		0.09	%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the six months ended June 30, 2011 and 2010 are summarized for all Registrant Subsidiaries in the following table:

	Average Interest Rate						Average Interest Rate
	for Funds Borrowed						for Funds Loaned
	from Utility Money Pool for						to Utility Money Pool for
	Six Months Ended June 30,						Six Months Ended June 30,
Company	2011			2010			2011			2010
APCo		0.38	%		0.23	%		0.27	%		-	%
CSPCo		0.52	%		0.18	%		0.27	%		0.26	%
I&M		0.44	%		-	%		0.23	%		0.21	%
OPCo		0.41	%		-	%		0.24	%		0.18	%
PSO		0.41	%		0.28	%		0.19	%		0.16	%
SWEPCo		0.25	%		0.19	%		0.33	%		0.25	%

Short-term Debt

The Registrant Subsidiaries’ outstanding short-term debt was as follows:

			June 30, 2011				December 31, 2010
			Outstanding		Interest		Outstanding		Interest
Company		Type of Debt	Amount		Rate (b)		Amount		Rate (b)
			(in thousands)				(in thousands)
SWEPCo		Line of Credit – Sabine (a)	$	-	-	%	$	6,217	2.15	%
(a)	Sabine Mining Company is a consolidated variable interest entity.
(b)	Weighted average rate.

224

Credit Facilities

AEP has two $1.5 billion credit facilities, under which up to $1.35 billion may be issued as letters of credit.  In July 2011, AEP replaced the $1.5 billion facility due in 2012 with a new $1.75 billion facility maturing in July 2016 and extended the $1.5 billion facility due in 2013 to expire in June 2015.  As of June 30, 2011, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $150 thousand for I&M and $4 million for SWEPCo.

In March 2011, the Registrant Subsidiaries and certain other companies in the AEP System terminated a $478 million credit agreement that was scheduled to mature in April 2011 and was used to support variable rate Pollution Control Bonds.  In March 2011, certain variable rate Pollution Control Bonds were remarketed and supported by bilateral letters of credit for $361 million while others were reacquired and are being held in trust.  As of June 30, 2011, $472 million of variable rate Pollution Control Bonds were remarketed or reacquired as follows:

	June 30, 2011
			Reacquired and		Bilateral Letters
Company	Remarketed		Held in Trust		of Credit Issued
	(in thousands)
APCo	$	229,650	$	-	$	232,293
I&M		77,000		-		77,886
OPCo		50,000		115,000		50,575

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.

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

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of June 30, 2011 and December 31, 2010 was as follows:

	June 30,		December 31,
Company	2011		2010
	(in thousands)
APCo	$	123,959	$	145,515
CSPCo		179,639		175,997
I&M		132,772		123,366
OPCo		192,529		168,701
PSO		150,689		121,679
SWEPCo		174,496		135,092

225

The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:

	Three Months Ended June 30,				Six Months Ended June 30,
Company	2011		2010		2011		2010
	(in thousands)
APCo	$	2,239	$	1,895	$	4,814	$	3,776
CSPCo		2,594		2,782		4,926		5,690
I&M		1,508		1,657		3,135		3,444
OPCo		1,811		2,449		3,514		5,149
PSO		1,483		1,367		2,717		2,750
SWEPCo		1,303		1,462		2,403		3,133

The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:

	Three Months Ended June 30,				Six Months Ended June 30,
Company	2011		2010		2011		2010
	(in thousands)
APCo	$	284,715	$	317,120	$	650,924	$	758,830
CSPCo		374,925		422,628		781,571		847,313
I&M		315,551		297,384		666,572		636,593
OPCo		456,910		410,331		961,302		851,840
PSO		317,060		311,883		585,629		526,530
SWEPCo		375,903		338,286		690,027		657,245

12.  COST REDUCTION INITIATIVES

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

Management recorded a charge to Other Operation expense during the second quarter of 2010 primarily related to severance benefits as the result of headcount reduction initiatives.  The total amount incurred in 2010 by Registrant Subsidiary was as follows:

Company	Total Cost Incurred
	(in thousands)
APCo	$	56,925
CSPCo		32,292
I&M		45,036
OPCo		53,108
PSO		24,005
SWEPCo		29,662

The Registrant Subsidiaries’ cost reduction activity for the six months ended June 30, 2011 is described in the following table:

