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 March 31,September 30, 2007
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
0-18135AEP GENERATING COMPANY (An Ohio Corporation)31-1033833
0-346AEP TEXAS CENTRAL COMPANY (A Texas Corporation)74-0550600
0-340AEP TEXAS NORTH COMPANY (A Texas Corporation)75-0646790
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
1-6858KENTUCKY POWER COMPANY (A Kentucky Corporation)61-0247775
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, or a non-accelerated filer.  See definition of ‘accelerated filer and large accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check One)
Large accelerated filer     X                                         Accelerated filer                                           Non-accelerated filer         

Indicate by check mark whether AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company, are large accelerated filers, accelerated filers, or non-accelerated filers.  See definition of ‘accelerated filer and large accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check One)
Large accelerated filer                                               Accelerated filer                                             Non-accelerated filer     X  
 
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act.)Act).
Yes       No   X  

AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company and Public Service Company of Oklahoma 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
April 30,October 31, 2007
    
AEP Generating Company1,000
($1,000 par value)
AEP Texas Central Company2,211,678
($25 par value)
AEP Texas North Company5,488,560
($25 par value)
American Electric Power Company, Inc.        398,766,908400,006,022
   ($6.50 par value)
Appalachian Power Company  13,499,500
   (no par value)
Columbus Southern Power Company  16,410,426
   (no par value)
Indiana Michigan Power Company  1,400,000
   (no par value)
Kentucky Power Company1,009,000
($50 par value)
Ohio Power Company  27,952,473
   (no par value)
Public Service Company of Oklahoma  9,013,000
   ($15 par value)
Southwestern Electric Power Company  7,536,640
   ($18 par value)


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX TO QUARTERLY REPORTS ON FORM 10-Q
March 31,September 30, 2007

 
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
  
AEP Generating Company:Appalachian 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
  
AEP Texas CentralColumbus 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
  
AEP Texas NorthIndiana Michigan Power Company and Subsidiary: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
 
AppalachianOhio Power Company and Subsidiaries: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
  
Columbus Southern PowerPublic Service Company and Subsidiaries:of Oklahoma:
 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 MichiganSouthwestern Electric Power Company and Subsidiaries:Consolidated:
 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
  
Kentucky Power Company:
Management’s Narrative 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
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 Narrative 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 12
     Exhibit 31(a)
     Exhibit 31(b)
     Exhibit 31(c)
     Exhibit 31(d)
     Exhibit 32(a)
     Exhibit 32(b)
      
SIGNATURE 

This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky 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
 
MeaningMeaning

ADITC Accumulated Deferred Investment Tax Credits.
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 domestic electric utility companies.
AEP East companies APCo, CSPCo, I&M, KPCo and OPCo.
AEP System or the System American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP System Power Pool or AEP
   AEP  Power Pool
 Members are APCo, CSPCo, I&M, KPCo and OPCo.  The Pool shares the generation, cost of generation and resultant wholesale off-system sales of the member companies.
AEP West companiesPSO, SWEPCo, TCC and TNC.
AEPEPAEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, asset management and commercial and industrial sales in the deregulated Texas market.
AEPSC American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AEP West companiesPSO, SWEPCo, TCC and TNC.
AFUDC Allowance for Funds Used During Construction.
ALJ Administrative Law Judge.
AOCI Accumulated Other Comprehensive Income (Loss).
APCo Appalachian Power Company, an AEP electric utility subsidiary.
ARO Asset Retirement Obligations.
CAA Clean Air Act.
CO2
 Carbon Dioxide.
Cook Plant Donald 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.).
CSW Operating AgreementAgreement, dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing generating capacity allocation. AEPSC acts as the agent.
CTC Competition Transition Charge.
DETM Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
ECARDOJ East Central Area Reliability Council.United States Department of Justice.
E&REnvironmental compliance and transmission and distribution system reliability.
EDFIT Excess Deferred Federal Income Taxes.
EITFFinancial Accounting Standards Board’s Emerging Issues Task Force.
ERCOT Electric Reliability Council of Texas.
FASB Financial Accounting Standards Board.
Federal EPA United States Environmental Protection Agency.
FERC Federal Energy Regulatory Commission.
FIN 46 FASB Interpretation No.
FIN 46FIN 46, “Consolidation of Variable Interest Entities.”
FIN 48 
FASB Interpretation No.FIN 48, “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1 "Definition“Definition of Settlementin FASB Interpretation No. 48."”
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.
IPPIndependent Power Producer.
IRS Internal Revenue Service.
IURC Indiana Utility Regulatory Commission.
I&M Indiana Michigan Power Company, an AEP electric utility subsidiary.
JMG JMG Funding LP.
KGPCoKingsport Power Company, an AEP electric distribution subsidiary.
KPCo Kentucky Power Company, an AEP electric utility subsidiary.
KPSC Kentucky Public Service Commission.
kV Kilovolt.
KWH Kilowatthour.
LPSC Louisiana Public Service Commission.
MISO Midwest Independent Transmission System Operator.
MTM Mark-to-Market.
MW Megawatt.
MWH Megawatthour.
NOx
 Nitrogen oxide.
Nonutility Money Pool AEP System’s Nonutility Money Pool.
NRC Nuclear Regulatory Commission.
NSR New Source Review.
NYMEX New York Mercantile Exchange.
OATT Open Access Transmission Tariff.
OCC Corporation Commission of the State of Oklahoma.
OPCo Ohio Power Company, an AEP electric utility subsidiary.
OTC Over the counter.
OVECOhio Valley Electric Corporation, which is 43.47% owned by AEP.
PJM Pennsylvania -– New Jersey -– Maryland regional transmission organization.
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; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC.
REPTexas Retail Electric Provider.SWEPCo.
Risk Management Contracts Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned by AEGCo and I&M.
RSP Ohio Rate Stabilization Plan.
RTO Regional Transmission Organization.
S&P Standard and Poor’s.
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.”
SFAS 158 Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”
SFAS 159 Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.”
SIA System Integration Agreement.
SO2
 Sulfur Dioxide.
SPP Southwest Power Pool.
Stall UnitJ. 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.
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.
Transmission Equalization
  Agreement
Transmission Equalization Agreement by and among APCo, CSPCo, I&M, KPCo and OPCo with AEPSC as agent, promoting the allocation of the cost of ownership and operation of the transmission system in proportion to their demand ratios.
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 PlantJohn 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 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 for new investments, transmission service and environmental compliance).
·Resolution of litigation (including pending Clean Air Act enforcement actions and disputes arising from the bankruptcy of Enron Corp. and related matters).
·Our ability to constrain operation and maintenance costs.
·The economic climate and growth in our service territory and changes in market demand and demographic patterns.
·Inflationary and interest rate trends.
·Our ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities.
·Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
·Actions of rating agencies, including changes in the ratings of debt.
·Volatility and changes in markets for electricity, natural gas and other energy-related commodities.
·Changes in utility regulation, including recent legislation in Virginia, the potential for new legislation in Ohio and membership in and integration into regional transmission organizations.RTOs.
·Accounting pronouncements periodically issued by accounting standard-setting bodies.
·The performance of our pension and other postretirement benefit plans.
·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

Regulatory Activity

Our significant regulatory activities in 2007 are updated to include:The status of base rate filings ongoing or finalized this year with implemented rates are:

Operating
Company
 
Jurisdiction
 
Revised Annual Rate Increase Request
 
Implemented Annual Rate Increase
 
Projected or
Effective Date of Rate Increase
 
Date of
Final Order
 
    
(in millions)
     
APCo Virginia $198(a)$24(a)October 2006 May 2007 
OPCo Ohio  8  4(b)May 2007 October 2007 
CSPCo Ohio  24  19(b)May 2007 October 2007 
TCC Texas  70  47 June 2007 October 2007 
TNC Texas  22  14 June 2007 May 2007 
PSO Oklahoma  48  10(c)July 2007 October 2007 
OPCo Ohio  12  NA January 2008 NA 
CSPCo Ohio  35  NA January 2008 NA 


·(a)In MarchThe difference between the requested and implemented amounts of annual rate increase is partially offset by approximately $35 million of incremental E&R costs which APCo has reflected as a regulatory asset.  APCo will file for recovery through the E&R surcharge mechanism in 2008.  APCo also implemented, beginning September 1, 2007 the Texas District Court judge reversed his earlier preliminary decision and concluded the sale of assets method used by TCCsubject to value its nuclear plant stranded costs was appropriate.
·In March 2007, various intervenors and the PUCT staff filed their recommendationsrefund, a net $50 million reduction in TCC’s and TNC’s energy delivery base rate filings. Though the recommendations varied, the range of recommended increase was $8 millioncredits to $30 million for TCC and $1 million to $14 million for TNC. In April 2007, TCC and TNC filed rebuttal testimony and continue to pursue $70 million and $22 million, respectively, in annual base rate increases. Hearings began in April 2007 and are scheduled to conclude in May 2007.
·In April 2007, the Virginia legislature approved amendments recommended by the Governor to the legislature’s recently adopted, comprehensive bill providing for the re-regulation of electric utilities generation/supply rates. The effective date of the new amendments is July 1, 2007.
·In March 2007, a Hearing Examiner (HE) in Virginia issued a report recommending a $76 million increase in APCo’s base rates and $45 million credit to the fuel factorcustomers for off-system sales margins. APCo continues to pursue an annual base rate increasemargins as part of $225 million and a $27 million credit for off-system sales margins. We expect a ruling during 2007.its July 2007 fuel clause filing under the new re-regulation legislation.
·(b)In April 2007, the FERC issued an order reversing an initial favorable ALJ decision which had found the existing PJM zonal rate designManagement plans to be unjust and determined that it should be replaced. In the April 2007 order, the FERC ruled that the existing PJM rate design is just and reasonable. As a result of this order, our retail customers will be asked to bear the full costseek rehearing of the existing AEP east transmission zone facilities. We presently recover approximately 85% of these costs from retail customers. The FERC further ruled that the cost of new facilities of 500 kV and above would be shared among all PJM participants.PUCO decision.
·(c)In MarchImplemented $9 million in July 2007, theincreased to $10 million upon OCC staff and various intervenors filed testimony in PSO’s base rate case. The recommendations were base rate reductions that ranged from $18 million to $52 million. In April 2007, PSO filed rebuttal testimony and continues to pursue an increase in annual base rates of $48 million.
·Beginning with the May 2007 billing cycle, CSPCo and OPCo implemented rates filed with the PUCO under the 4% provision of their RSPs to increase their annual generation rates for 2007 by $24 million and $8 million, respectively, to recover governmentally-mandated costs. These increases are subject to refund until the PUCO issues a final order in the matter. The hearingOctober 2007.

In Virginia, APCo filed the following non-base rate requests in July 2007 with the Virginia SCC:

 
 
Operating
Company
 
 
 
 
Jurisdiction
 
 
 
 
Cost Type
 
 
 
 
Request
 
Implemented Annual Rate Increase
 
Projected or Effective Date of Rate Increase
 
Date of
Final Order
      
(in millions)
    
APCo Virginia Incremental E&R $60 $NA December 2007 NA
APCo Virginia Fuel, Off-system Sales  33  33(a)September 2007 (a)

(a)Subject to refund.  Proceeding is scheduled to begin in late May 2007.
·In March 2007, CSPCo filed an application under the 4% provision of the RSP to adjust the Power Acquisition Rider (PAR) which was authorized in 2005 by the PUCO in connection with CSPCo's acquisition of Monongahela Power Company's certified territory in Ohio. If approved, CSPCo's revenues would increase by $22 million and $38 million for 2007 and 2008, respectively.
·In April 2007, CSPCo and OPCo filed a joint motion with the PUCO staff and other intervenors to withdraw the proposed enhanced reliability plan.on-going.

Investment ActivityOhio Restructuring

Our significant investment activities inAs permitted by the current Ohio restructuring legislation, CSPCo and OPCo can implement market-based rates effective January 2009, following the expiration of its RSPs on December 31, 2008.  In August 2007, are updatedlegislation was introduced that would significantly reduce the likelihood of CSPCo’s and OPCo’s ability to include:charge market-based rates for generation at the expiration of their RSPs.  In place of market-based rates, it is more likely that some form of cost-based rates or hybrid-based rates would be required.  The legislation passed through the Ohio Senate and still must be considered by the Ohio House of Representatives.  Management continues to analyze the proposed legislation and is working with various stakeholders to achieve a principled, fair and well-considered approach to electric supply pricing.  At this time, management is unable to predict whether CSPCo and OPCo will transition to market pricing, extend their RSP rates, with or without modification, or become subject to a legislative reinstatement of some form of cost-based regulation for their generation supply business on January 1, 2009.

·We completed the 480 MW Darby Electric Generation Station acquisition in April 2007.
·In April 2007, we signed a memorandum of understanding with Allegheny Energy Inc. to form a joint venture company to build and own certain electric transmission assets within PJM with the initial focus on a transmission line between AEP’s Amos power plant in West Virginia and Allegheny’s proposed Kemptown power plant in Maryland. We expect to execute definitive agreements for the joint venture with Allegheny Energy Inc. by mid-2007 and anticipate the joint venture will begin activities in the second half of 2007.
SWEPCo and PSO Construction Costs

SWEPCo has incurred pre-construction and equipment procurement costs of $206 million and $15 million related to its Turk and Stall plant construction projects, respectively.  In September 2007, the PUCT staff recommended that SWEPCo’s application to build the Turk Plant be denied suggesting the construction of the plant would adversely impact the development of competition in the SPP zone.  In the filings to date, both the APSC and LPSC staffs have supported the Turk Plant project.  Neither the PUCT, the APSC nor the LPSC have issued final orders regarding the Turk Plant.

PSO has deferred pre-construction costs of $20 million related to its Red Rock Generating Facility construction project.  In October 2007, the OCC issued a final order denying PSO’s application for pre-approval of the Red Rock project stating PSO failed to fully study other alternatives.  PSO has cancelled the project and intends to seek recovery of the $20 million.

Michigan Depreciation Study Filing

In September 2007, the Michigan Public Service Commission (MPSC) approved a settlement agreement authorizing I&M to implement new book depreciation rates.  Based on the depreciation study included in the settlement, I&M agreed to decrease pretax annual depreciation expense, on a Michigan jurisdictional basis, by approximately $10 million.  This petition was not a request for a change in retail customers’ electric service rates.  In addition and as a result of the new MPSC-approved rates, I&M will decrease pretax annual depreciation expense, on a FERC jurisdictional basis, by approximately $11 million which will reduce wholesale rates for customers representing approximately half the load beginning in November 2007 and reduce wholesale rates for the remaining customers in June 2008.

Dividend Increase

In October 2007, our Board of Directors approved a five percent increase in our quarterly dividend to $0.41 per share from $0.39 per share.

Investment Activity

In September 2007, AEGCo purchased the partially completed 580 MW Dresden Plant from Dominion Resources, Inc. for $85 million and the assumption of liabilities of $2 million.  Management estimates that approximately $180 million in additional costs (excluding AFUDC) will be required to finish the construction of the plant.

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.  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.  In the fourth quarter of 2007, we estimate that we will realize a total of $57 million in pretax gains related to the sales of our investment in the Sweeny Plant and the related purchase power contracts.

Environmental Litigation

In October 2007, we announced that we had reached a settlement agreement with the Federal EPA, the DOJ, various states and special interest groups.  Under the New Source Review (NSR) settlement agreement, we agreed to invest in additional environmental controls for our plants before 2019.  We will also pay a $15 million civil penalty and provide $36 million for environmental projects coordinated with the federal government and $24 million to the states for environmental mitigation.  In the third quarter of 2007, we expensed $77 million (before tax) related to the penalty and the environmental mitigation projects.
RESULTS OF OPERATIONS

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.

MEMCO Operations
·
Barging operations that annually transport approximately 34 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and Lowerlower Mississippi rivers.  Approximately 35% of the barging operations relates to the transportation of coal, 28%30% relates to agricultural products, 21%18% relates to steel and 16%17% relates to other commodities.

Generation and Marketing
·IPPs, wind farms and marketing and risk management activities primarily in ERCOT.  Our 50% interest in the Sweeny Cogeneration Plant was sold in October 2007.

The table below presents our consolidated Income Before Discontinued Operations and Extraordinary Loss for the three and nine months ended March 31,September 30, 2007 and 2006 (Earnings and Weighted Average Number of Basic Shares Outstanding in millions).2006.  We reclassified prior year amounts to conform to the current year’s segment presentation.

 
Three Months Ended March 31,
  
Three Months Ended September 30,
  
Nine Months Ended September 30,
 
 
2007
 
2006
  
2007
  
2006
  
2007
  
2006
 
 
Earnings
 
EPS (b)
 
Earnings
 
EPS (b)
  
(in millions)
 
Utility Operations $253 $0.63 $365 $0.93  $388  $378  $879  $902 
MEMCO Operations  15  0.04  21  0.05   18   19   40   54 
Generation and Marketing  (1) -  4  0.01   3   4   17   10 
All Other (a)  4  0.01  (12) (0.03)  (2)  (136)  (1)  (151)
Income Before Discontinued Operations
 $271 $0.68 $378 $0.96 
             
Weighted Average Number of Basic Shares Outstanding
     397     394 
Income Before Discontinued Operations
and Extraordinary Loss
 $407  $265  $935  $815 

(a)All Other includes:
 ·Parent company’sParent’s guarantee revenue received from affiliates, interest income and interest expense and other nonallocated costs.
 ·Other energy supply related businesses, including the Plaquemine Cogeneration Facility, which was sold in the fourth quarter of 2006.
(b)The earnings per share of any segment does not represent a direct legal interest in the assets and liabilities allocated to any one segment but rather represents a direct equity interest in AEP’s assets and liabilities as a whole.

FirstThird Quarter of 2007 Compared to FirstThird Quarter of 2006

Income Before Discontinued Operations and Extraordinary Loss in 2007 decreased $107increased $142 million compared to 2006 primarily due to a decrease$136 million after-tax impairment of the Plaquemine Cogeneration Facility recorded in Utility Operations segment earnings of $112 million. The decrease in Utility Operations segment earnings primarily relates to higher operation and maintenance expenses, higher regulatory amortization expense, lower earnings-sharing payments from Centrica, lower off-system sales margins and the elimination of SECA revenues. These decreases were partially offset by higher retail margins related to new rates in the east region and favorable weather.August 2006.

Average basic shares outstanding for the three-month period increased to 397399 million in 2007 from 394 million in 2006 primarily due to the issuance of shares under our incentive compensation and dividend reinvestment plans.  ActualAt September 30, 2007, actual shares outstanding were 400 million.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

Income Before Discontinued Operations and Extraordinary Loss in 2007 increased $120 million compared to 2006 primarily due to a $136 million after-tax impairment of the Plaquemine Cogeneration Facility recorded in 2006.  This increase was partially offset by a decrease in earnings of $23 million from our Utility Operations segment.  The decrease in Utility Operations segment earnings primarily relates to higher operation and maintenance expenses due to the NSR settlement, higher regulatory amortization expense, higher interest expense and lower earnings-sharing payments from Centrica received in March 2007, representing the last payment under an earnings-sharing agreement.  These decreases in earnings were partially offset by rate increases, increased residential and commercial usage and customer growth and favorable weather.

Average basic shares outstanding for the nine-month period increased to 398 million asin 2007 from 394 million in 2006 primarily due to the issuance of March 31, 2007.shares under our incentive compensation plans.  At September 30, 2007, actual shares outstanding were 400 million.

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.

  
Three Months Ended
 
  
March 31,
 
  
2007
 
2006
 
  
(in millions)
 
Revenues $3,033 $2,966 
Fuel and Purchased Power  1,119  1,126 
Gross Margin
  1,914  1,840 
Depreciation and Amortization  383  340 
Other Operating Expenses  991  836 
Operating Income
  540  664 
Other Income, Net  18  41 
Interest Charges and Preferred Stock Dividend Requirements  179  154 
Income Tax Expense  126  186 
Income Before Discontinued Operations
 $253 $365 
Utility Operations Income Summary
For the Three and Nine Months Ended September 30, 2007 and 2006

  
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
 
  
2007
  
2006
  
2007
  
2006
 
  
(in millions)
 
Revenues $3,600  $3,437  $9,587  $9,199 
Fuel and Purchased Power  1,413   1,384   3,641   3,633 
Gross Margin
  2,187   2,053   5,946   5,566 
Depreciation and Amortization  374   374   1,122   1,060 
Other Operating Expenses  1,037   962   2,985   2,781 
Operating Income
  776   717   1,839   1,725 
Other Income, Net  27   18   72   103 
Interest Charges and Preferred Stock Dividend Requirements  213   160   599   475 
Income Tax Expense  202   197   433   451 
Income Before Discontinued Operations and Extraordinary Loss
 $388  $378  $879  $902 


Summary of Selected Sales and Weather Data
For Utility Operations
For the Three and Nine Months Ended March 31,September 30, 2007 and 2006

 
 2007
 
2006
  
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
 
Energy Summary
 
 (in millions of KWH)
 
Energy/Delivery Summary
 
2007
  
2006
  
2007
  
2006
 
 
(in millions of KWH)
 
Energy
            
Retail:                  
Residential  14,139  12,938   13,749   13,482   38,015   36,010 
Commercial  9,359  8,909   11,164   10,799   30,750   29,149 
Industrial  13,565  13,222   14,697   13,468   43,110   40,405 
Miscellaneous  614  618   686   719   1,932   1,991 
Total Retail  37,677  35,687   40,296   38,468   113,807   107,555 
                       
Wholesale  8,778  10,844   13,493   13,464   31,648   35,132 
                       
Texas Wires Delivery  5,831  5,546 
Delivery
                
Texas Wires – Energy delivered to customers served
by AEP’s Texas Wires Companies
  7,721   7,877   20,297   20,338 
Total KWHs
  52,286  52,077   61,510   59,809   165,752   163,025 


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.  In general, degree day changes in our eastern region have a larger effect on results of operations 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 Heating and Cooling degree daysDegree Days for Utility Operations
For the Three and heating degree days in our service territory for the three months ended March 31,Nine Months Ended September 30, 2007 and 2006 were as follows:

                       
2007
 
2006
 
Weather Summary
 
(in degree days)
 
Eastern Region     
Actual - Heating (a) 1,816 1,456 
Normal - Heating (b) 1,792 1,817 
      
Actual - Cooling (c) 14 1 
Normal - Cooling (b) 3 3 
      
Western Region (d)     
Actual - Heating (a) 902 658 
Normal - Heating (b) 959 972 
      
Actual - Cooling (c) 56 43 
Normal - Cooling (b) 18 17 
  
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
 
  
2007
  
2006
  
2007
  
2006
 
  
(in degree days)
 
Weather Summary
            
Eastern Region            
Actual – Heating (a)  2   10   2,041   1,573 
Normal – Heating (b)  7   7   1,973   1,999 
                 
Actual – Cooling (c)  808   685   1,189   914 
Normal – Cooling (b)  685   688   963   970 
                 
Western Region (d)                
Actual – Heating (a)  0   0   994   664 
Normal – Heating (b)  2   2   993   1,007 
                 
Actual – Cooling (c)  1,406   1,468   2,084   2,325 
Normal – Cooling (b)  1,411   1,410   2,084   2,079 

(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.

FirstThird Quarter of 2007 Compared to FirstThird Quarter of 2006

Reconciliation of FirstThird Quarter of 2006 to FirstThird Quarter of 2007
Income from Utility Operations Before Discontinued Operations and Extraordinary Loss
(in millions)

First Quarter of 2006
    $365 
Third Quarter of 2006
    $378 
              
Changes in Gross Margin:
              
Retail Margins  139      155     
Off-system Sales  (41)     36     
Transmission Revenues  (29)   
Transmission Revenues, Net  (58)    
Other Revenues  5      1     
Total Change in Gross Margin
     74       134 
               
Changes in Operating Expenses and Other:
               
Other Operation and Maintenance  (111)     (69)    
Gain on Dispositions of Assets, Net  (47)   
Depreciation and Amortization  (43)   
Taxes Other Than Income Taxes  (6)    
Carrying Costs Income  (22)     11     
Other Income, Net  2      (2)    
Interest and Other Charges  (25)     (53)    
Total Change in Operating Expenses and Other
     (246)      (119)
               
Income Tax Expense     60       (5)
               
First Quarter of 2007
    $253 
Third Quarter of 2007
     $388 

Income from Utility Operations Before Discontinued Operations decreased $112and Extraordinary Loss increased $10 million to $253$388 million in 2007.  The key driver of the decreaseincrease was a $246$134 million increase in Gross Margin partially offset by a $119 million increase in Operating Expenses and Other offset by a $74 million increase in Gross Margin and a $60$5 million decreaseincrease in Income Tax Expense.

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

·Retail Margins increased $139$155 million primarily due to the following:
 ·A $35$29 million increase at APCo related to the Virginia base rate case and the West Virginia construction surcharge.
·A $29 million increase related to Ormet, a new industrial customer in Ohio, effective January 1, 2007.  See “Ormet” section of Note 3.
·A $23 million increase related to increased residential and commercial usage and customer growth.
·A $16 million increase in usage related to weather.  As compared to the prior year, our eastern region experienced an 18% increase in cooling degree days partially offset by a 4% decrease in cooling degree days in our western region.
·A $15 million increase related to new rates implemented in our Ohio jurisdictions as approved by the PUCO in our RSPs and a $58RSPs.
·A $15 million increase related to new rates implemented in other east jurisdictions of Kentucky, West Virginia and Virginia. See “APCo Virginia Base Rate Case” in Note 3 for discussion of the Virginia increase implemented subject to refund.Texas.
 ·A $34$14 million increase related to increased residentialsales to municipal, cooperative and commercial usage and customer growth.other customers primarily resulting from new power supply contracts.
 ·A $40 million increase in usage related to weather. As compared to the prior year, our eastern region and western region experienced 25% and 37% increases, respectively, in heating degree days.
These increases were partially offset by:
 ·
A $27$15 million decrease in financial transmission rights revenue, net of congestion, primarily due to fewer transmission constraints within the PJM market.Financial transmission rights are financial instruments which entitle the holder to receive compensation for transmission charges that arise when the PJM market is congested.
·Margins from Off-system Sales decreased $41increased $36 million primarily due to lower generation availabilityfavorable fuel reconciliations in our western territory, benefits from our eastern natural gas fleet, higher power prices, and higher sales volumes in the east due to planned outages for completion of environmental retrofits and higher retail load offset by higher margins from trading activities.east.
·Transmission Revenues, Net decreased $29$58 million primarily due to the eliminationPJM’s revision of SECA revenues as of Aprilits pricing methodology for transmission line losses to marginal-loss pricing effective June 1, 2006.2007.  See the “Transmission Rate Proceedings at the FERC”“PJM Marginal-Loss Pricing” section of Note 3.
·Other Revenues were essentially flat as a result of higher securitization revenue at TCC from the $1.7 billion securitization in October 2006 partially offset by lower gains on sale of emission allowances.  Securitization revenue represents amounts collected to recover securitization bond principal and interest payments related to TCC’s securitized transition assets and are fully offset by amortization and interest expenses.

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

·Other Operation and Maintenance expenses increased $111$69 million primarily due to the NSR settlement partially offset by an abandonment of digital turbine control equipment at the Cook Plant recorded in the prior year.  See “Federal EPA Complaint and Notice of Violation” section in Note 4.
·Depreciation and Amortization expense was flat as a result of increased Texas amortization of the securitized transition assets and overall higher depreciable property balances, offset by lower depreciation expense at I&M and APCo.  The decrease at I&M relates to the lower depreciation rates approved by the IURC in June 2007.  The decrease at APCo relates to the lower depreciation rates approved by the Virginia SCC in May 2007 and adjustments in the prior period related to the 2006 Virginia E&R case.
·Carrying Costs Income increased $11 million primarily due to higher carrying cost income related to APCo’s Virginia E&R cost deferrals offset by TCC’s start in recovering stranded costs in October 2006, thus eliminating future TCC carrying costs income.
·Interest and Other Charges increased $53 million primarily due to additional debt issued in the twelve months ended September 30, 2007 including TCC securitization bonds as well as higher rates on variable rate debt.
·Income Tax Expense increased $5 million due to an increase in pretax income.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

Reconciliation of Nine Months Ended September 30, 2006 to Nine Months Ended September 30, 2007
Income from Utility Operations Before Discontinued Operations and Extraordinary Loss
(in millions)
Nine Months Ended September 30, 2006
    $902 
        
Changes in Gross Margin:
       
Retail Margins  383     
Off-system Sales  49     
Transmission Revenues, Net  (87)    
Other Revenues  35     
Total Change in Gross Margin
      380 
         
Changes in Operating Expenses and Other:
        
Other Operation and Maintenance  (154)    
Gain on Dispositions of Assets, Net  (47)    
Depreciation and Amortization  (62)    
Taxes Other Than Income Taxes  (3)    
Carrying Costs Income  (28)    
Other Income, Net  (3)    
Interest and Other Charges  (124)    
Total Change in Operating Expenses and Other
      (421)
         
Income Tax Expense      18 
         
Nine Months Ended September 30, 2007
     $879 

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss decreased $23 million to $879 million in 2007.  The key driver of the decrease was a $421 million increase in Operating Expenses and Other, offset by a $380 million increase in Gross Margin and an $18 million decrease in Income Tax Expense.

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

·Retail Margins increased $383 million primarily due to the following:
·An $84 million increase related to new rates implemented in our Ohio jurisdictions as approved by the PUCO in our RSPs, a $51 million increase related to new rates implemented in our other east jurisdictions of Virginia, West Virginia and Kentucky and a $23 million increase related to new rates in Texas and a $9 million increase related to new rates in Oklahoma.
·A $93 million increase related to increased residential and commercial usage and customer growth.
·An $83 million increase in usage related to weather.  As compared to the prior year, our eastern region and western region experienced 30% and 50% increases, respectively, in heating degree days.  Also, our eastern region experienced a 30% increase in cooling degree days which was offset by a 10% decrease in cooling degree days in our western region.
·A $66 million increase related to Ormet, a new industrial customer in Ohio, effective January 1, 2007.  See “Ormet” section of Note 3.
·A $35 million increase related to increased sales to municipal, cooperative and other wholesale customers primarily resulting from new power supply contracts.
These increases were partially offset by:
·A $63 million decrease in financial transmission rights revenue, net of congestion, primarily due to fewer transmission constraints within the PJM market.
·A $25 million decrease due to a second quarter 2007 provision related to a SWEPCo Texas fuel reconciliation proceeding.  See “SWEPCo Fuel Reconciliation – Texas” section of Note 3.
·A $14 million decrease related to increased PJM ancillary costs.
·Margins from Off-system Sales increased $49 million primarily due to strong trading performance and favorable fuel reconciliations in our western territory.
·Transmission Revenues, Net decreased $87 million primarily due to PJM’s revision of its pricing methodology for transmission line losses to marginal-loss pricing effective June 1, 2007.  See “PJM Marginal-Loss Pricing” section of Note 3.
·Other Revenues increased $35 million primarily due to higher securitization revenue at TCC resulting from the $1.7 billion securitization in October 2006.  Securitization revenue represents amounts collected to recover securitization bond principal and interest payments related to TCC’s securitized transition assets and are fully offset by amortization and interest expenses.

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

·Other Operation and Maintenance expenses increased $154 million primarily due to a $77 million expense resulting from the NSR settlement.  The remaining increases relate to generation expenses related tofrom plant outages and removal costs,base operations and distribution expenses associated with service reliability and storm restoration primarily in Oklahoma and expenses associated with employee benefits.Oklahoma.
·Gain on Disposition of Assets, Net decreased $47 million primarily related to the earnings sharing agreement with Centrica from the sale of our REPs in 2002.  In 2006, we received $70 million from Centrica for earnings sharing and in 2007 we received $20 million as the earnings sharing agreement ended.expired.
·Depreciation and Amortization expense increased $43$62 million primarily due to increased Ohio regulatory asset amortization related to recovery of IGCC preconstructionpre-construction costs, increased Texas amortization of the securitized transition assets increased Virginia regulatory amortization related to environmental and reliability recovery and higher depreciable property balances.balances, partially offset by commission-approved lower depreciation rates in Indiana and Virginia.
·Carrying Costs Income decreased $22$28 million because TCC startedprimarily due to TCC’s start in recovering Texas stranded costs in October 2006, resulting in lower Texasthus eliminating future TCC carrying costs income, in 2007.offset by higher carrying costs income related to APCo’s Virginia E&R cost deferrals.
·Interest and Other Charges increased $25$124 million primarily due to additional debt issued in the fourth quarter of 2006 partially offset by an increase in allowance for borrowed funds used for construction.twelve months ended September 30, 2007 including TCC securitization bonds as well as higher rates on variable rate debt.
·Income Tax Expense decreased $60$18 million due to a decrease in pretax income.

MEMCO Operations

FirstThird Quarter of 2007 Compared to FirstThird Quarter of 2006

Income Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations segment decreased from $21$19 million in 2006 to $15$18 million in 2007.  The decrease wasOperating expenses increased $2 million mainly due to the increased fleet size, rising fuel costs and wage increases.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

Income Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations segment decreased from $54 million in 2006 to $40 million in 2007.  MEMCO operated approximately 11% more barges in the first nine months of 2007 than 2006; however, revenue remained flat as reduced imports, primarily relatedsteel and cement continued to a return to normal winter river operating conditions indepress freight rates and reduce northbound loadings.  Operating expenses were up for the first nine months of 2007 compared to milder and more favorable weather in 2006 and lower spot market ratesprimarily due to decreased barging demand caused by lower backhaul imports.the cost of the increased fleet size, rising fuel costs and wage increases.

Generation and Marketing

FirstThird Quarter of 2007 Compared to FirstThird Quarter of 2006

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment slightly decreased from $4 million in 2006 to $3 million in 2007.  The decrease was primarily due to increased purchased power and operating expenses.  The decrease was partially offset by increases in revenues primarily due to certain existing ERCOT energy contracts, which were transferred from our Utility Operations segment on January 1, 2007, and favorable marketing contracts with municipalities and cooperatives in ERCOT.
Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment increased from $10 million in 2006 to $17 million in 2007.  Revenues increased primarily due to certain existing ERCOT energy contracts, which were transferred from our Utility Operations segment on January 1, 2007, and favorable marketing contracts with municipalities and cooperatives in ERCOT.  The increase in revenues was partially offset by increased purchased power and operating expenses.

All Other

Third Quarter of 2007 Compared to Third Quarter of 2006

Loss Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment was $1All Other decreased from $136 million in 2007 compared2006 to income of $4$2 million in 2006.2007.  The decrease was primarily relatesdue to planned and forced outages at our Oklaunion planta $136 million after-tax impairment of the Plaquemine Cogeneration Facility recorded in 2007 that limited the availability of power under lease.

All OtherAugust 2006.

First Quarter ofNine Months Ended September 30, 2007 Compared to First Quarter ofNine Months Ended September 30, 2006

IncomeLoss Before Discontinued Operations and Extraordinary Loss from All Other increaseddecreased from a $12$151 million loss in 2006 to income of $4$1 million in 2007.  In 2006, we hadrecorded a $136 million after-tax losses of $8 million in 2006 from operationimpairment of the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006.  In 2007, we had an after-tax gain of $10 million on the sale of investment securities.

AEP System Income Taxes

Income Tax Expense decreased $59increased $72 million in the third quarter of 2007 compared to the third quarter of 2006 primarily due to a decreasean increase in pretax book income.

Income Tax Expense increased $49 million for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006 primarily due to an increase in pretax book 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
 
March 31, 2007
 
December 31, 2006
  
September 30, 2007
  
December 31, 2006
 
 
($ in millions)
  
($ in millions)
 
Long-term Debt, including amounts due within one year $13,902  58.7%  $13,698  59.1% 
Long-term Debt, Including Amounts Due
Within One Year
 $14,776   58.3% $13,698   59.1%
Short-term Debt  175  0.7  18  0.0   587   2.3   18   0.0 
Total Debt  14,077  59.4  13,716  59.1   15,363   60.6   13,716   59.1 
Common Equity  9,540  40.3  9,412  40.6   9,909   39.1   9,412   40.6 
Preferred Stock  61  0.3  61  0.3   61   0.3   61   0.3 
                             
Total Debt and Equity Capitalization
 $23,678  100.0%$23,189  100.0% $25,333   100.0% $23,189   100.0%

Our ratio of debt to total capital increased, as planned, from 59.1% to 59.4%60.6% in 2007 due to our increased borrowings.borrowings to support our construction program.

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability.  We are committed to maintaining adequate liquidity.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  At March 31,September 30, 2007, our available liquidity was approximately $3.1$2.6 billion as illustrated in the table below:

 
Amount
 
Maturity
   
Amount
 
Maturity
 
(in millions)
     
(in millions)
  
Commercial Paper Backup:      Commercial Paper Backup:    
Revolving Credit Facility $1,500 March 2011 
Revolving Credit Facility  1,500  April 2012 
Revolving Credit Facility $1,500 March 2011
Revolving Credit Facility  1,500 April 2012
Total
  3,000   
Total
 3,000  
Cash and Cash Equivalents  259    Cash and Cash Equivalents  196  
Total Liquidity Sources
  3,259   
Total Liquidity Sources
 3,196  
Less: AEP Commercial Paper Outstanding  150   Less: AEP Commercial Paper Outstanding 559  
Letters of Credit Drawn  27    
Letters of Credit Drawn  69  
           
Net Available Liquidity
 $3,082    
Net Available Liquidity
 $2,568  

In 2007, we amended the terms and extended the maturity of our two credit facilities by one year to March 2011 and April 2012, respectively.  The facilities are structured as two $1.5 billion credit facilities of which $300 million may be issued under each credit facility as letters of credit.

Sale of Receivables

In October 2007, we renewed our sale of receivables agreement.  The sale of receivables agreement provides a commitment of $650 million from a bank conduit to purchase receivables.  Under the agreement, the commitment will increase to $700 million for the months of August and September to accommodate seasonal demand.  This agreement expires in October 2008.

Debt Covenants and Borrowing Limitations

Our revolving credit agreements contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%.  The method for calculating our outstanding debt and other capital is contractually defined.defined in our revolving credit agreements. At March 31,September 30, 2007, this contractually-defined percentage was 54.5%56.3%.  Nonperformance of these covenants could result in an event of default under these credit agreements.  At March 31,September 30, 2007, 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.

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

Under a regulatory order, our utility subsidiaries, other than TCC, cannot incur additional indebtedness if the issuer’s common equity would constitute less than 30% of its capital.  In addition, this order restricts those utility subsidiaries from issuing long-term debt unless that debt will be rated investment grade by at least one nationally recognized statistical rating organization.  At March 31,September 30, 2007, all applicable utility subsidiaries complied with this order.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders.  At March 31,September 30, 2007, we had not exceeded those authorized limits.

Credit Ratings

AEP’s ratings have not been adjusted by any rating agency during 2007 and AEP is currently on a stable outlook by the rating agencies.  Our current credit ratings are as follows:

                  
Moody’s
  
S&P
  
Fitch
                         
AEP Short 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.

  
Nine Months Ended
 
  
September 30,
 
  
2007
  
2006
 
  
(in millions)
 
Cash and Cash Equivalents at Beginning of Period
 $301  $401 
Net Cash Flows From Operating Activities  1,630   2,196 
Net Cash Flows Used For Investing Activities  (2,935)  (2,457) 
Net Cash Flows From Financing Activities  1,200   119 
Net Decrease in Cash and Cash Equivalents
  (105)  (142) 
Cash and Cash Equivalents at End of Period
 $196  $259 
  
Three Months Ended
 
  
March 31,
 
  
2007
 
2006
 
  
(in millions)
 
Cash and Cash Equivalents at Beginning of Period
 $301 $401 
Net Cash Flows From Operating Activities  351  583 
Net Cash Flows Used For Investing Activities  (628) (750)
Net Cash Flows From Financing Activities  235  42 
Net Decrease in Cash and Cash Equivalents
  (42) (125)
Cash and Cash Equivalents at End of Period
 $259 $276 

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.  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 March 31,September 30, 2007, we had credit facilities totaling $3 billion to support our commercial paper program.  The maximum amount of commercial paper outstanding during 2007 was $150$865 million.  The weighted-average interest rate of our commercial paper duringfor the nine months ended September 30, 2007 was 5.43%5.6%.  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 common stock or long-term debt and sale-leaseback or leasing agreements.  Utility Money Pool borrowings and external borrowings may not exceed authorized limits under regulatory orders.  See the discussion below for further detail related to the components of our cash flows.

Operating Activities
 
Three Months Ended
  
Nine Months Ended
 
 
March 31,
  
September 30,
 
 
2007
 
2006
  
2007
  
2006
 
 
(in millions)
  
(in millions)
 
Net Income
 $271 $381  $858  $821 
Less: Discontinued Operations, Net of Tax  -  (3)  (2)  (6)
Income Before Discontinued Operations
  271  378   856   815 
Noncash Items Included in Earnings  420  323 
Changes in Assets and Liabilities  (340) (118)
Depreciation and Amortization  1,144   1,084 
Other  (370)  297 
Net Cash Flows From Operating Activities
 $351 $583  $1,630  $2,196 

Net Cash Flows From Operating Activities decreased in 2007 primarily due to lower fuel costs recovery.recovery, higher tax payments in 2007 in conjunction with the filing of the 2006 tax return and increased customer accounts receivable reflecting September 2007 weather’s impact on sales and new contracts in the Generation and Marketing segment.

Net Cash Flows From Operating Activities were $351 million$1.6 billion in 2007 consisting primarily of2007. We produced Income Before Discontinued Operations of $271 million. Income Before Discontinued Operations included$856 million adjusted for noncash expense items, primarily for depreciation amortization, deferred taxes and deferred investment tax credits.amortization.  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 these asset and liability accounts relates to a number of items, nonethe most significant of which were significant.relates to the Texas CTC refund of fuel over-recovery.

Net Cash Flows From Operating Activities were $583 million$2.2 billion in 2006.  We produced Income Before Discontinued Operations of $378 million. Income Before Discontinued Operations included$815 million adjusted for noncash expense items, primarily for depreciation amortization, deferred taxes and deferred investment tax credits.amortization.  In 2005, we initiated fuel proceedings in Oklahoma, Texas, Virginia and Arkansas seeking recovery of our increased fuel costs.  Under-recovered fuel costs decreased due to recovery of higher cost of fuel, especially natural gas.  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 these asset and liability accounts relates to a number of items; the most significant areis a $99$235 million decrease in cash increase from net Accounts Receivable/Accounts Payablerelated to customer deposits held for trading activities generally due to a lower balance of Customer Accounts Receivable at March 31, 2006gas and an increase in Accrued Taxes of $176 million. We did not make a federal income tax payment during the first quarter of 2006.power market prices.

Investing Activities
 
Three Months Ended
  
Nine Months Ended
 
 
March 31,
  
September 30,
 
 
2007
 
2006
  
2007
  
2006
 
 
(in millions)
  
(in millions)
 
Construction Expenditures $(907)$(765) $(2,595) $(2,428) 
Change in Other Temporary Cash Investments, Net  (20) 27 
(Purchases)/Sales of Investment Securities, Net  236  (89)
Acquisition of Darby, Dresden and Lawrenceburg Plants  (512)  - 
Proceeds from Sales of Assets  68  111   78   120 
Other  (5) (34)  94   (149) 
Net Cash Flows Used for Investing Activities
 $(628)$(750)
Net Cash Flows Used For Investing Activities
 $(2,935) $(2,457) 

Net Cash Flows Used For Investing Activities were $628 million$2.9 billion in 2007 primarily due to Construction Expenditures for our environmental, distribution and new generation investment plan. In our normal courseplan and purchases of business, we purchase investment securities including auction rate securities and variable rate demand notes with cash available for short-term investments. Also included in Purchases/Sales of Investment Securities, Net are purchases and sales of securities within our nuclear trusts.gas-fired generating units.

Net Cash Flows Used For Investing Activities were $750 million$2.5 billion in 2006 primarily due to Construction Expenditures. Construction Expenditures increased due tofor our environmental investment plan.plan, consistent with our budgeted cash flows.

We forecast approximately $2.6$1 billion of construction expenditures for the remainder of 2007 plus $427 million for announced purchases of gas-fired generating units.2007.  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 ofwith cash from operations and financing activities.

Financing Activities
 
Three Months Ended
  
Nine Months Ended
 
 
March 31,
  
September 30,
 
 
2007
 
2006
  
2007
  
2006
 
 
(in millions)
  
(in millions)
 
Issuance of Common Stock $54 $5 
Issuance/Retirement of Debt, Net  355  129  $1,623  $529 
Dividends Paid on Common Stock  (155) (146)  (467)  (437) 
Other  (19) 54   44   27 
Net Cash Flows From Financing Activities
 $235 $42  $1,200  $119 

Net Cash Flows From Financing Activities in 2007 were $235 million$1.2 billion primarily due to $150 millionissuing $1.9 billion of debt securities including $1 billion of new debt for plant acquisitions and construction and increasing short-term commercial paper borrowings under our credit facilities and issuing $250 million of debt securities.borrowings.  We paid common stock dividends of $155$467 million.  See Note 9 for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows From Financing Activities in 2006 were $42$119 million.  During the first quarter of 2006, we issued $50$115 million of obligations relating to pollution control bonds, issued $1 billion of senior unsecured notes and increased our short-term commercial paper outstanding. The Other amountretired $396 million of $54notes for a net increase in notes outstanding of $604 million and retired $100 million of first mortgage bonds and $52 million of securitization bonds.

We expect to issue debt in the above table primarily consistscapital markets of $68approximately $675 million received from a coal supplier related to a long-term coal purchase contract amended in March 2006.

In April 2007, OPCo issued $400 million of three-year floating rate notes at an initial rate of 5.53% due in 2010. The proceeds from this issuance will contribute tofund our investment in environmental equipment.

Our capital investment plans for 2007 will require additional funding from the capital markets.remainder of 2007.

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 currentinternal 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:
       
 
March 31,
2007 
 
December 31,
2007 
  
September 30,
2007
  
December 31,
2006
 
 
(in millions)
  
(in millions)
 
AEP Credit Accounts Receivable Purchase Commitments $549 $536  $530  $536 
Rockport Plant Unit 2 Future Minimum Lease Payments  2,364  2,364   2,290   2,364 
Railcars Maximum Potential Loss From Lease Agreement  31  31   30   31 

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 2006 Annual Report.

Summary Obligation Information

A summary of our contractual obligations is included in our 2006 Annual Report and has not changed significantly from year-end other than the debt issuances discussed in “Cash Flow” and “Financing Activities” above.above and the obligations resulting from the settlement agreement regarding alleged violations of the NSR provisions of the CAA.  See “Federal EPA Complaint and Notice of Violations” section of Note 4.  We also entered into additional contractual commitments related to the construction of the proposed Turk Plant announced in August 2006.  See “Turk Plant” in the “Arkansas Rate Matters” section of Note 3.

Other

Texas REPs

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.  We received $20 million and $70 million payments in 2007 and 2006, respectively, for our share in earnings.  The payment we received in 2007 was the final payment under the earnings sharing agreement.

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 2006 Annual Report.  The 2006 Annual Report should be read in conjunction with this report in order to understand significant factors without material changes in status since the issuance of our 2006 Annual Report, but may have a material impact on our future results of operations, cash flows and financial condition.

Electric Transmission Texas LLC Joint VentureOhio Restructuring

As permitted by the current Ohio restructuring legislation, CSPCo and OPCo can implement market-based rates effective January 2009, following the expiration of its RSPs on December 31, 2008.  In JanuaryAugust 2007, we signed a participation agreement with MidAmerican Energy Holdings Company (MidAmerican)legislation was introduced that would significantly reduce the likelihood of CSPCo’s and OPCo’s ability to form a joint venture company, Electric Transmission Texas LLC (ETT), to fund, own and operate electric transmission assets in ERCOT. ETT filed with the PUCT in January 2007 requesting regulatory approval to operate as an electric transmission utility in Texas, to transfer from TCC to ETT approximately $76 million of transmission assets currently under construction and to establish a wholesale transmission tariffcharge market-based rates for ETT. ETT also requested approval from the PUCT of initial rates based on an 11.25% return on equity. A procedural schedule has been established in the case, with a hearing scheduled for June. We expect a final order from the PUCT in the third quarter.

TCC also made a regulatory filinggeneration at the FERC in February 2007 regardingexpiration of their RSPs.  In place of market-based rates, it is more likely that some form of cost-based rates or hybrid-based rates would be required.  The legislation passed through the transferOhio Senate and still must be considered by the Ohio House of certain transmission assets from TCCRepresentatives.  Management continues to ETT. In April,analyze the FERC authorized the transfer.

Upon receipt of all required regulatory approvals, AEP Utilities, Inc.,proposed legislation and is working with various stakeholders to achieve a subsidiary of AEP,principled, fair and MEHC Texas Transco LLC, a subsidiary of MidAmerican, eachwell-considered approach to electric supply pricing.  At this time, management is unable to predict whether CSPCo and OPCo will acquire a 50 percent equity ownership in ETT. AEP and MidAmerican plan for ETTtransition to invest in additional transmission projects in ERCOT. The joint venture partners anticipate investments in excess of $1 billion of joint investment in Texas ERCOT Transmission projects could be constructed by ETT during the next several years. The joint venture is anticipated to be formed and begin operations in the second half of 2007,market pricing, extend their RSP rates, with or without modification, or become subject to regulatory approval from the PUCT and the FERC.

