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 JuneSeptember 30, 2008
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____

Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address of Principal Executive Offices, and Telephone Number Identification No.
     
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation) 13-4922640
1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790
1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203
1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455
1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation) 73-0410895
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation) 72-0323455
     
All Registrants 1 Riverside Plaza, Columbus, Ohio 43215-2373  
  Telephone (614) 716-1000  

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

Indicate by check mark whether American Electric Power Company, Inc. 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 31,October 30, 2008
  
American Electric Power Company, Inc.                         402,258,849403,554,634 
 ($6.50 par value)
Appalachian Power Company13,499,500
 (no par value)
Columbus Southern Power Company16,410,426
 (no par value)
Indiana Michigan Power Company1,400,000
 (no par value)
Ohio Power Company27,952,473
 (no par value)
Public Service Company of Oklahoma9,013,000
 ($15 par value)
Southwestern Electric Power Company7,536,640
 ($18 par value)


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX TO QUARTERLY REPORTS ON FORM 10-Q
JuneSeptember 30, 2008

Glossary of Terms
 
Forward-Looking Information
 
Part I. FINANCIAL INFORMATION
  
Items 1, 2 and 3 - Financial Statements, Management’s Financial Discussion and Analysis and Quantitative and Qualitative Disclosures About Risk Management Activities:
American Electric Power Company, Inc. and Subsidiary Companies:
Management’s Financial Discussion and Analysis of Results of Operations
Quantitative and Qualitative Disclosures About Risk Management Activities
Condensed Consolidated Financial Statements
Index to Condensed Notes to Condensed Consolidated Financial Statements
 
Appalachian Power Company and Subsidiaries:
Management’s Financial Discussion and Analysis
Quantitative and Qualitative Disclosures About Risk Management Activities
Condensed Consolidated Financial Statements
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
Columbus Southern Power Company and Subsidiaries:
Management’s Narrative Financial Discussion and Analysis
Quantitative and Qualitative Disclosures About Risk Management Activities
Condensed Consolidated Financial Statements
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
Indiana Michigan Power Company and Subsidiaries:
Management’s Narrative Financial Discussion and Analysis
Quantitative and Qualitative Disclosures About Risk Management Activities
Condensed Consolidated Financial Statements
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
Ohio Power Company Consolidated:
Management’s Financial Discussion and Analysis
Quantitative and Qualitative Disclosures About Risk Management Activities
Condensed Consolidated Financial Statements
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
Public Service Company of Oklahoma:
Management’s Financial Discussion and Analysis
Quantitative and Qualitative Disclosures About Risk Management Activities
Condensed Financial Statements
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
Southwestern Electric Power Company Consolidated:
Management’s Financial Discussion and Analysis
Quantitative and Qualitative Disclosures About Risk Management Activities
Condensed Consolidated Financial Statements
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
Combined Management’s Discussion and Analysis of Registrant Subsidiaries
 
Controls and Procedures
 
Part II.  OTHER INFORMATION
 
Item 1.Legal Proceedings
Item 1A.Risk Factors
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds
Item 4.Submission of Matters to a Vote of Security Holders
Item 5.Other Information
Item 6.Exhibits:
Exhibit 10(a) (AEP)
Exhibit 3(a) (PSO, SWEPCo) 10(b) (AEP)
Exhibit 3(b) (CSPCo, OPCo) 10(c) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
Exhibit 10(d) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
Exhibit 10(e) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
Exhibit 10(f) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
Exhibit 12 (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
Exhibit 31(a) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
Exhibit 31(b) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
Exhibit 32(a) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
Exhibit 32(b) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)
 
SIGNATURE

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




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

Term Meaning

AEGCo AEP Generating Company, an AEP electric utility subsidiary.
AEP or Parent American Electric Power Company, Inc.
AEP Consolidated AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East companies APCo, CSPCo, I&M, KPCo and OPCo.
AEPSC American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AEP System or the System American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP Power PoolMembers are APCo, CSPCo, I&M, KPCo and OPCo.  The Pool shares the generation, cost of generation and resultant wholesale off-system sales of the member companies.
AEP West companies PSO, SWEPCo, TCC and TNC.
AFUDC Allowance for Funds Used During Construction.
ALJ Administrative Law Judge.
AOCI Accumulated Other Comprehensive Income.
APCo Appalachian Power Company, an AEP electric utility subsidiary.
APSC Arkansas Public Service Commission.
CAA Clean Air Act.
CO2
 Carbon Dioxide.
Cook PlantDonald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CTC Competition Transition Charge.
CWIP Construction Work in Progress.
DETM Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
DOE United States Department of Energy.
E&R Environmental compliance and transmission and distribution system reliability.
EaR Earnings at Risk, a method to quantify risk exposure.
EITF Financial Accounting Standards Board’s Emerging Issues Task Force.
EITF 06-10EITF Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements.”
EPS Earnings Per Share.
ERCOT Electric Reliability Council of Texas.
ETTElectric Transmission Texas, LLC, a 50% equity interest joint venture with MidAmerican Energy Holding Company formed to own and operate electric transmission facilities in ERCOT.
FASB Financial Accounting Standards Board.
Federal EPA United States Environmental Protection Agency.
FERC Federal Energy Regulatory Commission.
FIN FASB Interpretation No.
FIN 46R FIN 46R, “Consolidation of Variable Interest Entities.”
FIN 48 
FIN 48, “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1 “Definition of Settlement in FASB Interpretation No. 48.”
FSP FASB Staff Position.
FTR 
Financial Transmission Right.Right, a financial instrument that entitles the holder to receive compensation for
    certain congestion-related transmission charges that arise when the power grid is congested
    resulting in differences in locational prices.
GAAP Accounting Principles Generally Accepted in the United States of America.
HPL Houston Pipeline Company, a former AEP 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.
I&M Indiana Michigan Power Company, an AEP electric utility subsidiary.
JMG JMG Funding LP.
KPCo Kentucky Power Company, an AEP electric utility subsidiary.
KPSC Kentucky Public Service Commission.
kV Kilovolt.
KWH Kilowatthour.
LPSC Louisiana Public Service Commission.
MISO Midwest Independent Transmission System Operator.
MTM Mark-to-Market.
MW Megawatt.
MWH Megawatthour.
NOx
 Nitrogen oxide.
Nonutility Money Pool AEP System’s Nonutility Money Pool.
NSR New Source Review.
NYMEXNew York Mercantile Exchange.
OCC Corporation Commission of the State of Oklahoma.
OPCo Ohio Power Company, an AEP electric utility subsidiary.
OPEB Other Postretirement Benefit Plans.
OTC Over-the-counter.
PJM Pennsylvania – New Jersey – Maryland regional transmission organization.
PMParticulate 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.
REP Texas Retail Electric Provider.
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.
RSP Rate Stabilization Plan.
RTO Regional Transmission Organization.
S&P Standard and Poor’s.
SCR Selective Catalytic Reduction.
SEC United States Securities and Exchange Commission.
SECA Seams Elimination Cost Allocation.
SFAS Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board.
SFAS 71 Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation.”
SFAS 133 Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.”
SFAS 157Statement of Financial Accounting Standards No. 157, “Fair Value Measurements.”
SIASystem Integration Agreement.
SNF Spent Nuclear Fuel.
SO2
 Sulfur Dioxide.
SPP Southwest Power Pool.
Stall Unit J. Lamar Stall Unit at Arsenal Hill Plant.
Sweeny Sweeny Cogeneration Limited Partnership, owner and operator of a four unit, 480 MW gas-fired generation facility, owned 50% by AEP.  AEP’s 50% interest in Sweeny was sold in October 2007.
SWEPCo Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC AEP Texas Central Company, an AEP electric utility subsidiary.
TEM SUEZ Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing, Inc.).
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.
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.
VaR Value at Risk, a method to quantify risk exposure.
Virginia SCC Virginia State Corporation Commission.
WPCo Wheeling Power Company, an AEP electric distribution subsidiary.
WVPSC Public Service Commission of West Virginia.




FORWARD-LOOKING INFORMATION

This report made by AEP and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Although AEP and each of its Registrant Subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

·Electric load and customer growth.
·Weather conditions, including storms.
·Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·Availability of generating capacity and the performance of our generating plants.
·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 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 canceled)cancelled) through applicable rate cases or competitive rates.
·New legislation, litigation and government regulation including requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances.
·Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions (including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance).
·Resolution of litigation (including disputes arising from the bankruptcy of Enron Corp. and related matters).
·Our ability to constrain operation and maintenance costs.
·The economic climate and growth or contraction, in our service territory and changes in market demand and demographic patterns.
·Inflationary and interest rate trends.
·Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairingimpacting our ability to refinance existing debt at attractive rates.
·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.markets.
·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 the recently-passed utility law in Ohio and the allocation of costs within RTOs.
·Accounting pronouncements periodically issued by accounting standard-setting bodies.
·The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans and nuclear decommissioning trust.trust and the impact on future funding requirements.
·Prices for power that we generate and sell at wholesale.
·Changes in technology, particularly with respect to new, developing or alternative sources of generation.
·Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events.


    The registrants expressly disclaim any obligation to update any forward-looking information.


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Base Rate Filings

Our significant base rate filings include:

Operating
Company
 Jurisdiction Revised Annual Rate Increase Request Projected Effective Date of Rate Increase  Jurisdiction Revised Annual Rate Increase Request Projected Effective Date of Rate Increase 
   (in millions)      (in millions)   
APCo Virginia $208 November 2008(a) Virginia $208 October 2008   (a) 
PSO Oklahoma  117(b)February 2009  Oklahoma  117(b)February 2009 
I&M Indiana  80 June 2009  Indiana  80 June 2009 

(a)
Subject to refund.An October settlement agreement of $168 million is pending with the Virginia SCC.
(b)Net of estimated amounts that PSO expects to recover through a generation cost recovery rider which will terminate upon implementation of the new base rates.


Ohio Electric Security Plan Filings

In April 2008, the Ohio legislature passed Senate Bill 221, which amends the restructuring law effective July 31, 2008 and requires electric utilities to adjust their rates by filing an Electric Security Plan (ESP).  In July 2008, within the parameters of the ESPs, CSPCo and OPCo each requested an annual rate increase for 2009 through 2011 that would not exceed approximately 15% per year.
Credit Markets

In recent months, the world and U.S. economies have experienced significant slowdowns.  These economic slowdowns have impacted and will continue to impact our residential, commercial and industrial sales. Concurrently, the financial markets have become increasingly unstable and constrained at both a global and domestic level.  This systemic marketplace distress is impacting our access to capital, our liquidity, asset valuations in our trust funds, the creditworthy status of our customers, suppliers and trading partners and our cost of capital.  Our financial staff actively manages these factors with oversight from our risk committee.  The uncertainties in the credit markets could have significant implications on our subsidiaries since they rely on continuing access to capital to fund operations and capital expenditures.

The current credit markets are constraining our ability to issue new debt, including commercial paper, and refinance existing debt.  Approximately $120 million and $300 million of our $16 billion of long-term debt as of September 30, 2008 will mature in the remainder of 2008 and 2009, respectively.  We intend to refinance these maturities.  To support our operations, we have $3.9 billion in aggregate credit facility commitments.  These commitments include 27 different banks with no bank having more than 10% of our total bank commitments.  In September 2008 and October 2008, we borrowed $600 million and $1.4 billion, respectively, under our credit agreements to enhance our cash position during this period of market disruptions.  In October 2008, we also renewed our $600 million sale of receivables agreement through October 2009.  At September 30, 2008, our available liquidity was approximately $3 billion.

We cannot predict the length of time the current credit situation will continue or the impact on our future operations and our ability to issue debt at reasonable interest rates.  However, when market conditions improve, we plan to repay the amounts drawn under the credit facilities, re-enter the commerical paper market and issue other long-term debt.  If there is not an improvement in access to capital, we believe that we have adequate liquidity to support our planned business operations and construction program through 2009.

We have significant investments in several trust funds to provide for future payments of pensions, OPEB, nuclear decommissioning and spent nuclear fuel disposal.  All of our trust funds’ investments are well-diversified and managed in compliance with all laws and regulations.  The value of the investments in these trusts has declined due to the decreases in the equity and fixed income markets.  Although the asset values are currently lower, this has not affected the funds’ ability to make their required payments.  As of September 30, 2008, the decline in pension asset values will not require us to make a contribution in 2008 or 2009.

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. Our risk management organization monitors these exposures on a daily basis to limit our economic and financial statement impact on a counterparty basis.  At September 30, 2008, our credit exposure net of collateral was approximately $827 million of which approximately 84% is to investment grade counterparties.  At September 30, 2008, our exposure to financial institutions was $145 million, which represents 18% of our total credit exposure net of collateral (all investment grade).  A
Capital Expenditures

Due to recent credit market instability, we are currently reviewing our projections for capital expenditures from our previous projection of $6.75 billion for 2009 through 2010.  We plan to identify reductions of approximately $750 million for 2009.  We are evaluating possible additional capital reductions for 2010.  We are also reviewing our projections for operation and maintenance expense.  Our intent is to keep operation and maintenance expense flat in 2009 as compared to 2008.

Cook Plant Unit 1 Fire and Shutdown

Cook Plant Unit 1 (Unit 1) is a 1,030 MW nuclear generating unit located in Bridgman, Michigan. In September 2008, I&M shut down Unit 1 due to turbine vibrations likely caused by blade failure which resulted in a fire on the electric generator.  This equipment is in the turbine building and is separate and isolated from the nuclear reactor.  The steam turbines that caused the vibration were installed in 2006 and are under warranty from the vendor.  The warranty provides for the replacement of the turbines if the damage was caused by a defect in the design or assembly of the turbines.  I&M is also working with its insurance company, Nuclear Electric Insurance Limited (NEIL), and turbine vendor to evaluate the extent of the damage resulting from the incident and the costs to return the unit to service.  We cannot estimate the ultimate costs of the outage at this time.  Management believes that I&M should recover a significant portion of these costs through the requested increases results fromturbine vendor’s warranty, insurance and the implementationregulatory process.  Our preliminary analysis indicates that Unit 1 could resume operations as early as late first quarter/early second quarter of 2009 or as late as the second half of 2009, depending upon whether the damaged components can be repaired or whether they need to be replaced. 
I&M maintains property insurance through NEIL with a fuel$1 million deductible.  I&M also maintains a separate accidental outage policy with NEIL whereby, after a 12 week deductible period, I&M is entitled to weekly payments of $3.5 million during the outage period for a covered loss.  If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if the unit is not returned to service in a reasonable period of time, it could have an adverse impact on net income, cash flows and financial condition.

Hurricanes

During the third quarter of 2008, our CSPCo, OPCo, SWEPCo and TCC service territories were significantly impacted by Hurricanes Dolly, Gustav and/or Ike.  Through September 30, 2008, we had incurred $54 million in total incremental operation and maintenance costs related to the three hurricanes.  Since we believe that cost recovery mechanism.related to the hurricanes is probable for most of these costs in our CSPCo, OPCo, and TCC service territories, we recorded $37 million in regulatory assets for these hurricane costs as of September 30, 2008.  We intend to pursue the recovery of $11 million of incremental hurricane costs incurred in our SWEPCo service territory.

Turk PlantNew Generation

In July 2008,May 2006, we announced plans to build the PUCT approvedStall Unit, a certificate of convenience and necessity for construction of the plant.  We expect a written ordernew intermediate load, 500 MW, natural gas-fired generating unit at SWEPCo’s existing Arsenal Hill Plant location in August 2008 which will also provide for the conditions of the PUCT’s approval.Shreveport, Louisiana.  SWEPCo has received approvals from allthe Louisiana Public Service Commission (LPSC) and the Public Utility Commission of Texas (PUCT) to construct the Stall Unit and is currently waiting for approval from the APSC.  The Stall Unit is estimated to cost $378 million, excluding AFUDC, and is expected to be in-service in mid-2010.

In August 2006, we announced plans to jointly build the Turk Plant, a new base load, 600 MW, pulverized coal, ultra-supercritical generating unit in Arkansas.  SWEPCo has received approvals from the APSC and the LPSC to construct the Turk Plant.  In August 2008, the PUCT issued an order approving the Turk Plant subject to certain conditions, including the capping of capital costs of the state commissions that regulate its retail rates and services.  However,Turk Plant at the APSC approval has been appealed to the Arkansas State Court of Appeals.$1.5 billion projected construction cost.  SWEPCo is also working with the Arkansas Department of Environmental Quality for the approval of an air permit and the U.S. Army Corps of Engineers for approval later this year.  Through June 30, 2008, SWEPCo capitalized $407 million in expenditures related to the Turk Plant.

IGCC Plants

We have delayed construction of the West Virginia and Ohio IGCC plants.  In May 2008, the Virginia SCC denied APCo’s request to reconsider the Virginia SCC's previous denial of APCo’s request to recover initial costs associated with a proposed IGCC plant in West Virginia.  In July 2008, the WVPSC issued a notice seeking comments from parties on how the WVPSC should proceed regarding its earlier approval of a wetlands and stream impact permit.  Once SWEPCo receives the IGCC plant.  In Ohio, CSPCo and OPCo awaitair permit, they will commence construction.  The Turk Plant is estimated to cost $1.5 billion, excluding AFUDC, with SWEPCo’s portion estimated to cost $1.1 billion.  If these permits are approved on a timely basis, the result of an Ohio Supreme Court remandplant is expected to the PUCO regarding recovery of IGCC pre-construction costs.be in-service in 2012.
 
Fuel Costs

We currently estimate 2008 coal prices to increase by about 20%approximately 28% due to escalating domestic prices and increased needs, primarily in the east.  We had initially expected coal costs to increase by 13% in 2008.  We continue to see increases in prices due to expiring lower pricedlower-priced coal and transportation contracts being replaced with higher pricedhigher-priced contracts.  Prices for fuel oil are at record highs and remain volatile.  We have limited exposure to price risk related toexposure in Ohio, representing approximately 20% of our open positions for coal, natural gas and fuel oil especiallycosts, since we do not currently have an active fuel cost recovery adjustment mechanism in Ohio, which represents approximately 20% of our fuel costs.mechanism.  However, under Ohio’s amended restructuring law, we have requested the PUCO to reinstate a fuel cost recovery mechanism effective January 1, 2009.  Fuel cost adjustment rate clauses in our other jurisdictions will help offset future negative impacts of fuel price increases on our gross margins.

Capital Expenditures

We reduced our projections for capital expenditures to approximately $6.75 billion from $7.35 billion for 2009 through 2010.

RESULTS OF OPERATIONS

Segments

Our principal operating business 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.

MEMCOAEP River Operations
·Barging operations that annually transport approximately 35 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and Lower Mississippi Rivers.  Approximately 39% of the barging is for the transportation of agricultural products, 30% for coal, 14% for steel and 17% for other commodities.  Effective July 30, 2008, AEP MEMCO LLC'sLLC’s name was changed to AEP River Operations LLC.

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

The table below presents our consolidated Income Before Discontinued Operations and Extraordinary Loss by segment for the three and sixnine months ended JuneSeptember 30, 2008 and 2007.

Three Months Ended June 30, Six Months Ended June 30, 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2008 2007 2008 2007 2008 2007 2008 2007 
(in millions) (in millions) 
Utility Operations $263  $238  $673  $491  $357  $388  $1,030  $879 
MEMCO Operations  3   7   10   22 
AEP River Operations  11   18   21   40 
Generation and Marketing  26   15   27   14   16   3   43   17 
All Other (a)  (12)  (3)  143   1   (10)  (2)  133   (1)
Income Before Discontinued Operations
and Extraordinary Loss
 $280  $257  $853  $528  $374  $407  $1,227  $935 

(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 will gradually liquidate and completely expire in 2011.
 ·The first quarter of 2008 cash settlement of a purchase power and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006.  The cash settlement of $255 million ($163 million, net of tax) is included in Net Income.
 ·Revenue sharing related to the Plaquemine Cogeneration Facility.


AEP Consolidated

SecondThird Quarter of 2008 Compared to SecondThird Quarter of 2007

Income Before Discontinued Operations and Extraordinary Loss in 2008 increased $23decreased $33 million compared to 2007 primarily due to an increasea decrease in Utility Operations segment earnings of $25$31 million.  The increasedecrease in Utility Operations segment earnings primarily relates to an increase in fuel and consumables expense in Ohio and a decrease in cooling degree days throughout our service territories, partially offset by increases in retail margins due to rate increases implemented since the second quarter of 2007 in Ohio, Virginia, West Virginia, Texas and Oklahoma, higher off-system sales and unfavorable regulatory provisions recorded in the prior year related to our Virginia and Texas jurisdictions, partially offset by higher operation and maintenance expenses system-wide and higher fuel expenses in Ohio.Oklahoma.

Average basic shares outstanding increased to 402 million in 2008 from 399 million in 2007 primarily due to the issuance of shares under our incentive compensation and dividend reinvestment plans.  Actual shares outstanding were 402403 million as of JuneSeptember 30, 2008.

SixNine Months Ended JuneSeptember 30, 2008 Compared to SixNine Months Ended JuneSeptember 30, 2007

Income Before Discontinued Operations and Extraordinary Loss in 2008 increased $325$292 million compared to 2007 primarily due to an increase in Utility Operations segment earnings of $182 million and income of $163 million (net of tax) from the cash settlement ofreceived in 2008 related to a power purchase-and-sale agreement with TEM related to the Plaquemine Cogeneration Facility which was soldand an increase in the fourth quarterUtility Operations segment earnings of 2006.$151 million.  The increase in Utility Operations segment earnings primarily relates to rate increases implemented since the second quarter of 2007 in Ohio, Virginia, West Virginia, Texas and Oklahoma and higher off-system sales, and lower operation and maintenance expenses as a result of a favorable Oklahoma ice storm settlement partially offset by higher interest expense.and fuel expenses.

Average basic shares outstanding increased to 401402 million in 2008 from 398 million in 2007 primarily due to the issuance of shares under our incentive compensation and dividend reinvestment plans.  Actual shares outstanding were 402403 million as of JuneSeptember 30, 2008.

Utility Operations

Our Utility Operations segment includes primarily regulated revenues with direct and variable offsetting expenses and net reported commodity trading operations.  We believe that a discussion of the results from our Utility Operations segment on a gross margin basis is most appropriate in order to further understand the key drivers of the segment.  Gross margin represents utility operating revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power.

Utility Operations Income Summary
For the Three and SixNine Months Ended JuneSeptember 30, 2008 and 2007

Three Months Ended
June 30,
 
Six Months Ended
June 30,
  
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
 
2008 2007 2008 2007  2008  2007  2008  2007 
(in millions)  (in millions) 
Revenues$3,313 $2,954 $6,607 $5,987  $3,968  $3,600  $10,575  $9,587 
Fuel and Purchased Power 1,374  1,109  2,587  2,228   1,841   1,413   4,428   3,641 
Gross Margin 1,939 1,845  4,020  3,759   2,127   2,187   6,147   5,946 
Depreciation and Amortization 365 365  720  748   379   374   1,099   1,122 
Other Operating Expenses 1,026  957  1,967  1,948   1,034   1,037   3,001   2,985 
Operating Income 548 523  1,333  1,063   714   776   2,047   1,839 
Other Income, Net 47 27  89  45   46   27   135   72 
Interest Charges and Preferred Stock Dividend Requirements 218 207  428  386   225   213   653   599 
Income Tax Expense 114  105  321  231   178   202   499   433 
Income Before Discontinued Operations and Extraordinary Loss$263 $238 $673 $491  $357  $388  $1,030  $879 


Summary of Selected Sales and Weather Data
For Utility Operations
For the Three and SixNine Months Ended JuneSeptember 30, 2008 and 2007

Three Months Ended
June 30,
 
Six Months Ended
June 30,
  
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
 
Energy/Delivery SummaryEnergy/Delivery Summary2008 2007 2008 2007  2008  2007  2008  2007 
(in millions of KWH) (in millions of KWH) 
EnergyEnergy                       
Retail:Retail:                       
Residential 9,829 10,127  24,329  24,267 
Commercial 9,909 10,227  19,456  19,586 
Industrial 15,060 14,848  29,410  28,413 
Miscellaneous 639  632  1,248  1,245 
Residential  12,754   13,749   37,084   38,015 
Commercial  10,794   11,164   30,249   30,750 
Industrial  14,761   14,697   44,171   43,110 
Miscellaneous  668   686   1,916   1,932 
Total RetailTotal Retail 35,437 35,834  74,443  73,511   38,977   40,296   113,420   113,807 
                           
WholesaleWholesale 10,932 9,376  22,597  18,154   13,130   13,493   35,728   31,648 
                           
DeliveryDelivery                           
Texas Wires – Energy delivered to customers served
by AEP’s Texas Wires Companies
Texas Wires – Energy delivered to customers served
by AEP’s Texas Wires Companies
 7,132  6,746  12,955  12,577   7,961   7,721   20,916   20,297 
Total KWHsTotal KWHs 53,501  51,956  109,995  104,242   60,068   61,510   170,064   165,752 

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

Summary of Weather Data
Summary of Heating and Cooling Degree Days for Utility Operations
For the Three and SixNine Months Ended JuneSeptember 30, 2008 and 2007

Three Months Ended
June 30,
 
Six Months Ended
June 30,
  
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
 
2008 2007 2008 2007  2008  2007  2008  2007 
(in degree days) (in degree days) 
Weather Summary                       
Eastern Region                       
Actual – Heating (a) 136 222  1,960  2,039   -   2   1,960   2,041 
Normal – Heating (b) 175 174  1,943  1,966   7   7   1,950   1,973 
                           
Actual – Cooling (c) 272 367  272  382   651   808   924   1,189 
Normal – Cooling (b) 278 275  281  278   687   685   969   963 
                           
Western Region (d)
                           
Actual – Heating (a) 40 92  989  994   -   -   989   994 
Normal – Heating (b) 35 33  966  991   2   2   967   993 
                           
Actual – Cooling (c) 675 622  700  678   1,250   1,406   1,951   2,084 
Normal – Cooling (b) 652 656  672  674   1,402   1,411   2,074   2,084 

(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 and western region cooling degree days are calculated on a 65 degree temperature base.
(d)Western region statistics represent PSO/SWEPCo customer base only.


SecondThird Quarter of 2008 Compared to SecondThird Quarter of 2007

Reconciliation of SecondThird Quarter of 2007 to SecondThird Quarter of 2008
Income from Utility Operations Before Discontinued Operations and Extraordinary Loss
(in millions)

Second Quarter of 2007   $238 
Third Quarter of 2007    $388 
            
Changes in Gross Margin:            
Retail Margins 47     (81)    
Off-system Sales 40     (7)    
Transmission Revenues 11     4     
Other Revenues (4)   
Other  24     
Total Change in Gross Margin   94       (60)
             
Changes in Operating Expenses and Other:             
Other Operation and Maintenance (70)     -     
Depreciation and Amortization -     (5)    
Taxes Other Than Income Taxes (1)     2     
Carrying Costs Income 10     7     
Interest Income 6     8     
Other Income, Net 6     5     
Interest and Other Charges (11)     (12)    
Total Change in Operating Expenses and Other   (60)      5 
             
Income Tax Expense    (9)      24 
             
Second Quarter of 2008   $263 
Third Quarter of 2008     $357 

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss decreased $31 million to $357 million in 2008.  The key drivers of the decrease were a $60 million decrease in Gross Margin offset by a $5 million decrease in Operating Expenses and Other and a $24 million decrease in Income Tax Expense.

The major components of the net decrease in Gross Margin were as follows:

·Retail Margins decreased $81 million primarily due to the following:
·
A $78 million increase in related to increased fuel and consumable expenses in Ohio.  CSPCo and OPCo have applied for an active fuel clause in their Ohio ESP to be effective January 1, 2009.
·An $80 million decrease in usage primarily due to a 19% decrease in cooling degree days in our eastern region, an 11% decrease in cooling degree days in our western region as well as outages caused by Hurricanes Dolly, Gustav and Ike.  Approximately 17% of our reduction in load was attributable to these storms.
These decreases were partially offset by:
·A $61 million increase related to net rate increases implemented in our Ohio jurisdictions, an $8 million increase related to recovery of E&R costs in Virginia and the construction financing costs rider in West Virginia, a $6 million increase in base rates in Texas and a $6 million increase in base rates in Oklahoma.
·A $9 million increase related to increased usage by Ormet, an industrial customer in Ohio.  See “Ormet” section of Note 3.
·Margins from Off-system Sales decreased $7 million primarily due to lower trading margins and the favorable effects of a fuel reconciliation recorded in our western service territory in the third quarter of 2007, partially offset by increases in East physical off-system sales margins due mostly to higher prices.
·Transmission Revenues increased $4 million primarily due to increased rates in the SPP region.
·Other revenues increased $24 million primarily due to increased third-party engineering and construction work and an increase in pole attachment revenue.

Utility Operating Expenses and Other and Income Taxes changed between years as follows:

·Other Operation and Maintenance expenses were flat in comparison to 2007.  We experienced decreases related to the following:
·A $77 million decrease related to the recording of the NSR settlement in the third quarter of 2007.  We are evaluating methods to pursue recovery in all of our affected jurisdictions.
·A $9 million decrease related to the establishment of a regulatory asset in the third quarter of 2008 for Virginia’s share of previously expended NSR settlement costs.
These decreases were offset by:
·A $24 million increase in non-storm system improvements, customer work and other distribution expenses.
·A $21 million increase in storm restoration costs, primarily related to Hurricanes Dolly, Gustav and Ike.
·A $15 million increase in recoverable PJM expenses in Ohio.
·A $10 million increase in generation plant maintenance.
·An $8 million increase in recoverable customer account expenses related to the Universal Service Fund for Ohio customers who qualify for payment assistance.
·An $8 million increase in transmission expenses for tree trimming and reliability.
·Depreciation and Amortization expense increased $5 million primarily due to higher depreciable property balances from the installation of environmental upgrades.
·Carrying Costs Income increased $7 million primarily due to increased carrying cost income on cost deferrals in Virginia and Oklahoma.
·Interest Income increased $8 million primarily due to the favorable effect of claims for refund filed with the IRS.
·Interest and Other Charges increased $12 million primarily due to additional debt issued and higher interest rates on variable rate debt.
·Income Tax Expense decreased $24 million due to a decrease in pretax income.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Reconciliation of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2008
Income from Utility Operations Before Discontinued Operations and Extraordinary Loss
(in millions)

Nine Months Ended September 30, 2007    $879 
        
Changes in Gross Margin:       
Retail Margins  79     
Off-system Sales  73     
Transmission Revenues  22     
Other Revenues  27     
Total Change in Gross Margin      201 
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  11     
Gain on Dispositions of Assets, Net  (18)    
Depreciation and Amortization  23     
Taxes Other Than Income Taxes  (9)    
Carrying Costs Income  26     
Interest Income  25     
Other Income, Net  12     
Interest and Other Charges  (54)    
Total Change in Operating Expenses and Other      16 
         
Income Tax Expense      (66)
         
Nine Months Ended September 30, 2008     $1,030 

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss increased $25$151 million to $263$1,030 million in 2008.  The key drivers of the increase were a $94$201 million increase in Gross Margin offset byand a $60$16 million increasedecrease in Operating Expenses and Other andoffset by a $9$66 million increase in Income Tax Expense.

The major components of the net increase in Gross Margin were as follows:

·Retail Margins increased $47$79 million primarily due to the following:
 ·A $39$148 million increase related to net rate increases implemented in our Ohio jurisdictions, a $17$39 million increase related to recovery of E&R costs in Virginia and the construction financing costs rider in West Virginia, a $3$20 million increase in base rates in TexasOklahoma and a $6$17 million increase in base rates in Oklahoma.Texas.
 ·A $38$42 million increase related to increased usage by Ormet, an industrial customer in Ohio.  See “Ormet” section of Note 3.
·A $37 million net increase due to adjustments recorded in the prior year related to the 2007 Virginia base rate case which included a second quarter 2007 provision for revenue refund.
 ·A $25$29 million increase due to a second quarter 2007 provision related to a SWEPCo Texas fuel reconciliation proceeding.
·A $12 million increase related to increased usage by Ormet, an industrial customercoal contract amendments in Ohio.  See “Ormet” section of Note 3.
·An $11 million increase primarily related to higher revenues under formula rate plans at I&M.2008.
 These increases were partially offset by:
 ·
A $90$164 million decrease related to increased fuel and consumable expenses in Ohio.  CSPCo and PJM costsOPCo have applied for an active fuel clause in their Ohio which included a $29 million expense resulting from a coal contract amendment.ESP to be effective January 1, 2009.
 ·
A $20$65 million decrease in usage related to weather primarily from a 26% decrease in cooling degree days and a 39% decrease in heating degree days in our eastern region.
·Margins from Off-system Sales increased $40 million primarily due to higher east physical off-system sales margins mostly due to higher volumes and stronger prices, partially offset by lower trading margins.
·Transmission Revenues increased $11 million primarily due to increased usage in the SPP and ERCOT regions and increased rates in the SPP region.

Utility Operating Expenses and Other and Income Taxes changed between years as follows:

·Other Operation and Maintenance expenses increased $70 million primarily due to increases in generation expenses for non-outage maintenance at Cook plant and outage expenses at other plants, transmission reliability expenses, recoverable PJM and customer account expenses in Ohio and administrative and general expenses primarily related to employee benefits.
·Depreciation and Amortization expense was flat primarily due to lower commission-approved depreciation rates in Indiana, Michigan, Oklahoma and Texas and lower Ohio regulatory asset amortization, offset by higher depreciable property balances and prior year adjustments related to the 2007 Virginia base rate case.
·Carrying Costs Income increased $10 million primarily due to increased carrying cost income on cost deferrals in Virginia and Oklahoma.
·Interest and Other Charges increased $11 million primarily due to additional debt issued and higher interest rates on variable rate debt.
·Income Tax Expense increased $9 million due to an increase in pretax income.

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

Reconciliation of Six Months Ended June 30, 2007 to Six Months Ended June 30, 2008
Income from Utility Operations Before Discontinued Operations and Extraordinary Loss
(in millions)

Six Months Ended June 30, 2007          $491 
              
Changes in Gross Margin:             
Retail Margins        162    
Off-system Sales        80    
Transmission Revenues        19    
Total Change in Gross Margin           261 
              
Changes in Operating Expenses and Other:             
Other Operation and Maintenance        11    
Gain on Dispositions of Assets, Net        (19)   
Depreciation and Amortization        28    
Taxes Other Than Income Taxes        (11)   
Carrying Costs Income        19    
Interest Income        17    
Other Income, Net        8    
Interest and Other Charges        (42)   
Total Change in Operating Expenses and Other           11 
              
Income Tax Expense           (90)
              
Six Months Ended June 30, 2008          $673 

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss increased $182 million to $673 million in 2008.  The key drivers of the increase were a $261 million increase in Gross Margin and an $11 million decrease in Operating Expenses and Other offset by a $90 million increase in Income Tax Expense.
The major components of the net increase in Gross Margin were as follows:

·Retail Margins increased $162 million primarily due to the following:
·An $83 million increase related to net rate increases implemented in our Ohio jurisdictions, a $31 million increase related to recovery of E&R costs in Virginia and the construction financing costs rider in West Virginia, a $12 million increase in base rates in Texas and a $14 million increase in base rates in Oklahoma.
·A $33 million increase related to increased usage by Ormet, an industrial customer in Ohio.  See “Ormet” section of Note 3.
·A $29 million increase related to coal contract amendments in 2008.
·A $28 million increase related to increased residential and commercial usage and customer growth.
·A $25 million increase due to a second quarter 2007 provision related to a SWEPCo Texas fuel reconciliation proceeding.
·A $21 million increase related to increased sales to municipal, cooperative and other customers primarily a result of new power supply contracts and higher revenues under formula rate plans at I&M.
These increases were partially offset by:
·A $79 million decrease related to increased fuel, consumable and PJM costs in Ohio.
·A $23 million decrease in usage related to weather primarily from a 29%22% decrease in cooling degree days in our eastern region and a 6% decrease in cooling degree days in our western region.
·
A $29 million increase in the sharing of off-system sales margins with customers due to an increase in total off-system sales.
·Margins from Off-system Sales increased $80$73 million primarily due to higher east physical off-system sales margins mostly due toin our eastern territory as the result of higher volumes and strongerhigher prices, aided by additional generation available in 2008 due to fewer planned outages and lower internal load.  This increase was partially offset by lower trading margins.margins and the favorable effects of a fuel reconciliation recorded in our western territory in the third quarter of 2007.
·Transmission Revenues increased $19$22 million primarily due to increased usage in the SPP and ERCOT regions and increased rates in the ERCOT and SPP region.regions.
·Other Revenues increased $27 million primarily due to increased third-party engineering and construction work, an increase in pole attachment revenue and the recording of an unfavorable provision for TCC for the refund of bonded rates recorded in 2007.

Utility Operating Expenses and Other and Income Taxes changed between years as follows:

·Other Operation and Maintenance expenses decreased $11 million primarily due to the following:
·A $77 million decrease related to the recording of NSR settlement costs in September 2007.  We are evaluating methods to pursue recovery in all of our affected jurisdictions.
·A $62 million decrease related to the deferral of Oklahoma storm restoration costs in the first quarter of 2008, net of amortization, of $63 million in Oklahoma as a result of a rate settlement to recover 2007 storm restoration costscosts.
·A $19 million decrease in generation plant removal costs.
These decreases were partially offset by anby:
·A $33 million increase in tree trimming, reliability and system improvement expense.
·A $29 million increase in recoverable PJM expenses in Ohio.
·A $23 million increase in generation plant operations and maintenance expense.
·A $21 million increase in recoverable customer account expenses related to the Universal Service Fund for Ohio customers who qualify for payment assistance.
·A $16 million increase in storm restoration costs, primarily related to Hurricanes Dolly, Gustav and Ike, which occurred in the third quarter of 2008.
·A $16 million increase in maintenance expense at the Cook plant,Plant.
·A $10 million increase related to the write-off of the unrecoverable pre-construction costs for PSO’s canceledcancelled Red Rock Generating Facility recoverable PJM and customer account expenses in Ohio and increases in administrative and general expenses primarily related to employee benefits.the first quarter of 2008.
·Gain on Disposition of Assets, Net decreased $19$18 million primarily due to the cessationexpiration of the earnings sharing agreement with Centrica from the sale of our Texas REPs in 2002.  In 2007, we received the final earnings sharing payment of $20 million.
·Depreciation and Amortization expense decreased $28$23 million primarily due to lower commission-approved depreciation rates in Indiana, Michigan, Oklahoma and Texas and lower Ohio regulatory asset amortization, partially offset by higher depreciable property balances and prior year adjustments related to the Virginia base rate case.
·Taxes Other Than Income Taxes increased $11$9 million primarily due to favorable adjustments to property tax returns recorded in the prior year.
·Carrying Costs Income increased $19$26 million primarily due to increased carrying cost income on cost deferrals in Virginia and Oklahoma.
·Interest Income increased $17$25 million primarily due to the favorable effect of claims for refund filed with the IRS.
·Other Income, Net increased $12 million primarily due to an increase in the equity component of AFUDC as a result of new generation projects.
·Interest and Other Charges increased $42$54 million primarily due to additional debt issued and higher interest rates on variable rate debt.
·Income Tax Expense increased $90$66 million due to an increase in pretax income.

MEMCOAEP River Operations

SecondThird Quarter of 2008 Compared to SecondThird Quarter of 2007

Income Before Discontinued Operations and Extraordinary Loss from our MEMCOAEP River Operations segment decreased to $3$11 million in 2008 from $7$18 million in 2007 primarily due to high water conditionssignificant disruptions of ship arrivals and reduced northbound loadings.  Fuel consumptiondepartures as the result of an oil spill in the New Orleans Harbor.  Ship arrivals were further disrupted by the impacts of Hurricanes Gustav and other operating costs were higherIke, which caused severe flooding on the Mississippi and Illinois Rivers.  The decrease in income was also due to the sustained high water conditions on all major rivers on which we operate.  Northbound loadings continue to be depressed as a result of reduced imports through the Gulf of Mexico.higher diesel fuel prices.  Additionally, decreases in import demand and grain export demand have resulted in lower freight demand, partially offset by increased coal exports.

SixNine Months Ended JuneSeptember 30, 2008 Compared to SixNine Months Ended JuneSeptember 30, 2007

Income Before Discontinued Operations and Extraordinary Loss from our MEMCOAEP River Operations segment decreased to $10$21 million in 2008 from $22$40 million in 2007 primarily due to high water conditionssignificant flooding on various inland waterways throughout 2008 and reduced northbound loadings.  Fuel consumptionrising diesel fuel prices.  Additionally, decreases in import demand and other operating costs were higher duegrain export demand have resulted in lower freight demand, largely the result of a slowing U.S. economy and a weak U.S. dollar.  The impact of Hurricanes Gustav and Ike and the oil spill in the New Orleans Harbor, all of which occurred during the third quarter of 2008, also contributed to the sustained high water conditions on all major rivers on which we operate.  Northbound loadings continue to be depressed as a result of reduced imports through the Gulf of Mexico.unfavorable variance.

Generation and Marketing

SecondThird Quarter of 2008 Compared to SecondThird Quarter of 2007

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment increased to $26$16 million in 2008 from $15$3 million in 2007 primarily due to favorable marketing contracts in ERCOT, higher gross margins atfrom its marketing activities and higher gross margins due to improved price realization, plant performance and hedging activities from its share of the Oklaunion plant from optimization activities and an increase in income from wind farm operations.Power Station.

SixNine Months Ended JuneSeptember 30, 2008 Compared to SixNine Months Ended JuneSeptember 30, 2007

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment increased to $27$43 million in 2008 from $14$17 million in 2007 primarily due to favorable marketing contracts in ERCOT, higher gross margins atfrom its marketing activities and higher gross margins due to improved price realization, plant performance and hedging activities from its share of the Oklaunion plant from optimization activities  and an increase in income from wind farm operations.Power Station.

All Other

SecondThird Quarter of 2008 Compared to SecondThird Quarter of 2007

Loss Before Discontinued Operations and Extraordinary Loss from All Other increased to $12$10 million in 2008 from $3$2 million in 2007.  The increase in the loss primarily relates to lower cash balances yielding lower interest income and higher interest expenseexpenses due to the issuance of AEP Junior Subordinated Debentures issued in March 2008 and increased short-term borrowings.lower interest income from affiliates.

SixNine Months Ended JuneSeptember 30, 2008 Compared to SixNine Months Ended JuneSeptember 30, 2007

Income Before Discontinued Operations and Extraordinary Loss from All Other increased to $143$133 million in 2008 from a $1 million loss in 2007.  In 2008, we had after-tax income of $163 million from a litigation settlement of a power purchase and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006.  The settlement was recorded as a pretax credit to Asset Impairments and Other Related ItemsCharges of $255 million in the accompanying Condensed Consolidated Statements of Income.  In 2007, we had a $16 million pretax gain ($10 million, net of tax) on the sale of a portion of our investment in Intercontinental Exchange, Inc. (ICE).

AEP System Income Taxes

Income Tax Expense increased $15decreased $13 million in the secondthird quarter of 2008 compared to the secondthird quarter of 2007 primarily due to an increasea decrease in pretax income.

Income Tax Expense increased $178$165 million in the six-monthnine-month period ended JuneSeptember 30, 2008 compared to the six-monthnine-month period ended JuneSeptember 30, 2007 primarily due to an increase in pretax income.

FINANCIAL CONDITION

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

Debt and Equity Capitalization
 June 30, 2008 December 31, 2007  September 30, 2008  December 31, 2007 
 ($ in millions)  ($ in millions) 
Long-term Debt, including amounts due within one year $15,753 58.0%$14,994 58.1% $16,007   56.6%   $14,994   58.1%
Short-term Debt  705 2.6  660 2.6   1,302   4.6   660   2.6 
Total Debt 16,458 60.6  15,654 60.7   17,309   61.2   15,654   60.7 
Common Equity 10,631 39.2  10,079 39.1   10,917   38.6   10,079   39.1 
Preferred Stock  61 0.2  61 0.2   61   0.2   61   0.2 
                          
Total Debt and Equity Capitalization $27,150 100.0%$25,794 100.0% $28,287   100.0% $25,794   100.0%

Our ratio of debt to total capital decreasedincreased from 60.7% to 60.6%61.2% in 2008 due to our net earningsissuance of debt to fund construction and increased common equityour strategy to deal with the credit situation by drawing cash from stock issuances through stock compensation and dividend reinvestment plans.our credit facilities.

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability.  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 and common stock.

Credit Markets

In recent months, the financial markets have become increasingly unstable and constrained at both a global and domestic level.  This systemic marketplace distress is impacting our access to capital, our liquidity and our cost of capital.  The uncertainties in the credit markets could have significant implications on our subsidiaries since they rely on continuing access to capital to fund operations and capital expenditures.  The current credit markets are constraining our ability to issue new debt, including commercial paper, and refinance existing debt.

We believe that we have adequate liquidity under our credit facilitiesfacilities.  In September 2008, in response to the bankruptcy of certain companies and tightening of credit markets, we borrowed $600 million under our credit lines to assure that cash is available to meet our working capital needs.  In October 2008, we borrowed an additional $1.4 billion under our existing credit facilities.  We took this proactive step to enhance our cash position during this period of market disruptions.

We cannot predict the length of time the current credit situation will continue or the impact on our future operations and our ability to issue debt at reasonable interest rates.  However, when market conditions improve, we plan to repay the amounts drawn under the credit facilities and issue other long-term debtdebt.  If there is not an improvement in access to capital, we believe that we have adequate liquidity to support our planned business operations and construction program through 2009.

In the current credit markets.  Asfirst quarter of June 30, 2008, we had $313 million outstanding of tax-exempt long-term debt sold at auction ratesdue to the exposure that reset every 35 days.  This debt is insured by bond insurers previously AAA-rated, namelylike Ambac Assurance Corporation and Financial Guaranty Insurance Co. Due to the exposure that these bond insurers havehad in connection with developments in the subprime credit market, the credit ratings of thesethose insurers have beenwere downgraded or placed on negative outlook.  These market factors have contributed to higher interest rates in successful auctions and increasing occurrences of failed auctions for tax-exempt long-term debt sold at auction rates, including many of the auctions of our tax-exempt long-term debt.  Consequently, we chose to exit the auction-rate debt market.  Through September 30, 2008, we reduced our outstanding auction rate securities by $1.2 billion.  As of September 30, 2008, we had $272 million outstanding of tax-exempt long-term debt sold at auction rates (rates range between 4.353% and 13%) that reset every 35 days.  Approximately $218 million of this debt relates to a lease structure with JMG that we are unable to refinance at this time.  In order to refinance this debt, we need the lessor’s consent.  This debt is insured by the previously AAA-rated bond insurers.  The instruments under which the bonds are issued allow us to convert to other short-term variable-rate structures, term-put structures and fixed-rate structures.  Through June 30, 2008, we reduced our outstanding auction rate securities by $1.2 billion.  We plan to continue the conversion and refunding process for the remaining $313 million to other permitted modes, including term-put structures, variable-rate and fixed-rate structures, during the second half of 2008 to lower our interest rates as such opportunities arise.

As of JuneSeptember 30, 2008, $367 million of the prior auction rate debt was issued in a weekly variable rate mode supported by letters of credit at variable rates ranging from 1.45%6.5% to 1.68% and $3848.25%, $495 million was issued at fixed rates ranging from 4.85%4.5% to 5.625%.  As of June 30, 2008, and trustees held, on our behalf, approximately $400$330 million of our reacquired auction rate tax-exempt long-term debt which we plan to reissue to the public as market conditions permit.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  At JuneSeptember 30, 2008, our available liquidity was approximately $3.1$3 billion as illustrated in the table below:
  Amount Maturity
  (in millions)  
Commercial Paper Backup:    
Revolving Credit Facility $1,500 March 2011
Revolving Credit Facility  1,454(a)April 2012
Revolving Credit Facility  627(a)April 2011
Revolving Credit Facility  338(a)April 2009
Total  3,919  
Short-term Investments  490  
Cash and Cash Equivalents  338  
Total Liquidity Sources  4,747  
Less: AEP Commercial Paper Outstanding  701  
   Cash Drawn on Credit Facilities  591  
   Letters of Credit Drawn  439  
      
Net Available Liquidity $3,016  

   Amount Maturity
   (in millions)  
Commercial Paper Backup:      
 Revolving Credit Facility  $1,500 March 2011
 Revolving Credit Facility   1,500 April 2012
Revolving Credit Facility   650 April 2011
Revolving Credit Facility   350 April 2009
Total   4,000  
Cash and Cash Equivalents   218  
Total Liquidity Sources   4,218  
Less: AEP Commercial Paper Outstanding   698  
         Letters of Credit Drawn   429  
       
Net Available Liquidity  $3,091  
(a)Reduced by Lehman Brothers Holdings Inc.’s commitment amount of $81 million following its bankruptcy.

The revolving credit facilities for commercial paper backup arewere structured as two $1.5 billion credit facilities.facilities which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $46 million following its bankruptcy.  In March 2008, the credit facilities were amended so that $750 million may be issued under each credit facility as letters of credit.

We use our corporate borrowing program to meet the short-term borrowing needs of our subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries.  In addition, we also fund, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  As of JuneSeptember 30, 2008, we had credit facilities totaling $3 billion to support our commercial paper program.  The maximum amount of commercial paper outstanding during the first sixnine months of 2008 was $1.2 billion.  The weighted-average interest rate of our commercial paper during the first sixnine months of 2008 was 3.22%3.25%.

In April 2008, we entered into a $650 million 3-year credit agreement and a $350 million 364-day credit agreement.agreement which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23 million and $12 million, respectively, following its bankruptcy.  Under the facilities, we may issue letters of credit.  As of JuneSeptember 30, 2008, $371$372 million of letters of credit were issued under the 3-year credit agreement to support variable rate demand notes.

Investments in Auction-Rate Securities

During the first six months ofPrior to June 30, 2008, we sold all of our investment in auction-rate securities at par.

Sale of Receivables

In October 2008, we renewed our sale of receivables agreement.  The sale of receivables agreement provides a commitment of $600 million from bank conduits to purchase receivables.  This agreement will expire in October 2009.

Debt Covenants and Borrowing Limitations

Our revolving credit agreements, including the new agreements entered into in April 2008, contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%.  The method for calculating our outstanding debt and other capital is contractually defined. At JuneSeptember 30, 2008, this contractually-defined percentage was 55.9%57.3%.  Nonperformance of these covenants could result in an event of default under these credit agreements.  At JuneSeptember 30, 2008, 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 permit the lenders to declare the outstanding amounts payable.

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

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders.  At JuneSeptember 30, 2008, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

We have declared common stock dividends payable in cash in each quarter since July 1910.  The Board of Directors declared a quarterly dividend of $0.41 per share in JulyOctober 2008.  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.  We have the option to defer interest payments on the $315 million of AEP Junior Subordinated Debentures issued in March 2008 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 believe that these restrictions will not have a material effect on our results of operations,net income, cash flows, financial condition or limit any dividend payments in the foreseeable future.

Credit Ratings

In the first quarter of 2008, Moody’s changed its outlook from stable to negative for APCo, SWEPCo, OPCo and TCC and affirmed its stable outlook for AEP and our other rated subsidiaries.  Also in the first quarter, Fitch downgraded PSO and SWEPCo from A- to BBB+ for senior unsecured debt.  In May 2008, Fitch revised APCo’s outlook from stable to negative.  Our current credit ratings are as follows:

 Moody’s S&P Fitch
      
AEP Short TermShort-term DebtP-2 A-2 F-2
AEP Senior Unsecured DebtBaa2 BBB BBB

If we or any of our rated subsidiaries receive an upgrade from any of the rating agencies listed above, our borrowing costs could decrease.  If we receive a downgrade in our credit ratings by one of the rating agencies listed above, our borrowing costs could increase and access to borrowed funds could be negatively affected.

Cash Flow

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

Six Months Ended Nine Months Ended 
June 30, September 30, 
2008 2007 2008 2007 
(in millions) (in millions) 
Cash and Cash Equivalents at Beginning of Period $178  $301  $178  $301 
Net Cash Flows from Operating Activities  1,197   969   2,053   1,630 
Net Cash Flows Used for Investing Activities  (1,645)  (2,127)   (3,061)  (2,935)
Net Cash Flows from Financing Activities  488   1,029   1,168   1,200 
Net Increase (Decrease) in Cash and Cash Equivalents  40   (129)   160   (105)
Cash and Cash Equivalents at End of Period $218  $172  $338  $196 

Cash from operations, combined with a bank-sponsored receivables purchase agreement and short-term borrowings, provides working capital and allows us to meet other short-term cash needs.

Operating Activities
 Six Months Ended Nine Months Ended 
 June 30, September 30, 
 2008 2007 2008 2007 
 (in millions) (in millions) 
Net Income $854 $451  $1,228  $858 
Less Discontinued Operations, Net of Tax  (1) (2)
Less: Discontinued Operations, Net of Tax  (1)  (2)
Income Before Discontinued Operations  853 449   1,227   856 
Depreciation and Amortization  736 763   1,123   1,144 
Other  (392) (243)  (297)  (370)
Net Cash Flows from Operating Activities $1,197 $969  $2,053  $1,630 

Net Cash Flows from Operating Activities increased in 2008 primarily due to the TEM settlement.

Net Cash Flows from Operating Activities were $1.2$2.1 billion in 2008 consisting primarily of Income Before Discontinued Operations of $853 million$1.2 billion and $736 million$1.1 billion of noncash depreciationDepreciation and amortization.Amortization.  Other represents items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Significant changes in other items include an increase in under-recovered fuel reflecting higher coal and natural gas prices.

Net Cash Flows from Operating Activities were $1$1.6 billion in 2007 consisting primarily of Income Before Discontinued Operations of $449$856 million and $763 million$1.1 billion of noncash depreciationDepreciation and amortization.Amortization.  Other represents items that had a prior 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 resulted in lower cash from operations due to a number of items, the most significant of which relates primarily to the Texas CTC refund of fuel over-recovery.

Investing Activities

 Nine Months Ended 
 September 30, 
 2008 2007 
 (in millions) 
Construction Expenditures $(2,576) $(2,595)
Purchases/Sales of Investment Securities, Net  (474)  217 
Acquisition of Assets  (97)  (512)
Proceeds from Sales of Assets  83   78 
Other  3   (123)
Net Cash Flows Used for Investing Activities $(3,061) $(2,935)
                       Six Months Ended 
                       June 30, 
                       2008 2007 
 (in millions) 
Construction Expenditures$(1,608)$(1,823)
Acquisition of Darby and Lawrenceburg Plants -  (427)
Acquisition of Other Assets (81) - 
Proceeds from Sales of Assets 69  74 
Other (25) 49 
Net Cash Flows Used for Investing Activities$(1,645)$(2,127)

Net Cash Flows Used for Investing Activities were $1.6$3.1 billion in 2008 primarily due to Construction Expenditures for our environmental, distribution and new generation investment plan.  Construction expenditures decreased compared to 2007 due to a decline in environmental, fossil, hydro and nuclear projects partially offset by increased expenditures for new generation and transmission projects.

Net Cash Flows Used for Investing Activities were $2.1$2.9 billion in 2007 primarily due to Construction Expenditures for our environmental, distribution and new generation investment plan.  We paid $427$512 million to purchase gas-fired generating units to acquire capacity at a cost below that of building a new, comparable plant.

In our normal course of business, we purchase and sell investment securities with cash available for short-term investments.investments including the cash drawn against our credit facilities in 2008.  We also purchase and sell investment securities within our nuclear trusts.  The net amount of these activities is included in Other.

We forecast approximately $2.2$1.2 billion of construction expenditures for the remainder of 2008.  Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  These construction expenditures will be funded through results ofcash flows from operations and financing activities.

Financing Activities

 Nine Months Ended 
 September 30, 
 2008 2007 
 (in millions) 
Issuance of Common Stock $106  $116 
Issuance/Retirement of Debt, Net  1,621   1,623 
Dividends Paid on Common Stock  (494)  (467)
Other  (65)  (72)
Net Cash Flows from Financing Activities $1,168  $1,200 
                       Six Months Ended 
                       June 30, 
                       2008 2007 
 (in millions) 
Issuance of Common Stock$72 $90 
Issuance/Retirement of Debt, Net 777  1,294 
Dividends Paid on Common Stock (330) (311)
Other (31) (44)
Net Cash Flows from Financing Activities$488 $1,029 

Net Cash Flows from Financing Activities in 2008 were $488 million$1.2 billion primarily due to the issuance of additional debt including $315 million of junior subordinated debenturesJunior Subordinated Debentures and a net increase of $1$1.3 billion in outstanding senior unsecured notesSenior Unsecured Notes partially offset, by the reacquisition of a net $440$370 million of pollution control bondsPollution Control Bonds and retirements of $53$125 million of mortgage notes and $75Securitization Bonds.  In September 2008, we borrowed $600 million of securitization bonds.under our credit agreements.  See Note 9 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows from Financing Activities in 2007 were $1$1.2 billion primarily due to issuing $1.1$1.9 billion of debt securities including $1 billion of new debt for plant acquisitions and construction and increasing short-term commercial paper borrowings.  We paid common stock dividends of $311 million.

Our capital investment plans for 2008 will require additional funding from the capital markets.

Off-balance Sheet ArrangementsNew Generation

Under
In May 2006, we announced plans to build the Stall Unit, a limited setnew intermediate load, 500 MW, natural gas-fired generating unit at SWEPCo’s existing Arsenal Hill Plant location in Shreveport, Louisiana.  SWEPCo has received approvals from the Louisiana Public Service Commission (LPSC) and the Public Utility Commission of circumstances,Texas (PUCT) to construct the Stall Unit and is currently waiting for approval from the APSC.  The Stall Unit is estimated to cost $378 million, excluding AFUDC, and is expected to be in-service in mid-2010.

In August 2006, we enter into off-balance sheet arrangementsannounced plans to accelerate cash collections, reduce operational expensesjointly build the Turk Plant, a new base load, 600 MW, pulverized coal, ultra-supercritical generating unit in Arkansas.  SWEPCo has received approvals from the APSC and spread riskthe LPSC to construct the Turk Plant.  In August 2008, the PUCT issued an order approving the Turk Plant subject to certain conditions, including the capping of losscapital costs of the Turk Plant at the $1.5 billion projected construction cost.  SWEPCo is also working with the Arkansas Department of Environmental Quality for the approval of an air permit and the U.S. Army Corps of Engineers for the approval of a wetlands and stream impact permit.  Once SWEPCo receives the air permit, they will commence construction.  The Turk Plant is estimated to third parties.  Our current guidelines restrictcost $1.5 billion, excluding AFUDC, with SWEPCo’s portion estimated to cost $1.1 billion.  If these permits are approved on a timely basis, the use of off-balance sheet financing entities or structuresplant is expected to traditional operating lease arrangementsbe in-service in 2012.
Fuel Costs

We currently estimate 2008 coal prices to increase by approximately 28% due to escalating domestic prices and sales of customer accounts receivable that we enterincreased needs, primarily in the normal courseeast.  We had initially expected coal costs to increase by 13% in 2008.  We continue to see increases in prices due to expiring lower-priced coal and transportation contracts being replaced with higher-priced contracts.  We have price risk exposure in Ohio, representing approximately 20% of business.  our fuel costs, since we do not have an active fuel cost recovery mechanism.  However, under Ohio’s amended restructuring law, we have requested the PUCO to reinstate a fuel cost recovery mechanism effective January 1, 2009.  Fuel cost adjustment rate clauses in our other jurisdictions will help offset future negative impacts of fuel price increases on our gross margins.

RESULTS OF OPERATIONS

Segments

Our significant off-balance sheet arrangementsprincipal operating business segments and their related business activities are as follows:

 
June 30,
2008
 
December 31,
2007
 
 (in millions)
AEP Credit Accounts Receivable Purchase Commitments$564 $507 
Rockport Plant Unit 2 Future Minimum Lease Payments 2,142  2,216 
Railcars Maximum Potential Loss From Lease Agreement 26  30 
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
·Barging operations that annually transport approximately 35 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and Lower Mississippi Rivers.  Approximately 39% of the barging is for the transportation of agricultural products, 30% for coal, 14% for steel and 17% for other commodities.  Effective July 30, 2008, AEP MEMCO LLC’s name was changed to AEP River Operations LLC.

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

The table below presents our consolidated Income Before Discontinued Operations and Extraordinary Loss by segment for the three and nine months ended September 30, 2008 and 2007.

 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 2008 2007 2008 2007 
 (in millions) 
Utility Operations $357  $388  $1,030  $879 
AEP River Operations  11   18   21   40 
Generation and Marketing  16   3   43   17 
All Other (a)  (10)  (2)  133   (1)
Income Before Discontinued Operations and Extraordinary Loss $374  $407  $1,227  $935 

(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 will gradually liquidate and completely expire in 2011.
·The first quarter of 2008 cash settlement of a purchase power and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006.  The cash settlement of $255 million ($163 million, net of tax) is included in Net Income.
·Revenue sharing related to the Plaquemine Cogeneration Facility.

AEP Consolidated

Third Quarter of 2008 Compared to Third Quarter of 2007

Income Before Discontinued Operations and Extraordinary Loss in 2008 decreased $33 million compared to 2007 primarily due to a decrease in Utility Operations segment earnings of $31 million.  The decrease in Utility Operations segment earnings primarily relates to an increase in fuel and consumables expense in Ohio and a decrease in cooling degree days throughout our service territories, partially offset by increases in retail margins due to rate increases in Ohio, Virginia, West Virginia, Texas and Oklahoma.

Average basic shares outstanding increased to 402 million in 2008 from 399 million in 2007 primarily due to the issuance of shares under our incentive compensation and dividend reinvestment plans.  Actual shares outstanding were 403 million as of September 30, 2008.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Income Before Discontinued Operations and Extraordinary Loss in 2008 increased $292 million compared to 2007 primarily due to income of $163 million (net of tax) from the cash settlement received in 2008 related to a power purchase-and-sale agreement with TEM and an increase in Utility Operations segment earnings of $151 million.  The increase in Utility Operations segment earnings primarily relates to rate increases implemented since the second quarter of 2007 in Ohio, Virginia, West Virginia, Texas and Oklahoma and higher off-system sales, partially offset by higher interest and fuel expenses.

Average basic shares outstanding increased to 402 million in 2008 from 398 million in 2007 primarily due to the issuance of shares under our incentive compensation and dividend reinvestment plans.  Actual shares outstanding were 403 million as of September 30, 2008.

Utility Operations

Our Utility Operations segment includes primarily regulated revenues with direct and variable offsetting expenses and net reported commodity trading operations.  We believe that a discussion of the results from our Utility Operations segment on a gross margin basis is most appropriate in order to further understand the key drivers of the segment.  Gross margin represents utility operating revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power.

Utility Operations Income Summary
For complete information on each of these off-balance sheet arrangements see the “Off-balance Sheet Arrangements” section of “Management’s Financial DiscussionThree and Analysis of Results of Operations” in theNine Months Ended September 30, 2008 and 2007 Annual Report.

  
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
 
  2008  2007  2008  2007 
  (in millions) 
Revenues $3,968  $3,600  $10,575  $9,587 
Fuel and Purchased Power  1,841   1,413   4,428   3,641 
Gross Margin  2,127   2,187   6,147   5,946 
Depreciation and Amortization  379   374   1,099   1,122 
Other Operating Expenses  1,034   1,037   3,001   2,985 
Operating Income  714   776   2,047   1,839 
Other Income, Net  46   27   135   72 
Interest Charges and Preferred Stock Dividend Requirements  225   213   653   599 
Income Tax Expense  178   202   499   433 
Income Before Discontinued Operations and Extraordinary Loss $357  $388  $1,030  $879 


Summary Obligation Informationof Selected Sales Data
For Utility Operations
For the Three and Nine Months Ended September 30, 2008 and 2007

A summary
  
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
 
Energy/Delivery Summary 2008  2007  2008  2007 
  (in millions of KWH) 
Energy            
Retail:            
Residential  12,754   13,749   37,084   38,015 
Commercial  10,794   11,164   30,249   30,750 
Industrial  14,761   14,697   44,171   43,110 
Miscellaneous  668   686   1,916   1,932 
Total Retail  38,977   40,296   113,420   113,807 
                 
Wholesale  13,130   13,493   35,728   31,648 
                 
Delivery                
Texas Wires – Energy delivered to customers served by
   AEP’s Texas Wires Companies
  7,961   7,721   20,916   20,297 
Total KWHs  60,068   61,510   170,064   165,752 

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 associated number of customers within each.

Summary of Weather Data
Summary of Heating and Cooling Degree Days for Utility Operations
For the Three and Nine Months Ended September 30, 2008 and 2007

  
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
 
  2008  2007  2008  2007 
  (in degree days) 
Weather Summary            
Eastern Region            
Actual – Heating (a)  -   2   1,960   2,041 
Normal – Heating (b)  7   7   1,950   1,973 
                 
Actual – Cooling (c)  651   808   924   1,189 
Normal – Cooling (b)  687   685   969   963 
                 
Western Region (d)
                
Actual – Heating (a)  -   -   989   994 
Normal – Heating (b)  2   2   967   993 
                 
Actual – Cooling (c)  1,250   1,406   1,951   2,084 
Normal – Cooling (b)  1,402   1,411   2,074   2,084 

(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 and western region cooling degree days are calculated on a 65 degree temperature base.
(d)Western region statistics represent PSO/SWEPCo customer base only.

Third Quarter of 2008 Compared to Third Quarter of 2007

Reconciliation of Third Quarter of 2007 to Third Quarter of 2008
Income from Utility Operations Before Discontinued Operations and Extraordinary Loss
(in millions)

Third Quarter of 2007    $388 
        
Changes in Gross Margin:       
Retail Margins  (81)    
Off-system Sales  (7)    
Transmission Revenues  4     
Other  24     
Total Change in Gross Margin      (60)
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  -     
Depreciation and Amortization  (5)    
Taxes Other Than Income Taxes  2     
Carrying Costs Income  7     
Interest Income  8     
Other Income, Net  5     
Interest and Other Charges  (12)    
Total Change in Operating Expenses and Other      5 
         
Income Tax Expense      24 
         
Third Quarter of 2008     $357 

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss decreased $31 million to $357 million in 2008.  The key drivers of the decrease were a $60 million decrease in Gross Margin offset by a $5 million decrease in Operating Expenses and Other and a $24 million decrease in Income Tax Expense.

The major components of the net decrease in Gross Margin were as follows:

·Retail Margins decreased $81 million primarily due to the following:
·
A $78 million increase in related to increased fuel and consumable expenses in Ohio.  CSPCo and OPCo have applied for an active fuel clause in their Ohio ESP to be effective January 1, 2009.
·An $80 million decrease in usage primarily due to a 19% decrease in cooling degree days in our eastern region, an 11% decrease in cooling degree days in our western region as well as outages caused by Hurricanes Dolly, Gustav and Ike.  Approximately 17% of our reduction in load was attributable to these storms.
These decreases were partially offset by:
·A $61 million increase related to net rate increases implemented in our Ohio jurisdictions, an $8 million increase related to recovery of E&R costs in Virginia and the construction financing costs rider in West Virginia, a $6 million increase in base rates in Texas and a $6 million increase in base rates in Oklahoma.
·A $9 million increase related to increased usage by Ormet, an industrial customer in Ohio.  See “Ormet” section of Note 3.
·Margins from Off-system Sales decreased $7 million primarily due to lower trading margins and the favorable effects of a fuel reconciliation recorded in our western service territory in the third quarter of 2007, partially offset by increases in East physical off-system sales margins due mostly to higher prices.
·Transmission Revenues increased $4 million primarily due to increased rates in the SPP region.
·Other revenues increased $24 million primarily due to increased third-party engineering and construction work and an increase in pole attachment revenue.

Utility Operating Expenses and Other and Income Taxes changed between years as follows:

·Other Operation and Maintenance expenses were flat in comparison to 2007.  We experienced decreases related to the following:
·A $77 million decrease related to the recording of the NSR settlement in the third quarter of 2007.  We are evaluating methods to pursue recovery in all of our affected jurisdictions.
·A $9 million decrease related to the establishment of a regulatory asset in the third quarter of 2008 for Virginia’s share of previously expended NSR settlement costs.
These decreases were offset by:
·A $24 million increase in non-storm system improvements, customer work and other distribution expenses.
·A $21 million increase in storm restoration costs, primarily related to Hurricanes Dolly, Gustav and Ike.
·A $15 million increase in recoverable PJM expenses in Ohio.
·A $10 million increase in generation plant maintenance.
·An $8 million increase in recoverable customer account expenses related to the Universal Service Fund for Ohio customers who qualify for payment assistance.
·An $8 million increase in transmission expenses for tree trimming and reliability.
·Depreciation and Amortization expense increased $5 million primarily due to higher depreciable property balances from the installation of environmental upgrades.
·Carrying Costs Income increased $7 million primarily due to increased carrying cost income on cost deferrals in Virginia and Oklahoma.
·Interest Income increased $8 million primarily due to the favorable effect of claims for refund filed with the IRS.
·Interest and Other Charges increased $12 million primarily due to additional debt issued and higher interest rates on variable rate debt.
·Income Tax Expense decreased $24 million due to a decrease in pretax income.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Reconciliation of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2008
Income from Utility Operations Before Discontinued Operations and Extraordinary Loss
(in millions)

Nine Months Ended September 30, 2007    $879 
        
Changes in Gross Margin:       
Retail Margins  79     
Off-system Sales  73     
Transmission Revenues  22     
Other Revenues  27     
Total Change in Gross Margin      201 
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  11     
Gain on Dispositions of Assets, Net  (18)    
Depreciation and Amortization  23     
Taxes Other Than Income Taxes  (9)    
Carrying Costs Income  26     
Interest Income  25     
Other Income, Net  12     
Interest and Other Charges  (54)    
Total Change in Operating Expenses and Other      16 
         
Income Tax Expense      (66)
         
Nine Months Ended September 30, 2008     $1,030 

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss increased $151 million to $1,030 million in 2008.  The key drivers of the increase were a $201 million increase in Gross Margin and a $16 million decrease in Operating Expenses and Other offset by a $66 million increase in Income Tax Expense.

The major components of the net increase in Gross Margin were as follows:

·Retail Margins increased $79 million primarily due to the following:
·A $148 million increase related to net rate increases implemented in our Ohio jurisdictions, a $39 million increase related to recovery of E&R costs in Virginia and the construction financing costs rider in West Virginia, a $20 million increase in base rates in Oklahoma and a $17 million increase in base rates in Texas.
·A $42 million increase related to increased usage by Ormet, an industrial customer in Ohio.  See “Ormet” section of Note 3.
·A $37 million net increase due to adjustments recorded in the prior year related to the 2007 Virginia base rate case which included a second quarter 2007 provision for revenue refund.
·A $29 million increase due to coal contract amendments in 2008.
These increases were partially offset by:
·
A $164 million decrease related to increased fuel and consumable expenses in Ohio.  CSPCo and OPCo have applied for an active fuel clause in their Ohio ESP to be effective January 1, 2009.
·
A $65 million decrease in usage primarily due to a 22% decrease in cooling degree days in our eastern region and a 6% decrease in cooling degree days in our western region.
·
A $29 million increase in the sharing of off-system sales margins with customers due to an increase in total off-system sales.
·Margins from Off-system Sales increased $73 million primarily due to higher physical off-system sales in our eastern territory as the result of higher volumes and higher prices, aided by additional generation available in 2008 due to fewer planned outages and lower internal load.  This increase was partially offset by lower trading margins and the favorable effects of a fuel reconciliation recorded in our western territory in the third quarter of 2007.
·Transmission Revenues increased $22 million primarily due to increased rates in the ERCOT and SPP regions.
·Other Revenues increased $27 million primarily due to increased third-party engineering and construction work, an increase in pole attachment revenue and the recording of an unfavorable provision for TCC for the refund of bonded rates recorded in 2007.

Utility Operating Expenses and Other and Income Taxes changed between years as follows:

·Other Operation and Maintenance expenses decreased $11 million primarily due to the following:
·A $77 million decrease related to the recording of NSR settlement costs in September 2007.  We are evaluating methods to pursue recovery in all of our affected jurisdictions.
·A $62 million decrease related to the deferral of Oklahoma storm restoration costs in the first quarter of 2008, net of amortization, as a result of a rate settlement to recover 2007 storm restoration costs.
·A $19 million decrease in generation plant removal costs.
These decreases were partially offset by:
·A $33 million increase in tree trimming, reliability and system improvement expense.
·A $29 million increase in recoverable PJM expenses in Ohio.
·A $23 million increase in generation plant operations and maintenance expense.
·A $21 million increase in recoverable customer account expenses related to the Universal Service Fund for Ohio customers who qualify for payment assistance.
·A $16 million increase in storm restoration costs, primarily related to Hurricanes Dolly, Gustav and Ike, which occurred in the third quarter of 2008.
·A $16 million increase in maintenance expense at the Cook Plant.
·A $10 million increase related to the write-off of the unrecoverable pre-construction costs for PSO’s cancelled Red Rock Generating Facility in the first quarter of 2008.
·Gain on Disposition of Assets, Net decreased $18 million primarily due to the expiration of the earnings sharing agreement with Centrica from the sale of our Texas REPs in 2002.  In 2007, we received the final earnings sharing payment of $20 million.
·Depreciation and Amortization expense decreased $23 million primarily due to lower commission-approved depreciation rates in Indiana, Michigan, Oklahoma and Texas and lower Ohio regulatory asset amortization, partially offset by higher depreciable property balances and prior year adjustments related to the Virginia base rate case.
·Taxes Other Than Income Taxes increased $9 million primarily due to favorable adjustments to property tax returns recorded in the prior year.
·Carrying Costs Income increased $26 million primarily due to increased carrying cost income on cost deferrals in Virginia and Oklahoma.
·Interest Income increased $25 million primarily due to the favorable effect of claims for refund filed with the IRS.
·Other Income, Net increased $12 million primarily due to an increase in the equity component of AFUDC as a result of new generation projects.
·Interest and Other Charges increased $54 million primarily due to additional debt issued and higher interest rates on variable rate debt.
·Income Tax Expense increased $66 million due to an increase in pretax income.

AEP River Operations

Third Quarter of 2008 Compared to Third Quarter of 2007

Income Before Discontinued Operations and Extraordinary Loss from our AEP River Operations segment decreased to $11 million in 2008 from $18 million in 2007 primarily due to significant disruptions of ship arrivals and departures as the result of an oil spill in the New Orleans Harbor.  Ship arrivals were further disrupted by the impacts of Hurricanes Gustav and Ike, which caused severe flooding on the Mississippi and Illinois Rivers.  The decrease in income was also due to higher diesel fuel prices.  Additionally, decreases in import demand and grain export demand have resulted in lower freight demand, partially offset by increased coal exports.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Income Before Discontinued Operations and Extraordinary Loss from our AEP River Operations segment decreased to $21 million in 2008 from $40 million in 2007 primarily due to significant flooding on various inland waterways throughout 2008 and rising diesel fuel prices.  Additionally, decreases in import demand and grain export demand have resulted in lower freight demand, largely the result of a slowing U.S. economy and a weak U.S. dollar.  The impact of Hurricanes Gustav and Ike and the oil spill in the New Orleans Harbor, all of which occurred during the third quarter of 2008, also contributed to the unfavorable variance.

Generation and Marketing

Third Quarter of 2008 Compared to Third Quarter of 2007

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment increased to $16 million in 2008 from $3 million in 2007 primarily due to higher gross margins from its marketing activities and higher gross margins due to improved price realization, plant performance and hedging activities from its share of the Oklaunion Power Station.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment increased to $43 million in 2008 from $17 million in 2007 primarily due to higher gross margins from its marketing activities and higher gross margins due to improved price realization, plant performance and hedging activities from its share of the Oklaunion Power Station.

All Other

Third Quarter of 2008 Compared to Third Quarter of 2007

Loss Before Discontinued Operations and Extraordinary Loss from All Other increased to $10 million in 2008 from $2 million in 2007.  The increase in the loss primarily relates to higher interest expenses due to the issuance of AEP Junior Subordinated Debentures and lower interest income from affiliates.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Income Before Discontinued Operations and Extraordinary Loss from All Other increased to $133 million in 2008 from a $1 million loss in 2007.  In 2008, we had after-tax income of $163 million from a litigation settlement of a power purchase and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006.  The settlement was recorded as a pretax credit to Asset Impairments and Other Related Charges of $255 million in the accompanying Condensed Consolidated Statements of Income.  In 2007, we had a $16 million pretax gain ($10 million, net of tax) on the sale of a portion of our contractual obligations is includedinvestment in ourIntercontinental Exchange, Inc. (ICE).

AEP System Income Taxes

Income Tax Expense decreased $13 million in the third quarter of 2008 compared to the third quarter of 2007 Annual Report and has not changed significantly from year-end other thanprimarily due to a decrease in pretax income.

Income Tax Expense increased $165 million in the debt issuances and retirements discussednine-month period ended September 30, 2008 compared to the nine-month period ended September 30, 2007 primarily due to an increase in “Cash Flow” above and standby letters of credit discussed in “Liquidity” above.pretax income.

SIGNIFICANT FACTORSFINANCIAL CONDITION

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

Debt and Equity Capitalization
  September 30, 2008  December 31, 2007 
  ($ in millions) 
Long-term Debt, including amounts due within one year $16,007   56.6%   $14,994   58.1%
Short-term Debt  1,302   4.6   660   2.6 
Total Debt  17,309   61.2   15,654   60.7 
Common Equity  10,917   38.6   10,079   39.1 
Preferred Stock  61   0.2   61   0.2 
                 
Total Debt and Equity Capitalization $28,287   100.0% $25,794   100.0%

Our ratio of debt to be involvedtotal capital increased from 60.7% to 61.2% in various matters described2008 due to our issuance of debt to fund construction and our strategy to deal with the credit situation by drawing cash from our credit facilities.

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability.  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 and common stock.

Credit Markets

In recent months, the financial markets have become increasingly unstable and constrained at both a global and domestic level.  This systemic marketplace distress is impacting our access to capital, our liquidity and our cost of capital.  The uncertainties in the “Significant Factors” sectioncredit markets could have significant implications on our subsidiaries since they rely on continuing access to capital to fund operations and capital expenditures.  The current credit markets are constraining our ability to issue new debt, including commercial paper, and refinance existing debt.

We believe that we have adequate liquidity under our credit facilities.  In September 2008, in response to the bankruptcy of “Management’s Financial Discussioncertain companies and Analysistightening of Resultscredit markets, we borrowed $600 million under our credit lines to assure that cash is available to meet our working capital needs.  In October 2008, we borrowed an additional $1.4 billion under our existing credit facilities.  We took this proactive step to enhance our cash position during this period of Operations” in our 2007 Annual Report.  The 2007 Annual Report should be read in conjunction with this report in order to understand significant factors which have not materially changed in status sincemarket disruptions.

We cannot predict the issuancelength of our 2007 Annual Report, but may have a materialtime the current credit situation will continue or the impact on our future results of operations cash flows and financial condition.our ability to issue debt at reasonable interest rates.  However, when market conditions improve, we plan to repay the amounts drawn under the credit facilities and issue other long-term debt.  If there is not an improvement in access to capital, we believe that we have adequate liquidity to support our planned business operations and construction program through 2009.

Ohio Electric Security Plan FilingsIn the first quarter of 2008, due to the exposure that bond insurers like Ambac Assurance Corporation and Financial Guaranty Insurance Co. had in connection with developments in the subprime credit market, the credit ratings of those insurers were downgraded or placed on negative outlook.  These market factors contributed to higher interest rates in successful auctions and increasing occurrences of failed auctions for tax-exempt long-term debt sold at auction rates, including auctions of our tax-exempt long-term debt.  Consequently, we chose to exit the auction-rate debt market.  Through September 30, 2008, we reduced our outstanding auction rate securities by $1.2 billion.  As of September 30, 2008, we had $272 million outstanding of tax-exempt long-term debt sold at auction rates (rates range between 4.353% and 13%) that reset every 35 days.  Approximately $218 million of this debt relates to a lease structure with JMG that we are unable to refinance at this time.  In order to refinance this debt, we need the lessor’s consent.  This debt is insured by the previously AAA-rated bond insurers.  The instruments under which the bonds are issued allow us to convert to other short-term variable-rate structures, term-put structures and fixed-rate structures.  We plan to continue the conversion and refunding process to other permitted modes, including term-put structures, variable-rate and fixed-rate structures, as opportunities arise.  As of September 30, 2008, $367 million of the prior auction rate debt was issued in a weekly variable rate mode supported by letters of credit at variable rates ranging from 6.5% to 8.25%, $495 million was issued at fixed rates ranging from 4.5% to 5.625% and trustees held, on our behalf, approximately $330 million of our reacquired auction rate tax-exempt long-term debt which we plan to reissue to the public as market conditions permit.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  At September 30, 2008, our available liquidity was approximately $3 billion as illustrated in the table below:
  Amount Maturity
  (in millions)  
Commercial Paper Backup:    
Revolving Credit Facility $1,500 March 2011
Revolving Credit Facility  1,454(a)April 2012
Revolving Credit Facility  627(a)April 2011
Revolving Credit Facility  338(a)April 2009
Total  3,919  
Short-term Investments  490  
Cash and Cash Equivalents  338  
Total Liquidity Sources  4,747  
Less: AEP Commercial Paper Outstanding  701  
   Cash Drawn on Credit Facilities  591  
   Letters of Credit Drawn  439  
      
Net Available Liquidity $3,016  

(a)Reduced by Lehman Brothers Holdings Inc.’s commitment amount of $81 million following its bankruptcy.

The revolving credit facilities for commercial paper backup were structured as two $1.5 billion credit facilities which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $46 million following its bankruptcy.  In March 2008, the credit facilities were amended so that $750 million may be issued under each credit facility as letters of credit.

We use our corporate borrowing program to meet the short-term borrowing needs of our subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries.  In addition, we also fund, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  As of September 30, 2008, we had credit facilities totaling $3 billion to support our commercial paper program.  The maximum amount of commercial paper outstanding during the first nine months of 2008 was $1.2 billion.  The weighted-average interest rate of our commercial paper during the first nine months of 2008 was 3.25%.

In April 2008, we entered into a $650 million 3-year credit agreement and a $350 million 364-day credit agreement which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23 million and $12 million, respectively, following its bankruptcy.  Under the Ohio legislature passed Senate Bill 221,facilities, we may issue letters of credit.  As of September 30, 2008, $372 million of letters of credit were issued under the 3-year credit agreement to support variable rate demand notes.

Investments in Auction-Rate Securities

Prior to June 30, 2008, we sold all of our investment in auction-rate securities at par.

Sale of Receivables

In October 2008, we renewed our sale of receivables agreement.  The sale of receivables agreement provides a commitment of $600 million from bank conduits to purchase receivables.  This agreement will expire in October 2009.

Debt Covenants and Borrowing Limitations

Our revolving credit agreements, including the new agreements entered into in April 2008, contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%.  The method for calculating our outstanding debt and other capital is contractually defined. At September 30, 2008, this contractually-defined percentage was 57.3%.  Nonperformance of these covenants could result in an event of default under these credit agreements.  At September 30, 2008, 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 permit the lenders to declare the outstanding amounts payable.

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

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders.  At September 30, 2008, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

We have declared common stock dividends payable in cash in each quarter since July 1910.  The Board of Directors declared a quarterly dividend of $0.41 per share in October 2008.  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.  We have the option to defer interest payments on the $315 million of AEP Junior Subordinated Debentures issued in March 2008 for one or more periods of up to 10 consecutive years per period.  During any period in which amendswe defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.  We believe that these restrictions will not have a material effect on our net income, cash flows, financial condition or limit any dividend payments in the restructuring law effective July 31,foreseeable future.

Credit Ratings

In the first quarter of 2008, Moody’s changed its outlook from stable to negative for APCo, SWEPCo, OPCo and requires electric utilitiesTCC and affirmed its stable outlook for AEP and our other rated subsidiaries.  Also in the first quarter, Fitch downgraded PSO and SWEPCo from A- to adjust their ratesBBB+ for senior unsecured debt.  In May 2008, Fitch revised APCo’s outlook from stable to negative.  Our current credit ratings are as follows:

Moody’sS&PFitch
AEP Short-term DebtP-2A-2F-2
AEP Senior Unsecured DebtBaa2BBBBBB

If we or any of our rated subsidiaries receive an upgrade from any of the rating agencies listed above, our borrowing costs could decrease.  If we receive a downgrade in our credit ratings by filing an Electric Security Plan (ESP).  Electric utilities may file an ESPone of the rating agencies listed above, our borrowing costs could increase and access to borrowed funds could be negatively affected.

Cash Flow

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

 Nine Months Ended 
 September 30, 
 2008 2007 
 (in millions) 
Cash and Cash Equivalents at Beginning of Period $178  $301 
Net Cash Flows from Operating Activities  2,053   1,630 
Net Cash Flows Used for Investing Activities  (3,061)  (2,935)
Net Cash Flows from Financing Activities  1,168   1,200 
Net Increase (Decrease) in Cash and Cash Equivalents  160   (105)
Cash and Cash Equivalents at End of Period $338  $196 

Cash from operations, combined with a bank-sponsored receivables purchase agreement and short-term borrowings, provides working capital and allows us to meet other short-term cash needs.

Operating Activities
 Nine Months Ended 
 September 30, 
 2008 2007 
 (in millions) 
Net Income $1,228  $858 
Less:  Discontinued Operations, Net of Tax  (1)  (2)
Income Before Discontinued Operations  1,227   856 
Depreciation and Amortization  1,123   1,144 
Other  (297)  (370)
Net Cash Flows from Operating Activities $2,053  $1,630 

Net Cash Flows from Operating Activities increased in 2008 primarily due to the TEM settlement.

Net Cash Flows from Operating Activities were $2.1 billion in 2008 consisting primarily of Income Before Discontinued Operations of $1.2 billion and $1.1 billion of noncash Depreciation and Amortization.  Other represents items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Significant changes in other items include an increase in under-recovered fuel reflecting higher coal and natural gas prices.

Net Cash Flows from Operating Activities were $1.6 billion in 2007 consisting primarily of Income Before Discontinued Operations of $856 million and $1.1 billion of noncash Depreciation and Amortization.  Other represents items that had a prior 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 resulted in lower cash from operations due to a number of items, the most significant of which relates primarily to the Texas CTC refund of fuel over-recovery.

Investing Activities
 Nine Months Ended 
 September 30, 
 2008 2007 
 (in millions) 
Construction Expenditures $(2,576) $(2,595)
Purchases/Sales of Investment Securities, Net  (474)  217 
Acquisition of Assets  (97)  (512)
Proceeds from Sales of Assets  83   78 
Other  3   (123)
Net Cash Flows Used for Investing Activities $(3,061) $(2,935)

Net Cash Flows Used for Investing Activities were $3.1 billion in 2008 primarily due to Construction Expenditures for our environmental, distribution and new generation investment plan.

Net Cash Flows Used for Investing Activities were $2.9 billion in 2007 primarily due to Construction Expenditures for our environmental, distribution and new generation investment plan.  We paid $512 million to purchase gas-fired generating units to acquire capacity at a cost recovery mechanism.  Electric utilitiesbelow that of building a new, comparable plant.

In our normal course of business, we purchase and sell investment securities with cash available for short-term investments including the cash drawn against our credit facilities in 2008.  We also have an optionpurchase and sell investment securities within our nuclear trusts.

We forecast approximately $1.2 billion of construction expenditures for the remainder of 2008.  Estimated construction expenditures are subject to file a Market Rate Offer (MRO) for generation pricing.  A MRO, from the date of its commencement, could transition CSPCoperiodic review and OPCo to full market rates no sooner than six yearsmodification and no later than ten years.  The PUCO has the authority to approve or modify the utilities’ ESP request.  The PUCO is required to approve an ESP if, in the aggregate, the ESP is more favorable to ratepayers than the MRO.  Both alternatives involve a “substantially excessive earnings” testmay vary based on what public companies, including other utilities with similar risk profiles, earn on equity.  Management has preliminarily concluded, pendingthe ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  These construction expenditures will be funded through cash flows from operations and financing activities.

Financing Activities
 Nine Months Ended 
 September 30, 
 2008 2007 
 (in millions) 
Issuance of Common Stock $106  $116 
Issuance/Retirement of Debt, Net  1,621   1,623 
Dividends Paid on Common Stock  (494)  (467)
Other  (65)  (72)
Net Cash Flows from Financing Activities $1,168  $1,200 

Net Cash Flows from Financing Activities in 2008 were $1.2 billion primarily due to the issuance of final rulesadditional debt including $315 million of Junior Subordinated Debentures and a net increase of $1.3 billion in outstanding Senior Unsecured Notes partially offset, by the PUCOreacquisition of a net $370 million of Pollution Control Bonds and the outcome$125 million of the ESP proceeding, that CSPCo’sSecuritization Bonds.  In September 2008, we borrowed $600 million under our credit agreements.  See Note 9 – Financing Activities for a complete discussion of long-term debt issuances and OPCo’s generation/supply operations are not subject to cost-based rate regulation accounting.  However, if a fuel cost recovery mechanism is implemented within the ESP, CSPCo’s and OPCo’s fuel operations would be subject to cost-based rate regulation accounting.  Management is unable to predict the financial statement impact of the restructuring legislation until the PUCO acts on specific proposals made by CSPCo and OPCo in their ESPs.retirements.

In July 2008, within the parametersNet Cash Flows from Financing Activities in 2007 were $1.2 billion primarily due to issuing $1.9 billion of the ESPs, CSPCodebt securities including $1 billion of new debt for plant acquisitions and OPCo filed with the PUCO to establish rates for 2009 through 2011.  CSPCoconstruction and OPCo did not file MROs.  CSPCo and OPCo each requested an annual rate increase for 2009 through 2011 that would not exceed approximately 15% per year.  A significant portion of the requested increases results from the implementation of a fuel cost recovery mechanism that primarily includes fuel costs, purchased power costs including mandated renewable energy, consumables such as urea, other variable production costs and gains and losses on sales of emission allowances.  The increases in customer bills related to the fuel cost recovery mechanism would be phased-in over the three year period from 2009 through 2011.  Effective January 1, 2009, CSPCo and OPCo will defer the fuel cost under-recoveries and related carrying costs for future recovery over seven years from 2012 through 2018.  In addition to the fuel cost recovery mechanisms, the requested increases would also recover incremental carrying costs associated with environmental costs, Provider of Last Resort (POLR) charges to compensate for the risk of customers changing electric suppliers, automatic increases for unexpected costs and reliability costs. The filings also include programs for smart metering initiatives and economic development and mandated energy efficiency and peak demand reduction programs.  Management expects a PUCO decision on the ESP filings in the fourth quarter of 2008.increasing short-term commercial paper borrowings.

Within the ESPs, CSPCo and OPCo would also recover existing regulatory assets of $45 million and $36 million, respectively, for customer choice implementation and line extension carrying costs.  In addition, CSPCo and OPCo would recover related unrecorded equity carrying costs of $28 million and $19 million, respectively.   Such costs would be recovered over an 8 year period beginning January 2011.  Failure of the PUCO to ultimately approve the recovery of the regulatory assets would have an adverse effect on future results of operations and cash flows.

Texas Restructuring Appeals

Pursuant to PUCT orders, TCC securitized its net recoverable stranded generation costs of $2.5 billion and is recovering such costs over a period ending in 2020.  TCC has refunded its net other true-up items of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider.  Cash paid for CTC refunds for the six months ended June 30, 2008 and 2007 was $68 million and $170 million, respectively. TCC appealed the PUCT stranded costs true-up and related orders seeking relief in both state and federal court on the grounds that certain aspects of the orders are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law and fail to fully compensate TCC for its net stranded cost and other true-up items.  Municipal customers and other intervenors also appealed the PUCT true-up and related orders seeking to further reduce TCC’s true-up recoveries. In March 2007, the Texas District Court judge hearing the appeal of the true-up order affirmed the PUCT’s April 2006 final true-up order for TCC with two significant exceptions.  The judge determined that the PUCT erred by applying an invalid rule to determine the carrying cost rate for the true-up of stranded costs and remanded this matter to the PUCT for further consideration.  The District Court judge also determined that the PUCT improperly reduced TCC’s net stranded plant costs for commercial unreasonableness.

TCC, the PUCT and intervenors appealed the District Court decision to the Texas Court of Appeals.  In May 2008, the Texas Court of Appeals affirmed the District Court decision in all but one major respect.  It reversed the District Court’s decision finding that the PUCT erred by applying an invalid rule to determine the carrying cost rate.  The Texas Court of Appeals denied intervenors’ motion for rehearing.  Management expects intervenors to appeal the decision to the Texas Supreme Court.  If upheld on appeal, this ruling could have a favorable effect on TCC’s results of operations and cash flows.

Management cannot predict the outcome of these court proceedings and PUCT remand decisions.  If TCC ultimately succeeds in its appeals, it could have a favorable effect on future results of operations, cash flows and financial condition.  If municipal customers and other intervenors succeed in their appeals it could have a substantial adverse effect on future results of operations, cash flows and financial condition.

FERC Market Power Mitigation

FERC allows utilities to sell wholesale power at market-based rates if they can demonstrate that they lack market power in the markets in which they participate.  Sellers with market rate authority must, at least every three years, update their studies demonstrating lack of market power.  In December 2007, AEP filed its most recent triennial update.  In March and May 2008, the PUCO filed comments suggesting that FERC should further investigate whether AEP continues to pass FERC’s indicative screens for the lack of market power in PJM.  Certain industrial retail customers also urged FERC to further investigate this matter.  AEP responded that its market power studies were performed in accordance with FERC’s guidelines, and continue to demonstrate lack of market power. Management is unable to predict the outcome of this proceeding; however, if a further investigation by the FERC limits AEP’s ability to sell power at market based rates in PJM, it would result in an adverse effect on future off-system sales margins, results of operations and cash flows.

New Generation

In May 2006, we announced plans to build the Stall Unit, a new intermediate load, 500 MW, natural gas-fired generating unit at SWEPCo’s existing Arsenal Hill Plant location in Shreveport, Louisiana.  SWEPCo has received approvals from the Louisiana Public Service Commission (LPSC) and the Public Utility Commission of Texas (PUCT) to construct the Stall Unit and is currently waiting for approval from the APSC.  The Stall Unit is estimated to cost $378 million, excluding AFUDC, and is expected to be in-service in mid-2010.

In August 2006, we announced plans to jointly build the Turk Plant, a new base load, 600 MW, pulverized coal, ultra-supercritical generating unit in Arkansas.  SWEPCo has received approvals from the APSC and the LPSC to construct the Turk Plant.  In August 2008, the PUCT issued an order approving the Turk Plant subject to certain conditions, including the capping of capital costs of the Turk Plant at the $1.5 billion projected construction cost.  SWEPCo is also working with the Arkansas Department of Environmental Quality for the approval of an air permit and the U.S. Army Corps of Engineers for the approval of a wetlands and stream impact permit.  Once SWEPCo receives the air permit, they will commence construction.  The Turk Plant is estimated to cost $1.5 billion, excluding AFUDC, with SWEPCo’s portion estimated to cost $1.1 billion.  If these permits are approved on a timely basis, the plant is expected to be in-service in 2012.
Fuel Costs

We currently estimate 2008 coal prices to increase by approximately 28% due to escalating domestic prices and increased needs, primarily in the east.  We had initially expected coal costs to increase by 13% in 2008.  We continue to see increases in prices due to expiring lower-priced coal and transportation contracts being replaced with higher-priced contracts.  We have price risk exposure in Ohio, representing approximately 20% of our fuel costs, since we do not have an active fuel cost recovery mechanism.  However, under Ohio’s amended restructuring law, we have requested the PUCO to reinstate a fuel cost recovery mechanism effective January 1, 2009.  Fuel cost adjustment rate clauses in our other jurisdictions will help offset future negative impacts of fuel price increases on our gross margins.

RESULTS OF OPERATIONS

Segments

Our principal operating business 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
·Barging operations that annually transport approximately 35 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and Lower Mississippi Rivers.  Approximately 39% of the barging is for the transportation of agricultural products, 30% for coal, 14% for steel and 17% for other commodities.  Effective July 30, 2008, AEP MEMCO LLC’s name was changed to AEP River Operations LLC.

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

The table below presents our consolidated Income Before Discontinued Operations and Extraordinary Loss by segment for the three and nine months ended September 30, 2008 and 2007.

 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 2008 2007 2008 2007 
 (in millions) 
Utility Operations $357  $388  $1,030  $879 
AEP River Operations  11   18   21   40 
Generation and Marketing  16   3   43   17 
All Other (a)  (10)  (2)  133   (1)
Income Before Discontinued Operations and Extraordinary Loss $374  $407  $1,227  $935 

(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 will gradually liquidate and completely expire in 2011.
·The first quarter of 2008 cash settlement of a purchase power and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006.  The cash settlement of $255 million ($163 million, net of tax) is included in Net Income.
·Revenue sharing related to the Plaquemine Cogeneration Facility.

AEP Consolidated

Third Quarter of 2008 Compared to Third Quarter of 2007

Income Before Discontinued Operations and Extraordinary Loss in 2008 decreased $33 million compared to 2007 primarily due to a decrease in Utility Operations segment earnings of $31 million.  The decrease in Utility Operations segment earnings primarily relates to an increase in fuel and consumables expense in Ohio and a decrease in cooling degree days throughout our service territories, partially offset by increases in retail margins due to rate increases in Ohio, Virginia, West Virginia, Texas and Oklahoma.

Average basic shares outstanding increased to 402 million in 2008 from 399 million in 2007 primarily due to the issuance of shares under our incentive compensation and dividend reinvestment plans.  Actual shares outstanding were 403 million as of September 30, 2008.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Income Before Discontinued Operations and Extraordinary Loss in 2008 increased $292 million compared to 2007 primarily due to income of $163 million (net of tax) from the cash settlement received in 2008 related to a power purchase-and-sale agreement with TEM and an increase in Utility Operations segment earnings of $151 million.  The increase in Utility Operations segment earnings primarily relates to rate increases implemented since the second quarter of 2007 in Ohio, Virginia, West Virginia, Texas and Oklahoma and higher off-system sales, partially offset by higher interest and fuel expenses.

Average basic shares outstanding increased to 402 million in 2008 from 398 million in 2007 primarily due to the issuance of shares under our incentive compensation and dividend reinvestment plans.  Actual shares outstanding were 403 million as of September 30, 2008.

Utility Operations

Our Utility Operations segment includes primarily regulated revenues with direct and variable offsetting expenses and net reported commodity trading operations.  We believe that a discussion of the results from our Utility Operations segment on a gross margin basis is most appropriate in order to further understand the key drivers of the segment.  Gross margin represents utility operating revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power.