	Balance at								Balance at
Company	December 31, 2010		Incurred		Settled		Adjustments		June 30, 2011
	(in thousands)
APCo	$	3,726	$	-	$	(2,327)	$	(452)	$	947
CSPCo		1,454		-		(1,346)		(4)		104
I&M		2,198		-		(1,650)		(136)		412
OPCo		2,919		-		(2,242)		(128)		549
PSO		1,526		-		(1,048)		(167)		311
SWEPCo		1,753		-		(1,325)		(38)		390

The remaining accruals are included primarily in Other Current Liabilities on the Condensed Consolidated Balance Sheets.

226

COMBINED MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the Registrant Subsidiaries’ management’s discussion and analysis.  The information in this section completes the information necessary for management’s discussion and analysis of financial condition and net income and is meant to be read with (a) Management’s Discussion and Analysis, (b) financial statements, (c) footnotes and (d) the schedules of each individual registrant.  The Combined Management’s Discussion and Analysis of Registrant Subsidiaries section of the 2010 Annual Report should also be read in conjunction with this report.

EXECUTIVE OVERVIEW

ENVIRONMENTAL ISSUES

The Registrant Subsidiaries are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements.  The Registrant Subsidiaries will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants from fossil fuel-fired power plants, new proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.

The Registrant Subsidiaries are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of I&M’s nuclear units.  Management is also involved in development of possible future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change.  See a complete discussion of these matters in the “Environmental Issues” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report.  Management will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  The Registrant Subsidiaries should be able to recover these expenditures through market prices in deregulated jurisdictions.  If not, the costs of environmental compliance could adversely affect future net income, cash flows and possibly financial condition.

Update to Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of June 30, 2011, the AEP System had a total generating capacity of nearly 38,000 MWs, of which 23,900 MWs are coal-fired.  In the second quarter of 2011, management refined the cost estimates of complying with these rules and other impacts of the environmental proposals on the coal-fired generating facilities.  For the Registrant Subsidiaries, management’s current ranges of estimates of environmental investments to comply with these proposed requirements, based upon the updates are listed below:

	2012 to 2020
	Estimated Environmental Investment
Company	Low		High
	(in millions)
APCo	$	580	$	765
CSPCo		552		736
I&M		660		885
OPCo		1,549		2,065
PSO		700		940
SWEPCo		900		1,200

For APCo, the projected environmental investments above include both the conversion of 470 MWs of coal generation to 422 MWs of natural gas generation and the building of 580 MWs of natural gas-fired generation.  For OPCo, the investments above include the conversion of 600 MWs of coal generation to 510 MWs of natural gas-fired generation.

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

Subject to the factors listed above and based upon management’s current evaluation, the Registrant Subsidiaries may retire the following plants or units of plants before 2015:

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

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

Management is also considering the conversion of some of the Registrant Subsidiaries’ coal units to natural gas, installing emission control equipment on other units and completing construction of the Turk and Dresden Plants.  Recovery of the remaining investments in facilities that may be closed will be subject to regulatory approval.

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

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

In July 2011, the Federal EPA released the final rule, renamed the Cross State Air Pollution Rule (CSAP Rule).  Like the proposed Transport Rule, the CSAP Rule relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states.  Interstate trading of allowances is allowed on a restricted sub-regional basis beginning in 2012.  Arkansas, Louisiana and Oklahoma are subject only to the seasonal NOx program in the final rule.  However, Texas is now subject to the annual programs for SO2 and NOx in addition to the seasonal NOx program.  The annual SO2 allowance budgets in Indiana, Ohio and West Virginia have been reduced significantly in the final rule.

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The time frames and stringency of the required emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and its electric utility customers.  The compliance plan described above was based on the requirements of the proposed Transport Rule.  The more stringent requirements included in the final CSAP Rule could accelerate unit retirements, increase capital requirements, constrain operations, decrease reliability and unfavorably impact financial condition if the increased costs are not recovered in rates or market prices.