In February 2007, ETT filed an informational proposal with the PUCT that addresses the Competitive Renewable Energy Zone initiativea legislative reinstatement of the Texas Legislature and in April ETT filed detailed testimony and exhibits supporting this proposal. The proposal outlines opportunitiessome form of cost-based regulation for additional significant investment in transmission assets in Texas.

We believe Texas can provide a high degree of regulatory certainty for transmission investment due to the predetermination of ERCOT’s need basedtheir generation supply business on reliability requirements and significant Texas economic growth as well as public policy that supports “green generation” initiatives, which require substantial transmission access. In addition, a streamlined annual interim transmission cost of service review process is available in ERCOT, which reduces regulatory lag. The use of a joint venture structure will allow us to share the significant capital requirements for the investments, and also allow us to participate in more transmission projects than previously anticipated.

AEP Interstate Project

In January 2006, we filed a proposal with the FERC and PJM to build a new 765 kV 550-mile transmission line from West Virginia to New Jersey. The 765 kV line is designed to reduce PJM congestion costs by substantially improving west-east transfer capability by approximately 5,000 MW during peak loading conditions and reducing transmission line losses by up to 280 MW. The project would also enhance reliability of the Eastern transmission grid. The projected cost for the project, as oringally proposed to PJM, is approximately $3 billion. The project is subject to PJM and state approvals, and FERC approvals of incentive cost recovery mechanisms. The projected in-service date assumes eight years for siting and construction. Due to PJM's need to review and evaluate the project in conjunction with other proposed projects, the projected in-service date is now 2015. This assumes approval by the PJM Board in mid-2007, followed by approval by the FERC on initial rates by the end of 2007.

We were the first entity to file with the Department of Energy (DOE) seeking to have the route of a proposed transmission project designated as a National Interest Electric Transmission Corridor (NIETC). The Energy Policy Act of 2005 provides for NIETC designation for areas experiencing electric energy transmission capacity constraints or congestion that adversely affects consumers. In August 2006, the DOE issued the “National Interest Electric Transmission Congestion Study.” In this study, DOE indicated that the mid-Atlantic Coastal area, which the AEP Interstate Project is designed to reinforce, is one of the two most critical congestion areas in the nation. In April 2007, the DOE approved the mid-Atlantic Coastal area as a NIETC which includes the entire proposed 765 kV transmission line.

In July 2006, pursuant to our request, the FERC provided that the new line is included in PJM’s formal Regional Transmission Expansion Plan to be finalized in 2007. The conditionally approved incentives include (a) a return on equity set at the high end of the “zone of reasonableness”; (b) the timely recovery of the cost of capital during the construction period; and (c) the ability to defer and recover costs incurred during the pre-construction and pre-operating period. Since the FERC has clarified that the project qualifies for these rate incentives, we expect to propose rates that will capture the incentives in a future FERC rate filing.

In April 2007, we signed a memorandum of understanding (MOU) with Allegheny Energy Inc. to form a joint venture company to build and own certain electric transmission assets within PJM including the first half of the West Virginia - New Jersey line proposed by AEP in January 2006.  Under the terms of the MOU, the joint venture company will build and own approximately 250 miles of 765kV transmission lines from AEP's Amos station to the Maryland border.  The MOU does not include any provisions for the remainder of the AEP Interstate Project proposal from Allegheny's Kemptown station to New Jersey. We expect to execute definitive agreements for the joint venture with Allegheny Energy Inc. by mid-2007 and anticipate the joint venture will begin activities in the second half of 2007.1, 2009.

Texas Restructuring

TCC recovered its net recoverable stranded generation costs through a securitization financing and is refunding its net other true-up items through a CTC rate rider credit under 2006 PUCT orders.  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 statute 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 it failed to determine a minimum price at which it would reject bids for the sale of its nuclear generating plant and it 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 cost, and
·The two federal matters regarding the allocation of off-system sales related to fuel recoveries and the 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.  On February 1,In March 2007, the Texas District Court judge hearing the various appeals issued a letter containing his preliminary determinations. He generallyappeal of the true-up order affirmed the PUCT’s April 4, 2006 final true-up order for TCC with two significant exceptions.  The judge determined that the PUCT erred when it determined TCC’s stranded cost using the sale of assets method instead of the Excess Cost Over Market (ECOM) methodby applying an invalid rule to value TCC’s nuclear plant. The judge also determined that the PUCT erred when it concluded it was required to usedetermine the carrying cost rate specified infor the true-up order.of stranded costs.  However, the District Court did not rule that the carrying cost rate was inappropriate.  He directed that these matters should be remanded to the PUCT to determine their specific impact on TCC’s future true-up revenues.

In March 2007,If the District Court judge reversed his earlier preliminary decision and concluded the sale of assets method to value TCC’s nuclear plant was appropriate. The District Court judge did not reconsider his preliminaryCourt’s ruling that the PUCT erred when it concluded it was required to useon the carrying cost rate specified in the true-up order. The District Court judge also determined the PUCT improperly reduced TCC’s net stranded plant costs from the sale of its generating units through the commercial unreasonableness disallowance, which could have a materially favorable effect on TCC. Management cannot predict the ultimate outcome of any future court appeals or any future remanded PUCT proceeding. If the District Court’s carrying cost rate remand ruling is ultimately upheld on appeal and remanded to the PUCT for reconsideration, the PUCT could either confirm the existing weighted average carrying cost (WACC) rate or redeterminedetermine a new rate.  If the PUCT changesreduces the rate, it could result in a material adverse change to TCC’s recoverable carrying costs, results of operations, cash flows and financial condition.

The District Court judge also determined the PUCT improperly reduced TCC’s net stranded plant costs for commercial unreasonableness.  If upheld on appeal, this ruling could have a materially favorable effect on TCC’s results of operations and cash flows.

TCC, the PUCT and intervenors appealed the District Court rulingtrue-up order rulings to the Texas Court of Appeals.  Management cannot predict what actions, if any, the PUCT will take regarding the carrying costs.
outcome of these true-up and related proceedings.  If TCC ultimately succeeds in its appeals in both state and federal court, 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, or if TCC has a tax normalization violation as discussed in the “TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes” section of Note 3, it could have a substantial adverse effect on future results of operations, cash flows and financial condition.

Virginia Restructuring

In April 2007, the Virginia legislature adopted a comprehensive law providing for the re-regulation of electric utilities’ generation and supply rates.  These amendments shorten the transition period by two years (from 2010 to 2008) after which rates for retail generation and supply will return to cost-based regulation in lieu of market-based rates.  The legislation provides for, among other things, biennial rate reviews beginning in 2009; rate adjustment clauses for the recovery of the costs of (a) transmission services and new transmission investments, (b) demand side management, load management, and energy efficiency programs, (c) renewable energy programs, and (d) environmental retrofit and new generation investments; significant return on equity enhancements for investments in new generation and, subject to Virginia SCC approval, certain environmental retrofits, and a floor on the allowed return on equity based on the average earned return on equities’ of regional vertically integrated electric utilities.  Effective July 1, 2007, the amendments allow utilities to retain a minimum of 25% of the margins from off-system sales with the remaining margins from such sales credited against fuel factor expenses with a true-up to actual.  The legislation also allows APCo to continue to defer and recover incremental environmental and reliability costs incurred through December 31, 2008.  The new re-regulation legislation should result in significant positive effects on APCo’s future earnings and cash flows from the mandated enhanced future returns on equity, the reduction of regulatory lag from the opportunities to adjust base rates on a biennial basis and the new opportunities to request timely recovery of certain new costs not included in base rates.

SECA Revenue Subject to Refund

We ceased collectingEffective December 1, 2004, AEP and other transmission owners in the region covered by PJM and MISO eliminated transaction-based through-and-out transmission service (T&O) revenuescharges in accordance with FERC orders and implementedcollected load-based charges, referred to as RTO SECA, rates to mitigate the loss of T&O revenues from December 1, 2004on a temporary basis through March 31, 2006, when SECA rates expired.2006.  Intervenors objected to the 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 or surcharge.  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. Approximately $10 million of these recorded SECA revenues billed by PJM were not collected.  The AEP East companies filed a motion with the FERC to force payment of these uncollected SECA billings.

In August 2006, thea 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 was not 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.

Since the implementation of SECA rates in December 2004,In 2006, the AEP East companies recorded approximately $220provided reserves of $37 million in net refunds for current and future SECA settlements with all of grossthe AEP East companies’ SECA revenues, subject to refund.customers.  The AEP East companies have reached settlements with certain SECA customers related to approximately $70$69 million of such revenues.revenues for a net refund of $3 million.  The unsettled grossAEP East companies are in the process of completing two settlements-in-principle on an additional $36 million of SECA revenues totaland expect to make net refunds of $4 million when those settlements are approved.  Thus, completed and in-process settlements cover $105 million of SECA revenues and will consume about $7 million of the reserves for refunds, leaving approximately $150 million.$115 million of contested SECA revenues and $30 million of refund reserves.  If the ALJ’s initial decision iswere upheld in its entirety, it would disallow $126approximately $90 million of the AEP East companies’companies' remaining $115 million of unsettled gross SECA revenues.  InBased on recent settlement experience and the second halfexpectation that most of 2006, the AEP East companies provided a$115 million of unsettled SECA revenues will be settled, management believes that the remaining reserve of $37$30 million in net refunds.will be adequate to cover all remaining settlements.

In September 2006, AEP, together with Exelon Corporation and theThe Dayton Power and Light Company, filed an extensive post hearingpost-hearing brief and reply brief noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part.  Management believes that the FERC should reject the initial decision because it is contrary tocontradicts 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 directed by the FERC, management is working to settle the remaining $115 million of unsettled revenues within the remaining reserve balance.  Although management believes they haveit has meritorious arguments and can settle with the remaining customers within the amount provided, management cannot predict the ultimate outcome of ongoing settlement talks and, if necessary, any future FERC proceedings or court appeals.  If the FERC adopts the ALJ’s decision and/or AEP cannot settle a significant portion of the remaining unsettled claims within the amount provided, it will have an adverse effect on future results of operations, cash flows and financial condition.

PJM Marginal-Loss Pricing

On June 1, 2007, in response to a 2006 FERC order, PJM revised its methodology for considering transmission line losses in generation dispatch and the calculation of locational marginal prices.   Marginal-loss dispatch recognizes the varying delivery costs of transmitting electricity from individual generator locations to the places where customers consume the energy.  Prior to the implementation of marginal-loss dispatch, PJM used average losses in dispatch and in the calculation of locational marginal prices.  Locational marginal prices in PJM now include the real-time impact of transmission losses from individual sources to loads.  Due to the implementation of marginal-loss pricing, for the period June 1, 2007 through September 30, 2007, AEP experienced an increase in the cost of delivering energy from the generating plant locations to customer load zones partially offset by cost recoveries and increased off-system sales resulting in a net loss of approximately $25 million.  AEP has initiated discussions with PJM regarding the impact it is experiencing from the change in methodology and will pursue through the appropriate stakeholder processes a modification of such methodology.  Management believes these additional costs should be recoverable through retail and/or cost-based wholesale rates and is seeking recovery in current and future fuel or base rate filings as appropriate in each of its eastern zone states.  In the interim, these costs will have an adverse effect on future results of operations and cash flows.
Virginia Restructuring

In April 2004, Virginia enacted legislation that extended the transition period for electricity restructuring, including capped rates, through December 31, 2010. The legislation provides APCo with specified cost  Management is unable to predict whether full recovery opportunities during the capped rate period, including two optional bundled general base rate changes and an opportunity for timely recovery, through a separate rate mechanism, of certain incremental environmental and reliability costs incurred on and after July 1, 2004. Under the restructuring law, APCo continues to have an active fuel clause recovery mechanism in Virginia and continues to practice deferred fuel accounting. Also, under the restructuring law, APCo defers incremental environmental generation costs and incremental T&D reliability costs for future recovery, to the extent such costs are not being recovered when incurred, and amortizes a portion of such deferrals commensurate with recovery.

In April 2007, the Virginia legislature adopted a comprehensive law providing for the re-regulation of electric utilities’ generation/supply rates. The amendments shorten the transition period by two years (from 2010 to 2008) after which rates for retail generation/supply will return to a form of cost-based regulation. The legislation provides for, among other things, biennial rate reviews beginning in 2009, rate adjustment clauses for the recovery of the costs of (a) transmission services and new transmission investment, (b) Demand Side Management, load management, and energy efficiency programs, (c) renewable energy programs, and (d) environmental retrofit and new generation investments, significant return on equity enhancements for large investments in new generation and a floor on the allowed return on equity based on the average earned return on equities’ of regional vertically integrated electric utilities. Effective July 1, 2007, utilities will retain a minimum of 25% of the margins from off-system sales with the remaining margins from such sales credited against the fuel factor. The legislation also allows APCo to continue to defer and recover incremental environmental and reliability costs incurred through December 31, 2008. APCo expects this new form of cost-based ratemaking should improve its annual return on equity and cash flow from operations when new ratemaking begins in 2009. However, with the return of cost-based regulation, APCo’s generation business will again meet the criteria for application of regulatory accounting principles under SFAS 71. Results of operations and financial condition couldultimately be adversely affected when APCo is required to re-establish certain net regulatory liabilities applicable to its generation/supply business. The timing and earnings effect from such reapplication of SFAS 71 regulatory accounting for APCo’s Virginia generation/supply business are uncertain at this time.approved.

New Generation

AEP is in various stages of construction of the following generation facilities.  Certain plants are pending regulatory approval:

                 
Commercial
      
Total
          
Operation
Operating
 
Project
   
Projected
        
MW
 
Date
Company
 
Name
 
Location
 
Cost (a)
 
CWIP
 
Fuel Type
 
Plant Type
 
Capacity
 
(Projected)
      
(in millions)
 
(in millions)
        
SWEPCo Mattison Arkansas $122(b)$52 Gas Simple-cycle 340(b)2007
PSO Southwestern Oklahoma  59(c) 45 Gas Simple-cycle 170 2008
PSO Riverside Oklahoma  58(c) 45 Gas Simple-cycle 170 2008
AEGCo Dresden(d)Ohio  265(d) 88 Gas Combined-cycle 580 2009
SWEPCo Stall Louisiana  375  15 Gas Combined-cycle 480 2010
SWEPCo Turk(e)Arkansas  1,300(e) 206 Coal Ultra-supercritical 600(e)2011
APCo Mountaineer West Virginia  2,230  - Coal IGCC 629 2012
CSPCo/OPCo Great Bend Ohio  2,230(f) - Coal IGCC 629 2017

(a)Amount excludes AFUDC.
(b)Includes Units 3 and 4, 150 MW, declared in commercial operation on July 12, 2007 with construction costs totaling $55 million.
(c)In April 2007, the OCC approved that PSO will recover through a rider, subject to a $135 million cost cap, all of the traditional costs associated with plant in service at the time these units are placed in service.
(d)In September 2007, AEGCo purchased the under-construction 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.
(e)SWEPCo plans to own approximately 73%, or 438 MW, totaling about $950 million in capital investment.  See “Turk Plant” section below.
(f)Front-end engineering and design study is complete.  Cost estimates are not yet filed with the PUCO due to the pending appeals to the Supreme Court of Ohio resulting from the PUCO’s April 2006 opinion and order.  See “Ohio IGCC Plant” section below.

AEP acquired the following generation facilities:

               
Operating
           
MW
 
Purchase
Company
 
Plant Name
 
Location
 
Cost
 
Fuel Type
 
Plant Type
 
Capacity
 
Date
      
(in millions)
        
CSPCo Darby(a)Ohio $102 Gas Simple-cycle 480 April 2007
AEGCo Lawrenceburg(b)Indiana  325 Gas Combined-cycle 1,096 May 2007

(a)CSPCo purchased Darby Electric Generating Station (Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light Company.
(b)AEGCo purchased Lawrenceburg Generating Station (Lawrenceburg), adjacent to I&M’s Tanners Creek Plant, from an affiliate of Public Service Enterprise Group (PSEG).  AEGCo sells the power to CSPCo under a FERC-approved unit power agreement.
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 during 2006; Phase 2, concurrent recovery of construction-financing costs; and Phase 3, recovery or refund in distribution rates of any difference between the market-based standard service offer price for generation and the cost of operating and maintaining the plant, including a return on and return of the ultimate cost to construct the plant, originally projected to be $1.2 billion, along with fuel, consumables and replacement power costs.  The proposed recoveries in Phases 1 and 2 would be applied against the average 4% limit on additional generation rate increases CSPCo and OPCo could request under their RSPs.

In April 2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase 1 of the cost recovery proposal.  In June 2006, the PUCO issued another order approving a tariff to recover Phase 1 pre-construction costs over a period of no more than a twelve-month periodtwelve months effective July 1, 2006.  Through March 31,September 30, 2007, CSPCo and OPCo each recorded pre-construction IGCC regulatory assets of $10 million and each recovered $9collected the entire $12 million approved by the PUCO.  As of those costs.September 30, 2007, CSPCo and OPCo will recoverhave recorded a liability of $2 million each for the remaining amounts through June 30, 2007. over-recovered portion.  CSPCo and OPCo expect to incur additional pre-construction costs equal to or greater than the $12 million each recovered.  
The PUCO indicated 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 chargesPhase 1 costs collected for pre-construction costs, associated with items that may be utilized in IGCC projects at other sites, must be refunded to Ohio ratepayers with interest.  The PUCO deferred ruling on cost recovery for Phases 2 and 3 cost recovery until further hearings are held.  A date for further rehearings has not been set.

In August 2006, the Ohio Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order in the IGCC proceeding.  CSPCo and OPCo believeThe Ohio Supreme Court heard oral arguments for these appeals in October 2007.  Management believes that the PUCO’s authorization to begin collection of Phase 1 ratespre-construction costs is lawful.  Management, however, cannot predict the outcome of these appeals.  If the PUCO’s order is found to be unlawful, CSPCo and OPCo could be required to refund Phase I1 cost-related recoveries.

Pending the outcome of the Supreme Court litigation, CSPCo and OPCo announced they may delay the start of construction of the IGCC plant. Recent estimates of the cost to build an IGCC plant have escalated to $2.2 billion.  CSPCo and OPCo may need to request an extension to the 5-year start of construction requirement if the commencement of construction is delayed beyond 2011.

Red Rock Generating Facility

In JanuaryJuly 2006, APCo filedPSO announced plans to enter into an agreement with Oklahoma Gas and Electric (OG&E) to build a petition with950 MW pulverized coal ultra-supercritical generating unit at the WVPSC requesting its approvalsite of a CertificateOG&E’s existing Sooner Plant near Red Rock, in north central Oklahoma.  PSO would own 50% of Public Conveniencethe new unit, OG&E would own approximately 42% and Necessitythe Oklahoma Municipal Power Authority (OMPA) would own approximately 8%.  OG&E would manage construction of the plant.  OG&E and PSO requested pre-approval to construct the Red Rock Generating Facility and implement a 629 MW IGCC plant adjacentrecovery rider.  In March 2007, the OCC consolidated PSO’s pre-approval application with OG&E’s request.  The Red Rock Generating Facility was estimated to APCo’s existing Mountaineercost $1.8 billion and was expected to be in service in 2012.  The OCC staff and the ALJ recommended the OCC approve PSO’s and OG&E’s filing.  As of September 2007, PSO incurred approximately $20 million of pre-construction costs and contract cancellation fees.

In October 2007, the OCC issued a final order approving PSO’s need for 450 MWs of additional capacity by the year 2012, but denied PSO’s and OG&E’s application for construction pre-approval stating PSO and OG&E failed to fully study other alternatives.  Since PSO and OG&E could not obtain pre-approval to build the Red Rock Generating Station in Mason County, WV. In January 2007, at APCo’s request,Facility, PSO and OG&E cancelled the WVPSC issued an order delayingthird party construction contract and their joint venture development contract.  Management believes the Commission’s deadlinepre-construction costs capitalized, including any cancellation fees, were prudently incurred, as evidenced by the OCC staff and the ALJ’s recommendations that the OCC approve PSO’s filing, and established a regulatory asset for issuing an order on the certificate to December 2007. Through March 31, 2007, APCo deferredfuture recovery.  Management believes such pre-construction IGCC costs totaling $10 million. If the plant is not built and these costs are not recoverable,probable of recovery and intends to seek full recovery of such costs in the near future.  If recovery is denied, future results of operations and cash flows would be adversely affected.  As a result of the OCC’s decision, PSO will be re-considering various alternative options to meet its capacity needs in the future.

Turk Plant

In December 2005, SWEPCo sought proposals for new peaking, intermediate and base load generation to be online between 2008 and 2011. In MayAugust 2006, SWEPCo announced plans to construct new generation to satisfy the demands of its customers. SWEPCo will build up to 480 MW of simple-cycle natural gas combustion turbine peaking generation in Tontitown, Arkansas and will build a 480 MW combined-cycle natural gas fired plant at its existing Arsenal Hill Power Plant in Shreveport, Louisiana. SWEPCo also plans to build a new base load 600 MW base loadpulverized coal plant, of which SWEPCo’s investment will be 73%,ultra-supercritical generating unit in Hempstead County, Arkansas by 2011 to meetnamed Turk Plant.  SWEPCo submitted filings with the long-term generation needs of its customers. Preliminary cost estimates for SWEPCo’s share of the new facilities are approximately $1.4 billion (this total excludes the related transmission investment and AFUDC). These new facilities are subject to regulatory approvals from SWEPCo’s three state commissions. The peaking generation facilityArkansas Public Service Commission (APSC) in Tontitown, Arkansas has been approved by all three state commissions and Units 3 and 4 are projected to be online in July 2007December 2006 and the remaining two units by 2008. Construction is expected to begin in 2007 on the intermediatePUCT and base load facilities upon approval from the state regulatory commissions. Expenditures related to construction of these facilities are expected to total $349 million in 2007.

In September 2005, PSO sought proposals for new peaking generation to be online in 2008, and in December 2005 PSO sought proposals for base load generation to be online in 2011. PSO received proposals and evaluated those proposals meeting the Request for Proposal criteria with oversight from a neutral third party. In March 2006, PSO announced plans to add 170 MW of peaking generation to its Riverside Station plant in Jenks, Oklahoma where PSO will construct and operate two 85 MW simple-cycle natural gas combustion turbines. Also in March 2006, PSO announced plans to add 170 MW of peaking generation to its Southwestern Station plant in Anadarko, Oklahoma where they will construct and operate two 85 MW simple-cycle natural gas combustion turbines. Combined preliminary cost estimates for these additions are approximately $120 million. In April 2007, the OCC approved a settlement agreement regarding these new peaking units. The settlement agreement provides for recovery of a purchase fee of $35 million to be paid by PSO to Lawton Cogeneration, LLC (Lawton) and for all rights to Lawton’s cogeneration facility for permits, options and engineering studies. PSO will record the purchase fee as a regulatory asset and recover it through a rider over a three-year period with a carrying charge of 8.25% beginning in September 2007. In addition, PSO will recover the traditional costs associated with plant in service of these new peaking units. Such costs will be recovered through the rider until cost recovery occurs through base rates or formula rates in a subsequent proceeding. PSO must file a rate case within eighteen months of the beginning of recovery through the rider unless the OCC approves a formula-based rate mechanism that provides for recovery of the peaking units.
In July 2006, PSO announced plans to enter a joint venture with Oklahoma Gas and Electric Company (OG&E) and Oklahoma Municipal Power Authority (OMPA) where OG&E will construct and operate a new 950 MW coal-fueled electricity generating unit near Red Rock, Oklahoma. PSO will own 50% of the new unit. PSO, OG&E and OMPA signed an agreementLPSC in February 2007 to seek approvals to proceed with Red Rock Power Partnersthe plant.  In September 2007, OMPA signed a joint ownership agreement and agreed to begin the first phaseown approximately 7% of the project. Preliminary cost estimates for 100%Turk Plant.  SWEPCo continues discussions with Arkansas Electric Cooperative Corporation and North Texas Electric Cooperative to become potential partners in the Turk Plant.  SWEPCo anticipates owning approximately 73% of the new facility are approximately $1.8Turk Plant and will operate the facility.  The Turk Plant is estimated to cost $1.3 billion andin total with SWEPCo’s portion estimated to cost $950 million, excluding AFUDC.  If approved on a timely basis, the unitplant is expected to be online no later thanin-service in mid-2011.  As of September 2007, SWEPCo incurred and capitalized approximately $206 million and has contractual commitments for an additional $875 million.  If the first half of 2012. These new facilities are subjectTurk Plant is not approved, cancellation fees may be required to regulatory approval from the OCC. Construction of all of these additions is expected to begin in 2007. Expenditures related to construction of these facilities are expected to total $125 million in 2007.terminate SWEPCo’s commitment.

In November 2006, CSPCo agreed to purchase Darby Electric Generating Station (Darby)August 2007, hearings began before the APSC seeking pre-approval of the plant. The APSC staff recommended the application be approved and intervenors requested the motion be denied.  In October 2007, final briefs and closing arguments were completed by all parties during which the APSC staff and Attorney General supported the plant.  A decision by the APSC will occur within 60 days from DPL Energy, LLC, a subsidiaryOctober 22, 2007.  In September 2007, the PUCT staff recommended that SWEPCo’s application be denied suggesting the construction of the Turk Plant would adversely impact the development of competition in the SPP zone.  The Dayton Power and Light Company, for $102 million. CSPCo completed the purchasePUCT hearings were held in AprilOctober 2007.  The DarbyLPSC held hearings in September 2007 and during this proceeding, the LPSC staff expressed support for the project.   If SWEPCo is not authorized to build the Turk plant, is located near Mount Sterling, OhioSWEPCo would seek recovery of incurred costs including any cancellation fees.  If SWEPCo cannot recover incurred costs, including any cancellation fees, it could adversely affect future results of operations, cash flows and is a natural gas, simple cycle power plant with a generating capacity of 480 MW.  The purchase of Darby is an economically efficient way to provide peaking generation to our customers at a cost below that of building a new, comparable plant. possibly financial condition.

Electric Transmission Texas LLC Joint Venture (Utility Operations segment)

In January 2007, AEGCo agreedwe signed a participation agreement with MidAmerican Energy Holdings Company (MidAmerican) to purchase Lawrenceburg Generating Station (Lawrenceburg)form a joint venture company, Electric Transmission Texas, LLC (ETT), to fund, own and operate electric transmission assets in ERCOT.  ETT filed with the PUCT in January 2007 requesting regulatory approval to operate as an electric transmission utility in Texas, to transfer from TCC to ETT approximately $76 million of transmission assets under construction and to establish a wholesale transmission tariff for ETT.  ETT also requested PUCT approval of initial rates based on an affiliate11.25% return on equity.  A hearing was held in July 2007.  On October 31, 2007, the PUCT issued an order approving the transaction and initial rates based on  9.96% return on equity.  ETT and MidAmerican are reviewing the order.

In February 2007, TCC also made a regulatory filing at the FERC regarding the transfer of Public Service Enterprise Group (PSEG)certain transmission assets from TCC to ETT.  In April 2007, the FERC authorized the transfer.  In July 2007, ETT made a subsequent filing requesting that FERC disclaim jurisdiction over ETT.  In October 2007, FERC disclaimed jurisdiction over ETT.

AEP Utilities, Inc., a subsidiary of AEP, and MEHC Texas Transco LLC, a subsidiary of MidAmerican, each would hold a 50 percent equity ownership in ETT.  ETT would not be consolidated with AEP for approximately $325 millionfinancial or tax reporting purposes.

AEP and MidAmerican plan for ETT to invest in additional transmission projects in ERCOT.  Upon formation, the joint venture partners anticipate investments in excess of $1 billion of joint investment in Texas ERCOT transmission projects that could be constructed by ETT during the next several years.

In February 2007, ETT filed a proposal with the PUCT that addresses the Competitive Renewable Energy Zone (CREZ) initiative of the Texas Legislature, which outlines opportunities for additional significant investment in transmission assets in Texas. A CREZ hearing was held in June 2007 and the assumptionPUCT issued an interim order in August 2007.  In that order, the PUCT directed ERCOT to perform studies by April 2008 that determine the necessary transmission upgrades to accommodate between 10,000 and 22,800 MW of liabilitieswind development from CREZs across the Texas panhandle and central West Texas.  The PUCT also indicated in its interim order that it plans to select transmission construction designees in the first quarter of 2008.

We believe Texas can provide a high degree of regulatory certainty for transmission investment due to the predetermination of ERCOT’s need based on reliability requirements and significant Texas economic growth as well as public policy that supports “green generation” initiatives, which require substantial transmission improvements.  In addition, a streamlined annual interim transmission cost of service review process is available in ERCOT, which reduces regulatory lag.  The use of a joint venture structure will allow us to share the significant capital requirements for the investments, and also allow us to participate in more transmission projects than previously anticipated.

Potomac-Appalachian Transmission Highline (PATH) (Utility Operations segment)

On June 22, 2007, PJM’s Board authorized the construction of a major new transmission line to address the reliability and efficiency needs of the PJM system.  PJM has identified a need for a new line as early as 2012.  The line would be 765kV for most of its length and would run approximately $2 million.290 miles from AEP’s Amos substation in West Virginia to Allegheny Energy Inc.’s (AYE) proposed Kemptown station in north central Maryland (the Amos-to-Kemptown Line). The transactionAmos-to-Kemptown Line has been named the “Potomac-Appalachian Transmission Highline” (PATH) by AEP and AYE.

Effective September 1, 2007, AEP and AYE formed a joint venture by creating Potomac-Appalachian Transmission Highline, LLC (PATH LLC) and its subsidiaries.  The subsidiaries of PATH LLC will operate as transmission utilities owning certain electric transmission assets within PJM including the PATH project.   The Amos-to-Kemptown Line has two segments:  a segment running from AEP’s Amos substation in West Virginia east to AYE’s Bedington substation in West Virginia (the “West Virginia Facilities”), to be constructed and owned by PATH West Virginia Transmission Company, LLC, and a segment running east from the Bedington substation to AYE’s Kemptown substation in Maryland (the “Bedington-Kemptown Facilities”), to be constructed and owned by PATH Allegheny Transmission Company, LLC.

In addition to the Amos-to-Kemptown Line, the joint venture will also pursue a high voltage transmission line up to 70 miles in length in northeastern Ohio (the “Ohio Facilities”) extending to the Pennsylvania border.  The Ohio Facilities would be constructed and owned by PATH Ohio Transmission Company, LLC, if the project is authorized by PJM prior to 2011.  This project is currently under study in PJM’s Regional Transmission Expansion Plan process.

The ownership in the West Virginia Facilities and the Ohio Facilities will be shared 50/50 between AEP and AYE.  The Bedington-Kemptown Facilities will be owned solely by AYE.  The ownership and management of the Ohio Facilities will be shared 50/50 between AEP and AYE.

Both AEP and AYE will be providing services to the PATH companies through service agreements. AEP will have lead responsibility for engineering, designing and managing construction of the 765-kV elements of the project, and AEP will provide business services to the PATH companies during the construction phase of the project.  Both companies will provide siting, right-of-way and regulatory services to the PATH companies.

PATH LLC, on behalf of the PATH operating companies, plans to file for necessary approvals from FERC for the Amos-to-Kemptown Line in the fourth quarter of 2007.  The PATH operating companies will seek regulatory approvals for the Amos-to-Kemptown project from the state utility commissions following completion of a routing study that is expected to closeoccur 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 plans to sell the power to CSPCo through a FERC-approved purchase power contract.2008.

The total cost of the Amos-to-Kemptown Line is estimated to be approximately $1.8 billion and AEP’s estimated share will be approximately $600 million.  The PATH companies will not be consolidated with AEP for financial or tax reporting purposes.
Litigation

In the ordinary course of business, we and 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 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 that have a probable likelihood of loss and the loss amount can be estimated.  For details on regulatory proceedings and our 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 2006 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 the results of operations, cash flows and financial condition of AEP and its subsidiaries.

See discussion of the “Environmental Litigation” within the “Environmental Matters” section of “Significant Factors.”

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 the Clean Air Act (CAA) to reduce emissions of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter (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 monitoring possible future requirements to reduce carbon dioxide (CO2) 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 2006 Annual Report.

Environmental Litigation

New Source Review (NSR) Litigation:  In 1999, the Federal EPA, and a number of states and certain special interest groups filed complaints alleging that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities including the Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric Company, Ohio Edison Company, Southern Indiana Gas & Electric Company, Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company and Duke Energy, modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA.  A separate lawsuit, initiated by certain special interest groups, has been consolidated with the Federal EPA case. Several similar complaints were filed in 1999 and thereafter against nonaffiliated utilities including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these cases were resolved through consent decrees. The alleged modifications at our power plants occurred over a twenty-year period. A bench trial on the liability issues was held during 2005. Briefing has concluded. In June 2006, the judge stayed the liability decision pending the issuance of a decision by the U.S. Supreme Court in the Duke Energy case.

Under the CAA, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant.

Courts that considered whether the activities at issue in these cases are routine maintenance, repair, or replacement, and therefore are excluded from NSR, reached different conclusions. Similarly, courts that considered whether the activities at issue increased emissions from the power plants reached different results. Appeals on these and other issues were filed in certain appellate courts, including a petition to appeal to the U.S. Supreme Court that was granted in the Duke Energy case. The Federal EPA issued a final rule that would exclude activities similar to those challenged in these cases from NSR as “routine replacements.” In March 2006, the Court of Appeals for the District of Columbia Circuit issued a decision vacating the rule. The Court denied the Federal EPA’s request for rehearing, and the Federal EPA and other parties filed a petition for review by the U.S. Supreme Court. In April 2007, the Supreme Court denied the petition for review. The Federal EPA also proposed a rule that would define “emissions increases” in a way that would exclude most of the challenged activities from NSR.

On April 2, 2007, the U.S. Supreme Court reversed the Fourth Circuit Court of Appeals’ decision that had supported the statutory construction argument of Duke Energy in its NSR proceeding.

In October 2007, we announced that we had entered into a unanimous decision, the Court ruled thatconsent decree with the Federal EPA, was not obligated to define “major modification” in two different CAA provisions in the same way. The Court also found thatDOJ, the Fourth Circuit’s interpretation of “major modification” as applying only to projects that increased hourly emission rates amounted to an invalidation of the relevant Federal EPA regulations, which under the CAA can only be challenged in the Court of Appeals within 60 days of the Federal EPA rulemaking. The U.S. Supreme Court did acknowledge, however, that Duke Energy may argue on remand that the Federal EPA has been inconsistent in its interpretations of the CAAstates and the regulationsspecial interest groups. Under the consent decree, we agreed to annual SO2 and may not retroactively change 20 years of accepted practice.

NOx emission caps for sixteen coal-fired power plants located in Indiana, Kentucky, Ohio, Virginia and West Virginia. In addition to providing guidance on certaincompleting the installation of previously announced environmental retrofit projects at many of the meritsplants, we agreed to install selective catalytic reduction (SCR) and flue gas desulfurization (FGD or scrubbers) emissions control equipment on the Rockport Plant units.

Since 2004, we spent nearly $2.6 billion on installation of the NSR proceedings brought against APCo, CSPCo, I&Memissions control equipment on our coal-fueled plants in Kentucky, Ohio, Virginia and OPCo in U.S. District Court for the Southern District of Ohio, the U.S. Supreme Court’s issuanceWest Virginia as part of a ruling inlarger plan to invest more than $5.1 billion by 2010 to reduce the Duke Energy cases has an impact on the timingemissions of our NSR proceedings. First,generating fleet.

Under the court inconsent decree, we will pay a $15 million civil penalty and provide $36 million for environmental projects coordinated with the casefederal government and $24 million to the states for which a trial on liability issues has been conducted has indicated an intent to issue a decision on liability. Second, the bench trial on remedy issues, if necessary, is likely to be scheduled to beginenvironmental mitigation.  We recognized these amounts in the third quarter of 2007.  See “Federal EPA Complaint and Notice of Violation” section of Note 4.

Litigation against three jointly-owned plants, operated by Duke Energy Ohio, Inc. and Dayton Power and Light Company, continues.  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 CAA proceedings. We are also unable to predict the timing of resolutionoutcome of these matters due to the number of alleged violations and the significant number of issues to be determined by the court. If we do not prevail, wecases.   We believe we can recover any capital and operating costs of additional pollution control equipment that may be required through regulated rates andor market prices for electricity.  If we are unable to recover such costs or if material penalties are imposed, it would adversely affect future results of operations and cash flowsflows.

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 possibly financial condition.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.

The rule was challenged in the courts by states, advocacy organizations and industry.  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 may seek further review or relief from the schedules included in our permits.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2006 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

FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold (whether a tax position is more likely than not to be sustained) without which, the benefit of that position is not recognized in the financial statements.  It requires a measurement determination for recognized tax positions based on the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.  FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.  FIN 48 requires that the cumulative effect of applying this interpretation be reported and disclosed as an adjustment to the opening balance of retained earnings for that fiscal year and presented separately.  We adopted FIN 48 effective January 1, 2007.  The effect of this interpretation on our financial statements was an unfavorable adjustment to retained earnings of $17 million.  See “FIN 48 “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1 "Definition“Definition of Settlement in FASB Interpretation No. 48""48”” section of Note 2 and see Note 8 -– Income Taxes.


QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

As a major power producer and marketer of wholesale electricity, coal and emission allowances, our Utility Operations segment is exposed to certain market risks.  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.

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 primarily financial derivatives, along with physical contracts, which will gradually liquidate and completely expire in 2011.  Our risk objective is to keep these positions generally risk neutral through maturity.

Our Generation and Marketing segment holds power sale contracts towith commercial and industrial customers and wholesale power trading and marketing contracts within ERCOT.

We employ risk management contracts including physical forward purchase and sale contracts, exchange futures and options, over-the-counter options, swaps and other derivative contracts to offset price risk where appropriate.  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 management 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 Treasurer.  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 the 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 March 31,September 30, 2007 and the reasons for changes in our total MTM value included on our condensed consolidated balance sheet as compared to December 31, 2006.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
March 31,September 30, 2007
(in millions)
Utility Operations
 
Generation and
Marketing
 
All Other
 
Sub-Total MTM Risk Management Contracts
 
PLUS: MTM of Cash Flow and Fair Value Hedges
 
Total
  
Utility Operations
  
Generation and
Marketing
  
All Other
  
Sub-Total MTM Risk Management Contracts
  
PLUS: MTM of Cash Flow and Fair Value Hedges
  
Total
 
Current Assets$319 $30 $121 $470 $6 $476  $233  $47  $62  $342  $9  $351 
Noncurrent Assets 210  21  110  341  10  351   199   63   79   341   6   347 
Total Assets
 529  51  231  811  16  827   432   110   141   683   15   698 
                                        
Current Liabilities (228) (35) (120) (383) (20) (403)  (148)  (53)  (64)  (265)  (2)  (267)
Noncurrent Liabilities (92) (8) (117) (217) (2) (219)  (101)  (21)  (85)  (207)  (3)  (210)
Total Liabilities
 (320) (43) (237) (600) (22) (622)  (249)  (74)  (149)  (472)  (5)  (477)
                                        
Total MTM Derivative
Contract Net Assets
(Liabilities)
$209 $8 $(6)$211 $(6)$205  $183  $36  $(8) $211  $10  $221 

MTM Risk Management Contract Net Assets (Liabilities)
ThreeNine Months Ended March 31,September 30, 2007
(in millions)
 
Utility Operations
 
Generation
and
Marketing
 
All Other
 
Total
  
Utility Operations
  
Generation
and
Marketing
  
All Other
  
Total
 
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2006
 $236 $2 $(5)$233  $236  $2  $(5) $233 
(Gain) Loss from Contracts Realized/Settled During
the Period and Entered in a Prior Period
  (23) -  -  (23)  (50)  (1)  (2)  (53)
Fair Value of New Contracts at Inception When Entered
During the Period (a)
  1  3  -  4   6   49   -   55 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During The Period  -  -  -  -   2   -   -   2 
Changes in Fair Value Due to Valuation Methodology
Changes on Forward Contracts
  -  -  -  -   -   -   -   - 
Changes in Fair Value Due to Market Fluctuations During
the Period (b)
  5  3  (1) 7   7   (14)  (1)  (8)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)  (10) -  -  (10)  (18)  -   -   (18)
Total MTM Risk Management Contract Net Assets (Liabilities) at March 31, 2007
 $209 $8 $(6) 211 
Total MTM Risk Management Contract Net Assets
(Liabilities) at September 30, 2007
 $183  $36  $(8)  211 
Net Cash Flow and Fair Value Hedge Contracts
           (6)              10 
Total MTM Risk Management Contract Net Assets at March 31, 2007
          $205 
Total MTM Risk Management Contract Net Assets at
September 30, 2007
             $221 

(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)Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)“ChangeChanges 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.

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

The following table presents:

·The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
·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 March 31,September 30, 2007
(in millions)
  
Remainder
2007
 
2008
 
2009
 
2010
 
2011
 
After
2011
 
Total
 
Utility Operations:
                      
Prices Actively Quoted - Exchange Traded Contracts $14 $1 $2 $- $- $- $17 
Prices Provided by Other External Sources -
  OTC Broker Quotes (a)
  85  50  33  14  -  -  182 
Prices Based on Models and Other Valuation Methods (b)  (18) (7) 9  17  4  5  10 
Total
 $81 $44 $44 $31 $4 $5 $209 
                       
Generation and Marketing:
                      
Prices Actively Quoted - Exchange Traded Contracts $(5)$(4)$1 $- $- $- $(8)
Prices Provided by Other External Sources -
  OTC Broker Quotes (a)
  (3) 8  1  -  -  -  6 
Prices Based on Models and Other Valuation Methods (b)  3  6  (1) -  -  2  10 
Total
 $(5)$10 $1 $- $- $2 $8 
                       
All Other:
                      
Prices Actively Quoted - Exchange Traded Contracts $4 $- $- $- $- $- $4 
Prices Provided by Other External Sources -
  OTC Broker Quotes (a)
  (3) -  -  -  -  -  (3)
Prices Based on Models and Other Valuation Methods (b)  -  (1) (4) (4) 2  -  (7)
Total
 $1 $(1)$(4)$(4)$2 $- $(6)
                       
Total:
                      
Prices Actively Quoted - Exchange Traded Contracts $13 $(3)$3 $- $- $- $13 
Prices Provided by Other External Sources -
  OTC Broker Quotes (a)
  79  58  34  14  -  -  185 
Prices Based on Models and Other Valuation Methods (b)  (15) (2) 4  13  6  7  13 
Total
 $77 $53 $41 $27 $6 $7 $211 
  
Remainder
2007
 
2008
 
2009
 
2010
 
2011
 
After
2011 (c)
 
Total
 
Utility Operations:
                      
Prices Actively Quoted – Exchange   
  Traded Contracts
 $5 $(15)$3 $- $- $- $(7)
Prices Provided by Other External
  Sources – OTC Broker Quotes (a)
  29  66  40  31  -  -  166 
Prices Based on Models and Other
  Valuation Methods (b)
  1  (1) 6  5  7  6  24 
Total
  35  50  49  36  7  6  183 
                       
Generation and Marketing:
                      
Prices Actively Quoted – Exchange   Traded Contracts  (3) 2  1  -  -  -  - 
Prices Provided by Other External
  Sources – OTC Broker Quotes (a)
  -  (6) 3  -  -  -  (3)
Prices Based on Models and Other
  Valuation Methods (b)
  -  (3) (2) 8  7  29  39 
Total
  (3) (7) 2  8  7  29  36 
                       
All Other:
                      
Prices Actively Quoted – Exchange   Traded  Contracts  -  -  -  -  -  -  - 
Prices Provided by Other External
  Sources – OTC Broker Quotes (a)
  -  (2) -  -  -  -  (2)
Prices Based on Models and Other
  Valuation Methods (b)
  -  -  (4) (4) 2  -  (6)
Total
  -  (2) (4) (4) 2  -  (8)
                       
Total:
                      
Prices Actively Quoted – Exchange
  Traded Contracts
  2  (13) 4  -  -  -  (7)
Prices Provided by Other External
  Sources – OTC Broker Quotes (a)
  29�� 58  43  31  -  -  161 
Prices Based on Models and Other
  Valuation Methods (b)
  1  (4) -  9  16  35  57 
Total
 $32 $41 $47 $40 $16 $35 $211 

(a)Prices Provided by Other External Sources -– OTC Broker Quotes reflects information obtained from over-the-counter brokers (OTC), industry services, or multiple-party online platforms.
(b)Prices Based on Models and Other Valuation Methods is used in the absence of pricingindependent information from external sources.  Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources.  In addition, where external pricing information or market liquidity is limited, such valuations are classified as modeled.
Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available.available including values determinable by other third party transactions.
(c)There is mark-to-market value of $35 million in individual periods beyond 2011.  $14 million of this mark-to-market value is in 2012, $8 million is in 2013, $7 million is in 2014, $2 million is in 2015, $2 million is in 2016 and $2 million is in 2017.
 
The determination of the point at which a market is no longer liquid for placing itsupported by independent quotes and therefore considered in the modeled category in the preceding table varies by market.  The following table generally reports an estimate of the maximum tenors (contract maturities) of the liquid portion of each energy market.

Maximum Tenor of the Liquid Portion of Risk Management Contracts
As of March 31,September 30, 2007

Commodity
 
Transaction Class
 
Market/Region
 
Tenor
      
(in Months)
Natural Gas Futures NYMEX / Henry Hub 60
  
Physical Forwards Gulf Coast, Texas 19
18
  Swaps Northeast, Mid-Continent, Gulf Coast, Texas 19
18
  Exchange Option Volatility NYMEX / Henry Hub 12
Power Futures AEP East - PJM 33
27
  Physical Forwards AEP East - Cinergy 45
39
  Physical Forwards AEP - PJM West 3339
  Physical ForwardsAEP - Dayton (PJM)39
  Physical Forwards AEP - ERCOT27
Physical ForwardsAEP - Entergy15
  Physical Forwards West Coast 33
39
  Peak Power Volatility (Options)AEP East - Cinergy, PJM 12
Emissions Credits 
SO2, NOx
 33
39
Coal Physical Forwards PRB, NYMEX, CSX 3339


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 forward contracts and collars as cash flow hedgesforeign currency derivatives to lock in prices on certain transactions denominated in foreign currencies where deemed necessary.necessary, and designate qualifying instruments as cash flow hedge strategies.  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, 2006 to March 31,September 30, 2007.  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
ThreeNine Months Ended March 31,September 30, 2007
(in millions)
    
Interest
    
    
Rate and
    
    
Foreign
    
 
 Power
 
 Interest Rate and
Foreign
Currency
 
 Total
  
Power
  
Currency
  
Total
 
Beginning Balance in AOCI, December 31, 2006
 $17 $(23)$(6) $17  $(23) $(6)
Changes in Fair Value  (15) -  (15)  4   (2)  2 
Reclassifications from AOCI to Net Income for
Cash Flow Hedges Settled
  (7) -  (7)  (15)  2   (13)
Ending Balance in AOCI, March 31, 2007
 $(5)$(23)$(28)
Ending Balance in AOCI, September 30, 2007
 $6  $(23) $(17)
                      
After Tax Portion Expected to be Reclassified
to Earnings During Next 12 Months
 $(10)$(1)$(11) $4  $(2) $2 

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.  Only after an entity meets our internal credit rating criteria will we extend unsecured credit.  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.  We use our analysis, in conjunction with the rating agencies’ information, to determine appropriate risk parameters.  We also require cash deposits, letters of credit and parent/affiliate guarantees as security from counterparties depending upon credit quality in our normal course of business.

We have risk management contracts with numerous counterparties.  Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily.  As of March 31,September 30, 2007, our credit exposure net of credit collateral to sub investment grade counterparties was approximately 3.10%4.6%, expressed in terms of net MTM assets, net receivables and the net receivables.open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).  As of March 31,September 30, 2007, 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):

 
Exposure
        
Number of
  
Net Exposure
 
 
Before
        
Counterparties
  
of
 
 
Credit
  
Credit
  
Net
  
>10% 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%
  
Collateral
  
Collateral
  
Exposure
  
Net Exposure
  
>10%
 
Investment Grade $665 $102 $563 1 $72  $649  $60  $589   -  $- 
Split Rating  7 2 5 2 4   25   11   14   2   13 
Noninvestment Grade  7 - 7 2 7   24   3   21   2   19 
No External Ratings:                                
Internal Investment Grade  15 - 15 3 11   68   -   68   1   39 
Internal Noninvestment Grade  45  33  12  2  8   13   2   11   3   8 
Total as of March 31, 2007
 $739 $137 $602  10 $102 
Total as of September 30, 2007
 $779  $76  $703   8  $79 
                                
Total as of December 31, 2006
 $998 $161 $837  9 $169  $998  $161  $837   9  $169 


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, 2009.  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 March 31,September 30, 2007

 
Remainder
    
 
2007
 
2008
 
2009
Estimated Plant Output Hedged93% 89% 90%
 
Remainder
    
 
2007
 
2008
 
2009
Estimated Plant Output Hedged95% 88% 91%

VaR Associated with Risk Management Contracts

Commodity Price Risk

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 March 31,September 30, 2007, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, 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

Three Months Ended
March 31, 2007
 
Twelve Months Ended
December 31, 2006
Nine Months Ended
Nine Months Ended
 
Twelve Months Ended
September 30, 2007
September 30, 2007
 
December 31, 2006
(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 $6 $2 $1 $3 $10 $3 $1
$1 $6 $2 $1 $3 $10 $3 $1

The High VaR for 2006 occurred in mid-August during a period of high gas and power volatility. The following day, positions were flattened and the VaR was significantly reduced.