Utility Operations Income Summary
For the Three and Nine Months Ended September 30, 2008 and 2007

  
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
 
  2008  2007  2008  2007 
  (in millions) 
Revenues $3,968  $3,600  $10,575  $9,587 
Fuel and Purchased Power  1,841   1,413   4,428   3,641 
Gross Margin  2,127   2,187   6,147   5,946 
Depreciation and Amortization  379   374   1,099   1,122 
Other Operating Expenses  1,034   1,037   3,001   2,985 
Operating Income  714   776   2,047   1,839 
Other Income, Net  46   27   135   72 
Interest Charges and Preferred Stock Dividend Requirements  225   213   653   599 
Income Tax Expense  178   202   499   433 
Income Before Discontinued Operations and Extraordinary Loss $357  $388  $1,030  $879 


Summary of Selected Sales Data
For Utility Operations
For the Three and Nine Months Ended September 30, 2008 and 2007

  
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
 
Energy/Delivery Summary 2008  2007  2008  2007 
  (in millions of KWH) 
Energy            
Retail:            
Residential  12,754   13,749   37,084   38,015 
Commercial  10,794   11,164   30,249   30,750 
Industrial  14,761   14,697   44,171   43,110 
Miscellaneous  668   686   1,916   1,932 
Total Retail  38,977   40,296   113,420   113,807 
                 
Wholesale  13,130   13,493   35,728   31,648 
                 
Delivery                
Texas Wires – Energy delivered to customers served by
   AEP’s Texas Wires Companies
  7,961   7,721   20,916   20,297 
Total KWHs  60,068   61,510   170,064   165,752 

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 associated number of customers within each.

Summary of Weather Data
Summary of Heating and Cooling Degree Days for Utility Operations
For the Three and Nine Months Ended September 30, 2008 and 2007

  
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
 
  2008  2007  2008  2007 
  (in degree days) 
Weather Summary            
Eastern Region            
Actual – Heating (a)  -   2   1,960   2,041 
Normal – Heating (b)  7   7   1,950   1,973 
                 
Actual – Cooling (c)  651   808   924   1,189 
Normal – Cooling (b)  687   685   969   963 
                 
Western Region (d)
                
Actual – Heating (a)  -   -   989   994 
Normal – Heating (b)  2   2   967   993 
                 
Actual – Cooling (c)  1,250   1,406   1,951   2,084 
Normal – Cooling (b)  1,402   1,411   2,074   2,084 

(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 and western region cooling degree days are calculated on a 65 degree temperature base.
(d)Western region statistics represent PSO/SWEPCo customer base only.

Third Quarter of 2008 Compared to Third Quarter of 2007

Reconciliation of Third Quarter of 2007 to Third Quarter of 2008
Income from Utility Operations Before Discontinued Operations and Extraordinary Loss
(in millions)

Third Quarter of 2007    $388 
        
Changes in Gross Margin:       
Retail Margins  (81)    
Off-system Sales  (7)    
Transmission Revenues  4     
Other  24     
Total Change in Gross Margin      (60)
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  -     
Depreciation and Amortization  (5)    
Taxes Other Than Income Taxes  2     
Carrying Costs Income  7     
Interest Income  8     
Other Income, Net  5     
Interest and Other Charges  (12)    
Total Change in Operating Expenses and Other      5 
         
Income Tax Expense      24 
         
Third Quarter of 2008     $357 

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss decreased $31 million to $357 million in 2008.  The key drivers of the decrease were a $60 million decrease in Gross Margin offset by a $5 million decrease in Operating Expenses and Other and a $24 million decrease in Income Tax Expense.

The major components of the net decrease in Gross Margin were as follows:

·Retail Margins decreased $81 million primarily due to the following:
·
A $78 million increase in related to increased fuel and consumable expenses in Ohio.  CSPCo and OPCo have applied for an active fuel clause in their Ohio ESP to be effective January 1, 2009.
·An $80 million decrease in usage primarily due to a 19% decrease in cooling degree days in our eastern region, an 11% decrease in cooling degree days in our western region as well as outages caused by Hurricanes Dolly, Gustav and Ike.  Approximately 17% of our reduction in load was attributable to these storms.
These decreases were partially offset by:
·A $61 million increase related to net rate increases implemented in our Ohio jurisdictions, an $8 million increase related to recovery of E&R costs in Virginia and the construction financing costs rider in West Virginia, a $6 million increase in base rates in Texas and a $6 million increase in base rates in Oklahoma.
·A $9 million increase related to increased usage by Ormet, an industrial customer in Ohio.  See “Ormet” section of Note 3.
·Margins from Off-system Sales decreased $7 million primarily due to lower trading margins and the favorable effects of a fuel reconciliation recorded in our western service territory in the third quarter of 2007, partially offset by increases in East physical off-system sales margins due mostly to higher prices.
·Transmission Revenues increased $4 million primarily due to increased rates in the SPP region.
·Other revenues increased $24 million primarily due to increased third-party engineering and construction work and an increase in pole attachment revenue.

Utility Operating Expenses and Other and Income Taxes changed between years as follows:

·Other Operation and Maintenance expenses were flat in comparison to 2007.  We experienced decreases related to the following:
·A $77 million decrease related to the recording of the NSR settlement in the third quarter of 2007.  We are evaluating methods to pursue recovery in all of our affected jurisdictions.
·A $9 million decrease related to the establishment of a regulatory asset in the third quarter of 2008 for Virginia’s share of previously expended NSR settlement costs.
These decreases were offset by:
·A $24 million increase in non-storm system improvements, customer work and other distribution expenses.
·A $21 million increase in storm restoration costs, primarily related to Hurricanes Dolly, Gustav and Ike.
·A $15 million increase in recoverable PJM expenses in Ohio.
·A $10 million increase in generation plant maintenance.
·An $8 million increase in recoverable customer account expenses related to the Universal Service Fund for Ohio customers who qualify for payment assistance.
·An $8 million increase in transmission expenses for tree trimming and reliability.
·Depreciation and Amortization expense increased $5 million primarily due to higher depreciable property balances from the installation of environmental upgrades.
·Carrying Costs Income increased $7 million primarily due to increased carrying cost income on cost deferrals in Virginia and Oklahoma.
·Interest Income increased $8 million primarily due to the favorable effect of claims for refund filed with the IRS.
·Interest and Other Charges increased $12 million primarily due to additional debt issued and higher interest rates on variable rate debt.
·Income Tax Expense decreased $24 million due to a decrease in pretax income.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Reconciliation of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2008
Income from Utility Operations Before Discontinued Operations and Extraordinary Loss
(in millions)

Nine Months Ended September 30, 2007    $879 
        
Changes in Gross Margin:       
Retail Margins  79     
Off-system Sales  73     
Transmission Revenues  22     
Other Revenues  27     
Total Change in Gross Margin      201 
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  11     
Gain on Dispositions of Assets, Net  (18)    
Depreciation and Amortization  23     
Taxes Other Than Income Taxes  (9)    
Carrying Costs Income  26     
Interest Income  25     
Other Income, Net  12     
Interest and Other Charges  (54)    
Total Change in Operating Expenses and Other      16 
         
Income Tax Expense      (66)
         
Nine Months Ended September 30, 2008     $1,030 

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss increased $151 million to $1,030 million in 2008.  The key drivers of the increase were a $201 million increase in Gross Margin and a $16 million decrease in Operating Expenses and Other offset by a $66 million increase in Income Tax Expense.

The major components of the net increase in Gross Margin were as follows:

·Retail Margins increased $79 million primarily due to the following:
·A $148 million increase related to net rate increases implemented in our Ohio jurisdictions, a $39 million increase related to recovery of E&R costs in Virginia and the construction financing costs rider in West Virginia, a $20 million increase in base rates in Oklahoma and a $17 million increase in base rates in Texas.
·A $42 million increase related to increased usage by Ormet, an industrial customer in Ohio.  See “Ormet” section of Note 3.
·A $37 million net increase due to adjustments recorded in the prior year related to the 2007 Virginia base rate case which included a second quarter 2007 provision for revenue refund.
·A $29 million increase due to coal contract amendments in 2008.
These increases were partially offset by:
·
A $164 million decrease related to increased fuel and consumable expenses in Ohio.  CSPCo and OPCo have applied for an active fuel clause in their Ohio ESP to be effective January 1, 2009.
·
A $65 million decrease in usage primarily due to a 22% decrease in cooling degree days in our eastern region and a 6% decrease in cooling degree days in our western region.
·
A $29 million increase in the sharing of off-system sales margins with customers due to an increase in total off-system sales.
·Margins from Off-system Sales increased $73 million primarily due to higher physical off-system sales in our eastern territory as the result of higher volumes and higher prices, aided by additional generation available in 2008 due to fewer planned outages and lower internal load.  This increase was partially offset by lower trading margins and the favorable effects of a fuel reconciliation recorded in our western territory in the third quarter of 2007.
·Transmission Revenues increased $22 million primarily due to increased rates in the ERCOT and SPP regions.
·Other Revenues increased $27 million primarily due to increased third-party engineering and construction work, an increase in pole attachment revenue and the recording of an unfavorable provision for TCC for the refund of bonded rates recorded in 2007.

Utility Operating Expenses and Other and Income Taxes changed between years as follows:

·Other Operation and Maintenance expenses decreased $11 million primarily due to the following:
·A $77 million decrease related to the recording of NSR settlement costs in September 2007.  We are evaluating methods to pursue recovery in all of our affected jurisdictions.
·A $62 million decrease related to the deferral of Oklahoma storm restoration costs in the first quarter of 2008, net of amortization, as a result of a rate settlement to recover 2007 storm restoration costs.
·A $19 million decrease in generation plant removal costs.
These decreases were partially offset by:
·A $33 million increase in tree trimming, reliability and system improvement expense.
·A $29 million increase in recoverable PJM expenses in Ohio.
·A $23 million increase in generation plant operations and maintenance expense.
·A $21 million increase in recoverable customer account expenses related to the Universal Service Fund for Ohio customers who qualify for payment assistance.
·A $16 million increase in storm restoration costs, primarily related to Hurricanes Dolly, Gustav and Ike, which occurred in the third quarter of 2008.
·A $16 million increase in maintenance expense at the Cook Plant.
·A $10 million increase related to the write-off of the unrecoverable pre-construction costs for PSO’s cancelled Red Rock Generating Facility in the first quarter of 2008.
·Gain on Disposition of Assets, Net decreased $18 million primarily due to the expiration of the earnings sharing agreement with Centrica from the sale of our Texas REPs in 2002.  In 2007, we received the final earnings sharing payment of $20 million.
·Depreciation and Amortization expense decreased $23 million primarily due to lower commission-approved depreciation rates in Indiana, Michigan, Oklahoma and Texas and lower Ohio regulatory asset amortization, partially offset by higher depreciable property balances and prior year adjustments related to the Virginia base rate case.
·Taxes Other Than Income Taxes increased $9 million primarily due to favorable adjustments to property tax returns recorded in the prior year.
·Carrying Costs Income increased $26 million primarily due to increased carrying cost income on cost deferrals in Virginia and Oklahoma.
·Interest Income increased $25 million primarily due to the favorable effect of claims for refund filed with the IRS.
·Other Income, Net increased $12 million primarily due to an increase in the equity component of AFUDC as a result of new generation projects.
·Interest and Other Charges increased $54 million primarily due to additional debt issued and higher interest rates on variable rate debt.
·Income Tax Expense increased $66 million due to an increase in pretax income.

AEP River Operations

Third Quarter of 2008 Compared to Third Quarter of 2007

Income Before Discontinued Operations and Extraordinary Loss from our AEP River Operations segment decreased to $11 million in 2008 from $18 million in 2007 primarily due to significant disruptions of ship arrivals and departures as the result of an oil spill in the New Orleans Harbor.  Ship arrivals were further disrupted by the impacts of Hurricanes Gustav and Ike, which caused severe flooding on the Mississippi and Illinois Rivers.  The decrease in income was also due to higher diesel fuel prices.  Additionally, decreases in import demand and grain export demand have resulted in lower freight demand, partially offset by increased coal exports.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Income Before Discontinued Operations and Extraordinary Loss from our AEP River Operations segment decreased to $21 million in 2008 from $40 million in 2007 primarily due to significant flooding on various inland waterways throughout 2008 and rising diesel fuel prices.  Additionally, decreases in import demand and grain export demand have resulted in lower freight demand, largely the result of a slowing U.S. economy and a weak U.S. dollar.  The impact of Hurricanes Gustav and Ike and the oil spill in the New Orleans Harbor, all of which occurred during the third quarter of 2008, also contributed to the unfavorable variance.

Generation and Marketing

Third Quarter of 2008 Compared to Third Quarter of 2007

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment increased to $16 million in 2008 from $3 million in 2007 primarily due to higher gross margins from its marketing activities and higher gross margins due to improved price realization, plant performance and hedging activities from its share of the Oklaunion Power Station.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment increased to $43 million in 2008 from $17 million in 2007 primarily due to higher gross margins from its marketing activities and higher gross margins due to improved price realization, plant performance and hedging activities from its share of the Oklaunion Power Station.

All Other

Third Quarter of 2008 Compared to Third Quarter of 2007

Loss Before Discontinued Operations and Extraordinary Loss from All Other increased to $10 million in 2008 from $2 million in 2007.  The increase in the loss primarily relates to higher interest expenses due to the issuance of AEP Junior Subordinated Debentures and lower interest income from affiliates.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Income Before Discontinued Operations and Extraordinary Loss from All Other increased to $133 million in 2008 from a $1 million loss in 2007.  In 2008, we had after-tax income of $163 million from a litigation settlement of a power purchase and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006.  The settlement was recorded as a pretax credit to Asset Impairments and Other Related Charges of $255 million in the accompanying Condensed Consolidated Statements of Income.  In 2007, we had a $16 million pretax gain ($10 million, net of tax) on the sale of a portion of our investment in Intercontinental Exchange, Inc. (ICE).

AEP System Income Taxes

Income Tax Expense decreased $13 million in the third quarter of 2008 compared to the third quarter of 2007 primarily due to a decrease in pretax income.

Income Tax Expense increased $165 million in the nine-month period ended September 30, 2008 compared to the nine-month period ended September 30, 2007 primarily due to an increase in pretax income.

FINANCIAL CONDITION

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

Debt and Equity Capitalization
  September 30, 2008  December 31, 2007 
  ($ in millions) 
Long-term Debt, including amounts due within one year $16,007   56.6%   $14,994   58.1%
Short-term Debt  1,302   4.6   660   2.6 
Total Debt  17,309   61.2   15,654   60.7 
Common Equity  10,917   38.6   10,079   39.1 
Preferred Stock  61   0.2   61   0.2 
                 
Total Debt and Equity Capitalization $28,287   100.0% $25,794   100.0%

Our ratio of debt to total capital increased from 60.7% to 61.2% in 2008 due to our issuance of debt to fund construction and our strategy to deal with the credit situation by drawing cash from our credit facilities.

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability.  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 and common stock.

Credit Markets

In recent months, the financial markets have become increasingly unstable and constrained at both a global and domestic level.  This systemic marketplace distress is impacting our access to capital, our liquidity and our cost of capital.  The uncertainties in the credit markets could have significant implications on our subsidiaries since they rely on continuing access to capital to fund operations and capital expenditures.  The current credit markets are constraining our ability to issue new debt, including commercial paper, and refinance existing debt.

We believe that we have adequate liquidity under our credit facilities.  In September 2008, in response to the bankruptcy of certain companies and tightening of credit markets, we borrowed $600 million under our credit lines to assure that cash is available to meet our working capital needs.  In October 2008, we borrowed an additional $1.4 billion under our existing credit facilities.  We took this proactive step to enhance our cash position during this period of market disruptions.

We cannot predict the length of time the current credit situation will continue or the impact on our future operations and our ability to issue debt at reasonable interest rates.  However, when market conditions improve, we plan to repay the amounts drawn under the credit facilities and issue other long-term debt.  If there is not an improvement in access to capital, we believe that we have adequate liquidity to support our planned business operations and construction program through 2009.

In the first quarter of 2008, due to the exposure that bond insurers like Ambac Assurance Corporation and Financial Guaranty Insurance Co. had in connection with developments in the subprime credit market, the credit ratings of those insurers were downgraded or placed on negative outlook.  These market factors contributed to higher interest rates in successful auctions and increasing occurrences of failed auctions for tax-exempt long-term debt sold at auction rates, including auctions of our tax-exempt long-term debt.  Consequently, we chose to exit the auction-rate debt market.  Through September 30, 2008, we reduced our outstanding auction rate securities by $1.2 billion.  As of September 30, 2008, we had $272 million outstanding of tax-exempt long-term debt sold at auction rates (rates range between 4.353% and 13%) that reset every 35 days.  Approximately $218 million of this debt relates to a lease structure with JMG that we are unable to refinance at this time.  In order to refinance this debt, we need the lessor’s consent.  This debt is insured by the previously AAA-rated bond insurers.  The instruments under which the bonds are issued allow us to convert to other short-term variable-rate structures, term-put structures and fixed-rate structures.  We plan to continue the conversion and refunding process to other permitted modes, including term-put structures, variable-rate and fixed-rate structures, as opportunities arise.  As of September 30, 2008, $367 million of the prior auction rate debt was issued in a weekly variable rate mode supported by letters of credit at variable rates ranging from 6.5% to 8.25%, $495 million was issued at fixed rates ranging from 4.5% to 5.625% and trustees held, on our behalf, approximately $330 million of our reacquired auction rate tax-exempt long-term debt which we plan to reissue to the public as market conditions permit.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  At September 30, 2008, our available liquidity was approximately $3 billion as illustrated in the table below:
  Amount Maturity
  (in millions)  
Commercial Paper Backup:    
Revolving Credit Facility $1,500 March 2011
Revolving Credit Facility  1,454(a)April 2012
Revolving Credit Facility  627(a)April 2011
Revolving Credit Facility  338(a)April 2009
Total  3,919  
Short-term Investments  490  
Cash and Cash Equivalents  338  
Total Liquidity Sources  4,747  
Less: AEP Commercial Paper Outstanding  701  
   Cash Drawn on Credit Facilities  591  
   Letters of Credit Drawn  439  
      
Net Available Liquidity $3,016  

(a)Reduced by Lehman Brothers Holdings Inc.’s commitment amount of $81 million following its bankruptcy.

The revolving credit facilities for commercial paper backup were structured as two $1.5 billion credit facilities which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $46 million following its bankruptcy.  In March 2008, the credit facilities were amended so that $750 million may be issued under each credit facility as letters of credit.

We use our corporate borrowing program to meet the short-term borrowing needs of our subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries.  In addition, we also fund, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  As of September 30, 2008, we had credit facilities totaling $3 billion to support our commercial paper program.  The maximum amount of commercial paper outstanding during the first nine months of 2008 was $1.2 billion.  The weighted-average interest rate of our commercial paper during the first nine months of 2008 was 3.25%.

In April 2008, we entered into a $650 million 3-year credit agreement and a $350 million 364-day credit agreement which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23 million and $12 million, respectively, following its bankruptcy.  Under the facilities, we may issue letters of credit.  As of September 30, 2008, $372 million of letters of credit were issued under the 3-year credit agreement to support variable rate demand notes.

Investments in Auction-Rate Securities

Prior to June 30, 2008, we sold all of our investment in auction-rate securities at par.

Sale of Receivables

In October 2008, we renewed our sale of receivables agreement.  The sale of receivables agreement provides a commitment of $600 million from bank conduits to purchase receivables.  This agreement will expire in October 2009.

Debt Covenants and Borrowing Limitations

Our revolving credit agreements, including the new agreements entered into in April 2008, contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%.  The method for calculating our outstanding debt and other capital is contractually defined. At September 30, 2008, this contractually-defined percentage was 57.3%.  Nonperformance of these covenants could result in an event of default under these credit agreements.  At September 30, 2008, 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 permit the lenders to declare the outstanding amounts payable.

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

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders.  At September 30, 2008, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

We have declared common stock dividends payable in cash in each quarter since July 1910.  The Board of Directors declared a quarterly dividend of $0.41 per share in October 2008.  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.  We have the option to defer interest payments on the $315 million of AEP Junior Subordinated Debentures issued in March 2008 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 believe that these restrictions will not have a material effect on our net income, cash flows, financial condition or limit any dividend payments in the foreseeable future.

Credit Ratings

In the first quarter of 2008, Moody’s changed its outlook from stable to negative for APCo, SWEPCo, OPCo and TCC and affirmed its stable outlook for AEP and our other rated subsidiaries.  Also in the first quarter, Fitch downgraded PSO and SWEPCo from A- to BBB+ for senior unsecured debt.  In May 2008, Fitch revised APCo’s outlook from stable to negative.  Our current credit ratings are as follows:

Moody’sS&PFitch
AEP Short-term DebtP-2A-2F-2
AEP Senior Unsecured DebtBaa2BBBBBB

If we or any of our rated subsidiaries receive an upgrade from any of the rating agencies listed above, our borrowing costs could decrease.  If we receive a downgrade in our credit ratings by one of the rating agencies listed above, our borrowing costs could increase and access to borrowed funds could be negatively affected.

Cash Flow

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

 Nine Months Ended 
 September 30, 
 2008 2007 
 (in millions) 
Cash and Cash Equivalents at Beginning of Period $178  $301 
Net Cash Flows from Operating Activities  2,053   1,630 
Net Cash Flows Used for Investing Activities  (3,061)  (2,935)
Net Cash Flows from Financing Activities  1,168   1,200 
Net Increase (Decrease) in Cash and Cash Equivalents  160   (105)
Cash and Cash Equivalents at End of Period $338  $196 

Cash from operations, combined with a bank-sponsored receivables purchase agreement and short-term borrowings, provides working capital and allows us to meet other short-term cash needs.

Operating Activities
 Nine Months Ended 
 September 30, 
 2008 2007 
 (in millions) 
Net Income $1,228  $858 
Less:  Discontinued Operations, Net of Tax  (1)  (2)
Income Before Discontinued Operations  1,227   856 
Depreciation and Amortization  1,123   1,144 
Other  (297)  (370)
Net Cash Flows from Operating Activities $2,053  $1,630 

Net Cash Flows from Operating Activities increased in 2008 primarily due to the TEM settlement.

Net Cash Flows from Operating Activities were $2.1 billion in 2008 consisting primarily of Income Before Discontinued Operations of $1.2 billion and $1.1 billion of noncash Depreciation and Amortization.  Other represents items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Significant changes in other items include an increase in under-recovered fuel reflecting higher coal and natural gas prices.

Net Cash Flows from Operating Activities were $1.6 billion in 2007 consisting primarily of Income Before Discontinued Operations of $856 million and $1.1 billion of noncash Depreciation and Amortization.  Other represents items that had a prior 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 resulted in lower cash from operations due to a number of items, the most significant of which relates primarily to the Texas CTC refund of fuel over-recovery.

Investing Activities
 Nine Months Ended 
 September 30, 
 2008 2007 
 (in millions) 
Construction Expenditures $(2,576) $(2,595)
Purchases/Sales of Investment Securities, Net  (474)  217 
Acquisition of Assets  (97)  (512)
Proceeds from Sales of Assets  83   78 
Other  3   (123)
Net Cash Flows Used for Investing Activities $(3,061) $(2,935)

Net Cash Flows Used for Investing Activities were $3.1 billion in 2008 primarily due to Construction Expenditures for our environmental, distribution and new generation investment plan.

Net Cash Flows Used for Investing Activities were $2.9 billion in 2007 primarily due to Construction Expenditures for our environmental, distribution and new generation investment plan.  We paid $512 million to purchase gas-fired generating units to acquire capacity at a cost below that of building a new, comparable plant.

In our normal course of business, we purchase and sell investment securities with cash available for short-term investments including the cash drawn against our credit facilities in 2008.  We also purchase and sell investment securities within our nuclear trusts.

We forecast approximately $1.2 billion of construction expenditures for the remainder of 2008.  Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  These construction expenditures will be funded through cash flows from operations and financing activities.

Financing Activities
 Nine Months Ended 
 September 30, 
 2008 2007 
 (in millions) 
Issuance of Common Stock $106  $116 
Issuance/Retirement of Debt, Net  1,621   1,623 
Dividends Paid on Common Stock  (494)  (467)
Other  (65)  (72)
Net Cash Flows from Financing Activities $1,168  $1,200 

Net Cash Flows from Financing Activities in 2008 were $1.2 billion primarily due to the issuance of additional debt including $315 million of Junior Subordinated Debentures and a net increase of $1.3 billion in outstanding Senior Unsecured Notes partially offset, by the reacquisition of a net $370 million of Pollution Control Bonds and $125 million of Securitization Bonds.  In September 2008, we borrowed $600 million under our credit agreements.  See Note 9 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows from Financing Activities in 2007 were $1.2 billion primarily due to issuing $1.9 billion of debt securities including $1 billion of new debt for plant acquisitions and construction and increasing short-term commercial paper borrowings.

Off-balance Sheet Arrangements

Under a limited set of circumstances, we enter into off-balance sheet arrangements to accelerate cash collections, reduce operational expenses and spread risk of loss to third parties.  Our current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements and sales of customer accounts receivable that we enter in the normal course of business.  Our significant off-balance sheet arrangements  are as follows:
 
September 30,
2008
 
December 31,
2007
 
 (in millions) 
AEP Credit Accounts Receivable Purchase Commitments $555  $507 
Rockport Plant Unit 2 Future Minimum Lease Payments  2,142   2,216 
Railcars Maximum Potential Loss From Lease Agreement  26   30 

For complete information on each of these off-balance sheet arrangements see the “Off-balance Sheet Arrangements” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2007 Annual Report.

Summary Obligation Information

A summary of our contractual obligations is included in our 2007 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” above and the drawdowns and standby letters of credit discussed in “Liquidity” above.

SIGNIFICANT FACTORS

We continue to be involved in various matters described in the “Significant Factors” section of “Management’s Financial Discussion and Analysis of Results of Operations” in our 2007 Annual Report.  The 2007 Annual Report should be read in conjunction with this report in order to understand significant factors which have not materially changed in status since the issuance of our 2007 Annual Report, but may have a material impact on our future net income, cash flows and financial condition.

Ohio Electric Security Plan Filings

In April 2008, the Ohio legislature passed Senate Bill 221, which amends the restructuring law effective July 31, 2008 and requires electric utilities to adjust their rates by filing an Electric Security Plan (ESP).  Electric utilities may file an ESP with a fuel cost recovery mechanism.  Electric utilities also have an option to file a Market Rate Offer (MRO) for generation pricing.  An MRO, from the date of its commencement, could transition CSPCo and OPCo to full market rates no sooner than six years and no later than ten years after the PUCO approves an MRO.  The PUCO has the authority to approve or modify the utilities’ ESP request.  The PUCO is required to approve an ESP if, in the aggregate, the ESP is more favorable to ratepayers than the MRO.  Both alternatives involve a “substantially excessive earnings” test based on what public companies, including other utilities with similar risk profiles, earn on equity.  Management has preliminarily concluded, pending the outcome of the ESP proceeding, that CSPCo’s and OPCo’s generation/supply operations are not subject to cost-based rate regulation accounting.  However, if a fuel cost recovery mechanism is implemented within the ESP, CSPCo’s and OPCo’s fuel and purchased power operations would be subject to cost-based rate regulation accounting.  Management is unable to predict the financial statement impact of the restructuring legislation until the PUCO acts on specific proposals made by CSPCo and OPCo in their ESPs.

In July 2008, within the parameters of the ESPs, CSPCo and OPCo filed with the PUCO to establish rates for 2009 through 2011.  CSPCo and OPCo did not file an optional MRO.  CSPCo and OPCo each requested an annual rate increase for 2009 through 2011 that would not exceed approximately 15% per year.  A significant portion of the requested increases results from the implementation of a fuel cost recovery mechanism (which excludes off-system sales) that primarily includes fuel costs, purchased power costs including mandated renewable energy, consumables such as urea, other variable production costs and gains and losses on sales of emission allowances.  The increases in customer bills related to the fuel-purchased power cost recovery mechanism would be phased-in over the three year period from 2009 through 2011.  If the ESP is approved as filed, effective with January 2009 billings, CSPCo and OPCo will defer any fuel cost under-recoveries and related carrying costs for future recovery.  The under-recoveries and related carrying costs that exist at the end of 2011 will be recovered over seven years from 2012 through 2018.  In addition to the fuel cost recovery mechanisms, the requested increases would also recover incremental carrying costs associated with environmental costs, Provider of Last Resort (POLR) charges to compensate for the risk of customers changing electric suppliers, automatic increases for distribution reliability costs and for unexpected non-fuel generation costs.  The filings also include programs for smart metering initiatives and economic development and mandated energy efficiency and peak demand reduction programs.  In September 2008, the PUCO issued a finding and order tentatively adopting rules governing MRO and ESP applications.  CSPCo and OPCo filed their ESP applications based on proposed rules and requested waivers for portions of the proposed rules.  The PUCO denied the waiver requests in September 2008 and ordered CSPCo and OPCo to submit information consistent with the tentative rules.  In October 2008, CSPCo and OPCo submitted additional information related to proforma financial statements and information concerning CSPCo and OPCo’s fuel procurement process.  In October 2008, CSPCo and OPCo filed an application for rehearing with the PUCO to challenge certain aspects of the proposed rules.
Within the ESPs, CSPCo and OPCo would also recover existing regulatory assets of $46 million and $38 million, respectively, for customer choice implementation and line extension carrying costs.  In addition, CSPCo and OPCo would recover related unrecorded equity carrying costs of $30 million and $21 million, respectively.  Such costs would be recovered over an 8-year period beginning January 2011.  Hearings are scheduled for November 2008 and an order is expected in the fourth quarter of 2008.  If an order is not received prior to January 1, 2009, CSPCo and OPCo have requested retroactive application of the new rates back to January 1, 2009 upon approval.  Failure of the PUCO to ultimately approve the recovery of the regulatory assets would have an adverse effect on future net income and cash flows.

Cook Plant Unit 1 Fire and Shutdown

Cook Plant Unit 1 (Unit 1) is a 1,030 MW nuclear generating unit located in Bridgman, Michigan. In September 2008, I&M shut down Unit 1 due to turbine vibrations likely caused by blade failure which resulted in a fire on the electric generator.  This equipment is in the turbine building and is separate and isolated from the nuclear reactor.  The steam turbines that caused the vibration were installed in 2006 and are under warranty from the vendor.  The warranty provides for the replacement of the turbines if the damage was caused by a defect in the design or assembly of the turbines.  I&M is also working with its insurance company, Nuclear Electric Insurance Limited (NEIL),  and turbine vendor to evaluate the extent of the damage resulting from the incident and the costs to return the unit to service.  We cannot estimate the ultimate costs of the outage at this time.  Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process.  Our preliminary analysis indicates that Unit 1 could resume operations as early as late first quarter/early second quarter of 2009 or as late as the second half of 2009, depending upon whether the damaged components can be repaired or whether they need to be replaced.
I&M maintains property insurance through NEIL with a $1 million deductible.  I&M also maintains a separate accidental outage policy with NEIL whereby, after a 12 week deductible period, I&M is entitled to weekly payments of $3.5 million during the outage period for a covered loss.  If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if the unit is not returned to service in a reasonable period of time, it could have an adverse impact on net income, cash flows and financial condition.
TCC Texas Restructuring Appeals

Pursuant to PUCT orders, TCC securitized its net recoverable stranded generation costs of $2.5 billion and is recovering the principal and interest on the securitization bonds over a period ending in 2020.  TCC has refunded its net other true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider.  Cash paid for these CTC refunds for the nine months ended September 30, 2008 and 2007 was $75 million and $207 million, respectively.  TCC appealed the PUCT stranded costs true-up and related orders seeking relief in both state and federal court on the grounds that certain aspects of the orders are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law and fail to fully compensate TCC for its net stranded cost and other true-up items.  Municipal customers and other intervenors also appealed the PUCT true-up orders seeking to further reduce TCC’s true-up recoveries.

In March 2007, the Texas District Court judge hearing the appeals of the true-up order affirmed the PUCT’s April 2006 final true-up order for TCC with two significant exceptions.  The judge determined that the PUCT erred by applying an invalid rule to determine the carrying cost rate for the true-up of stranded costs and remanded this matter to the PUCT for further consideration.  The district court judge also determined that the PUCT improperly reduced TCC’s net stranded plant costs for commercial unreasonableness.

TCC, the PUCT and intervenors appealed the district court decision to the Texas Court of Appeals.  In May 2008, the Texas Court of Appeals affirmed the district court decision in all but one major respect.  It reversed the district court’s unfavorable decision finding that the PUCT erred by applying an invalid rule to determine the carrying cost rate.  The favorable commercial unreasonableness decision was not reversed.  The Texas Court of Appeals denied intervenors’ motion for rehearing.  In May 2008, TCC, the PUCT and intervenors filed petitions for review with the Texas Supreme Court.

Management cannot predict the outcome of these court proceedings and PUCT remand decisions.  If TCC ultimately succeeds in its appeals, it could have a material favorable effect on future net income, cash flows and financial condition.  If municipal customers and other intervenors succeed in their appeals it could have a substantial adverse effect on future net income, cash flows and financial condition.
New Generation

In 2008, AEP completed or is in various stages of construction of the following generation facilities:
                Commercial                Commercial
     Total        Nominal Operation     Total        Nominal Operation
Operating Project   Projected        MW Date Project   Projected        MW Date
Company Name Location Cost (a) CWIP (b) Fuel Type Plant Type Capacity (Projected) Name Location Cost (a) CWIP (b) Fuel Type Plant Type Capacity (Projected)
     (in millions) (in millions)             (in millions) (in millions)        
PSO Southwestern(c)Oklahoma $56 $- Gas Simple-cycle 150 2008 Southwestern(c)Oklahoma $56 $- Gas Simple-cycle 150 2008 
PSO Riverside(d)Oklahoma  58  - Gas Simple-cycle 150 2008 Riverside(d)Oklahoma  58  - Gas Simple-cycle 150 2008 
AEGCo Dresden(e)Ohio  309(e) 119 Gas Combined-cycle 580 2010 Dresden(e)Ohio  309(h) 149 Gas Combined-cycle 580 2010(h)
SWEPCo Stall Louisiana  378  106 Gas Combined-cycle 500 2010 Stall Louisiana  378  158 Gas Combined-cycle 500 2010 
SWEPCo Turk(f)Arkansas  1,522(f) 407 Coal Ultra-supercritical 600(f)2012 Turk(f)Arkansas  1,522(f) 448 Coal Ultra-supercritical 600(f)2012 
APCo Mountaineer(g)West Virginia  2,230(g) - Coal IGCC 629 2012(g) Mountaineer(g)West Virginia   (g)   Coal IGCC 629 (g) 
CSPCo/OPCo Great Bend(g)Ohio  2,700(g) - Coal IGCC 629 2017(g) Great Bend(g)Ohio   (g)   Coal IGCC 629 (g) 

(a)Amount excludes AFUDC.
(b)Amount includes AFUDC.  Turk’s CWIP includes joint owners’ share.
(c)Southwestern Units were placed in service on February 29, 2008.
(d)The final Riverside Unit was placed in service on June 15, 2008.
(e)In September 2007, AEGCo purchased the partially completed Dresden plantPlant from Dresden Energy LLC, a subsidiary of Dominion Resources, Inc., for $85 million, which is included in the “Total Projected Cost” section above.
(f)SWEPCo plans to own approximately 73%, or 440 MW, totaling $1,110 million$1.1 billion in capital investment.  The increase in the cost estimate disclosed in the 2007 Annual Report relates to cost escalations due to the delay in receipt of permits and approvals.  See “Turk Plant” section below.
(g)Subject to revision; constructionConstruction of IGCC plants deferredare pending necessary permits and regulatory approval.  See “IGCC Plants” section below.
(h)Projected completion date of the Dresden Plant is currently under review.  To the extent that the completion date is delayed, the total projected cost of the Dresden Plant could change.

Turk Plant

In November 2007, the APSC granted approval to build the Turk Plant.  Certain landowners filed a notice of appeal to the Arkansas State Court of Appeals.  In March 2008, the LPSC approved the application to construct the Turk Plant.

In JulyAugust 2008, the PUCT approved a certificateissued an order approving the Turk Plant with the following four conditions: (a) the capping of convenience and necessity for construction of the plant.  We expect a written order in August 2008 which will also providecapital costs for the conditionsTurk Plant at the $1.5 billion projected construction cost, excluding AFUDC, (b) capping CO2 emission costs at $28 per ton through the year 2030, (c) holding Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers and (d) providing the PUCT all updates, studies, reviews, reports and analyses as previously required under the Louisiana and Arkansas orders.  An intervenor filed a motion for rehearing seeking reversal of the PUCT’s approval.decision.  SWEPCo filed a motion for rehearing stating that the two cost cap restrictions are unlawful.  In September 2008, the motions for rehearing were denied.  In October 2008, SWEPCo appealed the PUCT’s order regarding the two cost cap restrictions.  If the cost cap restrictions are upheld and construction or emissions costs exceed the restrictions, it could have a material adverse impact on future net income and cash flows.  In October 2008, an intervenor filed an appeal contending that the PUCT’s grant of a conditional Certificate of Public Convenience and Necessity for the Turk Plant was not necessary to serve retail customers.

SWEPCo is also working with the Arkansas Department of Environmental Quality for the approval of an air permit and the U.S. Army Corps of Engineers for the approval later this year.of a wetlands and stream impact permit.  Once SWEPCo receives the air permit, they will commence construction.  A request to stop pre-construction activities at the site was filed in Federalfederal court by the same Arkansas landowners who appealed the APSC decision to the Arkansas State Court of Appeals.  In July 2008, the Federalfederal court denied the request and the Arkansas landowners appealed the denial to the U.S. Court of Appeals.

In January 2008 and July 2008, SWEPCo filed applications for authority with the APSC to construct transmission lines necessary for service from the Turk Plant.  Several landowners filed for intervention status and one landowner also contended he should be permitted to re-litigate Turk Plant issues, including the need for the generation.  The APSC granted their intervention but denied the request to re-litigate the Turk Plant issues.  The landowner filed an appeal to the Arkansas State Court of Appeals in June 2008.

The Arkansas Governor’s Commission on Global Warming is scheduled to issue its final report to the Governor by November 1, 2008.  The Commission was established to set a global warming pollution reduction goal together with a strategic plan for implementation in Arkansas.  If legislation is passed as a result of the findings in the Commission’s report, it could impact SWEPCo’s proposal to build the Turk Plant.

If SWEPCo does not receive appropriate authorizations and permits to build the Turk Plant, SWEPCo could incur significant cancellation fees to terminate its commitments and would be responsible to reimburse the joint ownersOMPA, AECC and ETEC for their share of paid costs.  If that occurred, SWEPCo would seek recovery of its capitalized costs including any cancellation fees and joint owner reimbursements.  As of JuneSeptember 30, 2008, including the joint owners’ share, SWEPCo has capitalized approximately $407$448 million of expenditures and has significant contractual construction commitments for an additional $815$771 million.  As of JuneSeptember 30, 2008, if the plant had been canceled,cancelled, cancellation fees of $60$61 million would have been required in order to terminate these construction commitments.  If the Turk Plant does not receive all necessary approvals on reasonable terms and SWEPCo cannot recover its capitalized costs, including any cancellation fees, it would have an adverse effect on future results of operations,net income, cash flows and possibly financial condition.

IGCC Plants

We have delayedThe construction of the West Virginia and Ohio IGCC plants.plants are pending necessary permits and regulatory approvals.  In May 2008, the Virginia SCC denied APCo’s request to reconsider the Virginia SCC'sSCC’s previous denial of APCo’s request to recover initial costs associated with a proposed IGCC plant in West Virginia.  In July 2008, the WVPSC issued a notice seeking comments from parties on how the WVPSC should proceed regarding its earlier approval of the IGCC plant.  In July 2008, the IRS awardedallocated $134 million in future tax credits to APCo for the planned IGCC plant.  Management continues to pursueplant contingent upon the ultimatecommencement of construction, qualifying expenses being incurred and certification of the IGCC plant.plant prior to July 2010.  Through September 30, 2008, APCo deferred for future recovery preconstruction IGCC costs of $19 million.  If the West Virginia IGCC plant is canceled,cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs of $19 million.costs.  If the plant is canceledcancelled and if the deferred costs are not recoverable, it would have an adverse effect on future results of operationsnet income and cash flows.

In Ohio, CSPCo and OPCo continue to pursue the ultimate construction of the IGCC plant, but awaitplant.  In September 2008, the result of an Ohio Supreme Court remand toConsumers’ Counsel filed a motion with the PUCO regarding recovery of IGCC pre-construction costs.requesting all Phase 1 cost recoveries be refunded to Ohio ratepayers with interest.  CSPCo and OPCo filed a response with the PUCO that argued the Ohio Consumers’ Counsel’s motion was without legal merit and contrary to past precedent.  If CSPCo and OPCo were required to refund some or all of the $24 million collected for IGCC pre-construction costs and those costs were not recoverable in another jurisdiction in connection with the construction of an IGCC plant, it would have an adverse effect on future results of operationsnet income and cash flows.

Litigation

In the ordinary course of business, we, along with our subsidiaries, are involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome will be, or what the timing of the amount of any loss, fine or penalty may be.  Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases that have a probable likelihood of loss and if the loss amount can be estimated.  For details on our regulatory proceedings and pending litigation see Note 4 – Rate Matters, Note 6 – Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2007 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 results of operations.net income.

Environmental Litigation

New Source Review (NSR) Litigation:  The Federal EPA, a number of states and certain special interest groups filed complaints alleging that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities, including Cincinnati Gas & Electric Company, Dayton Power and Light Company (DP&L) and Duke Energy Ohio, Inc. (Duke), modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA.

In 2007, the AEP System settled their complaints under a consent decree.  CSPCo jointly-owns Beckjord and Stuart Stations with Duke and DP&L.  A jury trial in May 2008 returned a verdict of no liability at the jointly-owned Beckjord unit.  Settlement discussions are ongoingIn October 2008, the court approved a settlement in the citizen suit action filed by Sierra Club against the jointly-owned units at Stuart Station.  Under the settlement, the joint-owners of Stuart Station agreed to certain emission targets related to NOx, SO2 and PM.  We believe we can recover any capitalalso agreed to make energy efficiency and operating costsrenewable energy commitments that are conditioned on PUCO approval for recovery of additional pollution control equipment that may be required through future regulated rates or market prices for electricity.  If we are unablecosts.  The joint-owners also agreed to recover such costs or if material penalties are imposed, it would adversely affect future results of operationsforfeit 5,500 SO2 allowances and cash flows.provide $300 thousand to a third party organization to establish a solar water heater rebate program.

Environmental Matters

We are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements.  The sources of these requirements include:

·
Requirements under CAA to reduce emissions of SO2, NOx, particulate matter (PM)PM and mercury from fossil fuel-fired power plants; and
·
Requirements under the Clean Water Act (CWA) to reduce the impacts of water intake structures on aquatic species at certain of our power plants.

In addition, we are engaged in litigation with respect to certain environmental matters, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of spent nuclear fuel and future decommissioning of our nuclear units.  We are also engaged in the development of possible future requirements to reduce CO2 and other greenhouse gasesgas (GHG) emissions to address concerns about global climate change.  All of these matters are discussed in the “Environmental Matters” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2007 Annual Report.

Clean Air Act Requirements

As discussed in the 2007 Annual Report under “Clean Air Act Requirements,” various states and environmental organizations challenged the Clean Air Mercury Rule (CAMR) in the D. C. Circuit Court of Appeals.  The Courtcourt ruled that the Federal EPA’s action delisting fossil fuel-fired power plants did not conform to the procedures specified in the CAA.  The Courtcourt vacated and remanded the model federal rules for both new and existing coal-fired power plants to the Federal EPA.  The Federal EPA filed a petition for review by the U.S. Supreme Court.  We are unable to predict the outcome of this appeal or how the Federal EPA will respond to the remand.  In addition, in 2005, the Federal EPA issued a final rule, the Clean Air Interstate Rule (CAIR), that requires further reductions in SO2 and NOx emissions and assists states developing new state implementation plans to meet 1997 national ambient air quality standards (NAAQS).  CAIR reduces regional emissions of SO2 and NOx (which can be transformed into PM and ozone) from power plants in the Eastern U.S. (29 states and the District of Columbia).  CAIR requires power plants within these states to reduce emissions of SO2 by 50 percent50% by 2010, and by 65 percent65% by 2015.  NOx emissions will be subject to additional limits beginning in 2009, and will be reduced by a total of 70 percent70% from current levels by 2015.  Reduction of both SO2 and NOx would be achieved through a cap-and-trade program.  In July 2008, the D.C. Circuit Court of Appeals vacated the CAIR and remanded the rule to the Federal EPA.  The Federal EPA and other parties petitioned for rehearing.  We are unable to predict the outcome of the rehearing petitions or how the Federal EPA will respond to the remand which could be stayed or appealed to the U.S. Supreme Court.  The Federal EPA also issued revised NAAQS for both ozone and PM 2.5 that are more stringent than the 1997 standards used to establish CAIR, which could increase the levels of SO2 and NOx reductions required from our facilities.

In anticipation of compliance with CAIR in 2009, I&M purchased $8$9 million of annual CAIR NOx  allowances which are included in inventoryDeferred Charges and Other on our Condensed Consolidated Balance Sheet as of JuneSeptember 30, 2008.  The market value of annual CAIR NOx allowances decreased in the weeks following this court decision.  ManagementHowever, our weighted-average cost of these allowances is below market.  If CAIR remains vacated, management intends to seek partial recovery of the cost of purchased allowances.  If the recovery is denied, itAny unrecovered portion would have an adverse effect on future results of operationsnet income and cash flows.  None of AEP’s other subsidiaries purchased any significant number of CAIR allowances.  SO2 and seasonal NOx allowances allocated to our facilities under the Acid Rain Program and the NOx SIPstate implementation plan (SIP) Call will still be required to comply with existing CAA programs that were not affected by the court’s decision.

It is too early to determine the full implication of these decisions on our environmental compliance strategy.  However, independent obligations under the CAA, including obligations under future state implementation plan submittals, and actions taken pursuant to our recent settlement of the NSR enforcement action, are consistent with the actions included in our least-cost CAIR compliance plan.   Consequently, we do not anticipate making any immediate changes in our near-term compliance plans as a result of these court decisions.

Global Climate Change

In July 2008, the Federal EPA issued an advance notice of proposed rulemaking (ANPR) that requests comments on a wide variety of issues the agency is considering in formulating its response to the U.S. Supreme Court’s decision in Massachusetts v. EPA.  In that case, the Courtcourt determined that CO2 is an “air pollutant” and that the Federal EPA has authority to regulate mobile sources of CO2 emissions under the CAA if appropriate findings are made.  The Federal EPA has identified a number of issues that could affect stationary sources, such as electric generating plants, if the necessary findings are made for mobile sources, including the potential regulation of CO2 emissions for both new and existing stationary sources under the NSR programs of the CAA.  We plan to submit comments and participate in any subsequent regulatory development processes, but are unable to predict the outcome of the Federal EPA’s administrative process or its impact on our business.  Also, additional legislative measures to address CO2 and other GHGs have been introduced in Congress, and such legislative actions could impact future decisions by the Federal EPA on CO2 regulation.

In addition, the Federal EPA issued a proposed rule for the underground injection and storage of CO2 captured from industrial processes, including electric generating facilities, under the Safe Drinking Water Act’s Underground Injection Control (UIC) program.  The proposed rules provide a comprehensive set of well siting, design, construction, operation, closure and post-closure care requirements.  We plan to submit comments and participate in any subsequent regulatory development process, but are unable to predict the outcome of the Federal EPA’s administrative process or its impact on our business.  Permitting for our demonstration project at the Mountaineer Plant will proceed under the existing UIC rules.

Clean Water Act Regulations

In 2004, the Federal EPA issued a final rule requiring all large existing power plants with once-through cooling water systems to meet certain standards to reduce mortality of aquatic organisms pinned against the plant’s cooling water intake screen or entrained in the cooling water.  The standards vary based on the water bodies from which the plants draw their cooling water.  We expected additional capital and operating expenses, which the Federal EPA estimated could be $193 million for our plants.  We undertook site-specific studies and have been evaluating site-specific compliance or mitigation measures that could significantly change these cost estimates.

In January 2007, the Second Circuit Court of Appeals issued a decision remanding significant portions of the rule to the Federal EPA.  In July 2007, the Federal EPA suspended the 2004 rule, except for the requirement that permitting agencies develop best professional judgment (BPJ) controls for existing facility cooling water intake structures that reflect the best technology available for minimizing adverse environmental impact.  The result is that the BPJ control standard for cooling water intake structures in effect prior to the 2004 rule is the applicable standard for permitting agencies pending finalization of revised rules by the Federal EPA.  We cannot predict further action of the Federal EPA or what effect it may have on similar requirements adopted by the states.  We sought further review and filed for relief from the schedules included in our permits.

In April 2008, the U.S. Supreme Court agreed to review decisions from the Second Circuit Court of Appeals that limit the Federal EPA’s ability to weigh the retrofitting costs against environmental benefits.  Management is unable to predict the outcome of this appeal.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2007 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.

Adoption of New Accounting Pronouncements

In September 2006, the FASB issued SFAS 157 “Fair Value Measurements” (SFAS 157), enhancing existing guidance for fair value measurement of assets and liabilities and instruments measured at fair value that are classified in shareholders’ equity.  The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures.  It emphasizes that fair value is market-based with the highest measurement hierarchy level being market prices in active markets.  The standard requires fair value measurements be disclosed by hierarchy level, an entity includes its own credit standing in the measurement of its liabilities and modifies the transaction price presumption.  The standard also nullifies the consensus reached in EITF Issue No. 02-3 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3) that prohibited the recognition of trading gains or losses at the inception of a derivative contract, unless the fair value of such derivative is supported by observable market data.  In February 2008, the FASB issued FSP FASSFAS 157-1 “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” which amends SFAS 157 to exclude SFAS 13 “Accounting for Leases” and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under SFAS 13.  In February 2008, the FASB issued FSP FASSFAS 157-2 “Effective Date of FASB Statement No. 157” which delays the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).  In October 2008, the FASB issued FSP SFAS 157-3 “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active” which clarifies application of SFAS 157 in markets that are not active and provides an illustrative example.  The provisions of SFAS 157 are applied prospectively, except for a) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF 02-3, b) existing hybrid financial instruments measured initially at fair value using the transaction price and c) blockage discount factors.  Although the statement is applied prospectively upon adoption, in accordance with the provisions of SFAS 157 related to EITF 02-3, we recorded an immaterial transition adjustment to beginning retained earnings.  The impact of considering our own credit risk when measuring the fair value of liabilities, including derivatives, had an immaterial impact on fair value measurements upon adoption.  We partially adopted SFAS 157 effective January 1, 2008.  FSP SFAS 157-3 is effective upon issuance.  We will fully adopt SFAS 157 effective January 1, 2009 for items within the scope of FSP FASSFAS 157-2.  We expect that the adoption of FSP SFAS 157-2 will have an immaterial impact on our financial statements.  See “SFAS 157 “Fair Value Measurements” (SFAS 157)” section of Note 2.

In February 2007, the FASB issued SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159), permitting entities to choose to measure many financial instruments and certain other items at fair value.  The standard also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities.  If the fair value option is elected, the effect of the first remeasurement to fair value is reported as a cumulative effect adjustment to the opening balance of retained earnings.  The statement is applied prospectively upon adoption.  We adopted SFAS 159 effective January 1, 2008.  At adoption, we did not elect the fair value option for any assets or liabilities.

In March 2007, the FASB ratified EITF Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements” (EITF 06-10), a consensus on collateral assignment split-dollar life insurance arrangements in which an employee owns and controls the insurance policy.  Under EITF 06-10, an employer should recognize a liability for the postretirement benefit related to a collateral assignment split-dollar life insurance arrangement in accordance with SFAS 106 “Employers' Accounting for Postretirement Benefits Other Than Pension” or Accounting Principles Board Opinion No. 12 “Omnibus Opinion – 1967” if the employer has agreed to maintain a life insurance policy during the employee's retirement or to provide the employee with a death benefit based on a substantive arrangement with the employee.  In addition, an employer should recognize and measure an asset based on the nature and substance of the collateral assignment split-dollar life insurance arrangement.  EITF 06-10 requires recognition of the effects of its application as either (a) a change in accounting principle through a cumulative effect adjustment to retained earnings or other components of equity or net assets in the statement of financial position at the beginning of the year of adoption or (b) a change in accounting principle through retrospective application to all prior periods.  We adopted EITF 06-10 effective January 1, 2008 with a cumulative effect reduction of $16 million ($10 million, net of tax) to beginning retained earnings.

In June 2007, the FASB ratified the EITF Issue No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards” (EITF 06-11), consensus on the treatment of income tax benefits of dividends on employee share-based compensation.  The issue is how a company should recognize the income tax benefit received on dividends that are paid to employees holding equity-classified nonvested shares, equity-classified nonvested share units or equity-classified outstanding share options and charged to retained earnings under SFAS 123R, “Share-Based Payments.”  Under EITF 06-11, a realized income tax benefit from dividends or dividend equivalents that are charged to retained earnings and are paid to employees for equity-classified nonvested equity shares, nonvested equity share units and outstanding equity share options should be recognized as an increase to additional paid-in capital. We adopted EITF 06-11 effective January 1, 2008.  EITF 06-11 is applied prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years after December 15, 2007.  The adoption of this standard had an immaterial impact on our financial statements.

In April 2007, the FASB issued FSP FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1).  It amends FASB Interpretation No. 39 “Offsetting of Amounts Related to Certain Contracts” by replacing the interpretation’s definition of contracts with the definition of derivative instruments per SFAS 133.  It also requires entities that offset fair values of derivatives with the same party under a netting agreement to net the fair values (or approximate fair values) of related cash collateral.  The entities must disclose whether or not they offset fair values of derivatives and related cash collateral and amounts recognized for cash collateral payables and receivables at the end of each reporting period. We adopted FIN 39-1 effective January 1, 2008.  This standard changed our method of netting certain balance sheet amounts and reduced assets and liabilities.  It requires retrospective application as a change in accounting principle.  Consequently, we reduced total assets and liabilities on the December 31, 2007 balance sheet by $47 million each.  See “FSP FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1)” section of Note 2.


QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our Utility Operations segment is exposed to certain market risks as a major power producer and marketer of wholesale electricity, coal and emission allowances.  These risks include commodity price risk, interest rate risk and credit risk.  In addition, we may be 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, transacts in wholesale energy trading and 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 will gradually liquidate and completely expire in 2011.  Our risk objective is to keep these positions generally risk neutral through maturity.

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

We actively participate in theThe Committee of Chief Risk Officers (CCRO) to develop standard disclosures for risk management activities around risk management contracts.  The CCRO adopted disclosure standards for risk management contracts to improve clarity, understanding and consistency of information reported.  We support the work of the CCRO and embrace the disclosure standards applicable to our business activities.  The following tables provide information on our risk management activities.



Mark-to-Market Risk Management Contract Net Assets (Liabilities)

The following two tables summarize the various mark-to-market (MTM) positions included on our Condensed Consolidated Balance Sheet as of JuneSeptember 30, 2008 and the reasons for changes in our total MTM value included on our Condensed Consolidated Balance Sheet as compared to December 31, 2007.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
JuneSeptember 30, 2008
(in millions)

Utility Operations 
Generation and
Marketing
 All Other 
Sub-Total
MTM Risk Management Contracts
 
MTM
of Cash Flow and Fair Value Hedges
 
 
 
Collateral
Deposits
 Total  Utility Operations  
Generation and
Marketing
  All Other  
Sub-Total
MTM Risk Management Contracts
  
MTM
of Cash Flow and Fair Value Hedges
  
 
Collateral
Deposits
  Total 
Current Assets$653 $201 $121 $975 $34 $(118)$891  $246  $52  $43  $341  $25  $(26) $340 
Noncurrent Assets 309  144  86  539  14  (64) 489   164   128   40   332   6   (24)  314 
Total Assets 962  345  207  1,514  48  (182) 1,380   410   180   83   673   31   (50)  654 
                                           
Current Liabilities (660) (203) (124) (987) (101) 97 (991)  (209)  (65)  (47)  (321)  (18)  9   (330)
Noncurrent Liabilities (202) (75) (90) (367) (5) 24  (348)  (69)  (57)  (43)  (169)  (4)  8   (165)
Total Liabilities (862) (278) (214) (1,354) (106) 121  (1,339)  (278)  (122)  (90)  (490)  (22)  17   (495)
                                           
Total MTM Derivative
Contract Net Assets
(Liabilities)
$100 $67 $(7)$160 $
 
 
(58
 
 
)
 
 
$
 
 
(61
)$41  $132  $58  $(7) $183  $9  $(33) $159 

MTM Risk Management Contract Net Assets (Liabilities)
SixNine Months Ended JuneSeptember 30, 2008
(in millions)
  Utility Operations 
Generation
and
Marketing
 All Other Total 
Total MTM Risk Management Contract Net Assets (Liabilities)
  at December 31, 2007
 $156 $43 $(8)$191 
(Gain) Loss from Contracts Realized/Settled During the Period and
  Entered in a Prior Period
  (36) 4  -  (32)
Fair Value of New Contracts at Inception When Entered
  During the Period (a)
  2  16  -  18 
Changes in Fair Value Due to Valuation Methodology
  Changes on Forward Contracts (b)
  6  3  1  10 
Changes in Fair Value Due to Market Fluctuations During 
  the Period (c)
  6  1  -  7 
Changes in Fair Value Allocated to Regulated Jurisdictions (d)  (34) -  -  (34)
Total MTM Risk Management Contract Net Assets
  (Liabilities) at June 30, 2008
 $100 $67 $(7) 160 
Net Cash Flow and Fair Value Hedge Contracts
           (58)
Collateral Deposits           (61)
Ending Net Risk Management Assets at June 30, 2008          $41 
  Utility Operations  
Generation
and
Marketing
  All Other  Total 
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2007 $156  $43  $(8) $191 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period  (57)  4   1   (52)
Fair Value of New Contracts at Inception When Entered During the Period (a)  2   17   -   19 
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b)  3   3   1   7 
Changes in Fair Value Due to Market Fluctuations During the Period (c)  18   (9)  (1)  8 
Changes in Fair Value Allocated to Regulated Jurisdictions (d)  10   -   -   10 
Total MTM Risk Management Contract Net Assets (Liabilities) at September 30, 2008 $132  $58  $(7)  183 
Net Cash Flow and Fair Value Hedge Contracts
              9 
Collateral Deposits              (33)
Ending Net Risk Management Assets at September 30, 2008             $159 

(a)Reflects fair value on long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)Represents the impact of applying AEP’s credit risk when measuring the fair value of derivative liabilities according to SFAS 157.
(c)Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(d)“Change in Fair Value Allocated to Regulated Jurisdictions” 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 assets/liabilities for those subsidiaries that operate in regulated jurisdictions.liabilities.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets (Liabilities)

The following table presents the maturity, by year, of our net assets/liabilities, to give an indication of when these MTM amounts will settle and generate cash:

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets (Liabilities)
Fair Value of Contracts as of JuneSeptember 30, 2008
(in millions)
 
Remainder
2008
  2009  2010  2011  2012  
After
2012 (f)
  Total  
Remainder
2008
  2009  2010  2011  2012  
After
2012 (f)
  Total 
Utility Operations:                                          
Level 1 (a) $(6) $1  $-  $-  $-  $-  $(5) $(2) $(8) $-  $-  $-  $-  $(10)
Level 2 (b)  8   47   40   16   6   -   117   5   62   43   5   1   -   116 
Level 3 (c)  (29)  (5)  (12)  (8)  (4)  -   (58)  (15)  2   (6)  1   1   -   (17)
Total  (27)  43   28   8   2   -   54   (12)  56   37   6   2   -   89 
                                                        
Generation and Marketing:                                                        
Level 1 (a)  (36)  13   (1)  (1)  -   -   (25)  (1)  -   -   -   -   -   (1)
Level 2 (b)  31   (8)  6   5   5   3   42   (21)  2   11   12   11   20   35 
Level 3 (c)  (2)  -   8   9   9   26   50   5   2   3   2   2   10   24 
Total  (7)  5   13   13   14   29   67   (17)  4   14   14   13   30   58 
                                                        
All Other:                                                        
Level 1 (a)  -   -   -   -   -   -   -   -   -   -   -   -   -   - 
Level 2 (b)  (1)  (4)  (4)  2   -   -   (7)  (1)  (4)  (4)  2   -   -   (7)
Level 3 (c)  -   -   -   -   -   -   -   -   -   -   -   -   -   - 
Total  (1)  (4)  (4)  2   -   -   (7)  (1)  (4)  (4)  2   -   -   (7)
                                                        
Total:                                                        
Level 1 (a)  (42)  14   (1)  (1)  -   -   (30)  (3)  (8)  -   -   -   -   (11)
Level 2 (b)  38   35   42   23   11   3   152   (17)  60   50   19   12   20   144 
Level 3 (c) (d)  (31)  (5)  (4)  1   5   26   (8)  (10)  4   (3)  3   3   10   7 
Total  (35)  44   37   23   16   29   114   (30)  56   47   22   15   30   140 
Dedesignated Risk Management
Contracts (e)
  7   14   14   6   5   -   46   4   14   14   6   5   -   43 
Total MTM Risk Management
Contract Net Assets (Liabilities)
 $(28) $58  $51  $29  $21  $29  $160  $(26) $70  $61  $28  $20  $30  $183 


(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)A significant portion of the total volumetric position within the consolidated level 3 balance has been economically hedged.
(e)Dedesignated Risk Management Contracts are contracts that were originally MTM but were subsequently elected as normal under SFAS 133.  At the time of the normal election the MTM value was frozen and no longer fair valued.  This will be amortized within Utility Operations Revenues over the remaining life of the contract.
(f)There is mark-to-market value of $29$30 million in individual periods beyond 2012.  $13$14 million of this mark-to-market value is in 2013, $8 million is in 2014, $3 million is in 2015, $3$2 million is in 2016 and $2$3 million is in 2017.
The following table reports an estimate of the maximum tenors (contract maturities) of the liquid portion of each energy market.

Maximum Tenor of AEP’s Liquid Portion of Risk Management Contracts
As of June 30, 2008

CommodityTransaction ClassMarket/RegionTenor
(in Months)
Natural GasFuturesNYMEX / Henry Hub60
Physical ForwardsGulf Coast, Texas30
SwapsGas East, Mid-Continent, Gulf Coast, Texas30
Exchange Option VolatilityNYMEX / Henry Hub12
PowerFuturesPower East – PJM36
Physical ForwardsPower East – Cinergy54
Physical ForwardsPower East – PJM West54
Physical ForwardsPower East – AEP Dayton (PJM)54
Physical ForwardsPower East – ERCOT42
Physical ForwardsPower East – Entergy30
Physical ForwardsPower West – PV, NP15, SP15, MidC, Mead42
Peak Power Volatility (Options)Cinergy, PJM12
EmissionsCredits
SO2, NOx
42
CoalPhysical ForwardsPRB, NYMEX, CSX42

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed Consolidated Balance Sheets

We are exposed to market fluctuations in energy commodity prices impacting our power operations.  We monitor these risks on our future operations and may use various commodity derivative instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows.  We do not hedge all commodity price risk.

We use interest rate derivative transactions to manage interest rate risk related to existing variable rate debt and to manage interest rate exposure on anticipated borrowings of fixed-rate debt.  We do not hedge all interest rate exposure.

We use foreign currency derivatives to lock in prices on certain forecasted transactions denominated in foreign currencies where deemed necessary, and designate qualifying instruments as cash flow hedges.  We do not hedge all foreign currency exposure.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for changes in cash flow hedges from December 31, 2007 to JuneSeptember 30, 2008.  The following table also indicates what portion of designated, effective hedges are expected to be reclassified into net income in the next 12 months.  Only contracts designated as cash flow hedges are recorded in AOCI.  Therefore, economic hedge contracts which are not designated as effective cash flow hedges are marked-to-market and are included in the previous risk management tables.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
SixNine Months Ended JuneSeptember 30, 2008
(in millions)
 Power  
Interest
Rate and
Foreign
Currency
  Total  Power  
Interest Rate and
Foreign
Currency
  Total 
Beginning Balance in AOCI, December 31, 2007 $(1) $(25) $(26) $(1) $(25) $(26)
Changes in Fair Value  (32)  (4)  (36)  7   (5)  2 
Reclassifications from AOCI for Cash Flow Hedges Settled  1   1   2   2   3   5 
Ending Balance in AOCI, June 30, 2008 $(32) $(28) $(60)
Ending Balance in AOCI, September 30, 2008 $8  $(27) $(19)
                        
After Tax Portion Expected to be Reclassified to
Earnings During Next 12 Months
 $(38) $(6) $(44) $6  $(5) $1 

Credit Risk

We limit credit risk in our wholesale marketing and trading activities by assessing creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness after transactions have been initiated.  We use Moody’s Investors Service, Standard & Poor’s and qualitative and quantitative data to assess the financial health of counterparties on an ongoing basis.  If an external rating is not available, an internal rating is generated utilizing a quantitative tool developed by Moody’s to estimate probability of default that corresponds to an implied external agency credit rating.  Based on our analysis, we set appropriate risk parameters for each internally-graded counterparty.  We may also require cash deposits, letters of credit and parental/affiliate guarantees as security from counterparties in order to mitigate credit risk.

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.  At JuneSeptember 30, 2008, our credit exposure net of collateral to sub investment grade counterparties was approximately 20.1%14.5%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).  The increase from 5.4% at December 31, 2007 is primarily related to an increase in exposure with coal counterparties due to escalating coal prices.counterparties.  Approximately 55%57% of our credit exposure net of collateral to sub investment grade counterparties is short-term exposure of less than one year.  As of JuneSeptember 30, 2008, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable (in millions, except number of counterparties):

Counterparty Credit Quality Exposure Before Credit Collateral  Credit Collateral  Net Exposure  
Number of Counterparties >10% of
Net Exposure
  
Net Exposure
of Counterparties >10%
 
Investment Grade $873  $184  $689   2  $181 
Split Rating  36   7   29   4   27 
Noninvestment Grade  185   49   136   1   112 
No External Ratings:                    
 Internal Investment Grade  89   -   89   2   63 
 Internal Noninvestment Grade  68   1   67   2   61 
Total as of June 30, 2008 $1,251  $241  $1,010   11  $444 
                     
Total as of December 31, 2007 $673  $42  $631   6  $74 

Generation Plant Hedging Information

This table provides information on operating measures regarding the proportion of output of our generation facilities (based on economic availability projections) economically hedged, including both contracts designated as cash flow hedges under SFAS 133 and contracts not designated as cash flow hedges.  This information is forward-looking and provided on a prospective basis through December 31, 2010.  This table is a point-in-time estimate, subject to changes in market conditions and our decisions on how to manage operations and risk.  “Estimated Plant Output Hedged” represents the portion of MWHs of future generation/production, taking into consideration scheduled plant outages, for which we have sales commitments or estimated requirement obligations to customers.

Generation Plant Hedging Information
Estimated Next Three Years
As of June 30, 2008

 Remainder    
 2008 2009 2010
Estimated Plant Output Hedged90% 89% 91%
Counterparty Credit Quality Exposure Before Credit Collateral  Credit Collateral  Net Exposure  
Number of Counterparties >10% of
Net Exposure
  
Net Exposure
of Counterparties >10%
 
Investment Grade $626  $42  $584   2  $146 
Split Rating  14   -   14   2   14 
Noninvestment Grade  81   8   73   2   66 
No External Ratings:                    
Internal Investment Grade  110   -   110   2   77 
Internal Noninvestment Grade  46   -   46   2   40 
Total as of September 30, 2008 $877  $50  $827   10  $343 
                     
Total as of December 31, 2007 $673  $42  $631   6  $74 

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates Value at Risk (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, at JuneSeptember 30, 2008, a near term typical change in commodity prices is not expected to have a material effect on our results of operations,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 periods indicated:

VaR Model

Six Months Ended
June 30, 2008
 
Twelve Months Ended
December 31, 2007
Nine Months Ended
September 30, 2008
Nine Months Ended
September 30, 2008
 
Twelve Months Ended
December 31, 2007
(in millions)(in millions) (in millions)(in millions) (in millions)
End High Average Low End High Average Low High Average Low End High Average Low
$2 $2 $1 $1 $1 $6 $2 $1 $3 $1 $1 $1 $6 $2 $1

We back-test our VaR results against performance due to actual price moves.  Based on the assumed 95% confidence interval, the performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days.  Our backtesting results show that our actual performance exceeded VaR far fewer than once every 20 trading days.  As a result, we believe our VaR calculation is conservative.

As our VaR calculation captures recent price moves, we also perform regular stress testing of the portfolio to understand our exposure to extreme price moves.  We employ a historically-based method whereby the current portfolio is subjected to actual, observed price moves from the last three years in order to ascertain which historical price moves translates into the largest potential mark-to-market loss.  We then research the underlying positions, price moves and market events that created the most significant exposure.

Interest Rate Risk

We utilize an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which AEP’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  The estimated EaR on our debt portfolio was $32$51 million.



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in millions, except per-share amounts and shares outstanding)
(Unaudited)
 Three Months Ended  Six Months Ended  Three Months Ended  Nine Months Ended 
 2008  2007  2008  2007  2008  2007  2008  2007 
REVENUES                        
Utility Operations $3,200  $2,818  $6,210  $5,704  $4,108  $3,423  $10,318  $9,127 
Other  346   328   803   611   83   366   886   977 
TOTAL  3,546   3,146   7,013   6,315   4,191   3,789   11,204   10,104 
                                
EXPENSES                                
Fuel and Other Consumables Used for Electric Generation  1,053   868   2,033   1,754   1,480   1,099   3,513   2,853 
Purchased Energy for Resale  366   291   629   537 
Purchased Electricity for Resale  394   358   1,023   895 
Other Operation and Maintenance  982   881   1,860   1,819   1,010   964   2,870   2,783 
Gain on Disposition of Assets, Net  (5)  (3)  (8)  (26)  (6)  (2)  (14)  (28)
Asset Impairments and Other Related Items  -   -   (255)  - 
Asset Impairments and Other Related Charges  -   -   (255)  - 
Depreciation and Amortization  373   372   736   763   387   381   1,123   1,144 
Taxes Other Than Income Taxes  191   188   389   374   189   191   578   565 
TOTAL  2,960   2,597   5,384   5,221   3,454   2,991   8,838   8,212 
                                
OPERATING INCOME  586   549   1,629   1,094   737   798   2,366   1,892 
                                
Other Income:                
Interest and Investment Income  15   8   31   31   14   8   45   39 
Carrying Costs Income  26   16   43   24   21   14   64   38 
Allowance for Equity Funds Used During Construction  11   6   21   14 
Allowance For Equity Funds Used During Construction  11   9   32   23 
                                
INTEREST AND OTHER CHARGES                                
Interest Expense  234   213   454   399   216   216   670   615 
Preferred Stock Dividend Requirements of Subsidiaries  -   -   1   1   1   1   2   2 
TOTAL  234   213   455   400   217   217   672   617 
                                
INCOME BEFORE INCOME TAX EXPENSE, MINORITY
INTEREST EXPENSE AND EQUITY EARNINGS (LOSS)
  404   366   1,269   763 
INCOME BEFORE INCOME TAX EXPENSE, MINORITY
INTEREST EXPENSE AND EQUITY EARNINGS
  566   612   1,835   1,375 
                                
Income Tax Expense  123   108   416   238   192   205   608   443 
Minority Interest Expense  1   1   2   2   1   1   3   3 
Equity Earnings of Unconsolidated Subsidiaries  -   -   2   5   1   1   3   6 
                                
INCOME BEFORE DISCONTINUED OPERATIONS AND EXTRAORDINARY LOSS  280   257   853   528   374   407   1,227   935 
                                
DISCONTINUED OPERATIONS, NET OF TAX  1   2   1   2   -   -   1   2 
                                
INCOME BEFORE EXTRAORDINARY LOSS  281   259   854   530   374   407   1,228   937 
                                
EXTRAORDINARY LOSS, NET OF TAX  -   (79)  -   (79)  -   -   -   (79)
                                
NET INCOME $281  $180  $854  $451  $374  $407  $1,228  $858 
                                
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING  401,513,958   398,679,242   401,155,975   398,000,712   402,286,779   399,222,569   401,535,661   398,412,473 
                                
BASIC EARNINGS PER SHARE                                
Income Before Discontinued Operations and Extraordinary Loss $0.70  $0.64  $2.13  $1.33  $0.93  $1.02  $3.06  $2.35 
Discontinued Operations, Net of Tax  -   0.01   -   -   -   -   -   - 
Income Before Extraordinary Loss  0.70   0.65   2.13   1.33   0.93   1.02   3.06   2.35 
Extraordinary Loss, Net of Tax  -   (0.20)  -   (0.20)  -   -   -   (0.20)
TOTAL BASIC EARNINGS PER SHARE $0.70  $0.45  $2.13  $1.13  $0.93  $1.02  $3.06  $2.15 
                                
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING  402,785,942   399,868,900   402,429,019   399,214,277   403,910,309   400,215,911   402,925,534   399,552,630 
                                
DILUTED EARNINGS PER SHARE                                
Income Before Discontinued Operations and Extraordinary Loss $0.70  $0.64  $2.12  $1.32  $0.93  $1.02  $3.05  $2.34 
Discontinued Operations, Net of Tax  -   0.01   -   0.01   -   -   -   0.01 
Income Before Extraordinary Loss  0.70   0.65   2.12   1.33   0.93   1.02   3.05   2.35 
Extraordinary Loss, Net of Tax  -   (0.20)  -   (0.20)  -   -   -   (0.20)
TOTAL DILUTED EARNINGS PER SHARE $0.70  $0.45  $2.12  $1.13  $0.93  $1.02  $3.05  $2.15 
                                
CASH DIVIDENDS PAID PER SHARE $0.41  $0.39  $0.82  $0.78  $0.41  $0.39  $1.23  $1.17 

See Condensed Notes to Condensed Consolidated Financial Statements.


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
JuneSeptember 30, 2008 and December 31, 2007
(in millions)
(Unaudited)

 2008  2007  2008  2007 
CURRENT ASSETS            
Cash and Cash Equivalents $218  $178  $338  $178 
Other Temporary Investments  243   365   670   365 
Accounts Receivable:                
Customers  795   730   805   730 
Accrued Unbilled Revenues  400   379   370   379 
Miscellaneous  85   60   71   60 
Allowance for Uncollectible Accounts  (45)  (52)   (59)  (52)
Total Accounts Receivable  1,235   1,117   1,187   1,117 
Fuel, Materials and Supplies  1,049   967   1,018   967 
Risk Management Assets  891   271   340   271 
Regulatory Asset for Under-Recovered Fuel Costs  240   11 
Margin Deposits  63   47   67   47 
Regulatory Asset for Under-Recovered Fuel Costs  202   11 
Prepayments and Other  105   70   124   70 
TOTAL  4,006   3,026   3,984   3,026 
                
PROPERTY, PLANT AND EQUIPMENT                
Electric:                
Production  20,675   20,233   20,948   20,233 
Transmission  7,651   7,392   7,734   7,392 
Distribution  12,389   12,056   12,561   12,056 
Other (including coal mining and nuclear fuel)  3,479   3,445 
Other (including nuclear fuel and coal mining)  3,633   3,445 
Construction Work in Progress  3,257   3,019   3,516   3,019 
Total  47,451   46,145   48,392   46,145 
Accumulated Depreciation and Amortization  16,447   16,275   16,603   16,275 
TOTAL - NET  31,004   29,870   31,789   29,870 
                
OTHER NONCURRENT ASSETS                
Regulatory Assets  2,234   2,199   2,239   2,199 
Securitized Transition Assets  2,121   2,108   2,080   2,108 
Spent Nuclear Fuel and Decommissioning Trusts  1,362   1,347   1,292   1,347 
Goodwill  76   76   76   76 
Long-term Risk Management Assets  489   319   314   319 
Employee Benefits and Pension Assets  481   486   479   486 
Deferred Charges and Other  923   888   785   888 
TOTAL  7,686   7,423   7,265   7,423 
                
TOTAL ASSETS $42,696  $40,319  $43,038  $40,319 

See Condensed Notes to Condensed Consolidated Financial Statements.


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
JuneSeptember 30, 2008 and December 31, 2007
(Unaudited)

 2008  2007   2008  2007 
CURRENT LIABILITIESCURRENT LIABILITIES (in millions) CURRENT LIABILITIES (in millions) 
Accounts PayableAccounts Payable $1,414  $1,324 Accounts Payable $1,447  $1,324 
Short-term DebtShort-term Debt  705   660 Short-term Debt  1,302   660 
Long-term Debt Due Within One YearLong-term Debt Due Within One Year  569   792 Long-term Debt Due Within One Year  682   792 
Risk Management LiabilitiesRisk Management Liabilities  991   240 Risk Management Liabilities  330   240 
Customer DepositsCustomer Deposits  319   301 Customer Deposits  288   301 
Accrued TaxesAccrued Taxes  555   601 Accrued Taxes  564   601 
Accrued InterestAccrued Interest  256   235 Accrued Interest  235   235 
OtherOther  817   1,008 Other  874   1,008 
TOTALTOTAL  5,626   5,161 TOTAL  5,722   5,161 
                 
NONCURRENT LIABILITIESNONCURRENT LIABILITIES        NONCURRENT LIABILITIES        
Long-term DebtLong-term Debt  15,184   14,202 Long-term Debt  15,325   14,202 
Long-term Risk Management LiabilitiesLong-term Risk Management Liabilities  348   188 Long-term Risk Management Liabilities  165   188 
Deferred Income TaxesDeferred Income Taxes  5,021   4,730 Deferred Income Taxes  5,150   4,730 
Regulatory Liabilities and Deferred Investment Tax CreditsRegulatory Liabilities and Deferred Investment Tax Credits  2,895   2,952 Regulatory Liabilities and Deferred Investment Tax Credits  2,827   2,952 
Asset Retirement ObligationsAsset Retirement Obligations  1,081   1,075 Asset Retirement Obligations  1,090   1,075 
Employee Benefits and Pension ObligationsEmployee Benefits and Pension Obligations  677   712 Employee Benefits and Pension Obligations  672   712 
Deferred Gain on Sale and Leaseback – Rockport Plant Unit 2Deferred Gain on Sale and Leaseback – Rockport Plant Unit 2  134   139 Deferred Gain on Sale and Leaseback – Rockport Plant Unit 2  132   139 
Deferred Credits and OtherDeferred Credits and Other  1,038   1,020 Deferred Credits and Other  977   1,020 
TOTALTOTAL  26,378   25,018 TOTAL  26,338   25,018 
                 
TOTAL LIABILITIESTOTAL LIABILITIES  32,004   30,179 TOTAL LIABILITIES  32,060   30,179 
                 
Cumulative Preferred Stock Not Subject to Mandatory RedemptionCumulative Preferred Stock Not Subject to Mandatory Redemption  61   61 Cumulative Preferred Stock Not Subject to Mandatory Redemption  61   61 
                 
Commitments and Contingencies (Note 4)Commitments and Contingencies (Note 4)        Commitments and Contingencies (Note 4)        
                 
COMMON SHAREHOLDERS’ EQUITYCOMMON SHAREHOLDERS’ EQUITY        COMMON SHAREHOLDERS’ EQUITY        
Common Stock – $6.50 Par Value Per Share:Common Stock – $6.50 Par Value Per Share:        Common Stock – $6.50 Par Value Per Share:        
 2008  2007          2008  2007         
Shares Authorized  600,000,000   600,000,000           600,000,000   600,000,000         
Shares Issued  423,634,828   421,926,696           424,538,502   421,926,696         
(21,499,992 shares were held in treasury at June 30, 2008 and December 31, 2007, respectively)  2,754   2,743 
(21,499,992 shares were held in treasury at September 30, 2008 and December 31, 2007)(21,499,992 shares were held in treasury at September 30, 2008 and December 31, 2007)  2,760   2,743 
Paid-in CapitalPaid-in Capital  4,415   4,352 Paid-in Capital  4,444   4,352 
Retained EarningsRetained Earnings  3,651   3,138 Retained Earnings  3,861   3,138 
Accumulated Other Comprehensive Income (Loss)Accumulated Other Comprehensive Income (Loss)  (189)  (154)Accumulated Other Comprehensive Income (Loss)  (148)  (154)
TOTALTOTAL  10,631   10,079 TOTAL  10,917   10,079 
                 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITYTOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $42,696  $40,319 TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $43,038  $40,319 

See Condensed Notes to Condensed Consolidated Financial Statements.
 
See Condensed Notes to Condensed Consolidated Financial Statements.


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in millions)
(Unaudited)
 2008  2007  2008  2007 
OPERATING ACTIVITIES            
Net Income $854  $451  $1,228  $858 
Less: Discontinued Operations, Net of Tax  (1)  (2)   (1)  (2)
Income Before Discontinued Operations  853   449   1,227   856 
Adjustments to Reconcile Net Income to Net Cash Flow from Operating Activities:        
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization  736   763   1,123   1,144 
Deferred Income Taxes  316   (24)   397   44 
Deferred Investment Tax Credits  (10)  (13) 
Extraordinary Loss, Net of Tax  -   79   -   79 
Regulatory Provision  -   105 
Carrying Costs Income  (43)  (24)   (64)  (38)
Allowance for Equity Funds Used During Construction  (21)  (14)   (32)  (23)
Mark-to-Market of Risk Management Contracts  66   22   14   (7)
Amortization of Nuclear Fuel  45   33   72   48 
Deferred Property Taxes  36   24   136   118 
Fuel Over/Under-Recovery, Net  (245)  (101)   (284)  (133)
Gain on Sales of Assets and Equity Investments, Net  (8)  (26)   (14)  (28)
Change in Other Noncurrent Assets  (195)  (39)   (160)  (64)
Change in Other Noncurrent Liabilities  (80)  23   (74)  98 
Changes in Certain Components of Working Capital:                
Accounts Receivable, Net  (123)  (81)   (69)  (209)
Fuel, Materials and Supplies  (82)  (90)   (49)  (13)
Margin Deposits  (16)  32   (20)  39 
Accounts Payable  188   (58)   77   (54)
Customer Deposits  18   24   (14)  36 
Accrued Taxes, Net  (61)  49   (40)  (119)
Accrued Interest  16   67   (5)  22 
Other Current Assets  (13)  (21)   (43)  (33)
Other Current Liabilities  (180)  (210)   (125)  (133)
Net Cash Flows From Operating Activities  1,197   969 
Net Cash Flows from Operating Activities  2,053   1,630 
                
INVESTING ACTIVITIES                
Construction Expenditures  (1,608)  (1,823)   (2,576)  (2,595)
Change in Other Temporary Investments, Net  48   (129)   106   (50)
Purchases of Investment Securities  (635)  (6,827)   (1,386)  (8,632)
Sales of Investment Securities  666   7,035   912   8,849 
Acquisition of Nuclear Fuel  (99)  (30) 
Acquisition of Darby and Lawrenceburg Plants  -   (427) 
Acquisition of Other Assets  (81)  - 
Acquisitions of Nuclear Fuel  (99)  (73)
Acquisitions of Assets  (97)  (512)
Proceeds from Sales of Assets  69   74   83   78 
Other  (5)  -   (4)  - 
Net Cash Flows Used For Investing Activities  (1,645)  (2,127) 
Net Cash Flows Used for Investing Activities  (3,061)  (2,935)
                
FINANCING ACTIVITIES                
Issuance of Common Stock  72   90   106   116 
Issuance of Long-term Debt  2,561   1,924 
Change in Short-term Debt, Net  45   420   642   569 
Issuance of Long-term Debt  2,204   1,064 
Retirement of Long-term Debt  (1,472)  (190)   (1,582)  (870)
Principal Payments for Capital Lease Obligations  (76)  (49)
Dividends Paid on Common Stock  (330)  (311)   (494)  (467)
Other  (31)  (44)   11   (23)
Net Cash Flows From Financing Activities  488   1,029 
Net Cash Flows from Financing Activities  1,168   1,200 
                
Net Increase (Decrease) in Cash and Cash Equivalents  40   (129)   160   (105)
Cash and Cash Equivalents at Beginning of Period  178   301   178   301 
Cash and Cash Equivalents at End of Period $218  $172  $338  $196 
                
SUPPLEMENTARY INFORMATION                
Cash Paid for Interest, Net of Capitalized Amounts $412  $304  $657  $549 
Net Cash Paid for Income Taxes  131   128   126   363 
Noncash Acquisitions Under Capital Leases  35   23   47   59 
Noncash Acquisition of Land/Mineral Rights  42   -   42   - 
Construction Expenditures Included in Accounts Payable at June 30,  328   295 
Acquisition of Nuclear Fuel in Accounts Payable at June 30,  -   31 
Noncash Assumption of Liabilities Related to Acquisitions  -   5 
Construction Expenditures Included in Accounts Payable at September 30,  373   265 
Acquisition of Nuclear Fuel Included in Accounts Payable at September 30,  66   1 
Noncash Assumption of Liabilities Related to Acquisitions of Darby, Lawrenceburg and Dresden Plants  -   8 

See Condensed Notes to Condensed Consolidated Financial Statements.
 
See Condensed Notes to Condensed Consolidated Financial Statements.


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS’
EQUITY AND
COMPREHENSIVE INCOME (LOSS)
For the SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in millions)
(Unaudited)

 Common Stock     Accumulated Other Comprehensive Income (Loss)    Common Stock        Accumulated    
 Shares Amount Paid-in Capital Retained Earnings Total  Shares  Amount  Paid-in Capital  
Retained
Earnings
  Other Comprehensive Income (Loss)  Total 
DECEMBER 31, 2006DECEMBER 31, 2006 418 $2,718 $4,221 $2,696 $(223)$9,412   418  $2,718  $4,221  $2,696 ��$(223) $9,412 
FIN 48 Adoption, Net of TaxFIN 48 Adoption, Net of Tax       (17)   (17)              (17)      (17)
Issuance of Common StockIssuance of Common Stock 3 16 74     90   3   21   95           116 
Common Stock DividendsCommon Stock Dividends       (311)   (311)              (467)      (467)
OtherOther     10      10           12           12 
TOTALTOTAL            9,184                       9,056 
                                     
COMPREHENSIVE INCOMECOMPREHENSIVE INCOME                                     
Other Comprehensive Income (Loss), Net of Tax:Other Comprehensive Income (Loss), Net of Tax:                                     
Cash Flow Hedges, Net of Tax of $8         15 15 
Securities Available for Sale, Net of Tax of $3         (5) (5)
SFAS 158 Costs Established as a Regulatory Asset   for the Reapplication of SFAS 71, Net of Tax of   $6         11 11 
Cash Flow Hedges, Net of Tax of $6                  (11)  (11)
Securities Available for Sale, Net of Tax of $3                  (5)  (5)
SFAS 158 Costs Established as a Regulatory Asset Related to the Reapplication of SFAS 71, Net of Tax of $6                  11   11 
NET INCOMENET INCOME       451    451               858       858 
TOTAL COMPREHENSIVE INCOMETOTAL COMPREHENSIVE INCOME                 472                       853 
JUNE 30, 2007  421 $2,734 $4,305 $2,819 $(202)$9,656 
SEPTEMBER 30, 2007  421  $2,739  $4,328  $3,070  $(228) $9,909 
                                     
DECEMBER 31, 2007DECEMBER 31, 2007 422 $2,743 $4,352 $3,138 $(154)$10,079   422  $2,743  $4,352  $3,138  $(154) $10,079 
                                     
EITF 06-10 Adoption, Net of Tax of $6EITF 06-10 Adoption, Net of Tax of $6       (10)   (10)              (10)      (10)
SFAS 157 Adoption, Net of Tax of $0SFAS 157 Adoption, Net of Tax of $0       (1)   (1)              (1)      (1)
Issuance of Common StockIssuance of Common Stock 2 11 61     72   3   17   89           106 
Common Stock DividendsCommon Stock Dividends       (330)   (330)              (494)      (494)
OtherOther     2      2           3           3 
TOTALTOTAL            9,812                       9,683 
                                     
COMPREHENSIVE INCOMECOMPREHENSIVE INCOME                                     
Other Comprehensive Income, Net of Tax:             
Cash Flow Hedges, Net of Tax of $19         (34) (34)
Securities Available for Sale, Net of Tax of $4         (7) (7)
Amortization of Pension and OPEB Deferred Costs,
  Net of Tax of $3
         6 6 
Other Comprehensive Income (Loss), Net of Tax:                        
Cash Flow Hedges, Net of Tax of $4                  7   7 
Securities Available for Sale, Net of Tax of $5                  (10)  (10)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $5                  9   9 
NET INCOMENET INCOME       854    854               1,228       1,228 
TOTAL COMPREHENSIVE INCOMETOTAL COMPREHENSIVE INCOME                 819                       1,234 
JUNE 30, 2008  424 $2,754 $4,415 $3,651 $(189)$10,631 
SEPTEMBER 30, 2008  425  $2,760  $4,444  $3,861  $(148) $10,917 

See Condensed Notes to Condensed Consolidated Financial Statements.


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX TO CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

  
 1.Significant Accounting Matters
 2.New Accounting Pronouncements and Extraordinary Item
3.Rate Matters
 4.Commitments, Guarantees and Contingencies
5.Acquisitions, Dispositions and Discontinued Operations
6.Benefit Plans
7.Business Segments
8.Income Taxes
9.Financing Activities
10.Subsequent Event


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1.SIGNIFICANT ACCOUNTING MATTERS

General

The accompanying 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 interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our results of operations,net income, financial position and cash flows for the interim periods.  The results of operationsnet income for the three and sixnine months ended JuneSeptember 30, 2008 are not necessarily indicative of results that may be expected for the year ending December 31, 2008.  The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2007 consolidated financial statements and notes thereto, which are included in our Annual Report on Form 10-K for the year ended December 31, 2007 as filed with the SEC on February 28, 2008.

Earnings Per Share

The following table presents our basic and diluted EPS calculations included on our Condensed Consolidated Statements of Income:
 Three Months Ended June 30,  Three Months Ended September 30, 
 2008  2007  2008  2007 
 (in millions, except per share data)  (in millions, except per share data) 
    $/share     $/share     $/share     $/share 
Earnings Applicable to Common Stock $281     $180     $374     $407    
                            
Average Number of Basic Shares Outstanding  401.5  $0.70   398.7  $0.45   402.3  $0.93   399.2  $1.02 
Average Dilutive Effect of:                                
Performance Share Units  0.9   -   0.6   -   1.3   -   0.5   - 
Stock Options  0.2   -   0.4   -   0.1   -   0.3   - 
Restricted Stock Units  0.1   -   0.1   -   0.1   -   0.1   - 
Restricted Shares  0.1   -   0.1   -   0.1   -   0.1   - 
Average Number of Diluted Shares Outstanding  402.8  $0.70   399.9  $0.45   403.9  $0.93   400.2  $1.02 

 Six Months Ended June 30,  Nine Months Ended September 30, 
 2008  2007  2008  2007 
 (in millions, except per share data)  (in millions, except per share data) 
    $/share     $/share     $/share     $/share 
Earnings Applicable to Common Stock $854     $451     $1,228     $858    
                            
Average Number of Basic Shares Outstanding  401.2  $2.13   398.0  $1.13   401.5  $3.06   398.4  $2.15 
Average Dilutive Effect of:                                
Performance Share Units  0.8   (0.01)  0.6   -   1.0   (0.01)  0.6   - 
Stock Options  0.2   -   0.4   -   0.2   -   0.4   - 
Restricted Stock Units  0.1   -   0.1   -   0.1   -   0.1   - 
Restricted Shares  0.1   -   0.1   -   0.1   -   0.1   - 
Average Number of Diluted Shares Outstanding  402.4  $2.12   399.2  $1.13   402.9  $3.05   399.6  $2.15 

The assumed conversion of our share-based compensation does not affect net earnings for purposes of calculating diluted earnings per share.

Options to purchase 146,900 and 83,45083,550 shares of common stock were outstanding at JuneSeptember 30, 2008 and 2007, respectively, but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the quarter-end market price of the common shares and, therefore, the effect would be antidilutive.

Supplementary Information

 
Three Months Ended
June 30,
  
Six Months Ended
June 30,
  
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
 
 2008  2007  2008  2007  2008  2007  2008  2007 
Related Party Transactions (in millions)  (in millions)  (in millions)  (in millions) 
AEP Consolidated Revenues – Utility Operations:                        
Power Pool Purchases – Ohio Valley Electric Corporation
(43.47% owned)
 $(13) $(4) $(25) $(4) $(14) $(12) $(40) $(16)
AEP Consolidated Revenues – Other:                                
Ohio Valley Electric Corporation – Barging and Other
Transportation Services (43.47% Owned)
  5   8   14   17   7   7   21   24 
AEP Consolidated Expenses – Purchased Energy for Resale:                                
Ohio Valley Electric Corporation (43.47% Owned)  61   56   124   105   70   59   194   164 
Sweeny Cogeneration Limited Partnership (a)  -   29   -   59   -   27   -   86 

(a)In October 2007, we sold our 50% ownership in the Sweeny Cogeneration Limited Partnership.

Reclassifications

Certain prior period financial statement items have been reclassified to conform to current period presentation.  See “FSP FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1)” section of Note 2 for discussion of changes in netting certain balance sheet amounts.  These reclassifications had no impact on our previously reported results of operationsnet income or changes in shareholders’ equity.

2.NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM

NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of final pronouncements, we thoroughly review the new accounting literature to determine the relevance, if any, to our business.  The following represents a summary of new pronouncements issued or implemented in 2008 and standards issued but not implemented that we have determined relate to our operations.

SFAS 141 (revised 2007) “Business Combinations” (SFAS 141R)

In December 2007, the FASB issued SFAS 141R, improving financial reporting about business combinations and their effects.  It establishes how the acquiring entity recognizes and measures the identifiable assets acquired, liabilities assumed, goodwill acquired, any gain on bargain purchases and any noncontrolling interest in the acquired entity.  SFAS 141R no longer allows acquisition-related costs to be included in the cost of the business combination, but rather expensed in the periods they are incurred, with the exception of the costs to issue debt or equity securities which shall be recognized in accordance with other applicable GAAP.  SFAS 141R requires disclosure of information for a business combination that occurs during the accounting period or prior to the issuance of the financial statements for the accounting period.

SFAS 141R is effective prospectively for business combinations with an acquisition date on or after the beginning of the first annual reporting period after December 15, 2008.  Early adoption is prohibited.  We will adopt SFAS 141R effective January 1, 2009 and apply it to any business combinations on or after that date.

SFAS 157 “Fair Value Measurements” (SFAS 157)

In September 2006, the FASB issued SFAS 157, enhancing existing guidance for fair value measurement of assets and liabilities and instruments measured at fair value that are classified in shareholders’ equity.  The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures.  It emphasizes that fair value is market-based with the highest measurement hierarchy level being market prices in active markets.  The standard requires fair value measurements be disclosed by hierarchy level, an entity includes its own credit standing in the measurement of its liabilities and modifies the transaction price presumption.  The standard also nullifies the consensus reached in EITF Issue No. 02-3 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3) that prohibited the recognition of trading gains or losses at the inception of a derivative contract, unless the fair value of such derivative is supported by observable market data.

In February 2008, the FASB issued FSP SFAS 157-1 “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” (SFAS 157-1) which amends SFAS 157 to exclude SFAS 13 “Accounting for Leases” (SFAS 13) and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under SFAS 13.

In February 2008, the FASB issued FSP SFAS 157-2 “Effective Date of FASB Statement No. 157” (SFAS 157-2) which delays the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).

In October 2008, the FASB issued FSP SFAS 157-3 “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active” which clarifies application of SFAS 157 in markets that are not active and provides an illustrative example.  The FSP was effective upon issuance.  The adoption of this standard had no impact on our financial statements.

We partially adopted SFAS 157 effective January 1, 2008.  We will fully adopt SFAS 157 effective January 1, 2009 for items within the scope of FSP SFAS 157-2.  We expect that the adoption of FSP SFAS 157-2 will have an immaterial impact on our financial statements.  The provisions of SFAS 157 are applied prospectively, except for a) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF 02-3, b) existing hybrid financial instruments measured initially at fair value using the transaction price and c) blockage discount factors.  Although the statement is applied prospectively upon adoption, in accordance with the provisions of SFAS 157 related to EITF 02-3, we recorded an immaterial transition adjustment to beginning retained earnings.  The impact of considering our own credit risk when measuring the fair value of liabilities, including derivatives, had an immaterial impact on fair value measurements upon adoption.

In accordance with SFAS 157, assets and liabilities are classified based on the inputs utilized in the fair value measurement.  SFAS 157 provides definitions for two types of inputs: observable and unobservable.  Observable inputs are valuation inputs that reflect the assumptions market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the reporting entity.  Unobservable inputs are valuation inputs that reflect the reporting entity’s own assumptions about the assumptions market participants would use in pricing the asset or liability developed based on the best information in the circumstances.

As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). SFAS 157 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).

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, listed equities and U.S. government treasury securities that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.

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, OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market and certain non-exchange-traded debt securities.

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.

Risk Management Contracts include exchange traded, OTC and bilaterally executed derivative contracts.  Exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified within level 1.  Other actively traded derivativesderivative fair values are valuedverified using broker or dealer quotations, similar observable market transactions in either the listed or OTC markets, or throughvalued using pricing models  where significant valuation inputs are directly or indirectly observable in active markets.  Derivative instruments, primarily swaps, forwards, and options that meet these characteristics are classified within level 2.  Bilaterally executed agreements are derivative contracts entered into directly with third parties, and at times these instruments may be complex structured transactions that are tailored to meet the specific customer’s energy requirements.  Structured transactions utilize pricing models that are widely accepted in the energy industry to measure fair value.  Generally, we use a consistent modeling approach to value similar instruments.  Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data), and other observable inputs for the asset or liability.  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in level 2.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  In addition, long-dated and illiquid complex or structured transactions or 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 in level 3.  In certain instances, the fair values of the transactions that use internally developed model inputs, classified as level 3 are offset partially or in full, by transactions included in level 2 where observable market data exists for the offsetting transaction.

The following table sets 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 JuneSeptember 30, 2008.  As required by SFAS 157, 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.