Mercury and Other Hazardous Air Pollutants (HAPs) Regulation

The Federal EPA issued the Clean Air Mercury Rule (CAMR) in 2005, setting mercury emission standards for new coal-fired power plants and requiring all states to issue new state implementation plans including mercury requirements for existing coal-fired power plants.  The CAMR was vacated by the D.C. Circuit Court of Appeals in 2008.  In response, the Federal EPA has been developing a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The Federal EPA Administrator signed a proposed HAPs rule in March 2011, but the rule has not yet been published in the Federal Register.  The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrochloric acid (as a surrogate for acid gases) for units burning coal and oil, on a site-wide 30-day rolling average basis.  In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  Compliance is required within three years of the effective date of the final rule, which is expected by November 2011 per the Federal EPA’s settlement agreement with several environmental groups.  A one-year extension may be available if the extension is necessary for the installation of controls.  Management is developing comments to submit to the Federal EPA and collecting additional information regarding the performance of the coal-fired units.  Comments will be accepted for 60 days after the rule is published in the Federal Register.

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.  The AEP System has older coal units for which it may be economically inefficient to install scrubbers or other environmental controls.  Several of these units are included in the current list of potential plant closures discussed above.

Regional Haze – Oklahoma Affecting PSO

In March 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze state implementation plan (SIP) submitted by the State of Oklahoma through the Department of Environmental Quality.  The Federal EPA is proposing to approve all of the NOx control measures in the SIP and disapprove the SO2 control measures for six electric generating units, including two units owned by PSO.  The Federal EPA is proposing a federal implementation plan (FIP) that would require these units to install technology capable of reducing SO2 emissions to 0.06 pounds per million British thermal units within three years of the effective date of the FIP.  The proposal is open for public comment.

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 $3.9 billion including AFUDC for units across the AEP System.  Regulation of these materials as hazardous wastes would significantly increase these costs.

Clean Water Act Regulations

In April 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement.  Compliance with this standard is required within eight years of the effective date of the final rule.  The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment.  The proposed entrainment standard for new units at existing facilities requires either intake flows commensurate with closed cycle cooling or achieving entrainment reductions equivalent to 90% or greater of the reductions that could be achieved with closed cycle cooling.  Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority.  Management is evaluating the proposal and engaged in the collection of additional information regarding the feasibility of implementing this proposal at the AEP System’s facilities.  Comments on the proposal were due in July 2011.

Global Warming

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

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

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

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

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

For detailed information on global warming and the actions the AEP System is taking to address potential impacts, see Part I of the 2010 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters – Global Warming and “Combined Management Discussion and Analysis of Registrant Subsidiaries.”

FINANCIAL CONDITION

LIQUIDITY AND CAPITAL RESOURCES

Sources of Funding

Short-term funding for the Registrant Subsidiaries comes from AEP’s commercial paper program and revolving credit facilities through the Utility Money Pool.  AEP and its Registrant Subsidiaries operate a money pool to minimize the AEP System’s external short-term funding requirements and sell accounts receivable to provide liquidity.  Under credit facilities, $1.35 billion may be issued as letters of credit (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.

In March 2011, the Registrant Subsidiaries and certain other companies in the AEP System terminated a $478 million credit facility, used for letters of credit to support variable rate debt, that was scheduled to mature in April 2011.  In March 2011, APCo, I&M and OPCo issued bilateral letters of credit to support the remarketing of $230 million, $77 million and $50 million, respectively, of their variable rate debt.  OPCo reacquired $115 million which is held by a trustee on its behalf.

Dividend Restrictions

Under the Federal Power Act, the Registrant Subsidiaries are restricted from paying dividends out of stated capital.  Various charter provisions and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

Sales of Receivables

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

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MINE SAFETY INFORMATION

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

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

		DHLC		CCPC		Conner Run
Number of Citations for Violations of Mandatory Health or
	Safety Standards under 104 *		-		-		-
Number of Orders Issued under 104(b) *			-		-		-
Number of Citations and Orders for Unwarrantable Failure
	to Comply with Mandatory Health or Safety Standards under
	104(d) *		-		-		-
Number of Flagrant Violations under 110(b)(2) *			-		-		-
Number of Imminent Danger Orders Issued under 107(a) *			-		-		-
Total Dollar Value of Proposed Assessments		$	1,123	$	400	$	-
Number of Mining-related Fatalities			-		-		-
* References to sections under the Mine Act

DHLC currently has three legal actions pending before the Federal Mine Safety and Health Review Commission. Two are related to actions challenging four violations issued by Mine Safety and Health Administration following an employee fatality in March 2009 and the third legal action is challenging a citation issued in August 2010 related to a dragline boom issue.