Interest Rate Risk

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period.  The volatilities and correlations were based on three years of daily prices. The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $873$925 million at March 31,September 30, 2007 and $870 million at December 31, 2006.  We would not expect to liquidate our entire debt portfolio in a one-year holding period.  Therefore, a near term change in interest rates should not materially affect our results of operations, cash flows or financial position.


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended March 31,September 30, 2007 and 2006
(in millions, except per-share amounts and shares outstanding)
(Unaudited)

 
Three Months Ended
 
Nine Months Ended
 
 
2007
 
2006
  
2007
 
2006
 
2007
 
2006
 
REVENUES
              
Utility Operations $2,886 $2,982  $3,423 $3,478 $9,127 $9,259 
Other  283  126   366  116  977  379 
TOTAL
  3,169  3,108   3,789  3,594  10,104  9,638 
                
EXPENSES
                
Fuel and Other Consumables Used for Electric Generation  886  961  1,099 1,113 2,853 2,962 
Purchased Energy for Resale  246  166  358 271 895 674 
Other Operation and Maintenance  938  821  964 898 2,783 2,615 
Gain/Loss on Disposition of Assets, Net  (23) (68)
Gain on Disposition of Assets, Net (2) - (28) (68)
Asset Impairments and Other Related Charges - 209 - 209 
Depreciation and Amortization  391  348  381 382 1,144 1,084 
Taxes Other Than Income Taxes  186  191   191  186  565  567 
TOTAL
  2,624  2,419   2,991  3,059  8,212  8,043 
                
OPERATING INCOME
  545  689  798 535 1,892 1,595 
                
Interest and Investment Income  23  8  8 22 39 41 
Carrying Costs Income  8  30  14 3 38 66 
Allowance For Equity Funds Used During Construction  8  6  9 12 23 25 
Gain on Disposition of Equity Investments, Net  -  3  - - - 3 
                
INTEREST AND OTHER CHARGES
                
Interest Expense  186  168  216 174 615 518 
Preferred Stock Dividend Requirements of Subsidiaries  1  1   1  1  2  2 
TOTAL
  187  169   217  175  617  520 
                
INCOME BEFORE INCOME TAX EXPENSE, MINORITY
INTEREST EXPENSE AND EQUITY EARNINGS
  397  567  612 397 1,375 1,210 
                
Income Tax Expense  130  189  205 133 443 394 
Minority Interest Expense  1  -  1 1 3 2 
Equity Earnings of Unconsolidated Subsidiaries  5  -   1  2  6  1 
                
INCOME BEFORE DISCONTINUED OPERATIONS
  271  378 
INCOME BEFORE DISCONTINUED OPERATIONS AND
EXTRAORDINARY LOSS
 407 265 935 815 
                
DISCONTINUED OPERATIONS, Net of Tax
  -  3 
DISCONTINUED OPERATIONS, NET OF TAX
  -  -  2  6 
         
INCOME BEFORE EXTRAORDINARY LOSS
 407 265 937 821 
         
EXTRAORDINARY LOSS, NET OF TAX
  -  -  (79) - 
                
NET INCOME
 $271 $381  $407 $265 $858 $821 
                
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
  397,314,642  393,653,162   399,222,569  393,913,463  398,412,473  393,763,946 
                 
BASIC EARNINGS PER SHARE
                 
Income Before Discontinued Operations $0.68 $0.96 
Income Before Discontinued Operations and Extraordinary Loss $1.02 $0.67 $2.35 $2.07 
Discontinued Operations, Net of Tax  -  0.01   -  -  -  0.01 
Income Before Extraordinary Loss 1.02 0.67  2.35 2.08 
Extraordinary Loss, Net of Tax  -  -  (0.20) - 
TOTAL BASIC EARNINGS PER SHARE
 $0.68 $0.97  $1.02 $0.67 $2.15 $2.08 
                 
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
  398,552,113  395,580,106   400,215,911  396,266,250  399,552,630  395,783,241 
                 
DILUTED EARNINGS PER SHARE
                 
Income Before Discontinued Operations $0.68 $0.95 
Income Before Discontinued Operations and Extraordinary Loss $1.02 $0.67 $2.34 $2.06 
Discontinued Operations, Net of Tax  -  0.01   -  -  0.01  0.01 
Income Before Extraordinary Loss 1.02 0.67  2.35 2.07 
Extraordinary Loss, Net of Tax  -  -  (0.20) - 
TOTAL DILUTED EARNINGS PER SHARE
 $0.68 $0.96  $1.02 $0.67 $2.15 $2.07 
                 
CASH DIVIDENDS PAID PER SHARE
 $0.39 $0.37  $0.39 $0.37 $1.17 $1.11 
       
See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31,September 30, 2007 and December 31, 2006
(in millions)
(Unaudited)


 
2007
 
2006
  
2007
 
2006
 
CURRENT ASSETS
             
Cash and Cash Equivalents $259 $301  $196  $301 
Other Temporary Cash Investments  197  425 
Other Temporary Investments  231   425 
Accounts Receivable:               
Customers  757  676   780   676 
Accrued Unbilled Revenues  304  350   376   350 
Miscellaneous  59  44   87   44 
Allowance for Uncollectible Accounts  (31) (30)  (41)  (30)
Total Accounts Receivable  1,089  1,040   1,202   1,040 
Fuel, Materials and Supplies  942  913   961   913 
Risk Management Assets  476  680   351   680 
Regulatory Asset for Under-Recovered Fuel Costs  22  38   23   38 
Margin Deposits  88  120   61   120 
Prepayments and Other  90  71   86   71 
TOTAL
  3,163  3,588   3,111   3,588 
               
PROPERTY, PLANT AND EQUIPMENT
               
Electric:               
Production  17,736  16,787   19,749   16,787 
Transmission  7,094  7,018   7,354   7,018 
Distribution  11,539  11,338   11,894   11,338 
Other (including coal mining and nuclear fuel)  3,423  3,405   3,363   3,405 
Construction Work in Progress  2,902  3,473   2,809   3,473 
Total
  42,694  42,021   45,169   42,021 
Accumulated Depreciation and Amortization  (15,391) (15,240)  16,139   15,240 
TOTAL - NET
  27,303  26,781   29,030   26,781 
               
OTHER NONCURRENT ASSETS
               
Regulatory Assets  2,385  2,477   2,365   2,477 
Securitized Transition Assets  2,134  2,158   2,115   2,158 
Spent Nuclear Fuel and Decommissioning Trusts  1,263  1,248   1,315   1,248 
Goodwill  76  76   76   76 
Long-term Risk Management Assets  351  378   347   378 
Employee Benefits and Pension Assets  316  327   293   327 
Deferred Charges and Other  945  910   804   910 
TOTAL
  7,470  7,574   7,315   7,574 
               
Assets Held for Sale
  -  44   -   44 
               
TOTAL ASSETS
 $37,936 $37,987  $39,456  $37,987 

See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31,September 30, 2007 and December 31, 2006
(Unaudited)


     
2007
 
2006
   
2007
 
2006
 
CURRENT LIABILITIES
CURRENT LIABILITIES
 
(in millions)
 
CURRENT LIABILITIES
 
(in millions)
 
Accounts PayableAccounts Payable$1,263 $1,360 Accounts Payable $1,121 $1,360 
Short-term DebtShort-term Debt 175  18 Short-term Debt 587 18 
Long-term Debt Due Within One YearLong-term Debt Due Within One Year 1,377  1,269 Long-term Debt Due Within One Year 910 1,269 
Risk Management LiabilitiesRisk Management Liabilities 403  541 Risk Management Liabilities 267 541 
Customer DepositsCustomer Deposits 315  339 Customer Deposits 326 339 
Accrued TaxesAccrued Taxes 758  781 Accrued Taxes 616 781 
Accrued InterestAccrued Interest 247  186 Accrued Interest 246 186 
OtherOther 770  962 Other  835  962 
TOTAL
TOTAL
 5,308  5,456 
TOTAL
  4,908  5,456 
            
NONCURRENT LIABILITIES
NONCURRENT LIABILITIES
      
NONCURRENT LIABILITIES
     
Long-term DebtLong-term Debt 12,525  12,429 Long-term Debt 13,866 12,429 
Long-term Risk Management LiabilitiesLong-term Risk Management Liabilities 219  260 Long-term Risk Management Liabilities 210 260 
Deferred Income TaxesDeferred Income Taxes 4,581  4,690 Deferred Income Taxes 4,585 4,690 
Regulatory Liabilities and Deferred Investment Tax CreditsRegulatory Liabilities and Deferred Investment Tax Credits 2,759  2,910 Regulatory Liabilities and Deferred Investment Tax Credits 2,886 2,910 
Asset Retirement ObligationsAsset Retirement Obligations 1,035  1,023 Asset Retirement Obligations 1,059 1,023 
Employee Benefits and Pension ObligationsEmployee Benefits and Pension Obligations 829  823 Employee Benefits and Pension Obligations 855 823 
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 146  148 
Deferred Gain on Sale and Leaseback – Rockport Plant Unit 2Deferred Gain on Sale and Leaseback – Rockport Plant Unit 2 141 148 
Deferred Credits and OtherDeferred Credits and Other 933  775 Deferred Credits and Other  976  775 
TOTAL
TOTAL
 23,027  23,058 
TOTAL
  24,578  23,058 
            
TOTAL LIABILITIES
TOTAL LIABILITIES
 28,335  28,514 
TOTAL LIABILITIES
  29,486  28,514 
            
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’ EQUITY
COMMON SHAREHOLDERS’ EQUITY
      
COMMON SHAREHOLDERS’ EQUITY
     
Common Stock Par Value $6.50:Common Stock Par Value $6.50:      Common Stock Par Value $6.50:     
  2007  2006       2007 2006      
Shares Authorized  600,000,000  600,000,000       600,000,000 600,000,000      
Shares Issued  419,667,962  418,174,728       421,328,600 418,174,728      
(21,499,992 shares were held in treasury at March 31, 2007 and December 31, 2006) 2,728  2,718 
(21,499,992 shares were held in treasury at September 30, 2007 and December 31, 2006)(21,499,992 shares were held in treasury at September 30, 2007 and December 31, 2006) 2,739 2,718 
Paid-in CapitalPaid-in Capital 4,270  4,221 Paid-in Capital 4,328 4,221 
Retained EarningsRetained Earnings 2,795  2,696 Retained Earnings 3,070 2,696 
Accumulated Other Comprehensive Income (Loss)Accumulated Other Comprehensive Income (Loss) (253) (223)Accumulated Other Comprehensive Income (Loss)  (228) (223)
TOTAL
TOTAL
 9,540  9,412 
TOTAL
  9,909  9,412 
            
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
$37,936 $37,987 
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 $39,456 $37,987 

See Condensed Notes to Condensed Consolidated Financial Statements.


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the ThreeNine Months Ended March 31,September 30, 2007 and 2006
(in millions)
(Unaudited)

  
2007
  
2006
 
OPERATING ACTIVITIES
      
Net Income
 $858  $821 
Less:  Discontinued Operations, Net of Tax  (2)  (6)
Income Before Discontinued Operations
  856   815 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
        
Depreciation and Amortization  1,144   1,084 
Deferred Income Taxes  44   (88)
Deferred Investment Tax Credits  (18)  (20)
Extraordinary Loss, Net of Tax  79   - 
Asset Impairments, Investment Value Losses and Other Related Charges  -   209 
Carrying Costs Income  (38)  (66)
Mark-to-Market of Risk Management Contracts  22   (21)
Amortization of Nuclear Fuel  48   38 
Deferred Property Taxes  118   105 
Fuel Over/Under-Recovery, Net  (133)  158 
Gain on Sales of Assets and Equity Investments, Net  (28)  (71)
Change in Other Noncurrent Assets  (87)  36 
Change in Other Noncurrent Liabilities  116   26 
Changes in Certain Components of Working Capital:
        
Accounts Receivable, Net  (209)  139 
Fuel, Materials and Supplies  (13)  (84)
Margin Deposits  59   130 
Accounts Payable  (54)  (49)
Customer Deposits  (13)  (235)
Accrued Taxes, Net  (119)  176 
Accrued Interest  22   10 
Other Current Assets  (33)  12 
Other Current Liabilities  (133)  (108)
Net Cash Flows From Operating Activities
  1,630   2,196 
         
INVESTING ACTIVITIES
        
Construction Expenditures  (2,595)  (2,428)
Change in Other Temporary Cash Investments, Net  (50)  20 
Purchases of Investment Securities  (8,632)  (8,153)
Sales of Investment Securities  8,849   8,056 
Acquisitions of Darby, Lawrenceburg and Dresden Plants  (512)  - 
Proceeds from Sales of Assets  78   120 
Other  (73)  (72)
Net Cash Flows Used For Investing Activities
  (2,935)  (2,457)
         
FINANCING ACTIVITIES
        
Issuance of Common Stock  116   24 
Issuance of Long-term Debt  1,924   1,229 
Change in Short-term Debt, Net  569   11 
Retirement of Long-term Debt  (870)  (711)
Dividends Paid on Common Stock  (467)  (437)
Other  (72)  3 
Net Cash Flows From Financing Activities
  1,200   119 
         
Net Decrease in Cash and Cash Equivalents
  (105)  (142)
Cash and Cash Equivalents at Beginning of Period
  301   401 
Cash and Cash Equivalents at End of Period
 $196  $259 
         
SUPPLEMENTARY INFORMATION
        
Cash Paid for Interest, Net of Capitalized Amounts $549  $462 
Net Cash Paid for Income Taxes  363   206 
Noncash Acquisitions Under Capital Leases  59   66 
Construction Expenditures Included in Accounts Payable at September 30,  265   334 
Nuclear Fuel Expenditures Included in Accounts Payable at September 30,  1   - 
Noncash Assumption of Liabilities Related to Acquisitions  8   - 

  
2007
 
2006
 
OPERATING ACTIVITIES
       
Net Income
 $271 $381 
Less: Discontinued Operations, Net of Tax  -  (3)
Income before Discontinued Operations
  271  378 
Adjustments for Noncash Items:
       
Depreciation and Amortization  391  348 
Deferred Income Taxes  5  7 
Deferred Investment Tax Credits  (6) (7)
Carrying Costs Income  (8) (30)
Mark-to-Market of Risk Management Contracts  22  (9)
Amortization of Nuclear Fuel  16  14 
Deferred Property Taxes  (67) (82)
Fuel Over/Under-Recovery, Net  (62) 103 
Gain on Sales of Assets and Equity Investments, Net  (23) (71)
Change in Other Noncurrent Assets  44  45 
Change in Other Noncurrent Liabilities  16  10 
Changes in Certain Components of Working Capital:
       
Accounts Receivable, Net  (29) 214 
Fuel, Materials and Supplies  (3) (50)
Margin Deposits  33  50 
Accounts Payable  (31) (115)
Accrued Taxes  32  176 
Customer Deposits  (23) (157)
Other Current Assets  (40) 19 
Other Current Liabilities  (187) (260)
Net Cash Flows From Operating Activities
  351  583 
        
INVESTING ACTIVITIES
       
Construction Expenditures  (907) (765)
Change in Other Temporary Cash Investments, Net  (20) 27 
Purchases of Investment Securities  (3,693) (2,469)
Sales of Investment Securities  3,929  2,380 
Proceeds from Sales of Assets  68  111 
Other  (5) (34)
Net Cash Flows Used For Investing Activities
  (628) (750)
        
FINANCING ACTIVITIES
       
Issuance of Common Stock  54  5 
Change in Short-term Debt, Net  157  216 
Issuance of Long-term Debt  247  55 
Retirement of Long-term Debt  (49) (142)
Dividends Paid on Common Stock  (155) (146)
Other  (19) 54 
Net Cash Flows From Financing Activities
  235  42 
        
Net Decrease in Cash and Cash Equivalents
  (42) (125)
Cash and Cash Equivalents at Beginning of Period
  301  401 
Cash and Cash Equivalents at End of Period
 $259 $276 
        
SUPPLEMENTARY INFORMATION
       
Cash Paid for Interest, Net of Capitalized Amounts $152 $159 
Net Cash Paid for Income Taxes  66  13 
Noncash Acquisitions Under Capital Leases  11  20 
Construction Expenditures Included in Accounts Payable at March 31,  323  246 
        
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 ThreeNine Months Ended March 31,September 30, 2007 and 2006
(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, 2005
DECEMBER 31, 2005
  415 $2,699 $4,131 $2,285 $(27)$9,088 
DECEMBER 31, 2005
 415 $2,699 $4,131 $2,285 $(27)$9,088 
Issuance of Common StockIssuance of Common Stock    1 4     5 Issuance of Common Stock 1 5 19     24 
Common Stock DividendsCommon Stock Dividends        (146)   (146)Common Stock Dividends       (437)   (437)
OtherOther      2      2 Other     3      3 
TOTAL
TOTAL
             8,949 
TOTAL
            8,678 
                            
COMPREHENSIVE INCOME
COMPREHENSIVE INCOME
              
COMPREHENSIVE INCOME
             
Other Comprehensive Income, Net of Tax:
Other Comprehensive Income, Net of Tax:
              
Other Comprehensive Income, Net of Tax:
             
Cash Flow Hedges, Net of Tax of $19          35 35 Cash Flow Hedges, Net of Tax of $10         18 18 
Securities Available for Sale, Net of Tax of $10          19 19 Securities Available for Sale, Net of Tax of $4         8 8 
NET INCOME
NET INCOME
        381    381 
NET INCOME
       821    821 
TOTAL COMPREHENSIVE INCOME
TOTAL COMPREHENSIVE INCOME
                 435 
TOTAL COMPREHENSIVE INCOME
                 847 
MARCH 31, 2006
  415 $2,700 $4,137 $2,520 $27 $9,384 
SEPTEMBER 30, 2006
SEPTEMBER 30, 2006
  416 $2,704 $4,153 $2,669 $(1)$9,525 
                            
DECEMBER 31, 2006
DECEMBER 31, 2006
  418 $2,718 $4,221 $2,696 $(223)$9,412 
DECEMBER 31, 2006
 418 $2,718 $4,221 $2,696 $(223)$9,412 
              
FIN 48 Adoption, Net of TaxFIN 48 Adoption, Net of Tax        (17)   (17)FIN 48 Adoption, Net of Tax       (17)   (17)
Issuance of Common StockIssuance of Common Stock  2 10 44     54 Issuance of Common Stock 3 21 95     116 
Common Stock DividendsCommon Stock Dividends        (155)   (155)Common Stock Dividends       (467)   (467)
OtherOther      5      5 Other     12      12 
TOTAL
TOTAL
             9,299 
TOTAL
            9,056 
                            
COMPREHENSIVE INCOME
COMPREHENSIVE INCOME
              
COMPREHENSIVE INCOME
             
Other Comprehensive Loss, Net of Tax:
              
Other Comprehensive Income
(Loss), Net of Tax:
Other Comprehensive Income
(Loss), Net of Tax:
             
Cash Flow Hedges, Net of Tax of $6         (11) (11)
Cash Flow Hedges, Net of Tax of $12          (22) (22)Securities Available for Sale, Net of Tax of $3         (5) (5)
Securities Available for Sale, Net of Tax of $4          (8) (8)
SFAS 158 Costs Established as a Regulatory
  Asset for the Reapplication of SFAS 71, Net
  of Tax of $6
         11 11 
NET INCOME
NET INCOME
        271    271 
NET INCOME
       858    858 
TOTAL COMPREHENSIVE INCOME
TOTAL COMPREHENSIVE INCOME
                 241 
TOTAL COMPREHENSIVE INCOME
                 853 
MARCH 31, 2007
  420 $2,728 $4,270 $2,795 $(253)$9,540 
SEPTEMBER 30, 2007
SEPTEMBER 30, 2007
  421 $2,739 $4,328 $3,070 $(228)$9,909 

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, Discontinued Operations and Assets Held for Sale
6.Benefit Plans
7.Business Segments
8.Income Taxes
9.Financing Activities

 

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

         1.
1.
SIGNIFICANT ACCOUNTING MATTERS

General

The accompanying unaudited condensed consolidated financial statements and footnotes were prepared in accordance with accounting principles generally accepted in the United States of America (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 our results of operations, financial position and cash flows for the interim periods.  The results of operations for the three or nine months ended March 31,September 30, 2007 are not necessarily indicative of results that may be expected for the year ending December 31, 2007.  The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2006 consolidated financial statements and notes thereto, which are included in our Annual Report on Form 10-K for the year ended December 31, 2006 as filed with the SEC on February 28, 2007.

Property, Plant and Equipment and Equity Investments

Electric utility property, plant and equipment are stated at original purchase cost. Property, plant and equipment of nonregulated operations and other investments are stated at fair market value at acquisition (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals.  Additions, major replacements and betterments are added to the plant accounts.  For the Utility Operations segment, normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for both cost-based rate-regulated and most nonregulated operations under the group composite method of depreciation.  The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss.  The equipment in each primary electric plant account is identified as a separate group.  Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in the original cost, less salvage, being charged to accumulated depreciation.  For the nonregulated generation assets, a gain or loss would be recorded if the retirement is not considered an interim routine replacement.  The depreciation rates that are established for the generating plants take into account the past history of interim capital replacements and the amount of salvage received.  These rates and the related lives are subject to periodic review.  Gains and losses are recorded for any retirements in the MEMCO Operations and Generation and Marketing segments.  Removal costs are charged to regulatory liabilities for cost-based rate-regulated operations and charged to expense for nonregulated operations.  The costs of labor, materials and overhead incurred to operate and maintain our plants are included in operating expenses.

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held for sale criteria under SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.”  Equity investments are required to be tested for impairment when it is determined there may be an other than temporary loss in value.

The fair value of an asset or investment is the amount at which that asset or investment could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets or investments in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.
Revenue Recognition

Traditional Electricity Supply and Delivery Activities

Revenues are recognized from retail and wholesale electricity supply sales and electricity transmission and distribution delivery services.  We recognize the revenues on our Condensed Consolidated Statements of Income upon delivery of the energy to the customer and include unbilled as well as billed amounts.  In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue.

Most of the power produced at the generation plants of the AEP East companies is sold to PJM, the RTO operating in the east service territory, and we purchase power back from the same RTO to supply power to our load.  These power sales and purchases are reported on a net basis as revenues on our Condensed Consolidated Statements of Income.  Other RTOs in which we operate do not function in the same manner as PJM.  They function as balancing organizations and not as an exchange.

Physical energy purchases, including those from all RTOs, that are identified as non-trading, but excluding PJM purchases described in the preceding paragraph, are accounted for on a gross basis in Purchased Energy for Resale on our Condensed Consolidated Statements of Income.

In general, we record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase-and-sale contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated, such as in Ohio and the ERCOT portion of Texas.  In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

For power purchased under derivative contracts in our west zone where we are short capacity, we recognize as revenues the unrealized gains and losses (other than those subject to regulatory deferral) that result from measuring these contracts at fair value during the period before settlement.  If the contract results in the physical delivery of power from a RTO or any other counterparty, we reverse the previously recorded unrealized gains and losses from MTM valuations and record the settled amounts gross as Purchased Energy for Resale.  If the contract does not result in physical delivery, we reverse the previously recorded unrealized gains and losses from MTM valuations and record the settled amounts as revenues on our Condensed Consolidated Statements of Income on a net basis.

Energy Marketing and Risk Management Activities

We engage in wholesale electricity, natural gas, coal and emission allowances marketing and risk management activities focused on wholesale markets where we own assets.  Our activities include the purchase and sale of energy under forward contracts at fixed and variable prices and the buying and selling of financial energy contracts, which include exchange traded futures and options and over-the-counter options and swaps.  We engage in certain energy marketing and risk management transactions with RTOs.

We recognize revenues and expenses from wholesale marketing and risk management transactions that are not derivatives upon delivery of the commodity.  We use MTM accounting for wholesale marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow or fair value hedge relationship, or as a normal purchase or sale.  We include the unrealized and realized gains and losses on wholesale marketing and risk management transactions that are accounted for using MTM in revenues on our Condensed Consolidated Statements of Income on a net basis.  In jurisdictions subject to cost-based regulation, we defer the unrealized MTM amounts as regulatory assets (for losses) and regulatory liabilities (for gains).  We include unrealized MTM gains and losses resulting from derivative contracts on our Condensed Consolidated Balance Sheets as Risk Management Assets or Liabilities as appropriate.

Certain wholesale marketing and risk management transactions are designated as hedges of future cash flows as a result of forecasted transactions (cash flow hedge) or as hedges of a recognized asset, liability or firm commitment (fair value hedge).  We recognize the gains or losses on derivatives designated as fair value hedges in revenues on our Condensed Consolidated Statements of Income in the period of change together with the offsetting losses or gains on the hedged item attributable to the risks being hedged.  For derivatives designated as cash flow hedges, we initially record the effective portion of the derivative’s gain or loss as a component of Accumulated Other Comprehensive Income (Loss) and, depending upon the specific nature of the risk being hedged, subsequently reclassify into revenues or expenses on our Condensed Consolidated Statements of Income when the forecasted transaction is realized and affects earnings.  We recognize the ineffective portion of the gain or loss in revenues or expense, depending on the specific nature of the associated hedged risk, on our Condensed Consolidated Statements of Income immediately, except in those jurisdictions subject to cost-based regulation.  In those regulated jurisdictions we defer the ineffective portion as regulatory assets (for losses) and regulatory liabilities (for gains).

Components of Accumulated Other Comprehensive Income (Loss) (AOCI)

AOCI is included on the Condensed Consolidated Balance Sheets in the common shareholders’ equity section.  The following table provides the components that constitute the balance sheet amount in AOCI:

 
March 31,
 
December 31,
  
September 30,
  
December 31,
 
 
2007
 
2006
  
2007
  
2006
 
Components
 
(in millions)
  
(in millions)
 
Securities Available for Sale, Net of Tax $10 $18  $13  $18 
Cash Flow Hedges, Net of Tax  (28) (6)  (17)  (6)
SFAS 158 Adoption, Net of Tax  (235) (235)
SFAS 158 Costs, Net of Tax  (224)  (235)
Total
 $(253)$(223) $(228) $(223)

At March 31,September 30, 2007, during the next twelve months, we expect to reclassify approximately $11$2 million of net lossesgains from cash flow hedges in AOCI to Net Income during the next twelve months at the time the hedged transactions affect Net Income.  The actual amounts that are reclassified from AOCI to Net Income can differ as a result of market fluctuations.

At March 31,September 30, 2007, thirty-ninethirty-three months is the maximum length of time that our exposure to variability in future cash flows is hedged with contracts designated as cash flow hedges.

Earnings Per Share (EPS)

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

 
Three Months Ended March 31,
  
Three Months Ended September 30,
 
 
2007
 
2006
  
2007
  
2006
 
 
(in millions, except per share data)
  
(in millions, except per share data)
 
    
$/share
    
$/share
     
$/share
     
$/share
 
Earnings Applicable to Common Stock
 $271    $381     $407     $265    
                           
Average Number of Basic Shares Outstanding  397.3 $0.68  393.7 $0.97   399.2  $1.02   393.9  $0.67 
Average Dilutive Effect of:                             
Performance Share Units  0.6  -  1.4  (0.01)  0.5   -   2.0   - 
Stock Options  0.5  -  0.3  -   0.3   -   0.2   - 
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
  398.6 $0.68  395.6 $0.96   400.2  $1.02   396.3  $0.67 




  
Nine Months Ended September 30,
 
  
2007
  
2006
 
  
(in millions, except per share data)
 
     
$/share
     
$/share
 
Earnings Applicable to Common Stock
 $858     $821    
               
Average Number of Basic Shares Outstanding  398.4  $2.15   393.8  $2.08 
Average Dilutive Effect of:                
Performance Share Units  0.6   -   1.6   (0.01)
Stock Options  0.4   -   0.2   - 
Restricted Stock Units  0.1   -   0.1   - 
Restricted Shares  0.1   -   0.1   - 
Average Number of Diluted Shares
   Outstanding
  399.6  $2.15   395.8  $2.07 

The assumed conversion of our share-based compensation does not affect net earnings for purposes of calculating diluted earnings per share as of March 31,September 30, 2007.

Options to purchase 0.1 million and 0.4 million shares of common stock were outstanding at March 31,September 30, 2007 and 2006, respectively, but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the quarter-endaverage market price of the common shares for the period and, therefore, the effect would not be antidilutive.dilutive.

Supplementary Information
 
Three Months Ended
  
Nine Months Ended
 
 
Three Months Ended
March 31,
  
September 30,
  
September 30,
 
 
2007
 
2006
  
2007
  
2006
  
2007
  
2006
 
Related Party Transactions
 
(in millions)
  
(in millions)
  
(in millions)
 
AEP Consolidated Purchased Energy:                   
Ohio Valley Electric Corporation (43.47% Owned) $49 $55  $59  $54  $164  $167 
Sweeny Cogeneration Limited Partnership (50% Owned)  30  34 
AEP Consolidated Other Revenues - Barging and Other
Transportation Services - Ohio Valley Electric Corporation (43.47% Owned)
  9  7 
Sweeny Cogeneration Limited Partnership (a)  27   30   86   92 
AEP Consolidated Other Revenues – Barging and Other Transportation Services – Ohio Valley Electric Corporation
(43.47% Owned)
  
7
   8   
24
   23 
AEP Consolidated Revenues – Utility Operations:                
Power Pool Purchases – Ohio Valley Electric Corporation
(43.47% Owned)
  (12)  -   (16)  - 

(a)In October 2007, we sold our 50% ownership in the Sweeny Cogeneration Limited Partnership.  See “Sweeny Cogeneration Plant” section of Note 5.

Reclassifications

Certain prior period financial statement items have been reclassified to conform to current period presentation.

On our 2006 Condensed Consolidated Statement of Income, we reclassified regulatory credits related to regulatory asset cost deferral on ARO from Depreciation and Amortization to Other Operation and Maintenance to offset the ARO accretion expense.  These reclassifications totaled $7$6 million and $19 million for the three and nine months ended March 31, 2006.September 30, 2006, respectively.

In our segment information, we reclassified two subsidiary companies, AEP Texas Commercial & Industrial Retail GP, LLC and AEP Texas Commercial & Industrial Retail LP, from the Utility Operations segment to the Generation and Marketing segment.  Combined revenues for these companies totaled $5$7 million and $23 million for the three and nine months ended March 31, 2006.September 30, 2006, respectively.  As a result, on our 2006 Condensed Consolidated Statement of Income, we reclassified these revenues from Utility Operations to Other.

These revisions had no impact on our previously reported results of operations, cash flows or changes in shareholders’ equity.

2.
NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM

         2.NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of exposure drafts or 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 2007 and standards issued but not implemented that we have determined relate to our operations.

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 being market prices in active markets.  The standard requires fair value measurements be disclosed by hierarchy level, and an entity includeincludes its own credit standing in the measurement of its liabilities and modifies the transaction price presumption.

SFAS 157 is effective for interim and annual periods in fiscal years beginning after November 15, 2007.  We expect that the adoption of this standard will impact MTM valuations of certain contracts, but wecontracts.  We are unable to quantifyevaluating the effect.effect of the adoption of SFAS 157 on our results of operations and financial condition.  Although the statement is applied prospectively upon adoption, the effect of certain transactions is applied retrospectively as of the beginning of the fiscal year of application, with a cumulative effect adjustment to the appropriate balance sheet items.  Although we have not completed our analysis, we expect this cumulative effect adjustment will have an immaterial impact on our financial statements.  We will adopt SFAS 157 effective January 1, 2008.

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.

SFAS 159 is effective for annual periods in fiscal years beginning after November 15, 2007.  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.  If we elect the fair value option promulgated by this standard, the valuations of certain assets and liabilities may be impacted.  The statement is applied prospectively upon adoption.  We will adopt SFAS 159 effective January 1, 2008.  Although we have not completed our analysis, we expect the adoption of this standard to have an immaterial impact on our financial statements.

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 will be applied prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years beginning after September 15, 2007.  We expect that the adoption of this standard will have an immaterial impact on our financial statements.  We will adopt EITF 06-11 effective January 1, 2008.
FIN 48 “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1 "Definition“Definition of Settlement in FASB
   Interpretation No. 48"48” (FIN 48)

In July 2006, the FASB issued FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” and in May 2007, the FASB issued FASB Staff Position FIN 48-1 “Definition of Settlement in FASB Interpretation No. 48.”  FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold (whether a tax position is more likely than not to be sustained) without which, the benefit of that position is not recognized in the financial statements.  It requires a measurement determination for recognized tax positions based on the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.  FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

FIN 48 requires that the cumulative effect of applying this interpretation be reported and disclosed as an adjustment to the opening balance of retained earnings for that fiscal year and presented separately.  We adopted FIN 48 effective January 1, 2007, with an unfavorable adjustment to retained earnings of $17 million.

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.

FIN 39-1 is effective for fiscal years beginning after November 15, 2007.  We expect this standard to change our method of netting certain balance sheet amounts but are unable to quantify the effect.  It requires retrospective application as a change in accounting principle for all periods presented.  We will adopt FIN 39-1 effective January 1, 2008.

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 business combinations, revenue recognition, liabilities and equity, derivatives disclosures, emission allowances, earnings per share calculations, leases, insurance, subsequent events 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 operations 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.  See “Virginia Restructuring” section of Note 3.RATE MATTERS

3.
RATE MATTERS

As discussed in our 2006 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within our 2006 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, cash flows and possibly financial condition.  The following discusses ratemaking developments in 2007 and updates the 2006 Annual Report.

Ohio Rate Matters

Ohio Restructuring and Rate Stabilization Plans

Ending December 31, 2008, the approved three-year RSPs provide CSPCo and OPCo increases in their generation rates by 3% and 7%, respectively, effective January 1 each year and allow possible additional annual generation rate increases of up to an average of 4% per year to recover governmentally-mandated costs.  In January 2007, CSPCo and OPCo filed with the PUCO underpursuant to the average 4% generation rate provision of their RSPs to increase their annual generation rates for 2007 by $24 million and $8 million, respectively, to recover new governmentally-mandated costs. Pursuant to the RSPs,  CSPCo and OPCo implemented these proposed increases effectivein May 2007 subject to refund.  In October 2007, the PUCO issued an order in the average 4% proceeding which granted CSPCo and OPCo an annual generation rate increase through December 2008 of $19 million and $4 million, respectively.  In September 2007, CSPCo and OPCo recorded a provision for refund to adjust revenues consistent with the beginningrate revenues granted by the PUCO.  Management expects that the average 4% rider will be reduced to implement the required refunds, while OPCo would implement a credit to customers’ bills.  CSPCo and OPCo intend to seek rehearing of the MayPUCO decision.

In October 2007, billing cycle. TheseCSPCo and OPCo made a new filing with the PUCO pursuant to the average 4% generation rate provision of their RSPs for an additional increase in their annual generation rates effective January 2008 of $35 million and $12 million, respectively, to recover governmentally-mandated costs and increased costs related to marginal-loss pricing.  CSPCo and OPCo will implement these proposed increases arein January 2008 subject to refund until the PUCO issues a final order in the matter.  The hearingManagement is scheduledunable to begin in late May 2007.predict the outcome of this filing and its impact on future results of operations and cash flows.

In March 2007, CSPCo filed an application under the average 4% generation rate provision of thetheir RSP to adjust the Power Acquisition Rider (PAR) which was authorized in 2005 by the PUCO in connection withrelated to CSPCo's acquisition of Monongahela Power Company's certified territory in Ohio. The PAR is intendedwas increased to recover the difference between CSPCo's tariffed generation service rates and the cost of a new purchase power acquiredmarket contract to serve the former Monongahela Power load.load for that service territory.  The PAR was set for an initial 17-month period of January 2006 through May 2007. The filing would adjustPUCO approved the requested increase in the PAR, for the nineteen month period of June 2007 through December 2008. The filing reflects a true up for estimated under-recoveries during the initial period, $8 million as of March 31, 2007, as well as the power acquisition costs for the upcoming nineteen-month period. If approved,which is expected to increase CSPCo's revenues would increase by $22 million and $38 million for 2007 and 2008, respectively.

In March 2007, CSPCo and OPCo filed a settlement agreement at the PUCO resolving the Ohio Supreme Court's remand of the PUCO’s RSP order.  The Supreme Court indicated concern with the absence of a competitive bid process as an alternative to the generation rates set by the RSP. In response, the settling parties agreed to have CSPCo and OPCo take bids for Renewable Energy Certificates (RECs).  CSPCo and OPCo will give customers the option to pay a generation rate premium that would encourage the development of renewable energy sources by reimbursing CSPCo and OPCo for the cost of the RECs and the administrative costs of the program.  This settlement agreement was supported by theThe Office of Consumers'Consumers’ Counsel, the Ohio Partners for Affordable Energy, the Ohio Energy Group and the PUCO staff.staff supported this settlement agreement.  In May 2007, the PUCO adopted the settlement agreement in its entirety.

CSPCo and OPCo are involved in discussions with various stakeholders in Ohio about potential legislation to address the period following the expiration of the RSPs on December 31, 2008. At this time, management is unable to predict whether CSPCo and OPCo will transition to market pricing, as permitted by the current Ohio restructuring legislation, extend their RSP rates, with or without modification, or become subject to a legislative reinstatement of some form of cost-based regulation for their generation supply business on January 1, 2009 when the RSP period ends.

Customer Choice Deferrals

As provided in theCSPCo’s and OPCo’s restructuring settlement agreement approved by the PUCO in 2000, allows CSPCo and OPCo establishedto establish regulatory assets for customer choice implementation costs and related carrying costs in excess of $20 million each for recovery in the next general base rate filing which changes distribution rates after December 31, 2007 for OPCo and December 31, 2008 for CSPCo. Pursuant to the RSPs, recovery of these amounts for OPCo was further deferred until the next base rate filing to change distribution rates after the end of the RSP period of December 31, 2008.rates.  Through March 31,September 30, 2007, CSPCo and OPCo incurred $50$53 million and $51$54 million, respectively, of such costs and established regulatory assets of $25$27 million each for the future recovery of such costs.  CSPCo and OPCo also have not recognized $5the right to recover $6 million and $6$7 million, respectively, of equity carrying costs which are recognizable when collected.in addition to these regulatory assets.  In 2007, CSPCo and OPCo incurred $3 million and $4 million, respectively, of such costs and established regulatory assets of $2 million each for such costs.  Management believes that the deferred customer choice implementation costs were prudently incurred to implement customer choice in Ohio and are probable of recovery in future distribution rates.  However, failure to recover such costs would have an adverse effect on results of operations and cash flows.

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 during 2006; Phase 2, concurrent recovery of construction-financing costs; and Phase 3, recovery or refund in distribution rates of any difference between the market-based standard service offer price for generation and the cost of operating and maintaining the plant, including a return on and return of the ultimate cost to construct the plant, originally projected to be $1.2 billion, along with fuel, consumables and replacement power costs.  The proposed recoveries in Phases 1 and 2 would be applied against the average 4% limit on additional generation rate increases CSPCo and OPCo could request under their RSPs.

In April 2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase 1 of the cost recovery proposal.  In June 2006, the PUCO issued another order approving a tariff to recover Phase 1 pre-construction costs over a period of no more than a twelve-month periodtwelve months effective July 1, 2006.  Through March 31,September 30, 2007, CSPCo and OPCo each recorded pre-construction IGCC regulatory assets of $10 million and each recovered $9collected the entire $12 million approved by the PUCO.  As of those costs.September 30, 2007, CSPCo and OPCo will recoverhave recorded a liability of $2 million each for the remaining amounts through June 30, 2007. over-recovered portion.  CSPCo and OPCo expect to incur additional pre-construction costs equal to or greater than the $12 million each recovered.  
The PUCO indicated 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 chargesPhase 1 costs collected for pre-construction costs, associated with items that may be utilized in IGCC projects at other sites, must be refunded to Ohio ratepayers with interest.  The PUCO deferred ruling on cost recovery for Phases 2 and 3 cost recovery until further hearings are held.  A date for further rehearings has not been set.

In August 2006, the Ohio Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order in the IGCC proceeding.  The Ohio Supreme Court heard oral arguments for these appeals in October 2007.  Management believes that the PUCO’s authorization to begin collection of Phase 1 rates is lawful.  Management, however, cannot predict the outcome of these appeals.  If the PUCO’s order is found to be unlawful, CSPCo and OPCo could be required to refund Phase I1 cost-related recoveries.

Pending the outcome of the Supreme Court litigation, CSPCo and OPCo announced they may delay the start of construction of the IGCC plant. Recent estimates of the cost to build an IGCC plant have escalated to $2.2 billion.  CSPCo and OPCo may need to request an extension to the 5-year start of construction requirement if the commencement of construction is delayed beyond 2011.

Distribution Reliability Plan

In January 2006, CSPCo and OPCo initiated a proceeding at the PUCO seeking a new distribution rate rider to fund enhanced distribution reliability programs. In the fourth quarter of 2006, as directed by the PUCO, CSPCo and OPCo filed a proposed enhanced reliability plan.  The plan contemplated CSPCo and OPCo recovering approximately $28 million and $43 million, respectively, in additional distribution revenue during an eighteen montheighteen-month period beginning July 2007. In January 2007, the OCC filed testimony, which argued that CSPCo and OPCo should be required to improve distribution service reliability with funds from their existing rates.

In April 2007, CSPCo and OPCo filed a joint motion with the PUCO staff, the Ohio Consumers’ Counsel, the Appalachian People’s Action Coalition, the Ohio Partners for Affordable Energy and the Ohio Manufacturers Association to withdraw the proposed enhanced reliability plan.  The motion was granted in May 2007.  CSPCo and OPCo do not intend to implement the enhanced reliability plan without recovery of any incremental costs.

Ormet

Effective January 1, 2007, CSPCo and OPCo began to serve Ormet, a major industrial customer with a 520 MW load underin accordance with a PUCO encouraged settlement agreement. The settlement agreement between CSPCo and OPCo, Ormet, its employees’ union and certain other interested parties that was approved by the PUCO in November 2006.  The settlement agreement provides for the recovery in 2007 and 2008 by CSPCo and OPCo of the difference between $43 per MWH to be paid by Ormet for power and a PUCO approvedPUCO-approved market price, if higher.  The recovery will be accomplished by the amortization of a $57 million ($15 million for CSPCo and $42 million for OPCo) Ohio franchise tax phase-out regulatory liability recorded in 2005 and, if that is not sufficient,insufficient, an increase in RSP generation rates under the additional average 4% generation rate provision of the RSPs. The $43 per MWH price to be paid by Ormet for generation services is above the industrial RSP generation tariff but below current market prices.

In December 2006, CSPCo and OPCo submitted a market price of $47.69 per MWH for 2007, which is pendingwas approved by the PUCO approval.in June 2007.  CSPCo and OPCo have each amortized $5 million of their Ohio Franchise Tax phase-out tax regulatory liability to income through September 30, 2007.  If the PUCO approves a lower market price in 2008, it could have an adverse effect on future results of operations and cash flows.  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 off-system sales margins, which could have an adverse effect on future results of operations and cash flows.margins.

Texas Rate Matters

TCC TEXAS RESTRUCTURING

Texas District Court Appeal Proceedings

TCC recovered its net recoverable stranded generation costs through a securitization financing and is refunding its net other true-up items through a CTC rate rider credit under 2006 PUCT orders.  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 statuteTexas 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 itTCC failed to determine a minimum price at which it would reject bids for the sale of its nuclear generating plant and it bundled out of the moneyout-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 cost,costs, and
·The two federal matters regarding the allocation of off-system sales related to fuel recoveries and the potential tax normalization violation.  See “TCC and TNC Deferred Fuel” and“TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes” and “TCC and TNC Deferred Fuel ” sections below.

Municipal customers and other intervenors also appealed the PUCT true-up and related orders seeking to further reduce TCC’s true-up recoveries.  On February 1,In March 2007, the Texas District Court judge hearing the various appeals issued a letter containing his preliminary determinations. He generallyappeal of the true-up order affirmed the PUCT’s April 4, 2006 final true-up order for TCC with two significant exceptions.  The judge determined that the PUCT erred when it determined TCC’s stranded cost using the sale of assets method instead of the Excess Cost Over Market (ECOM) methodby applying an invalid rule to value TCC’s nuclear plant. The judge also determined that the PUCT erred when it concluded it was required to usedetermine the carrying cost rate specified infor the true-up order.of stranded costs.  However, the District Court did not rule that the carrying cost rate was inappropriate.  The judge directed that these matters should be remanded to the PUCT to determine the specific impact on TCC’s future true-up revenues.

In March 2007,If the District Court judge reversed his earlier preliminary decision and concluded the sale of assets method to value TCC’s nuclear plant was appropriate. The District Court judge did not reconsider his preliminaryCourt’s ruling that the PUCT erred when it concluded it was required to useon the carrying cost rate specified in the true-up order. The District Court judge also determined the PUCT improperly reduced TCC’s net stranded plant costs from the sale of its generating units through the commercial unreasonableness disallowance, which could have a materially favorable effect on TCC. Management cannot predict the ultimate outcome of any future court appeals or any future remanded PUCT proceeding. If the District Court’s carrying cost rate remand ruling is ultimately upheld on appeal and remanded to the PUCT for reconsideration, the PUCT could either confirm the existing weighted average carrying cost (WACC) rate or redeterminedetermine a new rate.  If the PUCT changesreduces the rate, it could result in a material adverse change to TCC’s recoverable carrying costs, results of operations, cash flows and financial condition.

The District Court judge also determined the PUCT improperly reduced TCC’s net stranded plant costs for commercial unreasonableness.  If upheld on appeal, this ruling could have a materially favorable effect on TCC’s results of operations and cash flows.

TCC, the PUCT and intervenors appealed the District Court rulingtrue-up order rulings to the Texas Court of Appeals.  Management cannot predict what actions, if any, the PUCT will take regarding the carrying costs.

outcome of these true-up and related proceedings.  If TCC ultimately succeeds in its appeals in both state and federal court, 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, or if TCC has a tax normalization violation, it could have a substantial adverse effect on future results of operations, cash flows and financial condition.

OTHER TEXAS RESTRUCTURING MATTERS

TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes

In TCC’s 2006 true-up and securitization orders, the PUCT reduced net regulatory assetsTCC’s stranded generation costs and the amount to be securitized by $51 million related to the present value of ADITC and by $10 million related toof EDFIT associated with TCC’s generation assets for a total reduction of $61 million.  The reductions were ordered after the PUCT concluded such reductions would not represent a violation of the Internal Revenue Code normalization requirements.

TCC filed a request for a private letter ruling with the IRS in June 2005 regarding the permissibility under the IRS rules and regulations of the ADITC and EDFIT reduction proposed by the PUCT.  The IRS issued its private letter ruling in May 2006, which stated that the PUCT’s proposed flow-through to customers of the present value of the ADITC and EDFIT benefits as a reduction of stranded costs would result in a normalization violation.  To address the matter and avoid a possible normalization violation, the PUCT agreed to allow TCC to defer an amount of the CTC refund totaling $103 million ($61 million in present value of ADITC and EDFIT associated with TCC’s generation assets plus $42 million of related carrying costs) pending resolution of the normalization issue.  If it is ultimately determined that a refund to customers through the true-up process of the ADITC and EDFIT discussed above, is not a normalization violation, then TCC will be required to refund the $103 million, plus additional carrying costs.costs adversely affecting future cash flows.  However, if such refund ofan ADITC and EDFIT reduction is ultimately determined to cause a normalization violation, TCC anticipates itthe PUCT will be permittedpermit TCC to retain the $61 million present value of ADITC and EDFIT plus carrying costs, favorably impacting future results of operations.operations and cash flows.

If a normalization violation occurs, it could result in TCC’s repayment to the IRS of ADITC on all property, including transmission and distribution property, which approximates $104 million as of March 31,September 30, 2007, and a loss of TCC’s right to claim accelerated tax depreciation in future tax returns.  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.  In TCC’s True-up Proceeding brief in the Texas Court of Appeals, the PUCT requested a remand of the tax normalization issue to consider additional evidence, including TCC’s private letter ruling issued after close of hearings and a change in proposed IRS regulations the PUCT had relied upon in its initial determination.  Management intends to continue its efforts to work with the PUCT to avoid a normalization violation that would adversely affect future results of operations and cash flows.