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of June 30, 2008 
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of September 30, 2008Assets and Liabilities Measured at Fair Value on a Recurring Basis as of September 30, 2008 
 Level 1  Level 2  Level 3  Other  Total  Level 1  Level 2  Level 3  Other  Total 
Assets: (in millions)  (in millions) 
                              
Cash and Cash Equivalents (a) $167  $-  $-  $51  $218  $271  $-  $-  $67  $338 
Other Temporary Investments:
                                        
Cash and Cash Equivalents (b) $188  $-  $-  $39  $227  $147  $-  $-  $22  $169 
Equity Securities  16   -   -   -   16 
Debt Securities (c)  -   490   -   -   490 
Equity Securities (d)  11   -   -   -   11 
Total Other Temporary Investments $204  $-  $-  $39  $243  $158  $490  $-  $22  $670 
                                        
Risk Management Assets:                                        
Risk Management Contracts (c) $375  $5,660  $143  $(4,892) $1,286 
Cash Flow and Fair Value Hedges (c)  -   65   -   (17)  48 
Dedesignated Risk Management Contracts (d)  -   -   -   46   46 
Risk Management Contracts (e) $41  $2,423  $75  $(1,959) $580 
Cash Flow and Fair Value Hedges (e)  9   37   -   (15)  31 
Dedesignated Risk Management Contracts (f)  -   -   -   43   43 
Total Risk Management Assets $375  $5,725  $143  $(4,863) $1,380  $50  $2,460  $75  $(1,931) $654 
                                        
Spent Nuclear Fuel and Decommissioning Trusts:                                        
Cash and Cash Equivalents (e) $-  $17  $-  $12  $29 
Debt Securities  326   508   -   -   834 
Equity Securities  499   -   -   -   499 
Cash and Cash Equivalents (g) $-  $4  $-  $6  $10 
Debt Securities (h)  -   837   -   -   837 
Equity Securities (d)  445   -   -   -   445 
Total Spent Nuclear Fuel and Decommissioning Trusts $825  $525  $-  $12  $1,362  $445  $841  $-  $6  $1,292 
                                        
Total Assets $1,571  $6,250  $143  $(4,761) $3,203  $924  $3,791  $75  $(1,836) $2,954 
                                        
Liabilities:                                        
                                        
Risk Management Liabilities:                                        
Risk Management Contracts (c) $405  $5,508  $151  $(4,831) $1,233 
Cash Flow and Fair Value Hedges (c)  8   115   -   (17)  106 
Risk Management Contracts (e) $52  $2,279  $68  $(1,926) $473 
Cash Flow and Fair Value Hedges (e)  -   37   -   (15)  22 
Total Risk Management Liabilities $413  $5,623  $151  $(4,848) $1,339  $52  $2,316  $68  $(1,941) $495 

(a)Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions.  Level 1 amounts primarily represent investments in money market funds.
(b)Amounts in “Other” column primarily represent cash deposits with third parties.  Level 1 amounts primarily represent investments in money market funds.
(c)Amounts represent Variable Rate Demand Notes.
(d)Amounts represent publicly traded equity securities.
(e)Amounts in “Other” column primarily represent counterparty netting of risk management contracts and associated cash collateral under FSP FIN 39-1.
(d)(f)“Dedesignated Risk Management Contracts” are contracts that were originally MTM but were subsequently elected as normal under SFAS 133.  At the time of the normal election, the MTM value was frozen and no longer fair valued.  This will be amortized into Utility Operations Revenues over the remaining life of the contract.
(e)(g)Amounts in “Other” column primarily represent accrued interest receivables to/from financial institutions.  Level 2 amounts primarily represent investments in money market funds.
(h)Amounts represent corporate, municipal and treasury bonds.

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:

Three Months Ended June 30, 2008 Net Risk Management Assets (Liabilities)  Other Temporary Investments  Investments in Debt Securities 
  (in millions) 
Balance as of April 1, 2008 $49  $22  $17 
Realized (Gain) Loss Included in Earnings (or Changes in Net Assets) (a)  (2)  -   - 
Unrealized Gain (Loss) Included in Earnings (or Changes in Net Assets)   
  Relating to Assets Still Held at the Reporting Date (a)
  (1)  -   - 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive   
  Income
  -   -   - 
Purchases, Issuances and Settlements  -   (22)  (17) 
Transfers in and/or out of Level 3 (b)  (8)  -   - 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)  (46)  -   - 
Balance as of June 30, 2008 $(8) $-  $- 
Three Months Ended September 30, 2008Net Risk Management Assets (Liabilities)Other Temporary InvestmentsInvestments in Debt Securities
(in millions)
Balance as of July 1, 2008$(8)$-$-
Realized (Gain) Loss Included in Earnings (or Changes in Net Assets) (a)17--
Unrealized Gain (Loss) Included in Earnings (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---
Transfers in and/or out of Level 3 (b)(10)--
Changes in Fair Value Allocated to Regulated Jurisdictions (c)15--
Balance as of September 30, 2008$7$-$-

Six Months Ended June 30, 2008 Net Risk Management Assets (Liabilities)  Other Temporary Investments  Investments in Debt Securities 
Nine Months Ended September 30, 2008 Net Risk Management Assets (Liabilities)  Other Temporary Investments  Investments in Debt Securities 
 (in millions)  (in millions) 
Balance as of January 1, 2008 $49  $-  $-  $49  $-  $- 
Realized (Gain) Loss Included in Earnings (or Changes in Net Assets) (a)  (2)  -   -   -   -   - 
Unrealized Gain (Loss) Included in Earnings (or Changes in Net Assets)
Relating to Assets Still Held at the Reporting Date (a)
  (3)  -   -   4   -   - 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive
Income
  -   -   -   -   -   - 
Purchases, Issuances and Settlements  -   (118)  (17)   -   (118)  (17)
Transfers in and/or out of Level 3 (b)  (1)  118   17   (35)  118   17 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)  (51)  -   -   (11)  -   - 
Balance as of June 30, 2008 $(8) $-  $- 
Balance as of September 30, 2008 $7  $-  $- 

(a)Included in revenues on our Condensed Consolidated StatementStatements of Income.
(b)“Transfers in and/or out of Level 3” represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.
(c)“Changes in Fair Value Allocated to Regulated Jurisdictions” 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 assets/liabilities for those subsidiaries that operate in regulated jurisdictions.liabilities.

SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159)

In February 2007, the FASB issued SFAS 159, permitting entities to choose to measure many financial instruments and certain other items at fair value.  The standard also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities.  If the fair value option is elected, the effect of the first remeasurement to fair value is reported as a cumulative effect adjustment to the opening balance of retained earnings.  The statement is applied prospectively upon adoption.

We adopted SFAS 159 effective January 1, 2008.  At adoption, we did not elect the fair value option for any assets or liabilities.
 
SFAS 160 “Noncontrolling Interest in Consolidated Financial Statements” (SFAS 160)

In December 2007, the FASB issued SFAS 160, modifying reporting for noncontrolling interest (minority interest) in consolidated financial statements.  It requires noncontrolling interest be reported in equity and establishes a new framework for recognizing net income or loss and comprehensive income by the controlling interest.  Upon deconsolidation due to loss of control over a subsidiary, the standard requires a fair value remeasurement of any remaining noncontrolling equity investment to be used to properly recognize the gain or loss.  SFAS 160 requires specific disclosures regarding changes in equity interest of both the controlling and noncontrolling parties and presentation of the noncontrolling equity balance and income or loss for all periods presented.

SFAS 160 is effective for interim and annual periods in fiscal years beginning after December 15, 2008.  The statement is applied prospectively upon adoption.  Early adoption is prohibited.  Upon adoption, prior period financial statements will be restated for the presentation of the noncontrolling interest for comparability.  Although we have not completed our analysis, weWe expect that the adoption of this standard will have an immaterial impact on our financial statements.  We will adopt SFAS 160 effective January 1, 2009.

SFAS 161 “Disclosures about Derivative Instruments and Hedging Activities” (SFAS 161)

In March 2008, the FASB issued SFAS 161, enhancing disclosure requirements for derivative instruments and hedging activities.  Affected entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.  SFAS 161 requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation.  This standard is intended to improve upon the existing disclosure framework in SFAS 133.

SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008.  We expect this standard to increase our disclosure requirements related to derivative instruments and hedging activities.  It encourages retrospective application to comparative disclosure for earlier periods presented.  We will adopt SFAS 161 effective January 1, 2009.

SFAS 162 “The Hierarchy of Generally Accepted Accounting Principles” (SFAS 162)

In May 2008, the FASB issued SFAS 162, clarifying the sources of generally accepted accounting principles in descending order of authority.  The statement specifies that the reporting entity, not its auditors, is responsible for its compliance with GAAP.

SFAS 162 is effective 60 days after the SEC approves the Public Company Accounting Oversight Board’s amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.”  We expect the adoption of this standard will have no impact on our financial statements.  We will adopt SFAS 162 when it becomes effective.

EITF Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements” (EITF 06-10)

In March 2007, the FASB ratified EITF 06-10, a consensus on collateral assignment split-dollar life insurance arrangements in which an employee owns and controls the insurance policy.  Under EITF 06-10, an employer should recognize a liability for the postretirement benefit related to a collateral assignment split-dollar life insurance arrangement in accordance with SFAS 106 “Employers' Accounting for Postretirement Benefits Other Than Pension” or Accounting Principles Board Opinion No. 12 “Omnibus Opinion – 1967” if the employer has agreed to maintain a life insurance policy during the employee's retirement or to provide the employee with a death benefit based on a substantive arrangement with the employee.  In addition, an employer should recognize and measure an asset based on the nature and substance of the collateral assignment split-dollar life insurance arrangement.  EITF 06-10 requires recognition of the effects of its application as either (a) a change in accounting principle through a cumulative effect adjustment to retained earnings or other components of equity or net assets in the statement of financial position at the beginning of the year of adoption or (b) a change in accounting principle through retrospective application to all prior periods.  We adopted EITF 06-10 effective January 1, 2008 with a cumulative effect reduction of $16 million ($10 million, net of tax) to beginning retained earnings.

EITF Issue No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards” (EITF 06-11)

In June 2007, the FASB ratified the EITF consensus on the treatment of income tax benefits of dividends on employee share-based compensation.  The issue is how a company should recognize the income tax benefit received on dividends that are paid to employees holding equity-classified nonvested shares, equity-classified nonvested share units or equity-classified outstanding share options and charged to retained earnings under SFAS 123R, “Share-Based Payments.”  Under EITF 06-11, a realized income tax benefit from dividends or dividend equivalents that are charged to retained earnings and are paid to employees for equity-classified nonvested equity shares, nonvested equity share units and outstanding equity share options should be recognized as an increase to additional paid-in capital.  EITF 06-11 is applied prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years after December 15, 2007.

We adopted EITF 06-11 effective January 1, 2008.  The adoption of this standard had an immaterial impact on our financial statements.
EITF Issue No. 08-5 “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (EITF 08-5)
In September 2008, the FASB ratified the EITF consensus on liabilities with third-party credit enhancements when the liability is measured and disclosed at fair value.  The consensus treats the liability and the credit enhancement as two units of accounting.  Under the consensus, the fair value measurement of the liability does not include the effect of the third-party credit enhancement.  Consequently, changes in the issuer’s credit standing without the support of the credit enhancement affect the fair value measurement of the issuer’s liability.  Entities will need to provide disclosures about the existence of any third-party credit enhancements related to their liabilities.

EITF 08-5 is effective for the first reporting period beginning after December 15, 2008.  It will be applied prospectively upon adoption with the effect of initial application included as a change in fair value of the liability in the period of adoption.  In the period of adoption, entities must disclose the valuation method(s) used to measure the fair value of liabilities within its scope and any change in the fair value measurement method that occurs as a result of its initial application.  Early adoption is permitted.  Although we have not completed our analysis, we expect that the adoption of this standard will have an immaterial impact on our financial statements.  We will adopt this standard effective January 1, 2009.

FSP EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (EITF  03-6-1)

In June 2008, the FASB issued EITF 03-6-1 addressing whether instruments granted in share-based payment transactions are participating securities prior to vesting and need to be included in earnings allocation in computing EPS under the two-class method described in SFAS 128 “Earnings per Share.”

EITF 03-6-1 is effective for interim and annual periods in fiscal years beginning after December 15, 2008.  The statement is applied retrospectively upon adoption.  Early adoption is prohibited.  Upon adoption, prior period financial statements will be restated for comparability.  Although we have not completed our analysis, we expect that the adoption of this standard will have an immaterial impact on our financial statements.  We will adopt EITF 03-6-1 effective January 1, 2009.

FSP SFAS 133-1 and FIN 45-4 “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment
    of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of
    FASB Statement No. 161” (SFAS 133-1 and FIN 45-4)

In September 2008, the FASB issued SFAS 133-1 and FIN 45-4 as amendments to original statements SFAS 133 and FIN 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” Under the SFAS 133 requirements, the seller of a credit derivative shall disclose the following information for each derivative, including credit derivatives embedded in a hybrid instrument, even if the likelihood of payment is remote:

(a)The nature of the credit derivative.
(b)The maximum potential amount of future payments.
(c)The fair value of the credit derivative.
(d)The nature of any recourse provisions and any assets held as collateral or by third parties.

Further, the standard requires the disclosure of current payment status/performance risk of all FIN 45 guarantees.  In the event an entity uses internal groupings, the entity shall disclose how those groupings are determined and used for managing risk.

The standard is effective for interim and annual reporting periods ending after November 15, 2008.  Upon adoption, the guidance will be prospectively applied.  We expect that the adoption of this standard will have an immaterial impact on our financial statements but increase our FIN 45 guarantees disclosure requirements.  We will adopt the standard effective December 31, 2008.

FSP SFAS 142-3 “Determination of the Useful Life of Intangible Assets” (SFAS 142-3)

In April 2008, the FASB issued SFAS 142-3 amending factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS 142, “Goodwill and Other Intangible Assets.”  The standard is expected to improve consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure its fair value.

SFAS 142-3 is effective for interim and annual periods in fiscal years beginning after December 15, 2008.  Early adoption is prohibited.  Upon adoption, the guidance within SFAS 142-3 will be prospectively applied to intangible assets acquired after the effective date.  We expect that the adoption of this standard will have an immaterial impact on our financial statements.  We will adopt SFAS 142-3 effective January 1, 2009.

FSP FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1)

In April 2007, the FASB issued FIN 39-1.  It amends FASB Interpretation No. 39 “Offsetting of Amounts Related to Certain Contracts” by replacing the interpretation’s definition of contracts with the definition of derivative instruments per SFAS 133.  It also requires entities that offset fair values of derivatives with the same party under a netting agreement to net the fair values (or approximate fair values) of related cash collateral.  The entities must disclose whether or not they offset fair values of derivatives and related cash collateral and amounts recognized for cash collateral payables and receivables at the end of each reporting period.

We adopted FIN 39-1 effective January 1, 2008.  This standard changed our method of netting certain balance sheet amounts and reduced assets and liabilities.  It requires retrospective application as a change in accounting principle.  Consequently, we reclassified the following amounts on the December 31, 2007 Condensed Consolidated Balance Sheet as shown:

Balance Sheet
Line Description
 
As Reported for
the December 2007 10-K
  
FIN 39-1
Reclassification
  
As Reported for
the June
2008 10-Q
  
As Reported for
the December 2007 10-K
  
FIN 39-1
Reclassification
  
As Reported for
the September 2008 10-Q
 
Current Assets: (in millions)  (in millions) 
Risk Management Assets $286  $(15) $271  $286  $(15) $271 
Margin Deposits  58   (11)  47   58   (11)  47 
Long-term Risk Management Assets  340   (21)  319   340   (21)  319 
                        
Current Liabilities:                        
Risk Management Liabilities  250   (10)  240   250   (10)  240 
Customer Deposits  337   (36)  301   337   (36)  301 
Long-term Risk Management Liabilities  189   (1)  188   189   (1)  188 

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 JuneSeptember 30, 2008 balance sheet, we netted $182$50 million of cash collateral received from third parties against short-term and long-term risk management assets and $121$17 million of cash collateral paid to third parties against short-term and long-term risk management liabilities.

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued by the FASB, 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, contingencies, liabilities and equity, emission allowances, earnings per share calculations, leases, hedge accounting, consolidation policy, trading inventory and related tax impacts.  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 results of operationsnet income and financial position.

EXTRAORDINARY ITEM

In April 2007, Virginia passed legislation to reestablish regulation for retail generation and supply of electricity.  As a result, we recorded an extraordinary loss of $118 million ($79 million, net of tax) during the second quarter of 2007 for the reestablishment of regulatory assets and liabilities related to our Virginia retail generation and supply operations.  In 2000, we discontinued SFAS 71 regulatory accounting in our Virginia jurisdiction for retail generation and supply operations due to the passage of legislation for customer choice and deregulation.

3.RATE MATTERS

As discussed in the 2007 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within our 2007 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact results of operations,net income, cash flows and possibly financial condition.  The following discusses ratemaking developments in 2008 and updates the 2007 Annual Report.

Ohio Rate Matters

Ohio Electric Security Plan Filings

In April 2008, the Ohio legislature passed Senate Bill 221, which amends the restructuring law effective July 31, 2008 and requires electric utilities to adjust their rates by filing an Electric Security Plan (ESP).  Electric utilities may file an ESP with a fuel cost recovery mechanism.  Electric utilities also have an option to file a Market Rate Offer (MRO) for generation pricing.  A MRO, from the date of its commencement, could transition CSPCo and OPCo to full market rates no sooner than six years and no later than ten years.years after the PUCO approves a MRO.  The PUCO has the authority to approve or modify theeach utilities’ ESP request.  The PUCO is required to approve an ESP if, in the aggregate, the ESP is more favorable to ratepayers than thea MRO.  Both alternatives involve a “substantially excessive earnings” test based on what public companies, including other utilities with similar risk profiles, earn on equity.  Management has preliminarily concluded, pending the issuance of final rules by the PUCO and the outcome of the ESP proceeding, that CSPCo’s and OPCo’s generation/supply operations are not subject to cost-based rate regulation accounting.  However, if a fuel cost recovery mechanism is implemented within the ESP, CSPCo’s and OPCo’s fuel and purchased power operations would be subject to cost-based rate regulation accounting.  Management is unable to predict the financial statement impact of the restructuring legislation until the PUCO acts on specific proposals made by CSPCo and OPCo in their ESPs.

In July 2008, within the parameters of the ESPs, CSPCo and OPCo filed with the PUCO to establish rates for 2009 through 2011.  CSPCo and OPCo did not file MROs.  an optional MRO.  CSPCo and OPCo each requested an annual rate increase for 2009 through 2011 that would not exceed approximately 15% per year.  A significant portion of the requested increases results from the implementation of a fuel cost recovery mechanism (which excludes off-system sales) that primarily includes fuel costs, purchased power costs including mandated renewable energy, consumables such as urea, other variable production costs and gains and losses on sales of emission allowances.  The increases in customer bills related to the fuelfuel-purchased power cost recovery mechanism would be phased-in over the three year period from 2009 through 2011.  EffectiveIf the ESP is approved as filed, effective with January 1, 2009 billings, CSPCo and OPCo will defer theany fuel cost under-recoveries and related carrying costs for future recoveryrecovery.  The under-recoveries and related carrying costs that exist at the end of 2011 will be recovered over seven years from 2012 through 2018.  In addition to the fuel cost recovery mechanisms, the requested increases would also recover incremental carrying costs associated with environmental costs, Provider of Last Resort (POLR) charges to compensate for the risk of customers changing electric suppliers, automatic increases for unexpecteddistribution reliability costs and reliabilityfor unexpected non-fuel generation costs.  The filings also include programs for smart metering initiatives and economic development and mandated energy efficiency and peak demand reduction programs.  Management expectsIn September 2008, the PUCO issued a finding and order tentatively adopting rules governing MRO and ESP applications.  CSPCo and OPCo filed their ESP applications based on proposed rules and requested waivers for portions of the proposed rules.  The PUCO decision ondenied the ESP filingswaiver requests in September 2008 and ordered CSPCo and OPCo to submit information consistent with the fourth quartertentative rules.  In October 2008, CSPCo and OPCo submitted additional information related to proforma financial statements and information concerning CSPCo and OPCo’s fuel procurement process.  In October 2008, CSPCo and OPCo filed an application for rehearing with the PUCO to challenge certain aspects of 2008.the proposed rules.

Within the ESPs, CSPCo and OPCo would also recover existing regulatory assets of $45$46 million and $36$38 million, respectively, for customer choice implementation and line extension carrying costs.  In addition, CSPCo and OPCo would recover related unrecorded equity carrying costs of $28$30 million and $19$21 million, respectively.  Such costs would be recovered over an 8 year8-year period beginning January 2011.  Hearings are scheduled for November 2008 and an order is expected in the fourth quarter of 2008.  If an order is not received prior to January 1, 2009, CSPCo and OPCo have requested retroactive application of the new rates back to January 1, 2009 upon approval.  Failure of the PUCO to ultimately approve the recovery of the regulatory assets would have an adverse effect on future results of operationsnet income and cash flows.

2008 Generation Rider and Transmission Rider Rate Settlement

On January 30, 2008, the PUCO approved a settlement agreement, among CSPCo, OPCo and other parties, under the additional average 4% generation rate increase and transmission cost recovery rider (“TCRR”)(TCRR) provisions of the RSP.  The increase was to recover additional governmentally-mandated costs including incremental environmental costs.  Under the settlement, the PUCO also approved recovery through the TCRR of increased PJM costs associated with transmission line losses of $39 million each for CSPCo and OPCo.  As a result, CSPCo and OPCo established regulatory assets induring the first quarter of 2008 of $12 million and $14 million, respectively, related to the future recovery of increased PJM billings previously expensed from June 2007 to December 2007.2007 for transmission line losses.  The PUCO also approved a credit applied to the TCRR of $10 million for OPCo and $8 million for CSPCo for a reduction in PJM net congestion costs.  To the extent that collections for the TCRR itemsrecoveries are over/underunder/over actual net costs, CSPCo and OPCo will defer the difference as a regulatory asset or regulatory liability and adjust future customer billings to reflect actual costs, including carrying costs on the unrecovered deferral.  Under the terms of the settlement, although the increased PJM costs associated with transmission line losses will be recovered through the TCRR, these recoveries will still be applied to reduce the annual average 4% generation rate increase limitation.  In addition, the PUCO approved recoveries through generation rates of environmental costs and related carrying costs of $29 million for CSPCo and $5 million for OPCo.  These RSP rate adjustments were implemented in February 2008.

InAlso, in February 2008, Ormet, a major industrial customer, filed a motion to intervene and an application for rehearing of the PUCO’s January 2008 RSP order claiming the settlement inappropriately shifted $4 million in cost recovery to Ormet.  In March 2008, the PUCO granted Ormet’s motion to intervene.  Ormet’s rehearing application also was granted for the purpose of providing the PUCO with additional time to consider the issues raised by Ormet.  Management cannot predictUpon PUCO approval of an unrelated amendment to the outcome of thisOrmet contract, Ormet withdrew its rehearing process.application in August 2008.

Ohio IGCC Plant

In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs related to building and operating a 629 MW IGCC power plant using clean-coal technology.  The application proposed three phases of cost recovery associated with the IGCC plant:  Phase 1, recovery of $24 million in pre-construction costs; Phase 2, concurrent recovery of construction-financing costs; and Phase 3, recovery or refund in distribution rates of any difference between the generation rates which may be a market-based standard service offer price for generation and the expected higher cost of operating and maintaining the plant, including a return on and return of the projected cost to construct the plant.

In June 2006, the PUCO issued an order approving a tariff to allow CSPCo and OPCo to recover Phase 1 pre-construction costs over a period of no more than twelve months effective July 1, 2006.  During that period CSPCo and OPCo each collected $12 million in pre-construction costs and incurred $11 million in pre-construction costs.  As a result, CSPCo and OPCo each established a net regulatory liability of approximately $1 million.

The order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant within five years of the June 2006 PUCO order, all Phase 1 costscost recoveries associated with items that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest.  The PUCO deferred ruling on cost recovery for Phases 2 and 3 pending further hearings.

In August 2006, intervenors filed four separate appeals of the PUCO’s order in the IGCC proceeding.  In March 2008, the Ohio Supreme Court issued its opinion affirming in part, and reversing in part the PUCO’s order and remanded the matter back to the PUCO.  The Ohio Supreme Court held that while there could be an opportunity under existing law to recover a portion of the IGCC costs in distribution rates, traditional rate making procedures would apply to the recoverable portion.  The Ohio Supreme Court did not address the matter of refunding the Phase 1 cost recovery and declined to create an exception to its precedent of denying claims for refund of past recoveries from approved orders of the PUCO.

Recent estimates of  In September 2008, the costOhio Consumers’ Counsel filed a motion with the PUCO requesting all Phase 1 costs be refunded to build the proposed IGCC plant are approximately $2.7 billion.  Management continues to pursue the ultimate construction of the IGCC plant.  However, in light ofOhio ratepayers with interest because the Ohio Supreme Court’s decision,Court invalidated the underlying foundation for the Phase 1 recovery.  CSPCo and OPCo will not start construction offiled a motion with the IGCC plant until sufficient assurance of cost recovery exists.PUCO that argued the Ohio Consumers’ Counsel’s motion was without legal merit and contrary to past precedent.  If CSPCo and OPCo were required to refund the $24 million collected and those costs were not recoverable in another jurisdiction in connection with the construction of an IGCC plant, it would have an adverse effect on future results of operationsnet income and cash flows.

As of December 31, 2007, the cost of the plant was estimated at $2.7 billion.  The estimated cost of the plant has continued to increase significantly.  Management continues to pursue the ultimate construction of the IGCC plant.  CSPCo and OPCo will not start construction of the IGCC plant until sufficient assurance of regulatory cost recovery exists.

Ormet

Effective January 1, 2007, CSPCo and OPCo began to serve Ormet, a major industrial customer with a 520 MW load, in accordance with a settlement agreement approved by the PUCO.  The settlement agreement allows for the recovery in 2007 and 2008 of the difference between the $43 per MWH Ormet pays for power and a PUCO-approved market price, if higher.  The PUCO approved a $47.69 per MWH market price for 2007 and the difference was recovered through the amortization of a $57 million ($15 million for CSPCo and $42 million for OPCo) excess deferred tax regulatory liability resulting from an Ohio franchise tax phase-out recorded in 2005.

CSPCo and OPCo each amortized $5$8 million of this regulatory liability to income for the sixnine months ended JuneSeptember 30, 2008 based on the previously approved 2007 price of $47.69 per MWH.  In December 2007, CSPCo and OPCo submitted for approval a market price of $53.03 per MWH for 2008.  The PUCO has not yet approved the increase.2008 market price.  If the PUCO approves a market price for 2008 below $47.69, it could have an adverse effect on future results of operationsnet income and cash flows.  A price above $47.69 should result in a favorable effect.  If CSPCo and OPCo serve the Ormet load after 2008 without any special provisions, they could experience incremental costs to acquire additional capacity to meet their reserve requirements and/or forgo more profitable market pricedmarket-priced off-system sales.

Hurricane Ike

In September 2008, the service territories of CSPCo and OPCo were impacted by strong winds from the remnants of Hurricane Ike.  CSPCo and OPCo incurred approximately $18 million and $13 million, respectively, in incremental distribution operation and maintenance costs related to service restoration efforts.  Under the current RSP, CSPCo and OPCo can seek a distribution rate adjustment to recover incremental distribution expenses related to major storm service restoration efforts.  In September 2008, CSPCo and OPCo established regulatory assets of $17 million and $10 million, respectively, for the incremental distribution operation and maintenance costs related to service restoration efforts.  The regulatory assets represent the excess above the average of the last three years of distribution storm expenses excluding Hurricane Ike, which was the methodology used by the PUCO to determine the recoverable amount of storm restoration expenses in the most recent 2006 PUCO storm damage recovery decision.  Prior to December 31, 2008, which is the expiration of the RSP, CSPCo and OPCo will file for recovery of the regulatory assets.  As a result of the past favorable treatment of storm restoration costs and the favorable RSP provisions, management believes the recovery of the regulatory assets is probable.  If these regulatory assets are not recoverable, it would have an adverse effect on future net income and cash flows.

Texas Rate Matters

TEXAS RESTRUCTURING

TCC Texas Restructuring Appeals

Pursuant to PUCT orders, TCC securitized its net recoverable stranded generation costs of $2.5 billion and is recovering such coststhe principal and interest on the securitization bonds over a period ending in 2020.  TCC has refunded its net other true-up itemsregulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider.  Cash paid for these CTC refunds for the sixnine months ended JuneSeptember 30, 2008 and 2007 was $68$75 million and $170$207 million, respectively. TCC appealed the PUCT stranded costs true-up and related orders seeking relief in both state and federal court on the grounds that certain aspects of the orders are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law and fail to fully compensate TCC for its net stranded cost and other true-up items.  The significant items appealed by TCC are:

·The PUCT ruling that TCC did not comply with the Texas Restructuring Legislation and PUCT rules regarding the required auction of 15% of its Texas jurisdictional installed capacity, which led to a significant disallowance of capacity auction true-up revenues.
·The PUCT ruling that TCC acted in a manner that was commercially unreasonable, because TCC failed to determine a minimum price at which it would reject bids for the sale of its nuclear generating plant and TCC bundled out-of-the-money gas units with the sale of its coal unit, which led to the disallowance of a significant portion of TCC’s net stranded generation plant costs.
·Two federal matters regarding the allocation of off-system sales related to fuel recoveries and a potential tax normalization violation.

Municipal customers and other intervenors also appealed the PUCT true-up and related orders seeking to further reduce TCC’s true-up recoveries.

In March 2007, the Texas District Court judge hearing the appealappeals of the true-up order affirmed the PUCT’s April 2006 final true-up order for TCC with two significant exceptions.  The judge determined that the PUCT erred by applying an invalid rule to determine the carrying cost rate for the true-up of stranded costs and remanded this matter to the PUCT for further consideration.  The District Court judge also determined that the PUCT improperly reduced TCC’s net stranded plant costs for commercial unreasonableness.

TCC, the PUCT and intervenors appealed the District Court decision to the Texas Court of Appeals.  In May 2008, the Texas Court of Appeals affirmed the District Court decision in all but one major respect.  It reversed the District Court’s unfavorable decision finding that the PUCT erred by applying an invalid rule to determine the carrying cost rate.  The favorable commercial unreasonableness decision was not reversed.  The Texas Court of Appeals denied intervenors’ motion for rehearing.  Management expectsIn May 2008, TCC, the PUCT and intervenors to appeal the decision tofiled petitions for review with the Texas Supreme Court.  If upheld on appeal, this ruling could have a favorable effect on TCC’s results of operations and cash flows.

Management cannot predict the outcome of these court proceedings and PUCT remand decisions.  If TCC ultimately succeeds in its appeals, it could have a material favorable effect on future results of operations,net income, cash flows and financial condition.  If municipal customers and other intervenors succeed in their appeals it could have a substantial adverse effect on future results of operations,net income, cash flows and financial condition.

TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes

Appeals remain outstanding related to the stranded costs true-up and related orders regarding whether the PUCT may require TCC to refund certain tax benefits to customers.  The PUCT agreed to allow TCC to defer a $103 million of the CTC other true-up items to refund to customers ($61 million in present value of the tax benefits associated with TCC’s generation assets plus $42 million of related carrying costs) pending resolution of whether the PUCT’s proposedsecuritization refund is an IRS normalization violation.  In May 2008, as requested by the PUCT, the Texas Court of Appeals ordered a remandThe deferral of the taxCTC refund negates the securitization reduction pending resolution of the normalization issue forviolation issue.

In March 2008, the consideration of additional evidence.
The IRS issued final regulations on March 20, 2008 addressing Accumulated Deferred Investment Tax Credit (ADITC) and Excess Deferred Federal Income Tax (EDFIT) normalization requirements.  Consistent with thea Private Letter Ruling TCC received in 2006, the regulations clearly state that TCC will sustain a normalization violation if the PUCT orders TCC to flow the tax benefits to customers.  TCC notified the PUCT that the final regulations were issued.  In May 2008, as requested by the PUCT, the Texas Court of Appeals ordered a remand of the tax normalization issue for the consideration of this additional evidence.

TCC expects that the PUCT will allow TCC to retain and not refund these amounts, whichamounts.  This will have a favorable effect on future results of operationsnet income and cash flows as TCC will record the ADITC and EDFIT tax benefits in income due to the sale of the generating plants that generated the tax benefits.  Since management expects that the PUCT will allow TCC to retain the deferred CTC refund amounts in order to avoid an IRS normalization violation, management has not accrued any related interest expense should TCC ultimately be required to refund these amounts.  If accrued, management estimates the interest expense would be approximately $2 million higher for the period July 1, 2008 through September 30, 2008 based on a CTC interest rate of 7.5%.

However, if the PUCT orders TCC to flow the tax benefits to customers, thereby causing TCC to have aviolate the IRS’ normalization violation,regulations, it could result in TCC’s repayment to the IRS of ADITC on all property, including transmission and distribution property, whichproperty.  This amount approximates $103 million as of JuneSeptember 30, 2008, and2008.  It will also lead to a loss of TCC’s right to claim accelerated tax depreciation in future tax returns.  If TCC is required to repay to the IRS its ADITC and is also required to refund ADITC to customers, it would have an unfavorable effect on future net income and cash flows.  Tax counsel advised management that a normalization violation should not occur until all remedies under law have been exhausted and the tax benefits are actually returned to ratepayers under a nonappealable order.  Management intends to continue its efforts to work with the PUCT to resolve the issue and avoid the adverse effects of a normalization violation.

TCCviolation on future net income, cash flows and TNC Deferred Fuel

TCC, TNC and the PUCT have been involved in litigation in the federal courts concerning whether the PUCT has the right to order a reallocation of off-system sales margins thereby reducing recoverable fuel costs.  In 2005, TCC and TNC recorded provisions for refunds after the PUCT ordered such reallocation.  After receipt of favorable federal court decisions and the refusal of the U.S. Supreme Court to hear a PUCT appeal of the TNC decision, TCC and TNC reversed their provisions of $16 million and $9 million, respectively, in the third quarter of 2007.

The PUCT or another interested party could file a complaint at the FERC to challenge the allocation of off-system sales margins under FERC-approved allocation agreements.  In December 2007, some cities served by TNC requested the PUCT to initiate, or order TNC to initiate a proceeding at the FERC to determine if AEP misapplied the allocation methodology under the FERC-approved agreements.  In January 2008, TNC filed a response with the PUCT recommending the cities’ request be denied.  Although management cannot predict if a complaint will be filed at the FERC, management believes its allocations were in accordance with the then-existing FERC-approved allocation agreements and additional off-system sales margins should not be retroactively reallocated to the AEP West companies including TCC and TNC.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.  On remand, the PUCT must determine how to implement the Court of Appeals decision given that the unauthorized refunds were made in lieu of reducing stranded cost recoveries in the True-up Proceeding.  As a result,It is possible that TCC’s stranded cost recovery, which is currently on appeal, may be affected by a PUCT remedy.

In December 2007,May 2008, the Texas Court of Appeals issued a decision in CenterPoint’s, a nonaffiliated Texas utility, true-up proceedingTCC’s True-up Proceeding determining that even though excess earnings had been previously refunded to the affiliated REP, CenterPointREPs, TCC still must reduce stranded cost recoveries in its true-up proceeding.True-up Proceeding.  In 2005, TCC reflected the obligation to refund excess earnings to customers through the true-up process and recorded a regulatory asset of $55 million representing a receivable from the REPs for prior refunds to them by TCC.  However, certain parties have taken positions that, if adopted, could result in TCC being required to refund additional amounts of excess earnings or interest through the true-up process without receiving a refund back from the REPs. If this were to occur it would have an adverse effect on future results of operationsnet income and cash flows.  AEP sold its affiliate REPs in December 2002.  While AEP owned the affiliate REPs, TCC refunded $11 million of excess earnings to the affiliate REPs.  Management cannot predict the outcome of these mattersthe excess earnings remand and whether theyit will adversely affect future results of operations,net income and cash flows and financial condition.flows.

OTHER TEXAS RATE MATTERS

Hurricanes Dolly and Ike

In July and September 2008, TCC’s service territory in south Texas was hit by Hurricanes Dolly and Ike, respectively.  TCC incurred $11 million and $1 million in incremental operation and maintenance costs related to service restoration efforts for Hurricanes Dolly and Ike, respectively.  TCC has a PUCT-approved catastrophe reserve which permits TCC to collect $1.3 million on an annual basis with authority to continue the collection until the catastrophe reserve reaches $13 million.  Any incremental operation and maintenance costs can be charged against the catastrophe reserve if the total incremental operation and maintenance costs for a storm exceed $500 thousand.  In June 2008, prior to these hurricanes, TCC had approximately $2 million recorded in the catastrophe reserve account.  Since the catastrophe reserve balance was less than the incremental operation and maintenance costs related to Hurricanes Dolly and Ike, TCC established a net regulatory asset for $10 million.

Under Texas law and as previously approved by the PUCT in prior base rate cases, the regulatory asset will be included in rate base in the next base rate filing.  At that time, TCC will evaluate the existing catastrophe reserve amounts and review potential future events to determine the appropriate funding level to request.

ETT

In December 2007, TCC contributed $70 million of transmission facilities to ETT, a newly-formed joint venture which will own and operate transmission assets in ERCOT.  The PUCT approved ETT's initial rates, its request for a transfer of facilities and a certificate of convenience and necessity to operate as a stand alone transmission utility in the ERCOT region.  ETT was awarded a 9.96% after tax return on equity rate in those approvals.  In 2008, intervenors filed a notice of appeal to the Travis County District Court.  In October 2008, the court ruled that the PUCT exceeded its authority by approving ETT’s application as a stand alone transmission utility without a service area under the wrong section of the statute.  Management believes that ruling is incorrect.  Moreover, ETT provided evidence in its application that ETT has complied with what the court determined was the proper section of the statute.  As of September 30, 2008, AEP’s net investment in ETT was $16 million.  ETT is considering its options for responding to the ruling including an appeal of the Travis County District Court ruling.  Depending upon the ultimate outcome of the Travis County District Court ruling, TCC may be required to repurchase the $70 million of transmission facilities TCC contributed to ETT.  Management cannot predict the outcome of this proceeding or its future effect on net income and cash flows.

Stall Unit

See “Stall Unit” section within the Louisiana Rate Matters for disclosure.

Turk Plant

See “Turk Plant” section within the Arkansas Rate Matters for disclosure.

Virginia Rate Matters

Virginia Base Rate Filing

In May 2008, APCo filed an application with the Virginia SCC to increase its base rates by $208 million on an annual basis.  The requested increase is based upon a calendar 2007 test year adjusted for changes in revenues, expenses, rate base and capital structure through June 2008 which2008.  This is consistent with the ratemaking treatment adopted by the Virginia SCC in APCo’s 2006 base rate case.  The proposed revenue requirement reflects a return on equity of 11.75%.  The Virginia SCC ordered hearings to beginHearings began in October 2008.  As permitted under Virginia law, APCo plans to implementimplemented these new base rates, subject to refund, effective October 28, 2008.

In September 2008, ifthe Attorney General’s office filed testimony recommending the proposed $208 million annual increase in base rate be reduced to $133 million.  The decrease is principally due to the use of a return on equity approved in the last base rate case of 10% and various rate base and operating income adjustments, including a $25 million proposed disallowance of capacity equalization charges payable by APCo as a deficit member of the FERC approved AEP Power Pool.

In October 2008, the Virginia SCC failsstaff filed testimony recommending the proposed $208 million annual increase in base rate be reduced to make$157 million.  The decrease is principally due to the use of a decisionrecommended return on equity of 10.1%.  In October 2008, hearings were held in which APCo filed a $168 million settlement agreement which was accepted by that date.all parties except one industrial customer.  APCo expects to receive a final order from the Virginia SCC in November 2008.

Virginia E&R Costs Recovery Filing

As of June 30,September 2008, APCo has $97$118 million of deferred Virginia incremental E&R costs.  Currently APCo is recovering $16costs (excluding $25 million of unrecognized equity carrying costs).  The $118 million consists of $6 million already approved by the deferral for incremental costs incurred through September 30, 2006.  InVirginia SCC to be collected during the fourth quarter 2008, $54 million relating to APCo’s May 2008 APCo filedfiling for recovery in 2009, and $58 million, representing costs deferred in 2008 to date, to be included (along with the fourth quarter 2008 E&R deferrals) in the 2009 E&R filing, to be collected in 2010.

In September 2008, a settlement was reached between the parties to the 2008 filing and a stipulation agreement (stipulation) was submitted to the hearing examiner.  The stipulation provides for recovery of deferred incremental E&R costs incurred from October 1, 2006 through December 31, 2007 which totals $50 million.  The remaining deferral will be requested in a 2009 filing.  As of June 30, 2008, APCo has $22$61 million of unrecorded E&R equity carrying costs of which $7 million should increase 2008 annual earnings as collected.  In connection with the 2009 filing, the Virginia SCC will determine the level of incremental E&R costs in 2009 which is an increase of $12 million over the level of E&R surcharge revenues being collected in base revenues since October 20062008.  The stipulation included an unfavorable $1 million adjustment related to certain costs considered not recoverable E&R costs and recovery of $4.5 million representing one-half of a $9 million Virginia jurisdictional portion of NSR settlement expenses recorded in 2007.  In accordance with the stipulation, APCo will request the remaining one-half of the $9 million of NSR settlement expenses in APCo’s 2009 E&R filing.  The stipulation also specifies that APCo has estimatedwill remove $3 million of the $9 million of NSR settlement expenses requested to be $48 million annually.  Ifrecovered over 3 years in the Virginia SCC were to determine that these recoveredcurrent base revenues are in excess of $48 million a year, it would require thatrate case from the E&R deferrals be reduced by the excess amount, thus adversely affecting future earnings and cash flows.base rate case’s revenue requirement.

In JulySeptember 2008, the Old Dominion Committee for Fair Utility Rates (ODC) filed a motion to dismiss the E&R filing based on ODC’s beliefhearing examiner recommended that the opportunity to collect E&R surcharges expires December 31, 2008.  A dismissal would not eliminate APCo’s ability to request for future recovery of its deferred E&R costs.  APCo filed a response requesting the Virginia SCC to deny ODC’s motion.accept the stipulation.  As a result, in September 2008, APCo deferred as a regulatory asset $9 million of NSR settlement expenses it had expensed in 2007 that have become probable of future recovery.  In October 2008, the Virginia SCC approved the stipulation which will have a favorable effect on 2009 future cash flows of $61 million and on net income for the previously unrecognized equity costs of approximately $11 million.  If the Virginia SCC were to disallow any additionala material portion of APCo’s 2008 deferral, it would also have an adverse effect on future results of operationsnet income and cash flows.  If the outstanding request for E&R recovery is approved it will have a favorable effect on future cash flows.

Virginia Fuel Clause Filings

In July 2007, APCo filed an application with the Virginia SCC to seek an annualized increase, effective September 1, 2007, of $33 million for fuel costs and sharing of off-system sales.

In February 2008, the Virginia SCC issued an order that approved a reduced fuel factor effective with the February 2008 billing cycle.  The order terminated the off-system sales margin rider and approved a 75%-25% sharing of off-system sales margins between customers and APCo effective September 1, 2007 as required by the re-regulation legislation in Virginia.  The order also allows APCo to include in its monthly under/over recovery deferrals the Virginia jurisdictional share of PJM transmission line loss costs from June 2007 to June 2008 which totaled $28 million.2007.  The adjusted factor increases annual fuel clause revenues by $4 million.  The order authorized the Virginia SCC staff and other parties to make specific recommendations to the Virginia SCC in APCo’s next fuel factor proceeding to ensure accurate assignment of the prudently incurred PJM transmission line loss costs to APCo’s Virginia jurisdictional operations.  Management believes the incurred PJM transmission line loss costs are prudently incurred and are being properly assigned to APCo’s Virginia jurisdictional operations.

In February 2008, the Old Dominion Committee for Fair Utility Rates (ODC) filed a notice of appeal to the Supreme Court of Virginia appealing the Virginia SCC’s decisions regarding off-system sales margins and PJM transmission line loss costs.  In May 2008, the ODC withdrew its appeal.

In July 2008, APCo filed its next fuel factor proceeding with the Virginia SCC and requested an annualized increase of $132 million effective September 1, 2008.  The increase primarily relates to increases in coal costs.

If costs included in APCo’s  In August 2008, the Virginia SCC issued an order to allow APCo to implement the increased fuel under/over recovery deferrals are disallowed, it couldfactor on an interim basis for services rendered after August 2008.  In September 2008, the Virginia SCC staff filed testimony recommending a lower fuel factor which will result in an adverse effectannualized increase of $117 million, which includes the PJM transmission line loss costs, instead of APCo’s proposed $132 million.  In October 2008, the Virginia SCC ordered an annualized increase of $117 million for services rendered on future results of operations and cash flows.after October 20, 2008.

APCo’s Virginia SCC Filing for an IGCC Plant

In July 2007, APCo filed a request with the Virginia SCC for a rate adjustment clause to recover initial costs associated with a proposed 629 MW IGCC plant to be constructed in Mason County, West Virginia adjacent to APCo’s existing Mountaineer Generating Station for an estimated cost of $2.2 billion.  The filing requested recovery of an estimated $45 million over twelve months beginning January 1, 2009 including a return on projected CWIP and development, design and planning pre-construction costs incurred from July 1, 2007 through December 31, 2009.  APCo also requested authorization to defer a return on deferred pre-construction costs incurred beginning July 1, 2007 until such costs are recovered.  Through JuneSeptember 30, 2008, APCo has deferred for future recovery pre-construction IGCC costs of approximately $9 million allocated to Virginia jurisdictional operations.  The rate adjustment clause provisions of the 2007 re-regulation legislation provides for full recovery of all costs of this type of new clean coal technology including recovery of an enhanced return on equity.

The Virginia SCC issued an order in April 2008 denying APCo’s requests stating the belief that the estimated cost may be significantly understated.  The Virginia SCC also expressed concern that the $2.2 billion estimated cost did not include a retrofitting of carbon capture and sequestration facilities.  In April 2008, APCo filed a petition for reconsideration in Virginia.  In May 2008, the Virginia SCC denied APCo’s request to reconsider its previous ruling.  In July 2008, the IRS awardedallocated $134 million in future tax credits to APCo for the planned IGCC plant.  Managementplant contingent upon the commencement of construction, qualifying expense being incurred and certification of the IGCC plant prior to July 2010.  Although management continues to pursue the ultimate construction of the IGCC plant; however,plant, APCo will not start construction of the IGCC plant until sufficient assurance of cost recovery exists.  If the plant is canceled,cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs.  If the plant is canceledcancelled and if the deferred costs are not recoverable, it would have an adverse effect on future results of operationsnet income and cash flows.

Mountaineer Carbon Capture Project

In January 2008, APCo and ALSTOM Power Inc. (Alstom), an unrelated third party, entered into an agreement to jointly construct a CO2 capture facility.  APCo and Alstom will each own part of the CO2 capture facility.  APCo will also construct and own the necessary facilities to store the CO2.  APCo’s estimated cost for its share of the facilities is $76 million.  Through September 30, 2008, APCo incurred $13 million in capitalized project costs which is included in Regulatory Assets.  APCo plans to seek recovery for the CO2 capture and storage project costs in its next Virginia and West Virginia base rate filings which are expected to be filed in 2009.  APCo is presently seeking a return on the capitalized project costs in its current Virginia base rate filing.  The Attorney General has recommended that the project costs should be shared by all affiliated operating companies with coal-fired generation plants.  If a significant portion of the project costs are excluded from base rates and ultimately disallowed in Virginia and/or West Virginia, it could have an adverse effect on future net income and cash flows.

West Virginia Rate Matters

APCo’s and WPCo’s 2008 Expanded Net Energy Cost (ENEC) Filing

In February 2008, APCo and WPCo filed for an increase of approximately $156 million including a $135 million increase in the ENEC, a $17 million increase in construction cost surcharges and $4 million of reliability expenditures, to become effective July 2008.  In June 2008, the WVPSC issued an order approving a joint stipulation and settlement agreement granting an increase,rate increases, effective July 2008, of approximately $106 million, including an $88 million increase in the ENEC, a $14 million increase in construction cost surcharges and $4 million of reliability expenditures.  The ENEC is an expanded form of fuel clause mechanism, which includes all energy-related costs including fuel, purchased power expenses, off-system sales credits, PJM costs associated with transmission line losses due to the implementation of marginal loss pricing and other energy/transmission items.

The ENEC is subject to a true uptrue-up to actual costs and should have no earnings effect if actual costs exceed the recoveries due to the deferral of any over/under-recovery of actual ENEC costs.  The construction cost and reliability surcharges are not subject to a true uptrue-up to actual costs and could result in an adverse under recovery.impact future net income and cash flows.

APCo’s West Virginia IGCC Plant Filing

In January 2006, APCo filed a petition with the WVPSC requesting its approval of a Certificate of Public Convenience and Necessity (CCN) to construct a 629 MW IGCC plant adjacent to APCo’s existing Mountaineer Generating Station in Mason County, West Virginia.

In June 2007, APCo filed testimony with the WVPSC supporting the requests for a CCN and for pre-approval of a surcharge rate mechanism to provide for the timely recovery of both pre-construction costs and the ongoing finance costs of the project during the construction period as well as the capital costs, operating costs and a return on equity once the facility is placed into commercial operation.  In March 2008, the WVPSC granted APCo the CCN to build the plant and the request for cost recovery.  VariousAlso, in March 2008, various intervenors filed petitions with the WVPSC to reconsider the order.  No action has been taken on the requests for rehearing.  At the time of the filing, the cost of the plant was estimated at $2.2 billion.  As of September 30, 2008, the estimated cost of the plant has continued to significantly increase.  In July 2008, based on the unfavorable order received in Virginia, the WVPSC issued a notice seeking comments from parties on how the WVPSC should proceed (Seeproceed.  See the “APCo’s Virginia SCC Filing for an IGCC Plant” section above).above.  Through JuneSeptember 30, 2008, APCo deferred for future recovery pre-construction IGCC costs of $8approximately $9 million applicable to the West Virginia jurisdiction and approximately $2 million applicable to the FERC jurisdiction.  In July 2008, the IRS awardedallocated $134 million in future tax credits to APCo for the planned IGCC plant.  ManagementAlthough management continues to pursue the ultimate construction of the IGCC plant; however,plant, APCo will not start construction of the IGCC plant until sufficient assurance of cost recovery exists. If the plant is canceled,cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs.  If the plant is canceledcancelled and if the deferred costs are not recoverable, it would have an adverse effect on future results of operationsnet income and cash flows.

Indiana Rate Matters

Indiana Base Rate Filing

In a January 2008, filing with the IURC, updated in the second quarter of 2008, I&M requested an increase in its Indiana base rates of $80 million including a return on equity of 11.5%.  The base rate increase includes the $69 million annual reduction in depreciation expense previously approved by the IURC and implemented for accounting purposes effective June 2007.  The depreciation reduction will no longer favorably impact earnings if and will adversely affect cash flows when tariff rates are revised to reflect the effect of the depreciation expense reduction.  The filing also requests trackers for certain variable components of the cost of service including recently increased PJM costs associated with transmission line losses due to the implementation of marginal loss pricing and other RTO costs, reliability enhancement costs, demand side management/energy efficiency costs, off-system sales margins and environmental compliance costs.  The trackers would initially increase annual revenues by an additional $45 million.  I&M proposes to share with ratepayers, through a tracker, 50% of off-system sales margins initially estimated to be $96 million annually with a guaranteed credit to customers of $20 million.

In September 2008, the Indiana Office of Utility Consumer Counselor (OUCC) and the Industrial Customer Coalition filed testimony recommending a $14 million and $37 million decrease in revenue, respectively.  Two other intervenors filed testimony on limited issues.  The OUCC and the Industrial Customer Coalition recommended that the IURC reduce the ROE proposed by I&M, reduce or limit the amount of off-system sales margin sharing, deny the recovery of reliability enhancement costs and reject the proposed environmental compliance cost recovery trackers.  In October 2008, I&M filed testimony rebutting the recommendations of the OUCC.  Hearings are scheduled for December 2008.  A decision is expected from the IURC by June 2009.

Michigan Rate Matters

Michigan Restructuring

Although customer choice commenced for I&M’s Michigan customers on January 1, 2002, I&M’s rates for generation in Michigan continued to be cost-based regulated because none of I&M's customers elected to change suppliers and no alternative electric suppliers were registered to compete in I&M's Michigan service territory.  In October 2008, the Governor of Michigan signed legislation to limit customer choice load to no more than 10% of the annual retail load for the preceding calendar year and to require the remaining 90% of annual retail load to be phased into cost-based rates.  The new legislation also requires utilities to meet certain energy efficiency and renewable portfolio standards and requires cost recovery of meeting those standards.  Management continues to conclude that I&M's rates for generation in Michigan are cost-based regulated.

Kentucky Rate Matters

Validity of Nonstatutory Surcharges

In August 2007, the Franklin County Circuit Court concluded the KPSC did not have the authority to order a surcharge for a gas company subsidiary of Duke Energy absent a full cost of service rate proceeding due to the lack of statutory authority.  The Kentucky Attorney General (AG) notified the KPSC that the Franklin County Circuit Court judge’s order in the Duke Energy case can be interpreted to include other existing surcharges, rates or fees established outside of the context of a general rate case proceeding and not specifically authorized by statute, including fuel clauses.  TheBoth the KPSC and Duke Energy appealed the Franklin County Circuit Court decision.

Although this order is not directly applicable, KPCo has existing surcharges which are not specifically authorized by statute.  These include KPCo’s fuel clause surcharge, the annual Rockport Plant capacity surcharge, the merger surcredit and the off-system sales credit rider.  On an annual basis these surcharges recently ranged from revenues of approximately $10 million to a reduction of revenues of $2 million due to the volatility of these surcharges.  The KPSC asked interested parties to brief the issue in KPCo’s fuel cost proceeding.  The AG responded that the KPCo fuel clause should be invalidated because the KPSC lacked the authority to implement a fuel clause for KPCo without a full rate case review.  The KPSC issued an order stating that it has the authority to provide for surcharges and surcredits until the Courtcourt of Appealsappeals rules.  The appeals process could take up to two years to complete.  The AG agreed to stay its challenge during that time.

We expect any adverse court of appeals decision could be applied prospectively but it is possible that a retrospective refund could also be ordered.  KPCo’s exposure is indeterminable at this time since it is not known whether a finalalthough an adverse appeal could result in a refund of prior amounts collected, whichdecision would have an adverseunfavorable effect on future results of operationsnet income and cash flows.flows, assuming the legislature does not enact legislation that authorizes such surcharges.

2008 Fuel Cost Reconciliation

In January 2008, KPCo filed its semi-annual fuel cost reconciliation covering the period May 2007 through October 2007.  As part of this filing, KPCo sought recovery of incremental costs associated with transmission line losses billed by PJM since June 2007 due to PJM’s implementation of marginal loss pricing.  KPCo expensed these incremental PJM costs associated with transmission line losses pending a determination that they are recoverable through the Kentucky fuel clause.  In June 2008, the KPSC issued an order approving KPCo’s semi-annual fuel cost reconciliation filing and recovery of incremental costs associated with transmission line losses billed by PJM beginning May 2008.  Therefore, inPJM.  For the second quarter ofnine months ended September 30, 2008, KPCo recorded $13$16 million of income and the related Regulatory Asset for Under-Recovered Fuel Costs for transmission line losses incurred from June 2007 through JuneSeptember 2008 of which $7 million related to 2007.

Oklahoma Rate Matters

PSO Fuel and Purchased Power and its Possible Impact on AEP East companies and

The Oklahoma Industrial Energy Consumers appealed an ALJ recommendation in June 2008 regarding a pending fuel case involving the reallocation of $42 million of purchased power costs among AEP West companies

In 2004, intervenors and in 2002.  The Oklahoma Industrial Energy Consumers requested that PSO be required to refund this $42 million of reallocated purchased power costs through its fuel clause.  PSO had recovered the OCC staff argued that AEP had inappropriately under allocated off-system sales credits to PSO by $37$42 million forduring the period June 2000 to December 2004 under a FERC-approved allocation agreement.  An ALJ assigned to hear intervenor claims found that2007 through May 2008.  In August 2008, the OCC lacked authority to examine whether AEP deviated fromheard the FERC-approved allocation methodology for off-system sales marginsappeal and held that any such complaints should be addressed at the FERC.  In October 2007, the OCC adopted the ALJ’s recommendation and orally directed the OCC staff to explore filing a complaint at FERC alleging the allocation of off-system sales margins to PSOdecision is not in compliance with the FERC-approved methodology which could result in an adverse effect on future results of operations and cash flows for AEP Consolidated and the AEP East companies.  In June 2008, the ALJ issued a final recommendation and incorporated the prior finding that the OCC lacked authority to review AEP’s application of a FERC-approved methodology.  The OCC is scheduled to consider the final recommendation in August 2008.  To date, no claim has been asserted at the FERC and management continues to believe that the allocation is consistent with the FERC-approved agreement.pending.

In February 2006, the OCC enacted a rule, requiring the OCC staff to conduct prudence reviews on PSO’s generation and fuel procurement processes, practices and costs on a periodic basis.  PSO filed testimony in June 2007 covering a prudence review for the year 2005.  The OCC staff and intervenors filed testimony in September 2007, and hearings were held in November 2007.  The only major issue in the proceeding was the alleged under allocation of off-system sales credits under the FERC-approved allocation methodology, which previously was determined not to be jurisdictional to the OCC.  See “Allocation of Off-system Sales Margins” section within “FERC Rate Matters”.  Consistent with herthe prior recommendation,OCC determination, the ALJ found that the OCC lacked authority to alter the FERC-approved allocation methodology and that PSO’s fuel costs were prudent.  The intervenors appealed the ALJ recommendation and the OCC is scheduled to considerheard the ALJ’s findings and ruleappeal in August 2008.  In August 2008, the OCC filed a complaint at the FERC alleging that AEPSC inappropriately allocated off-system trading margins between the AEP East companies and the AEP West companies and did not properly allocate off-system trading margins within the AEP West companies.

In November 2007, PSO filed testimony in another proceeding to address its fuel costs for 2006.  In April 2008, intervenor testimony was filed again challenging the allocation of off-system sales credits during the portion of the year when the allocation was in effect.  Hearings were held in July 2008 and the OCC changed the scope of the proceeding from a prudence review to only a review of the mechanics of the fuel cost calculation.  No party contested PSO’s fuel cost calculationcalculation.  In August 2008, the OCC issued a final order that PSO’s calculations of fuel and an orderpurchased power costs were accurate and are consistent with PSO’s fuel tariff.

In September 2008, the OCC initiated a review of PSO’s generation, purchased power and fuel procurement processes and costs for 2007.  Under the OCC minimum filing requirements, PSO is expectedrequired to file testimony and supporting data within 60 days which will occur in Augustthe fourth quarter of 2008.
Management cannot predict the outcome of the pending fuel and purchased power cost recovery filings andor prudence reviews or whether a complaint will be filed at FERC regarding the off-system sales allocation issue.reviews.  However, PSO believes its fuel and purchased power procurement practices and costs were prudent and properly incurred and that it allocated off-system sales credits consistent with governing FERC-approved agreements.  If a complaint is filed at FERC resulting in an unfavorable decision, it could have an adverse effect on results of operations and cash flows.therefore are legally recoverable.

Red Rock Generating Facility

In July 2006, PSO announced an agreement with Oklahoma Gas and Electric Company (OG&E) to build a 950 MW pulverized coal ultra-supercritical generating unit.  PSO would own 50% of the new unit.  Under the agreement, OG&E would manage construction of the plant.  OG&E and PSO requested preapprovalpre-approval to construct the coal-fired Red Rock Generating Facility (Red Rock) and to implement a recovery rider.

In October 2007, the OCC issued a final order approving PSO’s need for 450 MWs of additional capacity by the year 2012, but rejected the ALJ’s recommendation and denied PSO’s and OG&E’s applications for construction preapproval.pre-approval.  The OCC stated that PSO failed to fully study other alternatives to a coal-fired plant.  Since PSO and OG&E could not obtain preapprovalpre-approval to build the coal-fired Red Rock, Generating Facility, PSO and OG&E canceledcancelled the third party construction contract and their joint venture development contract.  In June 2008, PSO has issued a request-for-proposal to meet its capacity and energy needs.

In December 2007, PSO filed an application at the OCC requesting recovery of the $21 million in pre-construction costs and contract cancellation fees associated with Red Rock.  In March 2008, PSO and all other parties in this docket signed a settlement agreement that provides for recovery of $11 million of Red Rock costs, and provides carrying costs at PSO’s AFUDC rate beginning in March 2008 and continuing until the $11 million is included in PSO’s next base rate case.  PSO will recover the costs over the expected life of the peaking facilities at the Southwestern Station, and include the costs in rate base beginning in its next base rate filing.  The settlement was filed with the OCC in March 2008.  The OCC approved the settlement in May 2008.  As a result of the settlement, PSO wrote off $10 million of its deferred pre-construction costs/cancellation fees in the first quarter of 2008.  In July 2008, PSO filed a base rate case which included $11 million of deferred Red Rock costs plus carrying charges at PSO’s AFUDC rate beginning in March 2008.  See “2008 Oklahoma Base Rate Filing” section below.

Oklahoma 2007 Ice Storms

In October 2007, PSO filed with the OCC requesting recovery of $13 million of operation and maintenance expense related to service restoration efforts after a January 2007 ice storm.  PSO proposed in its application to establish a regulatory asset of $13 million to defer the previously expensed January 2007 ice storm restoration costs and to amortize the regulatory asset coincident with gains from the sale of excess SO2 emission allowances.  In December 2007, PSO expensed approximately $70 million of additional storm restoration costs related to anotherthe December 2007 ice storm in December 2007.storm.

In February 2008, PSO entered into a settlement agreement for recovery of costs from both ice storms.  In March 2008, the OCC approved the settlement subject to an audit of the final December ice storm costs filed in July 2008.  As a result, PSO recorded an $81 million regulatory asset for ice storm maintenance expenses and related carrying costs less $9 million of amortization expense to offset recognition of deferred gains from sales of SO2 emission allowances.  Under the settlement agreement, PSO would apply proceeds from sales of excess SO2 emission allowances of an estimated $26 million to recover part of the ice storm regulatory asset.  The settlement also provided for PSO willto amortize and recover the remaining amount of the regulatory asset through a rider over a period of five years beginning in the fourth quarter of 2008.  The regulatory asset will earn a return of 10.92% on the unrecovered balance.

In June 2008, PSO adjusted its regulatory asset to true-up the estimated costs to reflect actual costs as of June 30, 2008.costs.  After the true-up, application of proceeds from to-date sales of excess SO2 emission allowances and carrying costs, the ice storm regulatory asset as of June 30, 2008 was $64 million.  In July 2008, PSO filed with the OCC to establish the recovery rider and the final recoverable December 2007 ice storm costs.  The estimate of future gains from the sale of SO2 emission allowances has significantly declined with the decrease in value of such allowances.  As a result, estimated collections from customers through the special storm damage recovery rider will be higher than the estimate in the settlement agreement.  Nonetheless, management believes thatIn July 2008, as required by the settlement provides for full recoveryagreement, PSO filed its reconciliation of the remaining deferral.December 2007 storm restoration costs along with a proposed tariff to recover the amounts not offset by the sales of SO2 emission allowances.  In September 2008, the OCC staff filed testimony supporting PSO’s filing with minor changes.  In October 2008, an ALJ recommended that PSO recover $62 million of the December 2007 storm restoration costs before consideration of emission allowance gains and carrying costs.  In October 2008, the OCC approved the filing which allows PSO to recover $62 million of the December 2007 storm restoration costs beginning in November 2008.

2008 Oklahoma Annual Fuel Factor Filing

In May 2008, pursuant to its tariff, PSO filed its annual update with the OCC for increases in the various service level fuel factors based on estimated increases in fuel costs, primarily natural gas and purchased power expenses, of approximately $300 million.  The request included recovery of $26 million in under-recovered deferred fuel.  In June 2008, PSO implemented the fuel factor increase.  Because of the substantial increase, the OCC held an administrative proceeding to determine whether the proposed charges were based upon the appropriate coal, purchased gas and purchased power prices and were properly computed.  In June 2008, the OCC ordered that PSO properly estimated the increase in natural gas prices, properly determined its fuel costs and, thus, should implement the increase.

2008 Oklahoma Base Rate Filing

In July 2008, PSO filed an application with the OCC to increase its base rates by $133 million on an annual basis.  PSO recovers costs related to new peaking units recently placed into service through the Generation Cost Recovery Rider (GCRR).  Upon implementation of the new base rates, PSO will recover these costs through the new base rates and the GCRR will terminate.  Therefore, PSO’s net annual requested increase in total revenues is actually $117 million.  The requested increase is based upon a test year ended February 29, 2008, adjusted for known and measurable changes through August 2008, which is consistent with the ratemaking treatment adopted by the OCC in PSO’s 2006 base rate case.  The proposed revenue requirement reflects a return on equity of 11.25%.  PSO expects hearings to begin in December 2008 and new base rates to become effective in the first quarter of 2009.In October 2008, the OCC staff, the Attorney General’s office, and a group of industrial customers filed testimony recommending annual base rate increases of $86 million, $68 million and $29 million, respectively.  The differences are principally due to the use of recommended return on equity of 10.88%, 10% and 9.5% by the OCC staff, the Attorney General’s office, and a group of industrial customers.  The OCC staff and the Attorney General’s office recommended $22 million and $8 million, respectively, of costs included in the filing be recovered through the fuel adjustment clause and riders outside of base rates.

Louisiana Rate Matters

Louisiana Compliance Filing

In connection with SWEPCo’s merger related compliance filings, the LPSC approved a settlement agreement in April 2008 that prospectively resolves all issues regarding claims that SWEPCo had over-earned its allowed return.  SWEPCo agreed to a formula rate plan (FRP) with a three-year term.  BeginningUnder the plan, beginning in August 2008, rates shall be established to allow SWEPCo to earn an adjusted return on common equity of 10.565%.  The adjustments are standard Louisiana rate filing adjustments.

If in the second and third year of the FRP, the adjusted earned return is within the range of 10.015% to 11.115%, no adjustment to rates is necessary.  However, if the adjusted earned return is outside of the above-specified range, an FRP rider will be established to increase or decrease rates prospectively.  If the adjusted earned return is less than 10.015%, SWEPCo will prospectively increase rates to collect 60% of the difference between 10.565% and the adjusted earned return.  Alternatively, if the adjusted earned return is more than 11.115%, SWEPCo will prospectively decrease rates by 60% of the difference between the adjusted earned return and 10.565%.  SWEPCo will not record over/under recovery deferrals for refund or future recovery under this FRP.

The settlement provides for a separate credit rider decreasing Louisiana retail base rates by $5 million prospectively over the entire three yearthree-year term of the FRP, which shall not affect the adjusted earned return in the FRP calculation.  This separate credit rider will cease effective August 2011.

In addition, the settlement provides for a reduction in generation depreciation rates effective October 2007.  SWEPCo will defer as a regulatory liability, the effects of the expected depreciation reduction through July 2008.  SWEPCo will amortize this regulatory liability over the three yearthree-year term of the FRP as a reduction to the cost of service used to determine the adjusted earned return.  In August 2008, the LPSC issued an order approving the settlement.

In April 2008, SWEPCo filed the first FRP which would increase its annual Louisiana retail rates by $11 million in August 2008 to earn an adjusted return on common equity of 10.565%.  In June 2008,accordance with the settlement, SWEPCo recorded a $3$4 million regulatory liability related to the reduction in generation depreciation rates.  The amount of the unamortized regulatory liability for the reduction in generation depreciation was $4 million as of September 30, 2008.  In August 2008, SWEPCo implemented the FRP rates, subject to refund, as the LPSC staff reviews SWEPCo’s FRP filing and the production depreciation study.

Stall Unit

In May 2006, SWEPCo announced plans to build a new intermediate load, 500 MW, natural gas-fired, combustion turbine, combined cycle generating unit (the Stall Unit) at its existing Arsenal Hill Plant location in Shreveport, Louisiana.  SWEPCo submitted the appropriate filings to the PUCT, the APSC, the LPSC and the Louisiana Department of Environmental Quality to seek approvals to construct the unit.  The Stall Unit is currently estimated to cost $378 million, excluding AFUDC, and is expected to be in-service in mid-2010.

In March 2007, the PUCT approved SWEPCo’s request for a certificate for the facility based on a prior cost estimate.  In FebruarySeptember 2008, the LPSC staff submitted testimony in support ofapproved SWEPCo’s request for certification to construct the Stall Unit and one intervenor submitted testimony opposing the Stall Unit due to the increase in cost.  The LPSC held hearings in April 2008.  In July 2008, an ALJ in the LPSC proceeding recommended approval of the Stall Unit.Plant.  The APSC has not established a procedural schedule at this time.  The Louisiana Department of Environmental Quality issued an air permit for the unit in March 2008.  If SWEPCo does not receive appropriate authorizations and permits to build the Stall Unit, SWEPCo would seek recovery of the capitalized pre-construction costs including any cancellation fees.  As of JuneSeptember 30, 2008, SWEPCo has capitalized pre-construction costs of $106$158 million and has contractual construction commitments of an additional $191$145 million.  As of JuneSeptember 30, 2008, if the plant had been canceled,cancelled, cancellation fees of $60$61 million would have been required in order to terminate these construction commitments.  If SWEPCo canceledcancels the plant and cannot recover its capitalized costs, including any cancellation fees, it would have an adverse effect on future results of operationsnet income, cash flows and cash flows.possibly financial condition.

Turk Plant

See “Turk Plant” section within Arkansas Rate Matters for disclosure.

Arkansas Rate Matters

Turk Plant

In August 2006, SWEPCo announced plans to build the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas.  Ultra-supercritical technology uses higher temperatures and higher pressures to produce electricity more efficiently – thereby using less fuel and providing substantial emissions reductions.  SWEPCo submitted filings with the APSC, the PUCT and the LPSC seeking certification of the plant.  SWEPCo will own 73% of the Turk Plant and will operate the facility.  During 2007, SWEPCo signed joint ownership agreements with the Oklahoma Municipal Power Authority (OMPA), the Arkansas Electric Cooperative Corporation (AECC) and the East Texas Electric Cooperative (ETEC) for the remaining 27% of the Turk Plant.  The Turk Plant is currently estimated to cost $1.5 billion, excluding AFUDC, with SWEPCo’s portion estimated to cost $1.1 billion, excluding AFUDC.billion.  If approved on a timely basis, the plant is expected to be in-service in 2012.

In November 2007, the APSC granted approval to build the plant.  Certain landowners filed a notice of appeal to the Arkansas State Court of Appeals.  In March 2008, the LPSC approved the application to construct the Turk Plant.

In JulyAugust 2008, the PUCT approved a certificateissued an order approving the Turk Plant with the following four conditions: (a) the capping of convenience and necessity for construction of the plant.  We expect a written order in August 2008 which will also providecapital costs for the conditionsTurk Plant at the $1.5 billion projected construction cost, excluding AFUDC, (b) capping CO2 emission costs at $28 per ton through the year 2030, (c) holding Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers and (d) providing the PUCT all updates, studies, reviews, reports and analyses as previously required under the Louisiana and Arkansas orders.  An intervenor filed a motion for rehearing seeking reversal of the PUCT’s approval.decision.  SWEPCo filed a motion for rehearing stating that the two cost cap restrictions are unlawful.  In September 2008, the motions for rehearing were denied.  In October 2008, SWEPCo appealed the PUCT’s order regarding the two cost cap restrictions.  If the cost cap restrictions are upheld and construction or emissions costs exceed the restrictions, it could have a material adverse impact on future net income and cash flows.  In October 2008, an intervenor filed an appeal contending that the PUCT’s grant of a conditional Certificate of Public Convenience and Necessity for the Turk Plant was not necessary to serve retail customers.

SWEPCo is also working with the Arkansas Department of Environmental Quality for the approval of an air permit and the U.S. Army Corps of Engineers for the approval later this year.of a wetlands and stream impact permit.  Once SWEPCo receives the air permit, they will commence construction.  A request to stop pre-construction activities at the site was filed in Federal court by the same Arkansas landowners who appealed the APSC decision to the Arkansas State Court of Appeals.  In July 2008, the Federal court denied the request and the Arkansas landowners appealed the denial to the U.S. Court of Appeals.

In January 2008 and July 2008, SWEPCo filed applications for authority with the APSC to construct transmission lines necessary for service from the Turk Plant.  Several landowners filed for intervention status and one landowner also contended he should be permitted to re-litigate Turk Plant issues, including the need for the generation.  The APSC granted their intervention but denied the request to re-litigate the Turk Plant issues.  The landowner filed an appeal to the Arkansas State Court of Appeals in June 2008.

The Arkansas Governor’s Commission on Global Warming is scheduled to issue its final report to the Governor by November 1, 2008.  The Commission was established to set a global warming pollution reduction goal together with a strategic plan for implementation in Arkansas.  If legislation is passed as a result of the findings in the Commission’s report, it could impact SWEPCo’s proposal to build the Turk Plant.

If SWEPCo does not receive appropriate authorizations and permits to build the Turk Plant, SWEPCo could incur significant cancellation fees to terminate its commitments and would be responsible to reimburse OMPA, AECC and ETEC for their share of paid costs.  If that occurred, SWEPCo would seek recovery of its capitalized costs including any cancellation fees and joint owner reimbursements.  As of JuneSeptember 30, 2008, including the joint owners’ share, SWEPCo has capitalized approximately $407$448 million of expenditures and has significant contractual construction commitments for an additional $815$771 million.  As of JuneSeptember 30, 2008, if the plant had been canceled,cancelled, SWEPCo would have incurred cancellation fees of $60 million would have been required in order to terminate these construction commitments.$61 million.  If the Turk Plant does not receive all necessary approvals on reasonable terms and SWEPCo cannot recover its capitalized costs, including any cancellation fees, it would have an adverse effect on future results of operations,net income, cash flows and possibly financial condition.

Stall Unit

See “Stall Unit” section within Louisiana Rate Matters for disclosure.

FERC Rate Matters

Regional Transmission Rate Proceedings at the FERC

SECA Revenue Subject to Refund

Effective December 1, 2004, AEP eliminated transaction-based through-and-out transmission service (T&O) charges in accordance with FERC orders and collected at 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 31, 2006.  Intervenors objected to the temporary SECA rates, raising various issues.  As a result, the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund.  The AEP East companies paid SECA rates to other utilities at considerably lesser amounts than they collected.  If a refund is ordered, the AEP East companies would also receive refunds related to the SECA rates they paid to third parties.  The AEP East companies recognized gross SECA revenues of $220 million from December 2004 through March 2006 when the SECA rates terminated leaving the AEP East companies and ultimately their internal load retail customers to make up the short fall in revenues.

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

In September 2006, AEP filed briefs jointly with other affected companies noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part.  Management believes, based on advice of legal counsel, that the FERC should reject the ALJ’s initial decision because it contradicts prior related FERC decisions, which are presently subject to rehearing.  Furthermore, management believes the ALJ’s findings on key issues are largely without merit.  AEP and SECA ratepayers have engaged in settlement discussions in an effort to settle the SECA issue.  However, if the ALJ’s initial decision is upheld in its entirety, it could result in a disallowance of a large portion on any unsettled SECA revenues.

During 2006, based on anticipated settlements, the AEP East companies provided reserves of $37 million for net refunds for current and future SECA settlements.  After reviewing existing settlements the AEP East companies increased their reserves by an additionaltotaling $37 million and $5 million in December 2007.

Completed2006 and in-process settlements cover $107 million2007, respectively, applicable to a total of the $220 million of SECA revenues and will consume aboutrevenues.  AEP has completed settlements totaling $7 million applicable to $75 million of SECA revenues.  The balance in the reserve for refund, leaving approximately $113future settlements as of September 2008 was $35 million.  In-process settlements total $3 million applicable to $37 million of SECA revenues.  Management believes that the available $32 million of reserves for possible refunds are sufficient to settle the remaining $108 million of contested SECA revenues and $35 million of refund reserves.revenues.

If the FERC adopts the ALJ’s decision and/or AEP cannot settle all of the remaining unsettled claims within the remaining amount reserved for refunds,refund, it will have an adverse effect on future results of operationsnet income and cash flows.  Based on advice of external FERC counsel, recent settlement experience and the expectation that most of the unsettled SECA revenues will be settled, management believes that the remaining reserve of $35$32 million is adequate to cover all remaining settlements.  However, management cannot predict the ultimate outcome of ongoing settlement discussions or future FERC proceedings or court appeals, if such are necessary.

The FERC PJM Regional Transmission Rate Proceeding

With the elimination of T&O rates, and the expiration of SECA rates and after considerable administrative litigation at the FERC in which AEP sought to mitigate the effect of the T&O rate elimination, the FERC failed to implement a regional rate in PJM.  As a result, the AEP East companies’ retail customers incur the bulk of the cost of the existing AEP east transmission zone facilities.  However, the FERC ruled that the cost of any new 500 kV and higher voltage transmission facilities built in PJM would be shared by all customers in the region.  It is expected that most of the new 500 kV and higher voltage transmission facilities will be built in other zones of PJM, not AEP’s zone.  The AEP East companies will need to obtain regulatory approvals for recovery of any costs of new facilities that are assigned to them.  AEP had requested rehearing of this order, which the FERC denied.  In February 2008, AEP filed a Petition for Review of the FERC orders in this case in the United States Court of Appeals.  Management cannot estimate at this time what effect, if any, this order will have on the AEP East companies’ future construction of new transmission facilities, results of operationsnet income and cash flows.

The AEP East companies filed for and in 2006 obtained increases in itstheir wholesale transmission rates to recover lost revenues previously applied to reduce those rates.  AEP has also sought and received retail rate increases in Ohio, Virginia, West Virginia and Kentucky.  As a result, AEP is now recovering approximately 85%80% of the lost T&O transmission revenues.  AEP received net SECA transmission revenues of $128 million in 2005.  I&M requested recovery of these lost revenues in its Indiana rate filing in January 2008 but does not expect to commence recovering the new rates until early 2009.  Future results of operationsnet income and cash flows will continue to be adversely affected in Indiana and Michigan until the remaining 15%20% of the lost T&O transmission revenues are recovered in retail rates.

The FERC PJM and MISO Regional Transmission Rate Proceeding

In the SECA proceedings, the FERC ordered the RTOs and transmission owners in the PJM/MISO region (the Super Region) to file, by August 1, 2007, a proposal to establish a permanent transmission rate design for the Super Region to be effective February 1, 2008.  All of the transmission owners in PJM and MISO, with the exception of AEP and one MISO transmission owner, elected to support continuation of zonal rates in both RTOs.  In September 2007, AEP filed a formal complaint proposing a highway/byway rate design be implemented for the Super Region where users pay based on their use of the transmission system.  AEP arguesargued the use of other PJM and MISO facilities by AEP is not as large as the use of AEP transmission by others in PJM and MISO.  Therefore, a regional rate design change is required to recognize that the provision and use of transmission service in the Super Region is not sufficiently uniform between transmission owners and users to justify zonal rates.  In January 2008, the FERC denied AEP’s complaint.  AEP filed a rehearing request with the FERC in March 2008.  Should this effort be successful, earnings could benefit for a certain period of time due to regulatory lag; however,lag until the AEP East companies would reduce future retail revenues in their next fuel or base rate proceedings.  Management is unable to predict the outcome of this case.

PJM Transmission Formula Rate Filing

In July 2008, AEP filed an application with the FERC to increase its rates for wholesale transmission service within PJM.PJM by $63 million annually.  The filing seeks to implement a formula rate allowing annual adjustments reflecting future changes in AEP's cost of service.  The requested increase would result in additional annual revenues of approximately $9 million from nonaffiliated customers within PJM.  The remaining $54 million requested would be billed to the AEP East companies to be recovered in retail rates.  Retail rates for jurisdictions other than Ohio are not affected until the next base rate filing at FERC.  Retail rates for CSPCo and OPCo would be adjusted through the Transmission Cost Recovery Rider (TCRR) totaling approximately $10 million and $12 million, respectively.  The TCRR includes a true-up mechanism so CSPCo’s and OPCo’s net income will not be adversely affected by a FERC ordered transmission rate increase.  Other jurisdictions would be recoverable on a lag basis as base rates are changed.  AEP requested an effective date of October 1, 2008.  Retail rates are not immediately affected by the filing atIn September 2008, the FERC but retail rates in Ohio would reflectissued an order conditionally accepting AEP’s proposed formula rate, subject to a compliance filing, suspended the revised FERC transmission rate through the Transmission Cost Recovery Rider (TCRR) effective Januarydate until March 1, 2009 resulting in additional annual revenues of approximately $22 million.and established a settlement proceeding with an ALJ.  Management is unable to predict the outcome of this filing.

FERC Market Power Mitigation

The FERC allows utilities to sell wholesale power at market-based rates if they can demonstrate that they lack market power in the markets in which they participate.  Sellers with market rate authority must, at least every three years, update their studies demonstrating lack of market power.  In December 2007, AEP filed its most recent triennial update.  In March and May 2008, the PUCO filed comments suggesting that the FERC should further investigate whether AEP continues to pass the FERC’s indicative screens for the lack of market power in PJM.  Certain industrial retail customers also urgedrequested the FERC to further investigate this matter.  AEP responded that its market power studies were performed in accordance with the FERC’s guidelines and continue to demonstrate lack of market power.  ManagementIn September 2008, the FERC issued an order accepting AEP’s market-based rates with minor changes and rejected the PUCO’s and the industrial retail customers’ suggestions to further investigate AEP’s lack of market power.

In an unrelated matter, in May 2008, the FERC issued an order in response to a complaint from the state of Maryland’s Public Service Commission to hold a future hearing to review the structure of the three pivotal market power supplier tests in PJM.  In September 2008, PJM filed a report on the results of the PJM stakeholder process concerning the three pivotal supplier market power tests which recommended the FERC not make major revisions to the test because the test is unable to predict the outcome of this proceeding; however,not unjust or unreasonable.

The FERC’s order will become final if no requests for rehearing are filed.  If a request for rehearing is filed and ultimately results in a further investigation by the FERC which limits AEP’s ability to sell power at market basedmarket-based rates in PJM, it would result in an adverse effect on future off-system sales margins results of operations and cash flows.

Allocation of Off-system Sales Margins

In 2004, intervenors and the OCC staff argued that AEP had inappropriately under-allocated off-system sales credits to PSO by $37 million for the period June 2000 to December 2004 under a FERC-approved allocation agreement.  An ALJ assigned to hear intervenor claims found that the OCC lacked authority to examine whether AEP deviated from the FERC-approved allocation methodology for off-system sales margins and held that any such complaints should be addressed at the FERC.  In October 2007, the OCC adopted the ALJ’s recommendation and orally directed the OCC staff to explore filing a complaint at the FERC alleging the allocation of off-system sales margins to PSO is not in compliance with the FERC-approved methodology which could result in an adverse effect on future net income and cash flows for AEP Consolidated, the AEP East companies and the AEP West companies.  In June 2008, the ALJ issued a final recommendation and incorporated the prior finding that the OCC lacked authority to review AEP’s application of a FERC-approved methodology.  In June 2008, the Oklahoma Industrial Energy Consumers appealed the ALJ recommendation to the OCC.  In August 2008, the OCC heard the appeal and a decision is pending.  See “PSO Fuel and Purchased Power” section within “Oklahoma Rate Matters”.  In August 2008, the OCC filed a complaint at the FERC alleging that AEPSC inappropriately allocated off-system trading margins between the AEP East companies and the AEP West companies and did not properly allocate off-system trading margins within the AEP West companies.  The PUCT, the APSC and the Oklahoma Industrial Energy Consumers have all intervened in this filing.

TCC, TNC and the PUCT have been involved in litigation in the federal courts concerning whether the PUCT has the right to order a reallocation of off-system sales margins thereby reducing recoverable fuel costs in the final fuel  reconciliation in Texas under the restructuring legislation.  In 2005, TCC and TNC recorded provisions for refunds after the PUCT ordered such reallocation.  After receipt of favorable federal court decisions and the refusal of the U.S. Supreme Court to hear a PUCT appeal of the TNC decision, TCC and TNC reversed their provisions of $16 million and $9 million, respectively, in the third quarter of 2007.

Management cannot predict the outcome of these proceedings.  However, management believes its allocations were in accordance with the then-existing FERC-approved allocation agreements and additional off-system sales margins should not be retroactively reallocated.  The results of these proceedings could have an adverse effect on future net income and cash flows for AEP Consolidated, the AEP East companies and the AEP West companies.

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 2007 Annual Report should be read in conjunction with this report.

GUARANTEES

There are certain immaterial liabilities recorded for guarantees in accordance with FASB Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”  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 (LOCs) with third parties.  These LOCs cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.  As the Parent, we issued all of these LOCs in our ordinary course of business on behalf of our subsidiaries.  At JuneSeptember 30, 2008, the maximum future payments for LOCs issued under the two $1.5 billion credit facilities are approximately $58$67 million with maturities ranging from AugustOctober 2008 to October 2009.  The two $1.5 billion credit facilities were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $46 million following its bankruptcy.

In April 2008, we entered into a $650 million 3-year credit agreement and a $350 million 364-day credit agreement.agreement which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23 million and $12 million, respectively, following its bankruptcy.  As of JuneSeptember 30, 2008, $371$372 million of letters of credit were issued by subsidiaries under the 3-year credit agreement to support variable rate demand notes.

Guarantees Of Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation in the amount of approximately $65 million.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), an entity consolidated under FIN 46R.  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 2029 with final reclamation completed by 2036, at an estimated cost of approximately $39 million.  As of JuneSeptember 30, 2008, SWEPCo has collected approximately $36$37 million through a rider for final mine closure costs, of which approximately $7 million is recorded in Other Current Liabilities, $8$5 million is recorded in Asset Retirement Obligations and $21$25 million is recorded in Deferred Credits and Other on our Condensed Consolidated Balance Sheets.

Sabine charges SWEPCo, its only customer, all its costs.  SWEPCo passes these costs 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 sales agreements is discussed in the 2007 Annual Report, “Dispositions” section of Note 8.  These sale agreements include indemnifications with a maximum exposure related to the collective purchase price, which is approximately $1.3 billion (approximately $1 billion relates to the Bank of America (BOA) litigation, see “Enron Bankruptcy” section of this note).  There are no material liabilities recorded for any indemnifications other than amounts recorded related to the BOA litigation.

Master Operating Lease

We lease certain equipment under a master operating lease.  Under the lease agreement, the lessor is guaranteed receipt of up to 87% of the unamortized balance of the equipment at the end of the lease term.  If the fair market 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 market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance.  Historically, at the end of the lease term the fair market value has been in excess of the unamortized balance.  At JuneSeptember 30, 2008, the maximum potential loss for these lease agreements was approximately $66 million ($43 million, net of tax) assuming the fair market value of the equipment is zero at the end of the lease term.

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease is accounted for as an operating lease.  We intend to maintain the lease for twenty years, via renewal options.  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 over the current lease term from approximately 84% to 77% of the projected fair market value of the equipment.

In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignment is accounted for as new operating leases for I&M and SWEPCo.  The future minimum lease obligation is $21$20 million for I&M and $24$23 million for SWEPCo as of JuneSeptember 30, 2008.  I&M and SWEPCo intend to renew these leases for the full remaining terms and have assumed the guarantee under the return-and-sale option.  I&M’s maximum potential loss related to the guarantee discussed above is approximately $12 million ($8 million, net of tax) and SWEPCo’s is approximately $14 million ($9 million, net of tax). assuming the fair market value of the equipment is zero at the end of the current lease term.  However, we believe that the fair market value would produce a sufficient sales price to avoid any loss.

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

CONTINGENCIES

Federal EPA Complaint and Notice of Violation

The Federal EPA, certain special interest groups and a number of states alleged that APCo, CSPCo, I&M and OPCo modified certain units at their coal-fired generating plants in violation of the NSR requirements of the CAA.  The alleged modifications occurred over a 20-year period.  Cases with similar allegations against CSPCo, Dayton Power and Light Company (DP&L) and Duke Energy Ohio, Inc. were also filed related to their jointly-owned units.

The AEP System settled their cases in 2007.  AIn October 2008, the court approved a consent decree for a settlement reached with the Sierra Club in a case is still pending that could affectinvolving CSPCo’s share of jointly-owned units at the Stuart Station.  The Stuart units, operated by DP&L, are equipped with SCR and flue gas desulfurization equipment (FGD or scrubbers) controls.  A trialUnder the terms of the settlement, the joint-owners agreed to certain emission targets related to NOx, SO2 and PM.  They also agreed to make energy efficiency and renewable energy commitments that are conditioned on liability issues was scheduledreceiving PUCO approval for August 2008.recovery of costs.  The Court issuedjoint-owners also agreed to forfeit 5,500 SO2 allowances and  provide $300 thousand to a staythird party organization to allow the parties to pursue settlement discussions.  Those discussions are ongoing.establish a solar water heater rebate program.  Another case involving a jointly-owned Beckjord unit had a liability trial in May 2008.  Following the trial, the jury found no liability for claims made against the jointly-owned Beckjord unit.

We are unable to estimate the loss or range of loss related to any contingent liability, if any, we might have for civil penalties under the pending CAA proceedings for our jointly-owned units.  If we do not prevail, we believe we can recover any capital and operating costs of additional pollution control equipment that may be required through market prices of electricity.  If we are unable to recover such costs or if material penalties are imposed, it would adversely affect our future results of operations, cash flows and possibly financial condition.

SWEPCo Notice of Enforcement and Notice of Citizen Suit

In March 2005, two special interest groups, Sierra Club and Public Citizen, filed a complaint in Federal District Courtfederal district court for the Eastern District of Texas alleging violations of the CAA at SWEPCo’s Welsh Plant.  In April 2008, the parties filed a proposed consent decree to resolve all claims in this case and in the pending appeal of the altered permit for the Welsh Plant.  The consent decree requires SWEPCo to install continuous particulate emission monitors at the Welsh Plant, secure 65 MW of renewable energy capacity by 2010, fund $2 million in emission reduction, energy efficiency or environmental mitigation projects by 2012 and pay a portion of plaintiffs’ attorneys’ fees and costs.  The consent decree was entered as a final order in June 2008.

In 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant.  In April 2005, TCEQ issued an Executive Director’s Report (Report) recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of approximately $228 thousand against SWEPCo.  In 2008, the matter was remanded to TCEQ to pursue settlement discussions.  The original Report contained a recommendation to limit the heat input on each Welsh unit to the referenced heat input contained within the state permit within 10 days of the issuance of a final TCEQ order and until the permit is changed.  SWEPCo had previously requested a permit alteration to remove the reference to a specific heat input value for each Welsh unit and to clarify the sulfur content requirement for fuels consumed at the plant.  A permit alteration was issued in March 2007.  In June 2007, TCEQ denied a motion to overturn the permit alteration.  The permit alteration was appealed to the Travis County District Court, but was resolved by entry of the consent decree in the federal citizen suit action, and dismissed with prejudice in July 2008.  Notice of an administrative settlement of the TCEQ enforcement action was published in June 2008.  The settlement requires SWEPCo to pay an administrative penalty of $49 thousand and to fund a supplemental environmental project in the amount of $49 thousand, and resolves all violations alleged by TCEQ.  The settlement will become final upon approval byIn October 2008, TCEQ approved the TCEQ.settlement.

In February 2008, the Federal EPA issued a Notice of Violation (NOV) based on alleged violations of a percent sulfur in fuel limitation and the heat input values listed in the previous state permit.  The NOV also alleges that the permit alteration issued by TCEQ was improper.  SWEPCo met with the Federal EPA to discuss the alleged violations in March 2008.  The Federal EPA did not object to the settlement of similar alleged violations in the federal citizen suit.

We are unable to predict the timing of any future action by the Federal EPA or the effect of such action on our results of operations,net income, cash flows or financial condition.

Carbon Dioxide (CO2) 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 dismissal of this lawsuit was appealed to the Second Circuit Court of Appeals.  Briefing and oral argument have concluded.  In April 2007, the U.S. Supreme Court issued a decision holding that the Federal EPA has authority to regulate emissions of CO2 and other greenhouse gases under the CAA, which may impact the Second Circuit’s analysis of these issues.  The Second Circuit requested supplemental briefs addressing the impact of the U.S. Supreme Court’s decision on this case.  We believe the actions are without merit and intend to defend against the claims.

Alaskan Villages’ Claims

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska  filed a lawsuit in federal court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil & 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.  The defendants filed motions to dismiss the action.  The motions are pending before the court.  We believe the action is without merit and intend to defend against the claims.

Clean Air Act Interstate Rule

In 2005, the Federal EPA issued a final rule, the Clean Air Interstate Rule (CAIR), that required further reductions in SO2 and NOx emissions and assists states developing new state implementation plans to meet 1997 national ambient air quality standards (NAAQS).  CAIR reduces regional emissions of SO2 and NOx (which can be transformed into PM and ozone) from power plants in the Eastern U.S. (29 states and the District of Columbia).  Reduction of both SO2 and NOx would be achieved through a cap-and-trade program.  In July 2008, the D.C. Circuit Court of Appeals vacatedissued a decision that would vacate the CAIR and remandedremand the rule to the Federal EPA.  In September 2008, the Federal EPA and other parties petitioned for rehearing.  We are unable to predict the outcome of the rehearing petitions or how the Federal EPA will respond to the remand which could be stayed or appealed to the U.S. Supreme Court.

In anticipation of compliance with CAIR in 2009, I&M purchased $8$9 million of annual CAIR NOx  allowances which are included in inventoryDeferred Charges and Other on our Condensed Consolidated Balance Sheet as of JuneSeptember 30, 2008.  The market value of annual CAIR NOx allowances decreased in the weeks following this court decision.  ManagementHowever, our weighted-average cost of these allowances is below market.  If CAIR remains vacated, management intends to seek partial recovery of the cost of purchased allowances.  If the recovery is denied, itAny unrecovered portion would have an adverse effect on future results of operationsnet income and cash flows.  None of AEP’s other subsidiaries purchased any significant number of CAIR allowances.  SO2 and seasonal NOx allowances allocated to our facilities under the Acid Rain Program and the NOx SIPstate implementation plan (SIP) Call will still be required to comply with existing CAA programs that were not affected by the court’s decision.

It is too early to determine the full implication of these decisions on environmental compliance strategy.  However, independent obligations under the CAA, including obligations under future state implementation plan submittals, and actions taken pursuant to the recent settlement of the NSR enforcement action, are consistent with the actions included in a least-cost CAIR compliance plan.  Consequently, management does not anticipate making any immediate changes in near-term compliance plans as a result of these court decisions.

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 (PCBs) and other hazardous and nonhazardous materials.  We currently incur costs to safely dispose of these substances.

Superfund addresses clean-up of hazardous substances that have been released to the environment.  The Federal EPA administers the clean-up programs.  Several states have enacted similar laws.  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 requested remediation proposals from environmental consulting firms.  In May 2008, I&M issued a contract to one of the consulting firms andfirms.  I&M recorded approximately $1$4 million of expense.expense through September 30, 2008.  As the remediation work is completed, I&M’s cost may increase.  I&M cannot predict the amount of additional cost, if any.  At present, our estimates do not anticipate material cleanup costs for this site.

Cook Plant Unit 1 Fire and Shutdown

Cook Plant Unit 1 (Unit 1) is a 1,030 MW nuclear generating unit located in Bridgman, Michigan. In September 2008, I&M shut down Unit 1 due to turbine vibrations likely caused by blade failure which resulted in a fire on the electric generator.  This equipment is in the turbine building and is separate and isolated from the nuclear reactor.  The steam turbines that caused the vibration were installed in 2006 and are under warranty from the vendor.  The warranty provides for the replacement of the turbines if the damage was caused by a defect in the design or assembly of the turbines.  I&M is also working with its insurance company, Nuclear Electric Insurance Limited (NEIL), and turbine vendor to evaluate the extent of the damage resulting from the incident and the costs to return the unit to service.  We cannot estimate the ultimate costs of the outage at this time.  Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process.  Our preliminary analysis indicates that Unit 1 could resume operations as early as late first quarter/early second quarter of 2009 or as late as the second half of 2009, depending upon whether the damaged components can be repaired or whether they need to be replaced.
I&M maintains property insurance through NEIL with a $1 million deductible.  I&M also maintains a separate accidental outage policy with NEIL whereby, after a 12 week deductible period, I&M is entitled to weekly payments of $3.5 million during the outage period for a covered loss.  If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if the unit is not returned to service in a reasonable period of time, it could have an adverse impact on net income, cash flows and financial condition.
TEM Litigation

We agreed to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) (now known as SUEZ Energy Marketing NA, Inc.) for a period of 20 years under a Power Purchase and Sale Agreement (PPA).  Beginning May 1, 2003, we tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming.

In 2003, TEM and AEP separately filed declaratory judgment actions in the United States District Court for the Southern District of New York.  We alleged that TEM breached the PPA and sought a determination of our rights under the PPA.  TEM alleged that the PPA never became enforceable, or alternatively, that the PPA was terminated as the result of our breaches.

In January 2008, we reached a settlement with TEM to resolve all litigation regarding the PPA.  TEM paid us $255 million.  We recorded the $255 million as a pretax gain in January 2008 under Asset Impairments and Other Related ItemsCharges on our Condensed Consolidated Statements of Income.  This settlement and the PPA related to the Plaquemine Cogeneration Facility which was impaired and sold in 2006.

Enron Bankruptcy

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

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

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

In August 2007, the judge in the New York action issued a decision granting BOA summary judgment and dismissing our claims.  In December 2007, the judge held that BOA is entitled to recover damages of approximately $347 million ($437 million and $427427 million including interest at June 30, 2008 and December 31, 2007, respectively)2007).  In August 2008, the court entered a final judgment of $346 million (the original judgment less a to be determined amount$1 million BOA would have incurred to remove 55 BCF of natural gas from the Bammel storage facility.  The judge denied our Motion for Reconsideration.facility) and clarified the interest calculation method.  We plan to appeal the court’s decision once the court entersappealed and posted a final judgment.  If the Court enters a final judgment adverse to us and we appeal from the judgment, we will be required under court rules to post security in the form of a bond or stand-by letter of credit covering the amount of the judgment entered against us.

In 2005, we sold our interest in HPL.  We indemnified the buyer of HPL against any damages resulting from the BOA litigation up to the purchase price.  After recalculation for the final judgment, the liability for the BOA litigation was $431 million at September 30, 2008.  The amounts discussed aboveliability for the BOA litigation was $427 million at December 31, 2007. These liabilities are included in Deferred Credits and Other on our Condensed Consolidated Balance Sheets.