ACCOUNTING PRONOUNCEMENTS

Pronouncements Effective in the Future

The FASB issued ASU 2011-05 “Presentation of Comprehensive Income” eliminating the option to present the components of other comprehensive income as a part of the statement of shareholders’ equity.  The standard requires other comprehensive income be presented as part of a single continuous statement of comprehensive income or in a statement of other comprehensive income immediately following the statement of net income.  This standard will change the presentation of the financial statements but will not affect the calculation of net income or comprehensive income.  The Registrant Subsidiaries will retrospectively adopt ASU 2011-05 effective January 1, 2012.

Future Accounting Changes

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

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks

The Registrant Subsidiaries’ risk management assets and liabilities are managed by AEPSC as agent.  The related risk management policies and procedures are instituted and administered by AEPSC.  See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Market Risk” section.  Also, see Note 8 – Derivatives and Hedging and Note 9 – Fair Value Measurements for additional information related to the Registrant Subsidiaries’ risk management contracts.

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

	MTM Risk Management Contract Net Assets (Liabilities)
	Six Months Ended June 30, 2011
	(in thousands)
APCo
Total MTM Risk Management Contract Net Assets at December 31, 2010		$	26,882
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period			(3,767	)
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			(13	)
Changes in Fair Value Due to Market Fluctuations During the Period (b)			(861	)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)			4,328
Total MTM Risk Management Contract Net Assets at June 30, 2011			26,569
Commodity Cash Flow HedgeContracts			1,172
Collateral Deposits			7,389
Total MTM Derivative Contract Net Assets at June 30, 2011		$	35,130
OPCo
Total MTM Risk Management Contract Net Assets at December 31, 2010		$	18,264
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period			(2,804	)
Fair Value of New Contracts at Inception When Entered During the Period (a)			1,880
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered
During the Period			(75	)
Changes in Fair Value Due to Market Fluctuations During the Period (b)			3,180
Changes in Fair Value Allocated to Regulated Jurisdictions (c)			(2,399	)
Total MTM Risk Management Contract Net Assets at June 30, 2011			18,046
Commodity Cash Flow HedgeContracts			830
Collateral Deposits			5,220
Total MTM Derivative Contract Net Assets at June 30, 2011		$	24,096

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PSO
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2010	$	(378	)
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		132
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		(7	)
Changes in Fair Value Due to Market Fluctuations During the Period (b)		25
Changes in Fair Value Allocated to Regulated Jurisdictions (c)		141
Total MTM Risk Management Contract Net Assets (Liabilities) at June 30, 2011		(87	)
Commodity Cash Flow HedgeContracts		183
Collateral Deposits		44
Total MTM Derivative Contract Net Assets (Liabilities) at June 30, 2011	$	140
SWEPCo
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2010	$	(2,958	)
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		2,198
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		(7	)
Changes in Fair Value Due to Market Fluctuations During the Period (b)		41
Changes in Fair Value Allocated to Regulated Jurisdictions (c)		(339	)
Total MTM Risk Management Contract Net Assets (Liabilities) at June 30, 2011		(1,065	)
Commodity Cash Flow HedgeContracts		1,397
Collateral Deposits		43
Total MTM Derivative Contract Net Assets (Liabilities) at June 30, 2011	$	375

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

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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)
June 30, 2011
		Remainder
APCo		2011		2012-2014		2015		Total
		(in thousands)
Level 1 (a)		$	32	$	2	$	-	$	34
Level 2 (b)			1,966		15,065		1,471		18,502
Level 3 (c)			2,211		2,840		320		5,371
Total			4,209		17,907		1,791		23,907
Dedesignated Risk Management
	Contracts (d)		1,064		1,598		-		2,662
Total MTM Risk Management
	Contract Net Assets	$	5,273	$	19,505	$	1,791	$	26,569
		Remainder
OPCo		2011		2012-2014		2015		Total
		(in thousands)
Level 1 (a)		$	22	$	2	$	-	$	24
Level 2 (b)			643		10,794		1,021		12,458
Level 3 (c)			1,525		1,970		222		3,717
Total			2,190		12,766		1,243		16,199
Dedesignated Risk Management
	Contracts (d)		738		1,109		-		1,847
Total MTM Risk Management
	Contract Net Assets	$	2,928	$	13,875	$	1,243	$	18,046