TCC and TNC Deferred Fuel

The TCCTCC’s deferred fuel over-recovery regulatory liability is a component of the other true-up items net regulatory liability refunded through the CTC rate rider credit.  In 2002, TCC and TNC filed with the PUCT seeking to reconcile fuel costs and establish their final deferred fuel balances.  In its final fuel reconciliation orders, the PUCT ordered a reductionsubstantial reductions in TCC’s and TNC’s recoverable fuel costs for, among other things, the reallocation of additional AEP System off-system sales margins to TCC and TNC under a FERC-approved SIA.tariff.  As of September 30, 2007, TCC has refunded the over-recovered deferred fuel through the CTC rate rider credit.  Both TCC and TNC appealed the PUCT’s rulings regarding a number of issues in the fuel orders in state court and challenged the jurisdiction of the PUCT over the allocation of off-system sales margin allocationsmargins in the federal court.  Intervenors also appealed the PUCT’s final fuel rulings in state court.court seeking to increase the various allowances.

In 2006, the Federal District Court issued orders precluding the PUCT from enforcing the off-system sales reallocation portion of its ruling in the final TNC and TCC fuel reconciliation proceedings.  The Federal court ruled, in both cases, that the FERC, not the PUCT, has jurisdiction over the allocation.  The PUCT appealed both Federal District Court decisions to the United States Court of Appeals.  In TNC’s case, theThe Court of Appeals affirmed the District Court’s decision. Thedecision in the TNC case.  In April 2007, the PUCT has indicated they will appeal this ruling topetitioned the United States Supreme Court. TCC has filedCourt for a Motion for Summary Affirmance based on the outcomereview of the Court of Appeals’ order.  In October 2007, the United States Supreme Court denied review of TNC’s case.  As a result, TNC appeal. For TCC,recorded income of $9 million in the PUCT has concededthird quarter of 2007 by reversing the issue concerningpreviously recorded provision resulting from the allocationPUCT’s ordered reallocation of off-system sales margins to AEP West companies undermargins.  Since it is probable the SIAoutcome in the TCC case, still before the U.S. Court of Appeals, will be the same as governed byin the TNC case. However, the PUCT continues to challenge the allocation of those margins among AEP West companies under the CSW Operating Agreement. If the PUCT’s appeals are ultimately unsuccessful,case, TCC and TNC could recordalso recorded income of $16 million and $8 million, respectively, related to the reversal of the previously recorded fuel over-recovery regulatory liabilities.

If the PUCT is unsuccessfulby reversing its provision in the federal court system, itthird quarter of 2007.  Based on the TNC case, TCC reduced its deferred fuel regulatory liability by $16 million in the third quarter of 2007.
The PUCT or another interested party may file a complaint at the FERC to address the allocation issue.  If a complaint at the FERC results in the PUCT’s decisions being adopted by the FERC, there could be an adverse effect on results of operations and cash flows. An unfavorable FERC ruling may result in a retroactive reallocation of off-system sales margins from AEP East companies to AEP West companies under the then existing SIA allocation method. If the adjustments were applied retroactively, the AEP East companies may be unable to recover the amounts reallocated to the West companies from their customers due to past frozen rates, past inactive fuel clauses and fuel clauses that do not include off-system sales credits. Although management cannot predict if a complaint may be filed at the ultimate outcome of this federal litigation,FERC, management believes that itsthe allocations used were in accordance with the then existingthen-existing FERC-approved SIA and that it should not have to allocate additional off-system sales margins should not be retroactively reallocated to the AEP West companies including TCC and TNC.

In January 2007, TCC began refunding as part of the CTC rate rider credit described above, $149 million of its $165 million over-recovered deferred fuel regulatory liability. The remaining $16 million refund related to the favorable Federal District Court order has been deferred pending the outcome of the federal court appeal and would be subject to refund only upon a successful appeal by the PUCT.

TCC Excess Earnings

In 2005, the Texas Court of Appeals issued a decision finding that the PUCT’s prior order from the unbundled cost of service case 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.  In June 2007, the Texas Supreme Court declined review.  From 2002 to 2005, TCC refunded $55 million of excess earnings under the overturned PUCT order, including interest, of which $30 million went to the affiliated REP. In November 2005,interest. On remand, the PUCT filed a petition for review with the Supreme Court of Texas seeking reversal of the Texas Court of Appeals’ decision. The Supreme Court of Texas requested briefing, which has been provided, but it has not decided whether it will hear the case. Ifmust determine how to implement the Court of Appeals decision given that unauthorized refunds were made.  TCC’s stranded cost recovery, which is upheld and the refund mechanism is found tocurrently on appeal, may be unlawful, the impact on TCC would then depend on: (a) how and if TCC is orderedaffected by the PUCTremedy ordered as a result of the unauthorized refunds.  In 2005, management reflected the obligation to refund the excess earnings to customers through the true-up process and recorded a regulatory asset for the expected refund to ultimatebe received from the REPs, and believes its accounting is correct.  However, certain parties continue to take positions that, if adopted, could result in TCC being required to pay additional amounts of excess earnings or interest which would adversely affect future results of operations and cash flows.  Management cannot predict the outcome of these matters.

TCC Oklaunion Refund

In 2005, TCC filed a special request with the PUCT allowing TCC to file its True-up Proceeding before it had completed the sale of its share of the Oklaunion power plant.  TCC agreed to provide customers the net economic benefit related to its continued ownership of the Oklaunion power plant until the sale closed.  TCC also agreed to reduce stranded costs in the event the Oklaunion power plant sales price increased.  In June 2007, TCC filed with the PUCT reporting no change in the sales price and (b) whetherto include the net economic benefit from the operation of the Oklaunion power plant in the CTC credit rider.  As of September 30, 2007, TCC will be able to recoverhas recorded a $4 million regulatory liability for the amounts previously refundednet economic benefit related to the REPs includingoperation of the REP TCC sold to Centrica.Oklaunion power plant.  Management is unable to predict the ultimate outcome of this litigation and itsfiling.  If the PUCT orders a refund greater than the $4 million recorded liability, it would have an adverse effect on future results of operations and cash flows.

OTHER TEXAS RATE MATTERS

TCC and TNC Energy Delivery Base Rate Filings

TCC and TNC each filed a base rate case seeking to increase transmission and distribution energy delivery services (wires) base rates in Texas.  TCC and TNC requested increases in annual base rates of $81 million and $25 million, in annual increases, respectively.  Both requests includeincluded a return on common equity of 11.25% and thea favorable impact of thefrom an expiration of the CSW merger savings rate credits.credits (merger credits).  In March 2007, various intervenors and the PUCT staff filed their recommendations. Though the recommendations varied, the range of recommended increase waswith increases ranging from $8 million to $30 million for TCC and $1 million to $14 million for TNC.TCC.  The recommended return on common equity ranged from 9.00% to 9.75%.  In April 2007, TCC and TNC filed rebuttal testimony reducing theits requested annual increasesincrease to $70 million for TCC and $22 million for TNC including a reduced requested return on common equity of 10.75%.  Hearings beganIn May 2007, TNC reached a settlement agreement for a revenue increase of $14 million including an $8 million increase in Aprilbase rates and a $6 million increase related to the impact of the expiration of the merger credits.  TNC received a final order in May 2007 and are scheduled to concludebegan billing the increase in MayJune 2007.Management expects the new

Beginning in June 2007, TCC implemented an interim base wires rates to become effective,rate increase of $50 million, subject to refund, in accordance with Texas law.  In addition, TCC’s merger credits were terminated in June 2007, which effectively increased base rates by $20 million on an annual basis.  In May 2007, an ALJ issued an interim order affirming the second quartertermination of the merger credits.  In June 2007, with a decision from the PUCT expectedaffirmed the ALJ ruling.  In August 2007, an ALJ issued a proposal for decision.  In October 2007, the PUCT affirmed the ALJ’s proposal for decision.  TCC recognized revenues consistent with the final order which established a $20 million base rate increase, a $7 million decrease in depreciation rates, a $20 million increase in revenues related to the third quarterexpiration of 2007. Management is unable to predictTCC’s merger credits and a return on common equity of 9.96%.  TCC estimates the ultimate effectbase rate annual impact of this filing on future results of operations, cash flows and financial condition.final order will increase TCC’s pretax income by $47 million.

SWEPCo Fuel Reconciliation -– Texas

In June 2006, SWEPCo filed a fuel reconciliation proceeding with the PUCT for its Texas retail operations.operations for the three-year reconciliation period ended December 31, 2005.  SWEPCo sought, in the proceedings, to include under-recoveries related to the reconciliation period of $50 million.  In January 2007, intervenors filed testimony recommending that SWEPCo’s reconcilable fuel costs be reduced.  The PUCT staff and intervenor recommendationsdisallowances ranged from a $10 million to $28 million.  In June 2007, an ALJ issued a proposal for decision recommending a $17 million reduction.disallowance.  Results of operations for the second quarter of 2007 were adversely affected by $25 million to reflect the ALJ’s decision that apply to the reconciliation period and subsequent periods through 2007.  In FebruaryAugust 2007, the PUCT staffissued a final order affirming the ALJ report.  In September 2007, SWEPCo filed testimony recommendinga motion for rehearing.  In October 2007, the PUCT granted SWEPCo’s motion for rehearing.  The PUCT reversed its prior determination that SWEPCo’s reconcilableSO2 allowance gains should be credited through the fuel costsclause.  However, the PUCT ruled SWEPCo was obligated to credit the fuel clause with gains from sales of emissions allowances through June 30, 2006.  This change affects allowances sold after June 2006 and its impact will be reducedconsidered in the fourth quarter of 2007.  In October 2007, the PUCT issued a revised order which should allow SWEPCo to reverse $7 million of its earlier provision in the fourth quarter of 2007.  SWEPCO is considering whether to challenge other parts of the order.

ERCOT Price-to-Beat (PTB) Fuel Factor Appeal

Several parties including the Office of Public Utility Counsel and the cities served by $10 million. SWEPCo does not agree withboth TCC and TNC appealed the intervenor’s or staff’s recommendationsPUCT’s December 2001 orders establishing initial PTB fuel factors for Mutual Energy CPL and filed rebuttal testimonyMutual Energy WTU (TCC’s and TNC’s respective former affiliated REPs).  In 2003, the District Court ruled the PUCT record lacked substantial evidence regarding the amount of unaccounted-for energy (UFE) included in February 2007. Hearings have been held and briefs have been filed. ResultsTNC’s PTB fuel factor.  The Court of operations could beAppeals upheld the District Court regarding the UFE issue.  AEP’s third quarter 2005 pretax earnings were adversely affected by $28$3 million plus carrying costs ifat an assumed 1% UFE factor to reflect the impact of the court’s decision.  The Supreme Court of Texas has remanded this issue to the PUCT.  If the PUCT adopts alla different UFE factor on remand, future results of the intervenoroperations and staff recommendations.cash flows would be adversely affected.  Management is unable to predict the outcome of this proceedingremand or its effectimpact on future results of operations and cash flows.

Stall Unit

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

Turk Plant

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

Virginia Rate Matters

Virginia Restructuring

In April 2004, Virginia enacted legislation that extendedamended the Virginia Electric Utility Restructuring Act extending the transition period to market rates for the generation and supply of electricity, restructuring, including the extension of capped rates, through December 31, 2010.  The legislation providesprovided APCo with specified cost recovery opportunities during the extended capped rate period, including two optional bundled general base rate changes and an opportunity for timely recovery, through a separate rate mechanism, of certain unrecovered incremental environmental and reliability costs incurred on and after July 1, 2004.  Under the amended restructuring law, APCo continues to have an active fuel clause recovery mechanism in Virginia and continues to practice deferred fuel accounting. Also, underhave the restructuring law, APCo defersopportunity to recover incremental environmental generation costs and incremental transmission and distribution reliability costs for future recovery, to the extent such costs are not being recovered when incurred, and amortizes a portion of such deferrals commensurate with recovery.E&R costs.

In April 2007, the Virginia legislature adopted a comprehensive law providing for the re-regulation of electric utilities’ generation/generation and supply rates.  TheThese amendments shorten the transition period by two years (from 2010 to 2008) after which rates for retail generation/generation and supply will return to a formcost-based regulation in lieu of cost-based regulation.market-based rates.  The legislation provides for, among other things, biennial rate reviews beginning in 2009,2009; rate adjustment clauses for the recovery of the costs of (a) transmission services and new transmission investment,investments, (b) Demand Side Management,demand side management, load management, and energy efficiency programs, (c) renewable energy programs, and (d) environmental retrofit and new generation investments,investments; significant return on equity enhancements for large investments in new generation and, subject to Virginia SCC approval, certain environmental retrofits, and a floor on the allowed return on equity based on the average earned return on equities’ of regional vertically integrated electric utilities.  Effective July 1, 2007, the amendments allow utilities to retain a minimum of 25% of the margins from off-system sales with the remaining margins from such sales credited against fuel factor expenses.expenses with a true-up to actual.  The legislation also allows APCo to continue to defer and recover incremental environmental and reliability costs incurred through December 31, 2008.  APCo expects thisThe new form of cost-based ratemakingre-regulation legislation should improve its annual returnresult in significant positive effects on APCo’s future earnings and cash flows from the mandated enhanced future returns on equity, the reduction of regulatory lag from the opportunities to adjust base rates on a biennial basis and cash flow from operations whenthe new ratemaking beginsopportunities to request timely recovery of certain new costs not included in 2009. However, withbase rates.

With the return of cost-based regulation,new re-regulation legislation, APCo’s generation business will again meetmet the criteria for application of regulatory accounting principles under SFAS 71.  Results of operationsThe extraordinary pretax reduction in APCo’s earnings and financial condition could be adversely affected when APCo is required to re-establish certain net regulatory liabilities applicable to its generation/supply business. The timing and earnings effectshareholder’s equity from such reapplication of SFAS 71 regulatory accounting of $118 million ($79 million, net of tax) was recorded in the second quarter of 2007.  This extraordinary net loss relates to the reestablishment of $139 million in net generation-related customer-provided removal costs as a regulatory liability, offset by the restoration of $21 million of deferred state income taxes as a regulatory asset.  In addition, APCo established a regulatory asset of $17 million for APCo’s Virginia generation/supply businessqualifying SFAS 158 pension costs of the generation operations that, for ratemaking purposes, are uncertain at this time.deferred for future recovery under the new re-regulation legislation.  AOCI and Deferred Income Taxes increased by $11 million and $6 million, respectively.

APCo Virginia Base Rate Case

In May 2006, APCo filed a request with the Virginia SCC seeking an increase in base rates of $225 million to recover increasing costs including the cost of its investment in environmental equipment and a return on equity of 11.5%.  In addition, APCo requested to move off-system sales margins, currently credited to customers through base rates, to theits active fuel factor where they can be trued-up to actual.clause.  APCo also proposed to share the off-system sales margins with customers with 40% going to reduce rates and 60% being retained by APCo.  This proposed off-system sales fuel rate credit, which iswas estimated to be $27 million, partially offsets the $225 million requested increase in base rates for a net increase in base rate revenues of $198 million.  The major components of the $225 million base rate request include $73 million for the impact of removing off-system sales margins from the rate year ending September 30, 2007, $60 million mainly due to projected net environmental plant additions through September 30, 2007 and $48 million for return on equity.

In May 2006, the Virginia SCC issued an order consistent with Virginia law, placing the net requested base rate increase of $198 million into effect on October 2, 2006, subject to refund. The $198 million base rate increase being collected, subject to refund, includes recovery of incremental environmental compliance and transmission and distribution system reliability (E&R) costs projected to be incurred during the rate year beginning October 2006. These incremental E&R costs can be deferred and recovered through the E&R surcharge mechanism if not recovered through this base rate request.

In October 2006,May 2007, the Virginia SCC staff filed its direct testimony recommendingissued a final order approving an overall annual base rate increase of $13$24 million witheffective as of October 2006 and approving a return on equity of 9.9% and no off-system sales margin sharing. Other intervenors have recommended base rate increases ranging from10.0%.  As a result of the final order, APCo’s second quarter pretax earnings decreased by approximately $3 million due to a decrease in revenues of $42 million net of a recorded provision for refund and related interest offset by (a) a $15 million net effect from the deferral of unrecovered incremental E&R costs incurred from October 1, 2006 through June 30, 2007 to $112 million.be collected in a future E&R filing, (b) a $9 million net deferral of ARO costs to be recovered over 10 years and (c) a $15 million retroactive decrease in depreciation expense.  As a result of the Virginia SCC decision to limit the recovery of incremental E&R costs through the new base rates, APCo filed rebuttal testimonywill continue to defer for future recovery unrecovered incremental E&R costs incurred through 2008 utilizing the E&R surcharge mechanism.  APCo completed the $127 million refund in November 2006. Hearings were held in December 2006.August 2007.

Virginia E&R Costs Recovery Filing

In MarchJuly 2007, APCo filed a request with the Virginia SCC seeking recovery over the twelve months beginning December 1, 2007 of approximately $60 million of unrecovered incremental E&R costs inclusive of carrying costs thereon incurred from October 1, 2005 through September 30, 2006.  In August 2007, the Hearing Examiner (HE)Virginia SCC issued a reportscheduling order to begin the proceeding before a hearing examiner on November 5, 2007.  In October 2007, the Virginia SCC staff and the Attorney General both filed testimony recommending a $76that APCo recover $49 million increase inof its $60 million of requested E&R costs.  The two differences between APCo’s base ratesrequest and $45 million creditthe Virginia SCC staff and the Attorney General’s recommendations relate to the fuel factorrecovery of carrying costs on the unrecovered incremental E&R costs and the appropriate return on equity rate.  APCo intends to file in 2008 for off-system sales margins.recovery of additional incurred incremental E&R costs recorded and deferred after September 30, 2006.
APCo is currently recovering $21 million of incurred E&R costs through the initial E&R surcharge that will expire on November 30, 2007.  Through September 30, 2007, APCo deferred $70 million in incremental E&R costs to be recovered in the current and future E&R filings.  APCo has not recognized $15 million of equity carrying charges, which are recognizable when collected.  The HE’s recommendations$70 million regulatory asset does not include carrying costs on the unrecovered incremental E&R costs and is based on a return on equity of 10.1%rate which would reduce APCo’s revenue requirement by approximately $23 million. The HE also recommended limiting forward looking ratemaking adjustments to June 30, 2006 as opposed to September 30, 2007, which would reduce APCo’s revenue requirement by approximately $72approximates the Virginia SCC staff and Attorney General’s recommendations.  As a result, if APCo is awarded only $49 million of which approximately $60 million relates to incrementalfor the E&R costs that can be deferredincurred for future recovery through the E&R surcharge mechanism. The HE further proposed to share the off-system sales margins using the twelve months ended JuneSeptember 30, 2006 as recommended by the Virginia SCC staff and the Attorney General, it will not have to reverse any of $101its regulatory asset deferrals.

Virginia Fuel Clause Filing

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 a sharing of the benefits of off-system sales between APCo and its customers.  This filing was made in compliance with 50% reducing base rates, 45% reducing fuel rates and 5% retained by APCo to determine the revenue requirement. APCo’s proposal did not reduce base rates forminimum 25% retention of off-system sales margins but reducedprovision of the new re-regulation legislation which is effective with the first fuel rates approximately $27 million forclause filing after July 1, 2007.  This sharing requirement in the new law also includes a true-up to actual off-system sales margins.  In addition, APCo expects a final orderrequested authorization to be issued during 2007.defer for future recovery the difference between off-system sales margins credited to customers at 100% of the ordered amount through the current base rate margin rider and 75% of actual off-system sales margins as provided in the new law from July 1, 2007 until the new fuel rate becomes effective.

APCo is providing forIn August 2007, the Virginia SCC issued a possible refundscheduling order that implemented APCo’s proposed termination of revenues collectedits base rate off-system sales margin rider on an interim basis, subject to refund, consistenton September 1, 2007.  The order also implemented APCo’s proposed new fuel factor on an interim basis, effective September 1, 2007, which includes a credit for the sharing of 75% of off-system sales margins with customers in compliance with the HE recommendations. Management is unable to predictnew law.  In October 2007, APCo, the ultimate effectVirginia SCC staff and certain intervenors filed memorandums addressing legal issues identified by the Virginia SCC regarding the appropriateness of this filing on futurethe timing of the implementation of the new expanded fuel factor and off-system sales margins sharing with customers.  Hearings are scheduled for November 2007.  In October 2007, the Virginia SCC staff submitted testimony stating off-system sales margin sharing for July and August 2007 should be denied.  In addition, the Virginia SCC staff asserted that no language exists in the statute requiring implementation of off-system sales margin sharing any earlier than 2011.  Future results of operations and cash flows could be adversely affected if the Virginia SCC delays the effective date of the new expanded fuel clause beyond APCo’s filed request.

West Virginia IGCC Plant

In July 2007, APCo filed a request with the Virginia SCC to recover, over the twelve months beginning January 1, 2009, a return on projected construction work in progress including development, design and financial condition.planning costs from July 1, 2007 through December 31, 2009 estimated to be $45 million associated with the proposed 629 MW IGCC plant to be constructed in West Virginia for an estimated cost of $2.2 billion.  APCo is requesting authorization to defer a return on actual pre-construction costs incurred beginning July 1, 2007 until such costs are recovered, starting January 1, 2009 in accordance with the new re-regulation legislation.  The new re-regulation legislation provides for full recovery of all costs plus return on equity incentives for such new capacity once the plant is placed in service.  See “West Virginia IGCC Plant” section within West Virginia Rate Matters.

West Virginia Rate Matters

APCo and WPCo ENECExpanded Net Energy Cost (ENEC) Filing

In April 2007, the WVPSC issued an order establishing an investigation and hearing ofconcerning APCo’s and WPCo’s 2007 Expanded Net Energy Cost (ENEC)ENEC compliance filing.  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 and other energy/transmission items.   In the March 2007 ENEC joint filing, APCo and WPCo filed for an increase of approximately $101 million including a $72 million increase in ENEC and a $29 million increase in construction cost surcharges to become effective July 1, 2007.  A hearing onIn June 2007, the compliance filingWVPSC issued an order approving, without modification, a joint stipulation and agreement for settlement reached among the parties.  The settlement agreement provided for an increase in annual non-base revenues of approximately $86 million effective July 1, 2007.  This annual revenue increase primarily includes $55 million of ENEC and $29 million of construction cost surcharges.  The ENEC portion of the increase is scheduled for May 2007.subject to a true-up, which should avoid an earnings affect from an under-recovery of ENEC costs if they exceed the $55 million.

APCoWest Virginia IGCC Plant

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, WV.

In JanuaryJune 2007, at APCo’s request,APCo filed testimony with the WVPSC issuedsupporting the requests for a CCN and for pre-approval of a surcharge rate mechanism to provide for the timely recovery of both 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.  If APCo receives all necessary approvals, the plant could be completed as early as mid-2012 and currently is expected to cost an order delayingestimated $2.2 billion.  In July 2007, the Commission’sWVPSC staff and intervenors filed to delay the procedural schedule by 90 days.  APCo supported the changes to the procedural schedule.  The statutory decision deadline for issuing an order onwas revised to March 2008.  In July 2007, the certificate to December 2007.WVPSC approved the revised procedural schedule.  Through March 31,September 30, 2007, APCo deferred pre-construction IGCC costs totaling $10$11 million.  If the plant is not built and these costs are not recoverable, future results of operations and cash flows would be adversely affected.

Indiana Rate Matters

I&MIndiana Depreciation Study Filing

In February 2007, I&M filed a request with the IURC for approval of revised book depreciation rates effective January 1, 2007.  The filing included a settlement agreement entered into with the Indiana Office of the Utility Consumer Counsel (OUCC) that would provide direct benefits to I&M's customers if new lower book depreciation rates arewere approved by the IURC.  The direct benefits would include a $5 million credit to fuel costs and an approximate $8 million smart metering pilot program.  In addition, if the agreement iswere to be approved, I&M would initiate a general rate proceeding on or before July 1, 2007 and initiate two studies, one to investigate a general smart metering program and the other to study the market viability of demand side management programs.  Based on the depreciation study included in the filing, I&M recommended and parties to the settlement agreed to a decrease in pretax annual depreciation expense on an Indiana jurisdictional basis of approximately $69 million reflecting an NRC-approved 20-year extension of the Cook Plant licenses for Units 1 and 2 and an extension of the service life of the Tanners Creek coal-fired generating units.  This petition was not a request for a change in customers’ electric service rates.  As proposed,In June 2007, the IURC approved the settlement agreement, but modified the effective date of the new book depreciation reductionrates to the date I&M filed a general rate petition.  On June 19, 2007, I&M and the OUCC notified the IURC that the parties would accept the modification to the settlement agreement.  Therefore, I&M filed its rate petition and reduced its book depreciation rates as agreed upon in the settlement agreement.

The settlement agreement modification reduced book depreciation rates, which will result in an increase of $37 million in pretax earnings but would not impact cash flows untilfor the period June 19, 2007 to December 31, 2007.  The $37 million increase is partially offset by a $5 million regulatory liability, recorded in June 2007, to provide for the agreed-upon fuel credit.  I&M’s approved book depreciation rates are revised.subject to further review in the general rate case.  Management expects new base rates will become effective in early 2009.

Indiana Rate Filing

In June 2007, I&M filed a rate notification petition with the IURC regarding its intent to file for a base rate increase with a proposed test year ended September 30, 2007.  The IURC heldpetition indicated, among other things, the filing would include a public hearing in April 2007. I&M requested expeditious review and approval of its filing, but management cannot predict the outcomerequest to implement rate tracker mechanisms for certain variable components of the request orcost of service including PJM RTO costs, reliability enhancement costs, demand side management/energy efficiency program costs, off-system sales margins, and net environmental compliance costs.  This filing will also reflect the timingrevenue requirement reduction associated with an annual reduction in book depreciation expense. In August 2007, the IURC approved the September 30, 2007 test year and the inclusion of the above trackers in the rate filing with a rate case to be filed no later than January 31, 2008.  Management expects to file the case in early 2008 with a decision expected in early 2009.

Indiana Rate Cap

Effective July 1, 2007, I&M’s rate cap ended for both base and fuel rates in Indiana.  As a result, I&M’s fuel factor in Indiana increased with the July 2007 billing month to recover the projected cost of fuel.  I&M will resume deferring through revenues any approved depreciation reduction. If approved as filed,under/over-recovered fuel costs for future recovery/refund.  Under the capped rates, I&M was unable to recover $44 million of fuel costs since 2004 of which $7 million adversely impacted 2007 pretax earnings would increasethrough June 30, 2007.  Future results of operations should no longer be adversely impacted by $64fuel costs.

Michigan Rate Matters

Michigan Depreciation Study Filing
In December 2006, I&M filed a depreciation study in Michigan seeking to reduce its book depreciation rates.  In September 2007, the Michigan Public Service Commission (MPSC) approved a settlement agreement authorizing I&M to implement new book depreciation rates.  Based on the depreciation study included in the settlement, I&M  agreed to decrease pretax annual depreciation expense, on a Michigan jurisdictional basis, by approximately $10 million.  This settlement reflects an NRC-approved 20-year extension of the Cook Plant licenses for Units 1 and 2 and an extension of the service life of the Tanners Creek coal-fired generating units.  This petition was not a request for a change in retail customers’ electric service rates.  In addition and as a result of the new MPSC-approved rates, I&M will decrease pretax annual depreciation expense, on a FERC jurisdictional basis, by approximately $11 million which will reduce wholesale rates for customers representing half the load beginning in 2007.November 2007 and reduce wholesale rates for the remaining customers in June 2008.

Kentucky Rate Matters

KPCo Environmental Surcharge Filing

In July 2006, KPCo filed for approval of an amended environmental compliance plan and revised tariff to implement an adjusted environmental surcharge.  KPCo estimates the amended environmental compliance plan and revised tariff would increase revenues over 2006 levels by approximately $2 million in 2007 and $6 million in 2008 for a total of $8 million of additional revenue at current cost projections.  In January 2007, the KPSC issued an order approving KPCo’s proposed plan and surcharge.  Future recovery is based upon actual environmental costs and is subject to periodic review and approval of those actual costs by the KPSC.

In November 2006, the Kentucky Attorney General (AG) and the Kentucky Industrial Utility Consumers (KIUC) filed an appeal with the Kentucky Court of Appeals of the Franklin Circuit Court’s 2006 order upholding the KPSC’s 2005 Environmental Surcharge order.order specifically as it relates to the recovery of affiliated AEP Power Pool costs.  In itsKPCo’s order, the KPSC approved KPCo’s recovery of its environmental costs at its Big Sandy Plant and its share of environmental costs incurred as a result of the AEP Power Pool capacity settlement.  The KPSC has allowed KPCo to recover these FERC-approved allocated AEP Power Pool costs, via the environmental surcharge, since the KPSC’s first environmental surcharge order in 1997.  KPCo presently recovers $7 million a year in environmental surcharge revenues.

In March 2007, the KPSC issued an order, at the request of the Kentucky Attorney General, stating the environmental surcharge collections authorized in the January 2007 order that are associated with out-of-state generating facilities and paid through the AEP Power Pool should be collected over the six months beginning March 2007, subject to refund, pending the outcome of the courtCourt of appealsAppeals process.  At this time, management is unable to predict the outcome of this proceeding and its effect on KPCo’s current environmental surcharge revenues or on the January 2007 KPSC order increasing KPCo’s environmental rates.  If the appeal is successful, future results of operations and cash flows could be adversely affected.
Validity of Nonstatutory Surcharges

In August 2007, the Franklin 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 ruling results from the AG’s appeal of the KPSC’s approval of a natural gas distribution surcharge for replacement of gas mains.  The AG notified the KPSC that the Franklin County Circuit Court judge’s order in the Duke Energy case can be interpreted to include 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.  The KPSC and Duke Energy are appealing the Franklin County Circuit Court decision.

Although this order is not directly applicable to KPCo, it is possible that the AG or another intervenor could appeal an existing surcharge KPCo is collecting to the Franklin County Circuit Court.  KPCo’s fuel clause, annual Rockport Plant capacity surcharge, merger surcredit and credit system sales rider are not specifically authorized by statute. These surcharges are currently producing net annual revenues of approximately $10 million.  KPCo’s Environmental and demand side management surcharges are specifically authorized by statute.  The KPSC has asked interested parties to brief the issue in KPCo’s outstanding fuel cost proceeding.  The AG’s filed brief took the position that the KPCo fuel clause should be invalidated because the KPSC lacked the authority by statute to implement a fuel clause for KPCo without a full rate case review.  In August 2007, the KPSC issued an order stating despite the Franklin County Circuit Court decision, the KPSC has the authority to provide for surcharges and surcredits at least until a Court of Appeals ruling.  The appeals process could take up to two years to complete.  In August 2007, the AG agreed to stipulate to a stay order over the Franklin County Circuit Court’s decision pending the appeal decision.  KPCo’s exposure is indeterminable at this time.  If the appeal is unfavorable, future results of operations and cash flows could be adversely affected.

Oklahoma Rate Matters

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

In 2002, PSO under-recovered $44 million of purchased power costs through its fuel costsclause resulting from a reallocation among AEP West companies of purchased power costs for periods prior to January 1, 2002.  In July 2003, PSO proposed collection of those reallocated costs over eighteen months.  In August 2003, the OCC staff filed testimony recommending PSO recover $42 million of the reallocated purchased power costs over three years and PSO reduced its regulatory asset deferral by $2 million.  The OCC subsequently expanded the case to include a full prudence review of PSO’s 2001 fuel and purchased power practices. In January 2006, the OCC staff and intervenors issued supplemental testimony alleging that AEP deviated from the FERC-approved method of allocating off-system sales margins between AEP East companies and AEP West companies and among AEP West companies. The OCC staff proposed that the OCC offset the $42 million of under-recovered fuel with the proposed reallocation of off-system sales margins of $27 million to $37 million and with $9 million attributed to wholesale customers, which they claimed had not been refunded. In February 2006, the OCC staff filed a report concluding that the $9 million of reallocated purchased power costs assigned to wholesale customers had been refunded, thus removing that issue from its recommendation.

In 2004, an Oklahoma ALJ found that the OCC lacks authority to examine whether PSOAEP 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 August 2007, the OCC issued an order adopting the ALJ’s recommendation that the allocation of system sales/trading margins is a FERC jurisdictional issue.  The Oklahoma Industrial Energy Customers (OIEC) filed a motion asking the OCC to reconsider its order on the jurisdictional issue.  The OCC hasstayed its final order regarding the FERC jurisdictional issue. In October 2007, the OCC lifted its stay stating the OCC does not ruled on appeals by intervenors ofhave jurisdiction regarding the ALJ’s finding. The United States District Courtallocation methodology for the Western District of Texas issued orders in September 2005 regarding a TNC fuel proceeding and in August 2006 regarding a TCC fuel proceeding, preempting the PUCT from reallocating off-system sales margins between the AEP East companies and AEP West companies. The federal court agreed that the FERC has sole jurisdiction over that allocation. The PUCT appealed the ruling. The United States Court of Appeals for the Fifth Circuit, issued a decision in December 2006 regarding the TNC fuel proceeding that affirmed the United States District Court ruling.margins.

PSO does not agree with the intervenors’ and the OCC staff’s recommendations and proposals other than the staff’s original recommendation that PSO be allowed to recover the $42 million over three years and will defend its right to recover its under-recovered fuel balance. Management believes that if the position taken by the federal courts in the Texas proceeding is applied to PSO’s case, then the OCC should be preempted from disallowing fuel recoveries for alleged improper allocations of off-system sales margins between AEP East companies and AEP West companies. The OCCOIEC or another party could file a complaint at the FERC alleging the allocation of off-system sales margins to PSO is improper, which could result in an adverse effect on future results of operations and cash flows for AEP and the AEP East companies.  However, to date, there has been no claim asserted at the FERC that the AEP System deviated from the approvedFERC-approved allocation methodologies, but even if one were asserted, management believes that it would not prevail. its allocation of off-system sales margins under the FERC-approved SIA agreement was consistent with that agreement.  In October 2007, the OCC directed OCC Staff to file a complaint at FERC concerning this matter.

In June 2005, the OCC issued an order directing its staff to conduct a prudence review of PSO’s fuel and purchased power practices for the year 2003.  The OCC staff filed testimony finding no disallowances in the test year data.  The Attorney General of Oklahoma filed testimony stating that they could not determine if PSO’s gas procurement activities were prudent, but did not include a recommended disallowance.  However, an intervenor filed testimony in June 2006 proposing the disallowance of $22 million in fuel costs based on a historical review of potential hedging opportunities PSO failed to achieve that he alleges existed during the year.  A hearing was held inIn August 20062007, an ALJ issued a report recommending that PSO’s fuel procurement practices were prudent and management expectsno adjustments were warranted.  No parties appealed the recommendation.  In October 2007, the OCC issued a recommendation fromfinal order adopting the ALJ in 2007.ALJ’s report.

In February 2006, the OCC enacted a law was enactedrule, requiring the OCC to conduct prudence reviews on all generation and fuel procurement processes, practices and costs on either a two or three-year cycle depending on the number of customers served.  PSO is subject to the required biennialperiodic reviews.  In compliance with an OCC order, PSO is required to filefiled its testimony byin June 15, 2007. This proceeding will cover2007 covering the year 2005. The OCC Staff and intervenors filed testimony in September 2007.

In May 2007, PSO submitted a filing to the OCC to adjust its fuel/purchase power rates.  In the filing, PSO netted the $42 million of under-recovered pre-2002 reallocated purchased power costs against their $48 million over-recovered fuel balance as of April 30, 2007.  The $6 million net over-recovered fuel/purchased power cost deferral balance will be refunded over the twelve-month period beginning June 2007.  However, in August 2007, the OIEC filed a motion asking the OCC to order a refund of the $42 million pre-2002 reallocated purchased power costs netted against the current over-recovered fuel balance.  In October 2007, the OCC denied the OIEC’s request for refund of the $42 million of under-recovered pre-2002 reallocated purchased power costs.

Management cannot predict the outcome of the pending fuel and purchased power costs and prudence reviews, or planned future reviews, but believes that PSO’s fuel and purchased power procurement practices and costs are prudent and properly incurred. If the OCC disagrees and disallows fuel or purchased power costs including the unrecovered 2002 reallocation of such costs incurred by PSO, it would have an adverse effect on future results of operations and cash flows.

PSOOklahoma Rate Filing

In November 2006, PSO filed a request to increase base rates by $50 million for Oklahoma jurisdictional customers and set return on equity at 11.75% with a proposed effective date in the second quarter of 2007.  PSO sought a return on equity of 11.75%. PSO also proposed a formula rate plan that, if approved as filed, willwould permit PSO to defer any unrecovered costs as a result of a revenue deficiency that exceeds 50 basis points of the allowed return on equity for recovery within twelve months beginning six months after the test year.  The proposed formula rate plan would enable PSO to recover on a timely basis the cost of its new generation, transmission and distribution construction (including carrying costs during construction), provide the opportunity to achieve the approved return on equity and avoid recordingprevent the capitalization of a significant amount of AFUDC that would have been recorded during the construction time period.period and recovered in the future through depreciation expense.

In MarchThe ALJ issued a report in May 2007 the OCC staff and various intervenors filed testimony. The recommendations were base rate reductions that ranged from $18 million to $52 million. The recommended returnsrecommending a 10.5% return on equity ranged from 9.25% to 10.09%. These recommendations included reductions in depreciation expense of approximately $25 million, which has no earnings impact.but did not compute an overall revenue requirement.  The OCC staff filed testimony supportingALJ’s report did not recommend adopting a formula rate plan, generally similar tobut did recommend recovery through a rider of certain generation and transmission projects’ financing costs during construction.  However, the one proposed by PSO. In April 2007, PSO filed rebuttal testimony regarding various issues raised byreport also contained an alternative recommendation that the OCC Staffcould delay a decision on the rider and the intervenors. Astake up this issue in PSO’s application seeking regulatory approval of a result of rebuttal testimony,new coal-fueled generating unit.  PSO reduced its base rate request by $2 million. Hearings commenced on May 1,implemented interim rates, subject to refund, for residential customers beginning July 2007.

Management is unableIn October 2007, the OCC issued a final order providing for a $10 million annual increase in base rates with a return on equity of 10%.  The final order also provides for lower depreciation rates, which PSO estimates will decrease depreciation expense by approximately $10 million on an annual basis.  PSO estimates the annual impact of this final order will increase PSO’s pretax income by $20 million.  The final order also requires PSO to predictfile a plan with the outcome of these proceedings, however, ifOCC to promote energy efficiency and conservation programs within 60 days.  PSO implemented the approved rates are not increased in an amount sufficient to recover expected unavoidable cost increases future results of operations, cash flows and possibly financial condition could be adversely affected.October 2007.

PSO Lawton and Peaking Generation Settlement Agreement

OnIn November 26, 2003, pursuant to an application by Lawton Cogeneration, L.L.C. (Lawton) seeking approval of a Power Supply Agreement (the Agreement) with PSO and associated avoided cost payments, the OCC issued an order approving the Agreement and setting the avoided costs.

In December 2003, PSO filed an appeal of the OCC’s order with the Oklahoma Supreme Court (the Court).  In the appeal, PSO maintained that the OCC exceeded its authority under state and federal laws to require PSO to enter into the Agreement.  The Court issued a decision onin June 21, 2005, affirming portions of the OCC’s order and remanding certain provisions.  The Court affirmed the OCC’s finding that Lawton established a legally enforceablelegally-enforceable obligation and ruled that it was within the OCC’s discretion to award a 20-year contract and to base the capacity payment on a peaking unit.  The Court directed the OCC to revisit its determination of PSO’s avoided energy cost. Hearings were held on the remanded issues in April and May 2006.

In April 2007, all parties in the case filed a settlement agreement with the OCC resolving all issues. The OCC approved the settlement agreement in April 2007.  The OCC staff, the Attorney General, the Oklahoma Industrial Energy Consumers and Lawton Cogeneration, L.L.C. supported this settlement agreement.  The settlement agreement provides for a purchase fee of $35 million to be paid by PSO to Lawton and for Lawton to provide, at PSO’s direction, all rights to the Lawton Cogeneration Facility forincluding permits, options and engineering studies.  PSO will recordpaid the $35 million purchase fee in June 2007 and recorded the purchase fee as a regulatory asset and will recover it through a rider over a three-year period with a carrying charge of 8.25% beginning in September 2007.  In addition, PSO will recover through a rider, subject to a $135 million cost cap, all of the traditional costs associated with plant in service of its new peaking units to be located at the Southwestern Station and Riverside Station at the time these units are placed in service.service, currently expected to be 2008.  PSO expects these units will have a substantially lower plant-in-service cost than the proposed Lawton Cogeneration Facility.  PSO may request approval from the OCC for recovery of costs exceeding the cost cap if special circumstances occurredoccur necessitating a higher level of costs.  Such costs will continue to be recovered through the rider until cost recovery occurs through base rates or formula rates in a subsequent proceeding.  Under the settlement, PSO must file a rate case within eighteen months of the beginning of recovery through the rider unless the OCC approves a formula-based rate mechanism that provides for recovery of the peaking units. Once

Red Rock Generating Facility

In July 2006, PSO announced plans to enter into an agreement with Oklahoma Gas and Electric (OG&E) to build a 950 MW pulverized coal ultra-supercritical generating unit at the site of OG&E’s existing Sooner Plant near Red Rock, in north central Oklahoma.  PSO would own 50% of the new unit, OG&E would own approximately 42% and the Oklahoma Municipal Power Authority (OMPA) would own approximately 8%.  OG&E would manage construction of the plant.  OG&E and PSO requested pre-approval to construct the Red Rock Generating Facility and implement a recovery rider.  In March 2007, the OCC consolidated PSO’s pre-approval application with OG&E’s request.  The Red Rock Generating Facility was estimated to cost $1.8 billion and was expected to be in service in 2012.  The OCC staff and the ALJ recommended the OCC approve PSO’s and OG&E’s filing.  As of September 2007, PSO incurred approximately $20 million of pre-construction costs and contract cancellation fees.

In October 2007, the OCC issued a final order approving PSO’s need for 450 MWs of additional capacity by the year 2012, but denied PSO’s and OG&E’s application for construction pre-approval stating PSO and OG&E failed to fully study other alternatives.  Since PSO and OG&E could not obtain pre-approval to build the Red Rock Generating Facility, PSO and OG&E cancelled the third party construction contract and their joint venture development contract.  Management believes the pre-construction costs capitalized, including any cancellation fees, were prudently incurred, as evidenced by the OCC staff and the ALJ’s recommendations that the OCC approve PSO’s filing, and established a regulatory asset for future recovery.  Management believes such pre-construction costs are probable of recovery and intends to seek full recovery of such costs in the near future.  If recovery is denied, future results of operations and cash flows would be adversely affected.  As a result of the OCC’s decision, PSO will consider various alternative options to meet its capacity needs in the future.

2007 Oklahoma Ice Storm

In October 2007, PSO filed with the OCC requesting recovery of $13 million of operation and maintenance expenses related to service restoration effort after a January 2007 ice storm.  PSO proposed to establish a regulatory asset of $13 million and to amortize this asset coincident with the gains from the sale of SO2 allowances made during 2007 and thereafter until such gains provide for the new peaking units begins in mid-2008, PSO expects annual revenues of an estimated $36 million related to costfull recovery of the peaking units and the purchase fee. This settlement agreement was supported byregulatory asset.  If the OCC Staff,adopts the Attorney General, the Oklahoma Industrial Energy ConsumersPSO proposal, it would have a favorable impact on future results of operations and Lawton Cogeneration, L.L.C.cash flows.

Louisiana Rate Matters

SWEPCo Louisiana Compliance Filing

In October 2002, SWEPCo filed with the LPSC detailed financial information typically utilized in a revenue requirement filing, including a jurisdictional cost of service.service, with the LPSC.  This filing was required by the LPSC as a result of its order approving the merger between AEP and CSW.  Due to multiple delays, in April 2006, the LPSC and SWEPCo agreed to update the financial information based on a 2005 test year.  SWEPCo filed updated financial review schedules in May 2006 showing a return on equity of 9.44% compared to the previously authorizedpreviously-authorized return on equity of 11.1%.

In July 2006, the LPSC staff’s consultants filed direct testimony recommending a base rate reduction in the range of $12 million to $20 million for SWEPCo’s Louisiana jurisdictionjurisdictional customers, based on a proposed 10% return on equity.  The recommended reduction range iswas subject to SWEPCo validating certain ongoing operations and maintenance expense levels.  SWEPCo filed rebuttal testimony in October 2006 strongly refuting the consultants’ recommendations.  In December 2006, the LPSC staff’s consultants filed reply testimony asserting that SWEPCo’s Louisiana base rates are excessive by $17 million which includes a proposed return on equity of 9.8%.  SWEPCo filed rebuttal testimony in January 2007.  A decision is not expected until mid or late 2007.Constructive settlement negotiations are making meaningful progress.  At this time, management is unable to predict the outcome of this proceeding.  If a rate reduction is ultimately ordered, it would adversely impactaffect future results of operations, cash flows and possibly financial condition.

Stall Unit

In May 2006, SWEPCo announced plans to build a new intermediate load 480 MW natural gas-fired combustion turbine combined cycle generating unit at its existing Arsenal Hill Plant location in Shreveport, Louisiana.  SWEPCo submitted the appropriate filings with the PUCT and the Arkansas Public Service Commission (APSC) during the third quarter of 2006 and the LPSC during the first quarter of 2007 to seek approvals to construct the unit.  The Stall Unit is estimated to cost $375 million, excluding AFUDC, and expected to be in service in mid-2010.  As of September 2007, SWEPCo incurred and capitalized approximately $15 million and has contractual commitments of an additional $17 million.  If the Stall Unit is not approved, cancellation fees may be required to terminate SWEPCo’s commitment.

In March 2007, the PUCT approved SWEPCo’s request.  In Louisiana, this request has been separated from the original request, which included the Turk Plant.  Neither the LPSC nor the APSC have set a procedural schedule for the project.  The project is contingent upon obtaining pre-approval from the APSC, the LPSC, the PUCT and the Louisiana Department of Environmental Quality.  If SWEPCo is not authorized to build the Stall Unit, SWEPCo would seek recovery of incurred costs including any cancellation fees.  If SWEPCo cannot recover incurred costs, including any cancellation fees, it could adversely affect future results of operations, cash flows and 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 a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas named Turk Plant.  SWEPCo submitted filings with the APSC in December 2006 and the PUCT and LPSC in February 2007 to seek approvals to proceed with the plant.  In September 2007, OMPA signed a joint ownership agreement and agreed to own approximately 7% of the Turk Plant.  SWEPCo continues discussions with Arkansas Electric Cooperative Corporation and North Texas Electric Cooperative to become potential partners in the Turk Plant.  SWEPCo anticipates owning approximately 73% of the Turk Plant and will operate the facility.  The Turk Plant is estimated to cost $1.3 billion in total with SWEPCo’s portion estimated to cost $950 million, excluding AFUDC.  If approved on a timely basis, the plant is expected to be in-service in mid-2011.  As of September 2007, SWEPCo incurred and capitalized approximately $206 million and has contractual commitments for an additional $875 million.  If the Turk Plant is not approved, cancellation fees may be required to terminate SWEPCo’s commitment.

In August 2007, hearings began before the APSC seeking pre-approval of the plant. The APSC staff recommended the application be approved and intervenors requested the motion be denied.  In October 2007, final briefs and closing arguments were completed by all parties during which the APSC staff and Attorney General supported the plant.  A decision by the APSC will occur within 60 days from October 22, 2007.  In September 2007, the PUCT staff recommended that SWEPCo’s application be denied suggesting the construction of the Turk Plant would adversely impact the development of competition in the SPP zone.  The PUCT hearings were held in October 2007.  The LPSC held hearings in September 2007 and during this proceeding, the LPSC staff expressed support for the project.   If SWEPCo is not authorized to build the Turk plant, SWEPCo would seek recovery of incurred costs including any cancellation fees.  If SWEPCo cannot recover incurred costs, including any cancellation fees, it could adversely affect future results of operations, cash flows and possibly financial condition.

Stall Unit

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

FERC Rate Matters

Transmission Rate Proceedings at the FERC

The FERC PJM Regional Transmission Rate Proceeding

At AEP’s urging, the FERC instituted an investigation of PJM’s zonal rate regime, indicating that the present rate regime may need to be replaced through establishment of regional rates that would compensate AEP and other transmission owners for the regional transmission facilities they provide to PJM, which provides service for the benefit of customers throughout PJM. In September 2005, AEP and a nonaffiliated utility (Allegheny Power or AP) jointly filed a regional transmission rate design proposal with the FERC. This filing proposes and supports a new PJM rate regime generally referred to as Highway/Byway.

Parties to the regional rate proceeding proposed the following rate regimes:

·AEP/AP proposed a Highway/Byway rate design in which:
·The cost of all transmission facilities in the PJM region operated at 345 kV or higher would be included in a “Highway” rate that all load serving entities (LSEs) would pay based on peak demand. The AEP/AP proposal would produce about $125 million in additional revenues per year for AEP from users in other zones of PJM.
·The cost of transmission facilities operating at lower voltages would be collected in the zones where those costs are presently charged under PJM’s existing rate design.
·Two other utilities, Baltimore Gas & Electric Company (BG&E) and Old Dominion Electric Cooperative (ODEC), proposed a Highway/Byway rate that includes transmission facilities above 200 kV, which would produce lower revenues for AEP than the AEP/AP proposal.
·In another competing Highway/Byway proposal, a group of LSEs proposed rates that would include existing 500 kV and higher voltage facilities and new facilities above 200 kV in the Highway rate, which would produce considerably lower revenues for AEP than the AEP/AP proposal.
·In January 2006, the FERC staff issued testimony and exhibits supporting a PJM-wide flat rate or “Postage Stamp” type of rate design that would include all transmission facilities, which would produce higher transmission revenues for AEP than the AEP/AP proposal.