Shareholder Lawsuits

In 2002 and 2003, three putative class action lawsuits were filed against AEP, certain executives and AEP’s Employee Retirement Income Security Act (ERISA) Plan Administrator alleging violations of ERISA in the selection of AEP stock as an investment alternative and in the allocation of assets to AEP stock.  The ERISA actions were pending in Federal District Court, Columbus, Ohio.  In these actions, the plaintiffs sought recovery of an unstated amount of compensatory damages, attorney fees and costs.  Two of the three actions were dropped voluntarily by the plaintiffs in those cases.  In July 2006, the Courtcourt entered judgment in the remaining case, denying plaintiff’s motion for class certification and dismissing all claims without prejudice.  In August 2007, the appeals court reversed the trial court’s decision and held that the plaintiff did have standing to pursue his claim.  The appeals court remanded the case to the trial court to consider the issue of whether the plaintiff is an adequate representative for the class of plan participants.  In September 2008, the trial court denied the plaintiff’s motion for class certification and ordered briefing on whether the plaintiff may maintain an ERISA claim on behalf of the Plan in the absence of class certification.  In October 2008, Counsel for the plaintiff filed a motion to intervene on behalf of an individual seeking to intervene as a new plaintiff.  We intend to oppose this motion and continue to defend against these claims.

Natural Gas Markets Lawsuits

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

Rail Transportation Litigation

In October 2008, the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsville, Texas, as co-owners of Oklaunion Plant, filed a lawsuit in United States District Court, Western District of Oklahoma against AEP alleging breach of contract and breach of fiduciary duties related to negotiations for rail transportation services for the plant.  The plaintiffs allege that AEP took the duty of the project manager, PSO, and operated the plant for the project manager and is therefore responsible for the alleged breaches.  We intend to vigorously defend against these allegations.

FERC Long-term Contracts

In 2002, the FERC held a hearing related to a complaint filed by Nevada Power Company and Sierra Pacific Power Company (the Nevada utilities).  The complaint sought to break long-term contracts entered during the 2000 and 2001 California energy price spike which the customers alleged were “high-priced.”  The complaint alleged that we sold power at unjust and unreasonable prices because the market for power was allegedly dysfunctional at the time such contracts were executed.  In 2003, the FERC rejected the complaint.  In 2006, the U.S. Court of Appeals for the Ninth Circuit reversed the FERC order and remanded the case to the FERC for further proceedings.  That decision was appealed to the U.S. Supreme Court.  In June 2008, the U.S. Supreme Court affirmed the validity of contractually-agreed rates except in cases of serious harm to the public.  The U.S. Supreme Court affirmed the Ninth Circuit’s remand on two issues, market manipulation and excessive burden on consumers.  Management is unable to predict the outcome of these proceedings or their impact on future results of operationsnet income and cash flows.  We have asserted claims against certain companies that sold power to us, which we resold to the Nevada utilities, seeking to recover a portion of any amounts we may owe to the Nevada utilities.

5.ACQUISITIONS, DISPOSITIONS AND DISCONTINUED OPERATIONS

ACQUISITIONS

2008

Erlbacher companies (MEMCO(AEP River Operations segment)

In June 2008, MEMCOAEP River Operations purchased certain barging assets from Missouri Barge Line Company, Missouri Dry Dock and Repair Company and Cape Girardeau Fleeting, Inc. (collectively known as Erlbacher companies) for $35 million.  These assets were incorporated into MEMCO’s operationsAEP River Operations’ business which will diversify its customer base.

2007

Darby Electric Generating Station (Utility Operations segment)

In November 2006, CSPCo agreed to purchase Darby Electric Generating Station (Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light Company, for $102 million and the assumption of liabilities of $2 million.  CSPCo completed the purchase in April 2007.  The Darby plant is located near Mount Sterling, Ohio and is a natural gas, simple cycle power plant with a generating capacity of 480 MW.

Lawrenceburg Generating Station (Utility Operations segment)

In January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station (Lawrenceburg) from an affiliate of Public Service Enterprise Group (PSEG) for $325 million and the assumption of liabilities of $3 million.  AEGCo completed the purchase in May 2007.  The Lawrenceburg plant is located in Lawrenceburg, Indiana, adjacent to I&M’s Tanners Creek Plant, and is a natural gas, combined cycle power plant with a generating capacity of 1,096 MW.  AEGCo sells the power to CSPCo through a FERC-approved unit power agreement.

Dresden Plant (Utility Operations segment)

In August 2007, AEGCo agreed to purchase the partially completed Dresden Plant from Dominion Resources, Inc. for $85 million and the assumption of liabilities of $2 million.  AEGCo completed the purchase in September 2007.  As of September 30, 2008, AEGCo has incurred approximately $53 million in construction costs (excluding AFUDC) at the Dresden Plant and expects to incur approximately $169 million in additional costs (excluding AFUDC) prior to completion in 2010.  The projected completion date of the Dresden Plant is currently under review.  To the extent that the completion of the Dresden Plant is delayed, the total projected cost of the Dresden Plant could change.  The Dresden Plant is located near Dresden, Ohio and is a natural gas, combined cycle power plant.  When completed, the Dresden Plant will have a generating capacity of 580 MW.

DISPOSITIONS

2008

None

2007

Texas Plants – Oklaunion Power Station (Utility Operations segment)

In February 2007, TCC sold its 7.81% share of Oklaunion Power Station to the Public Utilities Board of the City of Brownsville for $43 million plus working capital adjustments.  The sale did not have an impact on our results of operationsnet income nor do we expect any remaining litigation to have a significant effect on our results of operations.net income.

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

In March 2007, we sold 130,000 shares of ICE and recognized a $16 million pretax gain ($10 million, net of tax).  We recorded the gain in Interest and Investment Income on our 2007 Condensed Consolidated Statement of Income.  Our remaining investment of approximately 138,000 shares at JuneSeptember 30, 2008 and December 31, 2007 is recorded in Other Temporary Investments on our Condensed Consolidated Balance Sheets.

Texas REPs (Utility Operations segment)

As part of the purchase-and-sale agreement related to the sale of our Texas REPs in 2002, we retained the right to share in earnings with Centrica from the two REPs above a threshold amount through 2006 if the Texas retail market developed increased earnings opportunities.  In 2007, we received the final earnings sharing payment of $20 million.  This payment is reflected in Gain on Disposition of Assets, Net on our Condensed Consolidated Statement of Income.

Sweeny Cogeneration Plant (Generation and Marketing segment)

In October 2007, we sold our 50% equity interest in the Sweeny Cogeneration Plant (Sweeny) to ConocoPhillips for approximately $80 million, including working capital and the buyer’s assumption of project debt.  The Sweeny Cogeneration Plant is a 480 MW cogeneration plant located within ConocoPhillips’ Sweeny refinery complex southwest of Houston, Texas.  We were the managing partner of the plant, which is co-owned by General Electric Company.  As a result of the sale, we recognized a $47 million pretax gain ($30 million, net of tax) in the fourth quarter of 2007, which is reflected in Gain on Disposition of Equity Investments, Net on our 2007 Consolidated Statement of Income.

In addition to the sale of our interest in Sweeny, we agreed to separately sell our purchase power contract for our share of power generated by Sweeny through 2014 for $11 million to ConocoPhillips. ConocoPhillips also agreed to assume certain related third-party power obligations.  These transactions were completed in conjunction with the sale of our 50% equity interest in October 2007.  As a result of this sale, we recognized an $11 million pretax gain ($7 million, net of tax) in the fourth quarter of 2007, which is included in Other revenues on our 2007 Consolidated Statement of Income.  In the fourth quarter of 2007, we recognized a total of $58 million in pretax gains ($37 million, net of tax).

DISCONTINUED OPERATIONS

We determined that certain of our operations were discontinued operations and classified them as such for all periods presented.  We recorded the following in 2008 and 2007 related to discontinued operations:

  
U.K.
Generation (a)
 
Three Months Ended JuneSeptember 30, (in millions) 
2008 Revenue $- 
2008 Pretax Income  2- 
2008 Earnings, Net of Tax  1- 
     
2007 Revenue $- 
2007 Pretax Income  3- 
2007 Earnings, Net of Tax  2- 

  
U.K.
Generation (a)
 
SixNine Months Ended JuneSeptember 30, (in millions) 
2008 Revenue $- 
2008 Pretax Income  2 
2008 Earnings, Net of Tax  1 
     
2007 Revenue $- 
2007 Pretax Income  3 
2007 Earnings, Net of Tax  2 

(a)The 2008 amounts relate to final proceeds received for the sale of land related to the sale of U.K. Generation.  The 2007 amounts relate to tax adjustments from the sale of U.K. Generation.

There were no cash flows used for or provided by operating, investing or financing activities related to our discontinued operations for the sixnine months ended JuneSeptember 30, 2008 and 2007.

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 sixnine months ended JuneSeptember 30, 2008 and 2007:
  Other Postretirement   Other Postretirement 
Pension Plans Benefit Plans Pension Plans Benefit Plans 
Three Months Ended June 30, Three Months Ended June 30, Three Months Ended September 30, Three Months Ended September 30, 
2008 2007 2008 2007 2008 2007 2008 2007 
(in millions) (in millions) 
Service Cost$25 $23 $11 $11  $25  $24  $10  $11 
Interest Cost 62  57  28  26   62   59   28   26 
Expected Return on Plan Assets (84) (82) (28) (26)  (84)  (85)  (27)  (26)
Amortization of Transition Obligation -  -  7  7   -   -   7   6 
Amortization of Net Actuarial Loss 10  14  2  3   10   15   3   3 
Net Periodic Benefit Cost$13 $12 $20 $21  $13  $13  $21  $20 

  Other Postretirement   Other Postretirement 
Pension Plans Benefit Plans Pension Plans Benefit Plans 
Six Months Ended June 30, Six Months Ended June 30, Nine Months Ended September 30, Nine Months Ended September 30, 
2008 2007 2008 2007 2008 2007 2008 2007 
(in millions) (in millions) 
Service Cost$50 $47 $21 $21  $75  $72  $31  $32 
Interest Cost 125  116  56  52   187   176   84   78 
Expected Return on Plan Assets (168) (167) (56) (52)  (252)  (254)  (83)  (78)
Amortization of Transition Obligation -  -  14  14   -   -   21   20 
Amortization of Net Actuarial Loss 19  29  5  6   29   44   8   9 
Net Periodic Benefit Cost$26 $25 $40 $41  $39  $38  $61  $61 

We have significant investments in several trust funds to provide for future pension and OPEB payments.  All of our trust funds’ investments are well-diversified and managed in compliance with all laws and regulations.  The value of the investments in these trusts has declined due to the decreases in the equity and fixed income markets.  Although the asset values are currently lower, this decline has not affected the funds’ ability to make their required payments.

7.BUSINESS SEGMENTS

As outlined in our 2007 Annual Report, our primary business strategy and the core of our business are to focus on 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.  Generation/supply in Ohio continues to have commission-determined rates transitioning from cost-based to market-based rates.   The legislature in Ohio is currently considering possibly returning to some form of cost-based rate-regulation or a hybrid form of rate-regulation for generation.  While our Utility Operations segment remains our primary business segment, other segments include our MEMCOAEP River Operations segment with significant barging activities and our Generation and Marketing segment, which includes our nonregulated generating, marketing and risk management activities in the ERCOT market area.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

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

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

MEMCOAEP River Operations
·Barging operations that annually transport approximately 35 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.  Approximately 39% of the barging is for transportation of agricultural products, 30% for coal, 14% for steel and 17% for other commodities.  Effective July 30, 2008, AEP MEMCO LLC'sLLC’s name was changed to AEP River Operations LLC.

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

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

·Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
·Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005.  These contracts are financial derivatives which will gradually liquidate and completely expire in 2011.
·The first quarter 2008 cash settlement of a purchase power and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006.
·Revenue sharing related to the Plaquemine Cogeneration Facility.

The tables below present our reportable segment information for the three and sixnine months ended JuneSeptember 30, 2008 and 2007 and balance sheet information as of JuneSeptember 30, 2008 and December 31, 2007.  These amounts include certain estimates and allocations where necessary. We reclassified prior year amounts to conform to the current year’s segment presentation.  See “FSP FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1)” section of Note 2 for discussion of changes in netting certain balance sheet amounts.

   Nonutility Operations          Nonutility Operations       
 Utility Operations 
MEMCO
Operations
 
Generation
and
Marketing
 All Other (a) Reconciling Adjustments Consolidated  Utility Operations 
AEP River 
Operations
 
Generation
and
Marketing
 All Other (a) Reconciling Adjustments Consolidated 
 (in millions) (in millions)
Three Months Ended June 30, 2008               
Three Months Ended September 30, 2008              
Revenues from:Revenues from:                             
External Customers $3,200(d)$144 $137 $65 $- $3,546 
Other Operating Segments  113(d) 7  (26) (57) (37) - 
External Customers $4,108 (d)$160 $1 $(78)$- $4,191 
Other Operating Segments  (140)(d) 7  95  83  (45) - 
Total RevenuesTotal Revenues $3,313 $151 $111 $8 $(37)$3,546  $3,968 $167 $96 $5 $(45)$4,191 
                             
Income (Loss) Before Discontinued Operations and Extraordinary LossIncome (Loss) Before Discontinued Operations and Extraordinary Loss $263 $3 $26 $(12)$- $280  $357 $11 $16 $(10)$- $374 
Discontinued Operations, Net of TaxDiscontinued Operations, Net of Tax  -  -  -  1  -  1   -  -  -  -   -  - 
Net Income (Loss)Net Income (Loss) $263 $3 $26 $(11)$- $281  $357 $11 $16 $(10)$- $374 

    Nonutility Operations       
  Utility Operations 
MEMCO
Operations
 
Generation
and
Marketing
 All Other (a) Reconciling Adjustments Consolidated 
  (in millions)
Three Months Ended June 30, 2007                   
Revenues from:                   
 External Customers $2,818(d)$116 $218 $(6)$- $3,146 
 Other Operating Segments  136(d) 3  (113) 12  (38) - 
Total Revenues $2,954 $119 $105 $6 $(38)$3,146 
                    
Income (Loss) Before Discontinued   Operations and Extraordinary Loss $238 $7 $15 $(3)$- $257 
Discontinued Operations, Net of Tax  -  -  -  2  -  2 
Extraordinary Loss, Net of Tax  (79) -  -  -  -  (79)
Net Income (Loss) $159 $7 $15 $(1)$- $180 
    Nonutility Operations       
  Utility Operations 
AEP River 
Operations
 
Generation
and
Marketing
 All Other (a) Reconciling Adjustments Consolidated 
  (in millions)
Three Months Ended September 30, 2007                   
Revenues from:                   
External Customers $3,423(d)$134 $241 $(9)$- $3,789 
Other Operating Segments  177(d) 4  (161) 19  (39) - 
Total Revenues $3,600 $138 $80 $10 $(39)$3,789 
                    
Net Income (Loss) $388 $18 $3 $(2)$- $407 

    Nonutility Operations       
  Utility Operations 
MEMCO
Operations
 
Generation
and
Marketing
 All Other (a) Reconciling Adjustments Consolidated 
  (in millions)
Six Months Ended June 30, 2008                   
Revenues from:                   
 External Customers $6,210(d)$282 $408 $113 $- $7,013 
 Other Operating Segments  397(d) 11  (238) (100) (70) - 
Total Revenues $6,607 $293 $170 $13 $(70)$7,013 
                    
Income Before Discontinued Operations
  and Extraordinary Loss
 $673 $10 $27 $143 $- $853 
Discontinued Operations, Net of Tax  -  -  -  1  -  1 
Net Income $673 $10 $27 $144 $- $854 
   Nonutility Operations          Nonutility Operations       
 Utility Operations 
MEMCO
Operations
 
Generation
and
Marketing
 All Other (a) Reconciling Adjustments Consolidated  Utility Operations 
AEP River 
Operations
 
Generation
and
Marketing
 All Other (a) Reconciling Adjustments Consolidated 
 (in millions) (in millions)
Six Months Ended June 30, 2007               
Nine Months Ended September 30, 2008              
Revenues from:Revenues from:                             
External Customers $5,704(d)$233 $333 $45 $- $6,315 
Other Operating Segments 283(d) 6 (186) (33) (70) - 
External Customers $10,318(d)$442 $409 $35 $- $11,204 
Other Operating Segments  257(d) 18  (143) (17) (115) - 
Total RevenuesTotal Revenues $5,987 $239 $147 $12 $(70)$6,315  $10,575 $460 $266 $18 $(115)$11,204 
                             
Income Before Discontinued Operations
and Extraordinary Loss
Income Before Discontinued Operations
and Extraordinary Loss
 $491 $22 $14 $1 $- $528  $1,030 $21 $43 $133 $- $1,227 
Discontinued Operations, Net of TaxDiscontinued Operations, Net of Tax -  - - 2 -  2   -  -  -  1  -  1 
Extraordinary Loss, Net of Tax  (79) -  -  -  -  (79)
Net IncomeNet Income $412 $22 $14 $3 $- $451  $1,030 $21 $43 $134 $- $1,228 

    Nonutility Operations       
  Utility Operations 
MEMCO
Operations
 
Generation
and
Marketing
 All Other (a) 
Reconciling Adjustments
(c)
 Consolidated 
  (in millions) 
June 30, 2008                   
Total Property, Plant and Equipment $46,776 $302 $576 $42 $(245)$47,451 
Accumulated Depreciation and
  Amortization
  16,266  66  126  7  (18) 16,447 
Total Property, Plant and Equipment – Net $30,510 $236 $450 $35 $(227)$31,004 
                    
Total Assets $41,519 $374 $953 $13,182 $(13,332)(b)$42,696 

    Nonutility Operations       
  Utility Operations 
AEP River 
Operations
 
Generation
and
Marketing
 All Other (a) Reconciling Adjustments Consolidated 
  (in millions)
Nine Months Ended September 30, 2007                   
Revenues from:                   
 External Customers $9,127(d)$367 $574 $36 $- $10,104 
 Other Operating Segments  460(d) 10  (347) (14) (109) - 
Total Revenues $9,587 $377 $227  22  (109)$10,104 
                    
Income (Loss) Before Discontinued Operations and Extraordinary Loss $879 $40 $17 $(1)$- $935 
Discontinued Operations, Net of Tax  -  -  -  2  -  2 
Extraordinary Loss, Net of Tax  (79) -  -  -  -  (79)
Net Income $800 $40 $17 $1 $- $858 

   Nonutility Operations          Nonutility Operations       
 Utility Operations 
MEMCO
Operations
 
Generation
and
Marketing
 All Other (a) 
Reconciling Adjustments
(c)
 Consolidated  Utility Operations 
AEP River 
Operations
 
Generation
and
Marketing
 All Other (a) 
Reconciling Adjustments
(c)
 Consolidated 
December 31, 2007 (in millions) 
 (in millions) 
September 30, 2008              
Total Property, Plant and Equipment $45,514 $263 $567 $38 $(237)$46,145  $47,699 $316 $577 $45 $(245)$48,392 
Accumulated Depreciation and
Amortization
  16,107  61  112  7  (12) 16,275   16,413  69  133  8  (20) 16,603 
Total Property, Plant and Equipment – Net $29,407 $202 $455 $31 $(225)$29,870  $31,286 $247 $444 $37 $(225)$31,789 
                             
Total Assets $39,298 $340 $697 $12,117 $(12,133)(b)$40,319  $41,322 $380 $771 $13,905  $(13,340)(b)$43,038 

    Nonutility Operations       
  Utility Operations 
AEP River 
Operations
 
Generation
and
Marketing
 All Other (a) 
Reconciling Adjustments
(c)
 Consolidated 
December 31, 2007 (in millions) 
Total Property, Plant and Equipment $45,514 $263 $567 $38 $(237)$46,145 
Accumulated Depreciation and Amortization  16,107  61  112  7  (12) 16,275 
Total Property, Plant and Equipment – Net $29,407 $202 $455 $31 $(225)$29,870 
                    
Total Assets $39,298 $340 $697 $12,117 $(12,133)(b)$40,319 

(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 will gradually liquidate and completely expire in 2011.
 ·The first quarter 2008 cash settlement of a purchase power and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006.  The cash settlement of $255 million ($163 million, net of tax) is included in Net Income.
 ·Revenue sharing related to the Plaquemine Cogeneration Facility.
(b)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.
(c)Includes eliminations due to an intercompany capital lease.
(d)PSO and SWEPCo transferred certain existing ERCOT energy marketing contracts to AEP Energy Partners, Inc. (AEPEP) (Generation and Marketing segment) and entered into intercompany financial and physical purchase and sales agreements with AEPEP.  As a result, we reported third-party net purchases or sales activity for these energy marketing contracts as a reduction of Revenues from External Customers for the Utility Operations segment.  This is offset by the Utility Operations segment’s related net sales (purchases)  for these contracts to AEPEP in Revenues from Other Operating Segments of $26$(95) million and $113$161 million for the three months ended JuneSeptember 30, 2008 and 2007, respectively, and $238$143 million and $186$347 million for the sixnine months ended JuneSeptember 30, 2008 and 2007, respectively.  The Generation and Marketing segment also reports purchases related to these purchase or sales contracts with Utility Operations as a reduction to Revenues from Other Operating segments.Segments.

8.     INCOME TAXES

We adopted FIN 48 as of January 1, 2007.  As a result, we recognized an increase in liabilities for unrecognized tax benefits, as well as related interest and penalties, which was accounted for as a reduction to the January 1, 2007 balance of retained earnings.

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 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 2000.  However, we have filed refund claims with the IRS for years 1997 through 2000 for the CSW pre-merger tax period, which are currently being reviewed.  We have completed the exam for the years 2001 through 2003 and have issues that will be pursuedwe are pursuing at the appeals level.  The returns for the years 2004 through 2006 are presently under audit by the IRS.  Although the outcome of tax audits is uncertain, in management’s opinion adequate provisions for income taxes have been made for potential liabilities resulting from such matters.  In addition, we accrue interest on these uncertain tax positions.  We are not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations.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.  However, management does not believe that the ultimate resolution of these audits will materially impact results of operations.net income.  With few exceptions, we are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2000.

Federal Tax Legislation

In 2005, the Energy Tax Incentives Act of 2005 was signed into law.  This act created a limited amount of tax credits for the building of IGCC plants.  The credit is 20% of the eligible property in the construction of a new plant or 20% of the total cost of repowering of an existing plant using IGCC technology.  In the case of a newly constructed IGCC plant, eligible property is defined as the components necessary for the gasification of coal, including any coal handling and gas separation equipment.  We announced plans to construct two new IGCC plants that may be eligible for the allocation of these credits.  We filed applications for the West Virginia and Ohio IGCC projects with the DOE and the IRS.  Both projects were certified by the DOE and qualified by the IRS.  However, neither project was awardedallocated credits during the first round of credit awards.  After one of the original credit recipients surrendered their credits in the Fall of 2007, the IRS announced a supplemental credit round for the Spring of 2008.   We filed a new application in 2008 for the West Virginia IGCC project and in July 2008 the IRS awardedallocated the project $134 million in credits subject to enteringcredits.  In September 2008, we entered into a memorandum of understanding with the IRS.IRS concerning the requirements of claiming the credits.

In October 2008, the Emergency Economic Stabilization Act of 2008 (the Act) was signed into law.  The Act extended several expiring tax provisions and added new energy incentive provisions. The legislation impacted the availability of research credits, accelerated depreciation of smart meters, production tax credits and energy efficient commercial building deductions.  We have evaluated the impact of the law change and the application of the law change will not materially impact our net income, cash flows or financial condition.

State Tax Legislation

In March 2008, the Governor of West Virginia signed legislation providing for, among other things, a reduction in the West Virginia corporate income tax rate from 8.75% to 8.5% beginning in 2009.  The corporate income tax rate could also be reduced to 7.75% in 2012 and 7% in 2013 contingent upon the state government achieving certain minimum levels of shortfall reserve funds.  We have evaluated the impact of the law change and the application of the law change will not materially impact our results of operations,net income, cash flows or financial condition.


9.   FINANCING ACTIVITIES

Long-term Debt
 June 30,  December 31,  September 30,  December 31, 
Type of Debt 2008  2007  2008  2007 
 (in millions)  (in millions) 
Senior Unsecured Notes $10,940  $9,905  $11,186  $9,905 
Pollution Control Bonds  1,747   2,190   1,817   2,190 
First Mortgage Bonds  -   19   -   19 
Notes Payable  258   311   244   311 
Securitization Bonds  2,183   2,257   2,132   2,257 
Junior Subordinated Debentures  315   -   315   - 
Notes Payable To Trust  113   113   113   113 
Spent Nuclear Fuel Obligation (a)  262   259   264   259 
Other Long-term Debt  3   2   2   2 
Unamortized Discount (net)  (68)  (62)  (66)  (62)
Total Long-term Debt Outstanding  15,753   14,994   16,007   14,994 
Less Portion Due Within One Year  569   792   682   792 
Long-term Portion $15,184  $14,202  $15,325  $14,202 

(a)Pursuant to the Nuclear Waste Policy Act of 1982, I&M (a nuclear licensee) has an obligation to the United States Department of Energy for spent nuclear fuel disposal.  The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983.  Trust fund assets related to this obligation of $294$297 million and $285 million at JuneSeptember 30, 2008 and December 31, 2007, respectively, are included in Spent Nuclear Fuel and Decommissioning Trusts on our Condensed Consolidated Balance Sheets.

Long-term debt and other securities issued, retired and principal payments made during the first sixnine months of 2008 are shown in the tables below.
Company Type of Debt Principal Amount Interest Rate Due Date
    (in millions) (%)  
Issuances:        
AEP Junior Subordinated Debentures $315 8.75 2063
APCo Pollution Control Bonds  40 4.85 2019
APCo Pollution Control Bonds  30 4.85 2019
APCo Pollution Control Bonds  75 Variable 2036
APCo Pollution Control Bonds  50 Variable 2036
APCo Senior Unsecured Notes  500 7.00 2038
CSPCo Senior Unsecured Notes  350 6.05 2018
I&M Pollution Control Bonds  25 Variable 2019
I&M Pollution Control Bonds  52 Variable 2021
I&M Pollution Control Bonds  40 5.25 2025
OPCo Pollution Control Bonds  50 Variable 2014
OPCo Pollution Control Bonds  50 Variable 2014
OPCo Pollution Control Bonds  65 Variable 2036
OPCo Senior Unsecured Notes  250 5.75 2013
SWEPCo Pollution Control Bonds  41 4.50 2011
SWEPCo Senior Unsecured Notes  400 6.45 2019
          
Non-Registrant:         
TCC Pollution Control Bonds  41 5.625 2017
TCC Pollution Control Bonds  120 5.125 2030
TNC Senior Unsecured Notes  30 5.89 2018
TNC Senior Unsecured Notes  70 6.76 2038
Total Issuances   $2,594(a)   
Company Type of Debt Principal Amount Interest Rate Due Date 
    (in millions) (%)   
Issuances:         
AEP Junior Subordinated Debentures $315 8.75 2063 
APCo Pollution Control Bonds  75 Variable 2036 
APCo Pollution Control Bonds  50 Variable 2036 
APCo Senior Unsecured Notes  500 7.00 2038 
CSPCo Senior Unsecured Notes  350 6.05 2018 
I&M Pollution Control Bonds  25 Variable 2019 
I&M Pollution Control Bonds  52 Variable 2021 
I&M Pollution Control Bonds  40 5.25 2025 
OPCo Pollution Control Bonds  50 Variable 2014 
OPCo Pollution Control Bonds  50 Variable 2014 
OPCo Pollution Control Bonds  65 Variable 2036 
SWEPCo Senior Unsecured Notes  400 6.45 2019 
           
Non-Registrant:          
TCC Pollution Control Bonds  41 5.625 2017 
TCC Pollution Control Bonds  120 5.125 2030 
TNC Senior Unsecured Notes  30 5.89 2018 
TNC Senior Unsecured Notes  70 6.76 2038 
Total Issuances   $2,233(a)    

Other than the possible dividend restrictions of the AEP Junior Subordinated Debentures, the above borrowing arrangements do not contain guarantees, collateral or dividend restrictions.

(a)
Amount indicated on statement of cash flows of $2,204$2,561 million is net of issuance costs and premium or discount.

The net proceeds from the sale of Junior Subordinated Debentures will bewere used for general corporate purposes including the payment of short-term indebtedness.
 
Company
 Type of Debt Principal Amount Paid Interest Rate Due Date
    (in millions) (%)  
Retirements and Principal Payments:        
APCo Senior Unsecured Notes $200  3.60 2008
APCo Pollution Control Bonds  40  Variable 2019
APCo Pollution Control Bonds  30  Variable 2019
APCo Pollution Control Bonds  18  Variable 2021
APCo Pollution Control Bonds  50  Variable 2036
APCo Pollution Control Bonds  75  Variable 2037
CSPCo Senior Unsecured Notes  60  6.55 2008
CSPCo Senior Unsecured Notes  52  6.51 2008
CSPCo Pollution Control Bonds  48  Variable 2038
CSPCo Pollution Control Bonds  44  Variable 2038
I&M Pollution Control Bonds  45  Variable 2009
I&M Pollution Control Bonds  25  Variable 2019
I&M Pollution Control Bonds  52  Variable 2021
I&M Pollution Control Bonds  50  Variable 2025
I&M Pollution Control Bonds  50  Variable 2025
I&M Pollution Control Bonds  40  Variable 2025
OPCo Notes Payable  1  6.81 2008
OPCo Notes Payable  12  6.27 2009
OPCo Pollution Control Bonds  50  Variable 2014
OPCo Pollution Control Bonds  50  Variable 2016
OPCo Pollution Control Bonds  50  Variable 2022
OPCo Pollution Control Bonds  35  Variable 2022
OPCo Pollution Control Bonds  65  Variable 2036
PSO Pollution Control Bonds  34  Variable 2014
SWEPCo Pollution Control Bonds  41  Variable 2011
SWEPCo Notes Payable  2  Variable 2008
SWEPCo Notes Payable  3  4.47 2011
          
Non-Registrant:         
AEP Subsidiaries Notes Payable  4  5.88 2011
AEP Subsidiaries Notes Payable  10  Variable 2017
AEGCo Senior Unsecured Notes  7  6.33 2037
AEPSC Notes Payable  34  9.60 2008
TCC First Mortgage Bonds  19  7.125 2008
TCC Securitization Bonds  29  5.01 2008
TCC Securitization Bonds  21  5.56 2010
TCC Securitization Bonds  75  4.98 2010
TCC Pollution Control Bonds  41  Variable 2015
TCC Pollution Control Bonds  60  Variable 2028
TCC Pollution Control Bonds  60  Variable 2028
Total Retirements and Principal Payments  $1,582     

 
Company
 Type of Debt Principal Amount Paid Interest Rate Due Date 
    (in millions) (%)   
Retirements and
  Principal Payments:
         
APCo Senior Unsecured Notes $200 3.60 2008 
APCo Pollution Control Bonds  40 Variable 2019 
APCo Pollution Control Bonds  30 Variable 2019 
APCo Pollution Control Bonds  18 Variable 2021 
APCo Pollution Control Bonds  50 Variable 2036 
APCo Pollution Control Bonds  75 Variable 2037 
CSPCo Senior Unsecured Notes  60 6.55 2008 
CSPCo Senior Unsecured Notes  52 6.51 2008 
CSPCo Pollution Control Bonds  48 Variable 2038 
CSPCo Pollution Control Bonds  44 Variable 2038 
I&M Pollution Control Bonds  45 Variable 2009 
I&M Pollution Control Bonds  25 Variable 2019 
I&M Pollution Control Bonds  52 Variable 2021 
I&M Pollution Control Bonds  50 Variable 2025 
I&M Pollution Control Bonds  50 Variable 2025 
I&M Pollution Control Bonds  40 Variable 2025 
OPCo Notes Payable  1 6.81 2008 
OPCo Notes Payable  6 6.27 2009 
OPCo Pollution Control Bonds  50 Variable 2014 
OPCo Pollution Control Bonds  50 Variable 2016 
OPCo Pollution Control Bonds  50 Variable 2022 
OPCo Pollution Control Bonds  35 Variable 2022 
OPCo Pollution Control Bonds  65 Variable 2036 
PSO Pollution Control Bonds  34 Variable 2014 
SWEPCo Notes Payable  2 Variable 2008 
SWEPCo Notes Payable  2 4.47 2011 
           
Non-Registrant:          
AEP Subsidiaries Notes Payable  4 5.88 2011 
AEP Subsidiaries Notes Payable  2 Variable 2017 
AEGCo Senior Unsecured Notes  4 6.33 2037 
AEPSC Mortgage Notes  34 9.60 2008 
TCC First Mortgage Bonds  19 7.125 2008 
TCC Securitization Bonds  29 5.01 2008 
TCC Securitization Bonds  45 4.98 2010 
TCC Pollution Control Bonds  41 Variable 2015 
TCC Pollution Control Bonds  60 Variable 2028 
TCC Pollution Control Bonds  60 Variable 2028 
Total Retirements and   
  Principal Payments
  $1,472     

In October 2008, SWEPCo retired $113 million of 5.25% Notes Payable due in 2043.

As of JuneSeptember 30, 2008, we had $313$272 million outstanding of tax-exempt long-term debt sold at auction rates (rates range between 4.353% and 13%) that reset every 35 days.  Approximately $218 million of this debt relates to a lease structure with JMG that we are unable to refinance at this time.  In order to refinance this debt, we need the lessor's consent.  This debt is insured by bond insurers previously AAA-rated, namely Ambac Assurance Corporation and Financial Guaranty Insurance Co.  Due to the exposure that these bond insurers havehad in connection with developments in the subprime credit market, the credit ratings of these insurers have beenwere downgraded or placed on negative outlook.  These market factors have contributed to higher interest rates in successful auctions and increasing occurrences of failed auctions, including many of the auctions of our tax-exempt long-term debt.  Consequently, we chose to exit the auction-rate debt market.  The instruments under which the bonds are issued allow us to convert to other short-term variable-rate structures, term-put structures and fixed-rate structures.  Through JuneSeptember 30, 2008, we reduced our outstanding auction rate securities by $1.2 billion.  We plan to continue the conversion and refunding process for the remaining $313$272 million to other permitted modes, including term-put structures, variable-rate and fixed-rate structures, during the second half of 2008 to lower our interest rates as such opportunities arise.

As of JuneSeptember 30, 2008, $367 million of the prior auction rate debt was issued in a weekly variable rate mode supported by letters of credit at variable rates ranging from 1.45%6.5% to 1.68%8.25% and $384$495 million was issued at fixed rates ranging from 4.85%4.5% to 5.625%.  As of JuneSeptember 30, 2008, trustees held, on our behalf, approximately $400$330 million of our reacquired auction rate tax-exempt long-term debt which we plan to reissue to the public as market conditions permit.

Dividend Restrictions

We have the option to defer interest payments on the AEP Junior Subordinated Debentures issued in March 2008 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 believe that these restrictions will not have a material effect on our results of operations,net income, cash flows, financial condition or limit any dividend payments in the foreseeable future.

Short-term Debt

Our outstanding short-term debt is as follows:
 September 30, 2008 December 31, 2007 
 June 30, 2008  December 31, 2007  Outstanding Interest Outstanding Interest 
 
Outstanding
Amount
 
Interest
Rate (a)
  
Outstanding
Amount
 
Interest
Rate (a)
  Amount Rate Amount Rate 
Type of Debt (in thousands)    (in thousands)    (in thousands)   (in thousands)   
Commercial Paper – AEP $697,974 3.22% $659,135 5.54% $701,416  3.25%(a)$659,135  5.54% (a)
Commercial Paper – JMG (b)  - -   701 5.35% -  -   701  5.35% (a)
Line of Credit – Sabine Mining Company (c)  7,039 3.25%  285 5.25% 9,520  7.75%(a) 285  5.25% (a)
Line of Credit – AEP (e)  590,700  3.4813%(d) -  -  
Total $705,013    $660,121    $1,301,636    $660,121    

(a)Weighted average rate.
(b)This commercial paper is specifically associated with the Gavin Scrubber and is backed by a separate credit facility.  This commercial paper does not reduce available liquidity under AEP’s credit facilities.
(c)Sabine Mining Company is consolidated under FIN 46R.  This line of credit does not reduce available liquidity under AEP’s credit facilities.
(d)Rate based on 1-month LIBOR.  In October 2008, this rate was converted to 4.55% based on prime.
(e)In October 2008, we borrowed an additional $1.4 billion at 4.55% based on prime.

Credit Facilities

As of JuneSeptember 30, 2008, in support of our commercial paper program, we had two $1.5 billion credit facilities to support our commercial paper program.which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $46 million following its bankruptcy.  In March 2008, the credit facilities were amended so that $750 million may be issued under each credit facility as letters of credit.

In April 2008, we entered into a $650 million 3-year credit agreement and a $350 million 364-day credit agreement.agreement which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23 million and $12 million, respectively, following its bankruptcy.  Under the facilities, we may issue letters of credit.  As of JuneSeptember 30, 2008, $371$372 million of letters of credit were issued by subsidiaries under the 3-year credit agreement to support variable rate demand notes.

10.   SUBSEQUENT EVENT
Sale of Receivables – AEP Credit

In JulyOctober 2008, TCC suffered damageswe renewed AEP Credit’s sale of receivables agreement.  The sale of receivables agreement provides a commitment of $600 million from bank conduits to purchase receivables from AEP Credit.  This agreement will expire in its southern Texas service territory related to Hurricane Dolly.  Management is currently developing an estimate of the storm recovery costs related to Hurricane Dolly, but does not believe that these costs will have a material effect on future results of operations due to expected recovery in rates.October 2009.


 













APPALACHIAN POWER COMPANY
AND SUBSIDIARIES


 
 
 


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations

SecondThird Quarter of 2008 Compared to SecondThird Quarter of 2007

Reconciliation of SecondThird Quarter of 2007 to SecondThird Quarter of 2008
Income Before Extraordinary Loss
(in millions)

Second Quarter of 2007    $3 
Third Quarter of 2007    $24 
              
Changes in Gross Margin:              
Retail Margins  48       (9)    
Off-system Sales  8       8     
Other  (1)      1     
Total Change in Gross Margin      55       - 
                
Changes in Operating Expenses and Other:                
Other Operation and Maintenance  6       26     
Depreciation and Amortization  (31)      (10)    
Taxes Other Than Income Taxes  (1)      (1)    
Carrying Costs Income  6       3     
Other Income  4       2     
Interest Expense  (2)      (2)    
Total Change in Operating Expenses and Other      (18)      18 
                
Income Tax Expense      (14)      (3)
                
Second Quarter of 2008     $26 
Third Quarter of 2008     $39 

Income Before Extraordinary Loss increased $23$15 million to $26$39 million in 2008.  The key drivers of the increase were2008 primarily due to a $55 million increase in Gross Margin partially offset by an increasedecrease in Operating Expenses and Other of $18 million, andpartially offset by an increase in Income Tax Expense of $14$3 million.

The major components of the change 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 an increase in sharing of off-system sales margins with customers and higher capacity settlement expenses under the Interconnection Agreement.  These unfavorable effects were partially offset by the impact of the Virginia base rate order issued in May 2007 which included a 2007 provision for revenue refund in addition to an increase in the recovery of E&R costs in Virginia.
·Margins from Off-system Sales increased $48$8 million primarily due to increased physical sales margins driven by higher prices, partially offset by lower trading margins.

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

·Other Operation and Maintenance expenses decreased $26 million primarily due to the following:
·A $26 million decrease resulting from a settlement agreement in the third quarter 2007 related to alleged violations of the NSR provisions of the CAA.  The $26 million represents APCo’s allocation of the settlement.
·A $9 million decrease related to the establishment of a regulatory asset in the third quarter 2008 for Virginia’s share of previously expended NSR settlement costs.  See “Virginia E&R Cost Recovery Filing” section of Note 3.
These decreases were partially offset by:
·A $6 million increase in employee-related expenses.
·A $5 million increase in overhead line maintenance expense primarily due to right-of-way clearing.
·Depreciation and Amortization expenses increased $10 million primarily due to a $6 million increase in the amortization of carrying charges and depreciation expense that are being collected through the Virginia E&R surcharges and a $3 million increase in depreciation expense primarily from the installation of environmental upgrades at the Mountaineer Plant.
·Carrying Costs Income increased $3 million due to an increase in Virginia E&R deferrals.
·Income Tax Expense increased $3 million primarily due to an increase in pretax book income, partially offset by changes in certain book/tax differences accounted for on a flow-through basis.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Reconciliation of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2008
Income Before Extraordinary Loss
(in millions)

Nine Months Ended September 30, 2007    $98 
        
Changes in Gross Margin:       
Retail Margins  19     
Off-system Sales  32     
Other  1     
Total Change in Gross Margin      52 
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  12     
Depreciation and Amortization  (44)    
Taxes Other Than Income Taxes  (5)    
Carrying Costs Income  16     
Other Income  7     
Interest Expense  (17)    
Total Change in Operating Expenses and Other      (31)
         
Income Tax Expense      2 
         
Nine Months Ended September 30, 2008     $121 

Income Before Extraordinary Loss increased $23 million to $121 million in 2008 primarily due to an increase in Gross Margin of $52 million, partially offset by a $31 million increase in Operating Expenses and Other.

The major components of the change 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 $19 million primarily due to the impact of the Virginia base rate order issued in May 2007 which included a second quarter 2007 provision for revenue refund in addition to an increase in the recovery of E&R costs in Virginia and construction financing costs in West Virginia.  These increases were partially offset by an increase in sharing of off-system sales margins with customers and higher capacity settlement expenses under the Interconnection Agreement.
·Margins from Off-system Sales increased $8$32 million primarily due to higherincreased physical sales margins driven by higher prices, partially offset by lower trading margins.

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

·Other Operation and Maintenance expenses decreased $6$12 million primarily due to a $3the following:
·A $26 million decrease resulting from a settlement agreement in expenses associated with the Transmission Equalization Agreement and a $3third quarter 2007 related to alleged violations of the NSR provisions of the CAA.  The $26 million represents APCo’s allocation of the settlement.
·A $9 million decrease related to the establishment of a regulatory asset in uncollectible accounts receivable expense.the third quarter 2008 for Virginia’s share of previously expended NSR settlement costs.  See “Virginia E&R Cost Recovery Filing” section of Note 3.
These decreases were partially offset by:
·A $7 million increase in employee-related expenses.
·A $10 million increase in overhead line maintenance expense due to right-of-way clearing and storm damage.
·Depreciation and Amortization expenses increased $31$44 million primarily due to favorable adjustments made in the second quarter of 2007 for the Virginia Rate Base order of $22 million and an increase in the amortization of carrying charges and depreciation expense of $6 million that are being collected through the Virginia E&R surcharges.
·Carrying Costs Income increased $6 million due to an increase in Virginia E&R deferrals.
·Interest Expense increased $2 million primarily due to an $11 million increase in interest expense from long-term debt issuances.  This increase was partially offset by a $4 million favorable increase in allowance for borrowed funds used during construction and a $3 million decrease in interest related to the Virginia provision for refund recorded in the second quarter of 2007.
·Income Tax Expense increased $14 million primarily due to an increase in pretax book income.

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

Reconciliation of Six Months Ended June 30, 2007 to Six Months Ended June 30, 2008
Income Before Extraordinary Loss
(in millions)

Six Months Ended June 30, 2007    $74 
        
Changes in Gross Margin:       
Retail Margins  29     
Off-system Sales  24     
Transmission Revenues  1     
Other  (2)    
Total Change in Gross Margin      52 
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  (14)    
Depreciation and Amortization  (34)    
Taxes Other Than Income Taxes  (4)    
Carrying Costs Income  13     
Other Income  4     
Interest Expense  (14)    
Total Change in Operating Expenses and Other      (49)
         
Income Tax Expense      5 
         
   Six Months Ended June 30, 2008     $82 

Income Before Extraordinary Loss increased $8 million to $82 million in 2008.  The key drivers of the increase were a $52 million increase in Gross Margin partially offset by a $49 million increase in Operating Expenses and Other.

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

·Retail Margins increased $29 million primarily due to the impact of the Virginia base rate order issued in May 2007 which included a second quarter 2007 provision for revenue refund in addition to an increase in the recovery of E&R costs in Virginia and construction financing costs in West Virginia.  These increases were partially offset by an increase in sharing of off-system sales margins with customers and higher capacity settlement expenses under the Interconnection Agreement.
·Margins from Off-system Sales increased $24 million primarily due to higher physical sales margins partially offset by lower trading margins.

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

·Other Operation and Maintenance expenses increased $14 million primarily due to a $6 million increase in distribution maintenance expenses resulting from repairs from storm damage.  In addition, steam maintenance expenses increased $5 million due to a planned outage at the Mountaineer Plant in March 2008.
·Depreciation and Amortization expenses increased $34 million primarily due to favorable adjustments made in the second quarter 2007 for theAPCo’s Virginia base rate order of $22and a $15 million and theincrease in amortization of carrying charges and depreciation expense of $9 million that are being collected through the Virginia E&R surcharges.
·Taxes Other Than Income Taxes increased $4$5 million primarily due to favorable franchise tax return adjustments recorded in 2007.
·Carrying Costs Income increased $13$16 million due to an increase in Virginia E&R deferrals.
·Other Income increased $7 million primarily due to higher interest income related to a tax refund in 2008 and other tax adjustments.
·Interest Expense increased $14$17 million primarily due to a $19$26 million increase in interest expense from long-term debt issuances, partially offset by a $4$7 million decrease in interest expense primarily related to interest on the Virginia provision for refund recorded in the second quarter of 2007.
·Income Tax Expense decreased $5$2 million primarily due to a decrease in state income taxes partially offset byand changes in certain book/tax differences accounted for on a flow-through basis.basis, partially offset by an increase in pretax book income.

Financial Condition

Credit Ratings

S&P currently has APCo on stable outlook, while Fitch placed APCo on negative outlook in the second quarter of 2008 and Moody’s placed APCo on negative outlook in the first quarter of 2008.  Current ratings are as follows:

 Moody’s S&P Fitch
      
Senior Unsecured DebtBaa2 BBB BBB+

If APCo receives an upgrade from any of the rating agencies listed above, its borrowing costs could decrease.  If APCo receives a downgrade from any of the rating agencies listed above, it borrowing costs could increase and access to borrowed funds could be negatively affected.

Cash Flow

Cash flows for the sixnine months ended JuneSeptember 30, 2008 and 2007 were as follows:

 2008  2007  2008  2007 
 (in thousands)  (in thousands) 
Cash and Cash Equivalents at Beginning of Period $2,195  $2,318  $2,195  $2,318 
Cash Flows from (Used for):                
Operating Activities  140,378   265,414   208,445   221,534 
Investing Activities  (296,095)  (378,985)  (472,029)  (570,019)
Financing Activities  155,398   112,605   263,376   347,436 
Net Decrease in Cash and Cash Equivalents  (319)  (966)  (208)  (1,049)
Cash and Cash Equivalents at End of Period $1,876  $1,352  $1,987  $1,269 

Operating Activities

Net Cash Flows from Operating Activities were $140$208 million in 2008.  APCo produced income of $82$121 million during the period and had noncash expense items of $124$187 million for Depreciation and Amortization, $72$111 million for Deferred Income Taxes and $27$39 million for Carrying Costs Income.  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$114 million outflow in 2008.  The $41 million cash inflow from Accounts Payable was primarily due to an increase in fuel costs.  The $77 million cash outflow from Fuel Over/Under-Recovery, Net resulted inas a result of a net under recovery of fuel cost in both Virginia and West Virginia due to higher fuel costs.

Net Cash Flows from Operating Activities were $265$222 million in 2007.  APCo incurred a Net Lossproduced income of $5$19 million during the period and had noncash expense items of $90$142 million for Depreciation and Amortization, and $79 million for Extraordinary Loss for the Reapplication of Regulatory Accounting for Generation and $105$23 million for Regulatory Provision related to the Virginia base rate case.Carrying Cost Income.  The other changes in assets and liabilities represent items that had a prior 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 had no significant items in 2007.

Investing Activities

Net Cash Flows Used for Investing Activities during 2008 and 2007 were $296$472 million and $379$570 million, respectively.  Construction Expenditures were $312$488 million and $383$538 million in 2008 and 2007, respectively, primarily related to transmission and distribution service reliability projects, as well as environmental upgrades for both periods.  Environmental upgrades includes the installation of the flue gas desulfurization equipment at the Amos and Mountaineer Plants.  In February 2007, environmental upgrades were completed for the Mountaineer Plant.  For the remainder of 2008, APCo expects construction expenditures to be approximately $458$250 million.

Financing Activities

Net Cash Flows from Financing Activities were $155$263 million in 2008.  APCo received a capital contributioncontributions from the Parent of $125$175 million.  APCo issued $500 million of Senior Unsecured Notes in March 2008, and $125 million of Pollution Control Bonds in June 2008 and $70 million of Pollution Control Bonds in September 2008.  These increases were partially offset by the retirement of $213 million of Pollution Control Bonds and the retirement of $200 million of Senior Unsecured Notes in the second quarter of 2008.  In addition, APCo had a net decrease of $171$182 million in borrowings from the Utility Money Pool.

Net Cash Flows from Financing Activities in 2007 were $113$347 million primarily due to an increase of $213 million in borrowings from the Utility Money Pool and the issuance of $75 million of Pollution Control Bonds.  These increases were partially offset byBonds in May 2007 and the issuance of $500 million of Senior Unsecured Notes in August 2007, net of retirement of $125 million of Senior Unsecured Notes and payment of $25 million in dividends on common stock.June 2007.  APCo also reduced its short-term borrowings from the Utility Money Pool by $35 million.

Financing Activity

Long-term debt issuances, retirements and principal payments made during the first sixnine months of 2008 were:

Issuances
 
Principal
Amount
 Interest Due Principal Interest Due
Type of Debt Rate Date Amount Rate Date
 (in thousands) (%)   (in thousands) (%)  
Pollution Control Bonds $75,000 Variable 2036 $40,000  4.85 2019
Pollution Control Bonds 50,275 Variable 2036  30,000  4.85 2019
Pollution Control Bonds  75,000  Variable 2036
Pollution Control Bonds  50,275  Variable 2036
Senior Unsecured Notes 500,000 7.00 2038  500,000  7.00 2038

Retirements and Principal Payments
 
Principal
Amount Paid
 Interest Due Principal Interest Due
Type of Debt Rate Date Amount Paid Rate Date
 (in thousands) (%)   (in thousands) (%)  
Pollution Control Bonds $40,000 Variable 2019 $40,000  Variable 2019
Pollution Control Bonds 17,500 Variable 2021  30,000  Variable 2019
Pollution Control Bonds 30,000 Variable 2019  17,500  Variable 2021
Pollution Control Bonds 50,275 Variable 2036  50,275  Variable 2036
Pollution Control Bonds 75,000 Variable 2037  75,000  Variable 2037
Senior Unsecured Notes 200,000 3.60 2008  200,000  3.60 2008
Other 7 13.718 2026  11  13.718 2026

Liquidity

APCo has solid investment grade ratings, which provide readyIn recent months, the financial markets have become increasingly unstable and constrained at both a global and domestic level.  This systemic marketplace distress is impacting APCo’s access to capital, liquidity and cost of capital.  The uncertainties in the credit markets in ordercould have significant implications on APCo since it relies on continuing access to issue new debt or refinance long-term debt maturities.  In addition, capital to fund operations and capital expenditures.

APCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  APCo has $150 million of Senior Unsecured Notes that will mature in 2009.  To the extent refinancing is unavailable due to the challenging credit markets, APCo will rely upon cash flows from operations and access to the Utility Money Pool to fund its maturity, continuing operations and capital expenditures.

Summary Obligation Information

A summary of contractual obligations is included in the 2007 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” and “Financing Activity” above and letters of credit.  In April 2008, the Registrant Subsidiaries and certain other companies in the AEP System entered into a $650 million 3-year credit agreement and a $350 million 364-day credit agreement.agreement which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23 million and $12 million, respectively, following its bankruptcy.  As of JuneSeptember 30, 2008, $127 million of letters of credit were issued by APCo under the 3-year credit agreement to support variable rate demand notes.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, APCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be.  Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases which have a probable likelihood of loss and the loss amount 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 2007 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section..  Adverse results in these proceedings have the potential to materially affect results of operations,net income, financial condition and cash flows.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of relevant factors.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2007 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.


QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Risk management assets and liabilities are managed by AEPSC as agent.  The related risk management policies and procedures are instituted and administered by AEPSC.  See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section.  The following tables provide information about AEP’s risk management activities’ effect on APCo.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in APCo’s Condensed Consolidated Balance Sheet as of JuneSeptember 30, 2008 and the reasons for changes in total MTM value as compared to December 31, 2007.
 
Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of JuneSeptember 30, 2008
(in thousands)

    Cash Flow              Cash Flow          
 MTM Risk  &  DETM        MTM Risk  &  DETM       
 Management  Fair Value  Assignment  Collateral     Management  Fair Value  Assignment  Collateral    
 Contracts  Hedges  (a)  Deposits  Total  Contracts  Hedges  (a)  Deposits  Total 
Current Assets $219,254  $3,871  $-  $(15,261) $207,864  $81,386  $4,104  $-  $(3,532) $81,958 
Noncurrent Assets  114,005   363   -   (8,538)  105,830   58,881   1,036   -   (4,718)  55,199 
Total MTM Derivative Contract Assets  333,259   4,234   -   (23,799)  313,694   140,267   5,140   -   (8,250)  137,157 
                                        
Current Liabilities  (223,908)  (28,732)  (3,396)  17,200   (238,836)  (69,529)  (2,996)  (3,127)  547   (75,105)
Noncurrent Liabilities  (80,869)  (1,287)  (3,720)  2,519   (83,357)  (29,631)  -   (3,194)  50   (32,775)
Total MTM Derivative Contract Liabilities  (304,777)  (30,019)  (7,116)  19,719   (322,193)  (99,160)  (2,996)  (6,321)  597   (107,880)
                                        
Total MTM Derivative Contract Net Assets (Liabilities) $28,482  $(25,785) $(7,116) $(4,080) $(8,499) $41,107  $2,144  $(6,321) $(7,653) $29,277 

(a)See “Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual Report.

MTM Risk Management Contract Net Assets
SixNine Months Ended JuneSeptember 30, 2008
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2007 $45,870  $45,870 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period (8,933)  (13,569)
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 -   - 
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b) 1,151   564 
Changes in Fair Value Due to Market Fluctuations During the Period (c) (408)  (165)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)  (9,198)  8,407 
Total MTM Risk Management Contract Net Assets 28,482   41,107 
Net Cash Flow & Fair Value Hedge Contracts (25,785)  2,144 
DETM Assignment (e) (7,116)  (6,321)
Collateral Deposits  (4,080)  (7,653)
Ending Net Risk Management Assets at June 30, 2008 $(8,499)
Ending Net Risk Management Assets at September 30, 2008 $29,277 

(a)Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term.  The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)Represents the impact of applying AEP’s credit risk when measuring the fair value of derivative liabilities according to SFAS 157.
(c)Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(d)“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income.  These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.liabilities.
(e)See “Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual Report.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The following table presents the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash:

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of JuneSeptember 30, 2008
(in thousands)

 Remainder              After     Remainder             After    
 2008  2009  2010  2011  2012  2012  Total  2008  2009  2010  2011  2012 2012  Total 
Level 1 (a) $(2,770) $471  $(21) $-  $-  $-  $(2,320) $(998) $(2,295) $(21) $-  $- $-  $(3,314)
Level 2 (b)  2,314   12,244   12,956   5,150   1,782   -   34,446   1,480   18,258   12,918   1,662   485  -   34,803 
Level 3 (c)  (9,305)  (1,566)  (3,892)  (2,504)  (1,293)  -   (18,560)  (3,850)  666   (1,881)  272   152  -   (4,641)
Total  (9,761)  11,149   9,043   2,646   489   -   13,566   (3,368)  16,629   11,016   1,934   637  -   26,848 
Dedesignated Risk Management Contracts (d)  2,380   4,602   4,565   1,778   1,591   -   14,916   1,403   4,720   4,681   1,823   1,632  -   14,259 
Total MTM Risk Management Contract Net Assets (Liabilities) $(7,381) $15,751  $13,608  $4,424  $2,080  $-  $28,482  $(1,965) $21,349  $15,697  $3,757  $2,269 $-  $41,107 

(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 SFAS 133.  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 contract.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed Consolidated Balance Sheet

APCo is exposed to market fluctuations in energy commodity prices impacting power operations.  Management  monitors these risks on future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows.  Management does not hedge all commodity price risk.

Management uses interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt.  Management does not hedge all interest rate risk.

Management uses foreign currency derivatives to lock in prices on certain forecasted transactions denominated in foreign currencies where deemed necessary, and designates qualifying instruments as cash flow hedges.  Management does not hedge all foreign currency exposure.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on APCo’s Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2007 to JuneSeptember 30, 2008.  Only contracts designated as cash flow hedges are recorded in AOCI.  Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables.  All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
SixNine Months Ended JuneSeptember 30, 2008
(in thousands)
   Interest Foreign  
 Power 
Interest
Rate
 
Foreign
Currency
 Total  Power Rate Currency Total
Beginning Balance in AOCI December 31, 2007 $783 $(6,602) $(125) $(5,944) $783  $(6,602) $(125) $(5,944)
Changes in Fair Value (15,824) (3,114) 75 (18,863) 670  (3,114) 68  (2,376)
Reclassifications from AOCI for Cash Flow Hedges Settled  (682)  813  3  134   (118)  1,231   5   1,118 
Ending Balance in AOCI June 30, 2008 $(15,723) $(8,903) $(47) $(24,673)
Ending Balance in AOCI September 30, 2008 $1,335  $(8,485) $(52) $(7,202)

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $16.8$1 million loss.

Credit Risk

Counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

Management uses risk measurement model, which calculates Value at Risk (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 JuneSeptember 30, 2008, a near term typical change in commodity prices is not expected to have a material effect on APCo’s results of operations,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 periods indicated:

Six Months Ended
June 30, 2008
  
Twelve Months Ended
December 31, 2007
 
Nine Months Ended
September 30, 2008
Nine Months Ended
September 30, 2008
 
Twelve Months Ended
December 31, 2007
(in thousands)(in thousands)  (in thousands) (in thousands) (in thousands)
EndEnd High Average Low  End High Average Low  High Average Low End High Average Low
$603  $1,002  $391  $161  $455  $2,328  $569  $117
$725 $1,096 $416 $161 $455 $2,328 $569 $117

Management back-tests its VaR results against performance due to actual price moves.  Based on the assumed 95% confidence interval, the performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days.  Management’s backtesting results show that its actual performance exceeded VaR far fewer than once every 20 trading days.  As a result, management believes APCo’s VaR calculation is conservative.

As APCo’s VaR calculation captures recent price moves, management also performs regular stress testing of the portfolio to understand its exposure to extreme price moves.  Management employs a historically-based method whereby the current portfolio is subjected to actual, observed price moves from the last three years in order to ascertain which historical price moves translate into the largest potential mark-to-market loss.  Management then researches the underlying positions, price moves and market events that created the most significant exposure.

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 APCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  The estimated EaR on APCo’s debt portfolio was $5.2$4.3 million.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)

  Three Months Ended  Nine Months Ended 
  2008  2007  2008  2007 
REVENUES            
Electric Generation, Transmission and Distribution $719,295  $639,830  $1,926,841  $1,740,565 
Sales to AEP Affiliates  74,632   64,099   262,230   181,015 
Other  4,906   2,647   12,186   8,134 
TOTAL  798,833   706,576   2,201,257   1,929,714 
                 
EXPENSES                
Fuel and Other Consumables Used for Electric Generation  220,955   200,702   554,022   535,906 
Purchased Electricity for Resale  71,075   47,430   167,205   117,708 
Purchased Electricity from AEP Affiliates  219,595   171,288   595,433   443,519 
Other Operation  66,316   94,190   210,262   236,944 
Maintenance  51,292   49,708   161,371   146,875 
Depreciation and Amortization  62,364   51,864   186,528   142,100 
Taxes Other Than Income Taxes  24,319   23,561   72,414   67,811 
TOTAL  715,916   638,743   1,947,235   1,690,863 
                 
OPERATING INCOME  82,917   67,833   254,022   238,851 
                 
Other Income (Expense):                
Interest Income  1,945   510   7,541   1,539 
Carrying Costs Income  11,924   8,701   38,921   22,817 
Allowance for Equity Funds Used During Construction  2,130   1,084   6,278   5,442 
Interest Expense  (47,385)  (44,980)  (138,644)  (121,758)
                 
INCOME BEFORE INCOME TAX EXPENSE  51,531   33,148   168,118   146,891 
                 
Income Tax Expense  12,516   9,090   47,508   49,325 
                 
INCOME BEFORE EXTRAORDINARY LOSS  39,015   24,058   120,610   97,566 
                 
Extraordinary Loss – Reapplication of Regulatory Accounting for Generation, Net of Tax  -   -   -   (78,763)
                 
NET INCOME  39,015   24,058   120,610   18,803 
                 
Preferred Stock Dividend Requirements Including Capital Stock Expense  238   238   714   714 
                 
EARNINGS APPLICABLE TO COMMON STOCK $38,777  $23,820  $119,896  $18,089 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




 
 
 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three and Six Months Ended June 30, 2008 and 2007
(in thousands)
(Unaudited)

  Three Months Ended  Six Months Ended 
  2008  2007  2008  2007 
REVENUES            
Electric Generation, Transmission and Distribution $566,089  $499,189  $1,207,546  $1,100,735 
Sales to AEP Affiliates  97,508   55,371   187,598   116,916 
Other  3,800   2,850   7,280   5,487 
TOTAL  667,397   557,410   1,402,424   1,223,138 
                 
EXPENSES                
Fuel and Other Consumables Used for Electric Generation  159,237   164,018   333,067   335,204 
Purchased Electricity for Resale  52,931   34,328   96,130   70,278 
Purchased Electricity from AEP Affiliates  186,243   144,630   375,838   272,231 
Other Operation  68,415   75,125   143,946   142,754 
Maintenance  52,235   51,414   110,079   97,167 
Depreciation and Amortization  61,592   31,076   124,164   90,236 
Taxes Other Than Income Taxes  24,104   22,975   48,095   44,250 
TOTAL  604,757   523,566   1,231,319   1,052,120 
                 
OPERATING INCOME  62,640   33,844   171,105   171,018 
                 
Other Income (Expense):                
Interest Income  2,827   390   5,596   1,029 
Carrying Costs Income  17,411   10,950   26,997   14,116 
Allowance for Equity Funds Used During Construction  2,652   1,581   4,148   4,358 
Interest Expense  (47,119)  (44,955)  (91,259)  (76,778)
                 
INCOME BEFORE INCOME TAX EXPENSE (CREDIT)  38,411   1,810   116,587   113,743 
                 
Income Tax Expense (Credit)  12,129   (1,471)  34,992   40,235 
                 
INCOME BEFORE EXTRAORDINARY LOSS  26,282   3,281   81,595   73,508 
                 
Extraordinary Loss – Reapplication of Regulatory Accounting for Generation, Net    of Tax  -   (78,763)  -   (78,763)
                 
NET INCOME (LOSS)  26,282   (75,482)  81,595   (5,255)
                 
Preferred Stock Dividend Requirements Including
  Capital Stock Expense
  238   238   476   476 
                 
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $26,044  $(75,720) $81,119  $(5,731)

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in thousands)
(Unaudited)

 Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total  Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
DECEMBER 31, 2006 $260,458  $1,024,994  $805,513  $(54,791) $2,036,174  $260,458  $1,024,994  $805,513  $(54,791) $2,036,174 
                                        
FIN 48 Adoption, Net of Tax          (2,685)      (2,685)          (2,685)      (2,685)
Common Stock Dividends          (25,000)      (25,000)          (25,000)      (25,000)
Preferred Stock Dividends          (400)      (400)          (600)      (600)
Capital Stock Expense      76   (76)      -       117   (114)      3 
TOTAL                  2,008,089                   2,007,892 
                                        
COMPREHENSIVE INCOME                                        
Other Comprehensive Income, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $2,482              4,610   4,610 
Other Comprehensive Income (Loss), Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $539              (1,000)  (1,000)
SFAS 158 Costs Established as a Regulatory
Asset Related to the Reapplication of
SFAS 71, Net of Tax of $6,055
              11,245   11,245               11,245   11,245 
NET LOSS          (5,255)      (5,255)
NET INCOME          18,803       18,803 
TOTAL COMPREHENSIVE INCOME                  10,600                   29,048 
                                        
JUNE 30, 2007 $260,458  $1,025,070  $772,097  $(38,936) $2,018,689 
SEPTEMBER 30, 2007 $260,458  $1,025,111  $795,917  $(44,546) $2,036,940 
                                        
DECEMBER 31, 2007 $260,458  $1,025,149  $831,612  $(35,187) $2,082,032  $260,458  $1,025,149  $831,612  $(35,187) $2,082,032 
                                        
EITF 06-10 Adoption, Net of Tax of $1,175          (2,181)      (2,181)          (2,181)      (2,181)
SFAS 157 Adoption, Net of Tax of $154          (286)      (286)          (286)      (286)
Capital Contribution from Parent      125,000           125,000       175,000           175,000 
Preferred Stock Dividends          (399)      (399)          (599)      (599)
Capital Stock Expense      77   (77)      -       115   (115)      - 
TOTAL                  2,204,166                   2,253,966 
                                        
COMPREHENSIVE INCOME                                        
Other Comprehensive Income (Loss), Net of Taxes:                                        
Cash Flow Hedges, Net of Tax of $10,085
              (18,729)  (18,729)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $897
              1,666   1,666 
Cash Flow Hedges, Net of Tax of $677               (1,258)  (1,258)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,346              2,499   2,499 
NET INCOME          81,595       81,595           120,610       120,610 
TOTAL COMPREHENSIVE INCOME                  64,532                   121,851 
                                        
JUNE 30, 2008 $260,458  $1,150,226  $910,264  $(52,250) $2,268,698 
SEPTEMBER 30, 2008 $260,458  $1,200,264  $949,041  $(33,946) $2,375,817 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



 
 
 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
JuneSeptember 30, 2008 and December 31, 2007
(in thousands)
(Unaudited)

 2008  2007  2008  2007 
CURRENT ASSETS            
Cash and Cash Equivalents $1,876  $2,195  $1,987  $2,195 
Accounts Receivable:                
Customers  198,958   176,834   204,692   176,834 
Affiliated Companies  79,810   113,582   96,277   113,582 
Accrued Unbilled Revenues  34,213   38,397   43,333   38,397 
Miscellaneous  592   2,823   1,923   2,823 
Allowance for Uncollectible Accounts  (5,835)  (13,948)   (16,224)  (13,948)
Total Accounts Receivable  307,738   317,688   330,001   317,688 
Fuel  84,139   82,203   80,853   82,203 
Materials and Supplies  80,244   76,685   74,552   76,685 
Risk Management Assets  207,864   62,955   81,958   62,955 
Regulatory Asset for Under-Recovered Fuel Costs  53,399   -   90,111   - 
Prepayments and Other  51,831   16,369   60,431   16,369 
TOTAL  787,091   558,095   719,893   558,095 
                
PROPERTY, PLANT AND EQUIPMENT                
Electric:                
Production  3,633,832   3,625,788   3,655,253   3,625,788 
Transmission  1,712,793   1,675,081   1,739,018   1,675,081 
Distribution  2,429,600   2,372,687   2,453,323   2,372,687 
Other  356,089   351,827   362,985   351,827 
Construction Work in Progress  856,270   713,063   947,101   713,063 
Total  8,988,584   8,738,446   9,157,680   8,738,446 
Accumulated Depreciation and Amortization  2,639,155   2,591,833   2,662,328   2,591,833 
TOTAL - NET  6,349,429   6,146,613   6,495,352   6,146,613 
                
OTHER NONCURRENT ASSETS                
Regulatory Assets  683,609   652,739   712,001   652,739 
Long-term Risk Management Assets  105,830   72,366   55,199   72,366 
Deferred Charges and Other  197,938   191,871   179,054   191,871 
TOTAL  987,377   916,976   946,254   916,976 
                
TOTAL ASSETS $8,123,897  $7,621,684  $8,161,499  $7,621,684 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


 
 
 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
JuneSeptember 30, 2008 and December 31, 2007
(Unaudited)

 2008  2007  2008  2007 
CURRENT LIABILITIES (in thousands)  (in thousands) 
Advances from Affiliates $103,802  $275,257  $93,558  $275,257 
Accounts Payable:                
General  281,893   241,871   290,320   241,871 
Affiliated Companies  99,692   106,852   105,647   106,852 
Long-term Debt Due Within One Year – Nonaffiliated  150,016   239,732   150,016   239,732 
Risk Management Liabilities  238,836   51,708   75,105   51,708 
Customer Deposits  50,978   45,920   51,243   45,920 
Accrued Taxes  48,527   58,519   34,154   58,519 
Accrued Interest  46,693   41,699   68,110   41,699 
Other  99,752   139,476   98,950   139,476 
TOTAL  1,120,189   1,201,034   967,103   1,201,034 
                
NONCURRENT LIABILITIES                
Long-term Debt – Nonaffiliated  2,803,466   2,507,567   2,873,980   2,507,567 
Long-term Debt – Affiliated  100,000   100,000   100,000   100,000 
Long-term Risk Management Liabilities  83,357   47,357   32,775   47,357 
Deferred Income Taxes  1,013,394   948,891   1,073,269   948,891 
Regulatory Liabilities and Deferred Investment Tax Credits  490,350   505,556   509,068   505,556 
Deferred Credits and Other  226,691   211,495   211,735   211,495 
TOTAL  4,717,258   4,320,866   4,800,827   4,320,866 
                
TOTAL LIABILITIES  5,837,447   5,521,900   5,767,930   5,521,900 
                
Cumulative Preferred Stock Not Subject to Mandatory Redemption  17,752   17,752   17,752   17,752 
                
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   260,458   260,458 
Paid-in Capital  1,150,226   1,025,149   1,200,264   1,025,149 
Retained Earnings  910,264   831,612   949,041   831,612 
Accumulated Other Comprehensive Income (Loss)  (52,250)  (35,187)  (33,946)  (35,187)
TOTAL  2,268,698   2,082,032   2,375,817   2,082,032 
                
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $8,123,897  $7,621,684  $8,161,499  $7,621,684 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


 
 
 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in thousands)
(Unaudited)

 2008  2007  2008  2007 
OPERATING ACTIVITIES            
Net Income (Loss) $81,595  $(5,255) 
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities:        
Net Income $120,610  $18,803 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization  124,164   90,236   186,528   142,100 
Deferred Income Taxes  71,728   (17,439)   111,297   32,021 
Extraordinary Loss, Net of Tax  -   78,763   -   78,763 
Regulatory Provision  -   105,110 
Carrying Costs Income  (26,997)  (14,116)   (38,921)  (22,817)
Allowance for Equity Funds Used During Construction  (4,148)  (4,358)   (6,278)  (5,442)
Mark-to-Market of Risk Management Contracts  17,298   5,457   7,450   (1,949)
Change in Other Noncurrent Assets  (14,006)  (7,896)   (24,670)  (9,185)
Change in Other Noncurrent Liabilities  (20,038)  (1,239)   (12,565)  27,247 
Changes in Certain Components of Working Capital:                
Accounts Receivable, Net  2,583   31,483   (12,313)  (87)
Fuel, Materials and Supplies  (5,495)  (20,654)   3,483   (11,387)
Accounts Payable  40,905   (26,786)   41,869   (38,724)
Accrued Taxes, Net  (31,213)  39,168   (51,208)  (9,990)
Accrued Interest  26,411   28,596 
Fuel Over/Under-Recovery, Net  (77,036)  15,221   (113,748)  35,770 
Other Current Assets  (14,225)  3,140   (17,202)  (21,483)
Other Current Liabilities  (4,737)  (5,421)   (12,298)  (20,702)
Net Cash Flows from Operating Activities  140,378   265,414   208,445   221,534 
                
INVESTING ACTIVITIES                
Construction Expenditures  (311,550)  (382,501)   (487,797)  (537,930)
Change in Other Cash Deposits, Net  (15)  (2,678)   (18)  (29)
Change in Advances to Affiliates, Net  -   (38,573)
Proceeds from Sales of Assets  15,470   6,194   15,786   6,713 
Other  -   (200)
Net Cash Flows Used for Investing Activities  (296,095)  (378,985)   (472,029)  (570,019)
                
FINANCING ACTIVITIES                
Capital Contribution from Parent  125,000   -   175,000   - 
Issuance of Long-term Debt – Nonaffiliated  617,111   73,438   686,512   568,778 
Change in Advances from Affiliates, Net  (171,455)  212,641   (181,699)  (34,975)
Retirement of Long-term Debt – Nonaffiliated  (412,782)  (125,006)   (412,786)  (125,009)
Retirement of Cumulative Preferred Stock  -   (9)
Principal Payments for Capital Lease Obligations  (2,077)  (2,200)   (3,052)  (3,316)
Amortization of Funds From Amended Coal Contract  -   (20,868) 
Amortization of Funds from Amended Coal Contract  -   (32,433)
Dividends Paid on Common Stock  -   (25,000)   -   (25,000)
Dividends Paid on Cumulative Preferred Stock  (399)  (400)  (599)  (600)
Net Cash Flows from Financing Activities  155,398   112,605   263,376   347,436 
                
Net Decrease in Cash and Cash Equivalents  (319)  (966)   (208)  (1,049)
Cash and Cash Equivalents at Beginning of Period  2,195   2,318   2,195   2,318 
Cash and Cash Equivalents at End of Period $1,876  $1,352  $1,987  $1,269 
                
SUPPLEMENTARY INFORMATION                
Cash Paid for Interest, Net of Capitalized Amounts $86,873  $69,823  $110,349  $86,199 
Net Cash Paid (Received) for Income Taxes  (10,708)  6,197   (26,330)  6,688 
Noncash Acquisitions Under Capital Leases  1,014   1,693   1,246   2,738 
Construction Expenditures Included in Accounts Payable at June 30,  98,958   97,044 
Construction Expenditures Included in Accounts Payable at September 30,  112,376   90,315 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


 
 
 

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

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

 Footnote Reference
  
Significant Accounting MattersNote 1
New Accounting Pronouncements and Extraordinary ItemNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
Benefit PlansNote 6
Business SegmentsNote 7
Income TaxesNote 8
Financing ActivitiesNote 9









COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES


 
 
 

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations

SecondThird Quarter of 2008 Compared to SecondThird Quarter of 2007

Reconciliation of SecondThird Quarter of 2007 to SecondThird Quarter of 2008
Net Income
(in millions)

Second Quarter of 2007    $80 
Third Quarter of 2007    $85 
              
Changes in Gross Margin:              
Retail Margins  (13)      (4)    
Off-system Sales  10       5     
Transmission Revenues  1   ��   1     
Total Change in Gross Margin      (2)      2 
                
Changes in Operating Expenses and Other:                
Other Operation and Maintenance  (30)      (2)    
Depreciation and Amortization  2       (3)    
Taxes Other Than Income Taxes  (5)      (3)    
Interest Expense  (1)      (1)    
Other  1     
Other Income  2     
Total Change in Operating Expenses and Other      (33)      (7)
                
Income Tax Expense      11       2 
                
Second Quarter of 2008     $56 
Third Quarter of 2008     $82 

Net Income decreased $24$3 million to $56$82 million in 2008.  The key drivers of the decrease were a $33$7 million increase in Operating Expenses and Other, partially offset by an $11a $2 million increase in Gross Margin and a $2 million decrease in Income Tax Expense.

The major components of the decreaseincrease 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 $13$4 million primarily due to:
 ·A $32 million decrease related to increased fuel and PJM expenses.
·A $12$23 million decrease in residential and commercial revenue primarily due to a 55% decrease in heating degree days and a 24%12% decrease in cooling degree days.days and the outages caused by the remnants of Hurricane Ike.
·A $20 million decrease related to increased fuel, allowance and consumables expenses.  CSPCo and OPCo have applied for an active fuel clause in their Ohio ESP to be effective January 1, 2009.
·A $4 million increase in capacity settlement charges under the Interconnection Agreement due to a change in relative peak demands.
 These decreases were partially offset by:
·A $26by a $44 million increase related to a net increase in rates implemented.
·A $7 million decrease in capacity purchases related to CSPCo’s unit power agreement for AEGCo’s Lawrenceburg Plant which began in May 2007 and the April 2007 acquisition of the Darby Plant.
·A $4 million increase in industrial revenue due to increased usage by Ormet, a major industrial customer.
·Margins from Off-system Sales increased $10$5 million primarily due to higherincreased physical sales margins anddriven by higher prices, partially offset by lower trading margins.

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

·Other Operation and Maintenance expenses increased $30$2 million due to:
·A $9 million increase in recoverable PJM costs.
·An $8 million increase in steam plant maintenance expenses primarily related to work performed at the Conesville Plant.
·A $4 million increase in boiler plant removal expenses primarily related to work performed at the Conesville Plant.
·A $4 million increase in expenses related to CSPCo’s unit power agreement for AEGCo’s Lawrenceburg Plant which began in May 2007.
·A $3 million increase in recoverable customer account expenses related to the Universal Service Fund for customers who qualify for payment assistance.
·A $3 million increase in employee-related expenses.
These increases were partially offset by a $15 million decrease resulting from a settlement agreement in the third quarter 2007 related to alleged violations of the NSR provisions of the CAA.  The $15 million represents CSPCo’s allocation of the settlement.
·Depreciation and Amortization decreased $2increased $3 million primarily due to the amortization of IGCC pre-construction costs, which endeda greater depreciation base related to environmental improvements placed in the second quarter of 2007.  The amortization of IGCC pre-construction costs was offset by a corresponding increase in Retail Margins in 2007.service.
·Taxes Other Than Income Taxes increased $5$3 million due to property tax adjustments.
·Income Tax Expense decreased $11$2 million primarily due to a decrease in pretax book income.

SixNine Months Ended JuneSeptember 30, 2008 Compared to SixNine Months Ended JuneSeptember 30, 2007

Reconciliation of SixNine Months Ended JuneSeptember 30, 2007 to SixNine Months Ended JuneSeptember 30, 2008
Net Income
(in millions)

Six Months Ended June 30, 2007    $127 
Nine Months Ended September 30, 2007    $212 
              
Changes in Gross Margin:              
Retail Margins  40       36     
Off-system Sales  20       24     
Transmission Revenues  1       3     
Total Change in Gross Margin      61       63 
                
Changes in Operating Expenses and Other:                
Other Operation and Maintenance  (43)      (45)    
Depreciation and Amortization  4       1     
Taxes Other Than Income Taxes  (9)      (12)    
Interest Expense  (6)    
Other Income  5       5     
Interest Expense  (5)    
Total Change in Operating Expenses and Other      (48)      (57)
                
Income Tax Expense      (7)      (4)
                
Six Months Ended June 30, 2008     $133 
Nine Months Ended September 30, 2008     $214 

Net Income increased $6$2 million to $133$214 million in 2008.  The key drivers of the increase were a $61$63 million increase in Gross Margin primarily offset by a $48$57 million increase in Operating Expenses and Other and a $7$4 million increase in Income Tax Expense.

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 $40$36 million primarily due to:
 ·A $58$106 million increase related to a net increase in rates implemented.
 ·A $39$35 million decrease in capacity settlement charges related to CSPCo’s unit power agreementUnit Power Agreement (UPA) for AEGCo’s Lawrenceburg Plant, which began in May 2007, and to the April 2007 acquisition of the Darby Plant.
 ·A $15 million increase in industrial revenue duerelated to increasedhigher usage by Ormet, a major industrial customer.Ormet.
 These increases were partially offset by:
 ·A $60$59 million decrease related to increased fuel, allowance and PJMconsumables expenses.  CSPCo and OPCo have applied for an active fuel clause in their Ohio ESP to be effective January 1, 2009.
 ·A $9$35 million decrease in residential and commercial revenue primarily due to a 25%16% decrease in cooling and a 6% decrease in heating degree days.
·Margins from Off-system Sales increased $20$24 million primarily due to higherincreased physical sales margins anddriven by higher prices, partially offset by lower trading margins.

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

·Other Operation and Maintenance expenses increased $43$45 million primarily due to:
·A $17 million increase in recoverable PJM expenses.
 ·A $13 million increase in expenses related to CSPCo’s unit power agreementUPA for AEGCo’s Lawrenceburg Plant which began in May 2007.
 ·A $12$10 million increase in steam plant maintenance expenses primarily related to work performed at the Conesville Plant.
 ·An $8 million increase in recoverable PJM expenses.
·A $5$9 million increase in recoverable customer account expenses related to the Universal Service Fund for customers who qualify for payment assistance.
 ·A $3$4 million increase in boiler plant removal expenses primarily related to work performed at the Conesville Plant.
·Depreciation and Amortization decreased $4 million primarily due to a $6 million decrease in amortization of IGCC pre-construction costsThese increases were partially offset by a $3$15 million increasedecrease resulting from a settlement agreement in the third quarter 2007 related to the acquisitionalleged violations of the Darby Plant in 2007.NSR provisions of the CAA.  The $15 million represents CSPCo’s allocation of the settlement.
·Taxes Other Than Income Taxes increased $9$12 million due to property tax adjustments.
·Interest Expense increased $5$6 million due to increased long-term borrowings and an increase in short-term borrowings from the Utility Money Pool.borrowings.
·Other Income increased $5 million primarily due to interest income on federal tax refunds.
·Income Tax Expense increased $7$4 million primarily due to an increase in pretax book income and state income taxes.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2007 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

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 and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

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 CSPCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  The estimated EaR on CSPCo’s debt portfolio was $2.1$1.3 million.


 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in thousands)
(Unaudited)

 Three Months Ended  Six Months Ended  Three Months Ended  Nine Months Ended 
 2008  2007  2008  2007  2008  2007  2008  2007 
REVENUES                        
Electric Generation, Transmission and Distribution $500,056  $469,648  $1,005,380  $893,114  $633,325  $553,518  $1,638,705  $1,446,632 
Sales to AEP Affiliates  47,413   35,356   82,521   58,369   29,032   52,331   111,553   110,700 
Other  1,478   1,018   2,695   2,451   1,426   1,292   4,121   3,743 
TOTAL  548,947   506,022   1,090,596   953,934   663,783   607,141   1,754,379   1,561,075 
                                
EXPENSES                                
Fuel and Other Consumables Used for Electric Generation  86,253   76,342   171,380   152,204   112,566   103,560   283,946   255,764 
Purchased Electricity for Resale  45,010   32,835   87,196   64,146   63,441   49,619   150,637   113,765 
Purchased Electricity from AEP Affiliates  110,578   87,788   204,682   171,329   139,017   107,386   343,699   278,715 
Other Operation  84,955   62,516   158,021   123,675   87,358   83,625   245,379   207,300 
Maintenance  34,435   26,723   57,666   49,287   23,039   24,250   80,705   73,537 
Depreciation and Amortization  47,693   49,446   96,295   99,743   50,373   47,589   146,668   147,332 
Taxes Other Than Income Taxes  40,989   35,796   85,545   76,378   44,533   41,382   130,078   117,760 
TOTAL  449,913   371,446   860,785   736,762   520,327   457,411   1,381,112   1,194,173 
                                
OPERATING INCOME  99,034   134,576   229,811   217,172   143,456   149,730   373,267   366,902 
                                
Other Income (Expense):                                
Interest Income  1,603   194   3,942   616   1,515   166   5,457   782 
Carrying Costs Income  1,538   1,139   3,304   2,231   1,566   1,261   4,870   3,492 
Allowance for Equity Funds Used During Construction  565   620   1,420   1,392   745   738   2,165   2,130 
Interest Expense  (17,246)  (16,382)  (36,485)  (31,663)  (21,127)  (19,530)  (57,612)  (51,193)
                                
INCOME BEFORE INCOME TAX EXPENSE  85,494   120,147   201,992   189,748   126,155   132,365   328,147   322,113 
                                
Income Tax Expense  29,101   40,125   69,446   62,745   44,493   46,911   113,939   109,656 
                                
NET INCOME   56,393    80,022    132,546    127,003   81,662   85,454   214,208   212,457 
                                
Capital Stock Expense  40   40   79   79   39   39   118   118 
                                
EARNINGS APPLICABLE TO COMMON STOCK  $ 56,353  $ 79,982  $  132,467  $ 126,924  $81,623  $85,415  $214,090  $212,339 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


 
 
 

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in thousands)
(Unaudited)

 Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total  Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
DECEMBER 31, 2006 $41,026  $580,192  $456,787  $(21,988) $1,056,017  $41,026  $580,192  $456,787  $(21,988) $1,056,017 
                                        
FIN 48 Adoption, Net of Tax          (3,022)      (3,022)          (3,022)      (3,022)
Common Stock Dividends          (40,000)      (40,000)          (90,000)      (90,000)
Capital Stock Expense      79   (79)      - 
Capital Stock Expense and Other      118   (118)      - 
TOTAL                  1,012,995                   962,995 
                                        
COMPREHENSIVE INCOME                                        
Other Comprehensive Income, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $360              669   669 
Other Comprehensive Loss, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $1,231              (2,285)  (2,285)
NET INCOME          127,003       127,003           212,457       212,457 
TOTAL COMPREHENSIVE INCOME                  127,672                   210,172 
                                        
JUNE 30, 2007 $41,026  $580,271  $540,689  $(21,319) $1,140,667 
SEPTEMBER 30, 2007 $41,026  $580,310  $576,104  $(24,273) $1,173,167 
                                        
DECEMBER 31, 2007 $41,026  $580,349  $561,696  $(18,794) $1,164,277  $41,026  $580,349  $561,696  $(18,794) $1,164,277 
                                        
EITF 06-10 Adoption, Net of Tax of $589          (1,095)      (1,095)          (1,095)      (1,095)
SFAS 157 Adoption, Net of Tax of $170          (316)      (316)          (316)      (316)
Common Stock Dividends          (62,500)      (62,500)          (87,500)      (87,500)
Capital Stock Expense      79   (79)      -       118   (118)      - 
TOTAL                  1,100,366                   1,075,366 
                                        
COMPREHENSIVE INCOME                                        
Other Comprehensive Income (Loss), Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $5,090              (9,451)  (9,451)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $304
              564   564 
Other Comprehensive Income, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $582              1,080   1,080 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $456              846   846 
NET INCOME          132,546       132,546           214,208       214,208 
TOTAL COMPREHENSIVE INCOME                  123,659                   216,134 
                                        
JUNE 30, 2008 $41,026  $580,428  $630,252  $(27,681) $1,224,025 
SEPTEMBER 30, 2008 $41,026  $580,467  $686,875  $(16,868) $1,291,500 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



 
 
 

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
JuneSeptember 30, 2008 and December 31, 2007
(in thousands)
(Unaudited)

 2008  2007  2008  2007 
CURRENT ASSETS            
Cash and Cash Equivalents $1,591  $1,389  $1,956  $1,389 
Other Cash Deposits  36,975   53,760   31,964   53,760 
Advances to Affiliates  25,199   -   21,833   - 
Accounts Receivable:                
Customers  78,715   57,268   65,581   57,268 
Affiliated Companies  20,346   32,852   27,933   32,852 
Accrued Unbilled Revenues  18,759   14,815   24,078   14,815 
Miscellaneous  15,238   9,905   11,256   9,905 
Allowance for Uncollectible Accounts  (2,647)  (2,563)   (2,814)  (2,563)
Total Accounts Receivable  130,411   112,277   126,034   112,277 
Fuel  37,196   35,849   30,081   35,849 
Materials and Supplies  37,191   36,626   34,979   36,626 
Emission Allowances  11,766   16,811   7,884   16,811 
Risk Management Assets  111,622   33,558   40,842   33,558 
Prepayments and Other  17,153   9,960   31,984   9,960 
TOTAL  409,104   300,230   327,557   300,230 
                
PROPERTY, PLANT AND EQUIPMENT                
Electric:                
Production  2,135,486   2,072,564   2,317,357   2,072,564 
Transmission  563,847   510,107   568,380   510,107 
Distribution  1,577,693   1,552,999   1,600,323   1,552,999 
Other  205,097   198,476   211,475   198,476 
Construction Work in Progress  464,286   415,327   322,885   415,327 
Total  4,946,409   4,749,473   5,020,420   4,749,473 
Accumulated Depreciation and Amortization  1,749,038   1,697,793   1,758,415   1,697,793 
TOTAL - NET  3,197,371   3,051,680   3,262,005   3,051,680 
                
OTHER NONCURRENT ASSETS                
Regulatory Assets  218,323   235,883   204,203   235,883 
Long-term Risk Management Assets  61,708   41,852   30,268   41,852 
Deferred Charges and Other  146,808   181,563   125,071   181,563 
TOTAL  426,839   459,298   359,542   459,298 
                
TOTAL ASSETS $4,033,314  $3,811,208  $3,949,104  $3,811,208 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
 
 
 

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY
JuneSeptember 30, 2008 and December 31, 2007
(Unaudited)

 2008  2007  2008  2007 
CURRENT LIABILITIES (in thousands)  (in thousands) 
Advances from Affiliates $-  $95,199  $-  $95,199 
Accounts Payable:                
General  150,298   113,290   145,733   113,290 
Affiliated Companies  57,025   65,292   53,532   65,292 
Long-term Debt Due Within One Year – Nonaffiliated  -   112,000   -   112,000 
Risk Management Liabilities  131,260   28,237   37,331   28,237 
Customer Deposits  45,190   43,095   29,995   43,095 
Accrued Taxes  154,288   179,831   153,391   179,831 
Other  85,794   96,892   84,432   96,892 
TOTAL  623,855   733,836   504,414   733,836 
                
NONCURRENT LIABILITIES                
Long-term Debt – Nonaffiliated  1,343,388   1,086,224   1,343,491   1,086,224 
Long-term Debt – Affiliated  100,000   100,000   100,000   100,000 
Long-term Risk Management Liabilities  49,103   27,419   18,061   27,419 
Deferred Income Taxes  440,884   437,306   447,465   437,306 
Regulatory Liabilities and Deferred Investment Tax Credits  159,635   165,635   155,332   165,635 
Deferred Credits and Other  92,424   96,511   88,841   96,511 
TOTAL  2,185,434   1,913,095   2,153,190   1,913,095 
                
TOTAL LIABILITIES  2,809,289   2,646,931   2,657,604   2,646,931 
                
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   41,026   41,026 
Paid-in Capital  580,428   580,349   580,467   580,349 
Retained Earnings  630,252   561,696   686,875   561,696 
Accumulated Other Comprehensive Income (Loss)  (27,681)  (18,794)  (16,868)  (18,794)
TOTAL  1,224,025   1,164,277   1,291,500   1,164,277 
                
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY $4,033,314  $3,811,208  $3,949,104  $3,811,208 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

 
 
 

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in thousands)
(Unaudited)

 2008  2007   2008  2007 
OPERATING ACTIVITIES             
Net Income $132,546  $127,003   $214,208  $212,457 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:                 
Depreciation and Amortization  96,295   99,743    146,668   147,332 
Deferred Income Taxes  9,670   (5,077)    8,981   (13,959)
Carrying Costs Income  (3,304)  (2,231)    (4,870)  (3,492)
Allowance for Equity Funds Used During Construction  (1,420)  (1,392)    (2,165)  (2,130)
Mark-to-Market of Risk Management Contracts  10,859   6,842    5,326   1,321 
Deferred Property Taxes  43,745   39,063    65,763   57,890 
Change in Other Noncurrent Assets  (19,046)  (24,593)    (7,942)  (29,199)
Change in Other Noncurrent Liabilities  (2,759)  (7,054)    (4,081)  2,713 
Changes in Certain Components of Working Capital:                 
Accounts Receivable, Net  (18,134)  7,678    (13,757)  (13,040)
Fuel, Materials and Supplies  (1,912)  (8,896)    7,415   (2,332)
Accounts Payable  8,747   (10,735)    (2,650)  (13,336)
Customer Deposits  2,095   15,616    (13,100)  10,212 
Accrued Taxes, Net  (25,530)  5,493    (26,358)  (44,295)
Other Current Assets  (2,160)  8,601    (13,178)  (1,490)
Other Current Liabilities  (13,657)  (1,952)    (14,018)  8,817 
Net Cash Flows from Operating Activities  216,035   248,109    346,242   317,469 
                 
INVESTING ACTIVITIES                 
Construction Expenditures  (191,668)  (169,014)    (304,175)  (246,130)
Change in Other Cash Deposits, Net  16,785   (20)    21,796   (44,360)
Change in Advances to Affiliates, Net  (25,199)  -    (21,833)  - 
Acquisition of Darby Plant  -   (102,032)    -   (102,032)
Proceeds from Sales of Assets  700   842    1,287   1,016 
Net Cash Flows Used for Investing Activities  (199,382)  (270,224)    (302,925)  (391,506)
                 
FINANCING ACTIVITIES                 
Issuance of Long-term Debt – Nonaffiliated  346,934   -    346,407   44,257 
Change in Advances from Affiliates, Net  (95,199)  63,307    (95,199)  122,347 
Retirement of Long-term Debt – Nonaffiliated  (204,245)  -    (204,245)  - 
Principal Payments for Capital Lease Obligations  (1,441)  (1,446)    (2,213)  (2,191)
Dividends Paid on Common Stock  (62,500)  (40,000)    (87,500)  (90,000)
Net Cash Flows from (Used for) Financing Activities  (16,451)  21,861    (42,750)  74,413 
                 
Net Increase (Decrease) in Cash and Cash Equivalents  202   (254)  
Net Increase in Cash and Cash Equivalents  567   376 
Cash and Cash Equivalents at Beginning of Period  1,389   1,319    1,389   1,319 
Cash and Cash Equivalents at End of Period $1,591  $1,065   $1,956  $1,695 
                 
SUPPLEMENTARY INFORMATION                 
Cash Paid for Interest, Net of Capitalized Amounts $38,531  $31,557   $57,004  $53,464 
Net Cash Paid for Income Taxes  22,307   1,704    53,682   93,709 
Noncash Acquisitions Under Capital Leases  1,228   1,347    1,374   1,900 
Construction Expenditures Included in Accounts Payable at June 30,  62,157   30,659  
Construction Expenditures Included in Accounts Payable at September 30,  51,997   34,630 
Noncash Assumption of Liabilities Related to Acquisition of Darby Plant  -   2,339    -   2,339 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

 
 
 

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

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

 
Footnote
Reference
  
Significant Accounting MattersNote 1
New Accounting Pronouncements and Extraordinary ItemNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
AcquisitionNote 5
Benefit PlansNote 6
Business SegmentsNote 7
Income TaxesNote 8
Financing ActivitiesNote 9




 
 
 







INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES


 
 
 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations

SecondThird Quarter of 2008 Compared to SecondThird Quarter of 2007

Reconciliation of SecondThird Quarter of 2007 to SecondThird Quarter of 2008
Net Income
(in millions)

Second Quarter of 2007    $30 
Third Quarter of 2007    $49 
              
Changes in Gross Margin:              
Retail Margins  (3)      (16)    
FERC Municipals and Cooperatives  3       (2)    
Off-system Sales  5       4     
Other  10       10     
Total Change in Gross Margin      15       (4)
                
Changes in Operating Expenses and Other:                
Other Operation and Maintenance  (14)      (2)    
Depreciation and Amortization  22       4     
Taxes Other Than Income Taxes  (1)    
Other Income  (1)    
Interest Expense  3       (2)    
Total Change in Operating Expenses and Other      10       (1)
                
Income Tax Expense      (5)      2 
                
Second Quarter of 2008     $50 
Third Quarter of 2008     $46 

Net Income increased $20decreased $3 million to $50$46 million in 2008.  The key drivers of the increasedecrease were a $15$4 million increasedecrease in Gross Margin and a $10$1 million decreaseincrease in Operating Expenses and Other, partially offset by a $5$2 million increasedecrease in Income Tax Expense.

The major components of the increasedecrease 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 $3$16 million primarily due to lower retail sales reflecting weather conditions as cooling degree days decreased significantlyat least 12% in both the Indiana and Michigan jurisdictions.
·FERC Municipals and Cooperatives margins increased $3 million due to higher revenues under formula rate plans in 2008.
·Margins from Off-system Sales increased $5$4 million primarily due to higherincreased physical sales margins driven by higher prices, partially offset by lower trading margins.
·Other revenues increased $10 million primarily due to increased River Transportation Division (RTD) revenues for barging services.  RTD’s related expenses which offset the RTD revenue increase are included in Other Operation on the Condensed Consolidated Statements of Income resulting in earning only a return approved under a regulatory order.

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

·Other Operation and Maintenance expenses increased $2 million primarily due to higher operation and maintenance expenses for RTD of $11 million caused by increased barging activity and increased cost of fuel in 2008, partially offset by a $9 million decrease in coal-fired plant operation expenses.  A settlement agreement related to alleged violations of the NSR provisions of the CAA, of which $14 million was allocated to I&M, increased 2007 Other Operation and Maintenance expenses.
·Depreciation and Amortization expense decreased $4 million primarily due to reduced depreciation rates reflecting longer estimated lives for Cook and Tanners Creek Plants.  Depreciation rates were reduced for the FERC and Michigan jurisdictions in October 2007.  See “Michigan Depreciation Study Filing” section of Note 4 in the 2007 Annual Report.
·Income Tax Expense decreased $2 million primarily due to a decrease in pretax book income.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Reconciliation of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2008
Net Income
(in millions)

Nine Months Ended September 30, 2007     $109 
         
Changes in Gross Margin:        
Retail Margins  (19)     
FERC Municipals and Cooperatives  4     
Off-system Sales  18     
Transmission Revenues  (2)     
Other  31     
Total Change in Gross Margin      32 
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  (24)     
Depreciation and Amortization  50     
Taxes Other Than Income Taxes  (3)     
Total Change in Operating Expenses and Other      23 
         
Income Tax Expense      (13) 
         
Nine Months Ended September 30, 2008     $151 

Net Income increased $42 million to $151 million in 2008.  The key drivers of the increase were a $32 million increase in Gross Margin and a $23 million decrease in Operating Expenses and Other, partially offset by a $13 million increase in Income Tax Expense.

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 $19 million primarily due to lower retail sales reflecting weather conditions as cooling degree days decreased at least 19% in both the Indiana and Michigan jurisdictions.
·Margins from Off-system Sales increased $18 million primarily due to increased physical sales margins driven by higher prices, partially offset by lower trading margins.
·Other revenues increased $31 million primarily due to increased RTD revenues for barging services.  RTD’s related expenses which offset the RTD revenue increase are included in Other Operation on the Condensed Consolidated Statements of Income resulting in earning only a return approved under regulatory order.

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

·Other Operation and Maintenance expenses increased $14$24 million primarily due to higher operation and maintenance expenses for RTD of $12$31 million caused by increased barging activity and increased cost of fuel.  Nuclearfuel and an increase in nuclear operation and maintenance expense increases were offset by lowerexpenses of $16 million.  Lower coal-fired plant operation and maintenance expenses.  Scheduled outages occurred at Cook Plantexpenses of $18 million, including the NSR settlement, and a $5 million decrease in 2008 and Rockport Plant in 2007.accretion expense partially offset the increases.
·Depreciation and Amortization expense decreased $22$50 million primarily due to the reduced depreciation rates reflecting longer estimated lives for Cook and Tanners Creek Plants.in all jurisdictions.  Depreciation rates were reduced for the Indiana jurisdiction in June 2007 and the FERC and Michigan jurisdictions in October 2007.  See “Indiana Depreciation Study Filing” and “Michigan Depreciation Study Filing” sections of Note 4 in the 2007 Annual Report.
·Income Tax Expense increased $5 million primarily due to an increase in pretax book income and a decrease in amortization of investment tax credits partially offset by changes in certain book/tax differences accounted for on a flow-through basis and a decrease in state income tax.