		Remainder
PSO		2011		2012-2014		Total
		(in thousands)
Level 1 (a)		$	1	$	-	$	1
Level 2 (b)			(596)		508		(88)
Level 3 (c)			-		-		-
Total MTM Risk Management
	Contract Net Assets (Liabilities)	$	(595)	$	508	$	(87)

		Remainder
SWEPCo		2011		2012-2014		Total
		(in thousands)
Level 1 (a)		$	1	$	-	$	1
Level 2 (b)			(1,197)		131		(1,066)
Level 3 (c)			-		-		-
Total MTM Risk Management
	Contract Net Assets (Liabilities)	$	(1,196)	$	131	$	(1,065)

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(a)	Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.  Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.
(b)	Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.  If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1 and OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market.
(c)	Level 3 inputs are unobservable inputs for the asset or liability.  Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.
(d)	Dedesignated Risk Management Contracts are contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for “Derivatives and Hedging.”  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This will be amortized into Revenues over the remaining life of the contracts.

Credit Risk

Counterparty credit quality and exposure of the Registrant Subsidiaries is generally consistent with that of AEP.

Value at Risk (VaR) Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates VaR to measure commodity price risk in the risk management portfolio.  The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, at June 30, 2011, a near term typical change in commodity prices is not expected to have a material effect on net income, cash flows or financial condition.

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

	Six Months Ended									Twelve Months Ended
	June 30, 2011									December 31, 2010
Company		End		High		Average		Low		End		High		Average		Low
	(in thousands)									(in thousands)
APCo		$	109	$	553	$	147	$	66	$	124	$	659	$	193	$	71
OPCo			84		423		128		53		100		545		161		54
PSO			6		39		15		4		3		70		15		1
SWEPCo			6		46		19		4		6		93		21		2

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

As the VaR calculations capture recent price movements, management also performs regular stress testing of the portfolio to understand the exposure to extreme price movements.  Management employs a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last four years in order to ascertain which historical price movements translated into the largest potential MTM loss.  Management then researches the underlying positions, price movements and market events that created the most significant exposure and reports the findings to the Risk Executive Committee or the Commercial Operations Risk Committee as appropriate.

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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 June 30, 2011 and December 31, 2010, the estimated EaR on the Registrant Subsidiaries’ debt portfolio was as follows:

	June 30,		December 31,
Company	2011		2010
	(in thousands)
APCo	$	6,944	$	1,165
CSPCo		279		178
I&M		2,514		274
OPCo		9,597		926
PSO		66		658
SWEPCo		2,062		1,027

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CONTROLS AND PROCEDURES

During the second quarter of 2011, management, including the principal executive officer and principal financial officer of each of AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo (collectively, the Registrants), evaluated the Registrants’ disclosure controls and procedures.  Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of June 30, 2011, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.  The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the second quarter of 2011 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

The Annual Report on Form 10-K for the year ended December 31, 2010 includes a detailed discussion of risk factors.  The information presented below amends and restates in their entirety certain of those risk factors that have been updated and should be read in conjunction with the risk factors and information disclosed in the 2010 Annual Report on Form 10-K.

RISKS RELATING TO REGULATED OPERATIONS

All of the investment in and expenses related to the Turk Plant may not be fully recovered. – Affecting AEP and SWEPCo

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

·   The validity of the air permit issued by the Arkansas Department of Environmental Quality in connection with the operation of the Turk Plant.

·   A preliminary injunction issued by the Federal District Court for the Western District of Arkansas, and upheld by the Eighth Circuit Federal Court of Appeals, enjoining SWEPCo from completing work authorized by the permit issued by the U.S. Army Corps of Engineers, the U.S. Department of Interior and the U.S. Fish and Wildlife Service.  The preliminary injunction also raises other alleged violations of various federal and state laws.

·   Whether SWEPCo is required to obtain APSC approval to construct the Turk Plant without pursuing authority to seek recovery of the originally approved 88 MW portion of Turk Plant costs in Arkansas retail rates.

·   The validity of PUCT approval of the Texas jurisdictional cost recovery and uncertainty regarding the caps on recovery included in the approval.

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.