All of these proposals were challenged by a majority of other transmission owners in the PJM region, who favor continuation of the existing PJM rate design which provides AEP with no compensation for through and out traffic on its east zone transmission system. Hearings were held in April 2006 and the ALJ issued an initial decision in July 2006. The ALJ found the existing PJM zonal rate design to be unjust and determined that it should be replaced. The ALJ found that the Highway/Byway rates proposed by AEP/AP and BG&E/ODEC and the Postage Stamp rate proposed by the FERC staff to be just and reasonable alternatives. The ALJ also found FERC staff’s proposed Postage Stamp rate to be just and reasonable and recommended that it be adopted. The ALJ also found that the effective date of the rate change should be April 1, 2006 to coincide with SECA rate elimination. Because the Postage Stamp rate was found to produce greater cost shifts than other proposals, the judge also recommended that the design be phased-in. Without a phase-in, the Postage Stamp method would produce more revenue for AEP than the AEP/AP proposal. The phase-in of Postage Stamp rates would delay the full impact of that result until about 2012.

AEP filed briefs noting exceptions to the initial decision and replies to the exceptions of other parties. AEP argued that a phase-in should not be required. Nevertheless, AEP argued that if the FERC adopts the Postage Stamp rate and a phase-in plan, the revenue collections curtailed by the phase-in should be deferred and paid later with interest.

During 2006, the AEP East companies sought to increase retail rates in most of their states to recover lost T&O and SECA revenues. The status of such state retail rate proceedings is as follows:

·In Kentucky, KPCo settled a rate case, which provided for the recovery of its share of the transmission revenue reduction in new rates effective March 30, 2006.
·In Ohio, CSPCo and OPCo recover their FERC-approved OATT that reflects their share of the full transmission revenue requirement retroactive to April 1, 2006 under a May 2006 PUCO order.
·In West Virginia, APCo settled a rate case, which provided for the recovery of its share of the T&O/SECA transmission revenue reduction beginning July 28, 2006.
·In Virginia, APCo filed a request for revised rates, which includes recovery of its share of the T&O/SECA transmission revenue reduction starting October 2, 2006, subject to refund.
·In Indiana, I&M is precluded by a rate cap from raising its rates until July 1, 2007.
·In Michigan, I&M has not filed to seek recovery of the lost transmission revenues.

In April 2007, the FERC issued an order reversing the ALJ decision. The FERC ruled that the current PJM rate design is just and reasonable. The FERC further ruled that the cost of new facilities of 500 kV and above would be shared among all PJM participants. As a result of this order, the AEP East companies retail customers will be asked to bear the full cost of the existing AEP east transmission zone facilities. However, the AEP East companies customers will also be charged a share of the cost of new 500 kV and higher voltage transmission facilities built in PJM, of which the vast majority for the foreseeable future will not be needed by their customers, but will bolster service and reduce costs in other zones of PJM. The AEP East companies will need to obtain regulatory approvals for recovery of any costs of new facilities that are assigned to them as a result of this order, if upheld. AEP will request rehearing of this order. Management cannot estimate at this time what effect, if any, this order will have on their future construction of new east transmission facilities, results of operations, cash flows and financial condition.

The AEP East companies presently recover from retail customers approximately 85% of the reduction in transmission revenues of $128 million a year. Future results of operations, cash flows and financial condition will continue to be adversely affected in Indiana and Michigan until these lost transmission revenues are recovered in retail rates.

SECA Revenue Subject to Refund

TheEffective December 1, 2004, AEP East companies ceased collectingand other transmission owners in the region covered by PJM and the Midwest ISO (MISO) eliminated transaction-based through-and-out transmission service (T&O) revenuescharges in accordance with FERC orders and collected load-based charges, referred to as RTO SECA, rates to mitigate the loss of T&O revenues from December 1, 2004on a temporary basis through March 31, 2006, when SECA rates expired.2006.  Intervenors objected to the 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 or surcharge.  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 as follows:

  
Gross SECA Revenues Recognized
 
  
(in millions)
 
Year Ended December 31, 2006 (a) $43 
Year Ended December 31, 2005  163 
Year Ended December 31, 2004  14 

(a)
Represents revenues through March 31, 2006, when SECA rates expired, and excludes all provisions for refund.

of $220 million. Approximately $19$10 million of these recorded SECA revenues billed by PJM were nevernot collected.  The AEP East companies filed a motion with the FERC to force payment of these uncollected SECA billings.

In August 2006, thea 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 was not 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.

Since the implementation of SECA rates in December 2004, the AEP East companies recorded approximately $220 million of gross SECA revenues, subject to refund. The AEP East companies reached settlements with certain customers related to approximately $70 million of such revenues. The unsettled gross SECA revenues total approximately $150 million. If the ALJ’s initial decision is upheld in its entirety, it would disallow $126 million of the AEP East companies’ unsettled gross SECA revenues. In the second half of 2006, the AEP East companies provided reserves of $37 million in net refunds.refunds for current and future SECA settlements with all of the AEP East companies’ SECA customers.  The AEP East companies reached settlements with certain SECA customers related to approximately $69 million of such revenues for a net refund of $3 million.  The AEP East companies are in the process of completing two settlements-in-principle on an additional $36 million of SECA revenues and expect to make net refunds of $4 million when those settlements are approved.  Thus, completed and in-process settlements cover $105 million of SECA revenues and will consume about $7 million of the reserves for refunds, leaving approximately $115 million of contested SECA revenues and $30 million of refund reserves.  If the ALJ’s initial decision were upheld in its entirety, it would disallow approximately $90 million of the AEP East companies’ remaining $115 million of unsettled gross SECA revenues.  Based on recent settlement experience and the expectation that most of the $115 million of unsettled SECA revenues will be settled, management believes that the remaining reserve of $30 million will be adequate to cover all remaining settlements.

In September 2006, AEP, together with Exelon Corporation and DP&L,The Dayton Power and Light Company, filed an extensive post-hearing brief and reply brief noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part.  Management believes that the FERC should reject the initial decision because it is contrary tocontradicts 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 directed by the FERC, management is working to settle the remaining $115 million of unsettled revenues within the remaining reserve balance.  Although management believes they haveit has meritorious arguments and can settle with the remaining customers within the amount provided, management cannot predict the ultimate outcome of ongoing settlement talks and, if necessary, any future FERC proceedings or court appeals.  If the FERC adopts the ALJ’s decision and/or AEP cannot settle a significant portion of the remaining unsettled claims within the amount provided, it will have an adverse effect on future results of operations, cash flows and financial condition.

The FERC PJM Regional Transmission Rate Proceeding

In January 2005, certain transmission owners in PJM proposed continuation of the zonal rate design in PJM after the June 2005 FERC deadline.  With the elimination of T&O rates and the expiration of SECA rates, zonal rates would provide the AEP System no revenue for use of its transmission facilities by other parties in PJM and the MISO.  AEP protested the zonal rate proposal and at AEP’s urging, the FERC instituted an investigation of PJM’s zonal rate regime indicating that the present rate regime may need to be replaced through establishment of regional rates that would compensate the AEP East companies and other transmission owners for the regional transmission facilities they provide to PJM, which provides service for the benefit of customers throughout PJM.  In September 2005, AEP and a nonaffiliated utility (Allegheny Power or AP) jointly filed a regional transmission rate design proposal with the FERC.  This filing proposed and supported a new PJM rate regime generally referred to as a Highway/Byway rate design.

Hearings were held in April 2006 and the ALJ issued an initial decision in July 2006.  The ALJ found the existing PJM zonal rate design to be unjust and determined that it should be replaced.  The ALJ found the Highway/Byway proposed rates to be just and reasonable alternatives.  The ALJ also found FERC staff’s proposed Postage Stamp rate to be just and reasonable and recommended that it be adopted.  The ALJ also found that the effective date of the rate change should be April 1, 2006 to coincide with SECA rate elimination.

In April 2007, the FERC issued an order reversing the ALJ’s decision.  The FERC ruled that the current PJM rate design is just and reasonable for existing transmission facilities.  However, the FERC ruled that the cost of new facilities of 500 kV and above would be shared among all PJM participants.  As a result of this order, the AEP East companies’ retail customers will bear the full cost of the existing AEP east transmission zone facilities.  Presently AEP is collecting the full cost of those facilities from its retail customers with the exception of Indiana and Michigan customers.  As a result of this order, the AEP East companies’ customers will also be charged a share of the cost of future new 500 kV and higher voltage transmission facilities built in PJM, most of which are expected to be upgrades of the facilities in other zones of PJM.  The AEP East companies will need to obtain regulatory approvals for recovery of any costs of new facilities that are assigned to them as a result of this order, if upheld.  AEP has requested rehearing of this order.  Management cannot estimate at this time what effect, if any, this order will have on the AEP East companies’ future construction of new east transmission facilities, results of operations, cash flows and financial condition.  In May 2007, the AEP East companies filed for rehearing related to this FERC decision.

Since the FERC’s decision in 2005 to cease through-and-out rates and replace them temporarily with SECA rates, which ceased on April 1, 2006, the AEP East companies increased their retail rates in all states except Indiana, Michigan and Tennessee to recover lost T&O and SECA revenues.  The AEP East companies presently recover from retail customers approximately 85% of the lost T&O/SECA transmission revenues of $128 million a year.  Future results of operations, cash flows and financial condition will continue to be adversely affected in Indiana, Michigan and Tennessee until these lost T&O/SECA 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 effective February 1, 2008.  All of the transmission owners in PJM and MISO, with the exception of AEP and one MISO transmission owner, voted to continue 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.  AEP argues 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 the provision and use of transmission service in the Super Region since it is not sufficiently uniform between transmission owners and users to justify zonal rates.  Management is unable to predict the outcome of this case.
SPP Transmission Formula Rate Filing

In June 2007, AEPSC filed revised tariff sheets on behalf of PSO and SWEPCo for the AEP pricing zone of the SPP OATT.  The revised tariff sheets seek to establish an up-to-date revenue requirement for SPP transmission services over the facilities owned by PSO and SWEPCo and implement a transmission cost of service formula rate.

PSO and SWEPCo requested an effective date of September 1, 2007 for the revised tariff.  The primary impact of the filed revised tariff will be an increase in network transmission service revenues from nonaffiliated municipal and rural cooperative utilities in the AEP pricing zone of SPP.  If the proposed formula rate and requested return on equity are approved, the 2008 network transmission service revenues from nonaffiliates will increase by approximately $10 million compared to the revenues that would result from the presently approved network transmission rate.  PSO and SWEPCo take service under the same rate, and will also incur the increased OATT charges resulting from the filing, but will receive corresponding revenue to offset the increase.  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 hearing and settlement judge proceedings. In October 2007, AEPSC submitted a compliance filing on behalf of PSO and SWEPCo.  Multiple intervenors have protested or requested re-hearing of the order.  Discovery and settlement discussions have begun.

PJM Marginal-Loss Pricing

On June 1, 2007, in response to a 2006 FERC order, PJM revised its methodology for considering transmission line losses in generation dispatch and the calculation of locational marginal prices.   Marginal-loss dispatch recognizes the varying delivery costs of transmitting electricity from individual generator locations to the places where customers consume the energy.  Prior to the implementation of marginal-loss dispatch, PJM used average losses in dispatch and in the calculation of locational marginal prices.  Locational marginal prices in PJM now include the real-time impact of transmission losses from individual sources to loads.  Due to the implementation of marginal-loss pricing, for the period June 1, 2007 through September 30, 2007, AEP experienced an increase in the cost of delivering energy from the generating plant locations to customer load zones partially offset by cost recoveries and increased off-system sales resulting in a net loss of approximately $25 million.  AEP has initiated discussions with PJM regarding the impact it is experiencing from the change in methodology and will pursue through the appropriate stakeholder processes a modification of such methodology.  Management believes these additional costs should be recoverable through retail and/or cost-based wholesale rates and is seeking recovery in current and future fuel or base rate filings as appropriate in each of its eastern zone states.  In the interim, these costs will have an adverse effect on future results of operations and cash flows.  Management is unable to predict whether full recovery will ultimately be approved.

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4.
COMMITMENTS, GUARANTEES AND CONTINGENCIES

We are subject to certain claims and legal actions arising in our ordinary course of business.  In addition, our business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation against us cannot be predicted.  For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on our financial statements.  The Commitments, Guarantees and Contingencies note within our 2006 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.”guarantees.  There is no collateral held in relation to any guarantees in excess of our ownership percentages.  In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letters Ofof 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, debt service reserves and credit enhancements for issued bonds.  As the parent company, we issued all of these LOCs in our ordinary course of business on behalf of our subsidiaries.  At March 31,September 30, 2007, the maximum future payments for all the LOCs arewere approximately $27$69 million with maturities ranging from JuneNovember 2007 to MarchOctober 2008.

Guarantees Ofof 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 $85$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 46.  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 March 31,September 30, 2007, SWEPCo has collected approximately $30$33 million through a rider for final mine closure costs, of which approximately $13$15 million is recorded in Deferred Credits and Other and approximately $17$18 million is recorded in Asset Retirement Obligations on our Condensed Consolidated Balance Sheets.

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

Indemnifications Andand 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 2006 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 $2.2$1.3 billion (approximately $1 billion relates to the BOABank of America (BOA) litigation, see “Enron Bankruptcy” section of this note).  There are no material liabilities recorded for any indemnifications.

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.  At March 31, 2007, the maximum potential loss for these lease agreements was approximately $56 million ($36 million, net of tax) assumingAssuming the fair market value of the equipment is zero at the end of the lease term.term, the maximum potential loss for these lease agreements was approximately $59 million ($39 million, net of tax) as of September 30, 2007.

Railcar Lease

In June 2003, we entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease has an initial term of five years.  At the end of each lease term, we may (a) renew for another five-year term, not to exceed a total of twenty years; (b) purchase the railcars for the purchase price amount specified in the lease, projected at the lease inception to be the then fair market value; or (c) return the railcars and arrange a third party sale (return-and-sale option).  The lease is accounted for as an operating lease.  We intend to renew the lease for the full twenty years.  This operating lease agreement allows us to avoid a large initial capital expenditure and to spread our railcar costs evenly over the expected twenty-year usage.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under the return-and-sale option discussed above will equal at least a lessee obligation amount specified in the lease, which declines over the current lease term from approximately 86% to 77% of the projected fair market value of the equipment.  At March 31, 2007, the maximum potential loss was approximately $31 million ($20 million, net of tax) assumingAssuming the fair market value of the equipment is zero at the end of the current lease term.term, the maximum potential loss was approximately $30 million ($20 million, net of tax) as of September 30, 2007.  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 allege that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities including the Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric Company, Ohio Edison Company, Southern Indiana Gas & Electric Company, Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company and Duke Energy, modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA.  The Federal EPA filed its complaints against our subsidiaries in U.S. District Court for the Southern District of Ohio.  The alleged modifications occurred at our generating units over a twenty-year20-year period.  A bench trial on the liability issues was held during July 2005. In June 2006, the judge stayed the liability decision pending the issuance of a decision byApril 2007, the U.S. Supreme Court inreversed the Fourth Circuit Court of Appeals’ decision that had supported the statutory construction argument of Duke Energy case.in its NSR proceeding.

On October 9, 2007, we announced that we had entered into a consent decree with the Federal EPA, the DOJ, the states and the special interest groups. Under the consent decree, we agreed to annual SO2 and NOx emission caps for sixteen coal-fired power plants located in Indiana, Kentucky, Ohio, Virginia and West Virginia. In addition to completing the installation of previously announced environmental retrofit projects at many of the plants, including the installation of flue gas desulfurization (FGD or scrubbers) equipment at Big Sandy and at Muskingum River plants by the end of 2015, we agreed to install selective catalytic reduction (SCR) and FGD emissions control equipment at Rockport Plant. Unit 1 at the Rockport Plant will be retrofit by the end of 2017, and Unit 2 will be retrofit by the end of 2019.  We also agreed to install selective non-catalytic reduction, a NOx-reduction technology, by the end of 2009 at Clinch River Plant.

Since 2004, we spent nearly $2.6 billion on installation of emissions control equipment on our coal-fueled plants in Kentucky, Ohio, Virginia and West Virginia as part of a larger plan to invest more than $5.1 billion by 2010 to reduce the emissions of our generating fleet.

We agreed to operate SCRs year round during 2008 at Mountaineer, Muskingum River and Amos plants, and agreed to plant-specific SO2 emission limits for Clinch River and Kammer plants.

Under the CAA, ifconsent decree, we will pay a plant undertakes$15 million civil penalty and provide $36 million for environmental mitigation projects coordinated with the federal government and $24 million to the states for environmental mitigation.  We expensed these amounts in the third quarter of 2007.

The consent decree will resolve all issues related to various parties’ claims against us in the two pending NSR cases. The consent decree has been filed with the U.S. District Court. The consent decree is subject to a major modification30-day public comment period and final approval by the Court.  A hearing on the motion to approve the consent decree is scheduled for December 10, 2007.
We believe we can recover any capital and operating costs of additional pollution control equipment that results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to routine maintenance, replacement of degraded equipment or failed component or other repairs needed for the reliable, safe and efficient operationas a result of the plant. The CAA authorizes civil penaltiesconsent decree through regulated rates or market prices of upelectricity.  If we are unable to $27,500 ($32,500 after March 15, 2004) per day per violation at each generating unit. In 2001, the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing daterecover such costs, it would adversely affect our future results of the complaints cannot be imposed. There is no time limit on claims for injunctive relief.operations, cash flows and possibly financial condition.

Cases are still pending that could affect CSPCo’s share of jointly-owned units at Beckjord, Zimmer, and Stuart Stations.stations.  No trial date has yet been established in the Stuart case, but the units, operated by Dayton Power and Light Company, are equipped with SCR controls and the installation of FGD controls will be completed in 2007.  The Beckjord and Zimmer case is scheduled for a liability trial in May 2008.  Zimmer is equipped with both FGD and SCR controls.  Beckjord and Zimmer are operated by Duke Energy Ohio, Inc.  Similar cases have been filed against other nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk.  Several of these cases were resolved through consent decrees.

Courts have reached different conclusions regarding whether the activities at issue in these cases are routine maintenance, repair or replacement, and therefore are excluded from NSR. Similarly, courts have reached different results regarding whether the activities at issue increased emissions from the power plants. Appeals on these and other issues were filed in certain appellate courts, including a petition to appeal to the U.S. Supreme Court that was granted in the Duke Energy case. The Federal EPA issued a final rule that would exclude activities similar to those challenged in these cases from NSR as “routine replacements.” In March 2006, the Court of Appeals for the District of Columbia Circuit issued a decision vacating the rule. The Court denied the Federal EPA’s request for rehearing, and the Federal EPA and other parties filed a petition for review by the U.S. Supreme Court. In April 2007, the Supreme Court denied the petition for review. The Federal EPA also proposed a rule that would define “emissions increases” in a way that most of the challenged activities would be excluded from NSR.

On April 2, 2007, the U.S. Supreme Court reversed the Fourth Circuit Court of Appeals’ decision that had supported the statutory construction argument of Duke Energy in its NSR proceeding. In a unanimous decision, the Court ruled that the Federal EPA was not obligated to define “major modification” in two different CAA provisions in the same way. The Court also found that the Fourth Circuit’s interpretation of “major modification” as applying only to projects that increased hourly emission rates amounted to an invalidation of the relevant Federal EPA regulations, which under the CAA can only be challenged in the Court of Appeals within 60 days of the Federal EPA rulemaking. The U.S. Supreme Court did acknowledge, however, that Duke Energy may argue on remand that the Federal EPA has been inconsistent in its interpretations of the CAA and the regulations and may not retroactively change 20 years of accepted practice.

In addition to providing guidance on certain of the merits of the NSR proceedings brought against APCo, CSPCo, I&M and OPCo in U.S. District Court for the Southern District of Ohio, the U.S. Supreme Court’s issuance of a ruling in the Duke Energy cases has an impact on the timing of our NSR proceedings. First, the court in the case for which a trial on liability issues has been conducted has indicated an intent to issue a decision on liability. Second, the bench trial on remedy issues, if necessary, is likely to be scheduled to begin in the third quarter of 2007.

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.proceedings for our jointly-owned plants.  We are also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court.  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 regulated rates and 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 Court for the Eastern District of Texas alleging violations of the CAA at SWEPCo’s Welsh Plant.  SWEPCo filed a response to the complaint in May 2005.  A trial in this matter is scheduled forto commence during the secondfirst quarter of 2007.2008.

In 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary of findings resulting from a compliance investigation at the plant.  In April 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of approximately $228 thousand against SWEPCo based on alleged violations of certain representations regarding heat input in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements.  SWEPCo responded to the preliminary report and petition in May 2005.  The enforcement order contains a recommendation limiting the heat input on each Welsh unit to the referenced heat input contained within the permit application within 10 days of the issuance of a final TCEQ order and until a permit amendment is issued.  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 removing the heat input references from the Welsh permit and clarifying the sulfur content of fuels burned at the plant is limited to 0.5% on an as-received basis.  The Sierra Club and Public Citizen filed a motion to overturn the permit alteration.  In June 2007, TCEQ denied that motion.

We are unable to predict the timing of any future action by TCEQ or the special interest groups or the effect of such actions on our results of operations, 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 defendants’ motion to dismiss the lawsuits was granted in September 2005.  The dismissal was appealed to the Second Circuit Court of Appeals.  Briefing and oral argument have concluded.  On April 2, 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 Supreme Court’s decision on this case.  We believe the actions are without merit and intend to defend against the claims.

TEM Litigation

OPCo 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 dated November 15, 2000 (PPA).  Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming.

In September 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 we 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 AEP’s breaches.  The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) provided a limited guaranty.

In August 2005, a federal judge ruled that TEM had breached the contract and awarded us damages of $123 million plus prejudgment interest.  Any eventual proceeds will be recorded as a gain when received.

In September 2005, TEM posted a $142 million letter of credit as security pending appeal of the judgment. Both parties filed Notices of Appeal withMay 2007, the United States Court of Appeals for the Second Circuit which heard oral argument onruled that the appealslower court was correct in December 2006.finding that TEM breached the PPA and we did not breach the PPA.  It also ruled that the lower court applied an incorrect standard in denying us any damages for TEM’s breach of the 20-year term of the PPA holding that we are entitled to the benefit of our bargain and that the trial court must determine our damages.  The Court of Appeals vacated approximately $117 million of our $123 million judgment for damages against TEM related to replacement products and remanded the issue for further proceedings to determine the correct amount of those damages.  One part of the judgment is final, that involves TEM’s liability for damages applicable to gas peaking and post-actual commercial operation date products.  We cannot predictexpect TEM to pay the ultimate outcomeamount of this proceeding.those damages, approximately $8 million, including interest, in the fourth quarter of 2007.

Enron Bankruptcy

In connection with the 2001 acquisition of HPL, we entered into an agreement with BAM Lease Company, which granted HPL the exclusive right to use approximately 65 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, Bank of America (BOA) and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of 65 BCF of 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.  In 2002, the BOA Syndicate filed a lawsuit against HPL in Texas state court seeking a declaratory judgment that the BOA Syndicate has a valid and enforceable security interest in gas purportedly in the Bammel storage facility.  In 2003, the Texas state court granted partial summary judgment in favor of the BOA Syndicate. HPL appealed this decision.  In August 2006, the Court of Appeals for the First District of Texas vacated the trial court’s judgment and dismissed the BOA Syndicate’s case.  The BOA Syndicate did not seek review of this decision.  In June 2004, BOA filed an amended petition in a separate lawsuit in Texas state court seeking to obtain possession of up to 55 BCF of storage gas in the Bammel storage facility or its fair value.  Following an adverse decision on its motion to obtain possession of this gas, BOA voluntarily dismissed this action.  In October 2004, BOA refiled this action.  HPL’s motion to have the case assigned to the judge who heard the case originally was granted.  HPL intends to defend against any renewed claims by BOA.

In 2003, AEP filed a lawsuit against BOA in the United States District Court for the Southern District of Texas.  BOA led a lending syndicate involving the 1997 gas monetization that Enron and its subsidiaries undertook and the leasing of the Bammel underground gas storage facility to HPL.  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 Bammel storage facility lease arrangement with Enron and 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 including that the 1997 gas monetization did not contravene or constitute a default of any federal, state, or local statute, rule, regulation, code or any law.  In February 2004, BOA filed a motion to dismiss this Texas federal lawsuit.  In September 2004, the Magistrate Judge issued a Recommended Decision and Order recommending that BOA’s Motion to Dismiss be denied, that the five counts in the lawsuit seeking declaratory judgments involving the Bammel facility and the right to use and cushion gas consent agreements be transferred to the Southern District of New York and that the four counts alleging breach of contract, fraud and negligent misrepresentation proceed in the Southern District of Texas.  BOA objected to the Magistrate Judge’s decision.  In April 2005, the Judge entered an order overruling BOA’s objections, denying BOA’s Motion to Dismiss and severing and transferring the declaratory judgment claims to the Southern District of New York.  HPL and BOA filed motions for summary judgment in the case pending in the Southern District of New York.  The case in federal court in Texas was set for trial beginning April 2007 but the Court continued the trial pending a decision on the motions for summary judgment in the New York case.

In FebruaryAugust 2007, the Judge in the New York action, afterissued a decision granting BOA summary judgment without awarding any damages and dismissing our claims.  The Judge held another hearing oral argumentin September 2007 and said that he plans a further hearing on the motions fordamages issue.  We asked the Judge to certify an appeal of the legal issues decided by his summary judgment made a series of oral “informal findings” and submitted a written memorandumrulings prior to the parties’ counsel. In the memorandum to counsel, the Judge stated that he was denying several of AEP’s motions for partial summary judgment and granting several of BOA motions for summary judgment. The substantive matters left open for further proceedings include the issue of the nature of the gas subject to BOA security interest and the value of that interest. The Judge stated that the memorandum to counsel is not an opinion or an order, and that no opinion or order will be issued until all motions pending before the Court have been decided. The Judge heard additional argumentsany ruling on the summary judgment motions in March 2007.damages.  At this time we are unable to predict how the Judge will rule on the pending motions due to the complexity of those issues and the parties’ disagreement over each issue.request.  If the Judge issues a judgment directing AEPus to pay an amount in excess of the gain on the sale of HPL, described below, and if AEP iswe are unsuccessful in having the judgment reversed or modified, the judgment could have a material adverse effect on the results of operations, cash flow,flows, and possibly financial condition.

In February 2004, in connection with BOA’s dispute, 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 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.  The determination and recognition of the gain on sale, estimated to be $380 million at March 31, 2007 and December 31, 2006, and the recognition of the gainsale are dependent on the ultimate resolution of the BOA dispute and the costs, if any, associated with the resolution of this matter.  The deferred gain, estimated to be $382 million and $380 million at September 30, 2007 and December 31, 2006, respectively, is included in Deferred Credits and Other on our Condensed Consolidated Balance Sheets.

Although management is unable to predict the outcome of the remaining lawsuits, it is possible that their resolution could have ana material adverse impact on our results of operations, cash flows and financial condition.

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.  In July 2006, the Court entered judgment denying plaintiff’s motion for class certification and dismissing all claims without prejudice.  In August 2006, the plaintiffs filed a notice of appeal to the United States Court of Appeals for the Sixth Circuit.  BriefingIn 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 this appeal was completed in December 2006 andwhether the parties awaitplaintiff is an adequate representative for the schedulingclass of oral argument.plan participants on whose behalf the litigation would be pursued. We intend to 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 forty energy companies, including AEP, and two publishing companies 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 filed in California.  In addition, a number of other cases were filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies.  In some of these cases, AEP (or a subsidiary) is among the companies named as defendants.  These cases are at various pre-trial stages.  Several of these cases were transferred to the United States District Court for the District of Nevada but subsequently were remanded to California state court.  In 2005 and subsequently, the judge in Nevada dismissed threea number of the remaining cases (AEP was a defendant in one of these cases), on the basis of the filed rate doctrine.  Plaintiffs in these cases appealed the decisions.  In July 2007, the judge in the California cases stayed those proceedings pending a decision by the Ninth Circuit in the federal cases.  In September 2007, the United States Court of Appeals for the Ninth Circuit reversed the dismissal of two of the cases and remanded those cases to the trial court.  However, the Ninth Circuit must rule on AEP’s claim that the plaintiffs failed to timely appeal the trial judge’s separate dismissal of AEP.  In the other case, AEP has pending before the trial court a separate motion to dismiss based on plaintiffs’ failure to state a claim against the AEP companies that was not addressed when the trial judge dismissed the case based on the filed rate doctrine.  We will continue to defend each case where an AEP company is a defendant.

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. In December 2002, a FERC ALJ ruled in our favor and dismissed the complaint filed by the Nevada utilities. In 2001, the Nevada utilities filed complaints asserting that the prices for power supplied under those contracts should be lowered asbecause the market for power was allegedly dysfunctional at the time such contracts were executed.  TheAn ALJ rejectedrecommended rejection of the complaint, heldholding that the markets for future delivery were not dysfunctional, and that the Nevada utilities failed to demonstrate that the public interest required that changes be made to the contracts.  In June 2003, the FERC issued an order affirming the ALJ’s decision.  In December 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.  On September 25, 2007, the U.S. Supreme Court decided to review the Ninth Circuit’s decision.  Management is unable to predict the outcome of these proceedings or their impact on future results of operations 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.
5.
ACQUISITIONS, DISPOSITIONS, DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

ACQUISITIONS

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 approximately $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 approximately $325 million and the assumption of liabilities of approximately $2$3 million.  AEGCo will completecompleted 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 contract.

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.  Management estimates that approximately $180 million in additional costs (excluding AFUDC) will be required to finish the construction of the plant.  The Dresden Plant is located near Dresden, Ohio and is a natural gas, combined cycle power plant.  When completed in 2009, the Dresden Plant will have a generating capacity of 580 MW.

2006

None

DISPOSITIONS

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 $42.8 million plus working capital adjustments.  The sale did not have an impact on our results of operations nor do we expect anythe remaining litigation to have a significant effect on our results of operations.

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

During March 2007, we sold 130,000 shares of ICE and recognized a $16 million pretax gain ($10 million, net of tax).  We recorded the gains in Interest and Investment Income on our 2007 Condensed Consolidated Statement of Income.  We recorded our remaining investment of approximately 138,000 shares in Other Temporary Cash Investments on our Condensed Consolidated Balance Sheets.

Texas REPs (Utility Operations Segment)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.  We received $20 million and $70 million payments in 2007 and 2006, respectively, for our share in earnings.  These payments are reflected in Gain/Loss on Disposition of Assets, Net on our Condensed Consolidated Statements of Income.  The payment we received in 2007 was the final payment under the earnings sharing agreement.

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 450 MW cogeneration plant located within ConocoPhillips’ Sweeny refinery complex southwest of Houston, Texas.  We are the managing partner of the plant, which is co-owned by General Electric Company.  As a result of the sale, we estimate that we will realize a $46 million pretax gain in the fourth quarter of 2007.

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 estimate that we will realize an $11 million pretax gain in the fourth quarter of 2007.  In the fourth quarter of 2007, we estimate that we will realize a total of $57 million in pretax gains related to the sales of our investments in the Sweeny Plant and the related purchase power contracts.

2006

Compresion Bajio S de R.L. de C.V. (All Other)

In January 2002, we acquired a 50% interest in Compresion Bajio S de R.L. de C.V. (Bajio), a 600 MW power plant in Mexico.  WeIn February 2006, we completed the sale of the 50% interest in February 2006Bajio for approximately $29 million with no effect on our 2006 results of operations.

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 2007 and 2006 related to discontinued operations:

U.K. 
Generation (a)
Nine Months Ended September 30,
(in millions)
2007 Revenue$-
2007 Pretax Income3
2007 Earnings, Net of Tax2
2006 Revenue$-
2006 Pretax Income9
2006 Earnings, Net of Tax6

(a)The 2007 amounts relate to tax adjustments from the sale.  Amounts in 2006 relate to a release of accrued liabilities for the settlement of the London office lease and tax adjustments related to the sale.

For the quarter ended September 30, 2007 and 2006, there was no income statement impact related to our discontinued operations.  There were no cash flows used for or chargesprovided by operating, investing or financing activities related to our discontinued operations during the first quarter of 2007. During the first quarter of 2006, we had discontinued operations from U.K. Generation related to a release of accrued liabilities for the London office leasenine months ended September 30, 2007 and tax adjustments from the sale. We recorded pretax income related to U.K. Generation of $5 million ($3 million, net of tax) during the first quarter of 2006.

ASSETS HELD FOR SALE

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.  The sale did not have a significant effect on our results of operations nor do we expect any remaining litigation to have a significant effect on our results of operations.

We classified TCC’s assets related to the Oklaunion Power Station in Assets Held for Sale on our Condensed Consolidated Balance Sheet at December 31, 2006.  The plant doesdid not meet the “component-of-an-entity” criteria because it doesthe plant did not have cash flows that can be clearly distinguished operationally.  The plant also doesdid not meet the “component-of-an-entity” criteria for financial reporting purposes because it doesthe plant did not operate individually, but rather as a part of the AEP System, which includes all of the generation facilities owned by our Registrant Subsidiaries except TNC.System.

Our Assets Held for Sale were as follows:

 
March 31,
 
December 31,
  
September 30,
  
December 31,
 
 
2007
 
2006
  
2007
  
2006
 
Texas Plants
 
(in millions)
  
(in millions)
 
Other Current Assets $- $1  $-  $1 
Property, Plant and Equipment, Net  -  43   -   43 
Total Assets Held for Sale
 $- $44  $-  $44 

6.BENEFIT PLANS

We adopted SFAS 158 as of December 31, 2006.  We recorded a SFAS 71 regulatory asset for qualifying SFAS 158 costs of our regulated operations that for ratemaking purposes will beare deferred for future recovery.

Components of Net Periodic Benefit Cost

The following table provides the components of our net periodic benefit cost for the plans for the three and nine months ended March 31,September 30, 2007 and 2006:
   
Other
     
Other
 
   
Postretirement
     
Postretirement
 
 
Pension Plans
 
Benefit Plans
  
Pension Plans
  
Benefit Plans
 
 
2007
 
2006
 
2007
 
2006
  
2007
  
2006
  
2007
  
2006
 
 
(in millions)
 
Three Months Ended September 30, 2007 and 2006
 
(in millions)
 
Service Cost $24 $24 $10 $10  $24  $23  $11  $10 
Interest Cost  59  57  26  25   59   57   26   26 
Expected Return on Plan Assets  (85) (83) (26) (23)  (85)  (82)  (26)  (24)
Amortization of Transition Obligation  -  -  7  7   -   -   6   7 
Amortization of Net Actuarial Loss  15  20  3  5   15   20   3   5 
Net Periodic Benefit Cost
 $13 $18 $20 $24  $13  $18  $20  $24 

         7.
     
Other
 
     
Postretirement
 
  
Pension Plans
  
Benefit Plans
 
  
2007
  
2006
  
2007
  
2006
 
Nine Months Ended September 30, 2007 and 2006
 
(in millions)
 
Service Cost $72  $71  $32  $30 
Interest Cost  176   171   78   76 
Expected Return on Plan Assets  (254)  (248)  (78)  (70)
Amortization of Transition Obligation  -   -   20   21 
Amortization of Net Actuarial Loss  44   59   9   15 
Net Periodic Benefit Cost
 $38  $53  $61  $72 
7.
BUSINESS SEGMENTS

As outlined in our 2006 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 all 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 and Virginia continuecontinues to have commission-determined transition rates. In April 2007, the Virginia legislature approved amendments recommended by the Governor providing for the re-regulation of electric utility generation/supply rates. See “Virginia Restructuring” section of Note 3.

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.

MEMCO Operations
·
Barging operations that annually transport approximately 34 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and Lowerlower Mississippi rivers.  Approximately 35% of the barging operations relates to the transportation of coal, 28%30% relates to agricultural products, 21%18% relates to steel and 16%17% relates to other commodities.

Generation and Marketing
·IPPs, wind farms and marketing and risk management activities primarily in ERCOT.  Our 50% interest in the Sweeny Cogeneration Plant was sold in October 2007.  See “Sweeny Cogeneration Plant” section of Note 5.

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

·Parent company’sParent’s guarantee revenue received from affiliates, interest income and interest expense and other nonallocated costs.
·Other energy supply related businesses, including the Plaquemine Cogeneration Facility, which was sold in the fourth quarter of 2006.

The tables below present our reportable segment information for the three and nine months ended March 31,September 30, 2007 and 2006 and balance sheet information as of March 31,September 30, 2007 and December 31, 2006.  These amounts include certain estimates and allocations where necessary. We reclassified prior year amounts to conform to the current year’s segment presentation.

   
Nonutility Operations
           
Nonutility Operations
          
 
Utility Operations
 
MEMCO
Operations
 
Generation
and
Marketing
 
All Other (a)
 
Reconciling Adjustments
 
Consolidated
  
Utility Operations
  
MEMCO
Operations
  
Generation
and
Marketing
  
All Other (a)
  
Reconciling Adjustments
  
Consolidated
 
 
(in millions)
 
(in millions)
 
Three Months Ended March 31, 2007
             
Three Months Ended September 30, 2007
                  
Revenues from:Revenues from:                               
External Customers $2,886 $117 $115 $51 $- $3,169 
Other Operating Segments  147  3  (73) (45) (32) - 
External Customers $3,423  $134  $241  $(9) $-  $3,789 
Other Operating Segments  177   4   (161)  19   (39)  - 
Total Revenues
Total Revenues
 $3,033 $120 $42 $6 $(32)$3,169  $3,600  $138  $80  $10  $(39) $3,789 
                                     
Net Income (Loss)Net Income (Loss) $253 $15 $(1)$4 $- $271  $388  $18  $3  $(2) $-  $407 

   
Nonutility Operations
           
Nonutility Operations
          
 
Utility Operations
 
MEMCO
Operations
 
Generation
and
Marketing
 
All Other (a)
 
Reconciling Adjustments
 
Consolidated
  
Utility Operations
  
MEMCO
Operations
  
Generation
and
Marketing
  
All Other (a)
  
Reconciling Adjustments
  
Consolidated
 
 
(in millions)
  
(in millions)
 
Three Months Ended March 31, 2006
                   
Three Months Ended September 30, 2006
                  
Revenues from:                                     
External Customers $2,982 $116 $13 $(3)$- $3,108  $3,478  $135  $14  $(33) $-  $3,594 
Other Operating Segments  (16) 3  -  22  (9) -   (41)  4   -   52   (15)  - 
Total Revenues
 $2,966 $119 $13 $19 $(9)$3,108  $3,437  $139  $14  $19  $(15) $3,594 
                                      
Income (Loss) Before Discontinued
Operations
 $365 $21 $4 $(12)$- $378 
Discontinued Operations, Net of Tax  
-
  -  -  3  -  3 
Net Income (Loss)
 $365 $21 $4 $(9)$- $381  $378  $19  $4  $(136) $-  $265 

    
Nonutility Operations
       
  
Utility Operations
 
MEMCO
Operations
 
Generation
and
Marketing
 
All Other (a)
 
Reconciling Adjustments
 
Consolidated
 
March 31, 2007
 
(in millions)
 
Total Property, Plant and Equipment $42,092 $239 $565 $35 $(237)(c)$42,694 
Accumulated Depreciation and Amortization  15,244  53  90  7  (3)(c) 15,391 
Total Property, Plant and Equipment - Net
 $26,848 $186 $475 $28 $(234)(c)$27,303 
                    
Total Assets $36,789 $305 $705 $11,732 $(11,595)(b)$37,936 
     
Nonutility Operations
          
  
Utility Operations
  
MEMCO
Operations
  
Generation
and
Marketing
  
All Other (a)
  
Reconciling Adjustments
  
Consolidated
 
  
(in millions)
 
Nine Months Ended September 30, 2007
                  
Revenues from:                   
External Customers $9,127  $367  $574  $36  $-  $10,104 
Other Operating Segments  460   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
          
  
Utility Operations
  
MEMCO
Operations
  
Generation
and
Marketing
  
All Other (a)
  
Reconciling Adjustments
  
Consolidated
 
  
(in millions)
 
Nine Months Ended September 30, 2006
                  
Revenues from:                  
External Customers $9,259  $368  $47  $(36) $-  $9,638 
Other Operating Segments  (60)  9   -   89   (38)  - 
Total Revenues
 $9,199  $377  $47  $53  $(38) $9,638 
                         
Income (Loss) Before Discontinued
  Operations
 $902  $54  $10  $(151) $-  $815 
Discontinued Operations, Net of Tax  
-
   -   -   6   -   6 
Net Income (Loss)
 $902  $54  $10  $(145) $-  $821 

     
Nonutility Operations
          
  
Utility Operations
 
MEMCO
Operations
 
Generation
and
Marketing
 
All Other (a)
 
Reconciling Adjustments
 
Consolidated
 
December 31, 2006
 
(in millions)
 
Total Property, Plant and Equipment $41,420 $239 $327 $35 $- $42,021 
Accumulated Depreciation and Amortization  15,101  51  83  5  -  15,240 
Total Property, Plant and Equipment - Net
 $26,319 $188 $244 $30 $- $26,781 
                    
Total Assets $36,632 $315 $342 $11,460 $(10,762)(b)$37,987 
Assets Held for Sale  44  -  -  -  -  44 
    
Nonutility Operations
       
  
Utility Operations
 
MEMCO
Operations
 
Generation
and
Marketing
 
All Other (a)
 
Reconciling Adjustments
 
Consolidated
 
September 30, 2007
 
(in millions)
 
Total Property, Plant and Equipment $44,547 $255 $566 $38 $(237) (b)$45,169 
Accumulated Depreciation and
  Amortization
  15,978  58  105  7  (9) (b) 16,139 
Total Property, Plant and Equipment –
  Net
 $28,569 $197 $461 $31 $(228) (b)$29,030 
                    
Total Assets $38,423 $326 $746 $11,948 $(11,987) (c)$39,456 

     
Nonutility Operations
          
  
Utility Operations
 
MEMCO
Operations
 
Generation
and
Marketing
 
All Other (a)
 
Reconciling Adjustments
 
Consolidated
 
December 31, 2006
 
(in millions)
 
Total Property, Plant and Equipment $41,420 $239 $327 $35 $- $42,021 
Accumulated Depreciation and
  Amortization
  15,101  51  83  5  -  15,240 
Total Property, Plant and Equipment –   Net
 $26,319 $188 $244 $30 $- $26,781 
                    
Total Assets $36,632 $315 $342 $11,460 $(10,762)(c)$37,987 
Assets Held for Sale  44  -  -  -  -  44 

(a)All Other includes:
 ·Parent company’sParent’s guarantee revenue received from affiliates, interest income and interest expense and other nonallocated costs.
 ·Other energy supply related businesses, including the Plaquemine Cogeneration Facility, which was sold in the fourth quarter of 2006.
(b)Reconciling Adjustments for Total Property, Plant and Equipment and Accumulated Depreciation and Amortization as of September 30, 2007 represent the elimination of an intercompany capital lease that began during the first quarter of 2007.
(c)Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies.
(c)Reconciling Adjustments for Total Property, Plant and Equipment and Accumulated Depreciation and Amortization as of March 31, 2007 represent the elimination of an intercompany capital lease that began during the first quarter of 2007.
8.     INCOME TAXES

          8.   INCOME TAXES

We, join in the filing ofalong with our subsidiaries, file a consolidated federal income tax return with our subsidiaries in the American Electric Power (AEP) System.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 company, the method of allocation approximates a separate return result for each company in the consolidated group.

Audit Status

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

We have settled with the IRS on all issues from the audits of our consolidated federal income tax returns for years prior to 1997.  We have effectively settled all outstanding proposed IRS adjustments for years 1997 through 1999 and through June 2000 for the CSW pre-merger tax period and anticipate payment for the agreed adjustments to occur during 2007.  Returns for the years 2000 through 20032005 are presently being audited by the IRS and we anticipate that the audit of the 2000 through 2003 years will be completed by the end of 2007.

The IRS has proposed certain significant adjustments to AEP’sour foreign tax credit and interest allocation positions.  Management is currently evaluating thosehas evaluated the proposed adjustments and has agreed to determine if it agrees, but if accepted, we dopay the related taxes.  Management does not anticipate that the adjustments wouldwill result in a material change to our financial position.

FIN 48 Adoption

We adopted the provisions of FIN 48 on January 1, 2007.  As a result of the implementation of FIN 48, we recognized approximately a $17 million 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.

At January 1, 2007, the total amount of unrecognized tax benefits under FIN 48 was $175 million.  We believe it is reasonably possible that there will be a $46 million net decrease in unrecognized tax benefits due to the settlement of audits and the expiration of statute of limitations within 12 months of the reporting date.  The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $73 million.  There are $66 million of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility.deductibility is uncertain.  Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

Prior to the adoption of FIN 48, we recorded interest and penalty accruals related to income tax positions in tax accrual accounts.  With the adoption of FIN 48, we began recognizing interest accruals related to income tax positions in interest income or expense as applicable, and penalties in operating expenses.Other Operation and Maintenance.  As of January 1, 2007, we accrued approximately $25 million for the payment of uncertain interest and penalties.

         9.   Michigan Tax Restructuring

On July 12, 2007, the Governor of Michigan signed Michigan Senate Bill 0094 (MBT Act) and related companion bills into law providing a comprehensive restructuring of Michigan’s principal business tax.  The new law is effective January 1, 2008 and replaces the Michigan Single Business Tax that is scheduled to expire at the end of 2007.  The MBT Act is composed of a new tax which will be calculated based upon two components:  (a) a business income tax (BIT) imposed at a rate of 4.95% and (b) a modified gross receipts tax (GRT) imposed at a rate of 0.80%, which will collectively be referred to as the BIT/GRT tax calculation.  The new law also includes significant credits for engaging in Michigan-based activity.

On September 30, 2007, the Governor of Michigan signed House Bill 5198 which amends the MBT Act to provide for a new deduction on the BIT and GRT tax returns equal to the book-tax basis differences triggered as a result of the enactment of the MBT Act.  This new state-only temporary difference will be deducted over a 15-year period on the MBT Act tax returns starting in 2015.  The purpose of the new MBT Act state deduction was to provide companies relief from the recordation of the SFAS 109 Income Tax Liability.  We have evaluated the impact of the MBT Act and the application of the MBT Act will not materially affect our results of operations, cash flows or financial condition.
9.
FINANCING ACTIVITIES

Long-term Debt
 
September 30,
  
December 31,
 
 
March 31,
 
December 31,
  
2007
  
2006
 
Type of Debt
 
2007
 
2006
  
(in millions)
 
 
(in millions)
 
Senior Unsecured Notes $8,903 $8,653  $9,752  $8,653 
Pollution Control Bonds  1,950  1,950   2,134   1,950 
First Mortgage Bonds  90  90   -   90 
Defeased First Mortgage Bonds (a)  27  27   19   27 
Notes Payable  320  337   303   337 
Securitization Bonds  2,303  2,335   2,257   2,335 
Notes Payable To Trust  113  113   113   113 
Spent Nuclear Fuel Obligation (b)  251  247   257   247 
Other Long-term Debt  2  2   2   2 
Unamortized Discount (net)  (57) (56)  (61)  (56)
Total Long-term Debt Outstanding
  13,902  13,698   14,776   13,698 
Less Portion Due Within One Year
  1,377  1,269   910   1,269 
Long-term Portion
 $12,525 $12,429  $13,866  $12,429 

(a)In May 2004, we deposited cash and treasury securities were deposited with a trustee to defease all of TCC’s outstanding First Mortgage Bonds.  The defeased TCC First Mortgage Bonds had a balance of $19 million at both March 31,September 30, 2007 and December 31, 2006.  Trust Fund Assets related to this obligation of $23$22 million and $2 million at March 31,September 30, 2007 and December 31, 2006, respectively, are included in Other Temporary Cash Investments and $0 and $21 million at March 31, 2007 and December 31, 2006, respectively, areis included in Other Noncurrent Assets on our Condensed Consolidated Balance Sheets.  In December 2005, we deposited cash and treasury securities were deposited with a trustee to defease the remaining TNC outstanding First Mortgage Bond.  The defeased TNC First Mortgage Bond was retired in June 2007.  The defeased TNC First Mortgage Bond had a balance of $8 million at both March 31, 2007 and  December 31, 2006.  Trust fund assets related to this obligation of $9 million at both March 31, 2007 and December 31, 2006, are included in Other Temporary Cash Investments on our Condensed Consolidated Balance Sheet.  Trust fund assets are restricted for exclusive use in funding the interest and principal due on the First Mortgage Bonds.
(b)Pursuant to the Nuclear Waste Policy Act of 1982, I&M (a nuclear licensee) has an obligation with 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 $276$280 million and $274 million at March 31,September 30, 2007 and December 31, 2006, 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 threenine months of 2007 are shown in the tables below.
Company
 
Type of Debt
 
Principal Amount
 
Interest Rate
 
Due Date
 
    
(in millions)
 
(%)
   
Issuances:
         
SWEPCo Senior Unsecured Notes $250 5.55 2017 
Total Issuances
   $250(a)    
      
Company
 
Type of Debt
 
Principal Amount
 
Interest Rate
 
Due Date
 
    
(in millions)
 
(%)
   
Issuances:
         
APCo Pollution Control Bonds $75 Variable 2037 
APCo Senior Unsecured Notes  250 5.65 2012 
APCo Senior Unsecured Notes  250 6.70 2037 
CSPCo Pollution Control Bonds  45 Variable 2040 
OPCo Pollution Control Bonds  65 4.90 2037 
OPCo Senior Unsecured Notes  400 Variable 2010 
PSO Pollution Control Bonds  13 4.45 2020 
SWEPCo Senior Unsecured Notes  250 5.55 2017 
           
Non-Registrant:
          
AEGCo Senior Unsecured Notes  220 6.33 2037(a)
KPCo Senior Unsecured Notes  325 6.00 2017 
TCC Pollution Control Bonds  6 4.45 2020 
TNC Pollution Control Bonds  44 4.45 2020 
Total Issuances
   $1,943(b)    

The above borrowing arrangements do not contain guarantees, collateral or dividend restrictions.