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

Reconciliation of Six Months Ended June 30, 2007 to Six Months Ended June 30, 2008
Net Income
(in millions)

Six Months Ended June 30, 2007    $59 
        
Changes in Gross Margin:       
Retail Margins  (2)    
FERC Municipals and Cooperatives  7     
Off-system Sales  14     
Transmission Revenues  (1)    
Other  18     
Total Change in Gross Margin      36 
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  (23)    
Depreciation and Amortization  47     
Taxes Other Than Income Taxes  (3)    
Other Income  2     
Interest Expense  3     
Total Change in Operating Expenses and Other      26 
         
Income Tax Expense      (16)
         
Six Months Ended June 30, 2008     $105 

Net Income increased $46 million to $105 million in 2008.  The key drivers of the increase were a $36 million increase in Gross Margin and a $26 million decrease in Operating Expenses and Other partially offset by a $16 million increase in Income Tax Expense.

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:

·FERC Municipals and Cooperatives margins increased $7 million due to higher revenues under formula rate plans in 2008.
·Margins from Off-system Sales increased $14 million primarily due to higher physical sales margins partially offset by lower trading margins.
·Other revenues increased $18 million primarily due to increased RTD revenues for barging services.  RTD’s related expenses which offset the RTD revenue increase are included in Other Operation on the Condensed Consolidated Statements of Income resulting in earning only a return approved under regulatory order.

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

·Other Operation and Maintenance expenses increased $23 million primarily due to higher operation and maintenance expenses for RTD of $19 million caused by increased barging activity and increased cost of fuel.  Nuclear operation and maintenance expense increases were offset by lower coal-fired plant maintenance and accretion expenses.  Scheduled outages occurred at Cook Plant in 2008 and Rockport Plant in 2007.
·Depreciation and Amortization expense decreased $47 million primarily due to the reduced depreciation rates in all jurisdictions.
·Income Tax Expense increased $16$13 million primarily due to an increase in pretax book income and a decrease in amortization of investment tax credits, partially offset by changes in certain book/tax differences accounted for on a flow-through basis.

Cook Plant Unit 1 Fire and Shutdown

Cook Plant Unit 1 (Unit 1) is a 1,030 MW nuclear generating unit located in Bridgman, Michigan. In September 2008, I&M shut down Unit 1 due to turbine vibrations likely caused by blade failure which resulted in a fire on the electric generator.  This equipment is in the turbine building and is separate and isolated from the nuclear reactor.  The steam turbines that caused the vibration were installed in 2006 and are under warranty from the vendor.  The warranty provides for the replacement of the turbines if the damage was caused by a defect in the design or assembly of the turbines.  I&M is also working with its insurance company, Nuclear Electric Insurance Limited (NEIL), and turbine vendor to evaluate the extent of the damage resulting from the incident and the costs to return the unit to service.  Management cannot estimate the ultimate costs of the outage at this time.  Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process.  Management's preliminary analysis indicates that Unit 1 could resume operations as early as late first quarter/early second quarter of 2009 or as late as the second half of 2009, depending upon whether the damaged components can be repaired or whether they need to be replaced.
I&M maintains property insurance through NEIL with a $1 million deductible.  I&M also maintains a separate accidental outage policy with NEIL whereby, after a 12 week deductible period, I&M is entitled to weekly payments of $3.5 million during the outage period for a covered loss.  If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if the unit is not returned to service in a reasonable period of time, it could have an adverse impact on net income, cash flows and financial condition.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2007 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.

 
 
 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

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 and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

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 I&M’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  The estimated EaR on I&M’s debt portfolio was $4.8$5.7 million.

 
 
 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in thousands)
(Unaudited)

 Three Months Ended  Six Months Ended  Three Months Ended  Nine Months Ended 
 2008  2007  2008  2007  2008  2007  2008  2007 
REVENUES                        
Electric Generation, Transmission and Distribution $425,018  $402,152  $856,610  $807,316  $513,548  $478,907  $1,370,158  $1,286,223 
Sales to AEP Affiliates  83,927   62,962   160,439   130,391   72,295   56,262   232,734   186,653 
Other – Affiliated  29,257   14,571   52,476   27,238   31,792   16,250   84,268   43,488 
Other – Nonaffiliated  4,445   6,352   10,271   13,961   3,388   7,757   13,659   21,718 
TOTAL  542,647   486,037   1,079,796   978,906   621,023   559,176   1,700,819   1,538,082 
                                
EXPENSES                                
Fuel and Other Consumables Used for Electric Generation  108,496   90,650   209,737   186,767   141,563   103,740   351,300   290,507 
Purchased Electricity for Resale  26,441   19,310   47,924   37,250   39,427   26,580   87,351   63,830 
Purchased Electricity from AEP Affiliates  91,858   75,791   184,499   153,304   112,060   96,451   296,559   249,755 
Other Operation  124,687   117,311   245,053   238,044   136,875   129,439   381,928   367,483 
Maintenance  52,608   45,725   103,829   88,155   52,573   58,502   156,402   146,657 
Depreciation and Amortization  31,757   53,890   63,479   110,197   31,822   35,604   95,301   145,801 
Taxes Other Than Income Taxes  20,342   19,238   40,244   37,232   19,992   19,704   60,236   56,936 
TOTAL  456,189   421,915   894,765   850,949   534,312   470,020   1,429,077   1,320,969 
                                
OPERATING INCOME  86,458   64,122   185,031   127,957   86,711   89,156   271,742   217,113 
                                
Other Income (Expense):                                
Interest Income  1,904   707   2,733   1,295 
Allowance for Equity Funds Used During Construction  128   727   1,008   992 
Other Income  880   1,986   4,621   4,273 
Interest Expense  (17,146)  (19,611)  (36,348)  (39,432)  (20,629)  (18,312)  (56,977)  (57,744)
                                
INCOME BEFORE INCOME TAX EXPENSE  71,344   45,945   152,424   90,812   66,962   72,830   219,386   163,642 
                                
Income Tax Expense  21,200   15,910   47,022   31,314   21,326   23,706   68,348   55,020 
                                
NET INCOME  50,144   30,035   105,402   59,498   45,636   49,124   151,038   108,622 
                                
Preferred Stock Dividend Requirements  85   85   170   170   85   85   255   255 
                                
EARNINGS APPLICABLE TO COMMON STOCK $50,059  $29,950  $105,232  $59,328  $45,551  $49,039  $150,783  $108,367 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

 
 
 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in thousands)
(Unaudited)

 Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total  Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
DECEMBER 31, 2006 $56,584  $861,290  $386,616  $(15,051) $1,289,439  $56,584  $861,290  $386,616  $(15,051) $1,289,439 
                                        
FIN 48 Adoption, Net of Tax          327       327           327       327 
Common Stock Dividends          (20,000)      (20,000)          (30,000)      (30,000)
Preferred Stock Dividends          (170)      (170)          (255)      (255)
Gain on Reacquired Preferred Stock      1           1       1           1 
TOTAL                  1,269,597                   1,259,512 
                                        
COMPREHENSIVE INCOME                                        
Other Comprehensive Income, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $649              1,206   1,206 
Other Comprehensive Loss, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $941              (1,747)  (1,747)
NET INCOME          59,498       59,498           108,622       108,622 
TOTAL COMPREHENSIVE INCOME                  60,704                   106,875 
                                        
JUNE 30, 2007 $56,584  $861,291  $426,271  $(13,845) $1,330,301 
SEPTEMBER 30, 2007 $56,584  $861,291  $465,310  $(16,798) $1,366,387 
                                        
DECEMBER 31, 2007 $56,584  $861,291  $483,499  $(15,675) $1,385,699  $56,584  $861,291  $483,499  $(15,675) $1,385,699 
                                        
EITF 06-10 Adoption, Net of Tax of $753          (1,398)      (1,398)          (1,398)      (1,398)
Common Stock Dividends          (37,500)      (37,500)          (56,250)      (56,250)
Preferred Stock Dividends          (170)      (170)          (255)      (255)
TOTAL                  1,346,631                   1,327,796 
                                        
COMPREHENSIVE INCOME                                        
Other Comprehensive Income (Loss), Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $4,618              (8,577)  (8,577)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $118
              220   220 
Other Comprehensive Income, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $967              1,795   1,795 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $178              331   331 
NET INCOME          105,402       105,402           151,038       151,038 
TOTAL COMPREHENSIVE INCOME                  97,045                   153,164 
                                        
JUNE 30, 2008 $56,584  $861,291  $549,833  $(24,032) $1,443,676 
SEPTEMBER 30, 2008 $56,584  $861,291  $576,634  $(13,549) $1,480,960 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

 
 
 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
JuneSeptember 30, 2008 and December 31, 2007
(in thousands)
(Unaudited)

 2008  2007  2008  2007 
CURRENT ASSETS            
Cash and Cash Equivalents $982  $1,139  $1,328  $1,139 
Accounts Receivable:                
Customers  97,676   70,995   82,788   70,995 
Affiliated Companies  62,238   92,018   77,640   92,018 
Accrued Unbilled Revenues  13,432   16,207   21,028   16,207 
Miscellaneous  1,080   1,335   2,010   1,335 
Allowance for Uncollectible Accounts  (2,776)  (2,711)   (3,200)  (2,711)
Total Accounts Receivable  171,650   177,844   180,266   177,844 
Fuel  56,541   61,342   46,745   61,342 
Materials and Supplies  145,091   141,384   143,245   141,384 
Risk Management Assets  105,164   32,365   40,215   32,365 
Accrued Tax Benefits  10,619   4,438   1,004   4,438 
Prepayments and Other  22,870   11,091   35,829   11,091 
TOTAL  512,917   429,603   448,632   429,603 
                
PROPERTY, PLANT AND EQUIPMENT                
Electric:                
Production  3,507,581   3,529,524   3,512,424   3,529,524 
Transmission  1,094,164   1,078,575   1,100,255   1,078,575 
Distribution  1,242,898   1,196,397   1,262,017   1,196,397 
Other (including nuclear fuel and coal mining)  608,205   626,390   655,257   626,390 
Construction Work in Progress  135,723   122,296   173,062   122,296 
Total  6,588,571   6,553,182   6,703,015   6,553,182 
Accumulated Depreciation, Depletion and Amortization  2,988,253   2,998,416   3,000,898   2,998,416 
TOTAL - NET  3,600,318   3,554,766   3,702,117   3,554,766 
                
OTHER NONCURRENT ASSETS                
Regulatory Assets  263,951   246,435   251,451   246,435 
Spent Nuclear Fuel and Decommissioning Trusts  1,361,927   1,346,798   1,291,986   1,346,798 
Long-term Risk Management Assets  58,516   40,227   29,518   40,227 
Deferred Charges and Other  134,693   128,623   118,574   128,623 
TOTAL  1,819,087   1,762,083   1,691,529   1,762,083 
                
TOTAL ASSETS $5,932,322  $5,746,452  $5,842,278  $5,746,452 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


 
 
 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
JuneSeptember 30, 2008 and December 31, 2007
(Unaudited)

  2008  2007 
CURRENT LIABILITIES (in thousands) 
Advances from Affiliates $272,707  $45,064 
Accounts Payable:        
General  107,120   184,435 
Affiliated Companies  47,603   61,749 
Long-term Debt Due Within One Year – Nonaffiliated  50,000   145,000 
Risk Management Liabilities  124,092   27,271 
Customer Deposits  27,341   26,445 
Accrued Taxes  73,783   60,995 
Obligations Under Capital Leases  44,388   43,382 
Other  108,766   130,232 
TOTAL  855,800   724,573 
         
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated  1,375,757   1,422,427 
Long-term Risk Management Liabilities  46,777   26,348 
Deferred Income Taxes  370,242   321,716 
Regulatory Liabilities and Deferred Investment Tax Credits  767,385   789,346 
Asset Retirement Obligations  874,941   852,646 
Deferred Credits and Other  189,664   215,617 
TOTAL  3,624,766   3,628,100 
         
TOTAL LIABILITIES  4,480,566   4,352,673 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  8,080   8,080 
         
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  861,291   861,291 
Retained Earnings  549,833   483,499 
Accumulated Other Comprehensive Income (Loss)  (24,032)  (15,675)
TOTAL  1,443,676   1,385,699 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $5,932,322  $5,746,452 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
  2008  2007 
CURRENT LIABILITIES (in thousands) 
Advances from Affiliates $224,071  $45,064 
Accounts Payable:        
General  177,480   184,435 
Affiliated Companies  64,970   61,749 
Long-term Debt Due Within One Year – Nonaffiliated  50,000   145,000 
Risk Management Liabilities  36,802   27,271 
Customer Deposits  26,957   26,445 
Accrued Taxes  60,111   60,995 
Obligations Under Capital Leases  43,626   43,382 
Other  133,267   130,232 
TOTAL  817,284   724,573 
         
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated  1,377,115   1,422,427 
Long-term Risk Management Liabilities  17,585   26,348 
Deferred Income Taxes  382,374   321,716 
Regulatory Liabilities and Deferred Investment Tax Credits  693,981   789,346 
Asset Retirement Obligations  886,278   852,646 
Deferred Credits and Other  178,621   215,617 
TOTAL  3,535,954   3,628,100 
         
TOTAL LIABILITIES  4,353,238   4,352,673 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  8,080   8,080 
         
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  861,291   861,291 
Retained Earnings  576,634   483,499 
Accumulated Other Comprehensive Income (Loss)  (13,549)  (15,675)
TOTAL  1,480,960   1,385,699 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $5,842,278  $5,746,452 


See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
 
 
 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in thousands)
(Unaudited)

 2008  2007  2008  2007 
OPERATING ACTIVITIES            
Net Income $105,402  $59,498  $151,038  $108,622 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:                
Depreciation and Amortization  63,479   110,197   95,301   145,801 
Deferred Income Taxes  41,362   (9,547)   47,565   (9,235)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net  (8,576)  23,099 
Amortization of Incremental Nuclear Refueling Outage Expenses, Net  834   14,450 
Allowance for Equity Funds Used During Construction  (1,008)  (992)   (967)  (2,726)
Mark-to-Market of Risk Management Contracts  10,862   6,903   4,876   3,046 
Amortization of Nuclear Fuel  45,312   33,003   72,453   48,360 
Change in Other Noncurrent Assets  (9,103)  (11,316)   5,678   17,163 
Change in Other Noncurrent Liabilities  19,847   19,425   38,568   33,995 
Changes in Certain Components of Working Capital:                
Accounts Receivable, Net  6,194   36,805   (2,422)  34,569 
Fuel, Materials and Supplies  1,094   9,911   12,736   14,584 
Accounts Payable  449   (46,049)   16,549   (27,015)
Accrued Taxes, Net  6,607   72,977   2,550   41,243 
Other Current Assets  (11,777)  3,373   (24,736)  (4,595)
Other Current Liabilities  (23,583)  (16,388)   1,393   3,150 
Net Cash Flows from Operating Activities  246,561   290,899   421,416   421,412 
                
INVESTING ACTIVITIES                
Construction Expenditures  (140,537)  (124,252)   (221,538)  (191,110)
Purchases of Investment Securities  (276,031)  (409,163)   (413,538)  (561,509)
Sales of Investment Securities  241,079   370,986   362,773   505,620 
Acquisitions of Nuclear Fuel  (98,732)  (30,498)   (99,110)  (73,112)
Proceeds from Sales of Assets and Other  2,912   292   3,376   670 
Net Cash Flows Used for Investing Activities  (271,309)  (192,635)   (368,037)  (319,441)
                
FINANCING ACTIVITIES                
Issuance of Long-term Debt – Nonaffiliated  115,553   -   115,225   - 
Change in Advances from Affiliates, Net  227,643   (76,232)   179,007   (66,939)
Retirement of Long-term Debt – Nonaffiliated  (262,000)  -   (262,000)  - 
Retirement of Cumulative Preferred Stock  -   (2)   -   (2)
Principal Payments for Capital Lease Obligations  (18,935)  (2,622)   (28,917)  (3,954)
Dividends Paid on Common Stock  (37,500)  (20,000)   (56,250)  (30,000)
Dividends Paid on Cumulative Preferred Stock  (170)  (170)   (255)  (255)
Net Cash Flows from (Used for) Financing Activities  24,591   (99,026) 
Net Cash Flows Used for Financing Activities  (53,190)  (101,150)
                
Net Decrease in Cash and Cash Equivalents  (157)  (762) 
Net Increase in Cash and Cash Equivalents  189   821 
Cash and Cash Equivalents at Beginning of Period  1,139   1,369   1,139   1,369 
Cash and Cash Equivalents at End of Period $982  $607  $1,328  $2,190 
                
SUPPLEMENTARY INFORMATION                
Cash Paid for Interest, Net of Capitalized Amounts $38,706  $32,082  $57,086  $49,628 
Net Cash Paid (Received) for Income Taxes  13,827   (20,001) 
Net Cash Paid for Income Taxes  7,482   14,395 
Noncash Acquisitions Under Capital Leases  2,911   1,160   3,279   5,847 
Construction Expenditures Included in Accounts Payable at June 30,  20,650   24,145 
Acquisition of Nuclear Fuel Included in Accounts Payable at June 30,  -   30,867 
Construction Expenditures Included in Accounts Payable at September 30,  26,150   23,935 
Acquisition of Nuclear Fuel Included in Accounts Payable at September 30,  66,127   691 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

 
 
 

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

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

 
Footnote
Reference
  
Significant Accounting MattersNote 1
New Accounting Pronouncements and Extraordinary ItemNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
Benefit PlansNote 6
Business SegmentsNote 7
Income TaxesNote 8
Financing ActivitiesNote 9



 
 
 





 


OHIO POWER COMPANY CONSOLIDATED
Financing Activity

Long-term debt issuances, retirements and principal payments made during the first nine months of 2008 were:

Issuances
  Principal Interest Due
Type of Debt Amount Rate Date
  (in thousands) (%)  
Pollution Control Bonds $40,000  4.85 2019
Pollution Control Bonds  30,000  4.85 2019
Pollution Control Bonds  75,000  Variable 2036
Pollution Control Bonds  50,275  Variable 2036
Senior Unsecured Notes  500,000  7.00 2038

Retirements and Principal Payments
  Principal Interest Due
Type of Debt Amount Paid Rate Date
  (in thousands) (%)  
Pollution Control Bonds $40,000  Variable 2019
Pollution Control Bonds  30,000  Variable 2019
Pollution Control Bonds  17,500  Variable 2021
Pollution Control Bonds  50,275  Variable 2036
Pollution Control Bonds  75,000  Variable 2037
Senior Unsecured Notes  200,000  3.60 2008
Other  11  13.718 2026

Liquidity

In recent months, the financial markets have become increasingly unstable and constrained at both a global and domestic level.  This systemic marketplace distress is impacting APCo’s access to capital, liquidity and cost of capital.  The uncertainties in the credit markets could have significant implications on APCo since it relies on continuing access to capital to fund operations and capital expenditures.

APCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  APCo has $150 million of Senior Unsecured Notes that will mature in 2009.  To the extent refinancing is unavailable due to the challenging credit markets, APCo will rely upon cash flows from operations and access to the Utility Money Pool to fund its maturity, continuing operations and capital expenditures.

Summary Obligation Information

A summary of contractual obligations is included in the 2007 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” and “Financing Activity” above and letters of credit.  In April 2008, the Registrant Subsidiaries and certain other companies in the AEP System entered into a $650 million 3-year credit agreement and a $350 million 364-day credit agreement which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23 million and $12 million, respectively, following its bankruptcy.  As of September 30, 2008, $127 million of letters of credit were issued by APCo under the 3-year credit agreement to support variable rate demand notes.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, APCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be.  Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases which have a probable likelihood of loss and the loss amount 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 2007 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries”.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for additional discussion of relevant factors.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2007 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of adoption of new accounting pronouncements.

 
 
 
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Risk management assets and liabilities are managed by AEPSC as agent.  The related risk management policies and procedures are instituted and administered by AEPSC.  See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section.  The following tables provide information about AEP’s risk management activities’ effect on APCo.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in APCo’s Condensed Consolidated Balance Sheet as of September 30, 2008 and the reasons for changes in total MTM value as compared to December 31, 2007.
Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of September 30, 2008
(in thousands)

     Cash Flow          
  MTM Risk  &  DETM       
  Management  Fair Value  Assignment  Collateral    
  Contracts  Hedges  (a)  Deposits  Total 
Current Assets $81,386  $4,104  $-  $(3,532) $81,958 
Noncurrent Assets  58,881   1,036   -   (4,718)  55,199 
Total MTM Derivative Contract Assets  140,267   5,140   -   (8,250)  137,157 
                     
Current Liabilities  (69,529)  (2,996)  (3,127)  547   (75,105)
Noncurrent Liabilities  (29,631)  -   (3,194)  50   (32,775)
Total MTM Derivative Contract Liabilities  (99,160)  (2,996)  (6,321)  597   (107,880)
                     
Total MTM Derivative Contract Net Assets (Liabilities) $41,107  $2,144  $(6,321) $(7,653) $29,277 

(a)See “Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual Report.

MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2008
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2007 $45,870 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period  (13,569)
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  - 
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b)  564 
Changes in Fair Value Due to Market Fluctuations During the Period (c)  (165)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)  8,407 
Total MTM Risk Management Contract Net Assets  41,107 
Net Cash Flow & Fair Value Hedge Contracts  2,144 
DETM Assignment (e)  (6,321)
Collateral Deposits  (7,653)
Ending Net Risk Management Assets at September 30, 2008 $29,277 

(a)Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term.  The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)Represents the impact of applying AEP’s credit risk when measuring the fair value of derivative liabilities according to SFAS 157.
(c)Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(d)“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income.  These net gains (losses) are recorded as regulatory assets/liabilities.
(e)See “Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual Report.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The following table presents the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash:

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2008
(in thousands)

  Remainder              After    
  2008  2009  2010  2011  2012  2012  Total 
Level 1 (a) $(998) $(2,295) $(21) $-  $-  $-  $(3,314)
Level 2 (b)  1,480   18,258   12,918   1,662   485   -   34,803 
Level 3 (c)  (3,850)  666   (1,881)  272   152   -   (4,641)
Total  (3,368)  16,629   11,016   1,934   637   -   26,848 
Dedesignated Risk Management Contracts (d)  1,403   4,720   4,681   1,823   1,632   -   14,259 
Total MTM Risk Management Contract Net Assets (Liabilities) $(1,965) $21,349  $15,697  $3,757  $2,269  $-  $41,107 

(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 SFAS 133.  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 contract.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed Consolidated Balance Sheet

APCo is exposed to market fluctuations in energy commodity prices impacting power operations.  Management  monitors these risks on future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows.  Management does not hedge all commodity price risk.

Management uses interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt.  Management does not hedge all interest rate risk.

Management uses foreign currency derivatives to lock in prices on certain forecasted transactions denominated in foreign currencies where deemed necessary, and designates qualifying instruments as cash flow hedges.  Management does not hedge all foreign currency exposure.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on APCo’s Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2007 to September 30, 2008.  Only contracts designated as cash flow hedges are recorded in AOCI.  Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables.  All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2008
(in thousands)
     Interest  Foreign   
  Power  Rate  Currency  Total
Beginning Balance in AOCI December 31, 2007 $783   $(6,602)  $(125)  $(5,944)
Changes in Fair Value  670    (3,114)   68    (2,376)
Reclassifications from AOCI for Cash Flow Hedges Settled  (118)   1,231    5    1,118 
Ending Balance in AOCI September 30, 2008 $1,335   $(8,485)  $(52)  $(7,202)

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $1 million loss.

Credit Risk

Counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

Management uses risk measurement model, which calculates Value at Risk (VaR) to measure commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, at September 30, 2008, a near term typical change in commodity prices is not expected to have a material effect on APCo’s 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 periods indicated:

Nine Months Ended
September 30, 2008
    
Twelve Months Ended
December 31, 2007
(in thousands)    (in thousands)
End High Average Low    End High Average Low
$725 $1,096 $416 $161    $455 $2,328 $569 $117

Management back-tests its VaR results against performance due to actual price moves.  Based on the assumed 95% confidence interval, the performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days.  Management’s backtesting results show that its actual performance exceeded VaR far fewer than once every 20 trading days.  As a result, management believes APCo’s VaR calculation is conservative.

As APCo’s VaR calculation captures recent price moves, management also performs regular stress testing of the portfolio to understand its exposure to extreme price moves.  Management employs a historically-based method whereby the current portfolio is subjected to actual, observed price moves from the last three years in order to ascertain which historical price moves translate into the largest potential mark-to-market loss.  Management then researches the underlying positions, price moves and market events that created the most significant exposure.

Interest Rate Risk

OHIOManagement utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which APCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  The estimated EaR on APCo’s debt portfolio was $4.3 million.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)

  Three Months Ended  Nine Months Ended 
  2008  2007  2008  2007 
REVENUES            
Electric Generation, Transmission and Distribution $719,295  $639,830  $1,926,841  $1,740,565 
Sales to AEP Affiliates  74,632   64,099   262,230   181,015 
Other  4,906   2,647   12,186   8,134 
TOTAL  798,833   706,576   2,201,257   1,929,714 
                 
EXPENSES                
Fuel and Other Consumables Used for Electric Generation  220,955   200,702   554,022   535,906 
Purchased Electricity for Resale  71,075   47,430   167,205   117,708 
Purchased Electricity from AEP Affiliates  219,595   171,288   595,433   443,519 
Other Operation  66,316   94,190   210,262   236,944 
Maintenance  51,292   49,708   161,371   146,875 
Depreciation and Amortization  62,364   51,864   186,528   142,100 
Taxes Other Than Income Taxes  24,319   23,561   72,414   67,811 
TOTAL  715,916   638,743   1,947,235   1,690,863 
                 
OPERATING INCOME  82,917   67,833   254,022   238,851 
                 
Other Income (Expense):                
Interest Income  1,945   510   7,541   1,539 
Carrying Costs Income  11,924   8,701   38,921   22,817 
Allowance for Equity Funds Used During Construction  2,130   1,084   6,278   5,442 
Interest Expense  (47,385)  (44,980)  (138,644)  (121,758)
                 
INCOME BEFORE INCOME TAX EXPENSE  51,531   33,148   168,118   146,891 
                 
Income Tax Expense  12,516   9,090   47,508   49,325 
                 
INCOME BEFORE EXTRAORDINARY LOSS  39,015   24,058   120,610   97,566 
                 
Extraordinary Loss – Reapplication of Regulatory Accounting for Generation, Net of Tax  -   -   -   (78,763)
                 
NET INCOME  39,015   24,058   120,610   18,803 
                 
Preferred Stock Dividend Requirements Including Capital Stock Expense  238   238   714   714 
                 
EARNINGS APPLICABLE TO COMMON STOCK $38,777  $23,820  $119,896  $18,089 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)

  Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
DECEMBER 31, 2006 $260,458  $1,024,994  $805,513  $(54,791) $2,036,174 
                     
FIN 48 Adoption, Net of Tax          (2,685)      (2,685)
Common Stock Dividends          (25,000)      (25,000)
Preferred Stock Dividends          (600)      (600)
Capital Stock Expense      117   (114)      3 
TOTAL                  2,007,892 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income (Loss), Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $539              (1,000)  (1,000)
SFAS 158 Costs Established as a Regulatory Asset Related to the Reapplication of SFAS 71, Net of Tax of $6,055              11,245   11,245 
NET INCOME          18,803       18,803 
TOTAL COMPREHENSIVE INCOME                  29,048 
                     
SEPTEMBER 30, 2007 $260,458  $1,025,111  $795,917  $(44,546) $2,036,940 
                     
DECEMBER 31, 2007 $260,458  $1,025,149  $831,612  $(35,187) $2,082,032 
                     
EITF 06-10 Adoption, Net of Tax of $1,175          (2,181)      (2,181)
SFAS 157 Adoption, Net of Tax of $154          (286)      (286)
Capital Contribution from Parent      175,000           175,000 
Preferred Stock Dividends          (599)      (599)
Capital Stock Expense      115   (115)      - 
TOTAL                  2,253,966 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income (Loss), Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $677                       (1,258)  (1,258)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,346              2,499   2,499 
NET INCOME          120,610       120,610 
TOTAL COMPREHENSIVE INCOME                  121,851 
                     
SEPTEMBER 30, 2008 $260,458  $1,200,264  $949,041  $(33,946) $2,375,817 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2008 and December 31, 2007
(in thousands)
(Unaudited)

  2008  2007 
CURRENT ASSETS      
Cash and Cash Equivalents $1,987  $2,195 
Accounts Receivable:        
Customers  204,692   176,834 
Affiliated Companies  96,277   113,582 
Accrued Unbilled Revenues  43,333   38,397 
Miscellaneous  1,923   2,823 
Allowance for Uncollectible Accounts  (16,224)  (13,948)
Total Accounts Receivable  330,001   317,688 
Fuel  80,853   82,203 
Materials and Supplies  74,552   76,685 
Risk Management Assets  81,958   62,955 
Regulatory Asset for Under-Recovered Fuel Costs  90,111   - 
Prepayments and Other  60,431   16,369 
TOTAL  719,893   558,095 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Production  3,655,253   3,625,788 
Transmission  1,739,018   1,675,081 
Distribution  2,453,323   2,372,687 
Other  362,985   351,827 
Construction Work in Progress  947,101   713,063 
Total  9,157,680   8,738,446 
Accumulated Depreciation and Amortization  2,662,328   2,591,833 
TOTAL - NET  6,495,352   6,146,613 
         
OTHER NONCURRENT ASSETS        
Regulatory Assets  712,001   652,739 
Long-term Risk Management Assets  55,199   72,366 
Deferred Charges and Other  179,054   191,871 
TOTAL  946,254   916,976 
         
TOTAL ASSETS $8,161,499  $7,621,684 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2008 and December 31, 2007
(Unaudited)

  2008  2007 
CURRENT LIABILITIES (in thousands) 
Advances from Affiliates $93,558  $275,257 
Accounts Payable:        
General  290,320   241,871 
Affiliated Companies  105,647   106,852 
Long-term Debt Due Within One Year – Nonaffiliated  150,016   239,732 
Risk Management Liabilities  75,105   51,708 
Customer Deposits  51,243   45,920 
Accrued Taxes  34,154   58,519 
Accrued Interest  68,110   41,699 
Other  98,950   139,476 
TOTAL  967,103   1,201,034 
         
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated  2,873,980   2,507,567 
Long-term Debt – Affiliated  100,000   100,000 
Long-term Risk Management Liabilities  32,775   47,357 
Deferred Income Taxes  1,073,269   948,891 
Regulatory Liabilities and Deferred Investment Tax Credits  509,068   505,556 
Deferred Credits and Other  211,735   211,495 
TOTAL  4,800,827   4,320,866 
         
TOTAL LIABILITIES  5,767,930   5,521,900 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  17,752   17,752 
         
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  1,200,264   1,025,149 
Retained Earnings  949,041   831,612 
Accumulated Other Comprehensive Income (Loss)  (33,946)  (35,187)
TOTAL  2,375,817   2,082,032 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $8,161,499  $7,621,684 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)

  2008  2007 
OPERATING ACTIVITIES      
Net Income $120,610  $18,803 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization  186,528   142,100 
Deferred Income Taxes  111,297   32,021 
Extraordinary Loss, Net of Tax  -   78,763 
Carrying Costs Income  (38,921)  (22,817)
Allowance for Equity Funds Used During Construction  (6,278)  (5,442)
Mark-to-Market of Risk Management Contracts  7,450   (1,949)
Change in Other Noncurrent Assets  (24,670)  (9,185)
Change in Other Noncurrent Liabilities  (12,565)  27,247 
Changes in Certain Components of Working Capital:        
Accounts Receivable, Net  (12,313)  (87)
Fuel, Materials and Supplies  3,483   (11,387)
Accounts Payable  41,869   (38,724)
Accrued Taxes, Net  (51,208)  (9,990)
Accrued Interest  26,411   28,596 
Fuel Over/Under-Recovery, Net  (113,748)  35,770 
Other Current Assets  (17,202)  (21,483)
Other Current Liabilities  (12,298)  (20,702)
Net Cash Flows from Operating Activities  208,445   221,534 
         
INVESTING ACTIVITIES        
Construction Expenditures  (487,797)  (537,930)
Change in Other Cash Deposits, Net  (18)  (29)
Change in Advances to Affiliates, Net  -   (38,573)
Proceeds from Sales of Assets  15,786   6,713 
Other  -   (200)
Net Cash Flows Used for Investing Activities  (472,029)  (570,019)
         
FINANCING ACTIVITIES        
Capital Contribution from Parent  175,000   - 
Issuance of Long-term Debt – Nonaffiliated  686,512   568,778 
Change in Advances from Affiliates, Net  (181,699)  (34,975)
Retirement of Long-term Debt – Nonaffiliated  (412,786)  (125,009)
Retirement of Cumulative Preferred Stock  -   (9)
Principal Payments for Capital Lease Obligations  (3,052)  (3,316)
Amortization of Funds from Amended Coal Contract  -   (32,433)
Dividends Paid on Common Stock  -   (25,000)
Dividends Paid on Cumulative Preferred Stock  (599)  (600)
Net Cash Flows from Financing Activities  263,376   347,436 
         
Net Decrease in Cash and Cash Equivalents  (208)  (1,049)
Cash and Cash Equivalents at Beginning of Period  2,195   2,318 
Cash and Cash Equivalents at End of Period $1,987  $1,269 
         
SUPPLEMENTARY INFORMATION        
Cash Paid for Interest, Net of Capitalized Amounts $110,349  $86,199 
Net Cash Paid (Received) for Income Taxes  (26,330)  6,688 
Noncash Acquisitions Under Capital Leases  1,246   2,738 
Construction Expenditures Included in Accounts Payable at September 30,  112,376   90,315 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

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

Footnote Reference
Significant Accounting MattersNote 1
New Accounting Pronouncements and Extraordinary ItemNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
Benefit PlansNote 6
Business SegmentsNote 7
Income TaxesNote 8
Financing ActivitiesNote 9






COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations

SecondThird Quarter of 2008 Compared to SecondThird Quarter of 2007

Reconciliation of SecondThird Quarter of 2007 to SecondThird Quarter of 2008
Net Income
(in millions)

Second Quarter of 2007    $74 
Third Quarter of 2007    $85 
              
Changes in Gross Margin:              
Retail Margins  (46)      (4)    
Off-system Sales  9       5     
Other  2     
Transmission Revenues  1     
Total Change in Gross Margin      (35)      2 
                
Changes in Operating Expenses and Other:                
Other Operation and Maintenance  (13)      (2)    
Depreciation and Amortization  14       (3)    
Taxes Other Than Income Taxes  4       (3)    
Interest Expense  (1)    
Other Income  2       2     
Interest Expense  (8)    
Total Change in Operating Expenses and Other      (1)      (7)
                
Income Tax Expense      15       2 
                
Second Quarter of 2008     $53 
Third Quarter of 2008     $82 

Net Income decreased $21$3 million to $53$82 million in 2008.  The key drivers of the decrease were a $7 million increase in Operating Expenses and Other, partially offset by a $2 million increase in Gross Margin and a $2 million decrease in Income Tax Expense.

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 $4 million primarily due to:
·A $23 million decrease in residential and commercial revenue primarily due to a 12% decrease in cooling degree days and the outages caused by the remnants of Hurricane Ike.
·A $20 million decrease related to increased fuel, allowance and consumables expenses.  CSPCo and OPCo have applied for an active fuel clause in their Ohio ESP to be effective January 1, 2009.
·A $4 million increase in capacity settlement charges under the Interconnection Agreement due to a change in relative peak demands.
These decreases were partially offset by a $44 million increase related to a net increase in rates implemented.
·Margins from Off-system Sales increased $5 million primarily due to increased physical sales margins driven by higher prices, partially offset by lower trading margins.

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

·Other Operation and Maintenance expenses increased $2 million due to:
· A $9 million increase in recoverable PJM costs.
· A $4 million increase in recoverable customer account expenses related to the Universal Service Fund for customers who qualify for payment assistance.
· A $3 million increase in employee-related expenses.
These increases were partially offset by a $15 million decrease resulting from a settlement agreement in the third quarter 2007 related to alleged violations of the NSR provisions of the CAA.  The $15 million represents CSPCo’s allocation of the settlement.
·Depreciation and Amortization increased $3 million primarily due to a greater depreciation base related to environmental improvements placed in service.
·Taxes Other Than Income Taxes increased $3 million due to property tax adjustments.
·Income Tax Expense decreased $2 million primarily due to a decrease in pretax book income.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Reconciliation of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2008
Net Income
(in millions)

Nine Months Ended September 30, 2007    $212 
        
Changes in Gross Margin:       
Retail Margins  36     
Off-system Sales  24     
Transmission Revenues  3     
Total Change in Gross Margin      63 
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  (45)    
Depreciation and Amortization  1     
Taxes Other Than Income Taxes  (12)    
Interest Expense  (6)    
Other Income  5     
Total Change in Operating Expenses and Other      (57)
         
Income Tax Expense      (4)
         
Nine Months Ended September 30, 2008     $214 

Net Income increased $2 million to $214 million in 2008.  The key drivers of the increase were a $63 million increase in Gross Margin primarily offset by a $57 million increase in Operating Expenses and Other and a $4 million increase in Income Tax Expense.

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 $36 million primarily due to:
·A $106 million increase related to a net increase in rates implemented.
·A $35 million decrease in capacity settlement charges related to CSPCo’s Unit Power Agreement (UPA) for AEGCo’s Lawrenceburg Plant, which began in May 2007, and to the April 2007 acquisition of the Darby Plant.
·A $15 million increase in industrial revenue related to higher usage by Ormet.
These increases were partially offset by:
·A $59 million decrease related to increased fuel, allowance and consumables expenses.  CSPCo and OPCo have applied for an active fuel clause in their Ohio ESP to be effective January 1, 2009.
·A $35 million decrease in residential and commercial revenue primarily due to a 16% decrease in cooling and a 6% decrease in heating degree days.
·Margins from Off-system Sales increased $24 million primarily due to increased physical sales margins driven by higher prices, partially offset by lower trading margins.

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

·Other Operation and Maintenance expenses increased $45 million primarily due to:
·A $17 million increase in recoverable PJM expenses.
·A $13 million increase in expenses related to CSPCo’s UPA for AEGCo’s Lawrenceburg Plant which began in May 2007.
·A $10 million increase in steam plant maintenance expenses primarily related to work performed at the Conesville Plant.
·A $9 million increase in recoverable customer account expenses related to the Universal Service Fund for customers who qualify for payment assistance.
·A $4 million increase in boiler plant removal expenses primarily related to work performed at the Conesville Plant.
These increases were partially offset by a $15 million decrease resulting from a settlement agreement in the third quarter 2007 related to alleged violations of the NSR provisions of the CAA.  The $15 million represents CSPCo’s allocation of the settlement.
·Taxes Other Than Income Taxes increased $12 million due to property tax adjustments.
·Interest Expense increased $6 million due to increased long-term borrowings.
·Other Income increased $5 million primarily due to interest income on federal tax refunds.
·Income Tax Expense increased $4 million primarily due to an increase in pretax book income and state income taxes.
Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2007 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of adoption of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

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 and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

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 CSPCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  The estimated EaR on CSPCo’s debt portfolio was $1.3 million.
 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)

  Three Months Ended  Nine Months Ended 
  2008  2007  2008  2007 
REVENUES            
Electric Generation, Transmission and Distribution $633,325  $553,518  $1,638,705  $1,446,632 
Sales to AEP Affiliates  29,032   52,331   111,553   110,700 
Other  1,426   1,292   4,121   3,743 
TOTAL  663,783   607,141   1,754,379   1,561,075 
                 
EXPENSES                
Fuel and Other Consumables Used for Electric Generation  112,566   103,560   283,946   255,764 
Purchased Electricity for Resale  63,441   49,619   150,637   113,765 
Purchased Electricity from AEP Affiliates  139,017   107,386   343,699   278,715 
Other Operation  87,358   83,625   245,379   207,300 
Maintenance  23,039   24,250   80,705   73,537 
Depreciation and Amortization  50,373   47,589   146,668   147,332 
Taxes Other Than Income Taxes  44,533   41,382   130,078   117,760 
TOTAL  520,327   457,411   1,381,112   1,194,173 
                 
OPERATING INCOME  143,456   149,730   373,267   366,902 
                 
Other Income (Expense):                
Interest Income  1,515   166   5,457   782 
Carrying Costs Income  1,566   1,261   4,870   3,492 
Allowance for Equity Funds Used During Construction  745   738   2,165   2,130 
Interest Expense  (21,127)  (19,530)  (57,612)  (51,193)
                 
INCOME BEFORE INCOME TAX EXPENSE  126,155   132,365   328,147   322,113 
                 
Income Tax Expense  44,493   46,911   113,939   109,656 
                 
NET INCOME  81,662   85,454   214,208   212,457 
                 
Capital Stock Expense  39   39   118   118 
                 
EARNINGS APPLICABLE TO COMMON STOCK $81,623  $85,415  $214,090  $212,339 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)

  Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
DECEMBER 31, 2006 $41,026  $580,192  $456,787  $(21,988) $1,056,017 
                     
FIN 48 Adoption, Net of Tax          (3,022)      (3,022)
Common Stock Dividends          (90,000)      (90,000)
Capital Stock Expense and Other      118   (118)      - 
TOTAL                  962,995 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Loss, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $1,231              (2,285)  (2,285)
NET INCOME          212,457       212,457 
TOTAL COMPREHENSIVE INCOME                  210,172 
                     
SEPTEMBER 30, 2007 $41,026  $580,310  $576,104  $(24,273) $1,173,167 
                     
DECEMBER 31, 2007 $41,026  $580,349  $561,696  $(18,794) $1,164,277 
                     
EITF 06-10 Adoption, Net of Tax of $589          (1,095)      (1,095)
SFAS 157 Adoption, Net of Tax of $170          (316)      (316)
Common Stock Dividends          (87,500)      (87,500)
Capital Stock Expense      118   (118)      - 
TOTAL                  1,075,366 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $582              1,080   1,080 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $456              846   846 
NET INCOME          214,208       214,208 
TOTAL COMPREHENSIVE INCOME                  216,134 
                     
SEPTEMBER 30, 2008 $41,026  $580,467  $686,875  $(16,868) $1,291,500 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2008 and December 31, 2007
(in thousands)
(Unaudited)

  2008  2007 
CURRENT ASSETS      
Cash and Cash Equivalents $1,956  $1,389 
Other Cash Deposits  31,964   53,760 
Advances to Affiliates  21,833   - 
Accounts Receivable:        
Customers  65,581   57,268 
Affiliated Companies  27,933   32,852 
Accrued Unbilled Revenues  24,078   14,815 
Miscellaneous  11,256   9,905 
Allowance for Uncollectible Accounts  (2,814)  (2,563)
Total Accounts Receivable  126,034   112,277 
Fuel  30,081   35,849 
Materials and Supplies  34,979   36,626 
Emission Allowances  7,884   16,811 
Risk Management Assets  40,842   33,558 
Prepayments and Other  31,984   9,960 
TOTAL  327,557   300,230 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Production  2,317,357   2,072,564 
Transmission  568,380   510,107 
Distribution  1,600,323   1,552,999 
Other  211,475   198,476 
Construction Work in Progress  322,885   415,327 
Total  5,020,420   4,749,473 
Accumulated Depreciation and Amortization  1,758,415   1,697,793 
TOTAL - NET  3,262,005   3,051,680 
         
OTHER NONCURRENT ASSETS        
Regulatory Assets  204,203   235,883 
Long-term Risk Management Assets  30,268   41,852 
Deferred Charges and Other  125,071   181,563 
TOTAL  359,542   459,298 
         
TOTAL ASSETS $3,949,104  $3,811,208 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY
September 30, 2008 and December 31, 2007
(Unaudited)

  2008  2007 
CURRENT LIABILITIES (in thousands) 
Advances from Affiliates $-  $95,199 
Accounts Payable:        
General  145,733   113,290 
Affiliated Companies  53,532   65,292 
Long-term Debt Due Within One Year – Nonaffiliated  -   112,000 
Risk Management Liabilities  37,331   28,237 
Customer Deposits  29,995   43,095 
Accrued Taxes  153,391   179,831 
Other  84,432   96,892 
TOTAL  504,414   733,836 
         
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated  1,343,491   1,086,224 
Long-term Debt – Affiliated  100,000   100,000 
Long-term Risk Management Liabilities  18,061   27,419 
Deferred Income Taxes  447,465   437,306 
Regulatory Liabilities and Deferred Investment Tax Credits  155,332   165,635 
Deferred Credits and Other  88,841   96,511 
TOTAL  2,153,190   1,913,095 
         
TOTAL LIABILITIES  2,657,604   2,646,931 
         
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  580,467   580,349 
Retained Earnings  686,875   561,696 
Accumulated Other Comprehensive Income (Loss)  (16,868)  (18,794)
TOTAL  1,291,500   1,164,277 
         
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY $3,949,104  $3,811,208 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)


  2008  2007 
OPERATING ACTIVITIES      
Net Income $214,208  $212,457 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization  146,668   147,332 
Deferred Income Taxes  8,981   (13,959)
Carrying Costs Income  (4,870)  (3,492)
Allowance for Equity Funds Used During Construction  (2,165)  (2,130)
Mark-to-Market of Risk Management Contracts  5,326   1,321 
Deferred Property Taxes  65,763   57,890 
Change in Other Noncurrent Assets  (7,942)  (29,199)
Change in Other Noncurrent Liabilities  (4,081)  2,713 
Changes in Certain Components of Working Capital:        
Accounts Receivable, Net  (13,757)  (13,040)
Fuel, Materials and Supplies  7,415   (2,332)
Accounts Payable  (2,650)  (13,336)
Customer Deposits  (13,100)  10,212 
Accrued Taxes, Net  (26,358)  (44,295)
Other Current Assets  (13,178)  (1,490)
Other Current Liabilities  (14,018)  8,817 
Net Cash Flows from Operating Activities  346,242   317,469 
         
INVESTING ACTIVITIES        
Construction Expenditures  (304,175)  (246,130)
Change in Other Cash Deposits, Net  21,796   (44,360)
Change in Advances to Affiliates, Net  (21,833)  - 
Acquisition of Darby Plant  -   (102,032)
Proceeds from Sales of Assets  1,287   1,016 
Net Cash Flows Used for Investing Activities  (302,925)  (391,506)
         
FINANCING ACTIVITIES        
Issuance of Long-term Debt – Nonaffiliated  346,407   44,257 
Change in Advances from Affiliates, Net  (95,199)  122,347 
Retirement of Long-term Debt – Nonaffiliated  (204,245)  - 
Principal Payments for Capital Lease Obligations  (2,213)  (2,191)
Dividends Paid on Common Stock  (87,500)  (90,000)
Net Cash Flows from (Used for) Financing Activities  (42,750)  74,413 
         
Net Increase in Cash and Cash Equivalents  567   376 
Cash and Cash Equivalents at Beginning of Period  1,389   1,319 
Cash and Cash Equivalents at End of Period $1,956  $1,695 
         
SUPPLEMENTARY INFORMATION        
Cash Paid for Interest, Net of Capitalized Amounts $57,004  $53,464 
Net Cash Paid for Income Taxes  53,682   93,709 
Noncash Acquisitions Under Capital Leases  1,374   1,900 
Construction Expenditures Included in Accounts Payable at September 30,  51,997   34,630 
Noncash Assumption of Liabilities Related to Acquisition of Darby Plant  -   2,339 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

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

Footnote
Reference
Significant Accounting MattersNote 1
New Accounting Pronouncements and Extraordinary ItemNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
AcquisitionNote 5
Benefit PlansNote 6
Business SegmentsNote 7
Income TaxesNote 8
Financing ActivitiesNote 9






INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations

Third Quarter of 2008 Compared to Third Quarter of 2007

Reconciliation of Third Quarter of 2007 to Third Quarter of 2008
Net Income
(in millions)

Third Quarter of 2007    $49 
        
Changes in Gross Margin:       
Retail Margins  (16)    
FERC Municipals and Cooperatives  (2)    
Off-system Sales  4     
Other  10     
Total Change in Gross Margin      (4)
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  (2)    
Depreciation and Amortization  4     
Other Income  (1)    
Interest Expense  (2)    
Total Change in Operating Expenses and Other      (1)
         
Income Tax Expense      2 
         
Third Quarter of 2008     $46 

Net Income decreased $3 million to $46 million in 2008.  The key drivers of the decrease were a $4 million decrease in Gross Margin and a $1 million increase in Operating Expenses and Other, partially offset by a $15$2 million decrease in Income Tax Expense.

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 $46$16 million primarily due to the following:
·A $29 million decrease related to a coal contract amendment in the second quarter of 2008.
·A $29 million decrease related to increased fuel, consumable, allowance and PJM expenses.
·A $6 million decrease in residential revenue primarily due to a 27% decrease inlower retail sales reflecting weather conditions as cooling degree days decreased at least 12% in both the Indiana and a 30% decrease in heating degree days.
These decreases were partially offset by:
·A $14 million increase related to a net increase in rates implemented.Michigan jurisdictions.
·Margins from Off-system Sales increased $9$4 million primarily due to higherincreased physical sales margins driven by higher prices, partially offset by lower trading margins.
·Other revenues increased $10 million primarily due to increased River Transportation Division (RTD) revenues for barging services.  RTD’s related expenses which offset the RTD revenue increase are included in Other Operation on the Condensed Consolidated Statements of Income resulting in earning only a return approved under a regulatory order.

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

·Other Operation and Maintenance expenses increased $13$2 million primarily due to:
·A $10to higher operation and maintenance expenses for RTD of $11 million increasecaused by increased barging activity and increased cost of fuel in recoverable PJM expenses.
·A $10 million increase in steam plant maintenance expenses.
·A $3 million increase in recoverable customer account expenses related to the Universal Service Fund for customers who qualify for payment assistance.
These increases were2008, partially offset by:
·A $4by a $9 million decrease in overhead line maintenancecoal-fired plant operation expenses.
·A $3settlement agreement related to alleged violations of the NSR provisions of the CAA, of which $14 million decrease in removal expenses duewas allocated to work performed at the Cardinal, MitchellI&M, increased 2007 Other Operation and Gavin Plants in 2007.Maintenance expenses.
·Depreciation and Amortization decreased $14 million primarily due to:
·A $17 million decrease in amortization as a result of completion of amortization of regulatory assets in December 2007.
·A $3 million decrease due to the amortization of IGCC pre-construction costs, which ended in the second quarter of 2007.  The amortization of IGCC pre-construction costs was offset by a corresponding increase in Retail Margins in 2007.
These decreases were partially offset by:
·A $6 million increase in depreciation related to environmental improvements placed in service at the Cardinal Plant in 2008 and the Mitchell Plant in July 2007.
·Taxes Other Than Income Taxesexpense decreased $4 million primarily due to property tax adjustments.
·Interest Expense increased $8 million primarily due to a decreasereduced depreciation rates reflecting longer estimated lives for Cook and Tanners Creek Plants.  Depreciation rates were reduced for the FERC and Michigan jurisdictions in October 2007.  See “Michigan Depreciation Study Filing” section of Note 4 in the debt component of AFUDC as a result of Mitchell Plant and Cardinal Plant environmental improvements placed in service and higher interest rates on variable rate debt.2007 Annual Report.
·Income Tax Expense decreased $15$2 million primarily due to a decrease in pretax book income.

SixNine Months Ended JuneSeptember 30, 2008 Compared to SixNine Months Ended JuneSeptember 30, 2007

Reconciliation of SixNine Months Ended JuneSeptember 30, 2007 to SixNine Months Ended JuneSeptember 30, 2008
Net Income
(in millions)

Six Months Ended June 30, 2007    $154 
Nine Months Ended September 30, 2007    $109 
            
Changes in Gross Margin:             
Retail Margins  (6)      (19)    
FERC Municipals and Cooperatives  4   
Off-system Sales  23       18   
Transmission Revenues  (2)    
Other  9       31   
Total Change in Gross Margin      26     32 
             
Changes in Operating Expenses and Other:              
Other Operation and Maintenance  10       (24)    
Depreciation and Amortization  29       50   
Taxes Other Than Income Taxes  1       (3)    
Other Income  5     
Interest Expense  (16)    
Total Change in Operating Expenses and Other      29     23 
             
Income Tax Expense      (18)     (13) 
             
Six Months Ended June 30, 2008     $191 
Nine Months Ended September 30, 2008    $151 

Net Income increased $37$42 million to $191$151 million in 2008.  The key drivers of the increase were a $26$32 million increase in Gross Margin and a $29$23 million decrease in Operating Expenses and Other, partially offset by an $18a $13 million increase in Income Tax Expense.

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 $6$19 million primarily due to the following:
·A $76 million decrease related to increased fuel, consumable and PJM expenses.
·A $5 million decrease in residential and commercial revenues primarily due to a 28% decrease inlower retail sales reflecting weather conditions as cooling degree days.
These decreases were partially offset by:
·A $29 million increase related to coal contract amendmentsdays decreased at least 19% in 2008.
·A $25 million increase related to a net increase in rates implemented.
·A $15 million increase related to increased usage by Ormet, an industrial customer.  See “Ormet” section of Note 3.
·A $7 million increase in capacity settlements underboth the Interconnection Agreement related to an increase in an affiliate’s peak.Indiana and Michigan jurisdictions.
·Margins from Off-system Sales increased $23$18 million primarily due to higherincreased physical sales margins anddriven by higher prices, partially offset by lower trading margins.
·Other revenues increased $9$31 million primarily due to increased gainsRTD revenues for barging services.  RTD’s related expenses which offset the RTD revenue increase are included in Other Operation on salesthe Condensed Consolidated Statements of emission allowances.Income resulting in earning only a return approved under regulatory order.

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

·Other Operation and Maintenance expenses decreased $10increased $24 million primarily due to:
·A $21to higher operation and maintenance expenses for RTD of $31 million caused by increased barging activity and increased cost of fuel and an increase in nuclear operation and maintenance expenses of $16 million.  Lower coal-fired plant operation and maintenance expenses of $18 million, including the NSR settlement, and a $5 million decrease in removal expenses.
·A $9 million decrease in overhead line maintenance expenses.
These decreases wereaccretion expense partially offset by:
·A $7 million increase in recoverable customer account expenses related to the Universal Service Fund for customers who qualify for payment assistance.
·A $7 million increase in recoverable PJM expenses.increases.
·Depreciation and Amortization expense decreased $29 million primarily due to:
·A $35 million decrease in amortization as a result of completion of amortization of regulatory assets in December 2007.
·A $6 million decrease due to the amortization of IGCC pre-construction costs, which ended in the second quarter of 2007.  The amortization of IGCC pre-construction costs was offset by a corresponding increase in Retail Margins in 2007.
These decreases were partially offset by:
·A $14 million increase in depreciation related to environmental improvements placed in service at the Cardinal Plant in 2008 and the Mitchell Plant during 2007.
·Interest Expense increased $16$50 million primarily due to a decreasethe reduced depreciation rates in all jurisdictions.  Depreciation rates were reduced for the Indiana jurisdiction in June 2007 and the FERC and Michigan jurisdictions in October 2007.  See “Indiana Depreciation Study Filing” and “Michigan Depreciation Study Filing” sections of Note 4 in the debt component of AFUDC as a result of Mitchell Plant and Cardinal Plant environmental improvements placed in service, the issuance of additional long-term debt and higher interest rates on variable rate debt.2007 Annual Report.
·Income Tax Expense increased $18$13 million primarily due to an increase in pretax book income.income and a decrease in amortization of investment tax credits, partially offset by changes in certain book/tax differences accounted for on a flow-through basis.

Financial ConditionCook Plant Unit 1 Fire and Shutdown

Credit RatingsCook Plant Unit 1 (Unit 1) is a 1,030 MW nuclear generating unit located in Bridgman, Michigan. In September 2008, I&M shut down Unit 1 due to turbine vibrations likely caused by blade failure which resulted in a fire on the electric generator.  This equipment is in the turbine building and is separate and isolated from the nuclear reactor.  The steam turbines that caused the vibration were installed in 2006 and are under warranty from the vendor.  The warranty provides for the replacement of the turbines if the damage was caused by a defect in the design or assembly of the turbines.  I&M is also working with its insurance company, Nuclear Electric Insurance Limited (NEIL), and turbine vendor to evaluate the extent of the damage resulting from the incident and the costs to return the unit to service.  Management cannot estimate the ultimate costs of the outage at this time.  Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process.  Management's preliminary analysis indicates that Unit 1 could resume operations as early as late first quarter/early second quarter of 2009 or as late as the second half of 2009, depending upon whether the damaged components can be repaired or whether they need to be replaced.
I&M maintains property insurance through NEIL with a $1 million deductible.  I&M also maintains a separate accidental outage policy with NEIL whereby, after a 12 week deductible period, I&M is entitled to weekly payments of $3.5 million during the outage period for a covered loss.  If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if the unit is not returned to service in a reasonable period of time, it could have an adverse impact on net income, cash flows and financial condition.

S&PCritical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Fitch currently have OPCo on stable outlook, while Moody’s placed OPCo on negative outlookAnalysis of Registrant Subsidiaries” in the first quarter2007 Annual Report for a discussion of 2008.  Current ratingsthe estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of adoption of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Risk management assets and liabilities are managed by AEPSC as follows:agent.  The related risk management policies and procedures are instituted and administered by AEPSC.  See complete discussion and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

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 I&M’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  The estimated EaR on I&M’s debt portfolio was $5.7 million.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)

  Three Months Ended  Nine Months Ended 
  2008  2007  2008  2007 
REVENUES            
Electric Generation, Transmission and Distribution $513,548  $478,907  $1,370,158  $1,286,223 
Sales to AEP Affiliates  72,295   56,262   232,734   186,653 
Other – Affiliated  31,792   16,250   84,268   43,488 
Other – Nonaffiliated  3,388   7,757   13,659   21,718 
TOTAL  621,023   559,176   1,700,819   1,538,082 
                 
EXPENSES                
Fuel and Other Consumables Used for Electric Generation  141,563   103,740   351,300   290,507 
Purchased Electricity for Resale  39,427   26,580   87,351   63,830 
Purchased Electricity from AEP Affiliates  112,060   96,451   296,559   249,755 
Other Operation  136,875   129,439   381,928   367,483 
Maintenance  52,573   58,502   156,402   146,657 
Depreciation and Amortization  31,822   35,604   95,301   145,801 
Taxes Other Than Income Taxes  19,992   19,704   60,236   56,936 
TOTAL  534,312   470,020   1,429,077   1,320,969 
                 
OPERATING INCOME  86,711   89,156   271,742   217,113 
                 
Other Income (Expense):                
Other Income  880   1,986   4,621   4,273 
Interest Expense  (20,629)  (18,312)  (56,977)  (57,744)
                 
INCOME BEFORE INCOME TAX EXPENSE  66,962   72,830   219,386   163,642 
                 
Income Tax Expense  21,326   23,706   68,348   55,020 
                 
NET INCOME  45,636   49,124   151,038   108,622 
                 
Preferred Stock Dividend Requirements  85   85   255   255 
                 
EARNINGS APPLICABLE TO COMMON STOCK $45,551  $49,039  $150,783  $108,367 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)

  Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
DECEMBER 31, 2006 $56,584  $861,290  $386,616  $(15,051) $1,289,439 
                     
FIN 48 Adoption, Net of Tax          327       327 
Common Stock Dividends          (30,000)      (30,000)
Preferred Stock Dividends          (255)      (255)
Gain on Reacquired Preferred Stock      1           1 
TOTAL                  1,259,512 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Loss, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $941              (1,747)  (1,747)
NET INCOME          108,622       108,622 
TOTAL COMPREHENSIVE INCOME                  106,875 
                     
SEPTEMBER 30, 2007 $56,584  $861,291  $465,310  $(16,798) $1,366,387 
                     
DECEMBER 31, 2007 $56,584  $861,291  $483,499  $(15,675) $1,385,699 
                     
EITF 06-10 Adoption, Net of Tax of $753          (1,398)      (1,398)
Common Stock Dividends          (56,250)      (56,250)
Preferred Stock Dividends          (255)      (255)
TOTAL                  1,327,796 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $967              1,795   1,795 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $178              331   331 
NET INCOME          151,038       151,038 
TOTAL COMPREHENSIVE INCOME                  153,164 
                     
SEPTEMBER 30, 2008 $56,584  $861,291  $576,634  $(13,549) $1,480,960 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2008 and December 31, 2007
(in thousands)
(Unaudited)

  2008  2007 
CURRENT ASSETS      
Cash and Cash Equivalents $1,328  $1,139 
Accounts Receivable:        
Customers  82,788   70,995 
Affiliated Companies  77,640   92,018 
Accrued Unbilled Revenues  21,028   16,207 
Miscellaneous  2,010   1,335 
Allowance for Uncollectible Accounts  (3,200)  (2,711)
Total Accounts Receivable  180,266   177,844 
Fuel  46,745   61,342 
Materials and Supplies  143,245   141,384 
Risk Management Assets  40,215   32,365 
Accrued Tax Benefits  1,004   4,438 
Prepayments and Other  35,829   11,091 
TOTAL  448,632   429,603 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Production  3,512,424   3,529,524 
Transmission  1,100,255   1,078,575 
Distribution  1,262,017   1,196,397 
Other (including nuclear fuel and coal mining)  655,257   626,390 
Construction Work in Progress  173,062   122,296 
Total  6,703,015   6,553,182 
Accumulated Depreciation, Depletion and Amortization  3,000,898   2,998,416 
TOTAL - NET  3,702,117   3,554,766 
         
OTHER NONCURRENT ASSETS        
Regulatory Assets  251,451   246,435 
Spent Nuclear Fuel and Decommissioning Trusts  1,291,986   1,346,798 
Long-term Risk Management Assets  29,518   40,227 
Deferred Charges and Other  118,574   128,623 
TOTAL  1,691,529   1,762,083 
         
TOTAL ASSETS $5,842,278  $5,746,452 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2008 and December 31, 2007
(Unaudited)

  2008  2007 
CURRENT LIABILITIES (in thousands) 
Advances from Affiliates $224,071  $45,064 
Accounts Payable:        
General  177,480   184,435 
Affiliated Companies  64,970   61,749 
Long-term Debt Due Within One Year – Nonaffiliated  50,000   145,000 
Risk Management Liabilities  36,802   27,271 
Customer Deposits  26,957   26,445 
Accrued Taxes  60,111   60,995 
Obligations Under Capital Leases  43,626   43,382 
Other  133,267   130,232 
TOTAL  817,284   724,573 
         
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated  1,377,115   1,422,427 
Long-term Risk Management Liabilities  17,585   26,348 
Deferred Income Taxes  382,374   321,716 
Regulatory Liabilities and Deferred Investment Tax Credits  693,981   789,346 
Asset Retirement Obligations  886,278   852,646 
Deferred Credits and Other  178,621   215,617 
TOTAL  3,535,954   3,628,100 
         
TOTAL LIABILITIES  4,353,238   4,352,673 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  8,080   8,080 
         
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  861,291   861,291 
Retained Earnings  576,634   483,499 
Accumulated Other Comprehensive Income (Loss)  (13,549)  (15,675)
TOTAL  1,480,960   1,385,699 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $5,842,278  $5,746,452 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)

  2008  2007 
OPERATING ACTIVITIES      
Net Income $151,038  $108,622 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization  95,301   145,801 
Deferred Income Taxes  47,565   (9,235)
Amortization of Incremental Nuclear Refueling Outage Expenses, Net  834   14,450 
Allowance for Equity Funds Used During Construction  (967)  (2,726)
Mark-to-Market of Risk Management Contracts  4,876   3,046 
Amortization of Nuclear Fuel  72,453   48,360 
Change in Other Noncurrent Assets  5,678   17,163 
Change in Other Noncurrent Liabilities  38,568   33,995 
Changes in Certain Components of Working Capital:        
Accounts Receivable, Net  (2,422)  34,569 
Fuel, Materials and Supplies  12,736   14,584 
Accounts Payable  16,549   (27,015)
Accrued Taxes, Net  2,550   41,243 
Other Current Assets  (24,736)  (4,595)
Other Current Liabilities  1,393   3,150 
Net Cash Flows from Operating Activities  421,416   421,412 
         
INVESTING ACTIVITIES        
Construction Expenditures  (221,538)  (191,110)
Purchases of Investment Securities  (413,538)  (561,509)
Sales of Investment Securities  362,773   505,620 
Acquisitions of Nuclear Fuel  (99,110)  (73,112)
Proceeds from Sales of Assets and Other  3,376   670 
Net Cash Flows Used for Investing Activities  (368,037)  (319,441)
         
FINANCING ACTIVITIES        
Issuance of Long-term Debt – Nonaffiliated  115,225   - 
Change in Advances from Affiliates, Net  179,007   (66,939)
Retirement of Long-term Debt – Nonaffiliated  (262,000)  - 
Retirement of Cumulative Preferred Stock  -   (2)
Principal Payments for Capital Lease Obligations  (28,917)  (3,954)
Dividends Paid on Common Stock  (56,250)  (30,000)
Dividends Paid on Cumulative Preferred Stock  (255)  (255)
Net Cash Flows Used for Financing Activities  (53,190)  (101,150)
         
Net Increase in Cash and Cash Equivalents  189   821 
Cash and Cash Equivalents at Beginning of Period  1,139   1,369 
Cash and Cash Equivalents at End of Period $1,328  $2,190 
         
SUPPLEMENTARY INFORMATION        
Cash Paid for Interest, Net of Capitalized Amounts $57,086  $49,628 
Net Cash Paid for Income Taxes  7,482   14,395 
Noncash Acquisitions Under Capital Leases  3,279   5,847 
Construction Expenditures Included in Accounts Payable at September 30,  26,150   23,935 
Acquisition of Nuclear Fuel Included in Accounts Payable at September 30,  66,127   691 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

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

 Moody’sS&PFitch
Footnote
Reference
  
Significant Accounting MattersNote 1
Senior Unsecured DebtNew Accounting Pronouncements and Extraordinary Item A3Note 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesBBBNote 4
Benefit PlansNote 6
Business SegmentsBBB+Note 7
Income TaxesNote 8
Financing ActivitiesNote 9

If OPCo receives an upgrade from any of the rating agencies listed above, its borrowing costs could decrease.  If OPCo receives a downgrade from any of the rating agencies listed above, it borrowing costs could increase and access to borrowed funds could be negatively affected.

Cash Flow

Cash flows for the six months ended June 30, 2008 and 2007 were as follows:

  2008  2007 
  (in thousands) 
Cash and Cash Equivalents at Beginning of Period $6,666  $1,625 
Cash Flows from (Used for):        
Operating Activities  289,944   279,029 
Investing Activities  (271,527)  (560,262)
Financing Activities  (14,985)  282,607 
Net Increase in Cash and Cash Equivalents  3,432   1,374 
Cash and Cash Equivalents at End of Period $10,098  $2,999 

Operating Activities

Net Cash Flows from Operating Activities were $290 million in 2008.  OPCo produced Net Income of $191 million during the period and a noncash expense item of $140 million for Depreciation and Amortization.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Accounts Payable had a $47 million inflow primarily due to increases in tonnage and prices per ton related to fuel and consumable purchases.  Fuel, Materials and Supplies had a $41 million outflow due to price increases.  Accounts Receivable, Net had a $38 million outflow primarily due to a coal contract amendment which reduced future deliveries in exchange for consideration received.

Net Cash Flows from Operating Activities were $279 million in 2007.  OPCo produced income of $154 million during the period and a noncash expense item of $169 million for Depreciation and Amortization.  The other changes in assets and liabilities represent items that had a prior 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 prior period activity in working capital relates to a number of items.  Accounts Payable had a $47 million cash outflow partially due to emission allowance payments in January 2007.  Accrued Taxes, Net, had a $47 million cash inflow primarily due to an increase of federal income tax related accruals offset by temporary timing differences of payments for property taxes.  Fuel, Materials and Supplies had a $42 million cash outflow primarily due to an increase in coal inventory in preparation for the summer cooling season and an increase in materials related to projects at the Mitchell, Amos, Gavin and Sporn Plants.

Investing Activities

Net Cash Used for Investing Activities were $272 million and $560 million in 2008 and 2007, respectively.  Construction Expenditures were $277 million and $566 million in 2008 and 2007, respectively, primarily related to environmental upgrades, as well as projects to improve service reliability for transmission and distribution.  Environmental upgrades include the installation of selective catalytic reduction equipment and the flue gas desulfurization projects at the Cardinal, Amos and Mitchell Plants.  In January 2007, environmental upgrades were completed for Unit 2 at the Mitchell Plant.  For the remainder of 2008, OPCo expects construction expenditures to be approximately $410 million.

Financing Activities

Net Cash Flows Used for Financing Activities were $15 million in 2008.  OPCo issued $165 million of Pollution Control Bonds and retired $250 million of Pollution Control Bonds.  OPCo had a net increase in borrowings of $72 million from the Utility Money Pool.

Net Cash Flows from Financing Activities were $283 million in 2007.  OPCo issued Senior Unsecured Notes for $400 million and $65 million of Pollution Control Bonds.  OPCo had a net decrease in borrowings of $165 million from the Utility Money Pool.

Financing Activity

Long-term debt issuances, retirements and principal payments made during the first sixnine months of 2008 were:

Issuances
��
Principal
Amount
 Interest Due Principal Interest Due
Type of Debt  Rate Date Amount Rate Date
  (in thousands) (%)   (in thousands) (%)  
Pollution Control Bonds $50,000 Variable 2014 $40,000  4.85 2019
Pollution Control Bonds  50,000 Variable 2014  30,000  4.85 2019
Pollution Control Bonds  65,000 Variable 2036  75,000  Variable 2036
Pollution Control Bonds  50,275  Variable 2036
Senior Unsecured Notes  500,000  7.00 2038

Retirements and Principal Payments

 
Principal
Amount Paid
 Interest Due Principal Interest Due
Type of Debt  Rate Date Amount Paid Rate Date
  (in thousands) (%)   (in thousands) (%)  
Notes Payable – Nonaffiliated $1,463 6.81 2008
Notes Payable – Nonaffiliated  6,000 6.27 2009
Pollution Control Bonds  50,000 Variable 2014 $40,000  Variable 2019
Pollution Control Bonds  50,000 Variable 2016  30,000  Variable 2019
Pollution Control Bonds  50,000 Variable 2022  17,500  Variable 2021
Pollution Control Bonds  35,000 Variable 2022  50,275  Variable 2036
Pollution Control Bonds  65,000 Variable 2036  75,000  Variable 2037
Senior Unsecured Notes  200,000  3.60 2008
Other  11  13.718 2026

Liquidity

OPCo has solid investment grade ratings, which provide readyIn recent months, the financial markets have become increasingly unstable and constrained at both a global and domestic level.  This systemic marketplace distress is impacting APCo’s access to capital, liquidity and cost of capital.  The uncertainties in the credit markets in ordercould have significant implications on APCo since it relies on continuing access to issue new debt, refinance short-term debt or refinance long-term debt maturities.  In addition, OPCocapital to fund operations and capital expenditures.

APCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  APCo has $150 million of Senior Unsecured Notes that will mature in 2009.  To the extent refinancing is unavailable due to the challenging credit markets, APCo will rely upon cash flows from operations and access to the Utility Money Pool to fund its maturity, continuing operations and capital expenditures.

Summary Obligation Information

A summary of contractual obligations is included in the 2007 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” and “Financing Activity” above and letters of credit.  In April 2008, the Registrant Subsidiaries and certain other companies in the AEP System entered into a $650 million 3-year credit agreement and a $350 million 364-day credit agreement.agreement which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23 million and $12 million, respectively, following its bankruptcy.  As of September 30, 2008, $127 million of letters of credit were issued by APCo under the 3-year credit agreement to support variable rate demand notes.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, APCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be.  Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases which have a probable likelihood of loss and the loss amount 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 2007 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries”.  Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for additional discussion of relevant factors.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2007 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of adoption of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Risk management assets and liabilities are managed by AEPSC as agent.  The related risk management policies and procedures are instituted and administered by AEPSC.  See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section.  The following tables provide information about AEP’s risk management activities’ effect on APCo.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in APCo’s Condensed Consolidated Balance Sheet as of September 30, 2008 and the reasons for changes in total MTM value as compared to December 31, 2007.
Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of September 30, 2008
(in thousands)

     Cash Flow          
  MTM Risk  &  DETM       
  Management  Fair Value  Assignment  Collateral    
  Contracts  Hedges  (a)  Deposits  Total 
Current Assets $81,386  $4,104  $-  $(3,532) $81,958 
Noncurrent Assets  58,881   1,036   -   (4,718)  55,199 
Total MTM Derivative Contract Assets  140,267   5,140   -   (8,250)  137,157 
                     
Current Liabilities  (69,529)  (2,996)  (3,127)  547   (75,105)
Noncurrent Liabilities  (29,631)  -   (3,194)  50   (32,775)
Total MTM Derivative Contract Liabilities  (99,160)  (2,996)  (6,321)  597   (107,880)
                     
Total MTM Derivative Contract Net Assets (Liabilities) $41,107  $2,144  $(6,321) $(7,653) $29,277 

(a)See “Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual Report.

MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2008
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2007 $45,870 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period  (13,569)
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  - 
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b)  564 
Changes in Fair Value Due to Market Fluctuations During the Period (c)  (165)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)  8,407 
Total MTM Risk Management Contract Net Assets  41,107 
Net Cash Flow & Fair Value Hedge Contracts  2,144 
DETM Assignment (e)  (6,321)
Collateral Deposits  (7,653)
Ending Net Risk Management Assets at September 30, 2008 $29,277 

(a)Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term.  The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)Represents the impact of applying AEP’s credit risk when measuring the fair value of derivative liabilities according to SFAS 157.
(c)Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(d)“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income.  These net gains (losses) are recorded as regulatory assets/liabilities.
(e)See “Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual Report.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The following table presents the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash:

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2008
(in thousands)

  Remainder              After    
  2008  2009  2010  2011  2012  2012  Total 
Level 1 (a) $(998) $(2,295) $(21) $-  $-  $-  $(3,314)
Level 2 (b)  1,480   18,258   12,918   1,662   485   -   34,803 
Level 3 (c)  (3,850)  666   (1,881)  272   152   -   (4,641)
Total  (3,368)  16,629   11,016   1,934   637   -   26,848 
Dedesignated Risk Management Contracts (d)  1,403   4,720   4,681   1,823   1,632   -   14,259 
Total MTM Risk Management Contract Net Assets (Liabilities) $(1,965) $21,349  $15,697  $3,757  $2,269  $-  $41,107 

(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 SFAS 133.  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 contract.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed Consolidated Balance Sheet

APCo is exposed to market fluctuations in energy commodity prices impacting power operations.  Management  monitors these risks on future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows.  Management does not hedge all commodity price risk.

Management uses interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt.  Management does not hedge all interest rate risk.

Management uses foreign currency derivatives to lock in prices on certain forecasted transactions denominated in foreign currencies where deemed necessary, and designates qualifying instruments as cash flow hedges.  Management does not hedge all foreign currency exposure.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on APCo’s Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2007 to September 30, 2008.  Only contracts designated as cash flow hedges are recorded in AOCI.  Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables.  All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2008
(in thousands)
     Interest  Foreign   
  Power  Rate  Currency  Total
Beginning Balance in AOCI December 31, 2007 $783   $(6,602)  $(125)  $(5,944)
Changes in Fair Value  670    (3,114)   68    (2,376)
Reclassifications from AOCI for Cash Flow Hedges Settled  (118)   1,231    5    1,118 
Ending Balance in AOCI September 30, 2008 $1,335   $(8,485)  $(52)  $(7,202)

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $1 million loss.

Credit Risk

Counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

Management uses risk measurement model, which calculates Value at Risk (VaR) to measure commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, at September 30, 2008, a near term typical change in commodity prices is not expected to have a material effect on APCo’s 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 periods indicated:

Nine Months Ended
September 30, 2008
    
Twelve Months Ended
December 31, 2007
(in thousands)    (in thousands)
End High Average Low    End High Average Low
$725 $1,096 $416 $161    $455 $2,328 $569 $117

Management back-tests its VaR results against performance due to actual price moves.  Based on the assumed 95% confidence interval, the performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days.  Management’s backtesting results show that its actual performance exceeded VaR far fewer than once every 20 trading days.  As a result, management believes APCo’s VaR calculation is conservative.

As APCo’s VaR calculation captures recent price moves, management also performs regular stress testing of the portfolio to understand its exposure to extreme price moves.  Management employs a historically-based method whereby the current portfolio is subjected to actual, observed price moves from the last three years in order to ascertain which historical price moves translate into the largest potential mark-to-market loss.  Management then researches the underlying positions, price moves and market events that created the most significant exposure.

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 APCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  The estimated EaR on APCo’s debt portfolio was $4.3 million.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)

  Three Months Ended  Nine Months Ended 
  2008  2007  2008  2007 
REVENUES            
Electric Generation, Transmission and Distribution $719,295  $639,830  $1,926,841  $1,740,565 
Sales to AEP Affiliates  74,632   64,099   262,230   181,015 
Other  4,906   2,647   12,186   8,134 
TOTAL  798,833   706,576   2,201,257   1,929,714 
                 
EXPENSES                
Fuel and Other Consumables Used for Electric Generation  220,955   200,702   554,022   535,906 
Purchased Electricity for Resale  71,075   47,430   167,205   117,708 
Purchased Electricity from AEP Affiliates  219,595   171,288   595,433   443,519 
Other Operation  66,316   94,190   210,262   236,944 
Maintenance  51,292   49,708   161,371   146,875 
Depreciation and Amortization  62,364   51,864   186,528   142,100 
Taxes Other Than Income Taxes  24,319   23,561   72,414   67,811 
TOTAL  715,916   638,743   1,947,235   1,690,863 
                 
OPERATING INCOME  82,917   67,833   254,022   238,851 
                 
Other Income (Expense):                
Interest Income  1,945   510   7,541   1,539 
Carrying Costs Income  11,924   8,701   38,921   22,817 
Allowance for Equity Funds Used During Construction  2,130   1,084   6,278   5,442 
Interest Expense  (47,385)  (44,980)  (138,644)  (121,758)
                 
INCOME BEFORE INCOME TAX EXPENSE  51,531   33,148   168,118   146,891 
                 
Income Tax Expense  12,516   9,090   47,508   49,325 
                 
INCOME BEFORE EXTRAORDINARY LOSS  39,015   24,058   120,610   97,566 
                 
Extraordinary Loss – Reapplication of Regulatory Accounting for Generation, Net of Tax  -   -   -   (78,763)
                 
NET INCOME  39,015   24,058   120,610   18,803 
                 
Preferred Stock Dividend Requirements Including Capital Stock Expense  238   238   714   714 
                 
EARNINGS APPLICABLE TO COMMON STOCK $38,777  $23,820  $119,896  $18,089 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)

  Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
DECEMBER 31, 2006 $260,458  $1,024,994  $805,513  $(54,791) $2,036,174 
                     
FIN 48 Adoption, Net of Tax          (2,685)      (2,685)
Common Stock Dividends          (25,000)      (25,000)
Preferred Stock Dividends          (600)      (600)
Capital Stock Expense      117   (114)      3 
TOTAL                  2,007,892 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income (Loss), Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $539              (1,000)  (1,000)
SFAS 158 Costs Established as a Regulatory Asset Related to the Reapplication of SFAS 71, Net of Tax of $6,055              11,245   11,245 
NET INCOME          18,803       18,803 
TOTAL COMPREHENSIVE INCOME                  29,048 
                     
SEPTEMBER 30, 2007 $260,458  $1,025,111  $795,917  $(44,546) $2,036,940 
                     
DECEMBER 31, 2007 $260,458  $1,025,149  $831,612  $(35,187) $2,082,032 
                     
EITF 06-10 Adoption, Net of Tax of $1,175          (2,181)      (2,181)
SFAS 157 Adoption, Net of Tax of $154          (286)      (286)
Capital Contribution from Parent      175,000           175,000 
Preferred Stock Dividends          (599)      (599)
Capital Stock Expense      115   (115)      - 
TOTAL                  2,253,966 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income (Loss), Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $677                       (1,258)  (1,258)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,346              2,499   2,499 
NET INCOME          120,610       120,610 
TOTAL COMPREHENSIVE INCOME                  121,851 
                     
SEPTEMBER 30, 2008 $260,458  $1,200,264  $949,041  $(33,946) $2,375,817 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2008 and December 31, 2007
(in thousands)
(Unaudited)

  2008  2007 
CURRENT ASSETS      
Cash and Cash Equivalents $1,987  $2,195 
Accounts Receivable:        
Customers  204,692   176,834 
Affiliated Companies  96,277   113,582 
Accrued Unbilled Revenues  43,333   38,397 
Miscellaneous  1,923   2,823 
Allowance for Uncollectible Accounts  (16,224)  (13,948)
Total Accounts Receivable  330,001   317,688 
Fuel  80,853   82,203 
Materials and Supplies  74,552   76,685 
Risk Management Assets  81,958   62,955 
Regulatory Asset for Under-Recovered Fuel Costs  90,111   - 
Prepayments and Other  60,431   16,369 
TOTAL  719,893   558,095 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Production  3,655,253   3,625,788 
Transmission  1,739,018   1,675,081 
Distribution  2,453,323   2,372,687 
Other  362,985   351,827 
Construction Work in Progress  947,101   713,063 
Total  9,157,680   8,738,446 
Accumulated Depreciation and Amortization  2,662,328   2,591,833 
TOTAL - NET  6,495,352   6,146,613 
         
OTHER NONCURRENT ASSETS        
Regulatory Assets  712,001   652,739 
Long-term Risk Management Assets  55,199   72,366 
Deferred Charges and Other  179,054   191,871 
TOTAL  946,254   916,976 
         
TOTAL ASSETS $8,161,499  $7,621,684 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2008 and December 31, 2007
(Unaudited)

  2008  2007 
CURRENT LIABILITIES (in thousands) 
Advances from Affiliates $93,558  $275,257 
Accounts Payable:        
General  290,320   241,871 
Affiliated Companies  105,647   106,852 
Long-term Debt Due Within One Year – Nonaffiliated  150,016   239,732 
Risk Management Liabilities  75,105   51,708 
Customer Deposits  51,243   45,920 
Accrued Taxes  34,154   58,519 
Accrued Interest  68,110   41,699 
Other  98,950   139,476 
TOTAL  967,103   1,201,034 
         
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated  2,873,980   2,507,567 
Long-term Debt – Affiliated  100,000   100,000 
Long-term Risk Management Liabilities  32,775   47,357 
Deferred Income Taxes  1,073,269   948,891 
Regulatory Liabilities and Deferred Investment Tax Credits  509,068   505,556 
Deferred Credits and Other  211,735   211,495 
TOTAL  4,800,827   4,320,866 
         
TOTAL LIABILITIES  5,767,930   5,521,900 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  17,752   17,752 
         
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  1,200,264   1,025,149 
Retained Earnings  949,041   831,612 
Accumulated Other Comprehensive Income (Loss)  (33,946)  (35,187)
TOTAL  2,375,817   2,082,032 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $8,161,499  $7,621,684 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)

  2008  2007 
OPERATING ACTIVITIES      
Net Income $120,610  $18,803 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization  186,528   142,100 
Deferred Income Taxes  111,297   32,021 
Extraordinary Loss, Net of Tax  -   78,763 
Carrying Costs Income  (38,921)  (22,817)
Allowance for Equity Funds Used During Construction  (6,278)  (5,442)
Mark-to-Market of Risk Management Contracts  7,450   (1,949)
Change in Other Noncurrent Assets  (24,670)  (9,185)
Change in Other Noncurrent Liabilities  (12,565)  27,247 
Changes in Certain Components of Working Capital:        
Accounts Receivable, Net  (12,313)  (87)
Fuel, Materials and Supplies  3,483   (11,387)
Accounts Payable  41,869   (38,724)
Accrued Taxes, Net  (51,208)  (9,990)
Accrued Interest  26,411   28,596 
Fuel Over/Under-Recovery, Net  (113,748)  35,770 
Other Current Assets  (17,202)  (21,483)
Other Current Liabilities  (12,298)  (20,702)
Net Cash Flows from Operating Activities  208,445   221,534 
         
INVESTING ACTIVITIES        
Construction Expenditures  (487,797)  (537,930)
Change in Other Cash Deposits, Net  (18)  (29)
Change in Advances to Affiliates, Net  -   (38,573)
Proceeds from Sales of Assets  15,786   6,713 
Other  -   (200)
Net Cash Flows Used for Investing Activities  (472,029)  (570,019)
         
FINANCING ACTIVITIES        
Capital Contribution from Parent  175,000   - 
Issuance of Long-term Debt – Nonaffiliated  686,512   568,778 
Change in Advances from Affiliates, Net  (181,699)  (34,975)
Retirement of Long-term Debt – Nonaffiliated  (412,786)  (125,009)
Retirement of Cumulative Preferred Stock  -   (9)
Principal Payments for Capital Lease Obligations  (3,052)  (3,316)
Amortization of Funds from Amended Coal Contract  -   (32,433)
Dividends Paid on Common Stock  -   (25,000)
Dividends Paid on Cumulative Preferred Stock  (599)  (600)
Net Cash Flows from Financing Activities  263,376   347,436 
         
Net Decrease in Cash and Cash Equivalents  (208)  (1,049)
Cash and Cash Equivalents at Beginning of Period  2,195   2,318 
Cash and Cash Equivalents at End of Period $1,987  $1,269 
         
SUPPLEMENTARY INFORMATION        
Cash Paid for Interest, Net of Capitalized Amounts $110,349  $86,199 
Net Cash Paid (Received) for Income Taxes  (26,330)  6,688 
Noncash Acquisitions Under Capital Leases  1,246   2,738 
Construction Expenditures Included in Accounts Payable at September 30,  112,376   90,315 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

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

Footnote Reference
Significant Accounting MattersNote 1
New Accounting Pronouncements and Extraordinary ItemNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
Benefit PlansNote 6
Business SegmentsNote 7
Income TaxesNote 8
Financing ActivitiesNote 9






COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations

Third Quarter of 2008 Compared to Third Quarter of 2007

Reconciliation of Third Quarter of 2007 to Third Quarter of 2008
Net Income
(in millions)

Third Quarter of 2007    $85 
        
Changes in Gross Margin:       
Retail Margins  (4)    
Off-system Sales  5     
Transmission Revenues  1     
Total Change in Gross Margin      2 
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  (2)    
Depreciation and Amortization  (3)    
Taxes Other Than Income Taxes  (3)    
Interest Expense  (1)    
Other Income  2     
Total Change in Operating Expenses and Other      (7)
         
Income Tax Expense      2 
         
Third Quarter of 2008     $82 

Net Income decreased $3 million to $82 million in 2008.  The key drivers of the decrease were a $7 million increase in Operating Expenses and Other, partially offset by a $2 million increase in Gross Margin and a $2 million decrease in Income Tax Expense.

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 $4 million primarily due to:
·A $23 million decrease in residential and commercial revenue primarily due to a 12% decrease in cooling degree days and the outages caused by the remnants of Hurricane Ike.
·A $20 million decrease related to increased fuel, allowance and consumables expenses.  CSPCo and OPCo have applied for an active fuel clause in their Ohio ESP to be effective January 1, 2009.
·A $4 million increase in capacity settlement charges under the Interconnection Agreement due to a change in relative peak demands.
These decreases were partially offset by a $44 million increase related to a net increase in rates implemented.
·Margins from Off-system Sales increased $5 million primarily due to increased physical sales margins driven by higher prices, partially offset by lower trading margins.

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

·Other Operation and Maintenance expenses increased $2 million due to:
· A $9 million increase in recoverable PJM costs.
· A $4 million increase in recoverable customer account expenses related to the Universal Service Fund for customers who qualify for payment assistance.
· A $3 million increase in employee-related expenses.
These increases were partially offset by a $15 million decrease resulting from a settlement agreement in the third quarter 2007 related to alleged violations of the NSR provisions of the CAA.  The $15 million represents CSPCo’s allocation of the settlement.
·Depreciation and Amortization increased $3 million primarily due to a greater depreciation base related to environmental improvements placed in service.
·Taxes Other Than Income Taxes increased $3 million due to property tax adjustments.
·Income Tax Expense decreased $2 million primarily due to a decrease in pretax book income.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Reconciliation of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2008
Net Income
(in millions)

Nine Months Ended September 30, 2007    $212 
        
Changes in Gross Margin:       
Retail Margins  36     
Off-system Sales  24     
Transmission Revenues  3     
Total Change in Gross Margin      63 
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  (45)    
Depreciation and Amortization  1     
Taxes Other Than Income Taxes  (12)    
Interest Expense  (6)    
Other Income  5     
Total Change in Operating Expenses and Other      (57)
         
Income Tax Expense      (4)
         
Nine Months Ended September 30, 2008     $214 

Net Income increased $2 million to $214 million in 2008.  The key drivers of the increase were a $63 million increase in Gross Margin primarily offset by a $57 million increase in Operating Expenses and Other and a $4 million increase in Income Tax Expense.

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 $36 million primarily due to:
·A $106 million increase related to a net increase in rates implemented.
·A $35 million decrease in capacity settlement charges related to CSPCo’s Unit Power Agreement (UPA) for AEGCo’s Lawrenceburg Plant, which began in May 2007, and to the April 2007 acquisition of the Darby Plant.
·A $15 million increase in industrial revenue related to higher usage by Ormet.
These increases were partially offset by:
·A $59 million decrease related to increased fuel, allowance and consumables expenses.  CSPCo and OPCo have applied for an active fuel clause in their Ohio ESP to be effective January 1, 2009.
·A $35 million decrease in residential and commercial revenue primarily due to a 16% decrease in cooling and a 6% decrease in heating degree days.
·Margins from Off-system Sales increased $24 million primarily due to increased physical sales margins driven by higher prices, partially offset by lower trading margins.

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

·Other Operation and Maintenance expenses increased $45 million primarily due to:
·A $17 million increase in recoverable PJM expenses.
·A $13 million increase in expenses related to CSPCo’s UPA for AEGCo’s Lawrenceburg Plant which began in May 2007.
·A $10 million increase in steam plant maintenance expenses primarily related to work performed at the Conesville Plant.
·A $9 million increase in recoverable customer account expenses related to the Universal Service Fund for customers who qualify for payment assistance.
·A $4 million increase in boiler plant removal expenses primarily related to work performed at the Conesville Plant.
These increases were partially offset by a $15 million decrease resulting from a settlement agreement in the third quarter 2007 related to alleged violations of the NSR provisions of the CAA.  The $15 million represents CSPCo’s allocation of the settlement.
·Taxes Other Than Income Taxes increased $12 million due to property tax adjustments.
·Interest Expense increased $6 million due to increased long-term borrowings.
·Other Income increased $5 million primarily due to interest income on federal tax refunds.
·Income Tax Expense increased $4 million primarily due to an increase in pretax book income and state income taxes.
Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2007 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of adoption of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

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 and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

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 CSPCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  The estimated EaR on CSPCo’s debt portfolio was $1.3 million.
 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)

  Three Months Ended  Nine Months Ended 
  2008  2007  2008  2007 
REVENUES            
Electric Generation, Transmission and Distribution $633,325  $553,518  $1,638,705  $1,446,632 
Sales to AEP Affiliates  29,032   52,331   111,553   110,700 
Other  1,426   1,292   4,121   3,743 
TOTAL  663,783   607,141   1,754,379   1,561,075 
                 
EXPENSES                
Fuel and Other Consumables Used for Electric Generation  112,566   103,560   283,946   255,764 
Purchased Electricity for Resale  63,441   49,619   150,637   113,765 
Purchased Electricity from AEP Affiliates  139,017   107,386   343,699   278,715 
Other Operation  87,358   83,625   245,379   207,300 
Maintenance  23,039   24,250   80,705   73,537 
Depreciation and Amortization  50,373   47,589   146,668   147,332 
Taxes Other Than Income Taxes  44,533   41,382   130,078   117,760 
TOTAL  520,327   457,411   1,381,112   1,194,173 
                 
OPERATING INCOME  143,456   149,730   373,267   366,902 
                 
Other Income (Expense):                
Interest Income  1,515   166   5,457   782 
Carrying Costs Income  1,566   1,261   4,870   3,492 
Allowance for Equity Funds Used During Construction  745   738   2,165   2,130 
Interest Expense  (21,127)  (19,530)  (57,612)  (51,193)
                 
INCOME BEFORE INCOME TAX EXPENSE  126,155   132,365   328,147   322,113 
                 
Income Tax Expense  44,493   46,911   113,939   109,656 
                 
NET INCOME  81,662   85,454   214,208   212,457 
                 
Capital Stock Expense  39   39   118   118 
                 
EARNINGS APPLICABLE TO COMMON STOCK $81,623  $85,415  $214,090  $212,339 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)

  Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
DECEMBER 31, 2006 $41,026  $580,192  $456,787  $(21,988) $1,056,017 
                     
FIN 48 Adoption, Net of Tax          (3,022)      (3,022)
Common Stock Dividends          (90,000)      (90,000)
Capital Stock Expense and Other      118   (118)      - 
TOTAL                  962,995 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Loss, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $1,231              (2,285)  (2,285)
NET INCOME          212,457       212,457 
TOTAL COMPREHENSIVE INCOME                  210,172 
                     
SEPTEMBER 30, 2007 $41,026  $580,310  $576,104  $(24,273) $1,173,167 
                     
DECEMBER 31, 2007 $41,026  $580,349  $561,696  $(18,794) $1,164,277 
                     
EITF 06-10 Adoption, Net of Tax of $589          (1,095)      (1,095)
SFAS 157 Adoption, Net of Tax of $170          (316)      (316)
Common Stock Dividends          (87,500)      (87,500)
Capital Stock Expense      118   (118)      - 
TOTAL                  1,075,366 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $582              1,080   1,080 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $456              846   846 
NET INCOME          214,208       214,208 
TOTAL COMPREHENSIVE INCOME                  216,134 
                     
SEPTEMBER 30, 2008 $41,026  $580,467  $686,875  $(16,868) $1,291,500 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2008 and December 31, 2007
(in thousands)
(Unaudited)

  2008  2007 
CURRENT ASSETS      
Cash and Cash Equivalents $1,956  $1,389 
Other Cash Deposits  31,964   53,760 
Advances to Affiliates  21,833   - 
Accounts Receivable:        
Customers  65,581   57,268 
Affiliated Companies  27,933   32,852 
Accrued Unbilled Revenues  24,078   14,815 
Miscellaneous  11,256   9,905 
Allowance for Uncollectible Accounts  (2,814)  (2,563)
Total Accounts Receivable  126,034   112,277 
Fuel  30,081   35,849 
Materials and Supplies  34,979   36,626 
Emission Allowances  7,884   16,811 
Risk Management Assets  40,842   33,558 
Prepayments and Other  31,984   9,960 
TOTAL  327,557   300,230 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Production  2,317,357   2,072,564 
Transmission  568,380   510,107 
Distribution  1,600,323   1,552,999 
Other  211,475   198,476 
Construction Work in Progress  322,885   415,327 
Total  5,020,420   4,749,473 
Accumulated Depreciation and Amortization  1,758,415   1,697,793 
TOTAL - NET  3,262,005   3,051,680 
         
OTHER NONCURRENT ASSETS        
Regulatory Assets  204,203   235,883 
Long-term Risk Management Assets  30,268   41,852 
Deferred Charges and Other  125,071   181,563 
TOTAL  359,542   459,298 
         
TOTAL ASSETS $3,949,104  $3,811,208 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY
September 30, 2008 and December 31, 2007
(Unaudited)

  2008  2007 
CURRENT LIABILITIES (in thousands) 
Advances from Affiliates $-  $95,199 
Accounts Payable:        
General  145,733   113,290 
Affiliated Companies  53,532   65,292 
Long-term Debt Due Within One Year – Nonaffiliated  -   112,000 
Risk Management Liabilities  37,331   28,237 
Customer Deposits  29,995   43,095 
Accrued Taxes  153,391   179,831 
Other  84,432   96,892 
TOTAL  504,414   733,836 
         
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated  1,343,491   1,086,224 
Long-term Debt – Affiliated  100,000   100,000 
Long-term Risk Management Liabilities  18,061   27,419 
Deferred Income Taxes  447,465   437,306 
Regulatory Liabilities and Deferred Investment Tax Credits  155,332   165,635 
Deferred Credits and Other  88,841   96,511 
TOTAL  2,153,190   1,913,095 
         
TOTAL LIABILITIES  2,657,604   2,646,931 
         
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  580,467   580,349 
Retained Earnings  686,875   561,696 
Accumulated Other Comprehensive Income (Loss)  (16,868)  (18,794)
TOTAL  1,291,500   1,164,277 
         
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY $3,949,104  $3,811,208 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)


  2008  2007 
OPERATING ACTIVITIES      
Net Income $214,208  $212,457 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization  146,668   147,332 
Deferred Income Taxes  8,981   (13,959)
Carrying Costs Income  (4,870)  (3,492)
Allowance for Equity Funds Used During Construction  (2,165)  (2,130)
Mark-to-Market of Risk Management Contracts  5,326   1,321 
Deferred Property Taxes  65,763   57,890 
Change in Other Noncurrent Assets  (7,942)  (29,199)
Change in Other Noncurrent Liabilities  (4,081)  2,713 
Changes in Certain Components of Working Capital:        
Accounts Receivable, Net  (13,757)  (13,040)
Fuel, Materials and Supplies  7,415   (2,332)
Accounts Payable  (2,650)  (13,336)
Customer Deposits  (13,100)  10,212 
Accrued Taxes, Net  (26,358)  (44,295)
Other Current Assets  (13,178)  (1,490)
Other Current Liabilities  (14,018)  8,817 
Net Cash Flows from Operating Activities  346,242   317,469 
         
INVESTING ACTIVITIES        
Construction Expenditures  (304,175)  (246,130)
Change in Other Cash Deposits, Net  21,796   (44,360)
Change in Advances to Affiliates, Net  (21,833)  - 
Acquisition of Darby Plant  -   (102,032)
Proceeds from Sales of Assets  1,287   1,016 
Net Cash Flows Used for Investing Activities  (302,925)  (391,506)
         
FINANCING ACTIVITIES        
Issuance of Long-term Debt – Nonaffiliated  346,407   44,257 
Change in Advances from Affiliates, Net  (95,199)  122,347 
Retirement of Long-term Debt – Nonaffiliated  (204,245)  - 
Principal Payments for Capital Lease Obligations  (2,213)  (2,191)
Dividends Paid on Common Stock  (87,500)  (90,000)
Net Cash Flows from (Used for) Financing Activities  (42,750)  74,413 
         
Net Increase in Cash and Cash Equivalents  567   376 
Cash and Cash Equivalents at Beginning of Period  1,389   1,319 
Cash and Cash Equivalents at End of Period $1,956  $1,695 
         
SUPPLEMENTARY INFORMATION        
Cash Paid for Interest, Net of Capitalized Amounts $57,004  $53,464 
Net Cash Paid for Income Taxes  53,682   93,709 
Noncash Acquisitions Under Capital Leases  1,374   1,900 
Construction Expenditures Included in Accounts Payable at September 30,  51,997   34,630 
Noncash Assumption of Liabilities Related to Acquisition of Darby Plant  -   2,339 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

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

Footnote
Reference
Significant Accounting MattersNote 1
New Accounting Pronouncements and Extraordinary ItemNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
AcquisitionNote 5
Benefit PlansNote 6
Business SegmentsNote 7
Income TaxesNote 8
Financing ActivitiesNote 9






INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations

Third Quarter of 2008 Compared to Third Quarter of 2007

Reconciliation of Third Quarter of 2007 to Third Quarter of 2008
Net Income
(in millions)

Third Quarter of 2007    $49 
        
Changes in Gross Margin:       
Retail Margins  (16)    
FERC Municipals and Cooperatives  (2)    
Off-system Sales  4     
Other  10     
Total Change in Gross Margin      (4)
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  (2)    
Depreciation and Amortization  4     
Other Income  (1)    
Interest Expense  (2)    
Total Change in Operating Expenses and Other      (1)
         
Income Tax Expense      2 
         
Third Quarter of 2008     $46 

Net Income decreased $3 million to $46 million in 2008.  The key drivers of the decrease were a $4 million decrease in Gross Margin and a $1 million increase in Operating Expenses and Other, partially offset by a $2 million decrease in Income Tax Expense.