Rate recovery approved in Ohio may be overturned on appeal, may not provide full recovery of costs and/or may have to be returned. – Affecting AEP, CSPCo and OPCo

The PUCO issued an order in March 2009 that modified and approved the Electric Security Plans (ESPs) of CSPCo and OPCo.  The ESPs established rates in effect through 2011.  The ESP order generally authorized rate increases during the ESP period, subject to caps that limit the rate increases, and also provides a fuel adjustment clause for the three-year period of the ESPs.  The recovery includes deferrals associated with the Ormet interim arrangement and is subject to the PUCO’s ultimate decision regarding the Ormet interim arrangement deferrals plus related carrying charges.  If the PUCO and/or the Supreme Court of Ohio reverses all or part of the rate recovery or if deferred fuel costs are not fully recovered for other reasons, it could reduce future net income and cash flows and impact financial condition.  In April 2011, the Supreme Court of Ohio issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged which resulted in three reversals, only two of which may have a prospective impact through a remand proceeding.  Pursuant to a May 2011 PUCO order, CSPCo and OPCo implemented rates subject to refund and filed remand testimony in June 2011.  In June 2011, the Ohio Consumers’ Counsel and the IEU filed testimony recommending a complete denial of collection of any POLR charges and carrying charges on certain environmental investments collected from 2009 through 2011.  Hearings were held in July 2011.

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Request for rate and other recovery in Ohio for distribution service may not be approved in its entirety. – Affecting AEP, CSPCo and OPCo

In February 2011, CSPCo and OPCo filed with the PUCO for annual increases in distribution rates to be effective January 2012.  In addition to the annual increase, CSPCo and OPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets, including unrecognized equity carrying costs.  These assets would be recovered in a distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013.  If the PUCO denies all or part of the requested rate and other recovery, it could reduce future net income and cash flows and impact financial condition.

Request for rate recovery in Ohio for generation service may not be approved in its entirety. – Affecting AEP, CSPCo and OPCo

In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer pricing for generation effective with the first billing cycle of January 2012 through the last billing cycle of May 2014.  If the PUCO denies all or part of the requested rate recovery, it could reduce future net income and cash flows.  The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESPs could impact the outcome of the January 2012-May 2014 ESP, though the nature and extent of that impact is not presently known.

Request for rate and other recovery in Virginia for generation and distribution service may not be approved in its entirety. – Affecting AEP and APCo

In March 2011, APCo filed a generation and distribution base rate request with the Virginia SCC to increase annual base rates to be effective no later than February 2012.  APCo proposed to mitigate a portion of the requested base rate increase by maintaining current depreciation rates until the next biennial filing.  In addition, APCo filed for approval of rate adjustment clauses for various costs including environmental and renewable energy and generation costs relating to the partially completed Dresden Plant.  If the Virginia SCC denies all or part of the requested rate and other recovery, it could reduce future net income and cash flows.

Request for rate recovery in Michigan may not be approved in its entirety.  – Affecting AEP and I&M

In July 2011, I&M filed a request with the MPSC for annual increases in Michigan base rates.  The request includes an increase in depreciation rates that would result in an increase in depreciation expense.  If the MPSC denies all or part of the requested rate recovery, it could reduce future net income and cash flows.

RISKS RELATING TO OWNING AND OPERATING GENERATION ASSETS AND SELLING POWER

Courts adjudicating nuisance and other similar claims against us may order us to limit or reduce our CO2 emissions.  (Applies to each registrant)

In 2004, eight states and the City of New York filed an action in Federal District Court for the Southern District of New York against AEP, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority.  The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants.  The actions allege that CO2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming, and sought injunctive relief in the form of specific emission reduction commitments from the defendants.  The Second Circuit Court of Appeals reinstated this lawsuit on appeal after the lower court had dismissed it.  The U.S. Supreme Court reversed the Court of Appeals, finding that any federal common law nuisance claim has been displaced by the provisions of the Clean Air Act that authorize Federal EPA to regulate CO2 emissions.  The Supreme Court remanded the case for consideration of plaintiffs' state law nuisance claims.