The above borrowing arrangement does not contain guarantees, collateral or dividend restrictions.(a)AEGCo’s senior unsecured notes due 2037 are payable over the life of the notes as a $7.3 million annual principal amount plus accrued interest paid semiannually in March and September.
(a)(b)Amount indicated on statement of cash flows of $247$1,924 million is net of issuance costs and unamortized premium or discount.

 
Company
 
Type of Debt
 
Principal Amount Paid
 
Interest Rate
 
Due Date
 
    
(in millions)
 
(%)
   
Retirements and  Principal Payments:
         
OPCo Notes Payable $1 6.81 2008 
OPCo Notes Payable  6 6.27 2009 
SWEPCo Notes Payable  2 4.47 2011 
SWEPCo Notes Payable  4 6.36 2007 
SWEPCo Notes Payable  1 Variable 2008 
TCC Securitization Bonds  32 5.01 2008 
           
Non-Registrant:
          
AEP Subsidiaries Notes Payable  3 Variable 2017 
Total Retirements
   $49     
In May 2007, I&M remarketed its outstanding $50 million Pollution Control Bonds, resulting in a new interest rate of 4.625%.  No proceeds were received related to this remarketing.  The principal amount of the Pollution Control Bonds is reflected in Long-term Debt on our Condensed Consolidated Balance Sheet as of September 30, 2007.
In August 2007, TCC remarketed its outstanding $60 million Pollution Control Bonds, resulting in a new interest rate of 5.20%.  No proceeds were received related to this remarketing.  The principal amount of Pollution Control Bonds is reflected in Long-term Debt on our Condensed Consolidated Balance Sheet as of September 30, 2007.

    
Principal
 
Interest
   
Company
 
Type of Debt
 
Amount Paid
 
Rate
 
Due Date
 
    
(in millions)
 
(%)
   
Retirements and Principal Payments:
       
AEP Senior Unsecured Notes $345 4.709 2007 
APCo Senior Unsecured Notes  125 Variable 2007 
OPCo Notes Payable  3 6.81 2008 
OPCo Notes Payable  6 6.27 2009 
PSO Pollution Control Bonds  13 6.00 2020 
SWEPCo First Mortgage Bonds  90 7.00 2007 
SWEPCo Notes Payable  4 4.47 2011 
SWEPCo Notes Payable  4 6.36 2007 
SWEPCo Notes Payable  3 Variable 2008 
           
Non-Registrant:
          
AEGCo Senior Unsecured Notes  2 6.33 2037(a)
AEP Subsidiaries Notes Payable  10 Variable 2017 
CSW Energy, Inc. Notes Payable  4 5.88 2011 
KPCo Senior Unsecured Notes  125 5.50 2007 
TCC Securitization Bonds  53 5.01 2008 
TCC Securitization Bonds  25 4.98 2010 
TCC Pollution Control Bonds  6 6.00 2020 
TNC Pollution Control Bonds  44 6.00 2020 
TNC Defeased First Mortgage Bonds  8 7.75 2007 
Total Retirements and
  Principal Payments
  $870     

(a)AEGCo’s Senior Unsecured Notes due 2037 are payable over the life of the notes as a $7.3 million annual principal amount plus accrued interest paid semiannually in March and September.
In AprilOctober 2007, OPCo issued $400KPCo retired $48 million of three-year floating rate notes at an initial rate of 5.53%6.91% Senior Unsecured Notes due in 2010. The proceeds from this issuance will contribute to our investment in environmental equipment.2007.

Short-term Debt

Short-term debt is used to fund our corporate borrowing program and fund other short-term cash needs.  Our outstanding short-term debt iswas as follows:
  
March 31, 2007
  
December 31, 2006
 
  
Outstanding
Amount
 
Interest
Rate
  
Outstanding
Amount
 
Interest
Rate
 
Type of Debt
 
(in millions)
     
(in millions)
    
Commercial Paper - AEP $150  5.43%(a)$-  - 
Commercial Paper - JMG (b)  5  5.56%  1  5.56%
Line of Credit - Sabine (c)  20  6.52%  17  6.38%
Total
 $175     $18    
  
September 30, 2007
  
December 31, 2006
 
  
Outstanding
 
Interest
  
Outstanding
 
Interest
 
  
Amount
 
Rate
  
Amount
 
Rate
 
Type of Debt
 
(in millions)
     
(in millions)
    
Commercial Paper – AEP $559  5.60%(a)$-  - 
Commercial Paper – JMG (b)  2  5.3588%  1  5.56%
Line of Credit – Sabine (c)  26  6.07%  17  6.38%
Total
 $587     $18    

(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 is consolidated under FIN 46.  This line of credit does not reduce available liquidity under AEP’s credit facilities.

Credit Facilities

In March 2007, we amended the terms of our credit facilities.  The amended facilities are structured as two $1.5 billion credit facilities, with an option in each to issue up to $300 million as letters of credit, expiring separately in March 2011 and April 2012.

Dividend Restrictions

Under the Federal Power Act, AEP’s public utility subsidiaries are restricted from paying dividends out of stated capital.

Sale of Receivables – AEP Credit

In October 2007, we renewed AEP Credit’s sale of receivables agreement.  The sale of receivables agreement provides a commitment of $650 million from a bank conduit to purchase receivables from AEP Credit.  Under the agreement, the commitment will increase to $700 million for the months of August and September to accommodate seasonal demand.  This agreement will expire in October 2008.
APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
 
 
 









AEP GENERATINGAPPALACHIAN POWER COMPANY






















AEP GENERATING COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

We engage in the generation and wholesale sale of electric power to two affiliates, I&M and KPCo, under long-term agreements. We derive operating revenues from the sale of Rockport Plant energy and capacity to I&M and KPCo pursuant to FERC-approved long-term unit power agreements through December 2022. Under the terms of its unit power agreement, I&M agreed to purchase all of our Rockport energy and capacity unless it is sold to other utilities or affiliates. I&M assigned 30% of its rights to energy and capacity to KPCo.

The unit power agreements provide for a FERC-approved rate of return on common equity, a return on other capital (net of temporary cash investments) and recovery of costs including operation and maintenance, fuel and taxes. Under the terms of the unit power agreements, we accumulate all expenses monthly and prepare bills for our affiliates. In the month the expenses are incurred, we recognize the billing revenues and establish a receivable from the affiliated companies. The co-owners divide the costs of operating the plant.

Results of Operations

FirstThird Quarter of 2007 Compared to FirstThird Quarter of 2006

Reconciliation of FirstThird Quarter of 2006 to FirstThird Quarter of 2007
Net Income
(in millions)

First Quarter of 2006
    $2.9 
        
Change in Gross Margin:
       
Wholesale Sales     (0.7)
        
Changes in Operating Expenses and Other:
       
Other Operation and Maintenance  (1.3)   
Interest Expense  (0.5)   
Total Change in Operating Expenses and Other
     (1.8)
        
Income Tax Expense (Credit)     1.2 
        
First Quarter of 2007
    $1.6 
Third Quarter of 2006
    $31 
        
Changes in Gross Margin:
       
Retail Margins  13     
Off-system Sales  18     
Transmission Revenues, Net  (22)    
Other  (14)    
Total Change in Gross Margin
      (5)
         
Changes in Operating Expenses and Other:
        
Other Operation and Maintenance  (27)    
Depreciation and Amortization  9     
Taxes Other Than Income Taxes  1     
Carrying Costs Income  36     
Other Income, Net  (8)    
Interest Expense  (18)    
Total Change in Operating Expenses and Other
      (7)
         
Income Tax Expense      5 
         
   Third Quarter of 2007
     $24 

Net Income decreased $1.3$7 million for 2007 compared with 2006.to $24 million.  The fluctuation in Net Income is a result of terms in the unit power agreements which allow for a return on total capitalkey drivers of the Rockport Plant calculated and adjusted monthly for over/under billings.

decrease were a $5 million decrease in Gross Margin defined asand a $7 million increase in Operating Revenues less Fuel for Electric Generation, decreased $0.7Expenses and Other, partially offset by a $5 million primarily due to year-end tax adjustments reflecteddecrease in January’s bill.

Other Operation and Maintenance expenses increased $1.3 million primarily due to increased maintenance cost reflecting more planned and forced outages at the Rockport Plant in 2007 than 2006.

Interest Expense increased $0.5 million primarily due to increased rates on short-term borrowings and increased money pool borrowings.

Income Taxes

Income Tax Expense (Credit) decreased $1.2 million primarily due to a decrease in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis.

Significant Factors

Lawrenceburg Generating Station

In January 2007, we agreed to purchase Lawrenceburg Generating Station (Lawrenceburg) from an affiliate of Public Service Enterprise Group (PSEG) for approximately $325 million and the assumption of liabilities of approximately $2 million. The transaction is expected to close 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. This new generation acquisition will be financed by a capital contribution from AEP and issuance of debt related to this acquisition. We plan to sell the power to CSPCo through a FERC-approved purchase power contract.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in our 2006 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets 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.


AEP GENERATING COMPANY
CONDENSED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
      
OPERATING REVENUES
 $77,151 $78,151 
        
EXPENSES
       
Fuel Used for Electric Generation  43,649  43,961 
Rent - Rockport Plant Unit 2  17,071  17,071 
Other Operation  3,326  3,068 
Maintenance  3,811  2,786 
Depreciation and Amortization  5,990  5,975 
Taxes Other Than Income Taxes  1,081  1,070 
TOTAL
  74,928  73,931 
        
OPERATING INCOME
  2,223  4,220 
        
Interest Expense  (1,252) (722)
        
INCOME BEFORE INCOME TAXES
  971  3,498 
        
Income Tax Expense (Credit)  (620) 570 
        
NET INCOME
 $1,591 $2,928 

CONDENSED STATEMENTS OF RETAINED EARNINGS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
      
BALANCE AT BEGINNING OF PERIOD
 $30,942 $26,038 
        
FIN 48 Adoption, Net of Tax  27  - 
        
Net Income  1,591  2,928 
        
Cash Dividends Declared  -  1,998 
        
BALANCE AT END OF PERIOD
 $32,560 $26,968 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY
CONDENSED BALANCE SHEETS
ASSETS
March 31, 2007 and December 31, 2006
(in thousands)
(Unaudited)


  
2007
 
2006
 
CURRENT ASSETS
       
Accounts Receivable - Affiliated Companies $29,380 $31,060 
Fuel  28,414  37,701 
Materials and Supplies  8,024  7,873 
Accrued Tax Benefits  1,820  3,808 
Prepayments and Other  38  57 
TOTAL
  67,676  80,499 
        
PROPERTY, PLANT AND EQUIPMENT
       
Electric - Production  688,599  686,776 
Other  2,567  2,460 
Construction Work in Progress  15,931  15,198 
Total
  707,097  704,434 
Accumulated Depreciation and Amortization  405,676  398,422 
TOTAL - NET
  301,421  306,012 
        
OTHER NONCURRENT ASSETS
       
Regulatory Assets  5,403  5,438 
Deferred Charges and Other  3,667  1,382 
TOTAL
  9,070  6,820 
        
TOTAL ASSETS
 $378,167 $393,331 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


AEP GENERATING COMPANY
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY
March 31, 2007 and December 31, 2006
(Unaudited)

  
2007
 
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates $29,997 $53,646 
Accounts Payable:       
General  6  549 
Affiliated Companies  18,918  27,935 
Accrued Taxes  7,092  3,685 
Accrued Rent - Rockport Plant Unit 2  23,427  4,963 
Other  521  1,200 
TOTAL
  79,961  91,978 
        
NONCURRENT LIABILITIES
       
Long-term Debt - Nonaffiliated  44,839  44,837 
Deferred Income Taxes  19,792  19,749 
Regulatory Liabilities and Deferred Investment Tax Credits  76,069  79,650 
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2  87,370  88,762 
Deferred Credits and Other  13,142  12,979 
TOTAL
  241,212  245,977 
        
TOTAL LIABILITIES
  321,173  337,955 
        
Commitments and Contingencies (Note 4)       
        
COMMON SHAREHOLDER’S EQUITY
       
Common Stock - Par Value - $1,000 Per Share:
  Authorized - 1,000 Shares
  Outstanding - 1,000 Shares
  1,000  1,000 
Paid-in Capital  23,434  23,434 
Retained Earnings  32,560  30,942 
TOTAL
  56,994  55,376 
        
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY
 $378,167 $393,331 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


AEP GENERATING COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)
  
2007
 
2006
 
OPERATING ACTIVITIES
       
Net Income
 $1,591 $2,928 
Adjustments for Noncash Items:
       
Depreciation and Amortization  5,990  5,975 
Deferred Income Taxes  (1,205) (1,126)
Deferred Investment Tax Credits  (820) (827)
Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2  (1,392) (1,392)
Deferred Property Taxes  (2,516) (2,734)
Changes in Other Noncurrent Assets  47  (403)
Changes in Other Noncurrent Liabilities  200  374 
Changes in Certain Components of Working Capital:
       
Accounts Receivable  1,680  1,607 
Fuel, Materials and Supplies  9,136  (1,044)
Accounts Payable  (9,560) (2,068)
Accrued Taxes, Net  5,252  6,179 
Accrued Rent - Rockport Plant Unit 2  18,464  18,464 
Other Current Assets  (28) (35)
Other Current Liabilities  (332) (379)
Net Cash Flows From Operating Activities
  26,507  25,519 
        
INVESTING ACTIVITIES
       
Construction Expenditures  (2,841) (1,693)
        
FINANCING ACTIVITIES
       
Change in Advances from Affiliates, Net  (23,649) (21,814)
Principal Payments for Capital Lease Obligations  (17) (14)
Dividends Paid on Common Stock  -  (1,998)
Net Cash Flows Used For Financing Activities
  (23,666) (23,826)
        
Net Change in Cash and Cash Equivalents
  -  - 
Cash and Cash Equivalents at Beginning of Period
  -  - 
Cash and Cash Equivalents at End of Period
 $- $- 

SUPPLEMENTARY INFORMATION
       
Cash Paid for Interest, Net of Capitalized Amounts $1,398 $1,109 
Net Cash Received for Income Taxes  (439) - 
Noncash Acquisitions Under Capital Leases  1  27 

   See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to AEGCo’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 AEGCo.

Footnote Reference
Significant Accounting MattersNote 1
New Accounting PronouncementsNote 2
Commitments, Guarantees and ContingenciesNote 4
Acquisitions, Dispositions and Assets Held for SaleNote 5
Business SegmentsNote 7
Income TaxesNote 8
Financing ActivitiesNote 9











AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES





AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS



Results of Operations

First Quarter of 2007 Compared to First Quarter of 2006

Reconciliation of First Quarter of 2006 to First Quarter of 2007
Net Income
(in millions)

First Quarter of 2006
    $4 
        
Changes in Gross Margin:
       
Off-system Sales  7    
Texas Wires  6    
Transmission Revenues  1    
Other  28    
Total Change in Gross Margin
     42 
        
Changes in Operating Expenses and Other:
       
Other Operation and Maintenance  2    
Depreciation and Amortization  (13)   
Taxes Other Than Income Taxes  2    
Carrying Costs Income  (19)   
Other Income  5    
Interest Expense  (19)   
Total Change in Operating Expenses and Other
     (42)
        
First Quarter of 2007
    $4 

Net Income remained relatively flat in the first quarter of 2007 compared to the first quarter of 2006.Expense.

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

·Margins from Off-system Sales increased $7 million primarily due to lower margins from optimization activities of $5 million in 2006. An additional $2 million increase was primarily due to a $4 million provision for refund recorded in 2006 related to the pending and subsequent sale of our portion of the Oklaunion Plant offset in part by reduced sales margins upon completion of the sale.
·Texas Wires revenues increased $6 million primarily due to increased usage and favorable weather conditions. As compared to the prior year, heating degree days more than doubled.
·Other revenues increased $28 million. This increase was due in part to $36 million of revenue from securitization transition charges primarily resulting from new financing in October 2006. Securitization transition charges represent amounts collected to recover securitization bond principal and interest payments related to our securitized transition assets and are fully offset by amortization and interest expenses. This increase was partially offset by a $7 million decrease in third party construction project revenues mainly related to work performed for the Lower Colorado River Authority.

Operating Expenses and Other changed between years as follows:

·Other Operation and Maintenance expenses decreased $2 million primarily due to a $5 million decrease from lower expenses related to construction projects performed for third parties, primarily Lower Colorado River Authority. This decrease is partially offset by an increase of $2 million in payments made for transmission services and approximately $1 million increase related to the replacement of meters.
·Depreciation and Amortization expense increased $13 million primarily due to the recovery and amortization of the securitization assets of $15 million offset in part by $2 million related to the amortization of the CTC liability (see “TCC’s 2006 Securitization Proceeding” and “TCC’s 2006 CTC Proceeding” sections of Note 4 of the 2006 Annual Report).
·Taxes Other Than Income Taxes decreased $2 million primarily due to lower property-related taxes related to Texas tax legislation and the sale of our portion of Oklaunion in February 2007.
·Carrying Costs Income decreased $19 million primarily due to the absence of carrying cost on stranded cost recovery.
·Other Income increased $5 million primarily due to larger invested balances in the Utility Money Pool.
·Interest Expense increased $19 million primarily due to a $22 million increase in long-term debt interest primarily related to the Securitization Bonds issued in October 2006, offset in part by the retirement of other long-term debt.

Income Taxes

Income Tax Expense remained relatively flat for the first quarter 2007.

Financial Condition

Credit Ratings

In April 2007, Fitch Ratings downgraded our unsecured debt from A- to BBB+ and placed us on negative outlook. The negative rating outlook reflects Fitch’s expectation that credit metrics will continue to be weak for the BBB rating category absent a favorable outcome in our pending rate case in Texas. See “TCC and TNC Energy Delivery Base Rate Filings” in Note 3.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in our 2006 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

VaR Associated with Debt Outstanding

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $228 million and $232 million at March 31, 2007 and December 31, 2006, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or consolidated financial position.



AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
REVENUES
     
Electric Generation, Transmission and Distribution $171,987 $123,211 
Sales to AEP Affiliates  1,130  1,598 
Other  3,814  10,479 
TOTAL
  176,931  135,288 
        
EXPENSES
       
Fuel and Other Consumables Used for Electric Generation  825  1,726 
Purchased Electricity for Resale  1,509  1,680 
Other Operation  57,396  58,902 
Maintenance  7,785  7,789 
Depreciation and Amortization  46,020  33,360 
Taxes Other Than Income Taxes  18,524  20,363 
TOTAL
  132,059  123,820 
        
OPERATING INCOME
  44,872  11,468 
        
Other Income (Expense):
       
Interest Income  4,959  505 
Carrying Costs Income  -  19,423 
Allowance for Equity Funds Used During Construction  1,159  373 
Interest Expense  (46,021) (26,773)
        
INCOME BEFORE INCOME TAXES
  4,969  4,996 
        
Income Tax Expense  1,431  1,223 
        
NET INCOME
  3,538  3,773 
        
Preferred Stock Dividend Requirements  60  60 
        
EARNINGS APPLICABLE TO COMMON STOCK
 $3,478 $3,713 

The common stock of TCC is owned by a wholly-owned subsidiary of AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
                 
DECEMBER 31, 2005
 $55,292 $132,606 $760,884 $(1,152)$947,630 
                 
Preferred Stock Dividends        (60)    (60)
TOTAL
              947,570 
                 
COMPREHENSIVE INCOME
                
Other Comprehensive Income, Net of Taxes:
                
Cash Flow Hedges, Net of Tax of $141           262  262 
NET INCOME
        3,773     3,773 
TOTAL COMPREHENSIVE INCOME
              4,035 
                 
MARCH 31, 2006
 $55,292 $132,606 $764,597 $(890)$951,605 
                 
DECEMBER 31, 2006
 $55,292 $132,606 $217,218 $- $405,116 
                 
FIN 48 Adoption, Net of Tax        (2,187)    (2,187)
Preferred Stock Dividends        (60)    (60)
TOTAL
              402,869 
                 
COMPREHENSIVE INCOME
                
NET INCOME
        3,538     3,538 
TOTAL COMPREHENSIVE INCOME
              3,538 
                 
MARCH 31, 2007
 $55,292 $132,606 $218,509 $- $406,407 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2007 and December 31, 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
CURRENT ASSETS
       
Cash and Cash Equivalents $52 $779 
Other Cash Deposits  131,824  104,203 
Advances to Affiliates  216,953  394,004 
Accounts Receivable:       
Customers  44,519  31,215 
Affiliated Companies  6,513  8,613 
Accrued Unbilled Revenues  17,969  10,093 
Allowance for Uncollectible Accounts  (45) (49)
   Total Accounts Receivable  68,956  49,872 
Materials and Supplies  30,526  28,347 
Prepayments and Other  11,107  5,672 
TOTAL
  459,418  582,877 
        
PROPERTY, PLANT AND EQUIPMENT
       
Electric:       
Transmission  917,708  904,527 
Distribution  1,602,745  1,579,498 
Other  224,856  220,028 
Construction Work in Progress  166,300  165,979 
Total
  2,911,609  2,870,032 
Accumulated Depreciation and Amortization  636,740  630,239 
TOTAL - NET
  2,274,869  2,239,793 
        
OTHER NONCURRENT ASSETS
       
Regulatory Assets  187,765  193,111 
Securitized Transition Assets  2,133,966  2,158,408 
Employee Benefits and Pension Assets  35,534  35,574 
Deferred Charges and Other  68,393  69,493 
TOTAL
  2,425,658  2,456,586 
        
Assets Held for Sale - Texas Generation Plant
  -  44,475 
        
TOTAL ASSETS
 $5,159,945 $5,323,731 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2007 and December 31, 2006
(Unaudited)

  
2007
 
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Accounts Payable:       
General $17,857 $26,934 
Affiliated Companies  17,329  21,234 
Long-term Debt Due Within One Year - Nonaffiliated  138,507  78,227 
Customer Deposits  17,851  18,742 
Accrued Taxes  33,474  74,499 
Accrued Interest  57,625  44,712 
Other  21,138  34,762 
TOTAL
  303,781  299,110 
        
NONCURRENT LIABILITIES
       
Long-term Debt - Nonaffiliated  2,845,020  2,937,387 
Deferred Income Taxes  1,037,080  1,034,123 
Regulatory Liabilities and Deferred Investment Tax Credits  503,627  598,027 
Deferred Credits and Other  58,109  44,047 
TOTAL
  4,443,836  4,613,584 
        
TOTAL LIABILITIES
  4,747,617  4,912,694 
        
Cumulative Preferred Stock Not Subject to Mandatory Redemption  5,921  5,921 
        
Commitments and Contingencies (Note 4)       
        
COMMON SHAREHOLDER’S EQUITY
       
Common Stock - Par Value - $25 Per Share:       
Authorized - 12,000,000 Shares       
Outstanding - 2,211,678 Shares  55,292  55,292 
Paid-in Capital  132,606  132,606 
Retained Earnings  218,509  217,218 
TOTAL
  406,407  405,116 
        
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 $5,159,945 $5,323,731 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
OPERATING ACTIVITIES
       
Net Income
 $3,538 $3,773 
Adjustments for Noncash Items:
       
Depreciation and Amortization  46,020  33,360 
Deferred Income Taxes  11,102  2,928 
Carrying Costs on Stranded Cost Recovery  -  (19,423)
Mark-to-Market of Risk Management Contracts  -  5,125 
Fuel Over/Under Recovery, Net  (98,665) - 
Deferred Property Taxes  (20,064) (25,755)
Change in Other Noncurrent Assets  (753) (1,330)
Change in Other Noncurrent Liabilities  3,187  1,398 
Changes in Certain Components of Working Capital:
       
Accounts Receivable, Net  (19,084) 121,367 
Fuel, Materials and Supplies  (2,543) (2,569)
Accounts Payable  (3,957) (53,124)
Customer Deposits  (891) (6,514)
Accrued Taxes, Net  (40,642) 6,854 
Accrued Interest  11,019  (16,152)
Other Current Assets  681  2,629 
Other Current Liabilities  (13,867) (7,461)
Net Cash Flows From (Used for) Operating Activities
  (124,919) 45,106 
        
INVESTING ACTIVITIES
       
Construction Expenditures  (59,872) (58,645)
Change in Other Cash Deposits, Net  (6,071) 29,736 
Change in Advances to Affiliates, Net  177,051  (32,101)
Proceeds from Sale of Assets  45,619  3,837 
Net Cash Flows From (Used For) Investing Activities
  156,727  (57,173)
        
FINANCING ACTIVITIES
       
Issuance of Long-term Debt - Affiliated  -  125,000 
Change in Advances from Affiliates, Net  -  (82,080)
Retirement of Long-term Debt - Nonaffiliated  (32,125) (30,641)
Principal Payments for Capital Lease Obligations  (350) (152)
Dividends Paid on Cumulative Preferred Stock  (60) (60)
Net Cash From (Used For) Financing Activities
  (32,535) 12,067 
        
Net Decrease in Cash and Cash Equivalents
  (727) - 
Cash and Cash Equivalents at Beginning of Period
  779  - 
Cash and Cash Equivalents at End of Period
 $52 $- 

SUPPLEMENTARY INFORMATION
       
Cash Paid for Interest, Net of Capitalized Amounts $27,961 $40,646 
Net Cash Paid for Income Taxes  32,601  485 
Noncash Acquisitions Under Capital Leases  363  680 
Construction Expenditures Included in Accounts Payable at March 31,  7,477  9,970 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to TCC’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 TCC.

Footnote Reference
Significant Accounting MattersNote 1
New Accounting PronouncementsNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
Acquisitions, Dispositions and Assets Held for SaleNote 5
Benefit PlansNote 6
Business SegmentsNote 7
Income TaxesNote 8
Financing ActivitiesNote 9












AEP TEXAS NORTH COMPANY AND SUBSIDIARY






AEP TEXAS NORTH COMPANY AND SUBSIDIARY
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations

First Quarter of 2007 Compared to First Quarter of 2006

Reconciliation of First Quarter of 2006 to First Quarter of 2007
Net Income
(in millions)

First Quarter of 2006
    $4 
        
Changes in Gross Margin:
       
Off-system Sales  3    
Texas Wires  2    
Transmission Revenues  1    
Total Change in Gross Margin
     6 
        
Changes in Operating Expenses and Other:
       
Other Operation and Maintenance  (4)   
Total Change in Operating Expenses and Other
     (4)
        
Income Tax Expense
     (1)
        
First Quarter of 2007
    $5 

Net Income increased $1 million primarily due to an increase in Gross Margin of $6 million partially offset by an increase in Other Operation and Maintenance expenses of $4 million.

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

·Margins from Off-system Sales increased $3 million primarily due to lower margins from optimization activities of $2 million in 2006. An additional $1 million increase was primarily due to the implementation of the Power Purchase Agreement with AEP Energy Partners in January 2007. Under this agreement, we recover our costs and capacity charges regardless of plant availability. See “Oklaunion PPA between TNC and AEP Energy Partners” section of Note 1.
·Texas Wires revenues increased $2 million primarily due to increased usage and favorable weather conditions. As compared to the prior year, heating degree days increased 77%.

Operating Expenses and Other changed between years as follows:

·Other Operation and Maintenance expenses increased $4 million primarily resulting from planned and forced outages at our Oklaunion Plant during the first quarter of 2007.

Income Taxes

Income Tax Expense increased $1 million primarily due to an increase in pretax book income.
Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in our 2006 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

Our risk management assets and liabilities are zero at March 31, 2007 as a result of our exit from the generation business. See “Oklaunion PPA between TNC and AEP Energy Partners” section of Note 1.

VaR Associated with Debt Outstanding

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $11 million and $12 million at March 31, 2007 and December 31, 2006, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or financial position.




AEP TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
REVENUES
     
Electric Generation, Transmission and Distribution $38,079 $68,825 
Sales to AEP Affiliates  24,654  6,025 
Other  230  (184)
TOTAL
  62,963  74,666 
        
EXPENSES
       
Fuel and Other Consumables Used for Electric Generation  6,276  12,115 
Purchased Electricity for Resale  2,802  14,396 
Other Operation  19,563  18,478 
Maintenance  7,467  5,201 
Depreciation and Amortization  10,346  10,301 
Taxes Other Than Income Taxes  4,841  5,540 
TOTAL
  51,295  66,031 
        
OPERATING INCOME
  11,668  8,635 
        
Other Income (Expense):
       
Interest Income  133  219 
Allowance for Equity Funds Used During Construction  52  382 
Interest Expense  (4,346) (4,362)
        
INCOME BEFORE INCOME TAXES
  7,507  4,874 
        
Income Tax Expense  2,230  1,040 
        
NET INCOME
  5,277  3,834 
        
Preferred Stock Dividend Requirements  26  26 
Gain on Reacquired Preferred Stock  -  2 
        
EARNINGS APPLICABLE TO COMMON STOCK
 $5,251 $3,810 

The common stock of TNC is owned by a wholly-owned subsidiary of AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


AEP TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2005
 $137,214 $2,351 $174,858 $(504)$313,919 
                 
Common Stock Dividends        (8,000)    (8,000)
Preferred Stock Dividends        (26)    (26)
Gain on Reacquired Preferred Stock        2     2 
TOTAL
              305,895 
                 
COMPREHENSIVE INCOME
                
Other Comprehensive Income, Net of Taxes:
                
Cash Flow Hedges, Net of Tax of $102           189  189 
NET INCOME
        3,834     3,834 
TOTAL COMPREHENSIVE INCOME
              4,023 
                 
MARCH 31, 2006
 $137,214 $2,351 $170,668 $(315)$309,918 
                 
DECEMBER 31, 2006
 $137,214 $2,351 $176,950 $(10,159)$306,356 
                 
FIN 48 Adoption, Net of Tax        (557)    (557)
Preferred Stock Dividends        (26)    (26)
TOTAL
              305,773 
                 
COMPREHENSIVE INCOME
                
Other Comprehensive Income, Net of Taxes:
                
Cash Flow Hedges, Net of Tax of $378           702  702 
NET INCOME
        5,277     5,277 
TOTAL COMPREHENSIVE INCOME
              5,979 
                 
MARCH 31, 2007
 $137,214 $2,351 $181,644 $(9,457)$311,752 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


AEP TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2007 and December 31, 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
CURRENT ASSETS
       
Cash and Cash Equivalents $3 $84 
Other Cash Deposits  8,958  8,863 
Advances to Affiliates  -  13,543 
Accounts Receivable:       
Customers  11,080  21,742 
Affiliated Companies  13,177  5,634 
Accrued Unbilled Revenues  2,917  2,292 
Allowance for Uncollectible Accounts  (18) (9)
   Total Accounts Receivable  27,156  29,659 
Fuel  11,401  8,559 
Materials and Supplies  9,544  9,319 
Prepayments and Other  1,879  1,681 
TOTAL
  58,941  71,708 
        
PROPERTY, PLANT AND EQUIPMENT
       
Electric:       
Production  290,654  290,485 
Transmission  330,272  327,845 
Distribution  506,752  512,265 
Other  160,141  159,451 
Construction Work in Progress  36,145  38,847 
Total
  1,323,964  1,328,893 
Accumulated Depreciation and Amortization  483,960  486,961 
TOTAL - NET
  840,004  841,932 
        
OTHER NONCURRENT ASSETS
       
Regulatory Assets  38,356  38,402 
Employee Benefits and Pension Assets  12,824  12,867 
Deferred Charges and Other  12,807  2,605 
TOTAL
  63,987  53,874 
        
TOTAL ASSETS
 $962,932 $967,514 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



AEP TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2007 and December 31, 2006
(Unaudited)

  
2007
 
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates $11,185 $- 
Accounts Payable:       
General  6,328  4,448 
Affiliated Companies  34,129  43,993 
Long-term Debt Due Within One Year - Nonaffiliated  8,151  8,151 
Accrued Taxes  19,477  21,782 
Other  8,687  14,934 
TOTAL
  87,957  93,308 
        
NONCURRENT LIABILITIES
       
Long-term Debt - Nonaffiliated  268,807  268,785 
Long-term Risk Management Liabilities  -  1,081 
Deferred Income Taxes  120,261  124,048 
Regulatory Liabilities and Deferred Investment Tax Credits  132,646  139,429 
Deferred Credits and Other  39,160  32,158 
TOTAL
  560,874  565,501 
        
TOTAL LIABILITIES
  648,831  658,809 
        
Cumulative Preferred Stock Not Subject to Mandatory Redemption  2,349  2,349 
        
Commitments and Contingencies (Note 4)       
        
COMMON SHAREHOLDER’S EQUITY
       
Common Stock - Par Value - $25 Per Share:       
Authorized - 7,800,000 Shares       
Outstanding - 5,488,560 Shares  137,214  137,214 
Paid-in Capital  2,351  2,351 
Retained Earnings  181,644  176,950 
Accumulated Other Comprehensive Income (Loss)  (9,457) (10,159)
TOTAL
  311,752  306,356 
        
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 $962,932 $967,514 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


AEP TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)


  
2007
 
2006
 
OPERATING ACTIVITIES
       
Net Income
 $5,277 $3,834 
Adjustments for Noncash Items:
       
Depreciation and Amortization  10,346  10,301 
Deferred Income Taxes  (1,016) (1,323)
Mark-to-Market of Risk Management Contracts  -  1,989 
Deferred Property Taxes  (10,862) (12,360)
Change in Other Noncurrent Assets  1,508  (2,081)
Change in Other Noncurrent Liabilities  (5,713) 652 
Changes in Certain Components of Working Capital:
       
Accounts Receivable, Net  2,503  36,836 
Fuel, Materials and Supplies  (3,067) (2,156)
Accounts Payable  (9,176) (36,932)
Accrued Taxes, Net  (302) 4,059 
Other Current Assets  (255) 1,676 
Other Current Liabilities  (5,975) (9,775)
Net Cash Flows Used For Operating Activities
  (16,732) (5,280)
        
INVESTING ACTIVITIES
       
Construction Expenditures  (19,793) (18,662)
Change in Other Cash Deposits, Net  (95) 792 
Change In Advances to Affiliates, Net  13,543  31,240 
Proceeds from Sale of Assets  11,965  - 
Net Cash Flows From Investing Activities
  5,620  13,370 
        
FINANCING ACTIVITIES
       
Change in Advances from Affiliates, Net  11,185  - 
Principal Payments for Capital Lease Obligations  (128) (64)
Dividends Paid on Common Stock  -  (8,000)
Dividends Paid on Cumulative Preferred Stock  (26) (26)
Net Cash Flows From (Used For) Financing Activities
  11,031  (8,090)
        
Net Decrease in Cash and Cash Equivalents
  (81) - 
Cash and Cash Equivalents at Beginning of Period
  84  - 
Cash and Cash Equivalents at End of Period
 $3 $- 

SUPPLEMENTARY INFORMATION
       
Cash Paid for Interest, Net of Capitalized Amounts $6,150 $6,113 
Net Cash Paid for Income Taxes  2,288  - 
Noncash Acquisitions Under Capital Leases  98  224 
Construction Expenditures Included in Accounts Payable at March 31,  2,509  2,372 

 See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY AND SUBSIDIARY
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to TNC’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 TNC.

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









APPALACHIAN POWER COMPANY
AND SUBSIDIARIES






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


Results of Operations

First Quarter of 2007 Compared to First Quarter of 2006

Reconciliation of First Quarter of 2006 to First Quarter of 2007
Net Income
(in millions)

First Quarter of 2006
    $74 
        
Changes in Gross Margin:
       
Retail Margins  29    
Off-system Sales  (6)   
Transmission Revenues  (11)   
Other  1    
Total Change in Gross Margin
     13 
        
Changes in Operating Expenses and Other:
       
Other Operation and Maintenance  (5)   
Depreciation and Amortization  (11)   
Taxes Other Than Income Taxes  2    
Carrying Costs Income  (3)   
Interest Expense  (2)   
Total Change in Operating Expenses and Other
     (19)
        
Income Tax Expense     2 
        
   First Quarter of 2007
    $70 

Net Income decreased $4 million to $70 million in 2007 primarily due to an increase in Operating Expenses and Other of $19 million, partially offset by an increase in Gross Margin of $13 million.

The major components of our 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$13 million in comparison to 2006 primarily due to:
·A $42 million increase in retail revenues primarily related to new rates implemented in relation to our Virginia general rate case, which are being collected subject to refund, and recovery of Virginia Environmental and Reliability (E&R) costs. See the “APCo Virginia Base Rate Case” section of Note 3.
·A $9 million increase in retail sales primarily due to the impact of the Virginia base rate order issued in May 2007, the Virginia E&R and fuel cost recovery filings and increased demand in the residential class associated with favorable weather conditions.  HeatingCooling degree days increased approximately 19%22%.
These increases were partially offset by:
·A $14 million decrease in revenues related to financial transmission rights, net of congestion, primarily due to fewer transmission constraints in the PJM market.
·A $9 million decrease in revenues related to the Expanded Net Energy Cost (ENEC) mechanism with West Virginia retail customers primarily due to pass-through of off-system sales margins. The mechanism was reinstated in West Virginia effective July 1, 2006 in conjunction with our West Virginia rate case.
·Margins from Off-system Sales decreased $6Off-System sales increased $18 million primarily due to an $18 million decreasehigher sales volumes and power prices in physical sales margins partially offset by a $10 million increase in marginsthe east, benefits from optimization activitiesAEP’s eastern natural gas fleet, and a $2 million increase in our allocation of off-system sales margins under the SIA. The change in allocation methodology of the SIA occurred on April 1, 2006.higher trading margins.
·Transmission Revenues, Net decreased $11$22 million primarily due to PJM’s revision of its pricing methodology for transmission line losses to marginal-loss pricing effective June 1, 2007.  See “PJM Marginal-Loss Pricing” section of Note 3.
·Other revenue decreased $14 million primarily due to the eliminationreversal in the third quarter of SECA revenues as2006 of April 1, 2006. Seepreviously deferred gains on sales of allowances associated with the “Transmission Rate Proceedings at the FERC” section of Note 3.Virginia Environmental and Reliability Costs (E&R) case.

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

·Other Operation and Maintenance expenses increased $5$27 million mainly due to a $6 million increase in expenses for overhead line right-of-way clearing, overhead line repairs and increases in various other operation and maintenance expenses totaling $8 million. These increases were partially offset by a $9 million decrease in expenses related to the AEP Transmission Equalization Agreementprimarily due to the additionsettlement agreement regarding alleged violations of our Wyoming-Jacksons Ferry 765 kV linethe NSR provisions of the CAA, of which $26 million was energizedallocated to APCo.  See “Federal EPA Complaint and placed into service in June 2006.Notice of Violation” section of Note 4.
·Depreciation and Amortization expenses increased $11decreased $9 million primarily due to the amortizationwrite-off in the third quarter of 2006 of previously deferred depreciation expenses associated with the E&R case.
·Carrying Costs Income increased $36 million primarily due to the write-off in the third quarter of 2006 of previously recorded carrying chargescosts income associated with the E&R case.
·Other Income, Net decreased $8 million primarily due to a $6 million decrease in the equity component of AFUDC resulting from AFUDC recorded in the third quarter of 2006 associated with the E&R case and a lower construction work in progress (CWIP) balance after the Wyoming-Jacksons Ferry 765 kV line and the Mountaineer scrubber were placed into service.  In addition, interest income from the Utility Money Pool decreased $2 million.
·Interest Expense increased $18 million primarily due to a $9 million decrease in the debt component of AFUDC resulting from AFUDC recorded in the third quarter of 2006 associated with the E&R case.  In addition, Interest Expense also increased due to a $2 million increase in interest expense from the Utility Money Pool and a $4 million increase in interest expense from long-term debt issuances.
·Income Tax Expense decreased $5 million primarily due to a decrease in pretax book income and state income taxes partially offset by changes in certain book/tax differences accounted for on a flow-through basis.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

Reconciliation of Nine Months Ended September 30, 2006 to Nine Months Ended September 30, 2007
Net Income Before Extraordinary Loss
(in millions)

Nine Months Ended September 30, 2006
    $114 
        
Changes in Gross Margin:
       
Retail Margins  9     
Off-system Sales  30     
Transmission Revenues, Net  (32)    
Other  (10)    
Total Change in Gross Margin
      (3)
         
Changes in Operating Expenses and Other:
        
Other Operation and Maintenance  (35)    
Depreciation and Amortization  16     
Taxes Other Than Income Taxes  3     
Carrying Costs Income  36     
Other Income, Net  (13)    
Interest Expense  (33)    
Total Change in Operating Expenses and Other
      (26)
         
Income Tax Expense      13 
         
NNine Months Ended September 30, 2007
     $98 

Net Income Before Extraordinary Loss decreased $16 million to $98 million in 2007.  The key drivers of the decrease were a $26 million increase in Operating Expenses and Other, partially offset by a $13 million decrease in Income Tax Expense.

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 $9 million due to the impact of the Virginia base rate order issued in May 2007, the Virginia E&R and fuel cost recovery filings and increased demand in the residential class associated with favorable weather conditions.  Cooling degree days increased approximately 33%.
·Margins for Off-system Sales increased $30 million primarily due to higher trading margins.
·Transmission Revenues, Net decreased $32 million primarily due to PJM’s revision of its pricing methodology for transmission line losses to marginal-loss pricing effective June 1, 2007.  See “PJM Marginal-Loss Pricing” section of Note 3.
·Other revenue decreased $10 million primarily due to lower gains on sales of allowances and the reversal in the third quarter of 2006 of previously deferred gains on sales of allowances associated with the E&R case.

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

·Other Operation and Maintenance expenses increased $35 million primarily due to the following:
·A $26 million increase resulting from the settlement between AEP and the Federal EPA regarding alleged violations of the NSR provisions of the CAA.  The $26 million represents APCo’s allocation of the settlement.  See “Federal EPA Complaint and Notice of Violation” section of Note 4.
·A $9 million increase in steam maintenance expenses resulting from 2007 forced and planned outages at the Amos and Glen Lyn plants.
·Depreciation and Amortization expenses decreased $16 million primarily due to the following:
·An $8 million decrease resulting from lower Virginia depreciation rates implemented retroactively to January 2006 partially offset by additional depreciation expense that are being collected through the E&R surcharges and increased plant in service related tofor the Wyoming-Jacksons Ferry 765 kV line, which was energized and placed in service in June 2006.2006, and the Mountaineer scrubber, which was placed in service in February 2007.
·A $10 million decrease resulting from a net deferral of $10 million in ARO costs as approved in APCo’s Virginia base rate case.
·A $9 million decrease in depreciation expense related to the write-off in the third quarter of 2006 of previously deferred depreciation expense associated with the E&R case.
These decreases were partially offset by:
·The amortization of carrying charges of $12 million that are being collected through E&R surcharges.
·Carrying Costs Income decreased $3increased $36 million relatedprimarily due to the write-off in the third quarter of 2006 of previously recorded carrying costs income associated with ourthe E&R case.
·Other Income, Net decreased $13 million primarily due to lower interest income from the Utility Money Pool of $4 million. In addition, the equity component of AFUDC decreased $8 million resulting from AFUDC recorded in the third quarter of 2006 associated with the E&R case and a lower CWIP balance after the Wyoming-Jacksons Ferry 765 kV line and the Mountaineer scrubber were placed into service.
·Interest Expense increased $33 million primarily due to a $14 million decrease in the debt component of AFUDC resulting from AFUDC recorded in the third quarter of 2006 associated with the E&R case, a $13 million increase in interest expense from long-term debt issuances, a $4 million increase in the interest on the Virginia provision for revenue collected subject to refund and a $3 million increase in interest expense from the Utility Money Pool.
·Income Tax Expense decreased $13 million primarily due to a decrease in pretax book income and state income taxes partially offset by changes in certain book/tax differences accounted for on a flow-through basis.

Income Taxes

Income Tax Expense decreased $2 million primarily due to a decrease in pretax book income.

Financial Condition

Credit Ratings

The rating agencies currently have usAPCo on stable outlook.  Current ratings are as follows:

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

Cash Flow

Cash flows for the threenine months ended March 31,September 30, 2007 and 2006 were as follows:
 
2007
 
2006
   
2007
 
2006
 
 
(in thousands)
   
(in thousands)
 
Cash and Cash Equivalents at Beginning of Period
 $2,318 $1,741 
Cash and Cash Equivalents at Beginning of Period
 $2,318 $1,741 
Cash Flows From (Used For):       Cash Flows From (Used For):      
Operating Activities  176,029  210,980 
Investing Activities  (200,894) (194,897)
Financing Activities  24,534  (16,372)
Operating Activities  221,534 430,735 
Investing Activities  (570,019) (719,590)
Financing Activities  347,436  288,363 
Net Decrease in Cash and Cash Equivalents  (331) (289)Net Decrease in Cash and Cash Equivalents  (1,049) (492)
Cash and Cash Equivalents at End of Period
 $1,987 $1,452 
Cash and Cash Equivalents at End of Period
 $1,269 $1,249 

Operating Activities

Net Cash Flows From Operating Activities were $176$222 million in 2007.  WeAPCo produced incomeNet Income of $70$19 million during the period and had noncash expense items of $142 million for Depreciation and Amortization and $79 million for Extraordinary Loss for the Reapplication of Regulatory Accounting for Generation and $23 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 included no significant unusual items.

Net Cash Flows From Operating Activities were $431 million in 2006.  APCo produced Net Income of $114 million during the period and a noncash expense item of $59$158 million for Depreciation and Amortization.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The current period activity in working capital hadincluded no significant items in 2007.items.

Net Cash Flows From Operating Activities were $211 million in 2006. We produced income of $74 million during the period and a noncash expense item of $48 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital had two significant items, an increase in Accounts Receivable, Net and Accrued Taxes, Net. During the first quarter of 2006, we did not make any federal income tax payments and collected receivables from our affiliates related to power sales, settled litigation and emission allowances.

Investing Activities

Net Cash Flows Used For Investing Activities during 2007 and 2006 primarily reflect our construction expenditures of $202$538 million and $197$633 million, respectively.  Construction expenditures are primarily for projects to improve service reliability for transmission and distribution, as well as environmental upgrades at power plants for both periods.  In 2006, capital projects for transmission expenditures were primarily related to the Wyoming-Jacksons Ferry 765 KV line placed into service in June 2006.  Environmental upgrades include the installation of selective catalytic reduction equipment on our plants and the flue gas desulfurization projectprojects at the Amos and Mountaineer plants.  In February 2007, environmental upgrades werethe flue gas desulfurization project was completed forat the Mountaineer plant.  For the remainder of 2007, we expectBased upon APCo’s current forecast, APCo expects construction expenditures to be approximately $460 million.$200 million for the remainder of 2007, excluding AFUDC.  In addition, APCo’s investments in the Utility Money Pool increased by $39 million and $94 million in 2007 and 2006, respectively.

Financing Activities

Net Cash Flows From Financing Activities in 2007 were $25$347 million primarily due to the issuance of $75 million of Pollution Control Bonds in May 2007 and the issuance of $500 million of Senior Unsecured Notes in August 2007, net of the retirement of $125 million of Senior Unsecured Notes in June 2007.  We had a net increase of $48 million in borrowings from the Utility Money Pool and paid $15 million in dividends on common stock.

Net Cash Flows Used For Financing Activities were $16 million in 2006. In 2006, we retired a First Mortgage Bond of $100 million and incurred obligations of $50 million relating to pollution control bonds. We repaidAPCo also reduced its short-term borrowings from the Utility Money Pool by $35 million.

Net Cash Flows From Financing Activities were $288 million in 2006.  In 2006, APCo issued $500 million in Senior Notes and $50 million in Pollution Control Bonds.  APCo also retired First Mortgage Bonds of $30$100 million and reduced its short-term borrowings from the Utility Money Pool by $194 million.  In addition, weAPCo received funds of $68 million related to a long-term coal purchase contract amended in March 2006.