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 $16 million primarily due to lower retail sales reflecting weather conditions as cooling degree days decreased at least 12% in both the Indiana and Michigan jurisdictions.
·Margins from Off-system Sales increased $4 million primarily due to increased physical sales margins driven by higher prices, partially offset by lower trading margins.
·Other revenues increased $10 million primarily due to increased River Transportation Division (RTD) revenues for barging services.  RTD’s related expenses which offset the RTD revenue increase are included in Other Operation on the Condensed Consolidated Statements of Income resulting in earning only a return approved under a regulatory order.

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

·Other Operation and Maintenance expenses increased $2 million primarily due to higher operation and maintenance expenses for RTD of $11 million caused by increased barging activity and increased cost of fuel in 2008, partially offset by a $9 million decrease in coal-fired plant operation expenses.  A settlement agreement related to alleged violations of the NSR provisions of the CAA, of which $14 million was allocated to I&M, increased 2007 Other Operation and Maintenance expenses.
·Depreciation and Amortization expense decreased $4 million primarily due to reduced depreciation rates reflecting longer estimated lives for Cook and Tanners Creek Plants.  Depreciation rates were reduced for the FERC and Michigan jurisdictions in October 2007.  See “Michigan Depreciation Study Filing” section of Note 4 in the 2007 Annual Report.
·Income Tax Expense decreased $2 million primarily due to a decrease in pretax book income.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Reconciliation of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2008
Net Income
(in millions)

Nine Months Ended September 30, 2007     $109 
         
Changes in Gross Margin:        
Retail Margins  (19)     
FERC Municipals and Cooperatives  4     
Off-system Sales  18     
Transmission Revenues  (2)     
Other  31     
Total Change in Gross Margin      32 
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  (24)     
Depreciation and Amortization  50     
Taxes Other Than Income Taxes  (3)     
Total Change in Operating Expenses and Other      23 
         
Income Tax Expense      (13) 
         
Nine Months Ended September 30, 2008     $151 

Net Income increased $42 million to $151 million in 2008.  The key drivers of the increase were a $32 million increase in Gross Margin and a $23 million decrease in Operating Expenses and Other, partially offset by a $13 million increase in Income Tax Expense.

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 $19 million primarily due to lower retail sales reflecting weather conditions as cooling degree days decreased at least 19% in both the Indiana and Michigan jurisdictions.
·Margins from Off-system Sales increased $18 million primarily due to increased physical sales margins driven by higher prices, partially offset by lower trading margins.
·Other revenues increased $31 million primarily due to increased RTD revenues for barging services.  RTD’s related expenses which offset the RTD revenue increase are included in Other Operation on the Condensed Consolidated Statements of Income resulting in earning only a return approved under regulatory order.

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

·Other Operation and Maintenance expenses increased $24 million primarily due to higher operation and maintenance expenses for RTD of $31 million caused by increased barging activity and increased cost of fuel and an increase in nuclear operation and maintenance expenses of $16 million.  Lower coal-fired plant operation and maintenance expenses of $18 million, including the NSR settlement, and a $5 million decrease in accretion expense partially offset the increases.
·Depreciation and Amortization expense decreased $50 million primarily due to the reduced depreciation rates in all jurisdictions.  Depreciation rates were reduced for the Indiana jurisdiction in June 2007 and the FERC and Michigan jurisdictions in October 2007.  See “Indiana Depreciation Study Filing” and “Michigan Depreciation Study Filing” sections of Note 4 in the 2007 Annual Report.
·Income Tax Expense increased $13 million primarily due to an increase in pretax book income and a decrease in amortization of investment tax credits, partially offset by changes in certain book/tax differences accounted for on a flow-through basis.

Cook Plant Unit 1 Fire and Shutdown

Cook Plant Unit 1 (Unit 1) is a 1,030 MW nuclear generating unit located in Bridgman, Michigan. In September 2008, I&M shut down Unit 1 due to turbine vibrations likely caused by blade failure which resulted in a fire on the electric generator.  This equipment is in the turbine building and is separate and isolated from the nuclear reactor.  The steam turbines that caused the vibration were installed in 2006 and are under warranty from the vendor.  The warranty provides for the replacement of the turbines if the damage was caused by a defect in the design or assembly of the turbines.  I&M is also working with its insurance company, Nuclear Electric Insurance Limited (NEIL), and turbine vendor to evaluate the extent of the damage resulting from the incident and the costs to return the unit to service.  Management cannot estimate the ultimate costs of the outage at this time.  Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process.  Management's preliminary analysis indicates that Unit 1 could resume operations as early as late first quarter/early second quarter of 2009 or as late as the second half of 2009, depending upon whether the damaged components can be repaired or whether they need to be replaced.
I&M maintains property insurance through NEIL with a $1 million deductible.  I&M also maintains a separate accidental outage policy with NEIL whereby, after a 12 week deductible period, I&M is entitled to weekly payments of $3.5 million during the outage period for a covered loss.  If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if the unit is not returned to service in a reasonable period of time, it could have an adverse impact on net income, cash flows and financial condition.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2007 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of adoption of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

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 and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

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 I&M’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  The estimated EaR on I&M’s debt portfolio was $5.7 million.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)

  Three Months Ended  Nine Months Ended 
  2008  2007  2008  2007 
REVENUES            
Electric Generation, Transmission and Distribution $513,548  $478,907  $1,370,158  $1,286,223 
Sales to AEP Affiliates  72,295   56,262   232,734   186,653 
Other – Affiliated  31,792   16,250   84,268   43,488 
Other – Nonaffiliated  3,388   7,757   13,659   21,718 
TOTAL  621,023   559,176   1,700,819   1,538,082 
                 
EXPENSES                
Fuel and Other Consumables Used for Electric Generation  141,563   103,740   351,300   290,507 
Purchased Electricity for Resale  39,427   26,580   87,351   63,830 
Purchased Electricity from AEP Affiliates  112,060   96,451   296,559   249,755 
Other Operation  136,875   129,439   381,928   367,483 
Maintenance  52,573   58,502   156,402   146,657 
Depreciation and Amortization  31,822   35,604   95,301   145,801 
Taxes Other Than Income Taxes  19,992   19,704   60,236   56,936 
TOTAL  534,312   470,020   1,429,077   1,320,969 
                 
OPERATING INCOME  86,711   89,156   271,742   217,113 
                 
Other Income (Expense):                
Other Income  880   1,986   4,621   4,273 
Interest Expense  (20,629)  (18,312)  (56,977)  (57,744)
                 
INCOME BEFORE INCOME TAX EXPENSE  66,962   72,830   219,386   163,642 
                 
Income Tax Expense  21,326   23,706   68,348   55,020 
                 
NET INCOME  45,636   49,124   151,038   108,622 
                 
Preferred Stock Dividend Requirements  85   85   255   255 
                 
EARNINGS APPLICABLE TO COMMON STOCK $45,551  $49,039  $150,783  $108,367 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)

  Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
DECEMBER 31, 2006 $56,584  $861,290  $386,616  $(15,051) $1,289,439 
                     
FIN 48 Adoption, Net of Tax          327       327 
Common Stock Dividends          (30,000)      (30,000)
Preferred Stock Dividends          (255)      (255)
Gain on Reacquired Preferred Stock      1           1 
TOTAL                  1,259,512 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Loss, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $941              (1,747)  (1,747)
NET INCOME          108,622       108,622 
TOTAL COMPREHENSIVE INCOME                  106,875 
                     
SEPTEMBER 30, 2007 $56,584  $861,291  $465,310  $(16,798) $1,366,387 
                     
DECEMBER 31, 2007 $56,584  $861,291  $483,499  $(15,675) $1,385,699 
                     
EITF 06-10 Adoption, Net of Tax of $753          (1,398)      (1,398)
Common Stock Dividends          (56,250)      (56,250)
Preferred Stock Dividends          (255)      (255)
TOTAL                  1,327,796 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $967              1,795   1,795 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $178              331   331 
NET INCOME          151,038       151,038 
TOTAL COMPREHENSIVE INCOME                  153,164 
                     
SEPTEMBER 30, 2008 $56,584  $861,291  $576,634  $(13,549) $1,480,960 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2008 and December 31, 2007
(in thousands)
(Unaudited)

  2008  2007 
CURRENT ASSETS      
Cash and Cash Equivalents $1,328  $1,139 
Accounts Receivable:        
Customers  82,788   70,995 
Affiliated Companies  77,640   92,018 
Accrued Unbilled Revenues  21,028   16,207 
Miscellaneous  2,010   1,335 
Allowance for Uncollectible Accounts  (3,200)  (2,711)
Total Accounts Receivable  180,266   177,844 
Fuel  46,745   61,342 
Materials and Supplies  143,245   141,384 
Risk Management Assets  40,215   32,365 
Accrued Tax Benefits  1,004   4,438 
Prepayments and Other  35,829   11,091 
TOTAL  448,632   429,603 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
Production  3,512,424   3,529,524 
Transmission  1,100,255   1,078,575 
Distribution  1,262,017   1,196,397 
Other (including nuclear fuel and coal mining)  655,257   626,390 
Construction Work in Progress  173,062   122,296 
Total  6,703,015   6,553,182 
Accumulated Depreciation, Depletion and Amortization  3,000,898   2,998,416 
TOTAL - NET  3,702,117   3,554,766 
         
OTHER NONCURRENT ASSETS        
Regulatory Assets  251,451   246,435 
Spent Nuclear Fuel and Decommissioning Trusts  1,291,986   1,346,798 
Long-term Risk Management Assets  29,518   40,227 
Deferred Charges and Other  118,574   128,623 
TOTAL  1,691,529   1,762,083 
         
TOTAL ASSETS $5,842,278  $5,746,452 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2008 and December 31, 2007
(Unaudited)

  2008  2007 
CURRENT LIABILITIES (in thousands) 
Advances from Affiliates $224,071  $45,064 
Accounts Payable:        
General  177,480   184,435 
Affiliated Companies  64,970   61,749 
Long-term Debt Due Within One Year – Nonaffiliated  50,000   145,000 
Risk Management Liabilities  36,802   27,271 
Customer Deposits  26,957   26,445 
Accrued Taxes  60,111   60,995 
Obligations Under Capital Leases  43,626   43,382 
Other  133,267   130,232 
TOTAL  817,284   724,573 
         
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated  1,377,115   1,422,427 
Long-term Risk Management Liabilities  17,585   26,348 
Deferred Income Taxes  382,374   321,716 
Regulatory Liabilities and Deferred Investment Tax Credits  693,981   789,346 
Asset Retirement Obligations  886,278   852,646 
Deferred Credits and Other  178,621   215,617 
TOTAL  3,535,954   3,628,100 
         
TOTAL LIABILITIES  4,353,238   4,352,673 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  8,080   8,080 
         
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  861,291   861,291 
Retained Earnings  576,634   483,499 
Accumulated Other Comprehensive Income (Loss)  (13,549)  (15,675)
TOTAL  1,480,960   1,385,699 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $5,842,278  $5,746,452 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)

  2008  2007 
OPERATING ACTIVITIES      
Net Income $151,038  $108,622 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization  95,301   145,801 
Deferred Income Taxes  47,565   (9,235)
Amortization of Incremental Nuclear Refueling Outage Expenses, Net  834   14,450 
Allowance for Equity Funds Used During Construction  (967)  (2,726)
Mark-to-Market of Risk Management Contracts  4,876   3,046 
Amortization of Nuclear Fuel  72,453   48,360 
Change in Other Noncurrent Assets  5,678   17,163 
Change in Other Noncurrent Liabilities  38,568   33,995 
Changes in Certain Components of Working Capital:        
Accounts Receivable, Net  (2,422)  34,569 
Fuel, Materials and Supplies  12,736   14,584 
Accounts Payable  16,549   (27,015)
Accrued Taxes, Net  2,550   41,243 
Other Current Assets  (24,736)  (4,595)
Other Current Liabilities  1,393   3,150 
Net Cash Flows from Operating Activities  421,416   421,412 
         
INVESTING ACTIVITIES        
Construction Expenditures  (221,538)  (191,110)
Purchases of Investment Securities  (413,538)  (561,509)
Sales of Investment Securities  362,773   505,620 
Acquisitions of Nuclear Fuel  (99,110)  (73,112)
Proceeds from Sales of Assets and Other  3,376   670 
Net Cash Flows Used for Investing Activities  (368,037)  (319,441)
         
FINANCING ACTIVITIES        
Issuance of Long-term Debt – Nonaffiliated  115,225   - 
Change in Advances from Affiliates, Net  179,007   (66,939)
Retirement of Long-term Debt – Nonaffiliated  (262,000)  - 
Retirement of Cumulative Preferred Stock  -   (2)
Principal Payments for Capital Lease Obligations  (28,917)  (3,954)
Dividends Paid on Common Stock  (56,250)  (30,000)
Dividends Paid on Cumulative Preferred Stock  (255)  (255)
Net Cash Flows Used for Financing Activities  (53,190)  (101,150)
         
Net Increase in Cash and Cash Equivalents  189   821 
Cash and Cash Equivalents at Beginning of Period  1,139   1,369 
Cash and Cash Equivalents at End of Period $1,328  $2,190 
         
SUPPLEMENTARY INFORMATION        
Cash Paid for Interest, Net of Capitalized Amounts $57,086  $49,628 
Net Cash Paid for Income Taxes  7,482   14,395 
Noncash Acquisitions Under Capital Leases  3,279   5,847 
Construction Expenditures Included in Accounts Payable at September 30,  26,150   23,935 
Acquisition of Nuclear Fuel Included in Accounts Payable at September 30,  66,127   691 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

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

Footnote
Reference
Significant Accounting MattersNote 1
New Accounting Pronouncements and Extraordinary ItemNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
Benefit PlansNote 6
Business SegmentsNote 7
Income TaxesNote 8
Financing ActivitiesNote 9




OHIO POWER COMPANY CONSOLIDATED


OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Third Quarter of 2008 Compared to Third Quarter of 2007

Reconciliation of Third Quarter of 2007 to Third Quarter of 2008
Net Income
(in millions)

Third Quarter of 2007    $75 
        
Changes in Gross Margin:       
Retail Margins  (48)    
Off-system Sales  11     
Other  3     
Total Change in Gross Margin      (34)
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  (2)    
Depreciation and Amortization  12     
Taxes Other Than Income Taxes  (1)    
Other Income  2     
Interest Expense  (4)    
Total Change in Operating Expenses and Other      7 
         
Income Tax Expense      8 
         
Third Quarter of 2008     $56 

Net Income decreased $19 million to $56 million in 2008.  The key drivers of the decrease were a $34 million decrease in Gross Margin, partially offset by an $8 million decrease in Income Tax Expense and a $7 million decrease in Operating Expenses and Other.

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 $48 million primarily due to the following:
·A $57 million decrease related to increased fuel and consumables expenses.  CSPCo and OPCo have applied for an active fuel clause in their Ohio ESP to be effective January 1, 2009.
·An $8 million decrease in residential revenue primarily due to an 18% decrease in cooling degree days and the outages caused by the remnants of Hurricane Ike.
These decreases were partially offset by:
·A $17 million increase related to a net increase in rates implemented.
·A $10 million increase in capacity settlements under the Interconnection Agreement related to an increase in an affiliate’s peak.
·Margins from Off-system Sales increased $11 million primarily due to increased physical sales margins driven by higher prices, partially offset by lower trading margins.
·Other revenues increased $3 million primarily due to increased gains on sales of emission allowances.

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

·Other Operation and Maintenance expenses increased $2 million primarily due to:
·A $6 million increase in recoverable PJM expenses.
·A $4 million increase in employee-related expenses.
·A $4 million increase in recoverable customer account expenses related to the Universal Service Fund for customers who qualify for payment assistance.
·A $3 million increase in operation and maintenance expenses related to service restoration expenses from the remnants of Hurricane Ike.
·A $2 million increase in plant maintenance expenses.
These increases were partially offset by a $17 million decrease resulting from a settlement agreement in the third quarter 2007 related to alleged violations of the NSR provisions of the CAA.  The $17 million represents OPCo’s allocation of the settlement.
·Depreciation and Amortization expense decreased $12 million primarily due to an $18 million decrease in amortization as a result of completion of amortization of regulatory assets in December 2007, partially offset by a $5 million increase in depreciation related to environmental improvements placed in service at the Cardinal Plant in 2008 and the Mitchell Plant in July 2007.
·Interest Expense increased $4 million primarily due to a decrease in the debt component of AFUDC as a result of Mitchell Plant and Cardinal Plant environmental improvements placed in service and higher interest rates on variable rate debt.
·Income Tax Expense decreased $8 million primarily due to a decrease in pretax book income.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Reconciliation of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2008
Net Income
(in millions)

Nine Months Ended September 30, 2007    $229 
        
Changes in Gross Margin:       
Retail Margins  (55)    
Off-system Sales  34     
Other  12     
Total Change in Gross Margin      (9)
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  8     
Depreciation and Amortization  42     
Carrying Costs Income  1     
Other Income  6     
Interest Expense  (20)    
Total Change in Operating Expenses and Other      37 
         
Income Tax Expense      (10)
         
Nine Months Ended September 30, 2008     $247 

Net Income increased $18 million to $247 million in 2008.  The key drivers of the increase were a $37 million decrease in Operating Expenses and Other, partially offset by a $10 million increase in Income Tax Expense and a $9 million decrease in Gross Margin.

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 $55 million primarily due to the following:
·A $105 million decrease related to increased fuel and consumables expenses.  CSPCo and OPCo have applied for an active fuel clause in their Ohio ESP to be effective January 1, 2009.
·A $9 million decrease in residential revenues primarily due to a 21% decrease in cooling degree days.
These decreases were partially offset by:
·A $42 million increase related to a net increase in rates implemented.
·A $29 million increase related to coal contract amendments in 2008.
·A $17 million increase in capacity settlements under the Interconnection Agreement related to an increase in an affiliate’s peak.
·Margins from Off-system Sales increased $34 million primarily due to increased physical sales margins driven by higher prices and higher trading margins.
·Other revenues increased $12 million primarily due to increased gains on sales of emission allowances.

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

·Other Operation and Maintenance expenses decreased $8 million primarily due to:
·A $20 million decrease in removal expenses related to planned outages at the Gavin and Mitchell Plants during 2007.
·A $17 million decrease resulting from a settlement agreement in the third quarter 2007 related to alleged violations of the NSR provisions of the CAA.  The $17 million represents OPCo’s allocation of the settlement.
·A $7 million decrease in overhead line maintenance expenses.
These decreases were partially offset by:
·A $13 million increase in recoverable PJM expenses.
·An $11 million increase in recoverable customer account expenses related to the Universal Service Fund for customers who qualify for payment assistance.
·A $7 million increase in maintenance expenses from planned and forced outages at various plants.
·A $4 million increase in employee-related expenses.
·Depreciation and Amortization decreased $42 million primarily due to:
·A $53 million decrease in amortization as a result of completion of amortization of regulatory assets in December 2007.
·A $6 million decrease due to the amortization of IGCC pre-construction costs, which ended in the second quarter of 2007.  The amortization of IGCC pre-construction costs was offset by a corresponding increase in Retail Margins in 2007.
These decreases were partially offset by a $19 million increase in depreciation related to environmental improvements placed in service at the Cardinal Plant in 2008 and the Mitchell Plant in 2007.
·Interest Expense increased $20 million primarily due to a decrease in the debt component of AFUDC as a result of Mitchell Plant and Cardinal Plant environmental improvements placed in service, the issuance of additional long-term debt and higher interest rates on variable rate debt.
·Income Tax Expense increased $10 million primarily due to an increase in pretax book income.

Financial Condition

Credit Ratings

S&P and Fitch currently have OPCo on stable outlook, while Moody’s placed OPCo on negative outlook in the first quarter of 2008.  Current ratings are as follows:
Moody’sS&PFitch
Senior Unsecured DebtA3BBBBBB+

If OPCo receives an upgrade from any of the rating agencies listed above, its borrowing costs could decrease.  If OPCo receives a downgrade from any of the rating agencies listed above, its borrowing costs could increase and access to borrowed funds could be negatively affected.

Cash Flow

Cash flows for the nine months ended September 30, 2008 and 2007 were as follows:

  2008  2007 
  (in thousands) 
Cash and Cash Equivalents at Beginning of Period $6,666  $1,625 
Cash Flows from (Used for):        
Operating Activities  434,295   402,980 
Investing Activities  (486,678)  (743,260)
Financing Activities  54,805   351,381 
Net Increase in Cash and Cash Equivalents  2,422   11,101 
Cash and Cash Equivalents at End of Period $9,088  $12,726 

Operating Activities

Net Cash Flows from Operating Activities were $434 million in 2008.  OPCo produced Net Income of $247 million during the period and a noncash expense item of $212 million for Depreciation and Amortization.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital and changes in the future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  Accounts Payable had a $45 million inflow primarily due to increases in tonnage and prices per ton related to fuel and consumable purchases.  Fuel, Materials and Supplies had a $48 million outflow due to price increases.

Net Cash Flows from Operating Activities were $403 million in 2007.  OPCo produced Net Income of $229 million during the period and a noncash expense item of $253 million for Depreciation and Amortization.  The other changes in assets and liabilities represent items that had a prior 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 prior period activity in working capital included two significant items.  Accounts Payable had a $60 million cash outflow partially due to emission allowance payments in January 2007, reduced accruals for Mitchell Plant environmental projects that went into service in 2007 and timing differences for payments to affiliates.  Accounts Receivable, Net had a $33 million cash outflow partially due to the timing of collections of receivables.

Investing Activities

Net Cash Used for Investing Activities were $487 million and $743 million in 2008 and 2007, respectively.  Construction Expenditures were $453 million and $751 million in 2008 and 2007, respectively, primarily related to environmental upgrades, as well as projects to improve service reliability for transmission and distribution.  Environmental upgrades include the installation of selective catalytic reduction equipment and flue gas desulfurization projects at the Cardinal, Amos and Mitchell Plants.  In 2007, environmental upgrades were completed for Units 1 and 2 at the Mitchell Plant.  For the remainder of 2008, OPCo expects construction expenditures to be approximately $230 million.

Financing Activities

Net Cash Flows from Financing Activities were $55 million in 2008.  OPCo issued $165 million of Pollution Control Bonds and $250 million of Senior Unsecured Notes.  These increases were partially offset by the retirement of $250 million of Pollution Control Bonds and $13 million of Notes Payable – Nonaffiliated.  OPCo also had a net decrease in borrowings of $102 million from the Utility Money Pool.

Net Cash Flows from Financing Activities were $351 million in 2007.  OPCo issued $400 million of Senior Unsecured Notes and $65 million of Pollution Control Bonds.  OPCo reduced borrowings by $96 million from the Utility Money Pool.

Financing Activity

Long-term debt issuances, retirements and principal payments made during the first nine months of 2008 were:

Issuances
  Principal Interest Due
Type of Debt Amount Rate Date
  (in thousands) (%)  
Pollution Control Bonds $50,000  Variable 2014
Pollution Control Bonds  50,000  Variable 2014
Pollution Control Bonds  65,000  Variable 2036
Senior Unsecured Notes  250,000  5.75 2013

Retirements and Principal Payments

  Principal Interest Due
Type of Debt Amount Paid Rate Date
  (in thousands) (%)  
Notes Payable – Nonaffiliated $1,463  6.81 2008
Notes Payable – Nonaffiliated  12,000  6.27 2009
Pollution Control Bonds  50,000  Variable 2014
Pollution Control Bonds  50,000  Variable 2016
Pollution Control Bonds  50,000  Variable 2022
Pollution Control Bonds  35,000  Variable 2022
Pollution Control Bonds  65,000  Variable 2036

Liquidity

In recent months, the financial markets have become increasingly unstable and constrained at both a global and domestic level.  This systemic marketplace distress is impacting OPCo’s access to capital, liquidity and cost of capital.  The uncertainties in the credit markets could have significant implications on OPCo since it relies on continuing access to capital to fund operations and capital expenditures.

OPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  OPCo has $37 million of Senior Unsecured Notes that will mature in 2008 and $82 million of Notes Payable that will mature in 2009.  To the extent refinancing is unavailable due to challenging credit markets, OPCo will rely upon cash flows from operations and access to the Utility Money Pool to fund its maturities, current operations and capital expenditures.

Summary Obligation Information

A summary of contractual obligations is included in the 2007 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” and “Financing Activity” above and letters of credit.  In April 2008, the Registrant Subsidiaries and certain other companies in the AEP System entered into a $650 million 3-year credit agreement and a $350 million 364-day credit agreement which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23 million and $12 million, respectively, following its bankruptcy.  As of September 30, 2008, $167 million of letters of credit were issued by OPCo under the 3-year credit agreement to support variable rate demand notes.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, OPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be.  Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases which have a probable likelihood of loss and the loss amount 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 2007 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section..  Adverse results in these proceedings have the potential to materially affect results of operations,net income, financial condition and cash flows.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of relevant factors.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2007 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.

 
 
 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Risk management assets and liabilities are managed by AEPSC as agent.  The related risk management policies and procedures are instituted and administered by AEPSC.  See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section.  The following tables provide information about AEP’s risk management activities’ effect on OPCo.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in OPCo’s Condensed Consolidated Balance sheet as of JuneSeptember 30, 2008 and the reasons for changes in total MTM value as compared to December 31, 2007.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of JuneSeptember 30, 2008
(in thousands)

 MTM Risk Management Contracts  
Cash Flow
 &
Fair Value Hedges
  DETM Assignment (a)  
 
Collateral
Deposits
  Total  MTM Risk Management Contracts  
Cash Flow &
Fair Value Hedges
  DETM Assignment (a)  
 
Collateral
Deposits
  Total 
Current Assets $183,037  $1,530  $-  $(10,714) $173,853  $77,357  $2,245  $-  $(2,466) $77,136 
Noncurrent Assets  93,550   254   -   (5,974)  87,830   48,369   720   -   (3,281)  45,808 
Total MTM Derivative Contract Assets  276,587   1,784   -   (16,688)  261,683   125,726   2,965   -   (5,747)  122,944 
                                        
Current Liabilities  (189,390)  (22,777)  (2,376)  17,082   (197,461)  (67,432)  (3,170)  (2,174)  620   (72,156)
Noncurrent Liabilities  (66,264)  (901)  (2,603)  4,305   (65,463)  (24,105)  -   (2,222)  36   (26,291)
Total MTM Derivative Contract Liabilities  (255,654)  (23,678)  (4,979)  21,387   (262,924)  (91,537)  (3,170)  (4,396)  656   (98,447)
                                        
Total MTM Derivative Contract Net Assets (Liabilities) $20,933  $(21,894) $(4,979) $4,699  $(1,241) $34,189  $(205) $(4,396) $(5,091) $24,497 

(a)See “Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual Report.

MTM Risk Management Contract Net Assets
SixNine Months Ended JuneSeptember 30, 2008
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2007 $30,248  $30,248 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period (5,931)  (8,565)
Fair Value of New Contracts at Inception When Entered During the Period (a) 866   1,154 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period (64)  (64)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b) 2,158   1,026 
Changes in Fair Value Due to Market Fluctuations During the Period (c) 4,368   13,061 
Changes in Fair Value Allocated to Regulated Jurisdictions (d)  (10,712)  (2,671)
Total MTM Risk Management Contract Net Assets 20,933   34,189 
Net Cash Flow & Fair Value Hedge Contracts (21,894)  (205)
DETM Assignment (e) (4,979)  (4,396)
Collateral Deposits  4,699   (5,091)
Ending Net Risk Management Assets at June 30, 2008 $(1,241)
Ending Net Risk Management Assets at September 30, 2008 $24,497 

(a)Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term.  The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)Represents the impact of applying AEP’s credit risk when measuring the fair value of derivative liabilities according to SFAS 157.
(c)Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(d)“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income.  These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.liabilities.
(e)See “Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual Report.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The following table presents the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash:

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of JuneSeptember 30, 2008
(in thousands)

 Remainder              After    
 
Remainder
2008
  2009  2010  2011  2012  
After
2012
  Total  2008  2009  2010  2011  2012  2012  Total 
Level 1 (a) $(1,938) $330  $(14) $-  $-  $-  $(1,622) $(695) $(1,596) $(15) $-  $-  $-  $(2,306)
Level 2 (b)  (1,281)  13,609   8,184   3,604   1,247   -   25,363   310   16,487   12,052   724   338   -   29,911 
Level 3 (c)  (6,774)  (1,096)  (2,719)  (1,752)  (904)  -   (13,245)  (2,788)  462   (1,303)  189   107   -   (3,333)
Total  (9,993)  12,843   5,451   1,852   343   -   10,496   (3,173)  15,353   10,734   913   445   -   24,272 
Dedesignated Risk Management Contracts (d)  1,666   3,220   3,194   1,244   1,113   -   10,437   976   3,282   3,256   1,268   1,135   -   9,917 
Total MTM Risk Management Contract Net Assets (Liabilities) $(8,327) $16,063  $8,645  $3,096  $1,456  $-  $20,933  $(2,197) $18,635  $13,990  $2,181  $1,580  $-  $34,189 


(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 SFAS 133.  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 contract.


Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed Consolidated Balance Sheet

OPCo is exposed to market fluctuations in energy commodity prices impacting power operations.  Management monitors these risks on future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows.  Management does not hedge all commodity price risk.

Management uses interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt.  Management does not hedge all interest rate risk.

Management uses foreign currency derivatives to lock in prices on certain forecasted transactions denominated in foreign currencies where deemed necessary, and designates qualifying instruments as cash flow hedges.  Management does not hedge all foreign currency exposure.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on OPCo’s Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2007 to JuneSeptember 30, 2008.  Only contracts designated as cash flow hedges are recorded in AOCI.  Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables.  All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
SixNine Months Ended JuneSeptember 30, 2008
(in thousands)
       Foreign    
 Power  Interest Rate  
Foreign
Currency
  Total  Power  Interest Rate  Currency  Total 
Beginning Balance in AOCI December 31, 2007 $(756) $2,167  $(254) $1,157  $(756) $2,167  $(254) $1,157 
Changes in Fair Value  (11,404)  (899)  205   (12,098)  431   (903)  68   (404)
Reclassifications from AOCI for Cash Flow Hedges Settled  101   (382)  (123)  (404)  859   160   10   1,029 
Ending Balance in AOCI June 30, 2008 $(12,059) $886  $(172) $(11,345)
Ending Balance in AOCI September 30, 2008 $534  $1,424  $(176) $1,782 

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $12.6 million$328 thousand loss.

Credit Risk

Counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates Value at Risk (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 JuneSeptember 30, 2008, a near term typical change in commodity prices is not expected to have a material effect on OPCo’s results of operations,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 periods indicated:

Six Months Ended  Twelve Months Ended
June 30, 2008  December 31, 2007
(in thousands)  (in thousands)
End High Average Low  End High Average Low
$585 $1,048 $385 $132  $325 $2,054 $490 $90
Nine Months Ended    Twelve Months Ended
September 30, 2008    December 31, 2007
(in thousands)    (in thousands)
End High Average Low    End High Average Low
$901 $1,284 $447 $132    $325 $2,054 $490 $90

Management back-tests its VaR results against performance due to actual price moves.  Based on the assumed 95% confidence interval, performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days.  Management’s backtesting results show that its actual performance exceeded VaR far fewer than once every 20 trading days.  As a result, management believes OPCo’s VaR calculation is conservative.

As OPCo’s VaR calculation captures recent price moves, management also performs regular stress testing of the portfolio to understand its exposure to extreme price moves.  Management employs a historically-based method whereby the current portfolio is subjected to actual, observed price moves from the last three years in order to ascertain which historical price moves translate into the largest potential mark-to-market loss.  Management then researches the underlying positions, price moves and market events that created the most significant exposure.

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 OPCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  The estimated EaR on OPCo’s debt portfolio was $10.7$10.1 million.

 
 
 


OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in thousands)
(Unaudited)

 Three Months Ended  Six Months Ended  Three Months Ended  Nine Months Ended 
 2008  2007  2008  2007  2008  2007  2008  2007 
REVENUES                        
Electric Generation, Transmission and Distribution $515,884  $480,445  $1,071,362  $972,979  $600,841  $543,404  $1,672,203  $1,516,383 
Sales to AEP Affiliates  256,399   180,205   493,247   359,099   245,830   205,193   739,077   564,292 
Other - Affiliated  6,487   6,817   11,786   10,855   5,759   5,749   17,545   16,604 
Other - Nonaffiliated  3,591   3,466   8,154   7,441   4,584   3,397   12,738   10,838 
TOTAL  782,361   670,933   1,584,549   1,350,374   857,014   757,743   2,441,563   2,108,117 
                                
EXPENSES                                
Fuel and Other Consumables Used for Electric Generation  330,190   201,338   569,124   399,631   359,341   254,310   928,465   653,941 
Purchased Electricity for Resale  39,155   27,868   73,732   52,722   56,142   33,178   129,874   85,900 
Purchased Electricity from AEP Affiliates  35,157   28,745   67,673   49,711   48,867   43,147   116,540   92,858 
Other Operation  91,959   86,972   181,841   189,959   98,653   102,850   280,494   292,809 
Maintenance  59,218   50,617   107,915   109,765   51,791   45,663   159,706   155,428 
Depreciation and Amortization  71,173   84,779   139,739   169,055   72,180   84,400   211,919   253,455 
Taxes Other Than Income Taxes  45,937   50,320   97,515   98,705   49,019   47,506   146,534   146,211 
TOTAL  672,789   530,639   1,237,539   1,069,548   735,993   611,054   1,973,532   1,680,602 
                                
OPERATING INCOME  109,572   140,294   347,010   280,826   121,021   146,689   468,031   427,515 
                                
Other Income (Expense):                                
Interest Income  1,750   472   4,658   884   2,252   108   6,910   992 
Carrying Costs Income  3,994   3,594   8,223   7,135   3,936   3,644   12,159   10,779 
Allowance for Equity Funds Used During Construction  702   446   1,246   1,017   555   590   1,801   1,607 
Interest Expense  (41,853)  (33,734)  (76,235)  (59,665)  (39,964)  (36,262)  (116,199)  (95,927)
                                
INCOME BEFORE INCOME TAX EXPENSE  74,165   111,072   284,902   230,197   87,800   114,769   372,702   344,966 
                                
Income Tax Expense  21,271   36,732   94,181   76,596   31,601   39,507   125,782   116,103 
                                
NET INCOME  52,894   74,340   190,721   153,601   56,199   75,262   246,920   228,863 
                                
Preferred Stock Dividend Requirements  183   183   366   366   183   183   549   549 
                                
EARNINGS APPLICABLE TO COMMON STOCK $52,711  $74,157  $190,355  $153,235  $56,016  $75,079  $246,371  $228,314 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
 
 
 

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in thousands)
(Unaudited)

 Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total  Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
DECEMBER 31, 2006 $321,201  $536,639  $1,207,265  $(56,763) $2,008,342  $321,201  $536,639  $1,207,265  $(56,763) $2,008,342 
                                        
FIN 48 Adoption, Net of Tax          (5,380)      (5,380)          (5,380)      (5,380)
Preferred Stock Dividends          (366)      (366)          (549)      (549)
TOTAL                  2,002,596                   2,002,413 
                                        
COMPREHENSIVE INCOME                                        
Other Comprehensive Income, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $523              971   971 
Other Comprehensive Loss, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $1,878              (3,486)  (3,486)
NET INCOME          153,601       153,601           228,863       228,863 
TOTAL COMPREHENSIVE INCOME                  154,572                   225,377 
                                        
JUNE 30, 2007 $321,201  $536,639  $1,355,120  $(55,792) $2,157,168 
SEPTEMBER 30, 2007 $321,201  $536,639  $1,430,199  $(60,249) $2,227,790 
                                        
DECEMBER 31, 2007 $321,201  $536,640  $1,469,717  $(36,541) $2,291,017  $321,201  $536,640  $1,469,717  $(36,541) $2,291,017 
                                        
EITF 06-10 Adoption, Net of Tax of $1,004          (1,864)      (1,864)          (1,864)      (1,864)
SFAS 157 Adoption, Net of Tax of $152          (282)      (282)          (282)      (282)
Preferred Stock Dividends          (366)      (366)          (549)      (549)
TOTAL                  2,288,505                   2,288,322 
                                        
COMPREHENSIVE INCOME                                        
Other Comprehensive Income (Loss), Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $6,732              (12,502)  (12,502)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $758
              1,406   1,406 
Other Comprehensive Income, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $337              625   625 
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,136              2,110   2,110 
NET INCOME          190,721       190,721           246,920       246,920 
TOTAL COMPREHENSIVE INCOME                  179,625                   249,655 
                                        
JUNE 30, 2008 $321,201  $536,640  $1,657,926  $(47,637) $2,468,130 
SEPTEMBER 30, 2008 $321,201  $536,640  $1,713,942  $(33,806) $2,537,977 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

 
 
 

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
JuneSeptember 30, 2008 and December 31, 2007
(in thousands)
(Unaudited)

 2008  2007  2008  2007 
CURRENT ASSETS            
Cash and Cash Equivalents $10,098  $6,666  $9,088  $6,666 
Advances to Affiliates  39,758   - 
Accounts Receivable:                
Customers  117,920   104,783   93,951   104,783 
Affiliated Companies  125,613   119,560   105,503   119,560 
Accrued Unbilled Revenues  26,903   26,819   24,947   26,819 
Miscellaneous  20,689   1,578   11,551   1,578 
Allowance for Uncollectible Accounts  (3,502)  (3,396)   (3,555)  (3,396)
Total Accounts Receivable  287,623   249,344   232,397   249,344 
Fuel  125,844   92,874   146,332   92,874 
Materials and Supplies  116,097   108,447   104,924   108,447 
Risk Management Assets  173,853   44,236   77,136   44,236 
Prepayments and Other  33,256   18,300   38,372   18,300 
TOTAL  746,771   519,867   648,007   519,867 
                
PROPERTY, PLANT AND EQUIPMENT                
Electric:                
Production  5,906,996   5,641,537   5,937,723   5,641,537 
Transmission  1,092,630   1,068,387   1,101,463   1,068,387 
Distribution  1,424,744   1,394,988   1,442,047   1,394,988 
Other  371,427   318,805   379,242   318,805 
Construction Work in Progress  586,892   716,640   683,404   716,640 
Total  9,382,689   9,140,357   9,543,879   9,140,357 
Accumulated Depreciation and Amortization  3,032,379   2,967,285   3,084,683   2,967,285 
TOTAL - NET  6,350,310   6,173,072   6,459,196   6,173,072 
                
OTHER NONCURRENT ASSETS                
Regulatory Assets  327,764   323,105   324,260   323,105 
Long-term Risk Management Assets  87,830   49,586   45,808   49,586 
Deferred Charges and Other  230,925   272,799   207,562   272,799 
TOTAL  646,519   645,490   577,630   645,490 
                
TOTAL ASSETS $7,743,600  $7,338,429  $7,684,833  $7,338,429 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


 
 
 

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
JuneSeptember 30, 2008 and December 31, 2007
(Unaudited)

 2008  2007  2008  2007 
CURRENT LIABILITIES (in thousands)  (in thousands) 
Advances from Affiliates $173,833  $101,548  $-  $101,548 
Accounts Payable:                
General  209,084   141,196   187,803   141,196 
Affiliated Companies  104,468   137,389   132,195   137,389 
Short-term Debt – Nonaffiliated  -   701   -   701 
Long-term Debt Due Within One Year – Nonaffiliated  125,225   55,188   119,225   55,188 
Risk Management Liabilities  197,461   40,548   72,156   40,548 
Customer Deposits  32,031   30,613   24,002   30,613 
Accrued Taxes  180,760   185,011   130,211   185,011 
Accrued Interest  39,687   41,880   37,704   41,880 
Other  143,465   149,658   151,044   149,658 
TOTAL  1,206,014   883,732   854,340   883,732 
                
NONCURRENT LIABILITIES                
Long-term Debt – Nonaffiliated  2,432,266   2,594,410   2,682,247   2,594,410 
Long-term Debt – Affiliated  200,000   200,000   200,000   200,000 
Long-term Risk Management Liabilities  65,463   32,194   26,291   32,194 
Deferred Income Taxes  926,957   914,170   957,441   914,170 
Regulatory Liabilities and Deferred Investment Tax Credits  154,258   160,721   150,794   160,721 
Deferred Credits and Other  256,438   229,635   242,084   229,635 
TOTAL  4,035,382   4,131,130   4,258,857   4,131,130 
                
TOTAL LIABILITIES  5,241,396   5,014,862   5,113,197   5,014,862 
                
Minority Interest  17,447   15,923   17,032   15,923 
                
Cumulative Preferred Stock Not Subject to Mandatory Redemption  16,627   16,627   16,627   16,627 
                
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   321,201   321,201 
Paid-in Capital  536,640   536,640   536,640   536,640 
Retained Earnings  1,657,926   1,469,717   1,713,942   1,469,717 
Accumulated Other Comprehensive Income (Loss)  (47,637)  (36,541)   (33,806)  (36,541)
TOTAL  2,468,130   2,291,017   2,537,977   2,291,017 
                
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $7,743,600  $7,338,429  $7,684,833  $7,338,429 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

 
 
 

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in thousands)
(Unaudited)

 2008  2007  2008  2007 
OPERATING ACTIVITIES            
Net Income $190,721  $153,601  $246,920  $228,863 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:                
Depreciation and Amortization  139,739   169,055   211,919   253,455 
Deferred Income Taxes  27,984   550   45,424   3,938 
Carrying Costs Income  (8,223)  (7,135)   (12,159)  (10,779)
Allowance for Equity Funds Used During Construction  (1,246)  (1,017)   (1,801)  (1,607)
Mark-to-Market of Risk Management Contracts  2,018   2,876   (2,028)  (3,894)
Deferred Property Taxes  42,089   34,629   63,867   54,036 
Change in Other Noncurrent Assets  (59,294)  (17,321)   (52,788)  (20,275)
Change in Other Noncurrent Liabilities  13,265   272   9,300   8,026 
Changes in Certain Components of Working Capital:                
Accounts Receivable, Net  (38,279)  (18,273)   16,947   (32,723)
Fuel, Materials and Supplies  (40,620)  (42,452)   (48,197)  (1,245)
Accounts Payable  47,035   (46,758)   45,252   (59,925)
Accrued Taxes, Net  (5,865)  46,587   (56,936)  (19,997)
Other Current Assets  (9,620)  162   (14,333)  (11,784)
Other Current Liabilities  (9,760)  4,253   (17,092)  16,891 
Net Cash Flows from Operating Activities  289,944   279,029   434,295   402,980 
                
INVESTING ACTIVITIES                
Construction Expenditures  (276,911)  (565,832)   (453,405)  (751,161)
Change in Advances to Affiliates, Net  (39,758)  - 
Proceeds from Sales of Assets  5,889   5,594   6,872   7,924 
Other  (505)  (24)   (387)  (23)
Net Cash Flows Used for Investing Activities  (271,527)  (560,262)   (486,678)  (743,260)
                
FINANCING ACTIVITIES                
Issuance of Long-term Debt – Nonaffiliated  164,474   461,324   412,389   461,324 
Change in Short-term Debt, Net – Nonaffiliated  (701)  (1,203)   (701)  895 
Change in Advances from Affiliates, Net  72,285   (164,698)   (101,548)  (95,940)
Retirement of Long-term Debt – Nonaffiliated  (257,463)  (8,927)   (263,463)  (8,927)
Retirement of Cumulative Preferred Stock  -   (2)   -   (2)
Principal Payments for Capital Lease Obligations  (3,214)  (3,521)   (4,636)  (5,420)
Dividends Paid on Cumulative Preferred Stock  (366)  (366)   (549)  (549)
Other  10,000   -   13,313   - 
Net Cash Flows from (Used for) Financing Activities  (14,985)  282,607 
Net Cash Flows from Financing Activities  54,805   351,381 
                
Net Increase in Cash and Cash Equivalents  3,432   1,374   2,422   11,101 
Cash and Cash Equivalents at Beginning of Period  6,666   1,625   6,666   1,625 
Cash and Cash Equivalents at End of Period $10,098  $2,999  $9,088  $12,726 
                
SUPPLEMENTARY INFORMATION                
Cash Paid for Interest, Net of Capitalized Amounts $72,685  $51,991  $112,321  $85,851 
Net Cash Paid (Received) for Income Taxes  32,569   (9,193) 
Net Cash Paid for Income Taxes  61,051   61,459 
Noncash Acquisitions Under Capital Leases  1,673   1,036   2,018   1,620 
Construction Expenditures Included in Accounts Payable at June 30,  27,610   65,936 
Noncash Acquisition of Coal Land Rights  41,600   - 
Construction Expenditures Included in Accounts Payable at September 30,  25,839   42,055 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


 
 
 

OHIO POWER COMPANY CONSOLIDATED
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

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

 
Footnote
Reference
  
Significant Accounting MattersNote 1
New Accounting Pronouncements and Extraordinary ItemNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
Benefit PlansNote 6
Business SegmentsNote 7
Income TaxesNote 8
Financing ActivitiesNote 9



 
 
 








PUBLIC SERVICE COMPANY OF OKLAHOMA


 
 
 

PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

SecondThird Quarter of 2008 Compared to SecondThird Quarter of 2007

Reconciliation of SecondThird Quarter of 2007 to SecondThird Quarter of 2008
Net Income
(in millions)

Second Quarter of 2007    $6 
Third Quarter of 2007    $37 
              
Changes in Gross Margin:              
Retail and Off-system Sales Margins  8       (6)    
Transmission Revenues  3       3     
Other  1     
Total Change in Gross Margin      12       (3)
                
Changes in Operating Expenses and Other:                
Other Operation and Maintenance  (6)      (11)    
Deferral of Ice Storm Costs  (8)    
Depreciation and Amortization  (2)      (3)    
Taxes Other Than Income Taxes  2     
Other Income  3       (1)    
Carrying Costs Income  3     
Interest Expense  (2)      (1)    
Total Change in Operating Expenses and Other      (15)      (11)
                
Income Tax Expense      1       5 
                
Second Quarter of 2008     $4 
Third Quarter of 2008     $28 

Net Income decreased $2$9 million to $4$28 million in 2008.  The key drivers of the decrease were a $15an $11 million increase in Operating Expenses and Other and a $3 million decrease in Gross Margin, offset by a $12$5 million decrease in Income Tax Expense.

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 and Off-system Sales Margins decreased $6 million primarily due to a decrease in retail sales margins mainly due to an 11% decrease in cooling degree days, partially offset by base rate adjustments.
·Transmission Revenues increased $3 million primarily due to higher rates within SPP.

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

·Other Operation and Maintenance expenses increased $11 million primarily due to:
·A $4 million increase primarily associated with outside services and employee-related expenses.
·A $2 million increase in overhead line expenses.
·A $1 million increase in transmission expense primarily due to higher rates within SPP.
·A $1 million increase in expense for the June 2008 storms.
·Depreciation and Amortization expenses increased $3 million primarily due to an increase in the amortization of the Lawton Settlement regulatory assets.
·Taxes Other Than Income Taxes decreased $2 million primarily due to decreases in real property tax and decreases in state sales and use tax.
·Carrying Costs Income increased $3 million primarily due to the new peaking units and to deferred ice storms costs.  See “Oklahoma 2007 Ice Storms” section of Note 3.
·Income Tax Expense decreased $5 million primarily due to a decrease in pretax book income.
Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Reconciliation of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2008
Net Income
(in millions)

Nine Months Ended September 30, 2007    $22 
        
Changes in Gross Margin:       
Retail and Off-system Sales Margins  16     
Transmission Revenues  7     
Other  11     
Total Change in Gross Margin      34 
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  (24)    
Deferral of Ice Storm Costs  72     
Depreciation and Amortization  (8)    
Taxes Other Than Income Taxes  1     
Other Income  2     
Carrying Costs Income  7     
Interest Expense  (7)    
Total Change in Operating Expenses and Other      43 
         
Income Tax Expense      (30)
         
Nine Months Ended September 30, 2008     $69 

Net Income increased $47 million to $69 million in 2008.  The key drivers of the increase were a $43 million decrease in Operating Expenses and Other and a $34 million increase in Gross Margin, andoffset by a $1$30 million decreaseincrease in Income Tax Expense.

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 and Off-system Sales Margins increased $8 million primarily due to:
·A $7 million increase in retail sales margins mainly due to base rate adjustments and a slight increase in KWH sales.
·A $1 million net increase in off-system margins retained primarily due to higher physical sales margins, partially offset by lower trading margins.
·Transmission Revenues increased $3 million primarily due to higher rates within SPP.

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

·Other Operation and Maintenance expenses increased $6 million primarily due to:
·A $7 million increase due to a credit in 2007 to adjust the expenses of the January 2007 ice storm.
·A $4 million increase in transmission expense primarily due to an increase in transmission services from other utilities.
·A $3 million increase in administrative and general expenses, primarily associated with maintenance, outside services and employee-related expenses.
·A $2 million increase in expense for the June 2008 storms.
·A $2 million increase due to amortization of the deferred ice storm costs.
These increases were partially offset by:
·A $10 million decrease primarily to true-up actual December ice storm costs to the 2007 estimated accrual and is offset in the Deferral below.  See “Deferral of Ice Storm Costs” below.
·Deferral of Ice Storm Costs increased $8 million due to 2008 costs and true-up entries as discussed above.  See “Oklahoma 2007 Ice Storms” section of Note 3.
·Depreciation and Amortization expenses increased $2 million primarily due to a $3 million increase in the amortization of the Lawton Settlement regulatory asset offset by a $1 million decrease in depreciation primarily resulting from lower rates.
·Other Income increased $3 million primarily due to an increase in carrying charges related to the new peaking units and to deferred ice storms costs.  See “Oklahoma 2007 Ice Storms” section of Note 3.
·Interest Expense increased $2 million primarily due to a $4 million increase in interest expense from long-term borrowings offset by a $1 million decrease in interest expense from short-term borrowings.

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

Reconciliation of Six Months Ended June 30, 2007 to Six Months Ended June 30, 2008
Net Income (Loss)
(in millions)

Six Months Ended June 30, 2007    $(14)
        
Changes in Gross Margin:       
Retail and Off-system Sales Margins  22     
Transmission Revenues  4     
Other  11     
Total Change in Gross Margin      37 
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  (13)    
Deferral of Ice Storm Costs  72     
Depreciation and Amortization  (5)    
Taxes Other Than Income Taxes  (1)    
Other Income  6     
Interest Expense  (5)    
Total Change in Operating Expenses and Other      54 
         
Income Tax Expense      (35)
         
Six Months Ended June 30, 2008     $42 

Net Income (Loss) increased $56 million to $42 million in 2008.  The key drivers of the increase were a $54 million decrease in Operating Expenses and Other and a $37 million increase in Gross Margin offset by a $35 million increase in Income Tax Expense.

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 and Off-system Sales Margins increased $22$16 million primarily due to an increase in retail sales margins resulting from base rate adjustments andduring the year, partially offset by a slight increase5% decrease in KWH sales.cooling degree days.
·Transmission Revenues increased $4$7 million primarily due to higher rates within SPP.
·
Other revenues increased $11 million primarily due to a $10 millionan increase related to the recognition of the sale of SO2 allowances.  See “Oklahoma 2007 Ice Storms” section of Note 3.

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

·Other Operation and Maintenance expenses increased $13$24 million primarily due to:
 ·A $10$12 million increase in production expenses primarily due to a $10 million write-off of pre-construction costs related to the canceledcancelled Red Rock Generating Facility.  See “Red Rock Generating Facility” section of Note 3.
 ·A $9$10 million increase due to amortization of the deferred 2007 ice storm costs.
 ·An $8A $7 million increase in transmission expense primarily due to an increase in transmission services from other utilities.higher rates within SPP.
 ·A $4$6 million increase in administrative and general expenses, primarily associated with maintenance, outside services and employee-related expenses.
 ·A $2$3 million increase in expense for the June 2008 storms.
 ·A $1$2 million increase in distribution maintenance expense due to increased vegetation management activities.
 These increases were partially offset by:
 ·A $14$12 million decrease for the costs of the January 2007 ice storm.
 ·A $10 million decrease primarily to true-up actual December ice storm costs to the 2007 estimated accrual.
·Deferral of Ice Storm Costs in 2008 of $72 million results from an OCC order approving recovery of ice storm costs related to ice storms in January and December 2007.  See “Oklahoma 2007 Ice Storms” section of Note 3.
·Depreciation and Amortization expenses increased $5$8 million primarily due to a $7 millionan increase related to the amortization of the Lawton Settlement regulatory asset offset by a $2 million decrease in depreciation primarily resulting from lower rates.assets.
·Other Income increased $6$2 million primarily due to a $3 million increase in carrying charges related to the new peaking units and to deferred ice storms costs (see “Oklahoma 2007 Ice Storms” section of Note 3) and a $1 millionan increase in the equity component of AFUDC.
·Carrying Costs Income increased $7 million due to the new peaking units and deferred ice storm costs.  See “Oklahoma 2007 Ice Storms” section of Note 3.
·Interest Expense increased $5$7 million primarily due to an $8a $12 million increase in interest expense from long-term borrowings, partially offset by a $2$4 million decrease in interest expense from short-term borrowings.
·Income Tax Expense increased $35$30 million primarily due to an increase in pretax book income.

Financial Condition

Credit Ratings

The rating agencies currently have PSO on stable outlook.  In the first quarter of 2008, Fitch downgraded PSO from A- to BBB+ for senior unsecured debt.  Current credit ratings are as follows:

 Moody’s S&P Fitch
      
Senior Unsecured DebtBaa1 BBB  BBB+

If PSO receives an upgrade from any of the rating agencies listed above, its borrowing costs could decrease.  If  PSO receives a downgrade from any of the rating agencies listed above, its borrowing costs could increase and access to borrowed funds could be negatively affected.

Cash Flow

Cash flows for the sixnine months ended JuneSeptember 30, 2008 and 2007 were as follows:

 2008  2007  2008  2007 
 (in thousands)  (in thousands) 
Cash and Cash Equivalents at Beginning of Period $1,370  $1,651  $1,370  $1,651 
Cash Flows from (Used for):                
Operating Activities  (6,309)  (30,543)  42,386   62,042 
Investing Activities  (99,942)  (161,760)  (161,523)  (231,916)
Financing Activities  106,405   191,560   120,011   169,713 
Net Increase (Decrease) in Cash and Cash Equivalents  154   (743)  874   (161)
Cash and Cash Equivalents at End of Period $1,524  $908  $2,244  $1,490 

Operating Activities

Net Cash Flows Used forfrom Operating Activities were $6$42 million in 2008.  PSO produced Net Income of $42$69 million during the period and had noncash expense items of $78 million for Depreciation and Amortization and $71 million for Deferred Income Taxes and $51 million for Depreciation and Amortization.Taxes.  PSO established a $72 million regulatory asset for an OCC order approving recovery of ice storm costs related to storms in January and December 2007.  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.  The $81 million outflow from Accounts Payable was primarily due to a decrease in accounts payable accruals and purchased power payable.  The $47 million outflow from Fuel Over/Under-Recovery, Net which had a $74 million outflow as a result ofresulted from rapidly increasing cost of natural gas costs which fuels the majority of PSO’s generators.generating facilities.  The $36 million inflow from Accrued Taxes, Net was the result of a refund for the 2007 overpayment of federal income taxes and increased accruals related to property and income taxes.

Net Cash Flows Used forfrom Operating Activities were $31$62 million in 2007.  PSO incurred aproduced Net LossIncome of $14$22 million during the period and had a noncash expense item of $46$70 million for Depreciation and Amortization.  The $26 million outflow from Other Noncurrent Assets was primarily related to the establishment of a $35 million regulatory asset for the payment of the Lawton Settlement.  The other changes in assets and liabilities represent items that had a priorcurrent 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 $14$32 million outflow from Accounts Receivable, Net was primarily due to a receivable booked on behalf of the joint owners of a generating station related to fuel transportation costs.  The $26 million inflow from Margin Deposits was primarily due to gas trading activities.  The $8 million outflow from Fuel Over/Under-Recovery,Under Recovery, Net was the result ofresulted from increasing costs of natural gas costs which fuels the majority of PSO’s generators.  The $22 million outflow from Other Current Liabilities was primarily due to $18 million fewer outstanding checks at June 30, 2007 when compared to December 31, 2006.generating facilities.

Investing Activities

Net Cash Flows Used for Investing Activities during 2008 and 2007 were $100$162 million and $162$232 million, respectively.  Construction Expenditures of $152$214 million and $235 million in 2008 and 2007, respectively, were primarily related to projects for improved generation, transmission and distribution service reliability.  In addition, during 2008, PSO had a net decrease of $51 million in loans to the Utility Money Pool.  For the remainder of 2008, PSO expects construction expenditures to be approximately $130$70 million.

Financing Activities

Net Cash Flows from Financing Activities were $106$120 million during 2008.  PSO had a net increase of $111$125 million in borrowings from the Utility Money Pool.  PSO repurchased $34 million in Pollution Control Bonds in May 2008.  PSO received a capital contributioncontributions from the Parent of $30 million.

Net Cash Flows from Financing Activities were $192$170 million during 2007.  PSO had a net increase of $140$111 million in borrowings from the Utility Money Pool.  PSO received a capital contributioncontributions from the Parent of $40$60 million.

Financing Activity

Long-term debt issuances, retirements and principal payments made during the first sixnine months of 2008 were:

Issuances

None

Retirements and Principal Payments
 Principal Interest Due
Type of Debt 
 Principal
Amount Paid
 Interest Rate Due Date Amount Paid Rate Date
 (in thousands) (%)   (in thousands) (%)  
Pollution Control Bonds $33,700 Variable 2014 $33,700  Variable 2014

Liquidity

PSO has solid investment grade ratings, which provide readyIn recent months, the financial markets have become increasingly unstable and constrained at both a global and domestic level.  This systemic marketplace distress is impacting PSO’s access to capital, liquidity and cost of capital.  The uncertainties in the credit markets in ordercould have significant implications on PSO since it relies on continuing access to issue new debt or refinance long-term debt maturities.  In addition, capital to fund operations and capital expenditures.

PSO participates in the Utility Money Pool, which provides access to AEP’s liquidity.  PSO has $50 million of Senior Unsecured Notes that will mature in 2009.  To the extent refinancing is unavailable due to the challenging credit markets, PSO will rely upon cash flows from operations and access to the Utility Money Pool to fund its maturity,  current operations and capital expenditures.

Summary Obligation Information

PSO’s contractual obligations include amounts reported on PSO’s Balance Sheets and other obligations disclosed in the footnotes.  The following table summarizes PSO’s contractual cash obligations at December 31, 2007:

Payments Due by Period
(in millions)

Contractual Cash Obligations 
Less Than
1 year
  2-3 years  4-5 years  
After
5 years
  Total 
Interest on Fixed Rate Portion of Long-term
  Debt (a)
 $51.7  $99.5  $78.5  $695.2  $924.9 
Fixed Rate Portion of Long-term Debt (b)  -   200.0   75.0   612.7   887.7 
Variable Rate Portion of Long-term Debt (c)  -   -   -   33.7   33.7 
Capital Lease Obligations (d)  1.7   2.2   0.5   -   4.4 
Noncancelable Operating Leases (d)  6.7   10.7   5.7   5.6   28.7 
Fuel Purchase Contracts (e)  295.6   130.1   85.3   -   511.0 
Energy and Capacity Purchase Contracts (f)  6.9   6.4   -   -   13.3 
Construction Contracts for Capital Assets (g)  55.2   128.4   143.5   10.0   337.1 
Total $417.8  $577.3  $388.5  $1,357.2  $2,740.8 

(a)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2007 and do not reflect anticipated future refinancing, early redemptions or debt issuances.
(b)See Note 15 of the 2007 Annual Report.  Represents principal only excluding interest.
(c)See Note 15 of the 2007 Annual Report.  Represents principal only excluding interest.  Variable rate debt had a 3.75% interest rate at December 31, 2007.
(d)See Note 14 of the 2007 Annual Report.
(e)Represents contractual obligations to purchase coal, natural gas and other consumable as fuel for electric generation along with related transportation of the fuel.
(f)Represents contractual cash flows of energy and capacity purchase contracts.
(g)Represents only capital assets that are contractual obligations.

PSO’s FIN 48 liabilities of $5 million are not included above because PSO cannot reasonably estimate the cash flows by period.

As discussed in Note 9 of the 2007 Annual Report, PSO’s minimum pension funding requirements are not included above as such amounts are discretionary based upon the status of the trusts.

As of December 31, 2007, PSO had no outstanding standby letters of credit or guarantees of performance.

The summary of contractual obligations for the year ended 2007 is included in the second quarter 2008 10-Q and has not changed significantly from year-end other than the debt retirement discussed in “Cash Flow” and “Financing Activity” above.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, PSO is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be.  Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases which have a probable likelihood of loss and the loss amount 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 2007 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section..  Adverse results in these proceedings have the potential to materially affect results of operations,net income, financial condition and cash flows.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of relevant factors.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2007 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.


 
 
 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Risk management assets and liabilities are managed by AEPSC as agent.  The related risk management policies and procedures are instituted and administered by AEPSC.  See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section.  The following tables provide information about AEP’s risk management activities’ effect on PSO.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in PSO’s Condensed Consolidated Balance Sheet as of JuneSeptember 30, 2008 and the reasons for changes in total MTM value as compared to December 31, 2007.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of JuneSeptember 30, 2008
(in thousands)

                        
 MTM Risk  DETM        MTM Risk  DETM       
 Management  Assignment  Collateral     Management  Assignment  Collateral    
 Contracts  (a)  Deposits  Total  Contracts  (a)  Deposits  Total 
Current Assets $88,788  $-  $(1,705) $87,083  $25,165  $-  $(448) $24,717 
Noncurrent Assets  12,321   -   (39)  12,282   2,703   -   (51)  2,652 
Total MTM Derivative Contract Assets  101,109   -   (1,744)  99,365   27,868   -   (499)  27,369 
                                
Current Liabilities  (86,621)  (93)  2,249   (84,465)  (25,508)  (110)  40   (25,578)
Noncurrent Liabilities  (11,098)  (102)  852   (10,348)  (1,891)  (112)  7   (1,996)
Total MTM Derivative Contract Liabilities  (97,719)  (195)  3,101   (94,813)  (27,399)  (222)  47   (27,574)
                                
Total MTM Derivative Contract Net Assets (Liabilities) $3,390  $(195) $1,357  $4,552  $469  $(222) $(452) $(205)

(a)See “Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual Report.

MTM Risk Management Contract Net Assets (Liabilities)
SixNine Months Ended JuneSeptember 30, 2008
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2007 $6,981  $6,981 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period (4,066)  (6,988)
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 -   - 
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b) 32   20 
Changes in Fair Value Due to Market Fluctuations During the Period (c) (146)  (104)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)  589   560 
Total MTM Risk Management Contract Net Assets 3,390   469 
DETM Assignment (e) (195)  (222)
Collateral Deposits  1,357   (452)
Ending Net Risk Management Assets at June 30, 2008 $4,552 
Ending Net Risk Management Assets (Liabilities) at September 30, 2008 $(205)

(a)Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term.  The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)Represents the impact of applying AEP’s credit risk when measuring the fair value of derivative liabilities according to SFAS 157.
(c)Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(d)“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income.  These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.liabilities.
(e)See “Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual Report.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The following table presents the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash:

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of JuneSeptember 30, 2008
(in thousands)

 
Remainder
2008
  2009  2010  2011  2012  
After
2012
  Total  
Remainder
2008
  2009  2010  2011  2012  
After
2012
  Total 
Level 1 (a) $1,167  $(235) $-  $-  $-  $-  $932  $316  $(250) $-  $-  $-  $-  $66 
Level 2 (b)  434   2,189   (128)  (14)  -   -   2,481   50   1,134   511   (85)  -   -   1,610 
Level 3 (c)  (24)  -   1   -   -   -   (23)  (1,208)  -   1   -   -   -   (1,207)
Total $1,577  $1,954  $(127) $(14) $-  $-  $3,390  $(842) $884  $512  $(85) $-  $-  $469 

(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.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed Consolidated Balance Sheet

Management uses interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt.  Management does not hedge all interest rate risk.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on PSO’s Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2007 to JuneSeptember 30, 2008.  Only contracts designated as cash flow hedges are recorded in AOCI.  Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables.  All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
SixNine Months Ended JuneSeptember 30, 2008
(in thousands)

 Interest Rate  Interest Rate 
Beginning Balance in AOCI December 31, 2007 $(887) $(887)
Changes in Fair Value -   - 
Reclassifications from AOCI for Cash Flow Hedges Settled
  91   137 
Ending Balance in AOCI June 30, 2008 $(796)
Ending Balance in AOCI September 30, 2008 $(750)

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is an $183 thousand loss.

Credit Risk

Counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates Value at Risk (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 JuneSeptember 30, 2008, a near term typical change in commodity prices is not expected to have a material effect on PSO’s results of operations,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 periods indicated:

Six Months Ended June 30, 2008 Twelve Months Ended December 31, 2007
Nine Months Ended September 30, 2008Nine Months Ended September 30, 2008 Twelve Months Ended December 31, 2007
(in thousands)(in thousands) (in thousands)(in thousands) (in thousands)
End High Average Low End High Average Low High Average Low End High Average Low
$39 $109 $37 $8 $13 $189 $53 $5
$69 $164 $45 $8 $13 $189 $53 $5

Management back-tests its VaR results against performance due to actual price moves.  Based on the assumed 95% confidence interval, the performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days.  Management’s backtesting results show that its actual performance exceeded VaR far fewer than once every 20 trading days.  As a result, management believes PSO’s VaR calculation is conservative.

As PSO’s VaR calculation captures recent price moves, management also performs regular stress testing of the portfolio to understand PSO’s exposure to extreme price moves.  Management employs a historically-based method whereby the current portfolio is subjected to actual, observed price moves from the last three years in order to ascertain which historical price moves translate into the largest potential mark-to-market loss.  Management then researches the underlying positions, price moves and market events that created the most significant exposure.

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 PSO’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  The estimated EaR on PSO’s debt portfolio was $800 thousand.$3.6 million.

 
 
 



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF OPERATIONSINCOME
For the Three and SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in thousands)
(Unaudited)

 Three Months Ended  Six Months Ended  Three Months Ended  Nine Months Ended 
 2008  2007  2008  2007  2008  2007  2008  2007 
REVENUES                        
Electric Generation, Transmission and Distribution $357,675  $304,820  $676,555  $594,900  $518,182  $433,737  $1,194,737  $1,028,637 
Sales to AEP Affiliates  41,767   16,275   57,702   40,868   32,286   12,737   89,988   53,605 
Other  892   544   2,077   1,184   781   1,562   2,858   2,746 
TOTAL  400,334   321,639   736,334   636,952   551,249   448,036   1,287,583   1,084,988 
                                
EXPENSES                                
Fuel and Other Consumables Used for Electric Generation  143,537   113,633   296,742   256,148   288,027   182,680   584,769   438,828 
Purchased Electricity for Resale  104,016   70,145   152,598   137,554   77,834   75,875   230,432   213,429 
Purchased Electricity from AEP Affiliates  21,506   18,979   38,775   32,463   15,169   16,216   53,944   48,679 
Other Operation  45,186   42,345   101,185   83,352   51,432   44,030   152,617   127,382 
Maintenance  25,655   22,177   60,242   65,262   27,530   24,128   87,772   89,390 
Deferral of Ice Storm Costs  8,223   -   (71,679)  -   69   -   (71,610)  - 
Depreciation and Amortization  24,720   22,992   50,887   45,698   27,192   24,430   78,079   70,128 
Taxes Other Than Income Taxes  10,474   9,890   21,426   20,184   7,839   10,007   29,265   30,191 
TOTAL  383,317   300,161   650,176   640,661   495,092   377,366   1,145,268   1,018,027 
                                
OPERATING INCOME (LOSS)  17,017   21,478   86,158   (3,709)
OPERATING INCOME  56,157   70,670   142,315   66,961 
                                
Other Income (Expense):                                
Interest Income  967   518   2,095   518 
Other Income  34   1,086   4,004   2,294 
Carrying Costs Income  2,128   -   3,762   -   3,183   -   6,945   - 
Allowance for Equity Funds Used During Construction  516   44   1,875   690 
Interest Expense  (14,525)  (12,785)  (29,466)  (24,168)  (13,713)  (12,381)  (43,179)  (36,549)
                                
INCOME (LOSS) BEFORE INCOME TAX EXPENSE
(CREDIT)
  6,103   9,255   64,424   (26,669)
INCOME BEFORE INCOME TAX EXPENSE  45,661   59,375   110,085   32,706 
                                
Income Tax Expense (Credit)  1,976   2,960   22,898   (12,538)
Income Tax Expense  17,917   22,804   40,815   10,266 
                                
NET INCOME (LOSS)  4,127   6,295   41,526   (14,131)
NET INCOME  27,744   36,571   69,270   22,440 
                                
Preferred Stock Dividend Requirements  53   53   106   106   53   53   159   159 
                                
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $4,074  $6,242  $41,420  $(14,237)
EARNINGS APPLICABLE TO COMMON STOCK $27,691  $36,518  $69,111  $22,281 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

 
 
 

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in thousands)
(Unaudited)

 Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total  Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
DECEMBER 31, 2006 $157,230  $230,016  $199,262  $(1,070) $585,438  $157,230  $230,016  $199,262  $(1,070) $585,438 
                                        
FIN 48 Adoption, Net of Tax          (386)      (386)          (386)      (386)
Capital Contribution from Parent      40,000           40,000       60,000           60,000 
Preferred Stock Dividends          (106)      (106)          (159)      (159)
TOTAL                  624,946                   644,893 
                                        
COMPREHENSIVE LOSS                    
COMPREHENSIVE INCOME                    
Other Comprehensive Income, Net of Taxes:                                        
Cash Flow Hedges, Net of Tax of $49              91   91 
NET LOSS          (14,131)      (14,131)
TOTAL COMPREHENSIVE LOSS                  (14,040)
Cash Flow Hedges, Net of Tax of $74              137   137 
NET INCOME          22,440       22,440 
TOTAL COMPREHENSIVE INCOME                  22,577 
                                        
JUNE 30, 2007 $157,230  $270,016  $184,639  $(979) $610,906 
SEPTEMBER 30, 2007 $157,230  $290,016  $221,157  $(933) $667,470 
                                        
DECEMBER 31, 2007 $157,230  $310,016  $174,539  $(887) $640,898  $157,230  $310,016  $174,539  $(887) $640,898 
                                        
EITF 06-10 Adoption, Net of Tax of $596          (1,107)      (1,107)          (1,107)      (1,107)
Capital Contribution from Parent      30,000           30,000       30,000           30,000 
Preferred Stock Dividends          (106)      (106)          (159)      (159)
TOTAL                  669,685                   669,632 
                                        
COMPREHENSIVE INCOME                                        
Other Comprehensive Income, Net of Taxes:                                        
Cash Flow Hedges, Net of Tax of $49              91   91 
Cash Flow Hedges, Net of Tax of $74              137   137 
NET INCOME          41,526       41,526           69,270       69,270 
TOTAL COMPREHENSIVE INCOME                  41,617                   69,407 
                                        
JUNE 30, 2008 $157,230  $340,016  $214,852  $(796) $711,302 
SEPTEMBER 30, 2008 $157,230  $340,016  $242,543  $(750) $739,039 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

 
 
 

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
JuneSeptember 30, 2008 and December 31, 2007
(in thousands)
(Unaudited)

 2008  2007  2008  2007 
CURRENT ASSETS      
Cash and Cash Equivalents $1,524  $1,370  $2,244  $1,370 
Advances to Affiliates  -   51,202   -   51,202 
Accounts Receivable:                
Customers  54,815   74,330   42,023   74,330 
Affiliated Companies  79,370   59,835   72,627   59,835 
Miscellaneous  10,748   10,315   9,716   10,315 
Allowance for Uncollectible Accounts  (18)  -   (28)  - 
Total Accounts Receivable  144,915   144,480   124,338   144,480 
Fuel  27,124   19,394   26,547   19,394 
Materials and Supplies  47,925   47,691   47,419   47,691 
Risk Management Assets  87,083   33,308   24,717   33,308 
Accrued Tax Benefits  52,082   31,756   13,040   31,756 
Regulatory Asset for Under-Recovered Fuel Costs  61,876   -   35,495   - 
Margin Deposits  992   8,980   426   8,980 
Prepayments and Other  14,559   18,137   18,385   18,137 
TOTAL  438,080   356,318   292,611   356,318 
          ��     
PROPERTY, PLANT AND EQUIPMENT                
Electric:                
Production  1,234,217   1,110,657   1,252,804   1,110,657 
Transmission  598,361   569,746   601,518   569,746 
Distribution  1,402,521   1,337,038   1,437,156   1,337,038 
Other  249,073   241,722   253,886   241,722 
Construction Work in Progress  94,615   200,018   77,392   200,018 
Total  3,578,787   3,459,181   3,622,756   3,459,181 
Accumulated Depreciation and Amortization  1,191,109   1,182,171   1,191,777   1,182,171 
TOTAL - NET  2,387,678   2,277,010   2,430,979   2,277,010 
                
OTHER NONCURRENT ASSETS                
Regulatory Assets  186,807   158,731   186,216   158,731 
Long-term Risk Management Assets  12,282   3,358   2,652   3,358 
Deferred Charges and Other  67,944   48,454   59,369   48,454 
TOTAL  267,033   210,543   248,237   210,543 
                
TOTAL ASSETS $3,092,791  $2,843,871  $2,971,827  $2,843,871 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
 
 
 

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
JuneSeptember 30, 2008 and December 31, 2007
(Unaudited)

 2008  2007  2008  2007 
CURRENT LIABILITIES (in thousands)  (in thousands) 
Advances from Affiliates $110,981  $-  $125,029  $- 
Accounts Payable:                
General  164,652   189,032   98,541   189,032 
Affiliated Companies  107,254   80,316   74,420   80,316 
Long-term Debt Due Within One Year – Nonaffiliated  50,000   -   50,000   - 
Risk Management Liabilities  84,465   27,118   25,578   27,118 
Customer Deposits  40,409   41,477   39,498   41,477 
Accrued Taxes  36,383   18,374   35,282   18,374 
Regulatory Liability for Over-Recovered Fuel Costs  -   11,697   -   11,697 
Other  42,588   57,708   46,703   57,708 
TOTAL  636,732   425,722   495,051   425,722 
                
NONCURRENT LIABILITIES                
Long-term Debt – Nonaffiliated  834,737   918,316   834,798   918,316 
Long-term Risk Management Liabilities  10,348   2,808   1,996   2,808 
Deferred Income Taxes  526,319   456,497   530,293   456,497 
Regulatory Liabilities and Deferred Investment Tax Credits  316,575   338,788   316,521   338,788 
Deferred Credits and Other  51,516   55,580   48,867   55,580 
TOTAL  1,739,495   1,771,989   1,732,475   1,771,989 
                
TOTAL LIABILITIES  2,376,227   2,197,711   2,227,526   2,197,711 
                
Cumulative Preferred Stock Not Subject to Mandatory Redemption  5,262   5,262   5,262   5,262 
                
Commitments and Contingencies (Note 4)                
                
COMMON SHAREHOLDER’S EQUITY                
Common Stock – $15 Par Value Per Share:                
Authorized – 11,000,000 Shares                
Issued – 10,482,000 Shares                
Outstanding – 9,013,000 Shares  157,230   157,230   157,230   157,230 
Paid-in Capital  340,016   310,016   340,016   310,016 
Retained Earnings  214,852   174,539   242,543   174,539 
Accumulated Other Comprehensive Income (Loss)  (796)  (887)   (750)  (887)
TOTAL  711,302   640,898   739,039   640,898 
                
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $3,092,791  $2,843,871  $2,971,827  $2,843,871 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
 
 
 

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in thousands)
(Unaudited)

 2008  2007  2008  2007 
OPERATING ACTIVITIES            
Net Income (Loss) $41,526  $(14,131) 
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows Used for Operating Activities:        
Net Income $69,270  $22,440 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization  50,887   45,698   78,079   70,128 
Deferred Income Taxes  70,618   11,059   70,856   23,220 
Deferral of Ice Storm Costs  (71,679)  -   (71,610)  - 
Allowance for Equity Funds Used During Construction  (1,875)  (690)   (1,840)  (649)
Mark-to-Market of Risk Management Contracts  2,216   4,832   6,973   7,120 
Deferred Property Taxes  (17,796)  (16,539) 
Change in Other Noncurrent Assets  25,981   (25,601)   9,920   (17,754)
Change in Other Noncurrent Liabilities  (33,384)  (22,811)   (34,426)  (31,165)
Changes in Certain Components of Working Capital:                
Accounts Receivable, Net  1,270   19,413   21,846   (31,617)
Fuel, Materials and Supplies  (7,964)  (8,414)   (6,881)  (2,110)
Margin Deposits  7,988   10,216   8,554   26,461 
Accounts Payable  18,238   11,810   (81,228)  10,226 
Customer Deposits  (1,068)  (3,354) 
Accrued Taxes, Net  (2,317)  (6,888)   35,624   19,725 
Fuel Over/Under-Recovery, Net  (73,573)  (13,512)   (47,192)  (8,260)
Other Current Assets  820   597   (1,676)  177 
Other Current Liabilities  (16,197)  (22,228)   (13,883)  (25,900)
Net Cash Flows Used for Operating Activities  (6,309)  (30,543) 
Net Cash Flows from Operating Activities  42,386   62,042 
                
INVESTING ACTIVITIES                
Construction Expenditures  (151,711)  (151,973)   (214,319)  (235,089)
Change in Other Cash Deposits, Net  -   (12,896) 
Change in Advances to Affiliates, Net  51,202   -   51,202   - 
Proceeds from Sales of Assets  567   3,109 
Other  1,594   3,173 
Net Cash Flows Used for Investing Activities  (99,942)  (161,760)   (161,523)  (231,916)
                
FINANCING ACTIVITIES                
Capital Contribution from Parent  30,000   40,000   30,000   60,000 
Issuance of Long-term Debt – Nonaffiliated  -   12,495   -   12,488 
Change in Advances from Affiliates, Net  110,981   139,916   125,029   111,169 
Retirement of Long-term Debt – Nonaffiliated  (33,700)  - 
Retirement of Long-term Debt – Affiliated  (33,700)  (12,660)
Principal Payments for Capital Lease Obligations  (770)  (745)   (1,159)  (1,125)
Dividends Paid on Cumulative Preferred Stock  (106)  (106)   (159)  (159)
Net Cash Flows from Financing Activities  106,405   191,560   120,011   169,713 
                
Net Increase (Decrease) in Cash and Cash Equivalents  154   (743)   874   (161)
Cash and Cash Equivalents at Beginning of Period  1,370   1,651   1,370   1,651 
Cash and Cash Equivalents at End of Period $1,524  $908  $2,244  $1,490 
                
SUPPLEMENTARY INFORMATION                
Cash Paid for Interest, Net of Capitalized Amounts $27,774  $21,339  $39,739  $34,427 
Net Cash Received for Income Taxes  19,529   2,353   44,559   18,004 
Noncash Acquisitions Under Capital Leases  253   434   403   600 
Construction Expenditures Included in Accounts Payable at June 30,  11,731   21,261 
Construction Expenditures Included in Accounts Payable at September 30,  12,251   16,358 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

 
 
 

PUBLIC SERVICE COMPANY OF OKLAHOMA
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

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

 
Footnote Reference
  
Significant Accounting MattersNote 1
New Accounting Pronouncements and Extraordinary ItemNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
Benefit PlansNote 6
Business SegmentsNote 7
Income TaxesNote 8
Financing ActivitiesNote 9







SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED


 
 
 







SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

SecondThird Quarter of 2008 Compared to SecondThird Quarter of 2007

Reconciliation of SecondThird Quarter of 2007 to SecondThird Quarter of 2008
Net Income
(in millions)
Second Quarter of 2007    $2 
Third Quarter of 2007    $44 
              
Changes in Gross Margin:              
Retail and Off-system Sales Margins (a)  23       11     
Transmission Revenues  2       3     
Other  (2)      3     
Total Change in Gross Margin      23       17 
                
Changes in Operating Expenses and Other:                
Other Operation and Maintenance  (7)      (15)    
Depreciation and Amortization  (2)      (1)    
Taxes Other Than Income Taxes  2       4     
Other Income  1       5     
Interest Expense  (7)    
Total Change in Operating Expenses and Other      (6)      (14)
                
Income Tax Expense      (5)
        
Second Quarter of 2008     $14 
Third Quarter of 2008     $47 

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

Net Income increased $12$3 million to $14$47 million in 2008.  The key drivers of the increase were a $23$17 million increase in Gross Margin, partially offset by a $6$14 million increase in Operating Expenses and Other and a $5 million increase in Income Tax Expense.Other.

The major componentcomponents 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 and Off-system Sales Margins increased $23$11 million primarily due to a $25 million refund provision bookedan increase in 2007 pursuant to an unfavorable ALJ ruling in the Texas Fuel Reconciliation proceeding.wholesale fuel recovery.
·Transmission Revenues increased $2$3 million due to higher rates in the SPP region.
·Other revenues decreased $2increased $3 million primarily due to a $6 million decrease in gains on sales of emission allowances offset by a $4 millionan increase in revenues from coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite Company, LLC, to Cleco Corporation, a nonaffiliated entity.  The increase in coal deliveries was the result of planned and forced outages during 2007 at the Dolet Hills Generating Station, which is jointly-owned by SWEPCo and Cleco Corporation.  The increased revenue from coal deliveries was offset by a corresponding increase in Other Operation and Maintenance expenses from mining operations as discussed below.

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

·Other Operation and Maintenance expenses increased $7$15 million primarily due to a $5the following:
·A $14 million increase in distribution expenses primarily due to storm restoration expenses for Hurricanes Ike and Gustav.  SWEPCo intends to pursue the recovery of these expenses.
·A $3 million increase in expense for coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite Company, LLC.  The increased expenses for coal deliveries were partially offset by a corresponding increase in revenues from mining operations as discussed above.
·Depreciation and Amortization increased $2 million primarily due to higher depreciable asset balances.
·Taxes Other Than Income Taxes decreased $2$4 million primarily due to a $3 million decrease in state and local franchise taxes.tax from refunds related to prior years.
·Other Income Tax Expense increased $5 million primarily due to anhigher nonaffiliated interest income resulting from the fuel under-recovery balance, the Texas state franchise refund and the Utility Money Pool.
·Interest Expense increased $7 million primarily due to a $10 million increase related to higher long-term debt outstanding, partially offset by a $3 million increase in pretax book income.the debt component of AFUDC due to new generation projects.

SixNine Months Ended JuneSeptember 30, 2008 Compared to SixNine Months Ended JuneSeptember 30, 2007

Reconciliation of SixNine Months Ended JuneSeptember 30, 2007 to SixNine Months Ended JuneSeptember 30, 2008
Net Income
(in millions)
Six Months Ended June 30, 2007    $11 
Nine Months Ended September 30, 2007    $55 
              
Changes in Gross Margin:              
Retail and Off-system Sales Margins (a)  28       38     
Transmission Revenues  3       7     
Other  (3)      -     
Total Change in Gross Margin      28       45 
                
Changes in Operating Expenses and Other:                
Other Operation and Maintenance  (17)      (33)    
Depreciation and Amortization  (4)      (5)    
Taxes Other Than Income Taxes  5     
Other Income  3       8     
Interest Expense  (2)      (8)    
Total Change in Operating Expenses and Other      (20)      (33)
                
Six Months Ended June 30, 2008     $19 
Income Tax Expense      (1)
        
Nine Months Ended September 30, 2008     $66 

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

Net Income increased $8$11 million to $19$66 million in 2008.  The key drivers of the increase were a $28$45 million increase in Gross Margin, partially offset by a $20$33 million increase in Operating Expenses and Other.

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 and Off-system Sales Margins increased $28$38 million primarily due to a $25higher fuel recovery resulting from an $18 million refund provision booked in 2007 pursuant to an unfavorable ALJ ruling in the Texas Fuel Reconciliation proceeding.  In addition, an increase of $10 million in wholesale revenue and lower purchase power capacity of $4 million was reflected in 2008.
·Transmission Revenues increased $3$7 million due to higher rates in the SPP region.
·While Other revenues decreased $3 million primarily due toin total were unchanged, there was a $12 million decrease in gains on sales of emission allowancesallowances.  This decrease was offset by a $9an $11 million increase in revenue from coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite Company, LLC, to Cleco Corporation, a nonaffiliated entity.  The increase in coal deliveries was the result of planned and forced outages during 2007 at the Dolet Hills Generating Station, which is jointly-owned by SWEPCo and Cleco Corporation.  The increased revenue from coal deliveries was offset by a corresponding increase in Other Operation and Maintenance expenses from mining operations as discussed below.

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

·Other Operation and Maintenance expenses increased $17$33 million primarily due to the following:
 ·An $11A $12 million increase in distribution expenses primarily due to storm restoration expenses from Hurricanes Ike and Gustav.  SWEPCo intends to pursue the recovery of these expenses.
·A $14 million increase in expenses for coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite Company, LLC.  The increased expenses for coal deliveries were partially offset by a corresponding increase in revenues from mining operations as discussed above.
·A $3 million increase in transmission expenses related to increased usage and rates in the SPP region.
·A $3 million increase in administrative and general expenses, primarily associated with outside services and employee-related expenses.
·Depreciation and Amortization increased $4$5 million primarily due to higher depreciable asset balances.
·Taxes Other Than Income increased $3Taxes decreased $5 million primarily due to a decrease in state and local franchise tax from refunds related to prior years.
·Other Income increased $8 million primarily due to higher nonaffiliated interest income and an increase in the equity component of AFUDC as a result of new generation projects.
·Interest Expense increased $2$8 million primarily due to higher interest of $8a $17 million related toincrease from higher long-term debt outstanding, partially offset by a $4$7 million increase in the debt component of AFUDC due to new generation projectsprojects.
·Income Tax Expense increased $1 million primarily due to an increase in pretax book income, partially offset by state income taxes and changes in certain book/tax differences accounted for on a $3 million decrease in other interest expense partially related to decreased interest expense on fuel recovery.flow-through basis.

Financial Condition

Credit Ratings

S&P and Fitch currently have SWEPCo on stable outlook, while Moody’s placed SWEPCo on negative outlook in the first quarter of 2008.  In addition, in the first quarter of 2008, Fitch downgraded SWEPCo from A- to BBB+ for senior unsecured debt.  Current credit ratings are as follows:

 Moody’s S&P Fitch
      
Senior Unsecured DebtBaa1 BBB  BBB+

If SWEPCo receives an upgrade from any of the rating agencies listed above, its borrowing costs could decrease.  If SWEPCo receives a downgrade from any of the rating agencies listed above, itits borrowing costs could increase and access to borrowed funds could be negatively affected.

Cash Flow

Cash flows for the sixnine months ended JuneSeptember 30, 2008 and 2007 were as follows:

 2008  2007  2008  2007 
 (in thousands)  (in thousands) 
Cash and Cash Equivalents at Beginning of Period $1,742  $2,618  $1,742  $2,618 
Cash Flows from (Used for):                
Operating Activities  74,622   120,597   130,250   180,146 
Investing Activities  (569,109)  (253,267)  (619,487)  (353,001)
Financing Activities  494,987   131,610   490,247   172,089 
Net Increase (Decrease) in Cash and Cash Equivalents  500   (1,060)  1,010   (766)
Cash and Cash Equivalents at End of Period $2,242  $1,558  $2,752  $1,852 

Operating Activities

Net Cash Flows from Operating Activities were $75$130 million in 2008.  SWEPCo produced Net Income of $19$66 million during the period and had a noncash expense item of $73$109 million for Depreciation and Amortization.Amortization and $37 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 $84$99 million outflow from Fuel Over/Under-Recovery, Net was the result of higher fuel costs.  The $61 million inflow from Accounts Payable was primarily due to higher fuel related costs.  The $32$47 million inflow from Accounts Receivable, Net was primarily due to the assignment of certain ERCOT contracts to an affiliate company.  The $13$35 million outflow from Accounts Payable was primarily due to a decrease in purchased power payables.  The $29 million inflow from Accrued Taxes, Net was due to a refund for the result2007 overpayment of increased payments related to property andfederal income taxes.

Net Cash Flows from Operating Activities were $121$180 million in 2007.  SWEPCo produced Net Income of $11$55 million during the period and had noncash expense items of $69$103 million for Depreciation and Amortization and $25$24 million related to the Provision for Fuel Disallowance recorded as the result of an ALJ ruling in SWEPCo’s Texas fuel reconciliation proceeding.  The other changes in assets and liabilities represent items that had a priorcurrent 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 $36 million inflow from Accrued Taxes, Net was the result of increased accruals related to property and income taxes.  The $27$48 million inflow from Accounts Receivable, Net was primarily due to the assignment of certain ERCOT contracts to an affiliate company.  The $30 million inflow from Margin Deposits was due to decreased trading-related deposits resulting from normal trading activities.  The $27 million outflow from Fuel Over/Under Recovery, Net is due to under recovery of higher fuel costs.

Investing Activities

Net Cash Flows Used for Investing Activities during 2008 and 2007 were $569$619 million and $253$353 million, respectively.  Construction Expenditures of $266$424 million and $250$353 million in 2008 and 2007, respectively, were primarily related to new generation projects at the Turk Plant, Mattison Plant and Stall Unit.  In addition, during 2008, SWEPCo had a net increase of $301$196 million in loans to the Utility Money Pool.  For the remainder of 2008, SWEPCo expects construction expenditures to be approximately $350$250 million.

Financing Activities

Net Cash Flows from Financing Activities were $495$490 million during 2008.  SWEPCo issued $400 million of Senior Unsecured Notes.  SWEPCo received a capital contributionCapital Contribution from Parent of $100 million.  SWEPCo retired $46 million of Nonaffiliated Long-term Debt.

Net Cash Flows from Financing Activities were $132$172 million during 2007.  SWEPCo issued $250 million of Senior Unsecured Notes and hadretired $90 million of First Mortgage Bonds.  SWEPCo received a net decreaseCapital Contribution from Parent of $135 million in$55 million.  SWEPCo also reduced its borrowings from the Utility Money Pool.  SWEPCo received a capital contribution from Parent of $25Pool by $33 million.

Financing Activity

Long-term debt issuances, retirements and principal payments made during the first sixnine months of 2008 were:

Issuances
 
Principal
Amount
 Interest Due 
Principal
Amount
 Interest Due
Type of Debt  Rate Date Rate Date
  (in thousands) (%)   (in thousands) (%)  
Senior Unsecured Notes $400,000 6.45 2019 $400,000  6.45 2019
Pollution Control Bonds  41,135  4.50 2011

Retirements and Principal Payments
  
Principal
Amount Paid
 Interest Due
Type of Debt  Rate Date
  (in thousands) (%)  
Notes Payable – Nonaffiliated $1,500  Variable 2008
Notes Payable – Nonaffiliated  3,304  4.47 2011
Pollution Control Bonds  41,135  Variable 2011

  
Principal
Amount Paid
 Interest Due
Type of Debt  Rate Date
   (in thousands) (%)  
Notes Payable – Nonaffiliated $2,203 4.47 2011
Notes Payable – Nonaffiliated  1,500 Variable 2008
In October 2008, SWEPCo retired $113 million of 5.25% Notes Payable due in 2043.

Liquidity

SWEPCo has solid investment grade ratings, which provide readyIn recent months, the financial markets have become increasingly unstable and constrained at both a global and domestic level.  This systemic marketplace distress is impacting SWEPCo’s access to capital, liquidity and cost of capital.  The uncertainties in the credit markets in ordercould have significant implications on SWEPCo since it relies on continuing access to issue new debt or refinance long-term debt maturities.  In addition, capital to fund operations and capital expenditures.

SWEPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.  SWEPCo has no debt obligations that will mature in the remainder of 2008 or 2009.  To the extent refinancing is unavailable due to the challenging credit markets, SWEPCo will rely upon cash flows from operations and access to the Utility Money Pool to fund its current operations.

Summary Obligation Information

A summary of contractual obligations is included in the 2007 Annual Report and has not changed significantly from year-end other than the debt issuance discussed in “Cash Flow” and “Financing Activity” above.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, SWEPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be.  Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases which have a probable likelihood of loss and the loss amount 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 2007 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section..  Adverse results in these proceedings have the potential to materially affect results of operations,net income, financial condition and cash flows.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of relevant factors.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2007 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.

 
 
 

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Risk management assets and liabilities are managed by AEPSC as agent.  The related risk management policies and procedures are instituted and administered by AEPSC.  See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section.  The following tables provide information about AEP’s risk management activities’ effect on SWEPCo.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in SWEPCo’s Condensed Consolidated Balance Sheet as of JuneSeptember 30, 2008 and the reasons for changes in total MTM value as compared to December 31, 2007.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of JuneSeptember 30, 2008
(in thousands)

 MTM Risk Management Contracts  
Cash Flow
&
Fair Value Hedges
  DETM Assignment (a)  
 
Collateral
Deposits
  Total  MTM Risk Management Contracts  
Cash Flow &
Fair Value Hedges
  DETM Assignment (a)  
 
Collateral
Deposits
  Total 
Current Assets $108,564  $-  $-  $(2,014) $106,550  $30,804  $-  $-  $(528) $30,276 
Noncurrent Assets  15,872   71   -   (46)  15,897   3,561   -   -   (60)  3,501 
Total MTM Derivative Contract Assets  124,436   71   -   (2,060)  122,447   34,365   -   -   (588)  33,777 
                                        
Current Liabilities  (106,167)  (4)  (110)  3,144   (103,137)  (31,197)  (90)  (130)  60   (31,357)
Noncurrent Liabilities  (14,030)  -   (120)  1,252   (12,898)  (2,406)  (93)  (132)  9   (2,622)
Total MTM Derivative Contract Liabilities  (120,197)  (4)  (230)  4,396   (116,035)  (33,603)  (183)  (262)  69   (33,979)
                                        
Total MTM Derivative Contract Net Assets (Liabilities) $4,239  $67  $(230) $2,336  $6,412  $762  $(183) $(262) $(519) $(202)

(a)See “Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual Report.

MTM Risk Management Contract Net Assets (Liabilities)
SixNine Months Ended JuneSeptember 30, 2008
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2007 $8,131  $8,131 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period (4,779)  (8,169)
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 -   - 
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b) 418   103 
Changes in Fair Value Due to Market Fluctuations During the Period (c) (258)  106 
Changes in Fair Value Allocated to Regulated Jurisdictions (d)  727   591 
Total MTM Risk Management Contract Net Assets 4,239   762 
Net Cash Flow & Fair Value Hedge Contracts 67   (183)
DETM Assignment (e) (230)  (262)
Collateral Deposits  2,336   (519)
Ending Net Risk Management Assets at June 30, 2008 $6,412 
Ending Net Risk Management Assets (Liabilities) at September 30, 2008 $(202)

(a)Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term.  The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)Represents the impact of applying AEP’s credit risk when measuring the fair value of derivative liabilities according to SFAS 157.
(c)Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(d)“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income.  These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.liabilities.
(e)See “Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual Report.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The following table presents the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash:

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of JuneSeptember 30, 2008
(in thousands)

 
Remainder
2008
  2009  2010  2011  2012  
After
2012
  Total  
Remainder
2008
  2009  2010  2011  2012  
After
2012
  Total 
Level 1 (a) $1,376  $(277) $-  $-  $-  $-  $1,099  $372  $(294) $-  $-  $-  $-  $78 
Level 2 (b)  366   3,072   (237)  (16)  -   -   3,185   10   1,467   757   (122)  -   -   2,112 
Level 3 (c)  (47)  -   2   -   -   -   (45)  (1,429)  -   1   -   -   -   (1,428)
Total $1,695  $2,795  $(235) $(16) $-  $-  $4,239  $(1,047) $1,173  $758  $(122) $-  $-  $762 

(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.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed Consolidated Balance Sheet

Management uses interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt.  Management does not hedge all interest rate risk.

Management uses foreign currency derivatives to lock in prices on certain forecasted transactions denominated in foreign currencies where deemed necessary, and designates qualifying instruments as cash flow hedges.  Management does not hedge all foreign currency exposure.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on SWEPCo’s Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2007 to JuneSeptember 30, 2008.  Only contracts designated as cash flow hedges are recorded in AOCI.  Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables.  All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
SixNine Months Ended JuneSeptember 30, 2008
(in thousands)

 Interest Rate  
Foreign
Currency
  Total  Interest Rate  
Foreign
Currency
  Total 
Beginning Balance in AOCI December 31, 2007 $(6,650) $629  $(6,021) $(6,650) $629  $(6,021)
Changes in Fair Value  -   120   120   -   (204)  (204)
Reclassifications from AOCI for Cash Flow Hedges Settled
  413   (705)  (292)  621   (544)  77 
Ending Balance in AOCI June 30, 2008 $(6,237) $44  $(6,193)
Ending Balance in AOCI September 30, 2008 $(6,029) $(119) $(6,148)

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is an $829 thousand loss.