The lower courts may dismiss the state law nuisance claims without prejudice to refiling in state court.  If the court finds a basis to retain jurisdiction over those claims, it could order the defendants, including us, to limit or reduce CO2 emissions.  This or similar remedies could require us to purchase power from third parties to fulfill our commitments to supply power to our customers.  This could have a material impact on our costs.  While management believes such costs should be recoverable from customers as costs of doing business, without such recovery those costs could reduce our future net income and cash flows and harm our financial condition.

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Other pending cases seek damages based on allegations of federal and state common law nuisance.  If these or other future actions are resolved against us, substantial modifications of our existing coal-fired power plants could be required.  In addition, we could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay damages or penalties and/or halt operations.  Moreover, our results of operations and financial position could be reduced due to the timing of recovery of these investments and the expense of ongoing litigation.

Our costs of compliance with existing environmental laws are significant.   (Applies to each registrant.)

Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety.  Approximately 90% of the electricity generated by the AEP System is produced by the combustion of fossil fuels.  Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generating plants are expected to be subject to increased regulations, controls and mitigation expenses.  Compliance with these legal requirements requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees and permits at all of our facilities and could cause us to retire generating capacity prior to the end of its estimated useful life.  These expenditures have been significant in the past and we expect that they will continue to be significant in order to comply with the current and proposed regulations.  Costs of compliance with environmental regulations could adversely affect our net income and financial position, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increase.  If we retire generating plants prior to the end of their estimated useful life, there can be no assurance that we will recover the remaining costs associated with such plants.  While we expect to recover our expenditures for pollution control technologies, replacement generation and associated operating costs from customers through regulated rates (in regulated jurisdictions) or market prices, without such recovery those costs could reduce our future net income and cash flows, and possibly harm our financial condition.

RISKS RELATING TO MARKET ECONOMICS OR FINANCIAL VOLATILITY AND OTHER RISKS

Our financial performance may be adversely affected if we are unable to successfully operate our facilities or perform certain corporate functions.   (Applies to each registrant.)

Our performance is highly dependent on the successful operation of our generation, transmission and distribution facilities.  Operating these facilities involves many risks, including:

·   Operator error and breakdown or failure of equipment or processes.

·   Operating limitations that may be imposed by environmental or other regulatory requirements.

·   Labor disputes.

·   Compliance with mandatory reliability standards, including mandatory cyber security standards.

·   Information technology failure.

·   Cyber intrusion.

·   Fuel supply interruptions caused by transportation constraints, adverse weather, non-performance by our suppliers and other factors.

·   Catastrophic events such as fires, earthquakes, explosions, hurricanes, terrorism, floods or other similar occurrences.

A decrease or elimination of revenues from our electric generation, transmission and distribution facilities or an increase in the cost of operating the facilities would adversely affect our results of operations.

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RISKS RELATED TO STATE RESTRUCTURING

Customers have recently begun to select alternative electric generation service providers, as allowed by Ohio legislation. – Affecting AEP, CSPCo and OPCo

Under current Ohio legislation, electric generation is sold in a competitive market in Ohio, and native load customers in Ohio have the ability to switch to alternative suppliers for their electric generation service.  Competitive power suppliers are targeting retail customers by offering alternative generation service.   A growing number of commercial retail customers (primarily CSPCo’s) have switched to alternative generation providers while additional Ohio customers have provided notice of their intent to switch.  Although to date OPCo’s losses have not been significant, OPCo could experience additional customer switching in the future.  These evolving market conditions will continue to impact CSPCo's and OPCo’s results of operations.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information about purchases by AEP or its publicly-traded subsidiaries during the quarter ended June 30, 2011 of equity securities that are registered by AEP or its publicly-traded subsidiaries pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASES OF EQUITY SECURITIES

Period	Total Number of Shares Purchased			Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
04/01/11 – 04/30/11		-		$	-		-	$	-
05/01/11 – 05/31/11		-			-		-		-
06/01/11 – 06/30/11		23	(a)		81.80		-		-

(a) OPCo purchased 15 shares of its 4.50% cumulative preferred stock and SWEPCo purchased 8 shares of its 5.00% cumulative preferred stock in privately-negotiated transactions outside of an announced program.

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Item 5.  Other Information

NONE

Item 6.  Exhibits

AEP

4(d) – Amended and Restated Credit Agreement for $1.5 Billion Dated July 2011.

4(e) – Credit Agreement for $1.75 Billion Dated July 2011.

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:  July 29, 2011

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