Financing Activity

There were no material long-termLong-term debt issuances and retirements during the first threenine months of 2007.2007 were:

Issuances
  
Principal
Amount
 
Interest
 
Due
Type of Debt
  
Rate
 
Date
   
(in thousands)
 
(%)
  
Pollution Control Bonds $75,000 Variable 2037
Senior Unsecured Notes  250,000 5.65 2012
Senior Unsecured Notes  250,000 6.70 2037

Retirements
  
Principal
Amount
 
Interest
 
Due
Type of Debt
  
Rate
 
Date
   
(in thousands)
 
(%)
  
Senior Unsecured Notes $125,000 Variable 2007

Liquidity

We haveAPCo has solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt or refinance long-term debt maturities.  In addition, we participateAPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.

Summary Obligation Information

A summary of our contractual obligations is included in ourthe 2006 Annual Report and has not changed significantly from year-end.year-end other than the debt issuances and retirements discussed in “Cash Flow” and “Financing Activity” above and the obligations resulting from the settlement agreement regarding alleged violations of the NSR provisions of the CAA.  See “Federal EPA Complaint and Notice of Violations” section of Note 4.

Significant Factors

New Generation

In January 2006, we filed a petition with the WVPSC requesting our approval of a Certificate of Public Convenience and Necessity to construct a 629 MW IGCC plant adjacent to our existing Mountaineer Generating Station in Mason County, WV. In January 2007, at our request, the WVPSC issued an order delaying the Commission’s deadline for issuing an order on the certificate to December 2007. Through March 31, 2007, we deferred pre-construction IGCC costs totaling $10 million. If the plant is not built and these costs are not recoverable, future results of operations and cash flows would be adversely affected.

Virginia Restructuring

In April 2004, Virginia enacted legislation that extended the transition period for electricity restructuring, including capped rates, through December 31, 2010. The legislation provides us with specified cost recovery opportunities during the capped rate period, including two optional bundled general base rate changes and an opportunity for timely recovery, through a separate rate mechanism, of certain incremental environmental and reliability costs incurred on and after July 1, 2004. Under the restructuring law, we continue to have an active fuel clause recovery mechanism in Virginia and continue to practice deferred fuel accounting. Also, under the restructuring law, we defer incremental environmental generation costs and incremental transmission and distribution reliability costs for future recovery, to the extent such costs are not being recovered when incurred, and amortize a portion of such deferrals commensurate with recovery.

In April 2007, the Virginia legislature adopted a comprehensive law providing for the re-regulation of electric utilities’ generation/generation and supply rates.  TheThese amendments shorten the transition period by two years (from 2010 to 2008) after which rates for retail generation/generation and supply will return to a form of cost-based regulation.regulation in lieu of market-based rates.  The legislation provides for, among other things, biennial rate reviews beginning in 2009,2009; rate adjustment clauses for the recovery of the costs of (a) transmission services and new transmission investment,investments, (b) Demand Side Management,demand side management, load management, and energy efficiency programs, (c) renewable energy programs, and (d) environmental retrofit and new generation investments,investments; significant return on equity enhancements for large investments in new generation and, subject to Virginia SCC approval, certain environmental retrofits, and a floor on the allowed return on equity based on the average earned return on equities’ of regional vertically integrated electric utilities.  Effective July 1, 2007, the amendments allow utilities to retain a minimum of 25% of the margins from off-system sales with the remaining margins from such sales credited against fuel factor expenses.expenses with a true-up to actual.  The legislation also allows usAPCo to continue to defer and recover incremental environmental and reliability costs incurred through December 31, 2008.  We expect thisThe new form of cost-based ratemakingre-regulation legislation should improve our annual returnresult in significant positive effects on APCo’s future earnings and cash flows from the mandated enhanced future returns on equity, and cash flow from operations when new ratemaking begins in 2009. However, with the return of cost-based regulation, our generation business will again meet the criteria for applicationreduction of regulatory accounting principles under SFAS 71. Resultslag from the opportunities to adjust base rates on a biennial basis and the new opportunities to request timely recovery of operations and financial condition could be adversely affected when we are required to re-establish certain net regulatory liabilities applicable to our generation/supply business. The timing and earnings effect from such reapplication of SFAS 71 regulatory accounting for our Virginia generation/supply business are uncertain at this time.new costs not included in base rates.

Litigation and Regulatory Activity

In the ordinary course of business, we areAPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, wemanagement 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 our pending litigation and regulatory proceedings, see Note 4 -– Rate Matters and Note 6 -– Commitments, Guarantees and Contingencies in ourthe 2006 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 our results of operations, financial condition and cash flows.

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

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2006 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

Our riskRisk management assets and liabilities are managed by AEPSC as agent for us.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 us.APCo.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included on ourthe condensed consolidated balance sheet as of March 31,September 30, 2007 and the reasons for changes in our total MTM value as compared to December 31, 2006.
 
Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of March 31,September 30, 2007
(in thousands)

 
MTM Risk Management Contracts
 
Cash Flow &
Fair Value
Hedges
 
DETM
Assignment (a)
 
Total
  
MTM Risk Management Contracts
  
Cash Flow &
Fair Value Hedges
  
DETM Assignment (a)
  
Total
 
Current Assets $66,058 $1,405 $- $67,463  $65,385  $3,806  $-  $69,191 
Noncurrent Assets  84,718  1,269  -  85,987   80,970   2,240   -   83,210 
Total MTM Derivative Contract Assets
  150,776  2,674  -  153,450   146,355   6,046   -   152,401 
                             
Current Liabilities  (47,767) (6,899) (3,152) (57,818)  (47,471)  (1,129)  (3,878)  (52,478)
Noncurrent Liabilities  (49,833) (804) (8,358) (58,995)  (48,866)  (214)  (6,478)  (55,558)
Total MTM Derivative Contract Liabilities
  (97,600) (7,703) (11,510) (116,813)  (96,337)  (1,343)  (10,356)  (108,036)
                             
Total MTM Derivative Contract Net Assets (Liabilities)
 $53,176 $(5,029)$(11,510)$36,637  $50,018  $4,703  $(10,356) $44,365 

(a)See “Natural Gas Contracts with DETM” section of Note 16 of the 2006 Annual Report.
 
MTM Risk Management Contract Net Assets
ThreeNine Months Ended March 31,September 30, 2007
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2006
 $52,489  $52,489 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period  (5,389) (10,155)
Fair Value of New Contracts at Inception When Entered During the Period (a)  255  255 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period  (35) 503 
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts  -  - 
Changes in Fair Value Due to Market Fluctuations During the Period (b)  4,918  3,858 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)  938   3,068 
Total MTM Risk Management Contract Net Assets
  53,176  50,018 
Net Cash Flow & Fair Value Hedge Contracts  (5,029) 4,703 
DETM Assignment (d)  (11,510)  (10,356)
Total MTM Risk Management Contract Net Assets at March 31, 2007
 $36,637 
Total MTM Risk Management Contract Net Assets at September 30, 2007
 $44,365 

(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)Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)“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 liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(d)See “Natural Gas Contracts with DETM” section of Note 16 of the 2006 Annual Report.

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

The following table presents:

·The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
·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
Fair Value of Contracts as of March 31,September 30, 2007
(in thousands)

  
Remainder
2007
 
2008
 
2009
 
2010
 
2011
 
After
2011
 
Total
 
Prices Actively Quoted - Exchange Traded Contracts $15,650 $(644)$706 $- $- $- $15,712 
Prices Provided by Other External Sources -
   OTC Broker Quotes (a)
  3,482  13,908  11,448  4,542  -  -  33,380 
Prices Based on Models and Other Valuation Methods (b)  (3,723) (2,358) 1,822  5,482  1,235  1,626  4,084 
Total
 $15,409 $10,906 $13,976 $10,024 $1,235 $1,626 $53,176 
  
Remainder
2007
 
2008
 
2009
 
2010
 
2011
 
After
2011
 
Total
Prices Actively Quoted – Exchange
  Traded Contracts
 $3,994 $(5,820)$1,134 $(20)$- $- $(712)
Prices Provided by Other External
  Sources – OTC Broker Quotes (a)
  1,170  17,393  13,606  10,310  -  -  42,479 
Prices Based on Models and Other
  Valuation Methods (b)
  754  660  1,027  1,685  2,112  2,013  8,251 
Total
 $5,918 $12,233 $15,767 $11,975 $2,112 $2,013 $50,018 

(a)“Prices Provided by Other External Sources -– OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)“Prices Based on Models and Other Valuation Methods” is used in absence of pricingindependent information from external sources.  Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources.  In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled.  The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.
Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available.available including values determinable by other third party transactions.

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

We areAPCo is exposed to market fluctuations in energy commodity prices impacting ourits power operations.  We monitorManagement monitors 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 doManagement does not hedge all commodity price risk.

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

We use forward contracts and collars as cash flow hedgesManagement uses foreign currency derivatives to lock in prices on certain transactions denominated in foreign currencies where deemed necessary. We donecessary, and designate qualifying instruments as cash flow hedge strategies.  Management does not hedge all foreign currency exposure.currency.
 
The following table provides the detail on designated, effective cash flow hedges included in AOCI on ourthe Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2006 to March 31,September 30, 2007.  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
ThreeNine Months Ended March 31,September 30, 2007
(in thousands)

 
Power
 
Foreign
Currency
 
Interest
Rate
 
Total
  
Power
 
Foreign
Currency
 
Interest
Rate
 
Total
 
Beginning Balance in AOCI December 31, 2006
 $5,332 $(164)$(7,715)$(2,547) $5,332 $(164) $(7,715) $(2,547)
Changes in Fair Value  (5,612) -  -  (5,612) 3,049 (2) (313) 2,734 
Reclassifications from AOCI to Net Income for
Cash Flow Hedges Settled
  (2,221) 2  347  (1,872)  (4,788)  5  1,049  (3,734)
Ending Balance in AOCI March 31, 2007
 $(2,501)$(162)$(7,368)$(10,031)
Ending Balance in AOCI September 30, 2007
 $3,593 $(161) $(6,979) $(3,547)

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $4,214$740 thousand loss.gain.

Credit Risk

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

VaR Associated with Risk Management Contracts

We useManagement uses 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 March 31,September 30, 2007, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, 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:

Three Months Ended
March 31, 2007
    
Twelve Months Ended
December 31, 2006
(in thousands)
    
(in thousands)
End
 
High
 
Average
 
Low
    
End
 
High
 
Average
 
Low
$712 $2,328 $1,037 $282    $756 $1,915 $658 $358

The High VaR for the twelve months ended December 31, 2006 occurred in the third quarter due to volatility in the ECAR/PJM region.
Nine Months Ended
September 30, 2007
  
Twelve Months Ended
December 31, 2006
 
(in thousands)
  
(in thousands)
 
End
  
High
  
Average
  
Low
  
End
  
High
  
Average
  
Low
 
$231  $2,328  $683  $168  $756  $1,915  $658  $358 

VaR Associated with Debt Outstanding

We utilizeManagement utilizes a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period.  The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $176$219 million and $153 million at March 31,September 30, 2007 and December 31, 2006, respectively. WeManagement would not expect to liquidate ourthe entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or consolidated financial position.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended March 31,September 30, 2007 and 2006
(in thousands)
(Unaudited)

 
Three Months Ended
  
Nine Months Ended
 
 
2007
 
2006
  
2007
  
2006
  
2007
  
2006
 
REVENUES
                 
Electric Generation, Transmission and Distribution $601,546 $559,993  $639,830  $588,684  $1,740,565  $1,612,735 
Sales to AEP Affiliates  61,545  71,772   64,099   57,177   181,015   177,557 
Other  2,637  2,676   2,647   2,740   8,134   7,338 
TOTAL
  665,728  634,441   706,576   648,601   1,929,714   1,797,630 
                       
EXPENSES
                       
Fuel and Other Consumables Used for Electric Generation  171,186  166,853   200,702   184,275   535,906   506,368 
Purchased Electricity for Resale  35,950  27,616   47,430   41,027   117,708   98,622 
Purchased Electricity from AEP Affiliates  127,601  122,399   171,288   130,826   443,519   356,682 
Other Operation  67,629  69,901   94,190   63,149   236,944   210,206 
Maintenance  45,753  37,839   49,708   53,874   146,875   138,381 
Depreciation and Amortization  59,160  48,268   51,864   61,270   142,100   158,226 
Taxes Other Than Income Taxes  21,275  23,092   23,561   24,464   67,811   70,355 
TOTAL
  528,554  495,968   638,743   558,885   1,690,863   1,538,840 
                       
OPERATING INCOME
  137,174  138,473   67,833   89,716   238,851   258,790 
                       
Other Income (Expense):
                       
Interest Income  639  951   510   2,463   1,539   6,228 
Carrying Costs Income  3,166  6,011 
Carrying Costs Income (Expense)  8,701   (27,316)  22,817   (13,532)
Allowance for Equity Funds Used During Construction  2,777  2,476   1,084   6,748   5,442   13,307 
Interest Expense  (31,823) (30,268)  (44,980)  (27,103)  (121,758)  (89,024)
                       
INCOME BEFORE INCOME TAXES
  111,933  117,643   33,148   44,508   146,891   175,769 
                       
Income Tax Expense  41,706  44,049   9,090   13,972   49,325   61,992 
                       
INCOME BEFORE EXTRAORDINARY LOSS
  24,058   30,536   97,566   113,777 
                
Extraordinary Loss – Reapplication of Regulatory Accounting for
Generation, Net of Tax
  -   -   (78,763)  - 
                
NET INCOME
  70,227  73,594   24,058   30,536   18,803   113,777 
                       
Preferred Stock Dividend Requirements including Capital Stock Expense
  238  238 
Preferred Stock Dividend Requirements Including Capital Stock Expense
and Other
  238   238   714   714 
                       
EARNINGS APPLICABLE TO COMMON STOCK
 $69,989 $73,356  $23,820  $30,298  $18,089  $113,063 

The common stock of APCo 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.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the ThreeNine Months Ended March 31,September 30, 2007 and 2006
(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, 2005
 $260,458 $924,837 $635,016 $(16,610)$1,803,701  $260,458  $924,837  $635,016  $(16,610) $1,803,701 
                                
Common Stock Dividends      (2,500)   (2,500)          (7,500)      (7,500)
Preferred Stock Dividends      (200)   (200)          (600)      (600)
Capital Stock Expense     38  (38)    - 
Capital Stock Expense and Other      118   (114)      4 
TOTAL
              1,801,001                   1,795,605 
                                
COMPREHENSIVE INCOME
                                    
Other Comprehensive Income, Net of Taxes:
                                
Cash Flow Hedges, Net of Tax of $7,144
        13,268 13,268 
Cash Flow Hedges, Net of Tax of $7,007
              13,014   13,014 
NET INCOME
        73,594     73,594           113,777       113,777 
TOTAL COMPREHENSIVE INCOME
              86,862                   126,791 
                                
MARCH 31, 2006
 $260,458 $924,875 $705,872 $(3,342)$1,887,863 
SEPTEMBER 30, 2006
 $260,458  $924,955  $740,579  $(3,596) $1,922,396 
                                
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      (15,000)   (15,000)          (25,000)      (25,000)
Preferred Stock Dividends      (200)   (200)          (600)      (600)
Capital Stock Expense     38  (38)    - 
Capital Stock Expense and Other      117   (114)      3 
TOTAL
              2,018,289                   2,007,892 
                                
COMPREHENSIVE INCOME
                                    
Other Comprehensive Loss, Net of Taxes:
            
Cash Flow Hedges, Net of Tax of $4,030        (7,484) (7,484)
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
        70,227     70,227           18,803       18,803 
TOTAL COMPREHENSIVE INCOME
              62,743                   29,048 
                                
MARCH 31, 2007
 $260,458 $1,025,032 $857,817 $(62,275)$2,081,032 
SEPTEMBER 30, 2007
 $260,458  $1,025,111  $795,917  $(44,546) $2,036,940 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31,September 30, 2007 and December 31, 2006
(in thousands)
(Unaudited)

 
2007
 
2006
  
2007
  
2006
 
CURRENT ASSETS
             
Cash and Cash Equivalents $1,987 $2,318  $1,269  $2,318 
Advances to Affiliates  38,573   - 
Accounts Receivable:               
Customers  199,112  180,190   200,173   180,190 
Affiliated Companies  85,919  98,237   79,576   98,237 
Accrued Unbilled Revenues  29,618  46,281   34,668   46,281 
Miscellaneous  4,849  3,400   3,366   3,400 
Allowance for Uncollectible Accounts  (4,573) (4,334)  (10,379)  (4,334)
Total Accounts Receivable  314,925  323,774   307,404   323,774 
Fuel  72,075  77,077   85,468   77,077 
Materials and Supplies  69,428  56,235   66,387   56,235 
Risk Management Assets  67,463  105,376   69,191   105,376 
Accrued Tax Benefits  9,189  3,748   8,881   3,748 
Regulatory Asset for Under-Recovered Fuel Costs  17,789  29,526   -   29,526 
Prepayments and Other  15,682  20,126   39,402   20,126 
TOTAL
  568,538  618,180   616,575   618,180 
               
PROPERTY, PLANT AND EQUIPMENT
               
Electric:               
Production  3,363,911  2,844,803   3,499,672   2,844,803 
Transmission  1,640,046  1,620,512   1,663,553   1,620,512 
Distribution  2,276,327  2,237,887   2,341,513   2,237,887 
Other  342,014  339,450   348,901   339,450 
Construction Work in Progress  512,388  957,626   678,095   957,626 
Total
  8,134,686  8,000,278   8,531,734   8,000,278 
Accumulated Depreciation and Amortization  2,470,106  2,476,290   2,578,083   2,476,290 
TOTAL - NET
  5,664,580  5,523,988   5,953,651   5,523,988 
               
OTHER NONCURRENT ASSETS
               
Regulatory Assets  612,352  622,153   680,644   622,153 
Long-term Risk Management Assets  85,987  88,906   83,210   88,906 
Deferred Charges and Other  167,913  163,089   149,137   163,089 
TOTAL
  866,252  874,148   912,991   874,148 
               
TOTAL ASSETS
 $7,099,370 $7,016,316  $7,483,217  $7,016,316 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31,September 30, 2007 and December 31, 2006
(Unaudited)

 
2007
 
2006
  
2007
  
2006
 
CURRENT LIABILITIES
 
(in thousands)
  
(in thousands)
 
Advances from Affiliates $82,860 $34,975  $-  $34,975 
Accounts Payable:               
General  286,892  296,437   218,212   296,437 
Affiliated Companies  77,642  105,525   88,326   105,525 
Long-term Debt Due Within One Year - Nonaffiliated  324,169  324,191 
Long-term Debt Due Within One Year – Nonaffiliated  399,214   324,191 
Risk Management Liabilities  57,818  81,114   52,478   81,114 
Customer Deposits  54,193  56,364   56,143   56,364 
Accrued Taxes  87,864  60,056   52,072   60,056 
Accrued Interest  55,787  30,617   62,775   30,617 
Other  119,509  142,326   109,085   142,326 
TOTAL
  1,146,734  1,131,605   1,038,305   1,131,605 
               
NONCURRENT LIABILITIES
               
Long-term Debt - Nonaffiliated  2,174,951  2,174,473 
Long-term Debt - Affiliated  100,000  100,000 
Long-term Debt – Nonaffiliated  2,547,043   2,174,473 
Long-term Debt – Affiliated  100,000   100,000 
Long-term Risk Management Liabilities  58,995  64,909   55,558   64,909 
Deferred Income Taxes  933,703  957,229   931,955   957,229 
Regulatory Liabilities and Deferred Investment Tax Credits  307,018  309,724   502,425   309,724 
Deferred Credits and Other  279,174  224,439   253,239   224,439 
TOTAL
  3,853,841  3,830,774   4,390,220   3,830,774 
               
TOTAL LIABILITIES
  5,000,575  4,962,379   5,428,525   4,962,379 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption  17,763  17,763   17,752   17,763 
               
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 
Common Stock – No Par Value:        
Authorized – 30,000,000 Shares        
Outstanding – 13,499,500 Shares  260,458   260,458 
Paid-in Capital  1,025,032  1,024,994   1,025,111   1,024,994 
Retained Earnings  857,817  805,513   795,917   805,513 
Accumulated Other Comprehensive Income (Loss)  (62,275) (54,791)  (44,546)  (54,791)
TOTAL
  2,081,032  2,036,174   2,036,940   2,036,174 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 $7,099,370 $7,016,316  $7,483,217  $7,016,316 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the ThreeNine Months Ended March 31,September 30, 2007 and 2006
(in thousands)
(Unaudited)

 
2007
 
2006
  
2007
  
2006
 
OPERATING ACTIVITIES
             
Net Income
 $70,227 $73,594  $18,803  $113,777 
Adjustments for Noncash Items:
       
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
        
Depreciation and Amortization  59,160  48,268   142,100   158,226 
Deferred Income Taxes  (3,901) (11,423)  32,021   (7,753)
Carrying Costs Income  (3,166) (6,011)
Extraordinary Loss, Net of Tax  78,763   - 
Carrying Costs (Income) Expense  (22,817)  13,532 
Mark-to-Market of Risk Management Contracts  (401) (5,696)  1,603   (3,817)
Change in Other Noncurrent Assets  (12,747) 4,020   (14,627)  1,714 
Change in Other Noncurrent Liabilities  30,172  5,848   27,247   20,171 
Changes in Certain Components of Working Capital:
               
Accounts Receivable, Net  8,849  75,278   (87)  24,423 
Fuel, Materials and Supplies  (1,034) 13,028   (11,387)  3,446 
Margin Deposits  (2,300)  27,103 
Accounts Payable  (19,891) (30,148)  (38,724)  22,063 
Customer Deposits  (2,171) (13,530)  (221)  (23,591)
Accrued Taxes, Net  29,539  56,180   (9,990)  43,071 
Accrued Interest  21,608  15,511   28,596   30,780 
Fuel Over/Under Recovery, Net  12,987  7,832   35,770   830 
Other Current Assets  3,899  (1,718)  (17,520)  4,972 
Other Current Liabilities  (17,101) (20,053)  (25,696)  1,788 
Net Cash Flows From Operating Activities
  176,029  210,980   221,534   430,735 
               
INVESTING ACTIVITIES
               
Construction Expenditures  (202,007) (196,561)  (537,930)  (633,164)
Change in Other Cash Deposits, Net  (29) -   (29)  (873)
Change in Advances to Affiliates, Net  (38,573)  (93,764)
Proceeds from Sales of Assets  1,142  1,664   6,713   8,211 
Other  (200)  - 
Net Cash Flows Used For Investing Activities
  (200,894) (194,897)  (570,019)  (719,590)
               
FINANCING ACTIVITIES
               
Issuance of Long-term Debt - Nonaffiliated  -  49,677 
Issuance of Long-term Debt – Nonaffiliated  568,778   544,364 
Change in Advances from Affiliates, Net  47,885  (29,941)  (34,975)  (194,133)
Retirement of Long-term Debt - Nonaffiliated  (3) (100,003)
Retirement of Long-term Debt – Nonaffiliated  (125,009)  (100,008)
Retirement of Cumulative Preferred Stock  (9)  (16)
Principal Payments for Capital Lease Obligations  (1,112) (1,483)  (3,316)  (4,008)
Funds From Amended Coal Contract  -  68,078   -   68,078 
Amortization of Funds From Amended Coal Contract  (7,036) -   (32,433)  (17,814)
Dividends Paid on Common Stock  (15,000) (2,500)  (25,000)  (7,500)
Dividends Paid on Cumulative Preferred Stock  (200) (200)  (600)  (600)
Net Cash Flows From (Used For) Financing Activities
  24,534  (16,372)
Net Cash Flows From Financing Activities
  347,436   288,363 
               
Net Decrease in Cash and Cash Equivalents
  (331) (289)  (1,049)  (492)
Cash and Cash Equivalents at Beginning of Period
  2,318  1,741   2,318   1,741 
Cash and Cash Equivalents at End of Period
 $1,987 $1,452  $1,269  $1,249 
        
SUPPLEMENTARY INFORMATION
        
Cash Paid for Interest, Net of Capitalized Amounts $86,199  $51,537 
Net Cash Paid for Income Taxes  6,688   12,047 
Noncash Acquisitions Under Capital Leases  2,738   2,598 
Construction Expenditures Included in Accounts Payable at September 30,  90,315   131,692 

SUPPLEMENTARY INFORMATION
       
Cash Paid for Interest, Net of Capitalized Amounts $7,084 $14,686 
Net Cash Paid for Income Taxes  7,775  1,771 
Noncash Acquisitions Under Capital Leases  444  1,184 
Construction Expenditures Included in Accounts Payable at March 31,  113,021  83,682 

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


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

In March 2007, CSPCo and AEGCo entered into a ten-year unit power agreement (UPA) for the entire output from the Lawrenceburg Plant effective with AEGCo’s purchase of the plant in May 2007.  The UPA has an option for an additional two-year period.  I&M operates the plant under an agreement with AEGCo.  Under the UPA, CSPCo pays AEGCo for the capacity, depreciation, fuel, operation, maintenance and tax expenses.  These payments are due regardless of the plant’s operating status.  Fuel, operation and maintenance payments are based on actual costs incurred.  All expenses will be trued up periodically.

Results of Operations

FirstThird Quarter of 2007 Compared to FirstThird Quarter of 2006

Reconciliation of FirstThird Quarter of 2006 to FirstThird Quarter of 2007
Net Income
(in millions)

First Quarter of 2006
    $51 
Third Quarter of 2006
    $84 
              
Changes in Gross Margin:
              
Retail Margins  27      40     
Off-system Sales  (11)     7     
Transmission Revenues  (7)   
Transmission Revenues, Net  (13)    
Other  (4)     1     
Total Change in Gross Margin
     5       35 
               
Changes in Operating Expenses and Other:
               
Other Operation and Maintenance  (10)     (27)    
Depreciation and Amortization  (4)     4     
Taxes Other Than Income Taxes  (1)     (3)    
Other Income, Net  (1)    
Interest Expense  2      (4)    
Other  1    
Total Change in Operating Expenses and Other
     (12)      (31)
               
Income Tax Expense     3       (3)
               
First Quarter of 2007
    $47 
Third Quarter of 2007
     $85 

Net Income decreased $4 millionremained relatively flat in the third quarter of 2007 compared to $47 million in 2007.the third quarter of 2006.  The key drivercomponents of the decrease was$1 million increase in Net Income were a $12$35 million increase in Gross Margin offset by a $31 million increase in Operating Expenses and Other offset by a $5 million increase in Gross Margin and a $3 million decreaseincrease in Income Tax Expense.

The major components of ourthe 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 $27$40 million primarily due to:
 ·
An $11A $35 million increase in residential and commercial revenue primarilycapacity settlements due to a 27% increaserecent plant acquisitions and changes in heating degree days.
relative peak demands of AEP Power Pool members under the Interconnection Agreement.
 ·A $10$15 million increase in industrial revenue due to the addition of Ormet, a major industrial customer effective January 1, 2007.  See “Ormet” section of Note 3.
·An $11 million increase in rate revenues related to a $4$13 million increase in ourCSPCo’s RSP offset by a $3 million decrease related to recovery of IGCC preconstruction costs.  See “Ohio Rate Matters” section of Note 3.  The decrease in rate recovery of IGCC preconstruction costs was offset by the decreased amortization of deferred expenses in Depreciation and Amortization.  CSPCo’s recovery of Phase 1 of IGCC preconstruction costs ended in July 2007.
These increases were partially offset by:
·A $28 million decrease in fuel margins.
·Margins from Off-system Sales increased $7 million primarily due to higher sales volumes and power prices in the east, benefits from AEP’s eastern natural gas fleet, and higher trading margins.
·Transmission Revenues, Net decreased $13 million primarily due to PJM’s revision of its pricing methodology for transmission line losses to marginal-loss pricing effective June 1, 2007.  See “PJM Marginal-Loss Pricing” section of Note 3.

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

·Other Operation and Maintenance expenses increased $27 million primarily due to:
·A $15 million increase due to the settlement agreement regarding alleged violations of the NSR provisions of the CAA.  The $15 million represents CSPCo’s allocation of the settlement.  See “Federal EPA Complaint and Notice of Violation” section of Note 4.
·An $8 million increase in expenses related to CSPCo’s UPA for AEGCo’s Lawrenceburg Plant which began in May 2007.
·A $7 million increase in overhead line expenses due to the 2006 recognition of a regulatory asset related to PUCO orders regarding distribution service reliability and restoration costs.
·Depreciation and Amortization decreased $4 million due to the end of amortization of IGCC preconstruction costs in 2007.  The decrease in amortization of IGCC preconstruction costs was offset by a corresponding decrease in Retail Margins.  CSPCo’s recovery of Phase 1 of IGCC preconstruction costs ended in July 2007.
·Taxes Other Than Income Taxes increased $3 million due to increases in property taxes and state excise taxes.
·Interest Expense increased $4 million partially due to a decrease in the debt component of AFUDC.
·Income Tax Expense increased $3 million primarily due to an increase in pretax book income, state income taxes and changes in certain book/tax differences accounted for on a flow-through basis.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

Reconciliation of Nine Months Ended September 30, 2006 to Nine Months Ended September 30, 2007
Net Income
(in millions)

Nine Months Ended September 30, 2006
    $168 
        
Changes in Gross Margin:
       
Retail Margins  134     
Off-system Sales  7     
Transmission Revenues, Net  (20)    
Other  (2)    
Total Change in Gross Margin
      119 
         
Changes in Operating Expenses and Other:
        
Other Operation and Maintenance  (45)    
Depreciation and Amortization  (4)    
Taxes Other Than Income Taxes  2     
Interest Expense  (1)    
Total Change in Operating Expenses and Other
      (48)
         
Income Tax Expense      (27)
         
Nine Months Ended September 30, 2007
     $212 

Net Income increased $44 million to $212 million in 2007.  The key driver of the increase was a $119 million increase in Gross Margin offset by a $48 million increase in Operating Expenses and Other and a $27 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 $134 million primarily due to:
·A $53 million increase in capacity settlements due to changes in relative peak demands of AEP Power Pool members under the Interconnection Agreement and recent plant acquisitions.
·A $46 million increase in rate revenues related to a $35 million increase in CSPCo’s RSP, an $8 million increase related to rate recovery of storm costs and a $3 million increase related to rate recovery of IGCC preconstruction costs (seecosts.  See “Ohio Rate Matters” section of Note 3).3.  The increase in rate recovery of storm costs was offset by the amortization of deferred expenses in Other Operation and Maintenance.  The increase in rate recovery of IGCC preconstruction costs was offset by the amortization of deferred expenses in Depreciation and Amortization.  CSPCo’s recovery of Phase 1 of IGCC preconstruction costs ended in July 2007.
 ·A $7$36 million increase in industrial revenue primarily due to the addition of Ormet, a major industrial customer, (seeeffective January 1, 2007.  See “Ormet” section of Note 3).3.
·A $32 million increase in residential and commercial revenue primarily due to a 30% increase in cooling degree days and a 33% increase in heating degree days.
These increases were partially offset by:
·A $50 million decrease in fuel margins.
·Margins from Off-system Sales decreased $11increased $7 million primarily due to an $8 million decrease in physical sales margins and a $4 million decrease in margins from optimization activities.higher trading margins.
·Transmission Revenues, Net decreased $7$20 million primarily due to the eliminationPJM’s revision of SECA revenues as of Aprilits pricing methodology for transmission line losses to marginal-loss pricing effective June 1, 2006.2007.  See the “Transmission Rate Proceedings at the FERC”“PJM Marginal-Loss Pricing” section of Note 3.
·Other revenues decreased $4$2 million primarily due to lower gains on sales of emission allowances.

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

·Other Operation and Maintenance expenses increased $10$45 million primarily due to:
·A $5$15 million increase in overhead line expenses, dueof which $7 million relates to the recognition in part2006 of a regulatory asset related to thePUCO orders regarding distribution service reliability and restoration costs and an $8 million increase in amortization of deferred storm expenses recovered through a cost-recovery rider.  The increase in amortization of deferred storm expenses was offset by a corresponding increase in Retail Margins.
·A $3$15 million increase due to the settlement agreement regarding alleged violations of the NSR provisions of the CAA.  The $15 million represents CSPCo’s allocation of the settlement.  See “Federal EPA Complaint and Notice of Violation” section of Note 4.
·A $12 million increase in our net allocated transmission costsexpenses related to the Transmission Equalization Agreement as a result of the addition of APCo’s Wyoming-Jacksons Ferry 765 kV line,CSPCo’s UPA for AEGCo’s Lawrenceburg Plant which was energized and placedbegan in service in June 2006.May 2007.
·
Depreciation and Amortization increased $4 million primarily due to the amortization of IGCC preconstruction costs of $3 millionbeginning in the first quarter of 2007.July 2006.  The increase in amortization of IGCC preconstruction costs was offset by a corresponding increase in Retail Margins.
  CSPCo’s recovery of Phase 1 of IGCC preconstruction costs ended in July 2007.
·InterestIncome Tax Expense decreased $2increased $27 million primarily due to an increase in allowance for borrowed funds used during construction.pretax book income.

Income Taxes

Income Tax Expense decreased $3 million primarily due to a decrease in pretax book income and state income taxes offset in part by the recording of tax adjustments.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in our 2006 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

Our risk management assets and liabilities are managed by AEPSC as agent for us. The related risk management policies and procedures are instituted and administered by AEPSC. See the complete discussion and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

VaR Associated with Debt Outstanding

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $80 million and $70 million at March 31, 2007 and December 31, 2006, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or consolidated financial position.


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
REVENUES
     
Electric Generation, Transmission and Distribution $423,466 $413,669 
Sales to AEP Affiliates  23,013  13,769 
Other  1,433  1,330 
TOTAL
  447,912  428,768 
        
EXPENSES
       
Fuel and Other Consumables Used for Electric Generation  75,862  69,820 
Purchased Electricity for Resale  31,311  24,765 
Purchased Electricity from AEP Affiliates  83,541  82,477 
Other Operation  61,159  55,945 
Maintenance  22,564  17,934 
Depreciation and Amortization  50,297  45,828 
Taxes Other Than Income Taxes  40,582  39,502 
TOTAL
  365,316  336,271 
        
OPERATING INCOME
  82,596  92,497 
        
Other Income (Expense):
       
Interest Income  422  455 
Carrying Costs Income  1,092  716 
Allowance for Equity Funds Used During Construction  772  464 
Interest Expense  (15,281) (17,520)
        
INCOME BEFORE INCOME TAXES
  69,601  76,612 
        
Income Tax Expense  22,620  25,275 
        
NET INCOME    46,981   51,337 
        
Capital Stock Expense  39  39 
       
EARNINGS APPLICABLE TO COMMON STOCK $ 46,942 $ 51,298 

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 Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
                 
DECEMBER 31, 2005
 $41,026 $580,035 $361,365 $(880)$981,546 
                 
Common Stock Dividends        (22,500)    (22,500)
Capital Stock Expense     39  (39)    - 
TOTAL
              959,046 
                 
COMPREHENSIVE INCOME
                
Other Comprehensive Income, Net of Taxes:
                
Cash Flow Hedges, Net of Tax of $2,176           4,041  4,041 
NET INCOME
        51,337     51,337 
TOTAL COMPREHENSIVE INCOME
              55,378 
                 
MARCH 31, 2006
 $41,026 $580,074 $390,163 $3,161 $1,014,424 
                 
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        (20,000)    (20,000)
Capital Stock Expense     39  (39)    - 
TOTAL
              1,032,995 
                 
COMPREHENSIVE INCOME
                
Other Comprehensive Loss, Net of Taxes:
                
Cash Flow Hedges, Net of Tax of $2,841           (5,276) (5,276)
NET INCOME
        46,981     46,981 
TOTAL COMPREHENSIVE INCOME
              41,705 
                 
MARCH 31, 2007
 $41,026 $580,231 $480,707 $(27,264)$1,074,700 

   See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2007 and December 31, 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
CURRENT ASSETS
       
Cash and Cash Equivalents $237 $1,319 
Advances to Affiliates  922  - 
Accounts Receivable:       
Customers  59,380  49,362 
Affiliated Companies  35,351  62,866 
Accrued Unbilled Revenues  8,011  11,042 
Miscellaneous  5,626  4,895 
Allowance for Uncollectible Accounts  (588) (546)
   Total Accounts Receivable  107,780  127,619 
Fuel  31,320  37,348 
Materials and Supplies  34,575  31,765 
Emission Allowances  8,971  3,493 
Risk Management Assets  36,969  66,238 
Accrued Tax Benefits  -  4,763 
Prepayments and Other  11,734  16,107 
TOTAL
  232,508  288,652 
        
PROPERTY, PLANT AND EQUIPMENT
       
Electric:       
Production  1,954,377  1,896,073 
Transmission  481,875  479,119 
Distribution  1,496,080  1,475,758 
Other  190,645  191,103 
Construction Work in Progress  269,771  294,138 
Total
  4,392,748  4,336,191 
Accumulated Depreciation and Amortization  1,629,386  1,611,043 
TOTAL - NET
  2,763,362  2,725,148 
        
OTHER NONCURRENT ASSETS
       
Regulatory Assets  277,251  298,304 
Long-term Risk Management Assets  46,978  56,206 
Deferred Charges and Other  131,818  152,379 
TOTAL
  456,047  506,889 
        
TOTAL ASSETS
 $3,451,917 $3,520,689 

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
March 31, 2007 and December 31, 2006
(Unaudited)

  
2007
 
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates $- $696 
Accounts Payable:       
General  97,767  112,431 
Affiliated Companies  51,552  59,538 
Long-term Debt Due Within One Year - Nonaffiliated  52,000  - 
Risk Management Liabilities  31,365  49,285 
Customer Deposits  37,563  34,991 
Accrued Taxes  144,223  166,551 
Accrued Interest  17,698  20,868 
Other  34,767  37,143 
TOTAL
  466,935  481,503 
        
NONCURRENT LIABILITIES
       
Long-term Debt - Nonaffiliated  1,045,422  1,097,322 
Long-term Debt - Affiliated  100,000  100,000 
Long-term Risk Management Liabilities  32,396  40,477 
Deferred Income Taxes  462,516  475,888 
Regulatory Liabilities and Deferred Investment Tax Credits  168,597  179,048 
Deferred Credits and Other  101,351  90,434 
TOTAL
  1,910,282  1,983,169 
        
TOTAL LIABILITIES
  2,377,217  2,464,672 
        
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  580,231  580,192 
Retained Earnings  480,707  456,787 
Accumulated Other Comprehensive Income (Loss)  (27,264) (21,988)
TOTAL
  1,074,700  1,056,017 
        
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY
 $3,451,917 $3,520,689 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
OPERATING ACTIVITIES
       
Net Income
 $46,981 $51,337 
Adjustments for Noncash Items:
       
Depreciation and Amortization  50,297  45,828 
Deferred Income Taxes  (716) 3,816 
Carrying Costs Income  (1,092) (716)
Mark-to-Market of Risk Management Contracts  4,400  (3,624)
Deferred Property Taxes  18,954  10,884 
Change in Other Noncurrent Assets  (912) (11,325)
Change in Other Noncurrent Liabilities  (15,510) 5,800 
Changes in Certain Components of Working Capital:
       
Accounts Receivable, Net  19,839  33,295 
Fuel, Materials and Supplies  3,218  (7,431)
Accounts Payable  (7,659) 12,540 
Customer Deposits  2,572  (7,901)
Accrued Taxes, Net  (8,651) (7,873)
Accrued Interest  (5,658) (4,127)
Other Current Assets  5,694  (728)
Other Current Liabilities  (5,056) (6,571)
Net Cash Flows From Operating Activities
  106,701  113,204 
        
INVESTING ACTIVITIES
       
Construction Expenditures  (85,641) (65,032)
Change in Other Cash Deposits, Net  (20) (1,151)
Change in Advances to Affiliates, Net  (922) (6,867)
Proceeds from Sale of Assets  189  531 
Net Cash Flows Used For Investing Activities
  (86,394) (72,519)
        
FINANCING ACTIVITIES
       
Change in Advances from Affiliates, Net  (696) (17,609)
Principal Payments for Capital Lease Obligations  (693) (759)
Dividends Paid on Common Stock  (20,000) (22,500)
Net Cash Flows Used For Financing Activities
  (21,389) (40,868)
        
Net Decrease in Cash and Cash Equivalents
  (1,082) (183)
Cash and Cash Equivalents at Beginning of Period
  1,319  940 
Cash and Cash Equivalents at End of Period
 $237 $757 

SUPPLEMENTARY INFORMATION
       
Cash Paid for Interest, Net of Capitalized Amounts $20,132 $22,320 
Net Cash Paid (Received) for Income Taxes  (2,907) 2,533 
Noncash Acquisitions Under Capital Leases  275  1,102 
Construction Expenditures Included in Accounts Payable at March 31,  20,636  12,054 

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 PronouncementsNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
Acquisitions, Dispositions and Assets Held for SaleNote 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

First Quarter of 2007 Compared to First Quarter of 2006

Reconciliation of First Quarter of 2006 to First Quarter of 2007
Net Income
(in millions)

First Quarter of 2006
    $58 
        
Changes in Gross Margin:
       
Retail Margins  (24)   
FERC Municipals and Cooperatives  9    
Off-system Sales  (4)   
Transmission Revenues  (2)   
Other  (7)   
Total Change in Gross Margin
     (28)
        
Changes in Operating Expenses and Other:
       
Other Operation and Maintenance  (6)   
Depreciation and Amortization  (7)   
Other Income  (1)   
Interest Expense  (2)   
Total Change in Operating Expenses and Other
     (16)
        
Income Tax Expense     15 
        
First Quarter of 2007
    $29 

Net Income decreased $29 million to $29 million in 2007. The key driver of the decrease was a $28 million decrease in Gross Margin.

The major components of our 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 $24 million primarily due to a reduction in capacity settlement revenues of $23 million under the Interconnection Agreement reflecting our new peak demand in July 2006.
·FERC Municipals and Cooperatives margins increased $9 million due to the addition of new municipal contracts including new rates and increased demand effective July 2006 and January 2007.
·Margins from Off-system Sales decreased $4 million primarily due to an $11 million decrease in physical sales margins partially offset by a $6 million increase in margins from optimization activities.
·Transmission Revenues decreased $2 million primarily due to the elimination of SECA revenues as of April 1, 2006. See the “Transmission Rate Proceedings at the FERC” section of Note 3.
·Other revenues decreased $7 million primarily due to decreased River Transportation Division (RTD) revenues for barging coal and decreased gains on sales of emission allowances. RTD related expenses which offset the RTD revenue decrease are included in Other Operation on the Condensed Consolidated Statements of Income resulting in our earning only a return approved under regulatory order.
Operating Expenses and Other changed between years as follows:

·Other Operation and Maintenance expenses increased $6 million primarily due to a $5 million increase in transmission expense due to our reduced credits under the Transmission Equalization Agreement. Our credits decreased due to our July 2006 peak and due to APCo’s addition of the Wyoming-Jacksons Ferry 765 kV line, which was energized and placed in service in June 2006 thus decreasing our share of the transmission investment pool.
·Depreciation and Amortization expense increased $7 million primarily due to a $5 million increase in depreciation related to capital additions and a $2 million increase in amortization related to capitalized software development costs.
·Interest Expense increased $2 million primarily due to an increase in outstanding long-term debt and higher interest rates.

Income Taxes

Income Tax Expense decreased $15 million primarily due to a decrease in pretax book income.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in our 2006 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

Our risk management assets and liabilities are managed by AEPSC as agent for us. The related risk management policies and procedures are instituted and administered by AEPSC. See the complete discussion and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

VaR Associated with Debt Outstanding

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $108 million and $93 million at March 31, 2007 and December 31, 2006, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or consolidated financial position.


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
REVENUES
     
Electric Generation, Transmission and Distribution $405,164 $403,769 
Sales to AEP Affiliates  67,429  88,534 
Other - Affiliated  12,667  15,094 
Other - Nonaffiliated  7,609  8,382 
TOTAL
  492,869  515,779 
        
EXPENSES
       
Fuel and Other Consumables Used for Electric Generation  96,117  89,452 
Purchased Electricity for Resale  17,940  11,010 
Purchased Electricity from AEP Affiliates  77,513  86,422 
Other Operation  120,733  111,617 
Maintenance  42,430  45,219 
Depreciation and Amortization  56,307  49,715 
Taxes Other Than Income Taxes  17,994  18,906 
TOTAL
  429,034  412,341 
        
OPERATING INCOME
  63,835  103,438 
        
Other Income (Expense):
       
Interest Income  588  694 
Allowance for Equity Funds Used During Construction  265  1,924 
Interest Expense  (19,821) (17,533)
        
INCOME BEFORE INCOME TAXES
  44,867  88,523 
        
Income Tax Expense  15,404  30,645 
        
NET INCOME
  29,463  57,878 
        
Preferred Stock Dividend Requirements  85  85 
        
EARNINGS APPLICABLE TO COMMON STOCK
 $29,378 $57,793 

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 Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2005
 $56,584 $861,290 $305,787 $(3,569)$1,220,092 
                 
Common Stock Dividends        (10,000)    (10,000)
Preferred Stock Dividends        (85)    (85)
TOTAL
              1,210,007 
                 
COMPREHENSIVE INCOME
                
Other Comprehensive Income, Net of Taxes:
                
Cash Flow Hedges, Net of Tax of $2,265           4,207  4,207 
NET INCOME
        57,878     57,878 
TOTAL COMPREHENSIVE INCOME
              62,085 
                 
MARCH 31, 2006
 $56,584 $861,290 $353,580 $638 $1,272,092 
                 
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        (10,000)    (10,000)
Preferred Stock Dividends        (85)    (85)
TOTAL
              1,279,681 
                 
COMPREHENSIVE INCOME
                
Other Comprehensive Loss, Net of Taxes:
                
Cash Flow Hedges, Net of Tax of $2,850           (5,293) (5,293)
NET INCOME
        29,463     29,463 
TOTAL COMPREHENSIVE INCOME
              24,170 
                 
MARCH 31, 2007
 $56,584 $861,290 $406,321 $(20,344)$1,303,851 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2007 and December 31, 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
CURRENT ASSETS
       
Cash and Cash Equivalents $753 $1,369 
Accounts Receivable:       
Customers  86,128  82,102 
Affiliated Companies  66,155  108,288 
Accrued Unbilled Revenues  806  2,206 
Miscellaneous  2,571  1,838 
Allowance for Uncollectible Accounts  (616) (601)
   Total Accounts Receivable  155,044  193,833 
Fuel  47,818  64,669 
Materials and Supplies  136,373  129,953 
Risk Management Assets  39,175  69,752 
Accrued Tax Benefits  8,680  27,378 
Prepayments and Other  13,500  15,170 
TOTAL
  401,343  502,124 
        
PROPERTY, PLANT AND EQUIPMENT
       
Electric:       
Production  3,383,343  3,363,813 
Transmission  1,052,730  1,047,264 
Distribution  1,143,815  1,102,033 
Other (including nuclear fuel and coal mining)  516,972  529,727 
Construction Work in Progress  144,856  183,893 
Total
  6,241,716  6,226,730 
Accumulated Depreciation, Depletion and Amortization  2,949,796  2,914,131 
TOTAL - NET
  3,291,920  3,312,599 
        
OTHER NONCURRENT ASSETS
       
Regulatory Assets  292,704  314,805 
Spent Nuclear Fuel and Decommissioning Trusts  1,262,960  1,248,319 
Long-term Risk Management Assets  49,470  59,137 
Deferred Charges and Other  117,384  109,453 
TOTAL
  1,722,518  1,731,714 
        
TOTAL ASSETS
 $5,415,781 $5,546,437 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2007 and December 31, 2006
(Unaudited)

  
2007
 
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates $45,759 $91,173 
Accounts Payable:       
General  99,223  146,733 
Affiliated Companies  57,940  65,497 
Long-term Debt Due Within One Year - Nonaffiliated  50,000  50,000 
Risk Management Liabilities  33,643  52,083 
Customer Deposits  31,436  34,946 
Accrued Taxes  76,087  59,652 
Other  115,714  128,461 
TOTAL
  509,802  628,545 
        
NONCURRENT LIABILITIES
       
Long-term Debt - Nonaffiliated  1,508,695  1,505,135 
Long-term Risk Management Liabilities  34,243  42,641 
Deferred Income Taxes  311,584  335,000 
Regulatory Liabilities and Deferred Investment Tax Credits  739,972  753,402 
Asset Retirement Obligations  820,371  809,853 
Deferred Credits and Other  179,181  174,340 
TOTAL
  3,594,046  3,620,371 
        
TOTAL LIABILITIES
  4,103,848  4,248,916 
        
Cumulative Preferred Stock Not Subject to Mandatory Redemption  8,082  8,082 
        
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  861,290  861,290 
Retained Earnings  406,321  386,616 
Accumulated Other Comprehensive Income (Loss)  (20,344) (15,051)
TOTAL
  1,303,851  1,289,439 
        
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 $5,415,781 $5,546,437 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
OPERATING ACTIVITIES
       
Net Income
 $29,463 $57,878 
Adjustments for Noncash Items:
       
Depreciation and Amortization  56,307  49,715 
Deferred Income Taxes  (3,638) 3,493 
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net  12,191  (1,639)
Amortization of Nuclear Fuel  16,372  13,596 
Mark-to-Market of Risk Management Contracts  4,897  (4,060)
Deferred Property Taxes  (10,836) (9,839)
Change in Other Noncurrent Assets  5,729  4,381 
Change in Other Noncurrent Liabilities  (1,971) 18,839 
Changes in Certain Components of Working Capital:
       
Accounts Receivable, Net  38,789  43,019 
Fuel, Materials and Supplies  14,985  (7,194)
Accounts Payable  (38,233) (7,010)
Customer Deposits  (3,510) (8,031)
Accrued Taxes, Net  39,525  42,871 
Accrued Rent - Rockport Plant Unit 2  18,464  18,464 
Other Current Assets  1,959  428 
Other Current Liabilities  (35,720) (20,797)
Net Cash Flows From Operating Activities
  144,773  194,114 
        
INVESTING ACTIVITIES
       
Construction Expenditures  (62,252) (89,411)
Purchases of Investment Securities  (204,874) (150,239)
Sales of Investment Securities  183,927  134,258 
Acquisitions of Nuclear Fuel  (5,366) (34,427)
Proceeds from Sales of Assets and Other  248  1,384 
Net Cash Flows Used For Investing Activities
  (88,317) (138,435)
        
FINANCING ACTIVITIES
       
Change in Advances from Affiliates, Net  (45,414) (44,565)
Principal Payments for Capital Lease Obligations  (1,573) (1,274)
Dividends Paid on Common Stock  (10,000) (10,000)
Dividends Paid on Cumulative Preferred Stock  (85) (85)
Net Cash Flows Used For Financing Activities
  (57,072) (55,924)
        
Net Decrease in Cash and Cash Equivalents
  (616) (245)
Cash and Cash Equivalents at Beginning of Period
  1,369  854 
Cash and Cash Equivalents at End of Period
 $753 $609 

SUPPLEMENTARY INFORMATION
       
Cash Paid for Interest, Net of Capitalized Amounts $15,048 $4,776 
Net Cash Paid (Received) for Income Taxes  (2,768) 1,324 
Noncash Acquisitions Under Capital Leases  369  2,218 
Construction Expenditures Included in Accounts Payable at March 31,  20,243  27,624 

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 PronouncementsNote 2
Rate MattersNote 3
Commitments, Guarantees and ContingenciesNote 4
Benefit PlansNote 6
Business SegmentsNote 7
Income TaxesNote 8
Financing ActivitiesNote 9














KENTUCKY POWER COMPANY







KENTUCKY POWER COMPANY
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations

First Quarter of 2007 Compared to First Quarter of 2006

Reconciliation of First Quarter of 2006 to First Quarter of 2007
Net Income
(in millions)

First Quarter of 2006
    $10 
        
Changes in Gross Margin:
       
Retail Margins  17    
Off-system Sales  (2)   
Transmission Revenues  (3)   
Other  (1)   
Total Change in Gross Margin
     11 
        
Other Operation and Maintenance     (3)
        
Income Tax Expense     (3)
        
First Quarter of 2007
    $15 

Net Income increased $5 million to $15 million in 2007. The key driver of the increase was an $11 million increase in Gross Margin, offset by an increase in Other Operation and Maintenance expenses of $3 million and an increase in Income Tax Expense of $3 million.