Credit Risk

Counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates Value at Risk (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 JuneSeptember 30, 2008, a near term typical change in commodity prices is not expected to have a material effect on SWEPCo’s results of operations,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 periods indicated:

Six Months Ended
June 30, 2008
 
Twelve Months Ended
December 31, 2007
Nine Months Ended
September 30, 2008
Nine Months Ended
September 30, 2008
 
Twelve Months Ended
December 31, 2007
(in thousands)(in thousands) (in thousands)(in thousands) (in thousands)
End High Average Low End High Average Low High Average Low End High Average Low
$62 $163 $54 $11 $17 $245 $75 $7
$101 $220 $64 $11 $17 $245 $75 $7

Management back-tests its VaR results against performance due to actual price moves.  Based on the assumed 95% confidence interval, the performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days.  Management’s backtesting results show that its actual performance exceeded VaR far fewer than once every 20 trading days.  As a result, management believes SWEPCo’s VaR calculation is conservative.

As SWEPCo’s VaR calculation captures recent price moves, management also performs regular stress testing of the portfolio to understand SWEPCo’s exposure to extreme price moves.  Management employs a historically-based method whereby the current portfolio is subjected to actual, observed price moves from the last three years in order to ascertain which historical price moves translate into the largest potential mark-to-market loss.  Management then researches the underlying positions, price moves and market events that created the most significant exposure.

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 SWEPCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  The estimated EaR on SWEPCo’s debt portfolio was $2$1.9 million.

 
 
 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in thousands)
(Unaudited)

 Three Months Ended  Six Months Ended  Three Months Ended  Nine Months Ended 
 2008  2007  2008  2007  2008  2007  2008  2007 
REVENUES                        
Electric Generation, Transmission and Distribution $405,632  $329,250  $731,533  $656,534  $500,484  $445,169  $1,232,017  $1,101,703 
Sales to AEP Affiliates  17,592   16,237   31,184   32,652   11,508   2,839   42,692   35,491 
Other  393   535   693   935   471   502   1,164   1,437 
TOTAL  423,617   346,022   763,410   690,121   512,463   448,510   1,275,873   1,138,631 
                                
EXPENSES                                
Fuel and Other Consumables Used for Electric Generation  147,147   125,994   264,808   237,981   197,474   141,837   462,282   379,818 
Purchased Electricity for Resale  54,378   56,870   94,648   109,368   50,449   73,438   145,097   182,806 
Purchased Electricity from AEP Affiliates  51,932   16,085   72,372   39,002   36,170   22,282   108,542   61,284 
Other Operation  58,757   50,204   122,336   103,987   64,377   59,759   186,713   163,746 
Maintenance  27,692   29,721   55,160   56,060   33,694   23,205   88,854   79,265 
Depreciation and Amortization  36,897   34,668   73,033   68,790   35,842   34,605   108,875   103,395 
Taxes Other Than Income Taxes  15,705   17,540   33,124   33,531   12,623   16,767   45,747   50,298 
TOTAL  392,508   331,082   715,481   648,719   430,629   371,893   1,146,110   1,020,612 
                                
OPERATING INCOME  31,109   14,940   47,929   41,402   81,834   76,617   129,763   118,019 
                                
Other Income (Expense):                                
Interest Income  1,540   776   2,417   1,481   5,417   518   7,834   1,999 
Allowance for Equity Funds Used During Construction  2,952   2,562   6,015   3,953   4,152   3,681   10,167   7,634 
Interest Expense  (17,270)  (17,235)  (34,412)  (32,725)  (22,659)  (15,966)  (57,071)  (48,691)
                                
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND MINORITY INTEREST EXPENSE  18,331   1,043   21,949   14,111 
INCOME BEFORE INCOME TAX EXPENSE AND MINORITY INTEREST EXPENSE  68,744   64,850   90,693   78,961 
                                
Income Tax Expense (Credit)  3,351   (1,553)  1,364   1,068 
Income Tax Expense  20,353   19,811   21,717   20,879 
Minority Interest Expense  899   972   1,894   1,814   976   919   2,870   2,733 
                                
NET INCOME  14,081   1,624   18,691   11,229   47,415   44,120   66,106   55,349 
                                
Preferred Stock Dividend Requirements  57   57   114   114   58   58   172   172 
                                
EARNINGS APPLICABLE TO COMMON STOCK $14,024  $1,567  $18,577  $11,115  $47,357  $44,062  $65,934  $55,177 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in thousands)
(Unaudited)

 Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total  Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
DECEMBER 31, 2006 $135,660  $245,003  $459,338  $(18,799) $821,202  $135,660  $245,003  $459,338  $(18,799) $821,202 
                                        
FIN 48 Adoption, Net of Tax          (1,642)      (1,642)          (1,642)      (1,642)
Capital Contribution from Parent      25,000           25,000       55,000           55,000 
Preferred Stock Dividends          (114)      (114)          (172)      (172)
TOTAL                  844,446                   874,388 
                                        
COMPREHENSIVE INCOME                                        
Other Comprehensive Loss, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $172              (79)  (79)
Other Comprehensive Income, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $90              168   168 
NET INCOME          11,229       11,229           55,349       55,349 
TOTAL COMPREHENSIVE INCOME                  11,150                   55,517 
                                        
JUNE 30, 2007 $135,660  $270,003  $468,811  $(18,878) $855,596 
SEPTEMBER 30, 2007 $135,660  $300,003  $512,873  $(18,631) $929,905 
                                        
DECEMBER 31, 2007 $135,660  $330,003  $523,731  $(16,439) $972,955  $135,660  $330,003  $523,731  $(16,439) $972,955 
                                        
EITF 06-10 Adoption, Net of Tax of $622          (1,156)      (1,156)          (1,156)      (1,156)
SFAS 157 Adoption, Net of Tax of $6          10       10           10       10 
Capital Contribution from Parent      100,000           100,000       100,000           100,000 
Preferred Stock Dividends          (114)      (114)          (172)      (172)
TOTAL                  1,071,695                   1,071,637 
                                        
COMPREHENSIVE INCOME                                        
Other Comprehensive Income (Loss), Net of Taxes:                                        
Cash Flow Hedges, Net of Tax of $92              (172)  (172)
Amortization of Pension and OPEB Deferred
Costs, Net of Tax of $253
              471   471 
Cash Flow Hedges, Net of Tax of $69              (127)  (127)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $380              706   706 
NET INCOME          18,691       18,691           66,106       66,106 
TOTAL COMPREHENSIVE INCOME                  18,990                   66,685 
                                        
JUNE 30, 2008 $135,660  $430,003  $541,162  $(16,140) $1,090,685 
SEPTEMBER 30, 2008 $135,660  $430,003  $588,519  $(15,860) $1,138,322 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

 
 
 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
JuneSeptember 30, 2008 and December 31, 2007
(in thousands)
(Unaudited)

 2008  2007  2008  2007 
CURRENT ASSETS            
Cash and Cash Equivalents $2,242  $1,742  $2,752  $1,742 
Advances to Affiliates  300,525   -   195,628   - 
Accounts Receivable:                
Customers  64,754   91,379   32,619   91,379 
Affiliated Companies  25,663   33,196   42,876   33,196 
Miscellaneous  12,723   10,544   12,781   10,544 
Allowance for Uncollectible Accounts  (139)  (143)   (135)  (143)
Total Accounts Receivable  103,001   134,976   88,141   134,976 
Fuel  87,705   75,662   89,408   75,662 
Materials and Supplies  51,581   48,673   51,565   48,673 
Risk Management Assets  106,550   39,850   30,276   39,850 
Regulatory Asset for Under-Recovered Fuel Costs  67,186   5,859   81,907   5,859 
Margin Deposits  1,319   10,650   600   10,650 
Prepayments and Other  70,233   28,147   38,406   28,147 
TOTAL  790,342   345,559   578,683   345,559 
                
PROPERTY, PLANT AND EQUIPMENT                
Electric:                
Production  1,751,081   1,743,198   1,756,486   1,743,198 
Transmission  770,560   737,975   771,747   737,975 
Distribution  1,351,982   1,312,746   1,364,596   1,312,746 
Other  642,255   631,765   698,764   631,765 
Construction Work in Progress  632,514   451,228   735,226   451,228 
Total  5,148,392   4,876,912   5,326,819   4,876,912 
Accumulated Depreciation and Amortization  1,964,954   1,939,044   1,996,531   1,939,044 
TOTAL - NET  3,183,438   2,937,868   3,330,288   2,937,868 
                
OTHER NONCURRENT ASSETS                
Regulatory Assets  118,139   133,617   120,858   133,617 
Long-term Risk Management Assets  15,897   4,073   3,501   4,073 
Deferred Charges and Other  107,440   67,269   93,126   67,269 
TOTAL  241,476   204,959   217,485   204,959 
                
TOTAL ASSETS $4,215,256  $3,488,386  $4,126,456  $3,488,386 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

 
 
 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
JuneSeptember 30, 2008 and December 31, 2007
(Unaudited)

 2008  2007  2008  2007 
CURRENT LIABILITIES (in thousands)  (in thousands) 
Advances from Affiliates $-  $1,565  $-  $1,565 
Accounts Payable:                
General  183,533   152,305   163,540   152,305 
Affiliated Companies  89,863   51,767   41,010   51,767 
Short-term Debt – Nonaffiliated  7,039   285   9,519   285 
Long-term Debt Due Within One Year – Nonaffiliated  4,406   5,906   117,809   5,906 
Risk Management Liabilities  103,137   32,629   31,357   32,629 
Customer Deposits  36,729   37,473   34,989   37,473 
Accrued Taxes  49,529   26,494   60,052   26,494 
Regulatory Liability for Over-Recovered Fuel Costs  -   22,879   -   22,879 
Other  91,895   76,554   94,559   76,554 
TOTAL  566,131   407,857   552,835   407,857 
                
NONCURRENT LIABILITIES                
Long-term Debt – Nonaffiliated  1,538,795   1,141,311   1,424,395   1,141,311 
Long-term Debt – Affiliated  50,000   50,000   50,000   50,000 
Long-term Risk Management Liabilities  12,898   3,334   2,622   3,334 
Deferred Income Taxes  397,158   361,806   407,149   361,806 
Regulatory Liabilities and Deferred Investment Tax Credits  340,563   334,014   331,985   334,014 
Deferred Credits and Other  212,656   210,725   214,153   210,725 
TOTAL  2,552,070   2,101,190   2,430,304   2,101,190 
                
TOTAL LIABILITIES  3,118,201   2,509,047   2,983,139   2,509,047 
                
Minority Interest  1,673   1,687   298   1,687 
                
Cumulative Preferred Stock Not Subject to Mandatory Redemption  4,697   4,697   4,697   4,697 
                
Commitments and Contingencies (Note 4)                
                
COMMON SHAREHOLDER’S EQUITY                
Common Stock – Par Value – $18 Per Share:                
Authorized – 7,600,000 Shares                
Outstanding – 7,536,640 Shares  135,660   135,660   135,660   135,660 
Paid-in Capital  430,003   330,003   430,003   330,003 
Retained Earnings  541,162   523,731   588,519   523,731 
Accumulated Other Comprehensive Income (Loss)  (16,140)  (16,439)  (15,860)  (16,439)
TOTAL  1,090,685   972,955   1,138,322   972,955 
                
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $4,215,256  $3,488,386  $4,126,456  $3,488,386 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

 
 
 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the SixNine Months Ended JuneSeptember 30, 2008 and 2007
(in thousands)
(Unaudited)

 2008  2007  2008  2007 
OPERATING ACTIVITIES            
Net Income $18,691  $11,229  $66,106  $55,349 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:                
Depreciation and Amortization  73,033   68,790   108,875   103,395 
Deferred Income Taxes  28,256   (21,658)   37,162   (17,863)
Provision for Fuel Disallowance  -   24,500   -   24,074 
Allowance for Equity Funds Used During Construction  (6,015)  (3,953)   (10,167)  (7,634)
Mark-to-Market of Risk Management Contracts  1,541   5,190   7,905   7,864 
Deferred Property Taxes  (19,866)  (19,210)   (9,315)  (9,172)
Change in Other Noncurrent Assets  3,434   3,846   9,104   10,170 
Change in Other Noncurrent Liabilities  (17,106)  (7,932)   (17,015)  (7,134)
Changes in Certain Components of Working Capital:                
Accounts Receivable, Net  31,975   26,897   46,835   47,992 
Fuel, Materials and Supplies  (14,978)  (11,126)   (16,665)  (11,572)
Margin Deposits  10,050   29,986 
Accounts Payable  60,552   8,388   (34,819)  (21,603)
Accrued Taxes, Net  (12,503)  36,445   29,271   25,556 
Fuel Over/Under-Recovery, Net  (84,206)  1,293   (98,928)  (26,891)
Other Current Assets  7,296   12,928   (3,121)  (687)
Other Current Liabilities  4,518   (15,030)   4,972   (21,684)
Net Cash Flows from Operating Activities  74,622   120,597   130,250   180,146 
                
INVESTING ACTIVITIES                
Construction Expenditures  (266,145)  (250,409)   (424,092)  (353,107)
Change in Advances to Affiliates, Net  (300,525)  -   (195,628)  - 
Other  (2,439)  (2,858)   233   106 
Net Cash Flows Used for Investing Activities  (569,109)  (253,267)   (619,487)  (353,001)
                
FINANCING ACTIVITIES                
Capital Contribution from Parent  100,000   25,000   100,000   55,000 
Issuance of Long-term Debt – Nonaffiliated  396,446   247,496   437,113   247,496 
Change in Short-term Debt, Net – Nonaffiliated  6,754   5,230   9,234   8,754 
Change in Advances from Affiliates, Net  (1,565)  (135,010)   (1,565)  (33,096)
Retirement of Long-term Debt – Nonaffiliated  (3,703)  (8,609)   (45,939)  (100,460)
Principal Payments for Capital Lease Obligations  (2,831)  (2,383)   (8,424)  (5,433)
Dividends Paid on Cumulative Preferred Stock  (114)  (114)   (172)  (172)
Net Cash Flows from Financing Activities  494,987   131,610   490,247   172,089 
                
Net Increase (Decrease) in Cash and Cash Equivalents  500   (1,060)   1,010   (766)
Cash and Cash Equivalents at Beginning of Period  1,742   2,618   1,742   2,618 
Cash and Cash Equivalents at End of Period $2,242  $1,558  $2,752  $1,852 
                
SUPPLEMENTARY INFORMATION                
Cash Paid for Interest, Net of Capitalized Amounts $19,848  $25,876  $44,255  $44,662 
Net Cash Paid for Income Taxes  10,276   10,617 
Net Cash Paid (Received) for Income Taxes  (20,835)  37,479 
Noncash Acquisitions Under Capital Leases  17,236   6,511   21,807   19,567 
Construction Expenditures Included in Accounts Payable at June 30,  68,670   38,630 
Construction Expenditures Included in Accounts Payable at September 30,  94,837   41,978 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

 
 
 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

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

 Footnote Reference
  
Significant Accounting MattersNote 1
New Accounting Pronouncements and Extraordinary ItemNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
Benefit PlansNote 6
Business SegmentsNote 7
Income TaxesNote 8
Financing ActivitiesNote 9

 
 
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 MattersAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
2.New Accounting Pronouncements and Extraordinary ItemAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
3.Rate MattersAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
4.Commitments, Guarantees and ContingenciesAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
5.AcquisitionCSPCo
6.Benefit PlansAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
7.Business SegmentsAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
8.Income TaxesAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
9.Financing ActivitiesAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo

 
 
 

1.SIGNIFICANT ACCOUNTING MATTERS

General

The accompanying 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 the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations,net income, financial position and cash flows for the interim periods for each Registrant Subsidiary.  The results of operationsnet income for the three and sixnine months ended JuneSeptember 30, 2008 are not necessarily indicative of results that may be expected for the year ending December 31, 2008.  The accompanying condensed financial statements are unaudited and should be read in conjunction with the audited 2007 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2007 as filed with the SEC on February 28, 2008.

Reclassifications

Certain prior period financial statement items have been reclassified to conform to current period presentation.  See “FSP FIN 39-1 Amendment of FASB Interpretation No. 39” section of Note 2 for discussion of changes in netting certain balance sheet amounts.  These revisionsreclassifications had no impact on the Registrant Subsidiaries’ previously reported results of operationsnet income or changes in shareholders’ equity.

2.  NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM

NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of final pronouncements, management thoroughly reviews the new accounting literature to determine the relevance, if any, to the Registrant Subsidiaries’ business.  The following represents a summary of new pronouncements issued or implemented in 2008 and standards issued but not implemented that management has determined relate to the Registrant Subsidiaries’ operations.

SFAS 141 (revised 2007) “Business Combinations” (SFAS 141R)

In December 2007, the FASB issued SFAS 141R, improving financial reporting about business combinations and their effects.  It establishes how the acquiring entity recognizes and measures the identifiable assets acquired, liabilities assumed, goodwill acquired, any gain on bargain purchases and any noncontrolling interest in the acquired entity.  SFAS 141R no longer allows acquisition-related costs to be included in the cost of the business combination, but rather expensed in the periods they are incurred, with the exception of the costs to issue debt or equity securities which shall be recognized in accordance with other applicable GAAP.  SFAS 141R requires disclosure of information for a business combination that occurs during the accounting period or prior to the issuance of the financial statements for the accounting period.

SFAS 141R is effective prospectively for business combinations with an acquisition date on or after the beginning of the first annual reporting period after December 15, 2008.  Early adoption is prohibited.  The Registrant Subsidiaries will adopt SFAS 141R effective January 1, 2009 and apply it to any business combinations on or after that date.

SFAS 157 “Fair Value Measurements” (SFAS 157)

In September 2006, the FASB issued SFAS 157, enhancing existing guidance for fair value measurement of assets and liabilities and instruments measured at fair value that are classified in shareholders’ equity.  The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures.  It emphasizes that fair value is market-based with the highest measurement hierarchy level being market prices in active markets.  The standard requires fair value measurements be disclosed by hierarchy level, an entity includes its own credit standing in the measurement of its liabilities and modifies the transaction price presumption.  The standard also nullifies the consensus reached in EITF Issue No. 02-3 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3) that prohibited the recognition of trading gains or losses at the inception of a derivative contract, unless the fair value of such derivative is supported by observable market data.

In February 2008, the FASB issued FSP SFAS 157-1 “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” (SFAS 157-1) which amends SFAS 157 to exclude SFAS 13 “Accounting for Leases” (SFAS 13) and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under SFAS 13.

In February 2008, the FASB issued FSP SFAS 157-2 “Effective Date of FASB Statement No. 157” (SFAS 157-2) which delays the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).

In October 2008, the FASB issued FSP SFAS 157-3 “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active” which clarifies application of SFAS 157 in markets that are not active and provides an illustrative example.  The FSP was effective upon issuance.  The adoption of this standard had no impact on the Registrant Subsidiaries’ financial statements.

The Registrant Subsidiaries partially adopted SFAS 157 effective January 1, 2008.  The Registrant Subsidiaries will fully adopt SFAS 157 effective January 1, 2009 for items within the scope of FSP SFAS 157-2.  Management expects that the adoption of FSP SFAS 157-2 will have an immaterial impact on the financial statements.  The provisions of SFAS 157 are applied prospectively, except for a) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF 02-3, b) existing hybrid financial instruments measured initially at fair value using the transaction price and c) blockage discount factors.  Although the statement is applied prospectively upon adoption, in accordance with the provisions of SFAS 157 related to EITF 02-3, APCo, CSPCo and OPCo reduced beginning retained earnings by $440 thousand ($286 thousand, net of tax), $486 thousand ($316 thousand, net of tax) and $434 thousand ($282 thousand, net of tax), respectively, for the transition adjustment.  SWEPCo’s transition adjustment was a favorable $16 thousand ($10 thousand, net of tax) adjustment to beginning retained earnings.  The impact of considering AEP’s credit risk when measuring the fair value of liabilities, including derivatives, had an immaterial impact on fair value measurements upon adoption.

In accordance with SFAS 157, assets and liabilities are classified based on the inputs utilized in the fair value measurement.  SFAS 157 provides definitions for two types of inputs: observable and unobservable.  Observable inputs are valuation inputs that reflect the assumptions market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the reporting entity.  Unobservable inputs are valuation inputs that reflect the reporting entity’s own assumptions about the assumptions market participants would use in pricing the asset or liability developed based on the best information in the circumstances.

As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).  SFAS 157 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).

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, listed equities and U.S. government treasury securities that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.

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, OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market and certain non-exchange-traded debt securities.

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.

Risk Management Contracts include exchange traded, OTC and bilaterally executed derivative contracts.  Exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified within level 1.  Other actively traded derivativesderivative fair values are valuedverified using broker or dealer quotations, similar observable market transactions in either the listed or OTC markets, or throughvalued using pricing models  where significant valuation inputs are directly or indirectly observable in active markets.  Derivative instruments, primarily swaps, forwards, and options that meet these characteristics are classified within level 2.  Bilaterally executed agreements are derivative contracts entered into directly with third parties, and at times these instruments may be complex structured transactions that are tailored to meet the specific customer’s energy requirements.  Structured transactions utilize pricing models that are widely accepted in the energy industry to measure fair value.  Generally, management uses a consistent modeling approach to value similar instruments.  Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data), and other observable inputs for the asset or liability.  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in level 2.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  In addition, long-dated and illiquid complex or structured transactions 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 in level 3.  In certain instances, the fair values of the transactions that use internally developed model inputs, classified as level 3 are offset partially or in full, by transactions included in level 2 where observable market data exists for the offsetting transaction.

The following table sets 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 JuneSeptember 30, 2008.  As required by SFAS 157, 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.

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of JuneSeptember 30, 2008

APCo                              
 Level 1  Level 2  Level 3  Other  Total  Level 1  Level 2  Level 3  Other  Total 
Assets: (in thousands)  (in thousands) 
                              
Risk Management Assets:                              
Risk Management Contracts (a) $35,609  $1,261,131  $10,761  $(1,012,957) $294,544  $7,275  $553,289  $5,005  $(447,811) $117,758 
Cash Flow and Fair Value Hedges (a)  -   9,201   -   (4,967)  4,234   -   10,120   -   (4,980)  5,140 
Dedesignated Risk Management Contracts (b)  -   -   -   14,916   14,916   -   -   -   14,259   14,259 
Total Risk Management Assets $35,609  $1,270,332  $10,761  $(1,003,008) $313,694  $7,275  $563,409  $5,005  $(438,532) $137,157 
                                        
Liabilities:                                        
                                        
Risk Management Liabilities:                                        
Risk Management Contracts (a) $37,928  $1,226,686  $29,321  $(1,008,877) $285,058  $10,589  $518,486  $9,646  $(440,158) $98,563 
Cash Flow and Fair Value Hedges (a)  -   34,986   -   (4,967)  30,019   -   7,976   -   (4,980)  2,996 
DETM Assignment (c)  -   -   -   7,116   7,116   -   -   -   6,321   6,321 
Total Risk Management Liabilities $37,928  $1,261,672  $29,321  $(1,006,728) $322,193  $10,589  $526,462  $9,646  $(438,817) $107,880 

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of JuneSeptember 30, 2008

CSPCo                              
 Level 1  Level 2  Level 3  Other  Total  Level 1  Level 2  Level 3  Other  Total 
Assets: (in thousands)  (in thousands) 
                              
Other Cash Deposits (e) $35,806  $-  $-  $1,169  $36,975  $31,002  $-  $-  $962  $31,964 
                                        
Risk Management Assets:                                        
Risk Management Contracts (a) $21,385  $692,082  $6,467  $(557,082) $162,852  $4,083  $286,118  $2,811  $(232,301) $60,711 
Cash Flow and Fair Value Hedges (a)  -   4,503   -   (2,983)  1,520   -   5,189   -   (2,795)  2,394 
Dedesignated Risk Management Contracts (b)  -   -   -   8,958   8,958   -   -   -   8,005   8,005 
Total Risk Management Assets $21,385  $696,585  $6,467  $(551,107) $173,330  $4,083  $291,307  $2,811  $(227,091) $71,110 
                                        
Total Assets $57,191  $696,585  $6,467  $(549,938) $210,305  $35,085  $291,307  $2,811  $(226,129) $103,074 
                                        
Liabilities:                                        
                                        
Risk Management Liabilities:                                        
Risk Management Contracts (a) $22,778  $671,311  $17,589  $(553,617) $158,061  $5,945  $266,791  $5,406  $(227,981) $50,161 
Cash Flow and Fair Value Hedges (b)  -   21,011   -   (2,983)  18,028 
Cash Flow and Fair Value Hedges (a)  -   4,477   -   (2,795)  1,682 
DETM Assignment (c)  -   -   -   4,274   4,274   -   -   -   3,549   3,549 
Total Risk Management Liabilities $22,778  $692,322  $17,589  $(552,326) $180,363  $5,945  $271,268  $5,406  $(227,227) $55,392 

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of JuneSeptember 30, 2008

I&M                              
 Level 1  Level 2  Level 3  Other  Total  Level 1  Level 2  Level 3  Other  Total 
Assets: (in thousands)  (in thousands) 
                              
Risk Management Assets:                              
Risk Management Contracts (a) $20,545  $643,285  $6,215  $(516,431) $153,614  $3,952  $283,053  $2,721  $(230,057) $59,669 
Cash Flow and Fair Value Hedges (a)  -   4,326   -   (2,866)  1,460   -   5,022   -   (2,705)  2,317 
Dedesignated Risk Management Contracts (b)  -   -   -   8,606   8,606   -   -   -   7,747   7,747 
Total Risk Management Assets $20,545  $647,611  $6,215  $(510,691) $163,680  $3,952  $288,075  $2,721  $(225,015) $69,733 
                                        
Spent Nuclear Fuel and Decommissioning Trusts:                                        
Cash and Cash Equivalents (d) $-  $16,728  $-  $12,246  $28,974  $-  $3,523  $-  $6,328  $9,851 
Debt Securities(f)  326,416   507,611   -   -   834,027   -   837,141   -   -   837,141 
Equity Securities(g)  498,926   -   -   -   498,926   444,994   -   -   -   444,994 
Total Spent Nuclear Fuel and Decommissioning Trusts $825,342  $524,339  $-  $12,246  $1,361,927  $444,994  $840,664  $-  $6,328  $1,291,986 
                                        
Total Assets $845,887  $1,171,950  $6,215  $(498,445) $1,525,607  $448,946  $1,128,739  $2,721  $(218,687) $1,361,719 
                                        
Liabilities:                                        
                                        
Risk Management Liabilities:                                        
Risk Management Contracts (a) $21,883  $623,352  $16,890  $(512,683) $149,442  $5,754  $264,220  $5,234  $(225,884) $49,324 
Cash Flow and Fair Value Hedges (a)  -   20,186   -   (2,866)  17,320   -   4,333   -   (2,705)  1,628 
DETM Assignment (c)  -   -   -   4,107   4,107   -   -   -   3,435   3,435 
Total Risk Management Liabilities $21,883  $643,538  $16,890  $(511,442) $170,869  $5,754  $268,553  $5,234  $(225,154) $54,387 

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of JuneSeptember 30, 2008

OPCo            ��                 
 Level 1  Level 2  Level 3  Other  Total  Level 1  Level 2  Level 3  Other  Total 
Assets: (in thousands)  (in thousands) 
                              
Other Cash Deposits (e) $3,216  $-  $-  $2,182  $5,398  $3,116  $-  $-  $2,164  $5,280 
                                        
Risk Management Assets:                                        
Risk Management Contracts (a) $24,915  $1,255,573  $7,493  $(1,038,518) $249,463  $5,059  $582,635  $3,476  $(481,108) $110,062 
Cash Flow and Fair Value Hedges (a)  -   5,259   -   (3,475)  1,784   -   6,428   -   (3,463)  2,965 
Dedesignated Risk Management Contracts (b)  -   -   -   10,436   10,436   -   -   -   9,917   9,917 
Total Risk Management Assets $24,915  $1,260,832  $7,493  $(1,031,557) $261,683  $5,059  $589,063  $3,476  $(474,654) $122,944 
                                        
Total Assets $28,131  $1,260,832  $7,493  $(1,029,375) $267,081  $8,175  $589,063  $3,476  $(472,490) $128,224 
                                        
Liabilities:                                        
                                        
Risk Management Liabilities:                                        
Risk Management Contracts (a) $26,538  $1,230,208  $20,738  $(1,043,217) $234,267  $7,365  $552,724  $6,809  $(476,017) $90,881 
Cash Flow and Fair Value Hedges (a)  -   27,153   -   (3,475)  23,678   -   6,633   -   (3,463)  3,170 
DETM Assignment (c)  -   -   -   4,979   4,979   -   -   -   4,396   4,396 
Total Risk Management Liabilities $26,538  $1,257,361  $20,738  $(1,041,713) $262,924  $7,365  $559,357  $6,809  $(475,084) $98,447 

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of JuneSeptember 30, 2008

PSO                              
 Level 1  Level 2  Level 3  Other  Total  Level 1  Level 2  Level 3  Other  Total 
Assets: (in thousands)  (in thousands) 
                              
Risk Management Assets:                              
Risk Management Contracts (a) $52,111  $562,955  $7  $(515,708) $99,365  $3,743  $141,674  $3,803  $(121,851) $27,369 
Cash Flow and Fair Value Hedges (a)  -   -   -   -   -   -   -   -   -   - 
Total Risk Management Assets $52,111  $562,955  $7  $(515,708) $99,365  $3,743  $141,674  $3,803  $(121,851) $27,369 
                                        
Liabilities:                                        
                                        
Risk Management Liabilities:                                        
Risk Management Contracts (a) $51,180  $560,473  $30  $(517,065) $94,618  $3,677  $140,064  $5,010  $(121,399) $27,352 
Cash Flow and Fair Value Hedges (a)  -   -   -   -   -   -   -   -   -   - 
DETM Assignment (c)  -   -   -   195   195   -   -   -   222   222 
Total Risk Management Liabilities $51,180  $560,473  $30  $(516,870) $94,813  $3,677  $140,064  $5,010  $(121,177) $27,574 

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of JuneSeptember 30, 2008

SWEPCo                              
 Level 1  Level 2  Level 3  Other  Total  Level 1  Level 2  Level 3  Other  Total 
Assets: (in thousands)  (in thousands) 
                              
Risk Management Assets:                              
Risk Management Contracts (a) $61,460  $701,896  $5  $(640,985) $122,376  $4,412  $177,218  $4,481  $(152,334) $33,777 
Cash Flow and Fair Value Hedges (a)  -   80   -   (9)  71   -   44   -   (44)  - 
Total Risk Management Assets $61,460  $701,976  $5  $(640,994) $122,447  $4,412  $177,262  $4,481  $(152,378) $33,777 
                                        
Liabilities:                                        
                                        
Risk Management Liabilities:                                        
Risk Management Contracts (a) $60,361  $698,711  $50  $(643,321) $115,801  $4,334  $175,106  $5,909  $(151,815) $33,534 
Cash Flow and Fair Value Hedges (a)  -   13   -   (9)  4   -   227   -   (44)  183 
DETM Assignment (c)  -   -   -   230   230   -   -   -   262   262 
Total Risk Management Liabilities $60,361  $698,724  $50  $(643,100) $116,035  $4,334  $175,333  $5,909  $(151,597) $33,979 

(a)Amounts in “Other” column primarily represent counterparty netting of risk management contracts and associated cash collateral under FSP FIN 39-1.
(b)“Dedesignated Risk Management Contracts” are contracts that were originally MTM but were subsequently elected as normal under SFAS 133.  At the time of the normal election the MTM value was frozen and no longer fair valued.  This will be amortized into Utility Operations Revenues over the remaining life of the contract.
(c)See “Natural Gas Contracts with DETM” section of Note 16 in the 2007 Annual Report.
(d)Amounts in “Other” column primarily represent accrued interest receivables to/from financial institutions.  Level 2 amounts primarily represent investments in money market funds.
(e)Amounts in “Other” column primarily represent cash deposits with third parties.  Level 1 amounts primarily represent investments in money market funds.
(f)Amounts represent corporate, municipal and treasury bonds.
(g)Amounts represent publicly traded equity securities.

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:

Three Months Ended June 30, 2008 APCo  CSPCo  I&M  OPCo  PSO  SWEPCo 
  (in thousands) 
Balance as of April 1, 2008 $(942) $(552) $(519) $(837) $(21) $(35)
Realized (Gain) Loss Included in Earnings   (or Changes in Net Assets) (a)  (532)  (324)  (315)  (327)  1   4 
Unrealized Gain (Loss) Included in Earnings   (or Changes in Net Assets) Relating to   Assets Still Held at the Reporting Date (a)  -   261   -   161   -   (5)
Realized and Unrealized Gains (Losses)   Included in Other Comprehensive Income  -   -   -   -   -   - 
Purchases, Issuances and Settlements  -   -   -   -   -   - 
Transfers in and/or out of Level 3 (b)  (2,186)  (1,313)  (1,261)  (1,530)  -   - 
Changes in Fair Value Allocated to    Regulated Jurisdictions (c)  (14,900)  (9,194)  (8,580)  (10,712)  (3)  (9)
Balance as of June 30, 2008 $(18,560) $(11,122) $(10,675) $(13,245) $(23) $(45)
Three Months Ended September 30, 2008 APCo  CSPCo  I&M  OPCo  PSO  SWEPCo 
  (in thousands) 
Balance as of July 1, 2008 $(18,560) $(11,122) $(10,675) $(13,245) $(23) $(45)
Realized (Gain) Loss Included in Earnings (or Changes in Net Assets) (a)  4,466   2,670   2,561   3,287   4   13 
Unrealized Gain (Loss) Included in Earnings (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)  -   (1,317)  -   (1,574)  -   26 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income  -   -   -   -   -   - 
Purchases, Issuances and Settlements  -   -   -   -   -   - 
Transfers in and/or out of Level 3 (b)  5,595   3,360   3,228   3,914   (1,249)  (1,471)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)  3,858   3,814   2,373   4,285   61   49 
Balance as of September 30, 2008 $(4,641) $(2,595) $(2,513) $(3,333) $(1,207) $(1,428)

Six Months Ended June 30, 2008 APCo  CSPCo  I&M  OPCo  PSO  SWEPCo 
  (in thousands) 
Balance as of January 1, 2008 $(697) $(263) $(280) $(1,607) $(243) $(408)
Realized (Gain) Loss Included in Earnings   (or Changes in Net Assets) (a)  (467)  (339)  (312)  232   98   174 
Unrealized Gain (Loss) Included in Earnings   (or Changes in Net Assets) Relating to   Assets Still Held at the Reporting Date (a)  -   (1,138)  -   (2,019)  -   (64)
Realized and Unrealized Gains (Losses)   Included in Other Comprehensive Income  -   -   -   -   -   - 
Purchases, Issuances and Settlements  -   -   -   -   -   - 
Transfers in and/or out of Level 3 (b)  (122)  (188)  (158)  861   232   375 
Changes in Fair Value Allocated to    Regulated Jurisdictions (c)  (17,274)  (9,194)  (9,925)  (10,712)  (110)  (122)
Balance as of June 30, 2008 $(18,560) $(11,122) $(10,675) $(13,245) $(23) $(45)
Nine Months Ended September 30, 2008 APCo  CSPCo  I&M  OPCo  PSO  SWEPCo 
  (in thousands) 
Balance as of January 1, 2008 $(697) $(263) $(280) $(1,607) $(243) $(408)
Realized (Gain) Loss Included in Earnings (or Changes in Net Assets) (a)  332   88   105   1,063   170   290 
Unrealized Gain (Loss) Included in Earnings (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a)  -   190   -   126   -   56 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income  -   -   -   -   -   - 
Purchases, Issuances and Settlements  -   -   -   -   -   - 
Transfers in and/or out of Level 3 (b)  (731)   (454)  (430)  (244)  (1,249)  (1,472)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)  (3,545)  (2,156)  (1,908)  (2,671)  115   106 
Balance as of September 30, 2008 $(4,641) $(2,595) $(2,513) $(3,333) $(1,207) $(1,428)

(a)Included in revenues on the Condensed StatementStatements of Income.
(b)“Transfers in and/or out of Level 3” represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.
(c)“Changes in Fair Value Allocated to Regulated Jurisdictions” 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 for those subsidiaries that operate in regulated jurisdictions.liabilities.

SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159)

In February 2007, the FASB issued SFAS 159, permitting entities to choose to measure many financial instruments and certain other items at fair value.  The standard also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities.  If the fair value option is elected, the effect of the first remeasurement to fair value is reported as a cumulative effect adjustment to the opening balance of retained earnings.  The statement is applied prospectively upon adoption.

The Registrant Subsidiaries adopted SFAS 159 effective January 1, 2008.  At adoption, the Registrant Subsidiaries did not elect the fair value option for any assets or liabilities.

SFAS 160 “Noncontrolling Interest in Consolidated Financial Statements” (SFAS 160)

In December 2007, the FASB issued SFAS 160, modifying reporting for noncontrolling interest (minority interest) in consolidated financial statements.  It requires noncontrolling interest be reported in equity and establishes a new framework for recognizing net income or loss and comprehensive income by the controlling interest.  Upon deconsolidation due to loss of control over a subsidiary, the standard requires a fair value remeasurement of any remaining noncontrolling equity investment to be used to properly recognize the gain or loss.  SFAS 160 requires specific disclosures regarding changes in equity interest of both the controlling and noncontrolling parties and presentation of the noncontrolling equity balance and income or loss for all periods presented.

SFAS 160 is effective for interim and annual periods in fiscal years beginning after December 15, 2008.  The statement is applied prospectively upon adoption.  Early adoption is prohibited.  Upon adoption, prior period financial statements will be restated for the presentation of the noncontrolling interest for comparability.  Although management has not completed its analysis, managementManagement expects that the adoption of this standard will have an immaterial impact on the financial statements.  The Registrant Subsidiaries will adopt SFAS 160 effective January 1, 2009.

SFAS 161 “Disclosures about Derivative Instruments and Hedging Activities” (SFAS 161)

In March 2008, the FASB issued SFAS 161, enhancing disclosure requirements for derivative instruments and hedging activities.  Affected entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.  SFAS 161 requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation.  This standard is intended to improve upon the existing disclosure framework in SFAS 133.

SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008.  Management expects this standard to increase the disclosure requirements related to derivative instruments and hedging activities.  It encourages retrospective application to comparative disclosure for earlier periods presented.  The Registrant Subsidiaries will adopt SFAS 161 effective January 1, 2009.

SFAS 162 “The Hierarchy of Generally Accepted Accounting Principles” (SFAS 162)

In May 2008, the FASB issued SFAS 162, clarifying the sources of generally accepted accounting principles in descending order of authority.  The statement specifies that the reporting entity, not its auditors, is responsible for its compliance with GAAP.

SFAS 162 is effective 60 days after the SEC approves the Public Company Accounting Oversight Board’s amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.”  The Registrant Subsidiaries expectManagement expects the adoption of this standard will have no impact on theirthe Registrant Subsidiaries’ financial statements.  The Registrant Subsidiaries will adopt SFAS 162 when it becomes effective.

EITF Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements” (EITF
(EITF 06-10)

In March 2007, the FASB ratified EITF 06-10, a consensus on collateral assignment split-dollar life insurance arrangements in which an employee owns and controls the insurance policy.  Under EITF 06-10, an employer should recognize a liability for the postretirement benefit related to a collateral assignment split-dollar life insurance arrangement in accordance with SFAS 106 “Employers' Accounting for Postretirement Benefits Other Than Pension” or Accounting Principles Board Opinion No. 12 “Omnibus Opinion – 1967” if the employer has agreed to maintain a life insurance policy during the employee's retirement or to provide the employee with a death benefit based on a substantive arrangement with the employee.  In addition, an employer should recognize and measure an asset based on the nature and substance of the collateral assignment split-dollar life insurance arrangement.  EITF 06-10 requires recognition of the effects of its application as either (a) a change in accounting principle through a cumulative effect adjustment to retained earnings or other components of equity or net assets in the statement of financial position at the beginning of the year of adoption or (b) a change in accounting principle through retrospective application to all prior periods.  The Registrant Subsidiaries adopted EITF 06-10 effective January 1, 2008.  The impact of this standard was an unfavorable cumulative effect adjustment, net of tax, to beginning retained earnings as follows:
  Retained   
  Earnings Tax 
Company Reduction Amount 
  (in thousands) 
APCo  $2,181  $1,175 
CSPCo   1,095   589 
I&M   1,398   753 
OPCo   1,864   1,004 
PSO   1,107   596 
SWEPCo   1,156   622 

EITF Issue No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards” (EITF
(EITF 06-11)

In June 2007, the FASB ratified the EITF consensus on the treatment of income tax benefits of dividends on employee share-based compensation.  The issue is how a company should recognize the income tax benefit received on dividends that are paid to employees holding equity-classified nonvested shares, equity-classified nonvested share units or equity-classified outstanding share options and charged to retained earnings under SFAS 123R, “Share-Based Payments.”  Under EITF 06-11, a realized income tax benefit from dividends or dividend equivalents that are charged to retained earnings and are paid to employees for equity-classified nonvested equity shares, nonvested equity share units and outstanding equity share options should be recognized as an increase to additional paid-in capital.  EITF 06-11 is applied prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years after December 15, 2007.

The Registrant Subsidiaries adopted EITF 06-11 effective January 1, 2008.  The adoption of this standard had an immaterial impact on the financial statements.

EITF Issue No. 08-5 “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (EITF 08-5)

In September 2008, the FASB ratified the EITF consensus on liabilities with third-party credit enhancements when the liability is measured and disclosed at fair value.  The consensus treats the liability and the credit enhancement as two units of accounting.  Under the consensus, the fair value measurement of the liability does not include the effect of the third-party credit enhancement.  Consequently, changes in the issuer’s credit standing without the support of the credit enhancement affect the fair value measurement of the issuer’s liability.  Entities will need to provide disclosures about the existence of any third-party credit enhancements related to their liabilities.

EITF 08-5 is effective for the first reporting period beginning after December 15, 2008.  It will be applied prospectively upon adoption with the effect of initial application included as a change in fair value of the liability in the period of adoption.  In the period of adoption, entities must disclose the valuation method(s) used to measure the fair value of liabilities within its scope and any change in the fair value measurement method that occurs as a result of its initial application.  Early adoption is permitted.  Although management has not completed an analysis, management expects that the adoption of this standard will have an immaterial impact on the financial statements.  The Registrant Subsidiaries will adopt this standard effective January 1, 2009.
FSP SFAS 133-1 and FIN 45-4 “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No.133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161” (SFAS 133-1 and FIN 45-4)
In September 2008, the FASB issued SFAS 133-1 and FIN 45-4 as amendments to original statements SFAS 133 and FIN 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” Under the SFAS 133 requirements, the seller of a credit derivative shall disclose the following information for each derivative, including credit derivatives embedded in a hybrid instrument, even if the likelihood of payment is remote:

(a)The nature of the credit derivative.
(b)The maximum potential amount of future payments.
(c)The fair value of the credit derivative.
(d)The nature of any recourse provisions and any assets held as collateral or by third parties.

Further, the standard requires the disclosure of current payment status/performance risk of all FIN 45 guarantees.  In the event an entity uses internal groupings, the entity shall disclose how those groupings are determined and used for managing risk.

The standard is effective for interim and annual reporting periods ending after November 15, 2008.  Upon adoption, the guidance will be prospectively applied.  Management expects that the adoption of this standard will have an immaterial impact on the financial statements but increase the FIN 45 guarantees disclosure requirements.  The Registrant Subsidiaries will adopt the standard effective December 31, 2008.

FSP SFAS 142-3 “Determination of the Useful Life of Intangible Assets” (SFAS 142-3)

In April 2008, the FASB issued SFAS 142-3 amending factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS 142, “Goodwill and Other Intangible Assets.”  The standard is expected to improve consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure its fair value.

SFAS 142-3 is effective for interim and annual periods in fiscal years beginning after December 15, 2008.  Early adoption is prohibited.  Upon adoption, the guidance within SFAS 142-3 will be prospectively applied to intangible assets acquired after the effective date.  Management expects that the adoption of this standard will have an immaterial impact on the Registrant Subsidiaries’ financial statements.  The Registrant Subsidiaries will adopt SFAS 142-3 effective January 1, 2009.

FASB Staff PositionFSP FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1)

In April 2007, the FASB issued FIN 39-1.  It amends FASB Interpretation No. 39 “Offsetting of Amounts Related to Certain Contracts” by replacing the interpretation’s definition of contracts with the definition of derivative instruments per SFAS 133.  It also requires entities that offset fair values of derivatives with the same party under a netting agreement to also net the fair values (or approximate fair values) of related cash collateral.  The entities must disclose whether or not they offset fair values of derivatives and related cash collateral and amounts recognized for cash collateral payables and receivables at the end of each reporting period.

The Registrant Subsidiaries adopted FIN 39-1 effective January 1, 2008.  This standard changed the method of netting certain balance sheet amounts and reduced assets and liabilities.  It requires retrospective application as a change in accounting principle.  Consequently, the Registrant Subsidiaries reclassified the following amounts on their December 31, 2007 balance sheets as shown:

APCo             
 As Reported for    As Reported for   As Reported for   As Reported for
Balance Sheet the December 2007 FIN 39-1  the June 2008    the December 2007 FIN 39-1 the September 2008
Line Description 10-K Reclassification 
 10-Q 
 10-K Reclassification 10-Q
Current Assets: (in thousands) (in thousands)
Risk Management Assets $64,707 $(1,752) $  62,955
 
 $64,707  $(1,752) $62,955 
Prepayments and Other  19,675  (3,306) 16,369  19,675   (3,306) 16,369 
Long-term Risk Management Assets  74,954  (2,588) 72,366  74,954   (2,588) 72,366 
               
Current Liabilities:               
Risk Management Liabilities  54,955  (3,247) 51,708  54,955  (3,247) 51,708 
Customer Deposits  50,260  (4,340)  45,920  50,260  (4,340) 45,920 
Long-term Risk Management Liabilities  47,416  (59) 47,357  47,416  (59) 47,357 

CSPCo              
 As Reported for    
   As Reported for
  As Reported for   As Reported for
Balance Sheet the December 2007 FIN 39-1     the June 2008  the December 2007 FIN 39-1 the September 2008
Line Description 10-K  Reclassification    10-Q  10-K Reclassification 10-Q
Current Assets: (in thousands) (in thousands)
Risk Management Assets $34,564 $(1,006) $ 33,558  $34,564  $(1,006) $33,558 
Prepayments and Other  11,877  (1,917) 9,960  11,877   (1,917) 9,960 
Long-term Risk Management Assets  43,352  (1,500) 41,852  43,352   (1,500) 41,852 
                
Current Liabilities:                
Risk Management Liabilities  30,118  (1,881)  28,237  30,118  (1,881) 28,237 
Customer Deposits  45,602  (2,507)  43,095  45,602  (2,507) 43,095 
Long-term Risk Management Liabilities  27,454  (35)  27,419  27,454  (35) 27,419 

I&M              
 As Reported for    As Reported for   As Reported for   As Reported for
Balance Sheet the December 2007 FIN 39-1  the June 2008   the December 2007 FIN 39-1 the September 2008
Line Description 10-K Reclassification   10-Q  10-K Reclassification 10-Q
Current Assets: (in thousands) (in thousands)
Risk Management Assets $33,334 $(969) $ 32,365  $33,334  $(969) $32,365 
Prepayments and Other  12,932  (1,841)  11,091  12,932  (1,841) 11,091 
Long-term Risk Management Assets  41,668  (1,441)  40,227  41,668  (1,441) 40,227 
                 
Current Liabilities:                 
Risk Management Liabilities  29,078  (1,807)  27,271  29,078  (1,807) 27,271 
Customer Deposits  28,855  (2,410)  26,445  28,855  (2,410) 26,445 
Long-term Risk Management Liabilities  26,382  (34)  26,348  26,382  (34) 26,348 
OPCo      
  As Reported for   As Reported for
Balance Sheet the December 2007 FIN 39-1 the September 2008
Line Description 10-K Reclassification 10-Q
Current Assets: (in thousands)
Risk Management Assets $45,490  $(1,254) $44,236 
Prepayments and Other  20,532   (2,232)  18,300 
Long-term Risk Management Assets  51,334   (1,748)  49,586 
          
Current Liabilities:         
Risk Management Liabilities  42,740   (2,192)  40,548 
Customer Deposits  33,615   (3,002)  30,613 
Long-term Risk Management Liabilities  32,234   (40)  32,194 

PSO      
  As Reported for   As Reported for
Balance Sheet the December 2007 FIN 39-1 the September 2008
Line Description 10-K Reclassification 10-Q
Current Assets: (in thousands)
Risk Management Assets $33,338  $(30) $33,308 
Margin Deposits  9,119   (139)  8,980 
Long-term Risk Management Assets  3,376   (18)  3,358 
          
Current Liabilities:         
Risk Management Liabilities  27,151   (33)  27,118 
Customer Deposits  41,525   (48)  41,477 
Long-term Risk Management Liabilities  2,914   (106)  2,808 

OPCo         
  As Reported for     As Reported for  
Balance Sheet the December 2007  FIN 39-1  the June 2008  
Line Description 10-K  Reclassification   10-Q 
Current Assets: (in thousands)
  Risk Management Assets $45,490  $(1,254) $ 44,236 
  Prepayments and Other  20,532   (2,232)   18,300 
Long-term Risk Management Assets  51,334   (1,748)   49,586 
             
Current Liabilities:            
  Risk Management Liabilities  42,740   (2,192)   40,548 
  Customer Deposits  33,615   (3,002)   30,613 
Long-term Risk Management Liabilities  32,234   (40)   32,194 
PSO        
SWEPCo      
 As Reported for    As Reported for   As Reported for   As Reported for
Balance Sheet the December 2007 FIN 39-1  the June 2008   the December 2007 FIN 39-1 the September 2008
Line Description 10-K Reclassification   10-Q  10-K Reclassification 10-Q
Current Assets: (in thousands) (in thousands)
Risk Management Assets $33,338 $(30) $33,308  $39,893  $(43) $39,850 
Margin Deposits  9,119  (139) 8,980  10,814  (164)  10,650 
Long-term Risk Management Assets  3,376  (18) 3,358  4,095  (22)  4,073 
                  
Current Liabilities:                  
Risk Management Liabilities  27,151  (33) 27,118  32,668  (39)  32,629 
Customer Deposits  41,525  (48) 41,477  37,537  (64)  37,473 
Long-term Risk Management Liabilities  2,914  (106) 2,808  3,460  (126)  3,334 

SWEPCo         
  As Reported for     As Reported for  
Balance Sheet the December 2007  FIN 39-1  the June 2008  
Line Description 10-K  Reclassification   10-Q 
Current Assets: (in thousands)
  Risk Management Assets $39,893  $(43) $39,850 
  Margin Deposits  10,814   (164)  10,650 
Long-term Risk Management Assets  4,095   (22)  4,073 
             
Current Liabilities:            
  Risk Management Liabilities  32,668   (39)  32,629 
  Customer Deposits  37,537   (64)  37,473 
Long-term Risk Management Liabilities  3,460   (126)  3,334 
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 JuneSeptember 30, 2008 balance sheets, the Registrant Subsidiaries netted 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, 2008 September 30, 2008 
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 
Assets Liabilities Assets Liabilities 
(in thousands) (in thousands) 
APCo$23,799 $19,719  $8,250  $597 
CSPCo 14,288  10,823   4,631   311 
I&M 13,724  9,976   4,482   309 
OPCo 16,688  21,387   5,747   656 
PSO 1,744  3,101   499   47 
SWEPCo 2,060  4,396   588   69 

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued by FASB, 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, contingencies, liabilities and equity, emission allowances, leases, hedge accounting, consolidation policy, trading inventory and related tax impacts.  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 results of operationsnet income and financial position.

EXTRAORDINARY ITEM

APCo recorded an extraordinary loss of $118 million ($79 million, net of tax) during the second quarter of 2007 for the establishment of regulatory assets and liabilities related to the Virginia generation operations.  In 2000, APCo discontinued SFAS 71 regulatory accounting for the Virginia jurisdiction due to the passage of legislation for customer choice and deregulation.  In April 2007, Virginia passed legislation to establish electric regulation again.

3.RATE MATTERS

The Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within the 2007 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact results of operations,net income, cash flows and possibly financial condition.  The following discusses ratemaking developments in 2008 and updates the 2007 Annual Report.

Ohio Rate Matters

Ohio Electric Security Plan Filings – Affecting CSPCo and OPCo

In April 2008, the Ohio legislature passed Senate Bill 221, which amends the restructuring law effective July 31, 2008 and requires electric utilities to adjust their rates by filing an Electric Security Plan (ESP).  Electric utilities may file an ESP with a fuel cost recovery mechanism.  Electric utilities also have an option to file a Market Rate Offer (MRO) for generation pricing.  A MRO, from the date of its commencement, could transition CSPCo and OPCo to full market rates no sooner than six years and no later than ten years.years after the PUCO approves a MRO.  The PUCO has the authority to approve or modify theeach utilities’ ESP request.  The PUCO is required to approve an ESP if, in the aggregate, the ESP is more favorable to ratepayers than thea MRO.  Both alternatives involve a “substantially excessive earnings” test based on what public companies, including other utilities with similar risk profiles, earn on equity.  Management has preliminarily concluded, pending the issuance of final rules by the PUCO and the outcome of the ESP proceeding, that CSPCo’s and OPCo’s generation/supply operations are not subject to cost-based rate regulation accounting.  However, if a fuel cost recovery mechanism is implemented within the ESP, CSPCo’s and OPCo’s fuel and purchased power operations would be subject to cost-based rate regulation accounting.  Management is unable to predict the financial statement impact of the restructuring legislation until the PUCO acts on specific proposals made by CSPCo and OPCo in their ESPs.

In July 2008, within the parameters of the ESPs, CSPCo and OPCo filed with the PUCO to establish rates for 2009 through 2011.  CSPCo and OPCo did not file MROs.an optional MRO.  CSPCo and OPCo each requested an annual rate increase for 2009 through 2011 that would not exceed approximately 15% per year.  A significant portion of the requested increases results from the implementation of a fuel cost recovery mechanism (which excludes off-system sales) that primarily includes fuel costs, purchased power costs including mandated renewable energy, consumables such as urea, other variable production costs and gains and losses on sales of emission allowances.  The increases in customer bills related to the fuelfuel-purchased power cost recovery mechanism would be phased-in over the three year period from 2009 through 2011.  EffectiveIf the ESP is approved as filed, effective with January 1, 2009 billings, CSPCo and OPCo will defer theany fuel cost under-recoveries and related carrying costs for future recoveryrecovery.  The under-recoveries and related carrying costs that exist at the end of 2011 will be recovered over seven years from 2012 through 2018.  In addition to the fuel cost recovery mechanisms, the requested increases would also recover incremental carrying costs associated with environmental costs, Provider of Last Resort (POLR) charges to compensate for the risk of customers changing electric suppliers, automatic increases for unexpecteddistribution reliability costs and reliabilityfor unexpected non-fuel generation costs.  The filings also include programs for smart metering initiatives and economic development and mandated energy efficiency and peak demand reduction programs.  Management expectsIn September 2008, the PUCO issued a finding and order tentatively adopting rules governing MRO and ESP applications.  CSPCo and OPCo filed their ESP applications based on proposed rules and requested waivers for portions of the proposed rules.  The PUCO decision ondenied the ESP filingswaiver requests in September 2008 and ordered CSPCo and OPCo to submit information consistent with the fourth quartertentative rules.  In October 2008, CSPCo and OPCo submitted additional information related to proforma financial statements and information concerning CSPCo and OPCo’s fuel procurement process.  In October 2008, CSPCo and OPCo filed an application for rehearing with the PUCO to challenge certain aspects of 2008.the proposed rules.

Within the ESPs, CSPCo and OPCo would also recover existing regulatory assets of $45$46 million and $36$38 million, respectively, for customer choice implementation and line extension carrying costs.  In addition, CSPCo and OPCo would recover related unrecorded equity carrying costs of $28$30 million and $19$21 million, respectively.  Such costs would be recovered over an 8 year8-year period beginning January 2011.  Hearings are scheduled for November 2008 and an order is expected in the fourth quarter of 2008.  If an order is not received prior to January 1, 2009, CSPCo and OPCo have requested retroactive application of the new rates back to January 1, 2009 upon approval.  Failure of the PUCO to ultimately approve the recovery of the regulatory assets would have an adverse effect on future results of operationsnet income and cash flows.

2008 Generation Rider and Transmission Rider Rate Settlement – Affecting CSPCo and OPCo

On January 30, 2008, the PUCO approved a settlement agreement, among CSPCo, OPCo and other parties, under the additional average 4% generation rate increase and transmission cost recovery rider (“TCRR”)(TCRR) provisions of the RSP.  The increase was to recover additional governmentally-mandated costs including incremental environmental costs.  Under the settlement, the PUCO also approved recovery through the TCRR of increased PJM costs associated with transmission line losses of $39 million each for CSPCo and OPCo.  As a result, CSPCo and OPCo established regulatory assets induring the first quarter of 2008 of $12 million and $14 million, respectively, related to the future recovery of increased PJM billings previously expensed from June 2007 to December 2007.2007 for transmission line losses.  The PUCO also approved a credit applied to the TCRR of $10 million for OPCo and $8 million for CSPCo for a reduction in PJM net congestion costs.  To the extent that collections for the TCRR itemsrecoveries are over/underunder/over actual net costs, CSPCo and OPCo will defer the difference as a regulatory asset or regulatory liability and adjust future customer billings to reflect actual costs, including carrying costs on the unrecovered deferral.  Under the terms of the settlement, although the increased PJM costs associated with transmission line losses will be recovered through the TCRR, these recoveries will still be applied to reduce the annual average 4% generation rate increase limitation.  In addition, the PUCO approved recoveries through generation rates of environmental costs and related carrying costs of $29 million for CSPCo and $5 million for OPCo.  These RSP rate adjustments were implemented in February 2008.

InAlso, in February 2008, Ormet, a major industrial customer, filed a motion to intervene and an application for rehearing of the PUCO’s January 2008 RSP order claiming the settlement inappropriately shifted $4 million in cost recovery to Ormet.  In March 2008, the PUCO granted Ormet’s motion to intervene.  Ormet’s rehearing application also was granted for the purpose of providing the PUCO with additional time to consider the issues raised by Ormet.  Management cannot predictUpon PUCO approval of an unrelated amendment to the outcome of thisOrmet contract, Ormet withdrew its rehearing process.application in August 2008.

Ohio IGCC Plant – Affecting CSPCo and OPCo

In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs related to building and operating a 629 MW IGCC power plant using clean-coal technology.  The application proposed three phases of cost recovery associated with the IGCC plant:  Phase 1, recovery of $24 million in pre-construction costs; Phase 2, concurrent recovery of construction-financing costs; and Phase 3, recovery or refund in distribution rates of any difference between the generation rates which may be a market-based standard service offer price for generation and the expected higher cost of operating and maintaining the plant, including a return on and return of the projected cost to construct the plant.

In June 2006, the PUCO issued an order approving a tariff to allow CSPCo and OPCo to recover Phase 1 pre-construction costs over a period of no more than twelve months effective July 1, 2006.  During that period CSPCo and OPCo each collected $12 million in pre-construction costs and incurred $11 million in pre-construction costs.  As a result, CSPCo and OPCo each established a net regulatory liability of approximately $1 million.

The order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant within five years of the June 2006 PUCO order, all Phase 1 costscost recoveries associated with items that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest.  The PUCO deferred ruling on cost recovery for Phases 2 and 3 pending further hearings.

In August 2006, intervenors filed four separate appeals of the PUCO’s order in the IGCC proceeding.  In March 2008, the Ohio Supreme Court issued its opinion affirming in part, and reversing in part the PUCO’s order and remanded the matter back to the PUCO.  The Ohio Supreme Court held that while there could be an opportunity under existing law to recover a portion of the IGCC costs in distribution rates, traditional rate making procedures would apply to the recoverable portion.  The Ohio Supreme Court did not address the matter of refunding the Phase 1 cost recovery and declined to create an exception to its precedent of denying claims for refund of past recoveries from approved orders of the PUCO.

Recent estimates of  In September 2008, the costOhio Consumers’ Counsel filed a motion with the PUCO requesting all Phase 1 costs be refunded to build the proposed IGCC plant are approximately $2.7 billion.  Management continues to pursue the ultimate construction of the IGCC plant.  However, in light ofOhio ratepayers with interest because the Ohio Supreme Court’s decision,Court invalidated the underlying foundation for the Phase 1 recovery.  CSPCo and OPCo will not start construction offiled a motion with the IGCC plant until sufficient assurance of cost recovery exists.PUCO that argued the Ohio Consumers’ Counsel’s motion was without legal merit and contrary to past precedent.  If CSPCo and OPCo were required to refund the $24 million collected and those costs were not recoverable in another jurisdiction in connection with the construction of an IGCC plant, it would have an adverse effect on future results of operationsnet income and cash flows.

As of December 31, 2007, the cost of the plant was estimated at $2.7 billion.  The estimated cost of the plant has continued to increase significantly.  Management continues to pursue the ultimate construction of the IGCC plant.  CSPCo and OPCo will not start construction of the IGCC plant until sufficient assurance of regulatory cost recovery exists.

Ormet – Affecting CSPCo and OPCo

Effective January 1, 2007, CSPCo and OPCo began to serve Ormet, a major industrial customer with a 520 MW load, in accordance with a settlement agreement approved by the PUCO.  The settlement agreement allows for the recovery in 2007 and 2008 of the difference between the $43 per MWH Ormet pays for power and a PUCO-approved market price, if higher.  The PUCO approved a $47.69 per MWH market price for 2007 and the difference was recovered through the amortization of a $57 million ($15 million for CSPCo and $42 million for OPCo) excess deferred tax regulatory liability resulting from an Ohio franchise tax phase-out recorded in 2005.

CSPCo and OPCo each amortized $5$8 million of this regulatory liability to income for the sixnine months ended JuneSeptember 30, 2008 based on the previously approved 2007 price of $47.69 per MWH.  In December 2007, CSPCo and OPCo submitted for approval a market price of $53.03 per MWH for 2008.  The PUCO has not yet approved the increase.2008 market price.  If the PUCO approves a market price for 2008 below $47.69, it could have an adverse effect on future results of operationsnet income and cash flows.  A price above $47.69 should result in a favorable effect.  If CSPCo and OPCo serve the Ormet load after 2008 without any special provisions, they could experience incremental costs to acquire additional capacity to meet their reserve requirements and/or forgo more profitable market pricedmarket-priced off-system sales.

Hurricane Ike – Affecting CSPCo and OPCo

In September 2008, the service territories of CSPCo and OPCo were impacted by strong winds from the remnants of Hurricane Ike.  CSPCo and OPCo incurred approximately $18 million and $13 million, respectively, in incremental distribution operation and maintenance costs related to service restoration efforts.  Under the current RSP, CSPCo and OPCo can seek a distribution rate adjustment to recover incremental distribution expenses related to major storm service restoration efforts.  In September 2008, CSPCo and OPCo established regulatory assets of $17 million and $10 million, respectively, for the incremental distribution operation and maintenance costs related to major storm service restoration efforts.  The regulatory assets represent the excess above the average of the last three years of distribution storm expenses excluding Hurricane Ike, which was the methodology used by the PUCO to determine the recoverable amount of storm restoration expenses in the most recent 2006 PUCO storm damage recovery decision.  Prior to December 31, 2008, which is the expiration of the RSP, CSPCo and OPCo will file for recovery of the regulatory assets.  As a result of the past favorable treatment of storm restoration costs and the favorable RSP provisions, management believes the recovery of the regulatory assets is probable.  If these regulatory assets are not recoverable, it would have an adverse effect on future net income and cash flows.

Virginia Rate Matters

Virginia Base Rate Filing – Affecting APCo

In May 2008, APCo filed an application with the Virginia SCC to increase its base rates by $208 million on an annual basis.  The requested increase is based upon a calendar 2007 test year adjusted for changes in revenues, expenses, rate base and capital structure through June 2008 which2008.  This is consistent with the ratemaking treatment adopted by the Virginia SCC in APCo’s 2006 base rate case.  The proposed revenue requirement reflects a return on equity of 11.75%.  The Virginia SCC ordered hearings to beginHearings began in October 2008.  As permitted under Virginia law, APCo plans to implementimplemented these new base rates, subject to refund, effective October 28, 2008.

In September 2008, ifthe Attorney General’s office filed testimony recommending the proposed $208 million annual increase in base rate be reduced to $133 million.  The decrease is principally due to the use of a return on equity approved in the last base rate case of 10% and various rate base and operating income adjustments, including a $25 million proposed disallowance of capacity equalization charges payable by APCo as a deficit member of the FERC approved AEP Power Pool.

In October 2008, the Virginia SCC failsstaff filed testimony recommending the proposed $208 million annual increase in base rate be reduced to make$157 million.  The decrease is principally due to the use of a decisionrecommended return on equity  of 10.1%.  In October 2008, hearings were held in which APCo filed a $168 million settlement agreement which was accepted by that date.all parties except one industrial customer.  APCo expects to receive a final order from the Virginia SCC in November 2008.

Virginia E&R Costs Recovery Filing – Affecting APCo

As of June 30,September 2008, APCo has $97$118 million of deferred Virginia incremental E&R costs.  Currently APCo is recovering $16costs (excluding $25 million of unrecognized equity carrying costs).  The $118 million consists of $6 million already approved by the deferral for incremental costs incurred through September 30, 2006.  InVirginia SCC to be collected during the fourth quarter 2008, $54 million relating to APCo’s May 2008 APCo filedfiling for recovery in 2009, and $58 million, representing costs deferred in 2008 to date, to be included (along with the fourth quarter 2008 E&R deferrals) in the 2009 E&R filing, to be collected in 2010.

In September 2008, a settlement was reached between the parties to the 2008 filing and a stipulation agreement (stipulation) was submitted to the hearing examiner.  The stipulation provides for recovery of deferred incremental E&R costs incurred from October 1, 2006 through December 31, 2007 which totals $50 million.  The remaining deferral will be requested in a 2009 filing.  As of June 30, 2008, APCo has $22$61 million of unrecorded E&R equity carrying costs of which $7 million should increase 2008 annual earnings as collected.  In connection with the 2009 filing, the Virginia SCC will determine the level of incremental E&R costs in 2009 which is an increase of $12 million over the level of E&R surcharge revenues being collected in base revenues since October 20062008.  The stipulation included an unfavorable $1 million adjustment related to certain costs considered not recoverable E&R costs and recovery of $4.5 million representing one-half of a $9 million Virginia jurisdictional portion of NSR settlement expenses recorded in 2007.  In accordance with the stipulation, APCo will request the remaining one-half of the $9 million of NSR settlement expenses in APCo’s 2009 E&R filing.  The stipulation also specifies that APCo has estimatedwill remove $3 million of the $9 million of NSR settlement expenses requested to be $48 million annually.  Ifrecovered over 3 years in the Virginia SCC were to determine that these recoveredcurrent base revenues are in excess of $48 million a year, it would require thatrate case from the E&R deferrals be reduced by the excess amount, thus adversely affecting future earnings and cash flows.base rate case’s revenue requirement.

In JulySeptember 2008, the Old Dominion Committee for Fair Utility Rates (ODC) filed a motion to dismiss the E&R filing based on ODC’s beliefhearing examiner recommended that the opportunity to collect E&R surcharges expires December 31, 2008.  A dismissal would not eliminate APCo’s ability to request for future recovery of its deferred E&R costs.  APCo filed a response requesting the Virginia SCC to deny ODC’s motion.accept the stipulation.  As a result, in September 2008, APCo deferred as a regulatory asset $9 million of NSR settlement expenses it had expensed in 2007 that have become probable of future recovery.  In October 2008, the Virginia SCC approved the stipulation which will have a favorable effect on 2009 future cash flows of $61 million and on net income for the previously unrecognized equity costs of approximately $11 million.  If the Virginia SCC were to disallow any additionala material portion of APCo’s 2008 deferral, it would also have an adverse effect on future results of operationsnet income and cash flows.  If the outstanding request for E&R recovery is approved it will have a favorable effect on future cash flows.

Virginia Fuel Clause Filings – Affecting APCo

In July 2007, APCo filed an application with the Virginia SCC to seek an annualized increase, effective September 1, 2007, of $33 million for fuel costs and sharing of off-system sales.

In February 2008, the Virginia SCC issued an order that approved a reduced fuel factor effective with the February 2008 billing cycle.  The order terminated the off-system sales margin rider and approved a 75%-25% sharing of off-system sales margins between customers and APCo effective September 1, 2007 as required by the re-regulation legislation in Virginia.  The order also allows APCo to include in its monthly under/over recovery deferrals the Virginia jurisdictional share of PJM transmission line loss costs from June 2007 to June 2008 which totaled $28 million.2007.  The adjusted factor increases annual fuel clause revenues by $4 million.  The order authorized the Virginia SCC staff and other parties to make specific recommendations to the Virginia SCC in APCo’s next fuel factor proceeding to ensure accurate assignment of the prudently incurred PJM transmission line loss costs to APCo’s Virginia jurisdictional operations.  Management believes the incurred PJM transmission line loss costs are prudently incurred and are being properly assigned to APCo’s Virginia jurisdictional operations.

In February 2008, the Old Dominion Committee for Fair Utility Rates (ODC) filed a notice of appeal to the Supreme Court of Virginia appealing the Virginia SCC’s decisions regarding off-system sales margins and PJM transmission line loss costs.  In May 2008, the ODC withdrew its appeal.

In July 2008, APCo filed its next fuel factor proceeding with the Virginia SCC and requested an annualized increase of $132 million effective September 1, 2008.  The increase primarily relates to increases in coal costs.

If costs included in APCo’s  In August 2008, the Virginia SCC issued an order to allow APCo to implement the increased fuel under/over recovery deferrals are disallowed, it couldfactor on an interim basis for services rendered after August 2008.  In September 2008, the Virginia SCC staff filed testimony recommending a lower fuel factor which will result in an adverse effectannualized increase of $117 million, which includes the PJM transmission line loss costs, instead of APCo’s proposed $132 million.  In October 2008, the Virginia SCC ordered an annualized increase of $117 million for services rendered on future results of operations and cash flows.after October 20, 2008.

APCo’s Virginia SCC Filing for an IGCC Plant – Affecting APCo

In July 2007, APCo filed a request with the Virginia SCC for a rate adjustment clause to recover initial costs associated with a proposed 629 MW IGCC plant to be constructed in Mason County, West Virginia adjacent to APCo’s existing Mountaineer Generating Station for an estimated cost of $2.2 billion.  The filing requested recovery of an estimated $45 million over twelve months beginning January 1, 2009 including a return on projected CWIP and development, design and planning pre-construction costs incurred from July 1, 2007 through December 31, 2009.  APCo also requested authorization to defer a return on deferred pre-construction costs incurred beginning July 1, 2007 until such costs are recovered.  Through JuneSeptember 30, 2008, APCo has deferred for future recovery pre-construction IGCC costs of approximately $9 million allocated to Virginia jurisdictional operations.  The rate adjustment clause provisions of the 2007 re-regulation legislation provides for full recovery of all costs of this type of new clean coal technology including recovery of an enhanced return on equity.

The Virginia SCC issued an order in April 2008 denying APCo’s requests stating the belief that the estimated cost may be significantly understated.  The Virginia SCC also expressed concern that the $2.2 billion estimated cost did not include a retrofitting of carbon capture and sequestration facilities.  In April 2008, APCo filed a petition for reconsideration in Virginia.  In May 2008, the Virginia SCC denied APCo’s request to reconsider its previous ruling.  In July 2008, the IRS awardedallocated $134 million in future tax credits to APCo for the planned IGCC plant.  Managementplant contingent upon the commencement of construction, qualifying expense being incurred and certification of the IGCC plant prior to July 2010.  Although management continues to pursue the ultimate construction of the IGCC plant; however,plant, APCo will not start construction of the IGCC plant until sufficient assurance of cost recovery exists.  If the plant is canceled,cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs.  If the plant is canceledcancelled and if the deferred costs are not recoverable, it would have an adverse effect on future results of operationsnet income and cash flows.

Mountaineer Carbon Capture Project – Affecting APCo

In January 2008, APCo and ALSTOM Power Inc. (Alstom), an unrelated third party, entered into an agreement to jointly construct a CO2 capture facility.  APCo and Alstom will each own part of the CO2 capture facility.  APCo will also construct and own the necessary facilities to store the CO2.  APCo’s estimated cost for its share of the facilities is $76 million.  Through September 30, 2008, APCo incurred $13 million in capitalized project costs which is included in Regulatory Assets.  APCo plans to seek recovery for the CO2 capture and storage project costs in its next Virginia and West Virginia base rate filings which are expected to be filed in 2009.  APCo is presently seeking a return on the capitalized project costs in its current Virginia base rate filing.  The Attorney General has recommended that the project costs should be shared by all affiliated operating companies with coal-fired generation plants.  If a significant portion of the project costs are excluded from base rates and ultimately disallowed in Virginia and/or West Virginia, it could have an adverse effect on future net income and cash flows.

West Virginia Rate Matters

APCo’s  2008 Expanded Net Energy Cost (ENEC) Filing – Affecting APCo

In February 2008, APCo filed for an increase of approximately $140 million including a $122 million increase in the ENEC, a $15 million increase in construction cost surcharges and $3 million of reliability expenditures, to become effective July 2008.  In June 2008, the WVPSC issued an order approving a joint stipulation and settlement agreement granting an increase,rate increases, effective July 2008, of approximately $95 million, including a $79 million increase in the ENEC, a $13 million increase in construction cost surcharges and $3 million of reliability expenditures.  The ENEC is an expanded form of fuel clause mechanism, which includes all energy-related costs including fuel, purchased power expenses, off-system sales credits, PJM costs associated with transmission line losses due to the implementation of marginal loss pricing and other energy/transmission items.

The ENEC is subject to a true uptrue-up to actual costs and should have no earnings effect if actual costs exceed the recoveries due to the deferral of any over/under-recovery of actual ENEC costs.  The construction cost and reliability surcharges are not subject to a true uptrue-up to actual costs and could result in an adverse under recovery.impact future net income and cash flows.

APCo’s West Virginia IGCC Plant Filing – Affecting APCo

In January 2006, APCo filed a petition with the WVPSC requesting its approval of a Certificate of Public Convenience and Necessity (CCN) to construct a 629 MW IGCC plant adjacent to APCo’s existing Mountaineer Generating Station in Mason County, West Virginia.

In June 2007, APCo filed testimony with the WVPSC supporting the requests for a CCN and for pre-approval of a surcharge rate mechanism to provide for the timely recovery of both pre-construction costs and the ongoing finance costs of the project during the construction period as well as the capital costs, operating costs and a return on equity once the facility is placed into commercial operation.  In March 2008, the WVPSC granted APCo the CCN to build the plant and the request for cost recovery.  VariousAlso, in March 2008, various intervenors filed petitions with the WVPSC to reconsider the order.  No action has been taken on the requests for rehearing.  At the time of the filing, the cost of the plant was estimated at $2.2 billion.  As of September 30, 2008, the estimated cost of the plant has continued to significantly increase.  In July 2008, based on the unfavorable order received in Virginia, the WVPSC issued a notice seeking comments from parties on how the WVPSC should proceed (Seeproceed.  See the “APCo’s Virginia SCC Filing for an IGCC Plant” section above).above.  Through JuneSeptember 30, 2008, APCo deferred for future recovery pre-construction IGCC costs of $8approximately $9 million applicable to the West Virginia jurisdiction and approximately $2 million applicable to the FERC jurisdiction.  In July 2008, the IRS awardedallocated $134 million in future tax credits to APCo for the planned IGCC plant.  ManagementAlthough management continues to pursue the ultimate construction of the IGCC plant; however,plant, APCo will not start construction of the IGCC plant until sufficient assurance of cost recovery exists. If the plant is canceled,cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs.  If the plant is canceledcancelled and if the deferred costs are not recoverable, it would have an adverse effect on future results of operationsnet income and cash flows.

Indiana Rate Matters

Indiana Base Rate Filing – Affecting I&M

In a January 2008, filing with the IURC, updated in the second quarter of 2008, I&M requested an increase in its Indiana base rates of $80 million including a return on equity of 11.5%.  The base rate increase includes the $69 million annual reduction in depreciation expense previously approved by the IURC and implemented for accounting purposes effective June 2007.  The depreciation reduction will no longer favorably impact earnings if and will adversely affect cash flows when tariff rates are revised to reflect the effect of the depreciation expense reduction.  The filing also requests trackers for certain variable components of the cost of service including recently increased PJM costs associated with transmission line losses due to the implementation of marginal loss pricing and other RTO costs, reliability enhancement costs, demand side management/energy efficiency costs, off-system sales margins and environmental compliance costs.  The trackers would initially increase annual revenues by an additional $45 million.  I&M proposes to share with ratepayers, through a tracker, 50% of off-system sales margins initially estimated to be $96 million annually with a guaranteed credit to customers of $20 million.

In September 2008, the Indiana Office of Utility Consumer Counselor (OUCC) and the Industrial Customer Coalition filed testimony recommending a $14 million and $37 million decrease in revenue, respectively.  Two other intervenors filed testimony on limited issues.  The OUCC and the Industrial Customer Coalition recommended that the IURC reduce the ROE proposed by I&M, reduce or limit the amount of off-system sales margin sharing, deny the recovery of reliability enhancement costs and reject the proposed environmental compliance cost recovery trackers.  In October 2008, I&M filed testimony rebutting the recommendations of the OUCC.  Hearings are scheduled for December 2008.  A decision is expected from the IURC by June 2009.

Michigan Rate Matters

Michigan Restructuring – Affecting I&M

Although customer choice commenced for I&M’s Michigan customers on January 1, 2002, I&M’s rates for generation in Michigan continued to be cost-based regulated because none of I&M's customers elected to change suppliers and no alternative electric suppliers were registered to compete in I&M's Michigan service territory.  In October 2008, the Governor of Michigan signed legislation to limit customer choice load to no more than 10% of the annual retail load for the preceding calendar year and to require the remaining 90% of annual retail load to be phased into cost-based rates.  The new legislation also requires utilities to meet certain energy efficiency and renewable portfolio standards and requires cost recovery of meeting those standards.  Management continues to conclude that I&M's rates for generation in Michigan are cost-based regulated.

Oklahoma Rate Matters

PSO Fuel and Purchased Power and its Possible Impact on AEP East companies and– Affecting PSO

The Oklahoma Industrial Energy Consumers appealed an ALJ recommendation in June 2008 regarding a pending fuel case involving the reallocation of $42 million of purchased power costs among AEP West companies

In 2004, intervenors and in 2002.  The Oklahoma Industrial Energy Consumers requested that PSO be required to refund this $42 million of reallocated purchased power costs through its fuel clause.  PSO had recovered the OCC staff argued that AEP had inappropriately under allocated off-system sales credits to PSO by $37$42 million forduring the period June 2000 to December 2004 under a FERC-approved allocation agreement.  An ALJ assigned to hear intervenor claims found that2007 through May 2008.  In August 2008, the OCC lacked authority to examine whether AEP deviated fromheard the FERC-approved allocation methodology for off-system sales marginsappeal and held that any such complaints should be addressed at the FERC.  In October 2007, the OCC adopted the ALJ’s recommendation and orally directed the OCC staff to explore filing a complaint at FERC alleging the allocation of off-system sales margins to PSOdecision is not in compliance with the FERC-approved methodology which could result in an adverse effect on future results of operations and cash flows for AEP Consolidated and the AEP East companies.  In June 2008, the ALJ issued a final recommendation and incorporated the prior finding that the OCC lacked authority to review AEP’s application of a FERC-approved methodology.  The OCC is scheduled to consider the final recommendation in August 2008.  To date, no claim has been asserted at the FERC and management continues to believe that the allocation is consistent with the FERC-approved agreement.pending.

In February 2006, the OCC enacted a rule, requiring the OCC staff to conduct prudence reviews on PSO’s generation and fuel procurement processes, practices and costs on a periodic basis.  PSO filed testimony in June 2007 covering a prudence review for the year 2005.  The OCC staff and intervenors filed testimony in September 2007, and hearings were held in November 2007.  The only major issue in the proceeding was the alleged under allocation of off-system sales credits under the FERC-approved allocation methodology, which previously was determined not to be jurisdictional to the OCC.  See “Allocation of Off-system Sales Margins” section within “FERC Rate Matters”.  Consistent with herthe prior recommendation,OCC determination, the ALJ found that the OCC lacked authority to alter the FERC-approved allocation methodology and that PSO’s fuel costs were prudent.  The intervenors appealed the ALJ recommendation and the OCC is scheduled to considerheard the ALJ’s findings and ruleappeal in August 2008.  In August 2008, the OCC filed a complaint at the FERC alleging that AEPSC inappropriately allocated off-system trading margins between the AEP East companies and the AEP West companies and did not properly allocate off-system trading margins within the AEP West companies.

In November 2007, PSO filed testimony in another proceeding to address its fuel costs for 2006.  In April 2008, intervenor testimony was filed again challenging the allocation of off-system sales credits during the portion of the year when the allocation was in effect.  Hearings were held in July 2008 and the OCC changed the scope of the proceeding from a prudence review to only a review of the mechanics of the fuel cost calculation.  No party contested PSO’s fuel cost calculationcalculation.  In August 2008, the OCC issued a final order that PSO’s calculations of fuel and an order is expected in August 2008.purchased power costs were accurate and are consistent with PSO’s fuel tariff.

In September 2008, the OCC initiated a review of PSO’s generation, purchased power and fuel procurement processes and costs for 2007.  Under the OCC minimum filing requirements, PSO is required to file testimony and supporting data within 60 days which will occur in the fourth quarter of 2008.  Management cannot predict the outcome of the pending fuel and purchased power cost recovery filings andor prudence reviews or whether a complaint will be filed at FERC regarding the off-system sales allocation issue.reviews.  However, PSO believes its fuel and purchased power procurement practices and costs were prudent and properly incurred and that it allocated off-system sales credits consistent with governing FERC-approved agreements.  If a complaint is filed at FERC resulting in an unfavorable decision, it could have an adverse effect on results of operations and cash flows.therefore are legally recoverable.

Red Rock Generating Facility – Affecting PSO

In July 2006, PSO announced an agreement with Oklahoma Gas and Electric Company (OG&E) to build a 950 MW pulverized coal ultra-supercritical generating unit.  PSO would own 50% of the new unit.  Under the agreement, OG&E would manage construction of the plant.  OG&E and PSO requested preapprovalpre-approval to construct the coal-fired Red Rock Generating Facility (Red Rock) and to implement a recovery rider.

In October 2007, the OCC issued a final order approving PSO’s need for 450 MWs of additional capacity by the year 2012, but rejected the ALJ’s recommendation and denied PSO’s and OG&E’s applications for construction preapproval.pre-approval.  The OCC stated that PSO failed to fully study other alternatives to a coal-fired plant.  Since PSO and OG&E could not obtain preapprovalpre-approval to build the coal-fired Red Rock, Generating Facility, PSO and OG&E canceledcancelled the third party construction contract and their joint venture development contract.  In June 2008, PSO has issued a request-for-proposal to meet its capacity and energy needs.

In December 2007, PSO filed an application at the OCC requesting recovery of the $21 million in pre-construction costs and contract cancellation fees associated with Red Rock.  In March 2008, PSO and all other parties in this docket signed a settlement agreement that provides for recovery of $11 million of Red Rock costs, and provides carrying costs at PSO’s AFUDC rate beginning in March 2008 and continuing until the $11 million is included in PSO’s next base rate case.  PSO will recover the costs over the expected life of the peaking facilities at the Southwestern Station, and include the costs in rate base beginning in its next base rate filing.  The settlement was filed with the OCC in March 2008.  The OCC approved the settlement in May 2008.  As a result of the settlement, PSO wrote off $10 million of its deferred pre-construction costs/cancellation fees in the first quarter of 2008.  In July 2008, PSO filed a base rate case which included $11 million of deferred Red Rock costs plus carrying charges at PSO’s AFUDC rate beginning in March 2008.  See “2008 Oklahoma Base Rate Filing” section below.

Oklahoma 2007 Ice Storms – Affecting PSO

In October 2007, PSO filed with the OCC requesting recovery of $13 million of operation and maintenance expense related to service restoration efforts after a January 2007 ice storm.  PSO proposed in its application to establish a regulatory asset of $13 million to defer the previously expensed January 2007 ice storm restoration costs and to amortize the regulatory asset coincident with gains from the sale of excess SO2 emission allowances.  In December 2007, PSO expensed approximately $70 million of additional storm restoration costs related to anotherthe December 2007 ice storm in December 2007.storm.

In February 2008, PSO entered into a settlement agreement for recovery of costs from both ice storms.  In March 2008, the OCC approved the settlement subject to an audit of the final December ice storm costs filed in July 2008.  As a result, PSO recorded an $81 million regulatory asset for ice storm maintenance expenses and related carrying costs less $9 million of amortization expense to offset recognition of deferred gains from sales of SO2 emission allowances.  Under the settlement agreement, PSO would apply proceeds from sales of excess SO2 emission allowances of an estimated $26 million to recover part of the ice storm regulatory asset.  The settlement also provided for PSO willto amortize and recover the remaining amount of the regulatory asset through a rider over a period of five years beginning in the fourth quarter of 2008.  The regulatory asset will earn a return of 10.92% on the unrecovered balance.

In June 2008, PSO adjusted its regulatory asset to true-up the estimated costs to reflect actual costs as of June 30, 2008.costs.  After the true-up, application of proceeds from to-date sales of excess SO2 emission allowances and carrying costs, the ice storm regulatory asset as of June 30, 2008 was $64 million.  In July 2008, PSO filed with the OCC to establish the recovery rider and the final recoverable December 2007 ice storm costs.  The estimate of future gains from the sale of SO2 emission allowances has significantly declined with the decrease in value of such allowances.  As a result, estimated collections from customers through the special storm damage recovery rider will be higher than the estimate in the settlement agreement.  Nonetheless, management believes thatIn July 2008, as required by the settlement provides for full recoveryagreement, PSO filed its reconciliation of the remaining deferral.December 2007 storm restoration costs along with a proposed tariff to recover the amounts not offset by the sales of SO2 emission allowances.  In September 2008, the OCC staff filed testimony supporting PSO’s filing with minor changes.  In October 2008, an ALJ recommended that PSO recover $62 million of the December 2007 storm restoration costs before consideration of emission allowance gains and carrying costs.  In October 2008, the OCC approved the filing which allows PSO to recover $62 million of the December 2007 storm restoration costs beginning in November 2008.

2008 Oklahoma Annual Fuel Factor Filing – Affecting PSO

In May 2008, pursuant to its tariff, PSO filed its annual update with the OCC for increases in the various service level fuel factors based on estimated increases in fuel costs, primarily natural gas and purchased power expenses, of approximately $300 million.  The request included recovery of $26 million in under-recovered deferred fuel.  In June 2008, PSO implemented the fuel factor increase.  Because of the substantial increase, the OCC held an administrative proceeding to determine whether the proposed charges were based upon the appropriate coal, purchased gas and purchased power prices and were properly computed.  In June 2008, the OCC ordered that PSO properly estimated the increase in natural gas prices, properly determined its fuel costs and, thus, should implement the increase.

2008 Oklahoma Base Rate Filing – Affecting PSO

In July 2008, PSO filed an application with the OCC to increase its base rates by $133 million on an annual basis.  PSO recovers costs related to new peaking units recently placed into service through the Generation Cost Recovery Rider (GCRR).  Upon implementation of the new base rates, PSO will recover these costs through the new base rates and the GCRR will terminate.  Therefore, PSO’s net annual requested increase in total revenues is actually $117 million.  The requested increase is based upon a test year ended February 29, 2008, adjusted for known and measurable changes through August 2008, which is consistent with the ratemaking treatment adopted by the OCC in PSO’s 2006 base rate case.  The proposed revenue requirement reflects a return on equity of 11.25%.  PSO expects hearings to begin in December 2008 and new base rates to become effective in the first quarter of 2009.
  In October 2008, the OCC staff, the Attorney General's office, and a group of industrial customers filed testimony recommending annual base rate increases of $86 million, $68 million and $29 million, respectively.  The differences are principally due to the use of recommended return on equity of 10.88%, 10% and 9.5% by the OCC staff, the Attorney General's office, and a group of industrial customers.  The OCC staff and the Attorney General's office recommended $22 million and $8 million, respectively, of costs included in the filing be recovered through the fuel adjustment clause and riders outside of base rates.

Louisiana Rate Matters

Louisiana Compliance Filing – Affecting SWEPCo

In connection with SWEPCo’s merger related compliance filings, the LPSC approved a settlement agreement in April 2008 that prospectively resolves all issues regarding claims that SWEPCo had over-earned its allowed return.  SWEPCo agreed to a formula rate plan (FRP) with a three-year term.  BeginningUnder the plan, beginning in August 2008, rates shall be established to allow SWEPCo to earn an adjusted return on common equity of 10.565%.  The adjustments are standard Louisiana rate filing adjustments.

If in the second and third year of the FRP, the adjusted earned return is within the range of 10.015% to 11.115%, no adjustment to rates is necessary.  However, if the adjusted earned return is outside of the above-specified range, an FRP rider will be established to increase or decrease rates prospectively.  If the adjusted earned return is less than 10.015%, SWEPCo will prospectively increase rates to collect 60% of the difference between 10.565% and the adjusted earned return.  Alternatively, if the adjusted earned return is more than 11.115%, SWEPCo will prospectively decrease rates by 60% of the difference between the adjusted earned return and 10.565%.  SWEPCo will not record over/under recovery deferrals for refund or future recovery under this FRP.

The settlement provides for a separate credit rider decreasing Louisiana retail base rates by $5 million prospectively over the entire three yearthree-year term of the FRP, which shall not affect the adjusted earned return in the FRP calculation.  This separate credit rider will cease effective August 2011.

In addition, the settlement provides for a reduction in generation depreciation rates effective October 2007.  SWEPCo will deferdeferred as a regulatory liability, the effects of the expected depreciation reduction through July 2008.  SWEPCo will amortize this regulatory liability over the three yearthree-year term of the FRP as a reduction to the cost of service used to determine the adjusted earned return.  In August 2008, the LPSC issued an order approving the settlement.

In April 2008, SWEPCo filed the first FRP which would increase its annual Louisiana retail rates by $11 million in August 2008 to earn an adjusted return on common equity of 10.565%.  In June 2008,accordance with the settlement, SWEPCo recorded a $3$4 million regulatory liability related to the reduction in generation depreciation rates.  The amount of the unamortized regulatory liability for the reduction in generation depreciation was $4 million as of September 30, 2008.  In August 2008, SWEPCo implemented the FRP rates, subject to refund, as the LPSC staff reviews SWEPCo’s FRP filing and the production depreciation study.

Stall Unit – Affecting SWEPCo

In May 2006, SWEPCo announced plans to build a new intermediate load, 500 MW, natural gas-fired, combustion turbine, combined cycle generating unit (the Stall Unit) at its existing Arsenal Hill Plant location in Shreveport, Louisiana.  SWEPCo submitted the appropriate filings to the PUCT, the APSC, the LPSC and the Louisiana Department of Environmental Quality to seek approvals to construct the unit.  The Stall Unit is currently estimated to cost $378 million, excluding AFUDC, and is expected to be in-service in mid-2010.

In March 2007, the PUCT approved SWEPCo’s request for a certificate for the facility based on a prior cost estimate.  In FebruarySeptember 2008, the LPSC staff submitted testimony in support of the Stall Unit and one intervenor submitted testimony opposing the Stall Unit dueapproved SWEPCo’s request for certification to the increase in cost.  The LPSC held hearings in April 2008.  In July 2008, an ALJ in the LPSC proceeding recommended approval ofconstruct the Stall Unit.  The APSC has not established a procedural schedule at this time.  The Louisiana Department of Environmental Quality issued an air permit for the unit in March 2008.  If SWEPCo does not receive appropriate authorizations and permits to build the Stall Unit, SWEPCo would seek recovery of the capitalized pre-construction costs including any cancellation fees.  As of JuneSeptember 30, 2008, SWEPCo has capitalized pre-construction costs of $106$158 million and has contractual construction commitments of an additional $191$145 million.  As of JuneSeptember 30, 2008, if the plant had been canceled,cancelled, cancellation fees of $60$61 million would have been required in order to terminate these construction commitments.  If SWEPCo canceledcancels the plant and cannot recover its capitalized costs, including any cancellation fees, it would have an adverse effect on future results of operationsnet income, cash flows and cash flows.possibly financial condition.

Turk Plant – Affecting SWEPCo

See “Turk Plant” section within Arkansas Rate Matters for disclosure.

Arkansas Rate Matters

Turk Plant – Affecting SWEPCo

In August 2006, SWEPCo announced plans to build the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas.  Ultra-supercritical technology uses higher temperatures and higher pressures to produce electricity more efficiently – thereby using less fuel and providing substantial emissions reductions.  SWEPCo submitted filings with the APSC, the PUCT and the LPSC seeking certification of the plant.  SWEPCo will own 73% of the Turk Plant and will operate the facility.  During 2007, SWEPCo signed joint ownership agreements with the Oklahoma Municipal Power Authority (OMPA), the Arkansas Electric Cooperative Corporation (AECC) and the East Texas Electric Cooperative (ETEC) for the remaining 27% of the Turk Plant.  The Turk Plant is currently estimated to cost $1.5 billion, excluding AFUDC, with SWEPCo’s portion estimated to cost $1.1 billion, excluding AFUDC.billion.  If approved on a timely basis, the plant is expected to be in-service in 2012.

In November 2007, the APSC granted approval to build the plant.  Certain landowners filed a notice of appeal to the Arkansas State Court of Appeals.  In March 2008, the LPSC approved the application to construct the Turk Plant.

In JulyAugust 2008, the PUCT approved a certificateissued an order approving the Turk Plant with the following four conditions: (a) the capping of convenience and necessity for construction of the plant.  We expect a written order in August 2008 which will also providecapital costs for the conditionsTurk Plant at the $1.5 billion projected construction cost, excluding AFUDC, (b) capping CO2 emission costs at $28 per ton through the year 2030, (c) holding Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers and (d) providing the PUCT all updates, studies, reviews, reports and analyses as previously required under the Louisiana and Arkansas orders.  An intervenor filed a motion for rehearing seeking reversal of the PUCT’s approval.decision.  SWEPCo filed a motion for rehearing stating that the two cost cap restrictions are unlawful.  In September 2008, the motions for rehearing were denied.  In October 2008, SWEPCo appealed the PUCT’s order regarding the two cost cap restrictions.  If the cost cap restrictions are upheld and construction or emissions costs exceed the restrictions, it could have a material adverse impact on future net income and cash flows.  In October 2008, an intervenor filed an appeal contending that the PUCT’s grant of a conditional Certificate of Public Convenience and Necessity for the Turk Plant was not necessary to serve retail customers.

SWEPCo is also working with the Arkansas Department of Environmental Quality for the approval of an air permit and the U.S. Army Corps of Engineers for the approval later this year.of a wetlands and stream impact permit.  Once SWEPCo receives the air permit, they will commence construction.  A request to stop pre-construction activities at the site was filed in Federal court by the same Arkansas landowners who appealed the APSC decision to the Arkansas State Court of Appeals.  In July 2008, the Federal court denied the request and the Arkansas landowners appealed the denial to the U.S. Court of Appeals.

In January 2008 and July 2008, SWEPCo filed applications for authority with the APSC to construct transmission lines necessary for service from the Turk Plant.  Several landowners filed for intervention status and one landowner also contended he should be permitted to re-litigate Turk Plant issues, including the need for the generation.  The APSC granted their intervention but denied the request to re-litigate the Turk Plant issues.  The landowner filed an appeal to the Arkansas State Court of Appeals in June 2008.

The Arkansas Governor’s Commission on Global Warming is scheduled to issue its final report to the Governor by November 1, 2008.  The Commission was established to set a global warming pollution reduction goal together with a strategic plan for implementation in Arkansas.  If legislation is passed as a result of the findings in the Commission’s report, it could impact SWEPCo’s proposal to build the Turk Plant.

If SWEPCo does not receive appropriate authorizations and permits to build the Turk Plant, SWEPCo could incur significant cancellation fees to terminate its commitments and would be responsible to reimburse OMPA, AECC and ETEC for their share of paid costs.  If that occurred, SWEPCo would seek recovery of its capitalized costs including any cancellation fees and joint owner reimbursements.  As of JuneSeptember 30, 2008, including the joint owners’ share, SWEPCo has capitalized approximately $407$448 million of expenditures and has significant contractual construction commitments for an additional $815$771 million.  As of JuneSeptember 30, 2008, if the plant had been canceled,cancelled, SWEPCo would have incurred cancellation fees of $60 million would have been required in order to terminate these construction commitments.$61 million.  If the Turk Plant does not receive all necessary approvals on reasonable terms and SWEPCo cannot recover its capitalized costs, including any cancellation fees, it would have an adverse effect on future results of operations,net income, cash flows and possibly financial condition.

Stall Unit – Affecting SWEPCo

See “Stall Unit” section within Louisiana Rate Matters for disclosure.

FERC Rate Matters

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

SECA Revenue Subject to Refund

Effective December 1, 2004, AEP eliminated transaction-based through-and-out transmission service (T&O) charges in accordance with FERC orders and collected at 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 31, 2006.  Intervenors objected to the temporary SECA rates, raising various issues.  As a result, the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund.  The AEP East companies paid SECA rates to other utilities at considerably lesser amounts than they collected.  If a refund is ordered, the AEP East companies would also receive refunds related to the SECA rates they paid to third parties.  The AEP East companies recognized gross SECA revenues of $220 million from December 2004 through March 2006 when the SECA rates terminated leaving the AEP East companies and ultimately their internal load retail customers to make up the short fall in revenues.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of recognized gross SECA revenues are as follows:

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

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

In September 2006, AEP filed briefs jointly with other affected companies noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part.  Management believes, based on advice of legal counsel, that the FERC should reject the ALJ’s initial decision because it contradicts prior related FERC decisions, which are presently subject to rehearing.  Furthermore, management believes the ALJ’s findings on key issues are largely without merit.  As a result,AEP and SECA ratepayers have been willing to engage with AEP in settlement discussions.  AEP has been engaged in settlement discussions in an effort to settle the SECA issue.  However, if the ALJ’s initial decision is upheld in its entirety, it could result in a disallowance of a large portion on any unsettled SECA revenues.

During 2006, based on anticipated settlements, the AEP East companies provided reserves of $37 million for net refunds for current and future SECA settlements.  After reviewing existing settlements the AEP East companies increased their reserves by an additionaltotaling $37 million and $5 million in December 2007.2006 and 2007, respectively, applicable to a total of $220 million of SECA revenues.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the provision are as follows:

  2007  2006 
Company (in millions) 
APCo $1.7  $12.0 
CSPCo  0.9   6.7 
I&M  1.0   7.0 
OPCo  1.3   9.1 

Completed and in-processAEP has completed settlements cover $107totaling $7 million of the $220applicable to $75 million of SECA revenues and will consume about $7 million ofrevenues.  The balance in the reserve for refund, leaving approximately $113future settlements as of September 2008 was $35 million.  In-process settlements total $3 million applicable to $37 million of SECA revenues.  Management believes that the available $32 million of reserves for possible refunds are sufficient to settle the remaining $108 million of contested SECA revenues and $35 million of refund reserves.revenues.

If the FERC adopts the ALJ’s decision and/or AEP cannot settle all of the remaining unsettled claims within the remaining amount reserved for refunds,refund, it will have an adverse effect on future results of operationsnet income and cash flows.  Based on advice of external FERC counsel, recent settlement experience and the expectation that most of the unsettled SECA revenues will be settled, management believes that the remaining reserve of $35$32 million is adequate to cover all remaining settlements.  However, management cannot predict the ultimate outcome of ongoing settlement discussions or future FERC proceedings or court appeals, if such are necessary.

The FERC PJM Regional Transmission Rate Proceeding

With the elimination of T&O rates, and the expiration of SECA rates and after considerable administrative litigation at the FERC in which AEP sought to mitigate the effect of the T&O rate elimination, the FERC failed to implement a regional rate in PJM.  As a result, the AEP East companies’ retail customers incur the bulk of the cost of the existing AEP east transmission zone facilities.  However, the FERC ruled that the cost of any new 500 kV and higher voltage transmission facilities built in PJM would be shared by all customers in the region.  It is expected that most of the new 500 kV and higher voltage transmission facilities will be built in other zones of PJM, not AEP’s zone.  The AEP East companies will need to obtain regulatory approvals for recovery of any costs of new facilities that are assigned to them.  AEP had requested rehearing of this order, which the FERC denied.  In February 2008, AEP filed a Petition for Review of the FERC orders in this case in the United States Court of Appeals.  Management cannot estimate at this time what effect, if any, this order will have on the AEP East companies’ future construction of new transmission facilities, results of operationsnet income and cash flows.

The AEP East companies filed for and in 2006 obtained increases in itstheir wholesale transmission rates to recover lost revenues previously applied to reduce those rates.  AEP has also sought and received retail rate increases in Ohio, Virginia, West Virginia and Kentucky.  As a result, AEP is now recovering approximately 85%80% of the lost T&O transmission revenues.  AEP received net SECA transmission revenues of $128 million in 2005.  I&M requested recovery of these lost revenues in its Indiana rate filing in January 2008 but does not expect to commence recovering the new rates until early 2009.  Future results of operationsnet income and cash flows will continue to be adversely affected in Indiana and Michigan until the remaining 15%20% of the lost T&O transmission revenues are recovered in retail rates.

The FERC PJM and MISO Regional Transmission Rate Proceeding

In the SECA proceedings, the FERC ordered the RTOs and transmission owners in the PJM/MISO region (the Super Region) to file, by August 1, 2007, a proposal to establish a permanent transmission rate design for the Super Region to be effective February 1, 2008.  All of the transmission owners in PJM and MISO, with the exception of AEP and one MISO transmission owner, elected to support continuation of zonal rates in both RTOs.  In September 2007, AEP filed a formal complaint proposing a highway/byway rate design be implemented for the Super Region where users pay based on their use of the transmission system.  AEP arguesargued the use of other PJM and MISO facilities by AEP is not as large as the use of AEP transmission by others in PJM and MISO.  Therefore, a regional rate design change is required to recognize that the provision and use of transmission service in the Super Region is not sufficiently uniform between transmission owners and users to justify zonal rates.  In January 2008, the FERC denied AEP’s complaint.  AEP filed a rehearing request with the FERC in March 2008.  Should this effort be successful, earnings could benefit for a certain period of time due to regulatory lag; however,lag until the AEP East companies would reduce future retail revenues in their next fuel or base rate proceedings.  Management is unable to predict the outcome of this case.

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

In July 2008, AEP filed an application with the FERC to increase its rates for wholesale transmission service within PJM.PJM by $63 million annually.  The filing seeks to implement a formula rate allowing annual adjustments reflecting future changes in AEP's cost of service.  The requested increase would result in additional annual revenues of approximately $9 million from nonaffiliated customers within PJM.  The remaining $54 million requested would be billed to the AEP East companies to be recovered in retail rates.  Retail rates for jurisdictions other than Ohio are not affected until the next base rate filing at FERC.  Retail rates for CSPCo and OPCo would be adjusted through the Transmission Cost Recovery Rider (TCRR) totaling approximately $10 million and $12 million, respectively.  The TCRR includes a true-up mechanism so CSPCo’s and OPCo’s net income will not be adversely affected by a FERC ordered transmission rate increase.  Other jurisdictions would be recoverable on a lag basis as base rates are changed.  AEP requested an effective date of October 1, 2008.  Retail rates are not immediately affected by the filing atIn September 2008, the FERC but retail rates in Ohio would reflectissued an order conditionally accepting AEP’s proposed formula rate, subject to a compliance filing, suspended the revised FERC transmission rate through the Transmission Cost Recovery Rider (TCRR) effective Januarydate until March 1, 2009 resulting in additional annual revenues of approximately $22 million.and established a settlement proceeding with an ALJ.  Management is unable to predict the outcome of this filing.

SPP Transmission Formula Rate Filing – Affecting PSO and SWEPCo

In June 2007, AEPSC filed revised tariffs to establish an up-to-date revenue requirement for SPP transmission services over the facilities owned by PSO and SWEPCo and to implement a transmission cost of service formula rate.  PSO and SWEPCo requested an effective date of September 1, 2007 for the revised tariff.  If approved as filed, the revised tariff will increase annual network transmission service revenues from nonaffiliated municipal and rural cooperative utilities in the AEP pricing zone of SPP by approximately $10 million.  In August 2007, the FERC issued an order conditionally accepting PSO’s and SWEPCo’s proposed formula rate, subject to a compliance filing, suspended the effective date until February 1, 2008 and established a hearing schedule and settlement judge proceedings.  New rates, subject to refund, were implemented in February 2008.  Multiple intervenors have protested or requested re-hearing of the order and settlement discussions are underway.  Management believes it has recognized the appropriate amount of revenues, subject to refund, since implementedbeginning in February 2008.    If the final refund exceeds the provisions it would adversely affect future net income and cash flows.  Management is unable to predict the outcome of this proceeding.

FERC Market Power Mitigation – Affecting APCo, CSPCo, I&M and OPCo

The FERC allows utilities to sell wholesale power at market-based rates if they can demonstrate that they lack market power in the markets in which they participate.  Sellers with market rate authority must, at least every three years, update their studies demonstrating lack of market power.  In December 2007, AEP filed its most recent triennial update.  In March and May 2008, the PUCO filed comments suggesting that the FERC should further investigate whether AEP continues to pass the FERC’s indicative screens for the lack of market power in PJM.  Certain industrial retail customers also urgedrequested the FERC to further investigate this matter.  AEP responded that its market power studies were performed in accordance with the FERC’s guidelines and continue to demonstrate lack of market power.  ManagementIn September 2008, the FERC issued an order accepting AEP’s market-based rates with minor changes and rejected the PUCO’s and the industrial retail customers’ suggestions to further investigate AEP’s lack of market power.

In an unrelated matter, in May 2008, the FERC issued an order in response to a complaint from the state of Maryland’s Public Service Commission to hold a future hearing to review the structure of the three pivotal market power supplier tests in PJM.  In September 2008, PJM filed a report on the results of the PJM stakeholder process concerning the three pivotal supplier market power tests which recommended the FERC not make major revisions to the test because the test is unable to predict the outcome of this proceeding; however,not unjust or unreasonable.

The FERC’s order will become final if no requests for rehearing are filed.  If a request for rehearing is filed and ultimately results in a further investigation by the FERC limitedwhich limits AEP’s ability to sell power at market basedmarket-based rates in PJM, it would result in an adverse effect on future off-system sales margins results of operations and cash flows.

Allocation of Off-system Sales Margins – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

In 2004, intervenors and the OCC staff argued that AEP had inappropriately under-allocated off-system sales credits to PSO by $37 million for the period June 2000 to December 2004 under a FERC-approved allocation agreement.  An ALJ assigned to hear intervenor claims found that the OCC lacked authority to examine whether AEP deviated from the FERC-approved allocation methodology for off-system sales margins and held that any such complaints should be addressed at the FERC.  In October 2007, the OCC adopted the ALJ’s recommendation and orally directed the OCC staff to explore filing a complaint at the FERC alleging the allocation of off-system sales margins to PSO is not in compliance with the FERC-approved methodology which could result in an adverse effect on future net income and cash flows for AEP Consolidated, the AEP East companies and the AEP West companies.  In June 2008, the ALJ issued a final recommendation and incorporated the prior finding that the OCC lacked authority to review AEP’s application of a FERC-approved methodology.  In June 2008, the Oklahoma Industrial Energy Consumers appealed the ALJ recommendation to the OCC.  In August 2008, the OCC heard the appeal and a decision is pending.  See “PSO Fuel and Purchased Power” section within “Oklahoma Rate Matters”.  In August 2008, the OCC filed a complaint at the FERC alleging that AEPSC inappropriately allocated off-system trading margins between the AEP East companies and the AEP West companies and did not properly allocate off-system trading margins within the AEP West companies.  The PUCT, the APSC and the Oklahoma Industrial Energy Consumers have all intervened in this filing.

TCC, TNC and the PUCT have been involved in litigation in the federal courts concerning whether the PUCT has the right to order a reallocation of off-system sales margins thereby reducing recoverable fuel costs in the final fuel  reconciliation in Texas under the restructuring legislation.  In 2005, TCC and TNC recorded provisions for refunds after the PUCT ordered such reallocation.  After receipt of favorable federal court decisions and the refusal of the U.S. Supreme Court to hear a PUCT appeal of the TNC decision, TCC and TNC reversed their provisions of $16 million and $9 million, respectively, in the third quarter of 2007.

Management cannot predict the outcome of these proceedings.  However, management believes its allocations were in accordance with the then-existing FERC-approved allocation agreements and additional off-system sales margins should not be retroactively reallocated.  The results of these proceedings could have an adverse effect on future net income and cash flows for AEP Consolidated, the AEP East companies and the AEP West companies.

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 2007 Annual Report should be read in conjunction with this report.

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

Certain Registrant Subsidiaries enter into standby letters of credit (LOCs) with third parties.  These LOCs cover items such as insurance programs, security deposits and debt service reserves.  These LOCs were issued in the Registrant Subsidiaries’ ordinary course of business under the two $1.5 billion credit facilities.facilities which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $46 million following its bankruptcy.

In April 2008, the Registrant Subsidiaries and certain other companies in the AEP System entered into a $650 million 3-year credit agreement and a $350 million 364-day credit agreement.agreement which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23 million and $12 million, respectively, following its bankruptcy.  As of JuneSeptember 30, 2008, $371$372 million of letters of credit were issued by Registrant Subsidiaries under the 3-year credit agreement to support variable rate demand notes.

At JuneSeptember 30, 2008, the maximum future payments of the LOCs were as follows:

      Borrower
Company Amount Maturity Sublimit
  (in thousands)     
$1.5 billion LOC:        
I&M $1,113  March 2009  N/A  
SWEPCo  4,000  December 2008  N/A  
         
$650 million LOC:        
APCo $126,717  June 2009 $300,000  
I&M  77,886  May 2009  230,000  
OPCo  166,899  June 2009  400,000  

Guarantees of Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation in the amount of approximately $65 million.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), an entity consolidated under FIN 46R.  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 2029 with final reclamation completed by 2036, at an estimated cost of approximately $39 million.  As of JuneSeptember 30, 2008, SWEPCo collected approximately $36$37 million through a rider for final mine closure costs, of which approximately $7 million is recorded in Other Current Liabilities and $29$30 million is recorded in Deferred Credits and Other 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

Contracts

All of the Registrant Subsidiaries enter into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  Prior to JuneSeptember 30, 2008, Registrant Subsidiaries entered into sale agreements which included indemnifications with a maximum exposure that was not significant for any individual Registrant Subsidiary.  There are no material liabilities recorded for any indemnifications.

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

Master Operating Lease

Certain Registrant Subsidiaries lease certain equipment under a master operating lease.  Under the lease agreement, the lessor is guaranteed to receive up to 87% of the unamortized balance of the equipment at the end of the lease term.  If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, the subsidiary hasRegistrant Subsidiaries have committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance.  Historically, at the end of the lease term the fair market value has been in excess of the unamortized balance.  At JuneSeptember 30, 2008, the maximum potential loss by subsidiaryRegistrant Subsidiary for these lease agreements assuming the fair market value of the equipment is zero at the end of the lease term is as follows:
  Maximum 
  Potential 
  Loss 
Company (in millions) 
APCo  $10 
CSPCo   5 
I&M   7 
OPCo   10 
PSO   6 
SWEPCo   6 

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.  AEP intends to maintain the lease for twenty years, via renewal options.  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 over the current lease term from approximately 84% to 77% of the projected fair market value of the equipment.

In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignment is accounted for as new operating leases for I&M and SWEPCo.  The future minimum lease obligation is $21$20 million for I&M and $24$23 million for SWEPCo as of JuneSeptember 30, 2008.  I&M and SWEPCo intend to renew these leases for the full remaining terms and have assumed the guarantee under the return-and-sale option.  I&M’s maximum potential loss related to the guarantee discussed above is approximately $12 million ($8 million, net of tax) and SWEPCo’s is approximately $14 million ($9 million, net of tax). assuming the fair market value of the equipment is zero at the end of the current lease term.  However, management believes that the fair market value would produce a sufficient sales price to avoid any loss.

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

CONTINGENCIES

Federal EPA Complaint and Notice of Violation – Affecting CSPCo

The Federal EPA, certain special interest groups and a number of states alleged that APCo, CSPCo, I&M and OPCo modified certain units at their coal-fired generating plants in violation of the NSR requirements of the CAA.  The alleged modifications occurred over a 20-year period.  Cases with similar allegations against CSPCo, Dayton Power and Light Company (DP&L) and Duke Energy Ohio, Inc. were also filed related to their jointly-owned units.

The AEP System settled their cases in 2007.  AIn October 2008, the court approved a consent decree for a settlement reached with the Sierra Club in a case is still pending that could affectinvolving CSPCo’s share of jointly-owned units at the Stuart Station.  The Stuart units, operated by DP&L, are equipped with SCR and flue gas desulfurization equipment (FGD or scrubbers) controls.  A trialUnder the terms of the settlement, the joint-owners agreed to certain emission targets related to NOx, SO2 and PM.  They also agreed to make energy efficiency and renewable energy commitments that are conditioned on liability issues was scheduledreceiving PUCO approval for August 2008.recovery of costs.  The Court issuedjoint-owners also agreed to forfeit 5,500 SO2 allowances and  provide $300 thousand to a staythird party organization to allow the parties to pursue settlement discussions.  Those discussions are ongoing.establish a solar water heater rebate program.  Another case involving a jointly-owned Beckjord unit had a liability trial in May 2008.  Following the trial, the jury found no liability for claims made against the jointly-owned Beckjord unit.

Management is unable to estimate the loss or range of loss related to any contingent liability, if any, CSPCo might have for civil penalties under the pending CAA proceedings for its jointly-owned plants.  If CSPCo does not prevail, management believes CSPCo can recover any capital and operating costs of additional pollution control equipment that may be required through market prices of electricity.  If CSPCo is unable to recover such costs or if material penalties are imposed, it would adversely affect future results of operations, cash flows and possibly financial condition.

Notice of Enforcement and Notice of Citizen Suit – Affecting SWEPCo

In March 2005, two special interest groups, Sierra Club and Public Citizen, filed a complaint in Federal District Courtfederal district court for the Eastern District of Texas alleging violations of the CAA at SWEPCo’s Welsh Plant.  In April 2008, the parties filed a proposed consent decree to resolve all claims in this case and in the pending appeal of the altered permit for the Welsh Plant.  The consent decree requires SWEPCo to install continuous particulate emission monitors at the Welsh Plant, secure 65 MW of renewable energy capacity by 2010, fund $2 million in emission reduction, energy efficiency or environmental mitigation projects by 2012 and pay a portion of plaintiffs’ attorneys’ fees and costs.  The consent decree was entered as a final order in June 2008.

In 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant.  In April 2005, TCEQ issued an Executive Director’s Report (Report) recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of approximately $228 thousand against SWEPCo.  In 2008, the matter was remanded to TCEQ to pursue settlement discussions.  The original Report contained a recommendation to limit the heat input on each Welsh unit to the referenced heat input contained within the state permit within 10 days of the issuance of a final TCEQ order and until the permit is changed.  SWEPCo had previously requested a permit alteration to remove the reference to a specific heat input value for each Welsh unit and to clarify the sulfur content requirement for fuels consumed at the plant.  A permit alteration was issued in March 2007.  In June 2007, TCEQ denied a motion to overturn the permit alteration.  The permit alteration was appealed to the Travis County District Court, but was resolved by entry of the consent decree in the federal citizen suit action, and dismissed with prejudice in July 2008.  Notice of an administrative settlement of the TCEQ enforcement action was published in June 2008.  The settlement requires SWEPCo to pay an administrative penalty of $49 thousand and to fund a supplemental environmental project in the amount of $49 thousand, and resolves all violations alleged by TCEQ.  The settlement will become final upon approval byIn October 2008, TCEQ approved the TCEQ.settlement.

In February 2008, the Federal EPA issued a Notice of Violation (NOV) based on alleged violations of a percent sulfur in fuel limitation and the heat input values listed in the previous state permit.  The NOV also alleges that the permit alteration issued by TCEQ was improper.  SWEPCo met with the Federal EPA to discuss the alleged violations in March 2008.  The Federal EPA did not object to the settlement of similar alleged violations in the federal citizen suit.

Management is unable to predict the timing of any future action by the Federal EPA or the effect of such action on results of operations,net income, cash flows or financial condition.

Carbon Dioxide (CO2) Public Nuisance Claims – Affecting AEP East companies and AEP West companies

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 dismissal of this lawsuit was appealed to the Second Circuit Court of Appeals.  Briefing and oral argument have concluded.  In April 2007, the U.S. Supreme Court issued a decision holding that the Federal EPA has authority to regulate emissions of CO2 and other greenhouse gases under the CAA, which may impact the Second Circuit’s analysis of these issues.  The Second Circuit requested supplemental briefs addressing the impact of the U.S. Supreme Court’s decision on this case.  Management believes the actions are without merit and intends to defend against the claims.

Alaskan Villages’ Claims – Affecting AEP East companies and AEP West companies

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska  filed a lawsuit in federal court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil & 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.  The defendants filed motions to dismiss the action.  The motions are pending before the court.  Management believes the action is without merit and intends to defend against the claims.

Clean Air Act Interstate Rule – Affecting Registrant Subsidiaries

In 2005, the Federal EPA issued a final rule, the Clean Air Interstate Rule (CAIR), that required further reductions in SO2 and NOx emissions and assists states developing new state implementation plans to meet 1997 national ambient air quality standards (NAAQS).  CAIR reduces regional emissions of SO2 and NOx (which can be transformed into PM and ozone) from power plants in the Eastern U.S. (29 states and the District of Columbia).  Reduction of both SO2 and NOx would be achieved through a cap-and-trade program.  In July 2008, the D.C. Circuit Court of Appeals vacatedissued a decision that would vacate the CAIR and remandedremand the rule to the Federal EPA.  We areIn September 2008, the Federal EPA and other parties petitioned for rehearing.  Management is unable to predict the outcome of the rehearing petitions or how the Federal EPA will respond to the remand which could be stayed or appealed to the U.S. Supreme Court.

In anticipation of compliance with CAIR in 2009, I&M purchased $8$9 million of annual CAIR NOx  allowances which are included in inventoryDeferred Charges and Other as of JuneSeptember 30, 2008.  The market value of annual CAIR NOx allowances decreased in the weeks following this court decision.  ManagementHowever, the weighted-average cost of these allowances is below market.  If CAIR remains vacated, management intends to seek partial recovery of the cost of purchased allowances.  If the recovery is denied, itAny unrecovered portion would have an adverse effect on future results of operationsnet income and cash flows.  None of the other Registrant Subsidiaries purchased any significant number of CAIR allowances.  SO2 and seasonal NOx allowances allocated to the Registrant Subsidiaries’ facilities under the Acid Rain Program and the NOX SIPstate implementation plan (SIP) Call will still be required to comply with existing CAA programs that were not affected by the court’s decision.

It is too early to determine the full implication of these decisions on environmental compliance strategy.  However, independent obligations under the CAA, including obligations under future state implementation plan submittals, and actions taken pursuant to the recent settlement of the NSR enforcement action, are consistent with the actions included in a least-cost CAIR compliance plan.  Consequently, management does not anticipate making any immediate changes in near-term compliance plans as a result of these court decisions.

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 (PCBs) and other hazardous and nonhazardous materials.  The Registrant Subsidiaries currently incur costs to safely dispose of these substances.

Superfund addresses clean-up of hazardous substances that have been released to the environment.  The Federal EPA administers the clean-up programs.  Several states have enacted similar laws.  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 requested remediation proposals from environmental consulting firms.  In May 2008, I&M issued a contract to one of the consulting firms andfirms.  I&M recorded approximately $1$4 million of expense.expense through September 30, 2008.  As the remediation work is completed, I&M’s cost may increase.  I&M cannot predict the amount of additional cost, if any.  At present, management’s estimates do not anticipate material cleanup costs for this site.

Cook Plant Unit 1 Fire and Shutdown – Affecting I&M

Cook Plant Unit 1 (Unit 1) is a 1,030 MW nuclear generating unit located in Bridgman, Michigan. In September 2008, I&M shut down Unit 1 due to turbine vibrations likely caused by blade failure which resulted in a fire on the electric generator.  This equipment is in the turbine building and is separate and isolated from the nuclear reactor.  The steam turbines that caused the vibration were installed in 2006 and are under warranty from the vendor.  The warranty provides for the replacement of the turbines if the damage was caused by a defect in the design or assembly of the turbines.  I&M is also working with its insurance company, Nuclear Electric Insurance Limited (NEIL), and turbine vendor to evaluate the extent of the damage resulting from the incident and the costs to return the unit to service.  Management cannot estimate the ultimate costs of the outage at this time.  Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process.  Management's preliminary analysis indicates that Unit 1 could resume operations as early as late first quarter/early second quarter of 2009 or as late as the second half of 2009, depending upon whether the damaged components can be repaired or whether they need to be replaced.
I&M maintains property insurance through NEIL with a $1 million deductible.  I&M also maintains a separate accidental outage policy with NEIL whereby, after a 12 week deductible period, I&M is entitled to weekly payments of $3.5 million during the outage period for a covered loss.  If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if the unit is not returned to service in a reasonable period of time, it could have an adverse impact on net income, cash flows and financial condition.

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.  At the end of 1991, PSO terminated the contract by paying a termination fee, as required by the agreement.  BNSF contends that the termination fee should have been calculated on the 1992 Rate, not the adjusted rate, resulting in an underpayment of approximately $9.5 million, including interest.

This matter was submitted to an arbitration board.  In April 2006, the arbitration board filed its decision, denying BNSF’s underpayments claim.  PSO filed a request for an order confirming the arbitration award and a request for entry of judgment on the award with the U.S. District Court for the Northern District of Oklahoma.  On July 14, 2006, the U.S. District Court issued an order confirming the arbitration award.  On July 24, 2006, BNSF filed a Motion to Reconsider the July 14, 2006 Arbitration Confirmation Order and Final Judgment and its Motion to Vacate and Correct the Arbitration Award with the U.S. District Court.  In February 2007, the U.S. District Court granted BNSF’s Motion to Reconsider.  PSO filed a substantive response to BNSF’s motion and BNSF filed a reply.  Management continues to defend its position that PSO paid BNSF all amounts owed.

Rail Transportation Litigation – Affecting PSO

In October 2008, the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsville, Texas, as co-owners of Oklaunion Plant, filed a lawsuit in United States District Court, Western District of Oklahoma against AEP alleging breach of contract and breach of fiduciary duties related to negotiations for rail transportation services for the plant.  The plaintiffs allege that AEP took the duty of the project manager, PSO, and operated the plant for the project manager and is therefore responsible for the alleged breaches.  Management intends to vigorously defend against these allegations.

FERC Long-term Contracts – Affecting AEP East companies and AEP West companies

In 2002, the FERC held a hearing related to a complaint filed by Nevada Power Company and Sierra Pacific Power Company (the Nevada utilities).  The complaint sought to break long-term contracts entered during the 2000 and 2001 California energy price spike which the customers alleged were “high-priced.”  The complaint alleged that AEP subsidiaries sold power at unjust and unreasonable prices because the market for power was allegedly dysfunctional at the time such contracts were executed.  In 2003, the FERC rejected the complaint.  In 2006, the U.S. Court of Appeals for the Ninth Circuit reversed the FERC order and remanded the case to the FERC for further proceedings.  That decision was appealed to the U.S. Supreme Court.  In June 2008, the U.S. Supreme Court affirmed the validity of contractually-agreed rates except in cases of serious harm to the public.  The U.S. Supreme Court affirmed the Ninth Circuit’s remand on two issues, market manipulation and excessive burden on consumers.  Management is unable to predict the outcome of these proceedings or their impact on future results of operationsnet income and cash flows.  The Registrant Subsidiaries asserted claims against certain companies that sold power to them, which was resold to the Nevada utilities, seeking to recover a portion of any amounts the Registrant Subsidiaries may owe to the Nevada utilities.

5.ACQUISITION

2008

None

2007

Darby Electric Generating Station – Affecting CSPCo

In November 2006, CSPCo agreed to purchase Darby Electric Generating Station (Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light Company, for $102 million and the assumption of liabilities of $2 million.  CSPCo completed the purchase in April 2007.  The Darby plant is located near Mount Sterling, Ohio and is a natural gas, simple cycle power plant with a generating capacity of 480 MW.

 6.BENEFIT PLANS

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

Components of Net Periodic Benefit Cost

The following tables provide the components of AEP’s net periodic benefit cost for the plans for the three and sixnine months ended JuneSeptember 30, 2008 and 2007:
  Other Postretirement   Other Postretirement 
Pension Plans Benefit Plans Pension Plans Benefit Plans 
Three Months Ended June 30, Three Months Ended June 30, Three Months Ended September 30, Three Months Ended September 30, 
2008 2007 2008 2007 2008 2007 2008 2007 
(in millions) (in millions) 
Service Cost$25 $23 $11 $11  $25  $24  $10  $11 
Interest Cost 62  57  28  26   62   59   28   26 
Expected Return on Plan Assets (84) (82) (28) (26)  (84)  (85)  (27)  (26)
Amortization of Transition Obligation -  -  7  7   -   -   7   6 
Amortization of Net Actuarial Loss 10  14  2  3   10   15   3   3 
Net Periodic Benefit Cost$13 $12 $20 $21  $13  $13  $21  $20 

  Other Postretirement   Other Postretirement 
Pension Plans Benefit Plans Pension Plans Benefit Plans 
Six Months Ended June 30, Six Months Ended June 30, Nine Months Ended September 30, Nine Months Ended September 30, 
2008 2007 2008 2007 2008 2007 2008 2007 
(in millions) (in millions) 
Service Cost$50 $47 $21 $21  $75  $72  $31  $32 
Interest Cost 125  116  56  52   187   176   84   78 
Expected Return on Plan Assets (168) (167) (56) (52)  (252)  (254)  (83)  (78)
Amortization of Transition Obligation -  -  14  14   -   -   21   20 
Amortization of Net Actuarial Loss 19  29  5  6   29   44   8   9 
Net Periodic Benefit Cost$26 $25 $40 $41  $39  $38  $61  $61 

The following tables provide the Registrant Subsidiaries’ net periodic benefit cost (credit) for the plans for the three and sixnine months ended JuneSeptember 30, 2008 and 2007:

   Other Postretirement   Other Postretirement 
 Pension Plans Benefit Plans Pension Plans Benefit Plans 
 Three Months Ended June 30, Three Months Ended June 30, Three Months Ended September 30, Three Months Ended September 30, 
 2008 2007 2008 2007 2008 2007 2008 2007 
Company (in thousands) (in thousands) 
APCo $834 $842 $3,700 $3,560  $834  $841  $3,797  $3,560 
CSPCo (349) (258) 1,499  1,491   (351)  (258)  1,545   1,491 
I&M 1,820  1,900  2,423  2,531   1,821   1,900   2,496   2,530 
OPCo 320  245  2,817  2,801   318   362   2,908   2,802 
PSO 508  424  1,387  1,430   509   425   1,420   1,431 
SWEPCo 936  747  1,376  1,419   935   747   1,411   1,420 

   Other Postretirement   Other Postretirement 
 Pension Plans Benefit Plans Pension Plans Benefit Plans 
 Six Months Ended June 30, Six Months Ended June 30, Nine Months Ended September 30, Nine Months Ended September 30, 
 2008 2007 2008 2007 2008 2007 2008 2007 
Company (in thousands) (in thousands) 
APCo $1,669 $1,684 $7,399 $7,120  $2,503  $2,525  $11,196  $10,680 
CSPCo (698) (515) 2,997  2,982   (1,049)  (773)  4,542   4,473 
I&M 3,641  3,800  4,846  5,061   5,462   5,700   7,342   7,591 
OPCo 639  490  5,633  5,603   957   1,088   8,541   8,405 
PSO 1,016  848  2,774  2,861   1,525   1,273   4,194   4,292 
SWEPCo 1,871  1,493  2,752  2,838   2,806   2,240   4,163   4,258 

AEP has significant investments in several trust funds to provide for future pension and OPEB payments.  All of the trust funds’ investments are well-diversified and managed in compliance with all laws and regulations.  The value of the investments in these trusts has declined due to the decreases in the equity and fixed income markets.  Although the asset values are currently lower, this decline has not affected the funds’ ability to make their required payments.

 7.BUSINESS SEGMENTS

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

 8.INCOME TAXES

The Registrant Subsidiaries adopted FIN 48 as of January 1, 2007.  As a result, the Registrant Subsidiaries recognized an increase in the liabilities for unrecognized tax benefits, as well as related interest expense and penalties, which was accounted for as a reduction to the January 1, 2007 balance of retained earnings by each Registrant Subsidiary.

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 2000.  However, AEP has filed refund claims with the IRS for years 1997 through 2000 for the CSW pre-merger tax period, which are currently being reviewed.  The Registrant Subsidiaries have completed the exam for the years 2001 through 2003 and have issues that will beare being pursued at the appeals level.  The returns for the years 2004 through 2006 are presently under audit by the IRS.  Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for income taxes have been made for potential liabilities resulting from such matters.  In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions.  Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations.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 does not believe that the ultimate resolution of these audits will materially impact results of operations.net income.  With few exceptions, the Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2000.

Federal Tax Legislation – Affecting APCo, CSPCo and OPCo

In 2005, the Energy Tax Incentives Act of 2005 was signed into law.  This act created a limited amount of tax credits for the building of IGCC plants.  The credit is 20% of the eligible property in the construction of a new plant or 20% of the total cost of repowering of an existing plant using IGCC technology.  In the case of a newly constructed IGCC plant, eligible property is defined as the components necessary for the gasification of coal, including any coal handling and gas separation equipment.  AEP announced plans to construct two new IGCC plants that may be eligible for the allocation of these credits.  AEP filed applications for the West Virginia and Ohio IGCC projects with the DOE and the IRS.  Both projects were certified by the DOE and qualified by the IRS.  However, neither project was awardedallocated credits during the first round of credit awards.  After one of the original credit recipients surrendered their credits in the Fall of 2007, the IRS announced a supplemental credit round for the Spring of 2008.  AEP filed a new application in 2008 for the West Virginia IGCC project and in July 2008 the IRS awardedallocated the project $134 million in credits subject to enteringcredits.  In September 2008, AEP entered into a memorandum of understanding with the IRS.IRS concerning the requirements of claiming the credits.

Federal Tax Legislation – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

In October 2008, the Emergency Economic Stabilization Act of 2008 (the Act) was signed into law.  The Act extended several expiring tax provisions and added new energy incentive provisions. The legislation impacted the availability of research credits, accelerated depreciation of smart meters, production tax credits and energy efficient commercial building deductions.  Management has evaluated the impact of the law change and the application of the law change will not materially impact net income, cash flows or financial condition.

State Tax Legislation – Affecting APCo, CSPCo, I&M and OPCo

In March 2008, the Governor of West Virginia signed legislation providing for, among other things, a reduction in the West Virginia corporate income tax rate from 8.75% to 8.5% beginning in 2009.  The corporate income tax rate could also be reduced to 7.75% in 2012 and 7% in 2013 contingent upon the state government achieving certain minimum levels of shortfall reserve funds.  Management has evaluated the impact of the law change and the application of the law change will not materially impact results of operations,net income, cash flows or financial condition.

9.       FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first sixnine months of 2008 were:
   Principal Interest Due   Principal Interest Due
Company Type of Debt Amount Rate Date Type of Debt Amount Rate Date
   (in thousands) (%)     (in thousands) (%)  
Issuances:                  
APCo Pollution Control Bonds $40,000  4.85 2019
APCo Pollution Control Bonds  30,000  4.85 2019
APCo Pollution Control Bonds $75,000 Variable 2036 Pollution Control Bonds  75,000  Variable 2036
APCo Pollution Control Bonds  50,275 Variable 2036 Pollution Control Bonds  50,275  Variable 2036
APCo Senior Unsecured Notes  500,000 7.00 2038 Senior Unsecured Notes  500,000  7.00 2038
CSPCo Senior Unsecured Notes  350,000 6.05 2018 Senior Unsecured Notes  350,000 ��6.05 2018
I&M Pollution Control Bonds  25,000 Variable 2019 Pollution Control Bonds  25,000  Variable 2019
I&M Pollution Control Bonds  52,000 Variable 2021 Pollution Control Bonds  52,000  Variable 2021
I&M Pollution Control Bonds  40,000 5.25 2025 Pollution Control Bonds  40,000  5.25 2025
OPCo Pollution Control Bonds  50,000 Variable 2014 Pollution Control Bonds  50,000  Variable 2014
OPCo Pollution Control Bonds  50,000 Variable 2014 Pollution Control Bonds  50,000  Variable 2014
OPCo Pollution Control Bonds  65,000 Variable 2036 Pollution Control Bonds  65,000  Variable 2036
OPCo Senior Unsecured Notes  250,000  5.75 2013
SWEPCo Senior Unsecured Notes  400,000 6.45 2019 Pollution Control Bonds  41,135  4.50 2011
SWEPCo Senior Unsecured Notes  400,000  6.45 2019

   Principal Interest Due   Principal Interest Due
Company Type of Debt Amount Paid Rate Date Type of Debt Amount Paid Rate Date
   (in thousands) (%)     (in thousands) (%)  
Retirements and Principal Payments:                  
APCo Senior Unsecured Notes $200,000 3.60 2008 Pollution Control Bonds $40,000   Variable 2019
APCo Pollution Control Bonds  40,000 Variable 2019 Pollution Control Bonds  30,000    Variable 2019
APCo Pollution Control Bonds  30,000 Variable 2019 Pollution Control Bonds  17,500   Variable 2021
APCo Pollution Control Bonds  17,500 Variable 2021 Pollution Control Bonds  50,275   Variable 2036
APCo Pollution Control Bonds  50,275 Variable 2036 Pollution Control Bonds  75,000    Variable 2037
APCo Pollution Control Bonds  75,000 Variable 2037 Senior Unsecured Notes  200,000   3.60 2008
APCo Other  7 13.718 2026 Other  11 13.718 2026
CSPCo Senior Unsecured Notes  52,000 6.51 2008 Pollution Control Bonds  48,550   Variable 2038
CSPCo Senior Unsecured Notes  60,000 6.55 2008 Pollution Control Bonds  43,695   Variable 2038
CSPCo Pollution Control Bonds  48,550 Variable 2038 Senior Unsecured Notes  52,000 6.51 2008
CSPCo Pollution Control Bonds  43,695 Variable 2038 Senior Unsecured Notes  60,000   6.55 2008
I&M Pollution Control Bonds  45,000 Variable 2009 Pollution Control Bonds  45,000 Variable 2009
I&M Pollution Control Bonds  25,000 Variable 2019 Pollution Control Bonds  25,000   Variable 2019
I&M Pollution Control Bonds  52,000 Variable 2021 Pollution Control Bonds  52,000   Variable 2021
I&M Pollution Control Bonds  50,000 Variable 2025 Pollution Control Bonds  50,000   Variable 2025
I&M Pollution Control Bonds  40,000 Variable 2025 Pollution Control Bonds  40,000   Variable 2025
I&M Pollution Control Bonds  50,000 Variable 2025 Pollution Control Bonds  50,000 Variable 2025
OPCo Notes Payable  1,463 6.81 2008 Pollution Control Bonds  50,000   Variable 2014
OPCo Notes Payable  6,000 6.27 2009 Pollution Control Bonds  50,000   Variable 2016
OPCo Pollution Control Bonds  50,000 Variable 2014 Pollution Control Bonds  50,000   Variable 2022
OPCo Pollution Control Bonds  50,000 Variable 2016 Pollution Control Bonds  35,000   Variable 2022
OPCo Pollution Control Bonds  50,000 Variable 2022 Pollution Control Bonds  65,000   Variable 2036
OPCo Pollution Control Bonds  35,000 Variable 2022 Notes Payable  1,463 6.81 2008
OPCo Pollution Control Bonds  65,000 Variable 2036 Notes Payable  12,000 6.27 2009
PSO Pollution Control Bonds  33,700 Variable 2014 Pollution Control Bonds  33,70 Variable 2014
SWEPCo Notes Payable  1,500 Variable 2008 Pollution Control Bonds  41,135 Variable 2011
SWEPCo Notes Payable  2,203 4.47 2011 Notes Payable  1,500 Variable 2008
SWEPCo Notes Payable  3,304 4.47 2011

In October 2008, SWEPCo retired $113 million of 5.25% Notes Payable due in 2043.

As of JuneSeptember 30, 2008, OPCo and SWEPCo had $218 million and $95$54 million, respectively, of tax-exempt long-term debt sold at auction rates that reset every 35 days.  These auction rates ranged from 11.117% to 13% for OPCo.  SWEPCo’s rate was 4.353%.  OPCo's $218 million of debt relates to a lease structure with JMG that OPCo is unable to refinance at this time.  In order to refinance this debt, OPCo needs the lessor's consent.  This debt is insured by bond insurers previously AAA-rated, namely Ambac Assurance Corporation and Financial Guaranty Insurance Co.  Due to the exposure that these bond insurers havehad in connection with recent developments in the subprime credit market, the credit ratings of these insurers have beenwere downgraded or placed on negative outlook.  These market factors have contributed to higher interest rates in successful auctions and increasing occurrences of failed auctions, including many of the auctions of tax-exempt long-term debt.  Consequently, the Registrant Subsidiaries chose to exit the auction-rate debt market.  The instruments under which the bonds are issued allow for conversion to other short-term variable-rate structures, term-put structures and fixed-rate structures.  Through JuneSeptember 30, 2008, the Registrant Subsidiaries reduced their outstanding auction rate securities.  Management plans to continue this conversion and refunding process for the remaining $313$272 million to other permitted modes, including term-put structures, variable-rate and fixed-rate structures, during the second half of 2008 to lower interest rates as such opportunities arise.

As of JuneSeptember 30, 2008, $367 million of the prior auction rate debt was issued in a weekly variable rate mode supported by letters of credit at variable rates ranging from 1.45%6.5% to 1.68%8.25% and $222$333 million was issued at fixed rates ranging from 4.85%4.5% to 5.25%.  As of JuneSeptember 30, 2008, trustees held, on behalf of the Registrant Subsidiaries, approximately $400$330 million of their reacquired auction rate tax-exempt long-term debt which management plans to reissue to the public as market conditions permit.  The following table shows the current status of debt which was issued as auction rate debt at December 31, 2007:

   Remarketed at    Remarketed at    Remains at      Remarketed at   Remarketed at   Remains at  
   Fixed Rates    Variable Rates    Auction Rate      Fixed Rates   Variable Rates Variable Rate Auction Rate Held by
   During the First    During the First Variable Rate  at Held by    During the First Fixed Rate at During the First at at Trustee at
 Retired in Six Months of Fixed Rate at  Six Months of at  June 30, Trustee at  Retired in Nine Months of September 30, Nine Months of September 30, September 30, September 30,
 2008 2008 June 30, 2008  2008 June 30, 2008  2008 June 30, 2008  2008 2008 2008 2008 2008 2008 2008
Company (in thousands)    (in thousands)    (in thousands)  (in thousands)   (in thousands)   (in thousands)
APCo $- $-  -% $75,000  1.62% $- $87,500  $-  $30,000  4.85% $75,000  8.00% $-  $17,500 
APCo  -  -  -%  50,275  1.68%  -  -   -   40,000  4.85%  50,275  8.05%  -   - 
CSPCo  -  56,000  5.10%  -  -%  -  92,245   -   56,000  5.10%  -  -  -   92,245 
CSPCo  -  44,500  4.85%  -  -%  -  -   -   44,500  4.85%  -  -  -   - 
I&M  45,000  40,000  5.25%  52,000  1.57%  -  100,000   45,000   40,000  5.25%  52,000  7.75%  -   100,000 
I&M  -  -  -%  25,000  1.50%  -  -   -   -  -  25,000  8.25%  -   - 
OPCo  -  -  -%  65,000  1.60%  218,000  85,000   -   -  -  65,000  6.50%  218,000   85,000 
OPCo  -  -  -%  50,000  1.45%  -  -   -   -  -  50,000  7.83%  -   - 
OPCo  -  -  -%  50,000  1.47%  -  -   -   -  -  50,000  7.50%  -   - 
PSO  -  -  -%  -  -%  -  33,700   -   -  -  -  -  -   33,700 
SWEPCo  -  81,700  4.95%  -  -%  94,635  -   -   81,700  4.95%  -  -  53,500   - 
SWEPCo  -   41,135  4.50%  -  -  -   - 
                                           
Total $45,000 $222,200     $367,275     $312,635 $398,445  $45,000  $333,335    $367,275    $271,500  $328,445 

Lines of Credit

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 corporate borrowing program 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 JuneSeptember 30, 2008 and December 31, 2007 are 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 sixnine months ended JuneSeptember 30, 2008 are described in the following table:

         Loans            Loans   
 Maximum Maximum Average Average (Borrowings) Authorized  Maximum Maximum Average Average (Borrowings) Authorized 
 Borrowings Loans to Borrowings Loans to to/from Utility Short-Term  Borrowings Loans to Borrowings Loans to to/from Utility Short-Term 
 from Utility Utility from Utility Utility Money Money Pool as of Borrowing  from Utility Utility from Utility Utility Money Money Pool as of Borrowing 
 Money Pool Money Pool Money Pool Pool June 30, 2008 Limit  Money Pool Money Pool Money Pool Pool September 30, 2008 Limit 
Company (in thousands)  (in thousands) 
APCo $307,226 $269,987 $226,292 $187,192 $(103,802) $600,000   $307,226  $269,987  $188,985  $187,192  $(93,558) $600,000 
CSPCo  238,172  150,358  157,569  65,413  25,199   350,000    238,172   150,358   157,569   53,962   21,833   350,000 
I&M  345,064  -  174,380  -  (272,707)  500,000    345,064   -   195,582   -   (224,071)  500,000 
OPCo  415,951  -  165,436  -  (173,833)  600,000    415,951   82,486   174,840   64,127   39,758   600,000 
PSO  128,114  59,384  61,023  29,811  (110,981)  300,000    149,278   59,384   72,688   29,811   (125,029)  300,000 
SWEPCo  168,495  300,525  87,426  273,118  300,525   350,000    168,495   300,525   87,426   219,159   195,628   350,000 

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:
 Six Months Ended June 30,  Nine Months Ended September 30, 
 2008  2007  2008  2007 
Maximum Interest Rate  5.37%  5.46%  5.37%  5.94%
Minimum Interest Rate  2.91%  5.30%  2.91%  5.30%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the sixnine months ended JuneSeptember 30, 2008 and 2007 are summarized for all Registrant Subsidiaries in the following table:

 Average Interest Rate for Funds  Average Interest Rate for Funds  Average Interest Rate for Funds  Average Interest Rate for Funds 
 Borrowed from  Loaned to  Borrowed from  Loaned to 
 the Utility Money Pool for the  the Utility Money Pool for the  the Utility Money Pool for the  the Utility Money Pool for the 
 Six Months Ended June 30,  Six Months Ended June 30,  Nine Months Ended September 30,  Nine Months Ended September 30, 
 2008  2007  2008  2007  2008  2007  2008  2007 
Company               
APCo  3.86% 5.36% 3.25% -%  3.62%  5.41%  3.25%  5.84%
CSPCo  3.66% 5.37% 2.93% 5.33%  3.66%  5.48%  2.99%  5.39%
I&M  3.30% 5.35% -% -%  3.19%  5.38%  -%  5.84%
OPCo  3.39% 5.35% -% 5.43%  3.24%  5.39%  3.62%  5.43%
PSO  3.03% 5.36% 4.53% -%  3.04%  5.47%  4.53%  -%
SWEPCo  3.36% 5.36% 2.93% 5.34%  3.36%  5.54%  3.01%  5.34%

Short-term Debt

The Registrant Subsidiaries’ outstanding short-term debt was as follows:

   June 30, 2008 December 31, 2007    September 30, 2008 December 31, 2007
   Outstanding Interest Outstanding Interest    Outstanding Interest Outstanding Interest
 Type of Debt Amount Rate Amount Rate  Type of Debt Amount Rate (a) Amount Rate (a)
Company   (in thousands)   (in thousands)      (in thousands)   (in thousands)  
OPCo Commercial Paper – JMG $- -%$701 5.35% Commercial Paper – JMG (b) $-  -% $701  5.35%
SWEPCo Line of Credit – Sabine Mining Company  7,039 3.25% 285 5.25% Line of Credit – Sabine Mining Company (c) 9,520  7.75% 285  5.25%

(a)Weighted average rate.
(b)This commercial paper is specifically associated with the Gavin Scrubber and is backed by a separate credit facility.
(c)Sabine Mining Company is consolidated under FIN 46R.

Credit Facilities

In April 2008, the Registrant Subsidiaries and certain other companies in the AEP System entered into a $650 million 3-year credit agreement and a $350 million 364-day credit agreement.agreement which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23 million and $12 million, respectively, following its bankruptcy.  Under the facilities, letters of credit may be issued.  As of JuneSeptember 30, 2008, $371$372 million of letters of credit were issued by Registrant Subsidiaries under the 3-year credit agreement to support variable rate demand notes.

 
 
 


COMBINED MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the registrants’ management’s discussion and analysis.  The information in this section completes the information necessary for management’s discussion and analysis of financial condition and results of operationsnet income and is meant to be read with (i) Management’s Financial Discussion and Analysis, (ii) financial statements and (iii) footnotes of each individual registrant.  The combined Management’s Discussion and Analysis of Registrant Subsidiaries section of the 2007 Annual Report should also be read in conjunction with this report.

Market Impacts

In recent months, the world and U.S. economies have experienced significant slowdowns.  These economic slowdowns have impacted and will continue to impact the Registrant Subsidiaries’ residential, commercial and industrial sales. Concurrently, the financial markets have become increasingly unstable and constrained at both a global and domestic level.  This systemic marketplace distress is impacting the Registrant Subsidiaries’ access to capital, liquidity, asset valuations in trust funds, creditworthy status of customers, suppliers and trading partners and cost of capital.  AEP’s financial staff actively manages these factors with oversight from the risk committee.  The uncertainties in the credit markets could have significant implications since the Registrant Subsidiaries rely on continuing access to capital to fund operations and capital expenditures.

The current credit markets are constraining the Registrant Subsidiaries’ ability to issue new debt and refinance existing debt.  Approximately $120 million and $300 million of AEP Consolidated’s $16 billion of long-term debt as of September 30, 2008 will mature in the remainder of 2008 and 2009, respectively.  I&M and OPCo have $50 million and $37 million, respectively, maturing in 2008.  APCo, OPCo and PSO have $150 million, $82 million and $50 million, respectively, maturing in 2009.  Management intends to refinance these maturities.  To support its operations, AEP has $3.9 billion in aggregate credit facility commitments.  These commitments include 27 different banks with no bank having more than 10% of the total bank commitments.  Short-term funding for the Registrant Subsidiaries comes from AEP’s commercial paper program credit facilities which supports the Utility Money Pool.  In September 2008 and October 2008, AEP borrowed $600 million and $1.4 billion, respectively, under the credit facilities to enhance its cash position during this period of market disruptions.  This money can be loaned to the Registrant Subsidiaries through the Utility Money Pool.

Management cannot predict the length of time the current credit situation will continue or its impact on future operations and the Registrant Subsidiaries’ ability to issue debt at reasonable interest rates.  However, when market conditions improve, management plans to repay the amounts drawn under the credit facilities, re-enter the commercial paper market and issue long-term debt.  If there is not an improvement in access to capital, management believes that the Registrant Subsidiaries have adequate liquidity, through the Utility Money Pool, to support their planned business operations and construction programs through 2009.

AEP has significant investments in several trust funds to provide for future payments of pensions and OPEB. I&M has significant investments in several trust funds to provide for future payments of nuclear decommissioning and spent nuclear fuel disposal.  All of the trust funds’ investments are well-diversified and managed in compliance with all laws and regulations.  The value of the investments in these trusts has declined due to the decreases in the equity and fixed income markets.  Although the asset values are currently lower, this has not affected the funds’ ability to make their required payments.  As of September 30, 2008, the decline in pension asset values will not require a contribution to be made in 2008 or 2009.

On behalf of the Registrant Subsidiaries, AEPSC enters into risk management contracts with numerous counterparties.  Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily. AEP’s risk management organization monitors these exposures on a daily basis to limit the Registrant Subsidiaries’ economic and financial statement impact on a counterparty basis.

Sources of Funding

Short-term funding for the Registrant Subsidiaries comes from AEP’s commercial paper program under two $1.5 billion revolvingThe credit facilities whichthat support the Utility Money Pool.Pool were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $46 million following its bankruptcy.  In March 2008, these credit facilities were amended so that $750 million may be issued under each credit facility as letters of credit (LOC).  Certain companies within the AEP System including the Registrant Subsidiaries operate the Utility Money Pool to minimize external short-term funding requirements.  The Registrant Subsidiaries also sell accounts receivable to provide liquidity.  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-leaseback, leasing arrangements and additional capital contributions from AEP.

In April 2008, the Registrant Subsidiaries and certain other companies in the AEP System entered into a $650 million 3-year credit agreement and a $350 million 364-day credit agreement.agreement which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $23 million and $12 million, respectively, following its bankruptcy.  The Registrant Subsidiaries may issue LOCs under the credit facilities.  Each subsidiary has a borrowing/LOC limit under the credit facilities.  As of JuneSeptember 30, 2008, a total of $371$372 million of LOCs were issued under the 3-year credit agreement to support variable rate demand notes.  The following table shows each Registrant Subsidiaries’ borrowing/LOC limit under each credit facility and the outstanding amount of LOCs for the $650 million facility.

     LOC Amount      LOC Amount 
     Outstanding      Outstanding 
 $650 million $350 million Against      Against 
 Credit Facility Credit Facility $650 million  
$650 million
 
$350 million
 $650 million 
 Borrowing/LOC Borrowing/LOC Agreement at  Credit Facility 
Credit Facility
 Agreement at 
 Limit Limit June 30, 2008  
Borrowing/LOC
Limit
 
Borrowing/LOC
Limit
 September 30, 2008 
Company (in millions)  (in millions) 
APCo  $300  $150  $127   $300  $150  $127 
CSPCo   230   120   -    230   120   - 
I&M   230   120   77    230   120   78 
OPCo   400   200   167    400   200   167 
PSO   65   35   -    65   35   - 
SWEPCo   230   120   -    230   120   - 

At JuneSeptember 30, 2008, there were no outstanding amounts under the $350 million facility.

Credit Markets

Management believesTo the extent financing is unavailable due to the challenging credit markets, the Registrant Subsidiaries throughwill rely upon cash flows from operations and access to the Utility Money Pool have adequate liquidity underto fund their debt maturities, continuing operations and capital expenditures.

In the first quarter of 2008, due to the exposure that bond insurers like Ambac Assurance Corporation and Financial Guaranty Insurance Co. had in connection with developments in the subprime credit facilitiesmarket, the credit ratings of those insurers were downgraded or placed on negative outlook.  These market factors contributed to higher interest rates in successful auctions and the ability to issueincreasing occurrences of failed auctions for tax-exempt long-term debt insold at auction rates.  Consequently, management chose to exit the current credit markets.auction-rate debt market.  As of JuneSeptember 30, 2008, OPCo had $218 million (rates range from 11.117% to 13%) and SWEPCo had $95$54 million (rate of 4.353%) outstanding of tax-exempt long-term debt sold at auction rates that reset every 35 days.  Approximately $218 million of this debt relates to a lease structure with JMG that OPCo is unable to refinance at this time.  In order to refinance this debt, OPCo needs the lessor's consent.  This debt is insured by bond insurers previously AAA-rated namely Ambac Assurance Corporation and Financial Guaranty Insurance Co.  Due to the exposure that these bond insurers have in connection with developments in the subprime credit market, the credit ratings of these insurers have been downgraded or placed on negative outlook.  These market factors have contributed to higher interest rates in successful auctions and increasing occurrences of failed auctions, including many of the auctions of tax-exempt long-term debt.insurers.  The instruments under which the bonds are issued allow us to convertfor their conversion to other short-term variable-rate structures, term-put structures and fixed-rate structures.  Through June 30, 2008, the Registrant Subsidiaries reduced their outstanding auction rate securities.  Management plans to continue the conversion and refunding process for the remaining $313 million to other permitted modes, including term-put structures, variable-rate and fixed-rate structures, duringas opportunities arise.  Through September 30, 2008, the second half of 2008 to lower interest rates as such opportunities arise.Registrant Subsidiaries reduced their outstanding auction rate securities.

As of JuneSeptember 30, 2008, trustees held, on behalf of the Registrant Subsidiaries, approximately $400$330 million of their reacquired auction rate tax-exempt long-term debt which management plans to reissue to the public as the market permits.  The following table shows the current status of debt that was issued as auction rate at December 31, 2007 by Registrant Subsidiary.

   Remarketed at     
   Fixed or        Remarketed at     
   Variable Rates Remains in Held    Fixed or Remains in Held 
 Retired During the First Auction Rate at by Trustee at  Retired Variable Rates Auction Rate at by Trustee at 
 in 2008 Half of 2008 June 30, 2008 June 30, 2008  in 2008 During 2008 September 30, 2008 September 30, 2008 
Company (in millions)  (in millions) 
APCo  $-  $125  $-  $88   $-  $195  $-  $18 
CSPCo   -   101   -   92    -   101   -   92 
I&M   45   117   -   100    45   117   -   100 
OPCo   -   165   218   85    -   165   218   85 
PSO   -   -   -   34    -   -   -   34 
SWEPCo   -   82   95   -    -   123   54   - 

APCo, I&M and OPCo issued $125 million, $77 million and $165 million, respectively, of weekly variable rate debt.  As of JuneSeptember 30, 2008, the variable rates ranged from 1.45%6.5% to 1.68%8.25%.  APCo issued fixed rate debt of $70 million at 4.85% until 2019.  CSPCo issued fixed rate debt of $45 million at 4.85% until 2012 and $56 million at 5.1% until 2013.  I&M issued $40 million of fixed rate debt at 5.25% due 2025.  SWEPCo remarketed $82 million of fixed rate debt at 4.95% due 2018.2018 and issued $41 million of fixed rate debt at 4.5% through 2011.

Budgeted ConstructionSales of Receivable Agreement

In October 2008, AEP Credit renewed its $600 million sale of receivables agreement through October 2009.  AEP Credit purchases accounts receivable from the Registrant Subsidiaries.

Capital Expenditures

Revised construction
Due to recent credit market instability, management is currently reviewing projections for capital expenditures for the Registrant Subsidiaries2009 through 2010.  Management plans to identify reductions of approximately $750 million for 2009 across the AEP System.  Management is evaluating possible additional capital reductions for 2010.  Management is also reviewing projections for operation and 2010 are:maintenance expense.  Management's intent is to keep operation and maintenance expense flat in 2009 as compared to 2008.

  Estimated Construction Expenditures 
  2009  2010 
Company (in millions) 
APCo $583.2  $474.4 
CSPCo  311.7   308.3 
I&M  457.7   496.8 
OPCo  441.1   410.9 
PSO  257.2   419.2 
SWEPCo  710.3   681.0 

The budgeted amounts increased for I&M and SWEPCo and decreased for APCo, CSPCo, OPCo and PSO.

Significant Factors

Ohio Electric Security Plan Filings

In April 2008, the Ohio legislature passed Senate Bill 221, which amends the restructuring law effective July 31, 2008 and requires electric utilities to adjust their rates by filing an Electric Security Plan (ESP).  Electric utilities may file an ESP with a fuel cost recovery mechanism.  Electric utilities also have an option to file a Market Rate Offer (MRO) for generation pricing.  AAn MRO, from the date of its commencement, could transition CSPCo and OPCo to full market rates no sooner than six years and no later than ten years.years after the PUCO approves an MRO.  The PUCO has the authority to approve or modify the utilities’ ESP request.  The PUCO is required to approve an ESP if, in the aggregate, the ESP is more favorable to ratepayers than the MRO.  Both alternatives involve a “substantially excessive earnings” test based on what public companies, including other utilities with similar risk profiles, earn on equity.  Management has preliminarily concluded, pending the issuance of final rules by the PUCO and the outcome of the ESP proceeding, that CSPCo’s and OPCo’s generation/supply operations are not subject to cost-based rate regulation accounting.  However, if a fuel cost recovery mechanism is implemented within the ESP, CSPCo’s and OPCo’s fuel and purchased power operations would be subject to cost-based rate regulation accounting.  Management is unable to predict the financial statement impact of the restructuring legislation until the PUCO acts on specific proposals made by CSPCo and OPCo in their ESPs.

In July 2008, within the parameters of the ESPs, CSPCo and OPCo filed with the PUCO to establish rates for 2009 through 2011.  CSPCo and OPCo did not file MROs.  CSPCo and OPCo did not file MROs.an optional MRO.  CSPCo and OPCo each requested an annual rate increase for 2009 through 2011 that would not exceed approximately 15% per year.  A significant portion of the requested increases results from the implementation of a fuel cost recovery mechanism (which excludes off-system sales) that primarily includes fuel costs, purchased power costs including mandated renewable energy, consumables such as urea, other variable production costs and gains and losses on sales of emission allowances.  The increases in customer bills related to the fuelfuel-purchased power cost recovery mechanism would be phased-in over the three year period from 2009 through 2011.  EffectiveIf the ESP is approved as filed, effective with January 1, 2009 billings, CSPCo and OPCo will defer theany fuel cost under-recoveries and related carrying costs for future recoveryrecovery.  The under-recoveries and related carrying costs that exist at the end of 2011 will be recovered over seven years from 2012 through 2018.  In addition to the fuel cost recovery mechanisms, the requested increases would also recover incremental carrying costs associated with environmental costs, Provider of Last Resort (POLR) charges to compensate for the risk of customers changing electric suppliers, automatic increases for unexpecteddistribution reliability costs and reliabilityfor unexpected non-fuel generation costs.  The filings also include programs for smart metering initiatives and economic development and mandated energy efficiency and peak demand reduction programs.  Management expectsIn September 2008, the PUCO issued a finding and order tentatively adopting rules governing MRO and ESP applications.  CSPCo and OPCo filed their ESP applications based on proposed rules and requested waivers for portions of the proposed rules.  The PUCO decision ondenied the ESP filingswaiver requests in September 2008 and ordered CSPCo and OPCo to submit information consistent with the fourth quartertentative rules.  In October 2008, CSPCo and OPCo submitted additional information related to proforma financial statements and information concerning CSPCo and OPCo’s fuel procurement process.  In October 2008, CSPCo and OPCo filed an application for rehearing with the PUCO to challenge certain aspects of 2008.the proposed rules.

Within the ESPs, CSPCo and OPCo would also recover existing regulatory assets of $45$46 million and $36$38 million, respectively, for customer choice implementation and line extension carrying costs.  In addition, CSPCo and OPCo would recover related unrecorded equity carrying costs of $28$30 million and $19$21 million, respectively.  Such costs would be recovered over an 8 year8-year period beginning January 2011.  Hearings are scheduled for November 2008 and an order is expected in the fourth quarter of 2008.  Failure of the PUCO to ultimately approve the recovery of the regulatory assets would have an adverse effect on future results of operations and cash flows.

FERC Market Power Mitigation

The FERC allows utilities to sell wholesale power at market-based rates if they can demonstrate that they lack market power in the markets in which they participate.  Sellers with market rate authority must, at least every three years, update their studies demonstrating lack of market power.  In December 2007, AEP filed its most recent triennial update.  In March and May 2008, the PUCO filed comments suggesting that the FERC should further investigate whether AEP continues to pass the FERC’s indicative screens for the lack of market power in PJM.  Certain industrial retail customers also urged the FERC to further investigate this matter.  AEP responded that its market power studies were performed in accordance with the FERC’s guidelines, and continue to demonstrate lack of market power.  Management is unable to predict the outcome of this proceeding; however, if a further investigation by the FERC limited AEP’s ability to sell power at market based rates in PJM, it would result in an adverse effect on future off-system sales margins, results of operationsnet income and cash flows.

New Generation

In 2008, AEP completed or is in various stages of construction of the following generation facilities:
                Commercial                Commercial
     Total        Nominal Operation     Total        Nominal Operation
Operating Project   Projected        MW Date Project   Projected        MW Date
Company Name Location Cost (a) CWIP (b) Fuel Type Plant Type Capacity (Projected) Name Location Cost (a) CWIP (b) Fuel Type Plant Type Capacity (Projected)
     (in millions) (in millions)             (in millions) (in millions)        
PSO Southwestern(c)Oklahoma  $56   $-  Gas Simple-cycle  150  2008 Southwestern(c)Oklahoma $56 $- Gas Simple-cycle 150 2008
PSO Riverside(d)Oklahoma   58    -  Gas Simple-cycle  150  2008 Riverside(d)Oklahoma  58  - Gas Simple-cycle 150 2008
AEGCo Dresden(e)Ohio   309 (e)  119  Gas Combined-cycle  580  2010 Dresden(e)Ohio  309(e) 149 Gas Combined-cycle 580 2010(h)
SWEPCo Stall Louisiana   378    106  Gas Combined-cycle  500  2010 Stall Louisiana  378  158 Gas Combined-cycle 500 2010
SWEPCo Turk(f)Arkansas   1,522 (f)  407  Coal Ultra-supercritical  600 (f)2012 Turk(f)Arkansas  1,522(f) 448 Coal Ultra-supercritical 600(f)2012
APCo Mountaineer(g)West Virginia   2,230 (g)  -  Coal IGCC  629  2012(g) Mountaineer(g)West Virginia   (g)   Coal IGCC 629 (g)
CSPCo/OPCo Great Bend(g)Ohio   2,700 (g)  -  Coal IGCC  629  2017(g) Great Bend(g)Ohio   (g)   Coal IGCC 629 (g)

(a)Amount excludes AFUDC.
(b)Amount includes AFUDC.  Turk’s CWIP includes joint owners’ share.
(c)Southwestern Units were placed in service on February 29, 2008.
(d)The final Riverside Unit was placed in service on June 15, 2008.
(e)In September 2007, AEGCo purchased the partially completed Dresden plant from Dresden Energy LLC, a subsidiary of Dominion Resources, Inc., for $85 million, which is included in the “Total Projected Cost” section above.
(f)SWEPCo plans to own approximately 73%, or 440 MW, totaling $1,110 million$1.1 billion in capital investment.  The increase in the cost estimate disclosed in the 2007 Annual Report relates to cost escalations due to the delay in receipt of permits and approvals.  See “Turk Plant” section below.
(g)Subject to revision; constructionConstruction of IGCC plants deferredare pending necessary permits and regulatory approval.  See “IGCC Plants” section below.
(h)Projected completion date of the Dresden Plant is currently under review.  To the extent that the completion date is delayed, the total projected cost of the Dresden Plant could change.

Turk Plant

In November 2007, the APSC granted approval to build the Turk Plant.  Certain landowners filed a notice of appeal to the Arkansas State Court of Appeals.  In March 2008, the LPSC approved the application to construct the Turk Plant.

In JulyAugust 2008, the PUCT approved a certificateissued an order approving the Turk Plant with the following four conditions: (a) the capping of convenience and necessity for construction of the plant.  We expect a written order in August 2008 which will also providecapital costs for the conditionsTurk Plant at the $1.5 billion projected construction cost, excluding AFUDC, (b) capping CO2 emission costs at $28 per ton through the year 2030, (c) holding Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers and (d) providing the PUCT all updates, studies, reviews, reports and analyses as previously required under the Louisiana and Arkansas orders.  An intervenor filed a motion for rehearing seeking reversal of the PUCT’s approval.decision.  SWEPCo filed a motion for rehearing stating that the two cost cap restrictions are unlawful.  In September 2008, the motions for rehearing were denied.  In October 2008, SWEPCo appealed the PUCT’s order regarding the two cost cap restrictions.  If the cost cap restrictions are upheld and construction or emissions costs exceed the restrictions, it could have a material adverse impact on future net income and cash flows.  In October 2008, an intervenor filed an appeal contending that the PUCT’s grant of a conditional Certificate of Public Convenience and Necessity for the Turk Plant was not necessary to serve retail customers.

SWEPCo is also working with the Arkansas Department of Environmental Quality for the approval of an air permit and the U.S. Army Corps of Engineers for the approval later this year.of a wetlands and stream impact permit.  Once SWEPCo receives the air permit, they will commence construction.  A request to stop pre-construction activities at the site was filed in Federalfederal court by the same Arkansas landowners who appealed the APSC decision to the Arkansas State Court of Appeals.  In July 2008, the Federalfederal court denied the request and the Arkansas landowners appealed the denial to the U.S. Court of Appeals.

In January 2008 and July 2008, SWEPCo filed applications for authority with the APSC to construct transmission lines necessary for service from the Turk Plant.  Several landowners filed for intervention status and one landowner also contended he should be permitted to re-litigate Turk Plant issues, including the need for the generation.  The APSC granted their intervention but denied the request to re-litigate the Turk Plant issues.  The landowner filed an appeal to the Arkansas State Court of Appeals in June 2008.

The Arkansas Governor’s Commission on Global Warming is scheduled to issue its final report to the Governor by November 1, 2008.  The Commission was established to set a global warming pollution reduction goal together with a strategic plan for implementation in Arkansas.  If legislation is passed as a result of the findings in the Commission’s report, it could impact SWEPCo’s proposal to build the Turk Plant.

If SWEPCo does not receive appropriate authorizations and permits to build the Turk Plant, SWEPCo could incur significant cancellation fees to terminate its commitments and would be responsible to reimburse the joint ownersOMPA, AECC and ETEC for their share of paid costs.  If that occurred, SWEPCo would seek recovery of its capitalized costs including any cancellation fees and joint owner reimbursements.  As of JuneSeptember 30, 2008, including the joint owners’ share, SWEPCo has capitalized approximately $407$448 million of expenditures and has significant contractual construction commitments for an additional $815$771 million.  As of JuneSeptember 30, 2008, if the plant had been canceled,cancelled, cancellation fees of $60$61 million would have been required in order to terminate these construction commitments.  If the Turk Plant does not receive all necessary approvals on reasonable terms and SWEPCo cannot recover its capitalized costs, including any cancellation fees, it would have an adverse effect on future results of operations,net income, cash flows and possibly financial condition.

IGCC Plants

We have delayedThe construction of the West Virginia and Ohio IGCC plants.plants are pending necessary permits and regulatory approvals.  In May 2008, the Virginia SCC denied APCo’s request to reconsider the Virginia SCCSCC’s previous denial of APCo’s request to recover initial costs associated with a proposed IGCC plant in West Virginia.  In July 2008, the WVPSC issued a notice seeking comments from parties on how the WVPSC should proceed regarding its earlier approval of the IGCC plant.  In July 2008, the IRS awardedallocated $134 million in future tax credits to APCo for the planned IGCC plant.  Management continues to pursueplant contingent upon the ultimatecommencement of construction, qualifying expenses being incurred and certification of the IGCC plant.plant prior to July 2010.  Through September 30, 2008, APCo deferred for future recovery preconstruction IGCC costs of $19 million.  If the West Virginia IGCC plant is canceled,cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs of $19 million.costs.  If the plant is canceledcancelled and if the deferred costs are not recoverable, it would have an adverse effect on future results of operationsnet income and cash flows.

In Ohio, CSPCo and OPCo continue to pursue the ultimate construction of the IGCC plant, but awaitplant.  In September 2008, the result of an Ohio Supreme Court remand toConsumers’ Counsel filed a motion with the PUCO regarding recovery of IGCC pre-construction costs.requesting all Phase 1 cost recoveries be refunded to Ohio ratepayers with interest.  CSPCo and OPCo filed a response with the PUCO that argued the Ohio Consumers’ Counsel’s motion was without legal merit and contrary to past precedent.  If CSPCo and OPCo were required to refund some or all of the $24 million collected for IGCC pre-construction costs and those costs were not recoverable in another jurisdiction in connection with the construction of an IGCC plant, it would have an adverse effect on future results of operationsnet income and cash flows.

Environmental Matters

The Registrant Subsidiaries are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements.  The sources of these requirements include:

·
Requirements under the CAA to reduce emissions of SO2, NOx, particulate matter (PM)PM and mercury from fossil fuel-fired power plants; and
·Requirements under the Clean Water Act (CWA) to reduce the impacts of water intake structures on aquatic species at certain power plants.

In addition, the Registrant Subsidiaries are engaged in litigation with respect to certain environmental matters, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of spent nuclear fuel and future decommissioning of I&M’s nuclear units.  Management is also engaged in the development of possible future requirements to reduce CO2 and other greenhouse gasesgas (GHG) emissions to address concerns about global climate change.  All of these matters are discussed in the “Environmental Matters” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2007 Annual Report.

Environmental Litigation

New Source Review (NSR) Litigation:  The Federal EPA, a number of states and certain special interest groups filed complaints alleging that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities, including Cincinnati Gas & Electric Company, Dayton Power and Light Company (DP&L) and Duke Energy Ohio, Inc. (Duke), modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA.

In 2007, the AEP System settled their complaints under a consent decree.  CSPCo jointly-owned Beckjord and Stuart Stations with Duke and DP&L.  A jury trial in May 2008 returned a verdict of no liability at the jointly-owned Beckjord unit.  Settlement discussions are ongoing in the citizen suit action filed by Sierra Club against the jointly-owned units at Stuart Station.  Management believes CSPCo can recover any capital and operating costs of additional pollution control equipment that may be required through future regulated rates or market prices for electricity.  If CSPCo is unable to recover such costs or if material penalties are imposed, it would adversely affect future results of operations and cash flows.

Clean Air Act Requirements

As discussed in the 2007 Annual Report under “Clean Air Act Requirements,” various states and environmental organizations challenged the Clean Air Mercury Rule (CAMR) in the D. C. Circuit Court of Appeals.  The Courtcourt ruled that the Federal EPA’s action delisting fossil fuel-fired power plants did not conform to the procedures specified in the CAA.  The Courtcourt vacated and remanded the model federal rules for both new and existing coal-fired power plants to the Federal EPA.  The Federal EPA filed a petition for review by the U.S. Supreme Court.  Management is unable to predict the outcome of this appeal or how the Federal EPA will respond to the remand.  In addition, in 2005, the Federal EPA issued a final rule, the Clean Air Interstate Rule (CAIR), that requires further reductions in SO2 and NOx emissions and assists states developing new state implementation plans to meet 1997 national ambient air quality standards (NAAQS).  CAIR reduces regional emissions of SO2 and NOx (which can be transformed into PM and ozone) from power plants in the Eastern U.S. (29 states and the District of Columbia).  CAIR requires power plants within these states to reduce emissions of SO2 by 50 percent50% by 2010, and by 65 percent65% by 2015.  NOx emissions will be subject to additional limits beginning in 2009, and will be reduced by a total of 70 percent70% from current levels by 2015.  Reduction of both SO2 and NOx would be achieved through a cap-and-trade program.  In July 2008, the D.C. Circuit Court of Appeals vacated the CAIR and remanded the rule to the Federal EPA.  The Federal EPA and other parties petitioned for rehearing.  Management is unable to predict the outcome of the rehearing petitions or how the Federal EPA will respond to the remand which could be stayed or appealed to the U.S. Supreme Court.  The Federal EPA also issued revised NAAQS for both ozone and PM 2.5 that are more stringent than the 1997 standards used to establish CAIR, which could increase the levels of SO2 and NOx reductions required from the AEP System’s facilities.

In anticipation of compliance with CAIR in 2009, I&M purchased $8$9 million of annual CAIR NOx  allowances which are included in inventory as of June 30, 2008.allowances.  The market value of annual CAIR NOx allowances decreased in the weeks following this court decision.  ManagementHowever, the weighted-average cost of these allowances is below market.  If CAIR remains vacated, management intends to seek partial recovery of the cost of purchased allowances.  If the recovery is denied, itAny unrecovered portion would have an adverse effect on future results of operationsnet income and cash flows.  None of the other Registrant Subsidiaries purchased any significant number of CAIR allowances.  SO2 and seasonal NOx allowances allocated to the Registrant Subsidiaries’ facilities under the Acid Rain Program and the NOX SIPstate implementation plan (SIP) Call will still be required to comply with existing CAA programs that were not affected by the court’s decision.

It is too early to determine the full implication of these decisions on the AEP System’s environmental compliance strategy.  However, independent obligations under the CAA, including obligations under future state implementation plan submittals, and actions taken pursuant to the recent settlement of the NSR enforcement action, are consistent with the actions included in the AEP System’s least-cost CAIR compliance plan.   Consequently, management does not anticipate making any immediate changes in the near-term compliance plans as a result of these court decisions.

Global Climate Change

In July 2008, the Federal EPA issued an advance notice of proposed rulemaking (ANPR) that requests comments on a wide variety of issues the agency is considering in formulating its response to the U.S. Supreme Court’s decision in Massachusetts v. EPA.  In that case, the Courtcourt determined that CO2 is an “air pollutant” and that the Federal EPA has authority to regulate mobile sources of CO2 emissions under the CAA if appropriate findings are made.  The Federal EPA has identified a number of issues that could affect stationary sources, such as electric generating plants, if the necessary findings are made for mobile sources, including the potential regulation of CO2 emissions for both new and existing stationary sources under the NSR programs of the CAA.  Management plans to submit comments and participate in any subsequent regulatory development processes, but are unable to predict the outcome of the Federal EPA’s administrative process or its impact on the AEP System’s business.  Also, additional legislative measures to address CO2 and other GHGs have been introduced in Congress, and such legislative actions could impact future decisions by the Federal EPA on CO2 regulation.

In addition, the Federal EPA issued a proposed rule for the underground injection and storage of CO2 captured from industrial processes, including electric generating facilities, under the Safe Drinking Water Act’s Underground Injection Control (UIC) program.  The proposed rules provide a comprehensive set of well siting, design, construction, operation, closure and post-closure care requirements.  Management plans to submit comments and participate in any subsequent regulatory development process, but are unable to predict the outcome of the Federal EPA’s administrative process or its impact on the AEP System’s business.  Permitting for a demonstration project at the Mountaineer Plant will proceed under the existing UIC rules.

Clean Water Act Regulation

In 2004, the Federal EPA issued a final rule requiring all large existing power plants with once-through cooling water systems to meet certain standards to reduce mortality of aquatic organisms pinned against the plant’s cooling water intake screen or entrained in the cooling water.  The standards vary based on the water bodies from which the plants draw their cooling water.  Management expected additional capital and operating expenses, which the Federal EPA estimated could be $193 million for the AEP System’s plants.  The Registrant Subsidiaries undertook site-specific studies and have been evaluating site-specific compliance or mitigation measures that could significantly change these cost estimates.  The following table shows the investment amount per Registrant Subsidiary.

  Estimated 
  Compliance 
  Investments 
Company (in millions) 
APCo $21 
CSPCo  19 
I&M  118 
OPCo  31 

In January 2007, the Second Circuit Court of Appeals issued a decision remanding significant portions of the rule to the Federal EPA.  In July 2007, the Federal EPA suspended the 2004 rule, except for the requirement that permitting agencies develop best professional judgment (BPJ) controls for existing facility cooling water intake structures that reflect the best technology available for minimizing adverse environmental impact.  The result is that the BPJ control standard for cooling water intake structures in effect prior to the 2004 rule is the applicable standard for permitting agencies pending finalization of revised rules by the Federal EPA.  Management cannot predict further action of the Federal EPA or what effect it may have on similar requirements adopted by the states.  The Registrant Subsidiaries sought further review and filed for relief from the schedules included in their permits.

In April 2008, the U.S. Supreme Court agreed to review decisions from the Second Circuit Court of Appeals that limit the Federal EPA’s ability to weigh the retrofitting costs against environmental benefits.  Management is unable to predict the outcome of this appeal.

Adoption of New Accounting Pronouncements

In September 2006, the FASB issued SFAS 157, enhancing existing guidance for fair value measurement of assets and liabilities and instruments measured at fair value that are classified in shareholders’ equity.  The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures.  It emphasizes that fair value is market-based with the highest measurement hierarchy level being market prices in active markets.  The standard requires fair value measurements be disclosed by hierarchy level, an entity includes its own credit standing in the measurement of its liabilities and modifies the transaction price presumption.  The standard also nullifies the consensus reached in EITF Issue No. 02-3 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3) that prohibited the recognition of trading gains or losses at the inception of a derivative contract, unless the fair value of such derivative is supported by observable market data.  In February 2008, the FASB issued FSP FASSFAS 157-1 “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” which amends SFAS 157 to exclude SFAS 13 “Accounting for Leases” and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under SFAS 13.  In February 2008, the FASB issued FSP FASSFAS 157-2 “Effective Date of FASB Statement No. 157” which delays the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).  In October 2008, the FASB issued FSP SFAS 157-3 “Determining the Fair Value of Financial Asset When the Market for That Asset is Not Active” which clarifies application of SFAS 157 in markets that are not active and provides an illustrative example.  The provisions of SFAS 157 are applied prospectively, except for a) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF 02-3, b) existing hybrid financial instruments measured initially at fair value using the transaction price and c) blockage discount factors.  The Registrant Subsidiaries partially adopted SFAS 157 effective January 1, 2008.  FSP SFAS 157-3 is effective upon issuance.  The Registrant Subsidiaries will fully adopt SFAS 157 effective January 1, 2009 for items within the scope of FSP FASSFAS 157-2.  Although the statement is applied prospectively upon adoption, in accordance with the provisions of SFAS 157 related to EITF 02-3, APCo, CSPCo and OPCo reduced beginning retained earnings by $440 thousand  ($286 thousand, net of tax), $486 thousand ($316 thousand, net of tax) and $434 thousand ($282 thousand, net of tax), respectively, for the transition adjustment.  SWEPCo’s transition adjustment was a favorable $16 thousand ($10 thousand, net of tax) adjustment to beginning retained earnings.  The impact of considering AEP’s credit risk when measuring the fair value of liabilities, including derivatives, had an immaterial impact on fair value measurements upon adoption.  See “SFAS 157 “Fair Value Measurements” (SFAS 157)” section of Note 2.

In February 2007, the FASB issued SFAS 159, permitting entities to choose to measure many financial instruments and certain other items at fair value.  The standard also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities.  If the fair value option is elected, the effect of the first remeasurement to fair value is reported as a cumulative effect adjustment to the opening balance of retained earnings.  The statement is applied prospectively upon adoption.  The Registrant Subsidiaries adopted SFAS 159 effective January 1, 2008.  At adoption, the Registrant Subsidiaries did not elect the fair value option for any assets or liabilities.

In March 2007, the FASB ratified EITF 06-10, a consensus on collateral assignment split-dollar life insurance arrangements in which an employee owns and controls the insurance policy.  Under EITF 06-10, an employer should recognize a liability for the postretirement benefit related to a collateral assignment split-dollar life insurance arrangement in accordance with SFAS 106 “Employers' Accounting for Postretirement Benefits Other Than Pension” or Accounting Principles Board Opinion No. 12 “Omnibus Opinion – 1967” if the employer has agreed to maintain a life insurance policy during the employee's retirement or to provide the employee with a death benefit based on a substantive arrangement with the employee.  In addition, an employer should recognize and measure an asset based on the nature and substance of the collateral assignment split-dollar life insurance arrangement.  EITF 06-10 requires recognition of the effects of its application as either (a) a change in accounting principle through a cumulative effect adjustment to retained earnings or other components of equity or net assets in the statement of financial position at the beginning of the year of adoption or (b) a change in accounting principle through retrospective application to all prior periods.  The Registrant Subsidiaries adopted EITF 06-10 effective January 1, 2008.  The impact of this standard was an unfavorable cumulative effect adjustment, net of tax, to beginning retained earnings as follows:
  Retained   
  Earnings Tax 
Company Reduction Amount 
  (in thousands) 
APCo  $2,181  $1,175 
CSPCo   1,095   589 
I&M   1,398   753 
OPCo   1,864   1,004 
PSO   1,107   596 
SWEPCo   1,156   622 

In June 2007, the FASB ratified the EITF Issue No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards” (EITF 06-11), consensus on the treatment of income tax benefits of dividends on employee share-based compensation.  The issue is how a company should recognize the income tax benefit received on dividends that are paid to employees holding equity-classified nonvested shares, equity-classified nonvested share units or equity-classified outstanding share options and charged to retained earnings under SFAS 123R, “Share-Based Payments.”  Under EITF 06-11, a realized income tax benefit from dividends or dividend equivalents that are charged to retained earnings and are paid to employees for equity-classified nonvested equity shares, nonvested equity share units and outstanding equity share options should be recognized as an increase to additional paid-in capital.  The Registrant Subsidiaries adopted EITF 06-11 effective January 1, 2008.  EITF 06-11 is applied prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years after December 15, 2007.  The adoption of this standard had an immaterial impact on the Registrant Subsidiaries’ financial statements.

In April 2007, the FASB issued FSP FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1).  It amends FASB Interpretation No. 39 “Offsetting of Amounts Related to Certain Contracts” by replacing the interpretation’s definition of contracts with the definition of derivative instruments per SFAS 133.  It also requires entities that offset fair values of derivatives with the same party under a netting agreement to net the fair values (or approximate fair values) of related cash collateral.  The entities must disclose whether or not they offset fair values of derivatives and related cash collateral and amounts recognized for cash collateral payables and receivables at the end of each reporting period.  The Registrant Subsidiaries adopted FIN 39-1 effective January 1, 2008.  This standard changed the method of netting certain balance sheet amounts and reduced assets and liabilities.  It requires retrospective application as a change in accounting principle.  See “FSP FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1)” section of Note 2.  Consequently, the Registrant Subsidiaries reduced total assets and liabilities on their December 31, 2007 balance sheet as follows:

Company (in thousands) 
APCo $7,646 
CSPCo  4,423 
I&M  4,251 
OPCo  5,234 
PSO  187 
SWEPCo  229 


 
 
 


CONTROLS AND PROCEDURES

During the secondthird quarter of 2008, 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 JuneSeptember 30, 2008 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 secondthird quarter of 2008 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.

 
 
 

PART II.  OTHER INFORMATION

Item 1.     Legal Proceedings

For a discussion of material legal proceedings, see Note 4, Commitments, Guarantees and Contingencies, incorporated herein by reference.

Item 1A.  Risk Factors

Our Annual Report on Form 10-K for the year ended December 31, 2007 includes a detailed discussion of our risk factors.  The information presented below amends and restates in their entirety certain of those risk factors that have been updated and should be read in conjunction with the risk factors and information disclosed in our 2007 Annual Report on Form 10-K.

General Risks of Our Regulated Operations

Our request for rate recovery in Oklahoma may not be approved.  (Applies to AEP and PSO)

In July 2008, PSO filed an application with the OCC to increase its base rates by $133 million on an annual basis (including an estimated $16 million that is being recovered through a rider).  The proposed revenue requirement reflects a return on equity of 11.25%.  In October 2008, intervenors filed testimony recommending annual base rate increases ranging from $29 million to $86 million.  The differences are principally due to lower recommended returns on equity.  If the OCC denies all or part of the requested rate recovery, it could have an adverse effect on future results of operations,net income, cash flows and financial condition.

Our request for rate recovery in Ohio may not be approved.  (Applies to AEP, OPCo and CSPCo)

In July 2008, within the parameters of the ESPs, CSPCo and OPCo filed with the PUCO to establish rates for 2009 through 2011.  CSPCo and OPCo each requested an annual rate increase for 2009 through 2011 that would not exceed approximately 15% per year.  A significant portion of the requested increases results from the implementation of a fuel cost recovery mechanism that primarily includes fuel costs, purchased power costs including renewable energy, consumables such as urea, other variable production costs and gains and losses on sales of emission allowances.  Management expects a PUCO decision on the ESP filings in the fourth quarter of 2008. If an order is not received prior to January 1, 2009, CSPCo and OPCo have requested retroactive application of the new rates back to January 1, 2009 upon approval.  If the PUCO denies all or part of the requested rate recovery, it could have an adverse effect on future resultsnet income, cash flows and financial condition.

Our request for rate recovery in Virginia may not be approved. (Applies to AEP and APCo)

In May 2008, APCo filed an application with the Virginia SCC to increase its base rates by $208 million on an annual basis.  The proposed revenue requirement reflects a return on equity of operations,11.75%.  In October 2008, the Virginia SCC staff filed testimony recommending the proposed increase be reduced to $157 million.  The decrease is principally due to the use of a recommended return on equity of 10.1%.  In October 2008, hearings were held in which APCo filed a $168 million settlement agreement which was accepted by all parties except one industrial customer.  If the Virginia SCC denies all or part of the requested rate recovery, it could have an adverse effect on future net income, cash flows and financial condition.

Our request for rate recovery in Indiana may not be approved. (Applies to AEP and I&M)

In a January 2008 filing with the IURC, updated in the second quarter of 2008, I&M requested an increase in its Indiana base rates of $80 million including a return on equity of 11.5%.  In September 2008, the Indiana Office of Utility Consumer Counselor (OUCC) and the Industrial Customer Coalition filed testimony recommending a $14 million and $37 million decrease in revenue, respectively.  In October 2008, I&M filed testimony rebutting the recommendations of the OUCC.  Hearings are scheduled for December 2008.  A decision is expected from the IURC by June 2009.  If the IURC denies all or part of the requested rate recovery, it could have an adverse effect on future net income, cash flows and financial condition.

Risks Related to Owning and Operating Generation Assets and Selling Power

Our financial performance may be impaired if Cook Plant Unit 1 is not returned to service in a reasonable period of time or in a cost-efficient manner.  (Applies to AEP and I&M)

Cook Plant Unit 1 is a 1,055 MW nuclear generating unit located in Bridgman, Michigan. In September 2008, I&M shut down Unit 1 due to a fire on the electric generator which resulted from steam turbine vibrations. I&M is working with its insurance company and turbine vendor to evaluate the extent of the damage resulting from the incident and the costs to return the unit to service.  At this time, management is unable to determine the ultimate costs of the incident or when the unit will return to service.  Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance, other reimbursements or the regulatory process.  If any of these costs are not covered by warranty, insurance or recovered through the regulatory process, or if the unit is not returned to service in a reasonable period of time, it could have an adverse impact on net income, cash flows and financial condition.

The different regional power markets in which we compete or will compete in the future have changing transmission regulatory structures, which could affect our performance in these regions. (Applies to AEP, APCo, CSPCo, I&M and OPCo.)OPCo)

FERC allows utilities to sell wholesale power at market-based rates if they can demonstrate that they lack market power in the markets in which they participate.  In December 2007, AEP filed its most recent triennial update.  In 2008, the PUCO filed comments suggesting that FERC should further investigate whether certain utilities, including AEP, continue to pass FERC’s indicative screens for the lack of market power in PJM.  Certain industrial retail customers also urged FERC to further investigate this matter.

  In September 2008, the FERC issued an order accepting AEP’s market-based rates with minor changes and rejected the PUCO’s and the industrial retail customers’ suggestions for further investigation.  If FERC limits AEP’s ability to sell power at market based rates in PJM, it could have an adverse effect on future off-system sales margins, results of operationsnet income and cash flows.

Our costs of compliance with environmental laws are significant and the cost of compliance with future environmental laws could harm our cash flow and profitability or cause some of our electric generating units to be uneconomical to maintain or operate. (Applies to each registrant.)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.  Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generating plants are potentially 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.  These expenditures have been significant in the past, and we expect that they will increase in the future.  Further, environmental advocacy groups, other organizations and some agencies in the United States are focusing considerable attention on CO2 emissions from power generation facilities and their potential role in climate change.  Although several bills have been introduced in Congress that would compel CO2 emission reductions, none have advanced through the legislature.  In April 2007 the U.S. Supreme Court determined that CO2 is an “air pollutant” and that the Federal EPA has authority to regulate CO2 emissions under the CAA.  In July 2008 the Federal EPA issued an advance notice of proposed rulemaking (ANPR) that requests comments on a wide variety of issues in response to the U.S. Supreme Court’s decision.  The ANPR could lead to regulations limiting the emissions of CO2 from our generating plants.  Costs of compliance with environmental regulations could adversely affect our results of operationsnet 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.  All of our estimates are subject to significant uncertainties about the outcome of several interrelated assumptions and variables, including timing of implementation, required levels of reductions, allocation requirements of the new rules and our selected compliance alternatives.  As a result, we cannot estimate our compliance costs with certainty.  The actual costs to comply could differ significantly from our estimates.  All of the costs are incremental to our current investment base and operating cost structure.  In addition, any legal obligation that would require us to substantially reduce our emissions beyond present levels could require extensive mitigation efforts and, in the case of CO2 legislation, would raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities.  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 (in Ohio and Texas), without such recovery those costs could adversely affect future results of operationsnet income and cash flows, and possibly financial condition.

Risks Related to Market, Economic or Financial Volatility

If we are unable to access capital markets on reasonable terms, it could have an adverse impact on our net income, cash flows and financial condition.  (Applies to each registrant)

We rely on access to capital markets as a significant source of liquidity for capital requirements not satisfied by operating cash flows.  The recent volatility and reduced liquidity in the financial markets could affect our ability to raise capital and fund our capital needs, including construction costs and refinancing maturing indebtedness.  In addition, if capital is available only on less than reasonable terms, interest costs could increase materially.  Restricted access to capital markets and/or increased borrowing costs could have an adverse impact on net income, cash flows and financial condition.

Downgrades in our credit ratings could negatively affect our ability to access capital and/or to operate our power trading businesses.  (Applies to each registrant.)registrant)

Since the bankruptcy of Enron, the credit ratings agencies have periodically reviewed our capital structure and the quality and stability of our earnings.  Any negative ratings actions could constrain the capital available to our industry and could limit our access to funding for our operations.  Our business is capital intensive, and we are dependent upon our ability to access capital at rates and on terms we determine to be attractive.  If our ability to access capital becomes significantly constrained, our interest costs will likely increase and our financial condition could be harmed and future results of operationsnet income could be adversely affected.

If Moody’s or S&P were to downgrade the long-term rating of any of the securities of the registrants, particularly below investment grade, the borrowing costs of that registrant would increase, which would diminish its financial results.  In addition, the registrant’s potential pool of investors and funding sources could decrease.  In the first quarter of 2008, Fitch downgraded the senior unsecured debt rating of PSO and SWEPCo to BBB+ with stable outlook.  Moody’s placed the senior unsecured debt rating of APCo, OPCo, SWEPCo and TCC on negative outlook in January 2008.  Moody’s assigns the following ratings to the senior unsecured debt of these companies:  APCo Baa2, OPCo A3, SWEPCo Baa1 and TCC Baa2.

Our power trading business relies on the investment grade ratings of our individual public utility subsidiaries’ senior unsecured long-term debt.  Most of our counterparties require the creditworthiness of an investment grade entity to stand behind transactions.  If those ratings were to decline below investment grade, our ability to operate our power trading business profitably would be diminished because we would likely have to deposit cash or cash-related instruments which would reduce our profits.

In Ohio, we have limited ability to pass on our fuel costs to our customers.  (Applies to AEP, CSPCo and OPCo.)OPCo)

See risk factor above “Our request for rate recovery in Ohio may not be approved.”

Risks Relating to State Restructuring

In Ohio, our future rates are uncertain. (Applies to AEP, OPCo and CSPCo.)CSPCo)

See risk factor above “Our request for rate recovery in Ohio may not be approved.”

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 JuneSeptember 30, 2008 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
04/07/01/08 – 04/30/07/31/08 - $- - $-
05/08/01/08 – 05/08/31/08 -  - -  -
06/09/01/08 – 06/09/30/08 -  - -  -

Item 4. Submission of Matters to a Vote of Security Holders

AEP

The annual meeting of shareholders was held in Shreveport, Louisiana, on April 22, 2008.  The holders of shares entitled to vote at the meeting or their proxies cast votes at the meeting with respect to the following three matters, as indicated below:

1.  Election of eleven directors to hold office until the next annual meeting and until their successors are duly elected.  Each nominee for director received the votes of shareholders as follows:

  Number of Shares Voted For  Number of Shares Abstaining 
       
E. R. Brooks  312,075,636   9,048,078 
Donald M. Carlton  312,678,087   8,445,627 
Ralph D. Crosby, Jr.  313,030,107   8,093,607 
John P. DesBarres  298,693,953   22,429,761 
Linda A. Goodspeed  312,709,888   8,413,826 
Thomas E. Hoaglin  311,691,406   9,432,308 
Lester A. Hudson, Jr.  312,928,042   8,195,672 
Michael G. Morris  298,827,464   22,296,250 
Lionel L. Nowell, III  311,500,225   9,623,489 
Richard L. Sandor  308,409,310   12,714,404 
Kathryn D. Sullivan  310,429,848   10,693,866 

2.Ratification of the appointment of the firm of Deloitte & Touche LLP as the independent registered public accounting firm for 2008.  The proposal was approved by a vote of the shareholders as follows:

Votes FOR313,470,119
Votes AGAINST4,721,969
Votes ABSTAINED2,931,626

APCo

The annual meeting of stockholders was held on April 22, 2008 at 1 Riverside Plaza, Columbus, Ohio.  At the meeting, 13,499,500 votes were cast FOR each of the following ten persons for election as directors and there were no votes withheld and such persons were elected directors to hold office for one year or until their successors are elected and qualify:

Nicholas K. AkinsRobert P. Powers
Carl L. EnglishStephen P. Smith
John B. KeaneBrian X. Tierney
Holly K. KoeppelSusan Tomasky
Michael G. MorrisDennis E. Welch

CSPCo

Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated April 28, 2008, the following ten persons were elected directors to hold office for one year or until their successors are elected and qualify:

Nicholas K. AkinsRobert P. Powers
Carl L. EnglishStephen P. Smith
John B. KeaneBrian X. Tierney
Holly K. KoeppelSusan Tomasky
Michael G. MorrisDennis E. Welch
I&M

Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated July 24, 2008, the following fifteen persons were elected directors to hold office for one year or until their successors are elected and qualify:
Nicholas K. AkinsMarc E. Lewis
Kent D. CurrySusanne M. Moorman Rowe
John E. EhlerMichael G. Morris
Carl L. EnglishHelen J. Murray
Allen R. GlassburnRobert P. Powers
JoAnn M. GrevenowBrian X. Tierney
Patrick C. HaleSusan Tomasky
Holly K. Koeppel

OPCo

The annual meeting of shareholders was held on May 6, 2008 at 1 Riverside Plaza, Columbus, Ohio.  At the meeting there were 27,952,473 votes were cast FOR each of the following ten persons for election as directors and there were no votes withheld and such persons were elected directors to hold office for one year or until their successors are elected and qualify:

Nicholas K. AkinsRobert P. Powers
Carl L. EnglishStephen P. Smith
John B. KeaneBrian X. Tierney
Holly K. KoeppelSusan Tomasky
Michael G. MorrisDennis E. Welch

PSO

Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated July 24, 2008, the following ten persons were elected directors to hold office for one year or until their successors are elected and qualify:
Nicholas K. AkinsMichael G. Morris
Carl L. EnglishRichard E. Munczinski
John B. KeaneRobert P. Powers
Holly K. KoeppelSusan Tomasky
Venita McCellon-AllenDennis E. Welch

SWEPCo

Pursuant to action by written consent in lieu of an annual meeting of the sole shareholder dated July 24, 2008, the following ten persons were elected directors to hold office for one year or until their successors are elected and qualify:
Nicholas K. AkinsMichael G. Morris
Carl L. EnglishRichard E. Munczinski
John B. KeaneRobert P. Powers
Holly K. KoeppelSusan Tomasky
Venita McCellon-AllenDennis E. Welch
NONE

Item 5.  Other Information

NONE

Item 6.  Exhibits

AEP

10(a) – Second Amended and Restated $1.5 Billion Credit Agreement, dated as of March 31, 2008, among AEP, the banks, financial institutions and other institutional lenders listed on the signatures pages thereof, and JPMorgan Chase Bank, N.A., as Administrative Agent.
10(b) – Second Amended and Restated $1.5 Billion Credit Agreement, dated as of March 31, 2008, among AEP, the banks, financial institutions and other institutional lenders listed on the signatures pages thereof, and Barclays Bank plc, as Administrative Agent.

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

3(a) – Certificate of Amendment to Restated Certificate of Incorporation.
10(c) – $650 Million Credit Agreement, dated as of April 4, 2008. among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.

10(d) – Amendment, dated as of April 25, 2008, to $650 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.
CSPCo and
10(e) – $350 Million Credit Agreement, dated as of April 4, 2008, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.

3(b) – Amended Code of Regulations.
10(f) – Amendment, dated as of April 25, 2008, to $350 Million Credit Agreement, among AEP, TCC, TNC, APCo, CSPCo, I&M, KPCo, OPCo, PSO and SWEPCo, the Initial Lenders named therein, the Swingline Bank party thereto, the LC Issuing Banks party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.

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.

 
 
 

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:  August 1,October 31, 2008