The major components of our 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 $17 million primarily due to rate relief of $14 million from the March 2006 approval of the settlement agreement in our base rate case.
·Transmission Revenues decreased $3 million primarily due to the elimination of SECA revenues as of April 1, 2006. See the “Transmission Rate Proceedings at the FERC” section of Note 3.

Other Operation and Maintenance

Other Operation and Maintenance expenses increased $3 million primarily due to an increase in our net allocated transmission costs related to the Transmission Equalization Agreement as a result of the addition of APCo’s Wyoming-Jacksons Ferry 765 kV line which was energized and placed into service in June 2006. Other Operation and Maintenance expenses also increased as a result of increased forced outages at the Big Sandy Plant.

Income Taxes

Income Tax Expense increased $3 million primarily due to an increase in pretax book income.
Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in our 2006 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

Our risk management assets and liabilities are managed by AEPSC as agent for us. The related risk management policies and procedures are instituted and administered by AEPSC. See the complete discussion and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

VaR Associated with Debt Outstanding

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $19 million and $13 million at March 31, 2007 and December 31, 2006, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or financial position.



KENTUCKY POWER COMPANY
CONDENSED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
REVENUES
     
Electric Generation, Transmission and Distribution $140,486 $137,620 
Sales to AEP Affiliates  13,461  13,968 
Other  149  259 
TOTAL
  154,096  151,847 
        
EXPENSES
       
Fuel and Other Consumables Used for Electric Generation  38,304  43,966 
Purchased Electricity for Resale  3,305  973 
Purchased Electricity from AEP Affiliates  43,257  49,526 
Other Operation  15,886  13,726 
Maintenance  8,210  7,141 
Depreciation and Amortization  11,796  11,479 
Taxes Other Than Income Taxes  2,803  2,512 
TOTAL
  123,561  129,323 
        
OPERATING INCOME
  30,535  22,524 
        
Other Income (Expense):
       
Interest Income  112  166 
Allowance for Equity Funds Used During Construction  14  101 
Interest Expense  (7,011) (7,296)
        
INCOME BEFORE INCOME TAXES
  23,650  15,495 
        
Income Tax Expense  8,439  5,665 
        
NET INCOME
 $15,211 $9,830 

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


KENTUCKY POWER COMPANY
CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
Common
Stock
 
Paid-in
Capital 
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2005
 $50,450 $208,750 $88,864 $(223)$347,841 
                 
Common Stock Dividends        (2,500)    (2,500)
TOTAL
              345,341 
                 
COMPREHENSIVE INCOME
                
Other Comprehensive Income, Net of Taxes:
                
Cash Flow Hedges, Net of Tax of $873           1,621  1,621 
NET INCOME
        9,830     9,830 
TOTAL COMPREHENSIVE INCOME
              11,451 
                 
MARCH 31, 2006
 $50,450 $208,750 $96,194 $1,398 $356,792 
                 
DECEMBER 31, 2006
 $50,450 $208,750 $108,899 $1,552 $369,651 
                 
FIN 48 Adoption, Net of Tax        (786)    (786)
Common Stock Dividends        (5,000)    (5,000)
TOTAL
              363,865 
                 
COMPREHENSIVE INCOME
                
Other Comprehensive Loss, Net of Taxes:
                
Cash Flow Hedges, Net of Tax of $1,100           (2,042) (2,042)
NET INCOME
        15,211     15,211 
TOTAL COMPREHENSIVE INCOME
              13,169 
                 
MARCH 31, 2007
 $50,450 $208,750 $118,324 $(490)$377,034 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


KENTUCKY POWER COMPANY
CONDENSED BALANCE SHEETS
ASSETS
March 31, 2007 and December 31, 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
CURRENT ASSETS
       
Cash and Cash Equivalents $775 $702 
Accounts Receivable:       
Customers  30,027  30,112 
Affiliated Companies  9,142  10,540 
Accrued Unbilled Revenues  6,093  3,602 
Miscellaneous  684  327 
Allowance for Uncollectible Accounts  (242) (227)
   Total Accounts Receivable  45,704  44,354 
Fuel  12,852  16,070 
Materials and Supplies  10,277  8,726 
Risk Management Assets  16,110  25,624 
Accrued Tax Benefits  -  1,021 
Margin Deposits  1,458  2,923 
Prepayments and Other  2,637  2,425 
TOTAL
  89,813  101,845 
        
PROPERTY, PLANT AND EQUIPMENT
       
Electric:       
Production  480,501  478,955 
Transmission  395,646  394,419 
Distribution  480,690  481,083 
Other  60,047  61,089 
Construction Work in Progress  27,705  29,587 
Total
  1,444,589  1,445,133 
Accumulated Depreciation and Amortization  441,565  442,778 
TOTAL - NET
  1,003,024  1,002,355 
        
OTHER NONCURRENT ASSETS
       
Regulatory Assets  135,241  136,139 
Long-term Risk Management Assets  19,313  21,282 
Deferred Charges and Other  46,953  48,944 
TOTAL
  201,507  206,365 
        
TOTAL ASSETS
 $1,294,344 $1,310,565 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


KENTUCKY POWER COMPANY
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY
March 31, 2007 and December 31, 2006
(Unaudited)

  
2007
 
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates $20,769 $30,636 
Accounts Payable:       
General  33,876  31,490 
Affiliated Companies  17,615  23,658 
Long-term Debt Due Within One Year - Nonaffiliated  322,554  322,048 
Risk Management Liabilities  14,167  20,001 
Customer Deposits  15,273  16,095 
Accrued Taxes  18,933  18,775 
Other  22,759  26,303 
TOTAL
  465,946  489,006 
        
NONCURRENT LIABILITIES
       
Long-term Debt - Nonaffiliated  104,944  104,920 
Long-term Debt - Affiliated  20,000  20,000 
Long-term Risk Management Liabilities  13,464  15,426 
Deferred Income Taxes  239,776  242,133 
Regulatory Liabilities and Deferred Investment Tax Credits  47,426  49,109 
Deferred Credits and Other  25,754  20,320 
TOTAL
  451,364  451,908 
        
TOTAL LIABILITIES
  917,310  940,914 
        
Commitments and Contingencies (Note 4)       
        
COMMON SHAREHOLDER’S EQUITY
       
Common Stock - $50 Par Value Per Share:       
Authorized - 2,000,000 Shares       
Outstanding - 1,009,000 Shares  50,450  50,450 
Paid-in Capital  208,750  208,750 
Retained Earnings  118,324  108,899 
Accumulated Other Comprehensive Income (Loss)  (490) 1,552 
TOTAL
  377,034  369,651 
        
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY
 $1,294,344 $1,310,565 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


KENTUCKY POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
OPERATING ACTIVITIES
       
Net Income
 $15,211 $9,830 
Adjustments for Noncash Items:
       
Depreciation and Amortization  11,796  11,479 
Deferred Income Taxes  956  2,217 
Mark-to-Market of Risk Management Contracts  1,092  (1,378)
Change in Other Noncurrent Assets  980  2,518 
Change in Other Noncurrent Liabilities  (78) 1,845 
Changes in Certain Components of Working Capital:
       
Accounts Receivable, Net  (1,350) 16,149 
Fuel, Materials and Supplies  3,609  (2,808)
Accounts Payable  (2,557) (6,212)
Customer Deposits  (822) (3,127)
Accrued Taxes, Net  1,447  2,676 
Other Current Assets  1,012  2,069 
Other Current Liabilities  (3,348) (1,480)
Net Cash Flows From Operating Activities
  27,948  33,778 
        
INVESTING ACTIVITIES
       
Construction Expenditures  (13,001) (19,376)
Change in Advances to Affiliates, Net  -  (5,923)
Proceeds from Sale of Assets  231  301 
Net Cash Flows Used For Investing Activities
  (12,770) (24,998)
        
FINANCING ACTIVITIES
       
Change in Advances from Affiliates, Net  (9,867) (6,040)
Principal Payments for Capital Lease Obligations  (238) (343)
Dividends Paid on Common Stock  (5,000) (2,500)
Net Cash Flows Used For Financing Activities
  (15,105) (8,883)
        
Net Increase (Decrease) in Cash and Cash Equivalents
  73  (103)
Cash and Cash Equivalents at Beginning of Period
  702  526 
Cash and Cash Equivalents at End of Period
 $775 $423 

SUPPLEMENTARY INFORMATION
       
Cash Paid for Interest, Net of Capitalized Amounts $5,371 $4,156 
Net Cash Paid for Income Taxes  738  214 
Noncash Acquisitions Under Capital Leases  139  224 
Construction Expenditures Included in Accounts Payable at March 31,  2,257  3,079 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to KPCo’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 KPCo.

Footnote Reference
Significant Accounting MattersNote 1
New Accounting PronouncementsNote 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

First Quarter of 2007 Compared to First Quarter of 2006

Reconciliation of First Quarter of 2006 to First Quarter of 2007
Net Income
(in millions)

First Quarter of 2006
    $95 
        
Changes in Gross Margin:
       
Retail Margins  59    
Off-system Sales  (22)   
Transmission Revenues  (9)   
Other  (10)   
Total Change in Gross Margin
     18 
        
Changes in Operating Expenses and Other:
       
Other Operation and Maintenance  (28)   
Depreciation and Amortization  (5)   
Taxes Other Than Income Taxes  (1)   
Interest Expense  (3)   
Total Change in Operating Expenses and Other
     (37)
        
Income Tax Expense     3 
        
First Quarter of 2007
    $79 

Net Income decreased $16 million to $79 million in 2007. The key driver of the decrease was a $37 million increase in Operating Expenses and Other offset by an $18 million increase in Gross Margin.

The major components of our 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 $59 million primarily due to the following:
·A $25 million increase in capacity settlements under the Interconnection Agreement related to certain of our affiliates’ peaks and the expiration of our supplemental capacity and energy obligation to Buckeye Power, Inc. under the Cardinal Station Agreement.
·
A $14 million increase in rate revenues related to an $8 million increase in our RSP, a $3 million increase related to rate recovery of storm costs and a $3 million increase related to rate recovery of IGCC preconstruction costs (see “Ohio Rate Matters” section of Note 3). The increase in rate recovery of storm costs was offset by the amortization of deferred expenses in Other Operation and Maintenance. The increase in rate recovery of IGCC preconstruction costs was offset by the amortization of deferred expenses in Depreciation and Amortization.
·A $9 million increase in fuel margins.
·A $7 million increase in industrial revenue due to the addition of Ormet, a major industrial customer (see “Ormet” section of Note 3).
·A $6 million increase in residential revenue primarily due to a 25% increase in heating degree days.
These increases were partially offset by:
·
A $9 million decrease in revenues associated with SO2 allowances received in 2006 from Buckeye Power, Inc. under the Cardinal Station Allowances Agreement.
·Margins from Off-system Sales decreased $22 million due to a $19 million decrease in physical sales margins and a $4 million decrease in margins from optimization activities.
·Transmission Revenues decreased $9 million primarily due to the elimination of SECA revenues as of April 1, 2006 (see the “Transmission Rate Proceedings at the FERC” section of Note 3).
·Other revenues decreased $10 million primarily due to a $4 million decrease related to the expiration of an obligation to sell supplemental capacity and energy to Buckeye Power, Inc. under the Cardinal Station Agreement, a $3 million decrease in gains on sales of emission allowances and a $2 million decrease in revenue associated with Cook Coal Terminal.

Operating Expenses and Other changed between years as follows:

·Other Operation and Maintenance expenses increased $28 million primarily due to a $19 million increase in maintenance and removal costs related to planned and forced outages at the Gavin, Muskingum, Mitchell and Cardinal plants and a $5 million increase due to the prior period adjustment of liabilities related to sold coal companies.
·
Depreciation and Amortization increased $5 million primarily due to the amortization of IGCC preconstruction costs of $3 million in the first quarter of 2007 and a $1 million increase in depreciation related to environmental improvements placed in service at the Mitchell plant. The increase in amortization of IGCC preconstruction costs was offset by a corresponding increase in Retail Margins.
·Interest Expense increased $3 million primarily due to a $5 million increase related to long-term debt issuances since June 2006 and a $3 million increase related to higher borrowings from the Utility Money Pool partially offset by a $6 million increase in allowance for borrowed funds used during construction.

Income Taxes

Income Tax Expense decreased $3 million primarily due to a decrease in pretax book income offset in part by state income taxes.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

Moody’s
S&P
Fitch
Senior Unsecured DebtA3BBBBBB+

Cash Flow

Cash flows for the three months ended March 31, 2007 and 2006 were as follows:

  
2007
 
2006
 
  
(in thousands)
 
Cash and Cash Equivalents at Beginning of Period
 $1,625 $1,240 
Cash Flows From (Used For):       
Operating Activities  96,864  182,002 
Investing Activities  (306,826) (221,862)
Financing Activities  209,598  39,577 
Net Decrease in Cash and Cash Equivalents  (364) (283)
Cash and Cash Equivalents at End of Period
 $1,261 $957 

Operating Activities

Net Cash Flows From Operating Activities were $97 million in 2007. We produced Net Income of $79 million during the period and a noncash expense item of $84 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items. Accounts Receivable, Net had a $38 million outflow due to temporary timing differences of rent receivables and an increase in billed revenue for electric customers. Accounts Payable had a $26 million outflow primarily due to emission allowance payments in January 2007. Fuel, Materials and Supplies had a $24 million outflow primarily due to an increase in coal inventories.
Our Net Cash Flows From Operating Activities were $182 million in 2006. We produced income of $95 million during the period and a noncash expense item of $79 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital primarily relates to two items. Accounts Receivable, Net had a $102 million inflow due to receivables collected from our affiliates related to power sales, settled litigation and emission allowances. Accounts Payable had a $60 million outflow due to emission allowance payments in January 2006 and temporary timing differences for payments to affiliates.

Investing Activities

Our Net Cash Used For Investing Activities were $307 million and $222 million in 2007 and 2006, respectively. Construction Expenditures were $302 million and $223 million in 2007 and 2006, 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 2007, we expect construction expenditures to be approximately $530 million.

Financing Activities

Net Cash Flows From Financing Activities were $210 million in 2007 primarily due to a net increase of $216 million in borrowings from the Utility Money Pool.

Net Cash Flows From Financing Activities were $40 million in 2006 primarily due to a $35 million capital contribution from AEP.

Financing Activity

Long-term debt issuances and retirements during the first three months of 2007 were:

Issuances

None

Retirements
  
Principal
Amount Paid
 
Interest
 
Due
Type of Debt
  
Rate
 
Date
   
(in thousands)
 
(%)
  
Notes Payable - Nonaffiliated $1,463 6.81 2008
Notes Payable - Nonaffiliated  6,000 6.27 2009

In April 2007, we issued $400 million of three-year floating rate notes at an initial rate of 5.53% due in 2010. The proceeds from this issuance will contribute to our investment in environmental equipment.

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt, refinance short-term debt or refinance long-term debt maturities. In addition, we participate in the Utility Money Pool, which provides access to AEP’s liquidity.

Summary Obligation Information

A summary of our contractual obligations is included in our 2006 Annual Report and has not changed significantly from year-end other than the debt issuance discussed in “Financing Activity” above.
Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual 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 our pending litigation and regulatory proceedings, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies in our 2006 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 our results of operations, financial condition and cash flows.

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

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2006 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

Our riskRisk management assets and liabilities are managed by AEPSC as agentagent.  The related risk management policies and procedures are instituted and administered by AEPSC.  See the complete discussion and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for us.disclosures about risk management activities.

VaR Associated with Debt Outstanding

Management utilizes a VaR model to measure interest rate market risk exposure.  The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period.  The risk of potential loss in fair value attributable to exposure to interest rates primarily related to long-term debt with fixed interest rates was $79 million and $70 million at September 30, 2007 and December 31, 2006, respectively.  Management would not expect to liquidate the entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect results of operations or consolidated financial position.
 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2007 and 2006
(in thousands)
(Unaudited)

  
Three Months Ended
  
Nine Months Ended
 
  
2007
  
2006
  
2007
  
2006
 
REVENUES
            
Electric Generation, Transmission and Distribution $553,518  $513,643  $1,446,632  $1,321,422 
Sales to AEP Affiliates  52,331   24,806   110,700   60,337 
Other  1,292   1,449   3,743   4,016 
TOTAL
  607,141   539,898   1,561,075   1,385,775 
                 
EXPENSES
                
Fuel and Other Consumables Used for Electric Generation  103,560   90,510   255,764   231,543 
Purchased Electricity for Resale  49,619   35,449   113,765   87,902 
Purchased Electricity from AEP Affiliates  107,386   102,669   278,715   272,334 
Other Operation  83,625   66,188   207,300   179,993 
Maintenance  24,250   14,704   73,537   56,140 
Depreciation and Amortization  47,589   51,156   147,332   143,524 
Taxes Other Than Income Taxes  41,382   38,586   117,760   119,875 
TOTAL
  457,411   399,262   1,194,173   1,091,311 
                 
OPERATING INCOME
  149,730   140,636   366,902   294,464 
                 
Other Income (Expense):
                
Interest Income  166   989   782   1,919 
Carrying Costs Income  1,261   1,046   3,492   3,082 
Allowance for Equity Funds Used During Construction  738   659   2,130   1,466 
Interest Expense  (19,530)  (15,813)  (51,193)  (50,247)
                 
INCOME BEFORE INCOME TAXES
  132,365   127,517   322,113   250,684 
                 
Income Tax Expense  46,911   43,496   109,656   83,064 
                 
NET INCOME
  85,454   84,021   212,457   167,620 
                 
Capital Stock Expense  39   39   118   118 
                 
EARNINGS APPLICABLE TO COMMON  STOCK
 $85,415  $83,982  $212,339  $167,502 

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, 2007 and 2006
(in thousands)
(Unaudited)

  
Common Stock
  
Paid-in Capital
  
Retained Earnings
  
Accumulated Other Comprehensive Income (Loss)
  
Total
 
DECEMBER 31, 2005
 $41,026  $580,035  $361,365  $(880) $981,546 
                     
Common Stock Dividends          (67,500)      (67,500)
Capital Stock Expense      118   (118)      - 
TOTAL
                  914,046 
                     
COMPREHENSIVE INCOME
                    
Other Comprehensive Income, Net of Taxes:
                    
Cash Flow Hedges, Net of Tax of $2,121              3,940   3,940 
NET INCOME
          167,620       167,620 
TOTAL COMPREHENSIVE INCOME
                  171,560 
                     
SEPTEMBER 30, 2006
 $41,026  $580,153  $461,367  $3,060  $1,085,606 
                     
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 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2007 and December 31, 2006
(in thousands)
(Unaudited)

  
2007
  
2006
 
CURRENT ASSETS
      
Cash and Cash Equivalents $1,695  $1,319 
Other Cash Deposits  45,511   1,151 
Accounts Receivable:        
  Customers  53,919   49,362 
  Affiliated Companies  36,934   62,866 
  Accrued Unbilled Revenues  33,756   11,042 
  Miscellaneous  7,792   4,895 
  Allowance for Uncollectible Accounts  (842)  (546)
Total Accounts Receivable  131,559   127,619 
Fuel  42,518   37,348 
Materials and Supplies  36,784   31,765 
Emission Allowances  3,103   3,493 
Risk Management Assets  38,776   66,238 
Prepayments and Other  15,305   19,719 
TOTAL
  315,251   288,652 
         
PROPERTY, PLANT AND EQUIPMENT
        
Electric:        
  Production  2,055,590   1,896,073 
  Transmission  498,180   479,119 
  Distribution  1,538,056   1,475,758 
Other  204,395   191,103 
Construction Work in Progress  360,560   294,138 
Total
  4,656,781   4,336,191 
Accumulated Depreciation and Amortization  1,672,118   1,611,043 
TOTAL - NET
  2,984,663   2,725,148 
         
OTHER NONCURRENT ASSETS
        
Regulatory Assets  263,054   298,304 
Long-term Risk Management Assets  47,634   56,206 
Deferred Charges and Other  95,464   152,379 
TOTAL
  406,152   506,889 
         
TOTAL ASSETS
 $3,706,066  $3,520,689 

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, 2007 and December 31, 2006
(Unaudited)

  
2007
  
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates $123,043  $696 
Accounts Payable:        
General  104,217   112,431 
Affiliated Companies  44,320   59,538 
Long-term Debt Due Within One Year - Nonaffiliated  112,000   - 
Risk Management Liabilities  29,305   49,285 
Customer Deposits  41,467   34,991 
Accrued Taxes  109,477   166,551 
Other  74,852   58,011 
TOTAL
  638,681   481,503 
         
NONCURRENT LIABILITIES
        
Long-term Debt – Nonaffiliated  1,030,123   1,097,322 
Long-term Debt – Affiliated  100,000   100,000 
Long-term Risk Management Liabilities  31,907   40,477 
Deferred Income Taxes  451,456   475,888 
Regulatory Liabilities and Deferred Investment Tax Credits  171,431   179,048 
Deferred Credits and Other  109,301   90,434 
TOTAL
  1,894,218   1,983,169 
         
TOTAL LIABILITIES
  2,532,899   2,464,672 
         
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  580,310   580,192 
Retained Earnings  576,104   456,787 
Accumulated Other Comprehensive Income (Loss)  (24,273)  (21,988)
TOTAL
  1,173,167   1,056,017 
         
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY
 $3,706,066  $3,520,689 

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, 2007 and 2006
(in thousands)
(Unaudited)


  
2007
  
2006
 
OPERATING ACTIVITIES
      
Net Income
 $212,457  $167,620 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
        
Depreciation and Amortization  147,332   143,524 
Deferred Income Taxes  (13,959)  (5,097)
Carrying Costs Income  (3,492)  (3,082)
Mark-to-Market of Risk Management Contracts  3,982   (4,502)
Deferred Property Taxes  57,890   49,518 
Change in Other Noncurrent Assets  (31,329)  (24,692)
Change in Other Noncurrent Liabilities  2,713   11,752 
Changes in Certain Components of Working Capital:
        
Accounts Receivable, Net  (13,040)  (3,374)
Fuel, Materials and Supplies  (2,332)  (8,200)
Accounts Payable  (13,336)  31,765 
Customer Deposits  6,476   (14,565)
Accrued Taxes, Net  (44,295)  (8,981)
Other Current Assets  (415)  26,838 
Other Current Liabilities  8,817   (2,878)
Net Cash Flows From Operating Activities
  317,469   355,646 
         
INVESTING ACTIVITIES
        
Construction Expenditures  (246,130)  (207,875)
Change in Other Cash Deposits, Net  (44,360)  (1,151)
Change in Advances to Affiliates, Net  -   (60,417)
Acquisition of Darby Plant  (102,032)  - 
Proceeds from Sales of Assets  1,016   1,525 
Net Cash Flows Used For Investing Activities
  (391,506)  (267,918)
         
FINANCING ACTIVITIES
        
Issuance of Long-term Debt – Nonaffiliated  44,257   - 
Change in Advances from Affiliates, Net  122,347   (17,609)
Principal Payments for Capital Lease Obligations  (2,191)  (2,308)
Dividends Paid on Common Stock  (90,000)  (67,500)
Net Cash Flows From (Used For) Financing Activities
  74,413   (87,417)
         
Net Increase in Cash and Cash Equivalents
  376   311 
Cash and Cash Equivalents at Beginning of Period
  1,319   940 
Cash and Cash Equivalents at End of Period
 $1,695  $1,251 
         
SUPPLEMENTARY INFORMATION
        
Cash Paid for Interest, Net of Capitalized Amounts $53,464  $52,958 
Net Cash Paid for Income Taxes  93,709   35,561 
Noncash Acquisitions Under Capital Leases  1,900   2,130 
Construction Expenditures Included in Accounts Payable at September 30,  34,630   22,955 
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 2007 Compared to Third Quarter of 2006

Reconciliation of Third Quarter of 2006 to Third Quarter of 2007
Net Income
(in millions)

Third Quarter of 2006
    $35 
        
Changes in Gross Margin:
       
Retail Margins  7     
FERC Municipals and Cooperatives  14     
Off-system Sales  7     
Transmission Revenues, Net  (11)    
Total Change in Gross Margin
      17 
         
Changes in Operating Expenses and Other:
        
Other Operation and Maintenance  (11)    
Depreciation and Amortization  18     
Taxes Other Than Income Taxes  (1)    
Other Income  (2)    
Interest Expense  (1)    
Total Change in Operating Expenses and Other
      3 
         
Income Tax Expense      (6)
         
Third Quarter of 2007
     $49 

Net Income increased $14 million to $49 million in 2007.  The key drivers of the increase were a $17 million increase in Gross Margin and a $3 million decrease in Operating Expenses and Other partially offset by a $6 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 $7 million primarily due to higher fuel margins of $9 million due to reactivation of the fuel clause and higher retail sales of $5 million reflecting favorable weather conditions as cooling degree days increased for both the Indiana and Michigan jurisdictions.  Lower revenues from financial transmission rights, net of congestion, due to fewer constraints in the PJM market partially offset the increases.
·FERC Municipals and Cooperatives margins increased $14 million due to the addition of new municipal contracts effective January 2007 including new rates and increased customer demand.
·Margins from Off-system Sales increased $7 million primarily due to higher sales volumes and power prices in the east, benefits from AEP’s eastern natural gas fleet, and higher trading margins.
·Transmission Revenues, Net decreased $11 million primarily due to PJM’s revision of its pricing methodology for transmission line losses to marginal-loss pricing effective June 1, 2007.  See “PJM Marginal-Loss Pricing” section of Note 3.

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

·Other Operation and Maintenance expenses increased $11 million primarily due to a settlement agreement regarding alleged violations of the NSR provisions of the CAA, of which $14 million was allocated to I&M.  See “Federal EPA Complaint and Notice of Violation” section of Note 4.
·Depreciation and Amortization expense decreased $18 million primarily due to a settlement agreement approved by the IURC reducing depreciation rates to reflect longer estimated lives for Cook and Tanners Creek plants.  See “Indiana Depreciation Study Filing” section of Note 3.
·Income Tax Expense increased $6 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 state income taxes.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

Reconciliation of Nine Months Ended September 30, 2006 to Nine Months Ended September 30, 2007
Net Income
(in millions)

Nine Months Ended September 30, 2006
    $121 
        
Changes in Gross Margin:
       
Retail Margins  (20)    
FERC Municipals and Cooperatives  40     
Off-system Sales  9     
Transmission Revenues, Net  (12)    
Other  (4)    
Total Change in Gross Margin
      13 
         
Changes in Operating Expenses and Other:
        
Other Operation and Maintenance  (31)    
Depreciation and Amortization  8     
Other Income  (4)    
Interest Expense  (5)    
Total Change in Operating Expenses and Other
      (32)
         
Income Tax Expense      7 
         
Nine Months Ended September 30, 2007
     $109 

Net Income decreased $12 million to $109 million in 2007.  The key driver of the decrease was a $32 million increase in Operating Expenses and Other partially offset by a $13 million increase in Gross Margin and a $7 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 $20 million primarily due to a $37 million reduction in capacity settlement revenues under the Interconnection Agreement reflecting I&M’s new peak demand in July 2006 and lower revenues from financial transmission rights, net of congestion, of $21 million due to fewer constraints in the PJM market.  Higher retail sales of $32 million reflecting favorable weather conditions partially offset the decreases.  Heating and cooling degree days increased significantly in both the Indiana and Michigan jurisdictions.
·FERC Municipals and Cooperatives margins increased $40 million due to the addition of new municipal contracts including new rates and increased demand effective July 2006 and January 2007.
·Margins from Off-system Sales increased $9 million primarily due to higher trading margins.
·Transmission Revenues, Net decreased $12 million primarily due to PJM’s revision of its pricing methodology for transmission line losses to marginal-loss pricing effective June 1, 2007.  See “PJM Marginal-Loss Pricing” section of Note 3.

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

·Other Operation and Maintenance expenses increased $31 million primarily due to the settlement agreement regarding alleged violations of the NSR provisions of the CAA, of which $14 million was allocated to I&M, a $13 million increase in coal-fired plant maintenance expenses resulting from planned outages at Rockport and Tanners Creek plants and an $8 million increase in transmission expense primarily due to reduced credits under the Transmission Equalization Agreement.  Credits decreased due to I&M’s July 2006 peak and due to APCo’s addition of the Wyoming-Jacksons Ferry 765 kV line, which was energized and placed in service in June 2006 thus decreasing I&M’s share of the transmission investment pool.
·Depreciation and Amortization expense decreased $8 million primarily due to a $14 million decrease in depreciation related to the revised depreciation rates in Indiana partially offset by an increase in amortization related to capitalized software development costs.
·Interest Expense increased $5 million primarily due to an increase in outstanding long-term debt.
·Income Tax Expense decreased $7 million primarily due to a decrease in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis, partially offset by a decrease in amortization of investment tax credits.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2006 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 the complete discussion and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

VaR Associated with Debt Outstanding

Management utilizes a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period.  The risk of potential loss in fair value attributable to exposure to interest rates primarily related to long-term debt with fixed interest rates was $109 million and $93 million at September 30, 2007 and December 31, 2006, respectively. Management would not expect to liquidate the entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect results of operations or consolidated financial position.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2007 and 2006
(in thousands)
(Unaudited)

  
Three Months Ended
  
Nine Months Ended
 
  
2007
  
2006
  
2007
  
2006
 
REVENUES
            
Electric Generation, Transmission and Distribution $478,907  $449,259  $1,286,223  $1,224,609 
Sales to AEP Affiliates  56,262   54,793   186,653   223,728 
Other – Affiliated  16,250   12,903   43,488   37,838 
Other – Nonaffiliated  7,757   8,580   21,718   24,593 
TOTAL
  559,176   525,535   1,538,082   1,510,768 
                 
EXPENSES
                
Fuel and Other Consumables Used for Electric Generation  103,740   98,135   290,507   283,734 
Purchased Electricity for Resale  26,580   20,450   63,830   46,993 
Purchased Electricity from AEP Affiliates  96,451   92,052   249,755   259,304 
Other Operation  129,439   119,661   367,483   340,666 
Maintenance  58,502   56,960   146,657   142,531 
Depreciation and Amortization  35,604   53,404   145,801   153,897 
Taxes Other Than Income Taxes  19,704   18,472   56,936   56,343 
TOTAL
  470,020   459,134   1,320,969   1,283,468 
                 
OPERATING INCOME
  89,156   66,401   217,113   227,300 
                 
Other Income (Expense):
                
Interest Income  252   1,102   1,547   2,459 
Allowance for Equity Funds Used During Construction  1,734   2,517   2,726   5,881 
Interest Expense  (18,312)  (17,228)  (57,744)  (52,663)
                 
INCOME BEFORE INCOME TAXES
  72,830   52,792   163,642   182,977 
                 
Income Tax Expense  23,706   18,231   55,020   62,013 
                 
NET INCOME
  49,124   34,561   108,622   120,964 
                 
Preferred Stock Dividend Requirements  85   85   255   255 
                 
EARNINGS APPLICABLE TO COMMON STOCK
 $49,039  $34,476  $108,367  $120,709 

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, 2007 and 2006
(in thousands)
(Unaudited)

  
Common Stock
  
Paid-in Capital
  
Retained Earnings
  
Accumulated Other Comprehensive Income (Loss)
  
Total
 
DECEMBER 31, 2005
 $56,584  $861,290  $305,787  $(3,569) $1,220,092 
                     
Common Stock Dividends          (30,000)      (30,000)
Preferred Stock Dividends          (255)      (255)
TOTAL
                  1,189,837 
                     
COMPREHENSIVE INCOME
                    
Other Comprehensive Loss, Net of Taxes:
                    
Cash Flow Hedges, Net of Tax of $2,712              (5,036)  (5,036)
NET INCOME
          120,964       120,964 
TOTAL COMPREHENSIVE INCOME
                  115,928 
                     
SEPTEMBER 30, 2006
 $56,584  $861,290  $396,496  $(8,605) $1,305,765 
                     
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 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2007 and December 31, 2006
(in thousands)
(Unaudited)

  
2007
  
2006
 
CURRENT ASSETS
      
Cash and Cash Equivalents $2,190  $1,369 
Accounts Receivable:        
  Customers  74,743   82,102 
  Affiliated Companies  61,771   108,288 
  Accrued Unbilled Revenues  12,424   2,206 
  Miscellaneous  1,627   1,838 
  Allowance for Uncollectible Accounts  (863)  (601)
 Total Accounts Receivable  149,702   193,833 
Fuel  48,261   64,669 
Materials and Supplies  136,332   129,953 
Risk Management Assets  37,351   69,752 
Accrued Tax Benefits  177   27,378 
Prepayments and Other  17,968   15,170 
TOTAL
  391,981   502,124 
         
PROPERTY, PLANT AND EQUIPMENT
        
Electric:        
  Production  3,402,220   3,363,813 
  Transmission  1,067,434   1,047,264 
  Distribution  1,180,230   1,102,033 
Other (including nuclear fuel and coal mining)  558,168   529,727 
Construction Work in Progress  179,597   183,893 
Total
  6,387,649   6,226,730 
Accumulated Depreciation, Depletion and Amortization  3,003,588   2,914,131 
TOTAL - NET
  3,384,061   3,312,599 
         
OTHER NONCURRENT ASSETS
        
Regulatory Assets  282,020   314,805 
Spent Nuclear Fuel and Decommissioning Trusts  1,314,892   1,248,319 
Long-term Risk Management Assets  45,810   59,137 
Deferred Charges and Other  92,710   109,453 
TOTAL
  1,735,432   1,731,714 
         
TOTAL ASSETS
 $5,511,474  $5,546,437 

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, 2007 and December 31, 2006
(Unaudited)

  
2007
  
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates $24,234  $91,173 
Accounts Payable:        
General  118,010   146,733 
Affiliated Companies  44,772   65,497 
Long-term Debt Due Within One Year – Nonaffiliated  -   50,000 
Risk Management Liabilities  28,340   52,083 
Customer Deposits  31,498   34,946 
Accrued Taxes  69,302   59,652 
Other  133,966   128,461 
TOTAL
  450,122   628,545 
         
NONCURRENT LIABILITIES
        
Long-term Debt – Nonaffiliated  1,564,811   1,505,135 
Long-term Risk Management Liabilities  30,717   42,641 
Deferred Income Taxes  305,429   335,000 
Regulatory Liabilities and Deferred Investment Tax Credits  757,136   753,402 
Asset Retirement Obligations  841,791   809,853 
Deferred Credits and Other  187,001   174,340 
TOTAL
  3,686,885   3,620,371 
         
TOTAL LIABILITIES
  4,137,007   4,248,916 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  8,080   8,082 
         
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   861,290 
Retained Earnings  465,310   386,616 
Accumulated Other Comprehensive Income (Loss)  (16,798)  (15,051)
TOTAL
  1,366,387   1,289,439 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 $5,511,474  $5,546,437 

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, 2007 and 2006
(in thousands)
(Unaudited)

  
2007
  
2006
 
OPERATING ACTIVITIES
      
Net Income
 $108,622  $120,964 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
        
Depreciation and Amortization  145,801   153,897 
Deferred Income Taxes  (9,235)  7,734 
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net  14,450   (20,673)
Mark-to-Market of Risk Management Contracts  6,226   (4,915)
Amortization of Nuclear Fuel  48,360   37,839 
Change in Other Noncurrent Assets  14,437   16,508 
Change in Other Noncurrent Liabilities  33,995   35,920 
Changes in Certain Components of Working Capital:
        
Accounts Receivable, Net  34,569   37,368 
Fuel, Materials and Supplies  14,584   (20,665)
Accounts Payable  (27,015)  29,483 
Customer Deposits  (3,448)  (14,315)
Accrued Taxes, Net  41,243   28,292 
Other Current Assets  (3,459)  20,997 
Other Current Liabilities  2,282   25,489 
Net Cash Flows From Operating Activities
  421,412   453,923 
         
INVESTING ACTIVITIES
        
Construction Expenditures  (191,110)  (240,806)
Purchases of Investment Securities  (561,509)  (559,803)
Sales of Investment Securities  505,620   517,017 
Acquisitions of Nuclear Fuel  (73,112)  (72,614)
Other  670   3,344 
Net Cash Flows Used For Investing Activities
  (319,441)  (352,862)
         
FINANCING ACTIVITIES
        
Issuance of Long-term Debt – Nonaffiliated  -   49,745 
Change in Advances from Affiliates, Net  (66,939)  (66,086)
Retirement of Long-term Debt – Nonaffiliated  -   (50,000)
Retirement of Cumulative Preferred Stock  (2)  (1)
Principal Payments for Capital Lease Obligations  (3,954)  (4,612)
Dividends Paid on Common Stock  (30,000)  (30,000)
Dividends Paid on Cumulative Preferred Stock  (255)  (255)
Net Cash Flows Used For Financing Activities
  (101,150)  (101,209)
         
Net Increase (Decrease) in Cash and Cash Equivalents
  821   (148)
Cash and Cash Equivalents at Beginning of Period
  1,369   854 
Cash and Cash Equivalents at End of Period
 $2,190  $706 
         
SUPPLEMENTARY INFORMATION
        
Cash Paid for Interest, Net of Capitalized Amounts $49,628  $37,708 
Net Cash Paid for Income Taxes  14,395   20,180 
Noncash Acquisitions Under Capital Leases  5,847   4,359 
Construction Expenditures Included in Accounts Payable at September 30,  23,935   29,755 
Acquisition of Nuclear Fuel in Accounts Payable at September 30,  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 2007 Compared to Third Quarter of 2006

Reconciliation of Third Quarter of 2006 to Third Quarter of 2007
Net Income
(in millions)

Third Quarter of 2006
    $83 
        
Changes in Gross Margin:
       
Retail Margins  30     
Off-system Sales  (7)    
Transmission Revenues, Net  (15)    
Other  (1)    
Total Change in Gross Margin
      7 
         
Changes in Operating Expenses and Other:
        
Other Operation and Maintenance  (4)    
Depreciation and Amortization  (2)    
Other Income, Net  (1)    
Interest Expense  (11)    
Total Change in Operating Expenses and Other
      (18)
         
Income Tax Expense      3 
         
Third Quarter of 2007
     $75 

Net Income decreased $8 million to $75 million in 2007.  The key driver of the decrease was an $18 million increase in Operating Expenses and Other offset by a $7 million increase in Gross Margin and a $3 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 increased $30 million partially due to a $13 million increase in industrial revenue primarily due to the addition of Ormet, a major industrial customer, effective January 1, 2007.  See “Ormet” section of Note 3.  Retail Margins also increased due to a $3 million increase in rate revenues primarily related to an $8 million increase in OPCo’s RSP partially offset by a $3 million decrease related to rate recovery of IGCC preconstruction costs.  See “Ohio Rate Matters” section of Note 3.  The decrease in rate recovery of IGCC preconstruction costs was offset by the decreased amortization of deferred expenses in Depreciation and Amortization.
·Margins from Off-system Sales decreased $7 million primarily due to a $10 million decrease related to OPCo’s purchase power and sale agreement with Dow Chemical Company (Dow) which ended in November 2006 and a decrease in OPCo’s allocated share of off-system sales revenue due to an affiliate’s new peak.  These decreases were offset by higher sales volumes and power prices in the east, benefits from AEP’s eastern natural gas fleet, and higher trading margins.
·Transmission Revenues, Net decreased $15 million primarily due to PJM’s revision of its pricing methodology for transmission line losses to marginal-loss pricing effective June 1, 2007.  See “PJM Marginal-Loss Pricing” section of Note 3.

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

·Other Operation and Maintenance expenses increased $4 million primarily due to:
·A $17 million increase due to the settlement agreement regarding alleged violations of the NSR provisions of the CAA.  The $17 million represents OPCo’s allocation of the settlement.  See “Federal EPA Complaint and Notice of Violation” section of Note 4.
·A $7 million increase in overhead line expenses due to the 2006 recognition of a regulatory asset related to PUCO orders regarding distribution service reliability and restoration costs.
These increases were partially offset by:
·A $10 million decrease due to the absence of maintenance and rental expenses related to OPCo’s purchase power and sale agreement with Dow which ended in November 2006.  The decrease in Other Operation and Maintenance expenses related to Dow were offset by a corresponding decrease in margins from Off-system Sales.
·A $3 million decrease in maintenance from planned and forced outages at the Muskingum River and Kammer Plants related to boiler tube inspections in 2006.
·Depreciation and Amortization increased $2 million primarily due to a $7 million increase in depreciation related to environmental improvements placed in service at the Mitchell Plant.  This increase was offset by decreased amortization of IGCC preconstruction costs of $3 million and a $2 million amortization of a regulatory liability related to Ormet.  See “Ormet” section of Note 3.  The decrease in amortization of IGCC preconstruction costs was offset by a corresponding decrease in Retail Margins.
·Interest Expense increased $11 million due to additional long-term debt and a decrease in the debt component of AFUDC as a result of Mitchell Plant environmental improvements placed in service.
·Income Tax Expense decreased $3 million primarily due to a decrease in pretax book income offset by changes in certain book/tax differences accounted for on a flow-through basis.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

Reconciliation of Nine Months Ended September 30, 2006 to Nine Months Ended September 30, 2007
Net Income
(in millions)

Nine Months Ended September 30, 2006
    $202 
        
Changes in Gross Margin:
       
Retail Margins  152     
Off-system Sales  (23)    
Transmission Revenues, Net  (26)    
Other  (16)    
Total Change in Gross Margin
      87 
         
Changes in Operating Expenses and Other:
        
Other Operation and Maintenance  1     
Depreciation and Amortization  (14)    
Taxes Other Than Income Taxes  (2)    
Other Income, Net  (1)    
Interest Expense  (23)    
Total Change in Operating Expenses and Other
      (39)
         
Income Tax Expense      (21)
         
Nine Months Ended September 30, 2007
     $229 

Net Income increased $27 million to $229 million in 2007.  The key driver of the increase was an $87 million increase in Gross Margin offset by a $39 million increase in Operating Expenses and Other and a $21 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 $152 million primarily due to the following:
·A $42 million increase in capacity settlements under the Interconnection Agreement related to certain affiliates’ peaks and the June 2006 expiration of OPCo’s supplemental capacity and energy obligation to Buckeye Power, Inc. under the Cardinal Station Agreement.
·A $38 million increase in rate revenues primarily related to a $26 million increase in OPCo’s RSP, a $9 million increase related to rate recovery of storm costs and a $3 million increase related to rate recovery of IGCC preconstruction costs.  See “Ohio Rate Matters” section of Note 3.  The increase in rate recovery of storm costs was offset by the amortization of deferred expenses in Other Operation and Maintenance.  The increase in rate recovery of IGCC preconstruction costs was offset by the amortization of deferred expenses in Depreciation and Amortization.
·A $31 million increase in industrial revenue due to the addition of Ormet, a major industrial customer, effective January 1, 2007.  See “Ormet” section of Note 3.
·A $20 million increase in residential and commercial revenue primarily due to a 26% increase in cooling degree days and a 27% increase in heating degree days.
·Margins from Off-system Sales decreased $23 million primarily due to a decrease in OPCo’s allocated share of off-system sales revenue due to an affiliate’s new peak and a $20 million decrease related to OPCo’s purchase power and sale agreement with Dow Chemical Company (Dow) which ended in November 2006.  Higher trading margins helped to offset a portion of the decrease over last year.
·Transmission Revenues, Net decreased $26 million primarily due to PJM’s revision of its pricing methodology for transmission line losses to marginal-loss pricing effective June 1, 2007.  See “PJM Marginal-Loss Pricing” section of Note 3.
·Other revenues decreased $16 million primarily due to a $7 million decrease related to the April 2006 expiration of an obligation to sell supplemental capacity and energy to Buckeye Power, Inc. under the Cardinal Station Agreement and a $5 million decrease in gains on sales of emission allowances.

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

·Other Operation and Maintenance expenses decreased $1 million primarily due to the following:
·A $21 million decrease in maintenance from planned and forced outages at the Muskingum River, Kammer and Sporn Plants related to boiler tube inspections in 2006.
·A $20 million decrease in maintenance and rental expenses related to OPCo’s purchase power and sale agreement with Dow which ended in November 2006.  This decrease was offset by a corresponding decrease in margins from Off-system Sales.
These decreases were partially offset by:
·A $17 million increase due to the settlement agreement regarding alleged violations of the NSR provisions of the CAA.  See “Federal EPA Complaint and Notice of Violation” section of Note 4.
·A $13 million increase in overhead line expenses due to the 2006 recognition of a regulatory asset related to PUCO orders regarding distribution service reliability and restoration costs and the amortization of deferred storm expenses recovered through a cost-recovery rider.  The increase in the amortization of deferred storm expenses was offset by a corresponding increase in Retail Margins.
·A $7 million increase in removal costs related to planned and forced outages at the Gavin, Mitchell and Cardinal Plants.
·Depreciation and Amortization increased $14 million primarily due to a $16 million increase in depreciation related to environmental improvements placed in service at the Mitchell Plant and the amortization of IGCC preconstruction costs of $3 million in 2007.  These increases were partially offset by a $5 million decrease related to the amortization of a regulatory liability related to Ormet.  See “Ormet” section of Note 3.  The increase in amortization of IGCC preconstruction costs was offset by a corresponding increase in Retail Margins.
·Interest Expense increased $23 million primarily due to additional long-term debt.
·Income Tax Expense increased $21 million primarily due to an increase in pretax book income and state income taxes.

Financial Condition

Credit Ratings

The rating agencies currently have OPCo on stable outlook. Current ratings are as follows:

Moody’s
S&P
Fitch
Senior Unsecured DebtA3BBBBBB+

Cash Flow

Cash flows for the nine months ended September 30, 2007 and 2006 were as follows:
  
2007
  
2006
 
  
(in thousands)
 
Cash and Cash Equivalents at Beginning of Period
 $1,625  $1,240 
Cash Flows From (Used For):        
Operating Activities  402,980   470,180 
Investing Activities  (743,260)  (703,550)
Financing Activities  351,381   233,455 
Net Increase in Cash and Cash Equivalents  11,101   85 
Cash and Cash Equivalents at End of Period
 $12,726  $1,325 

Operating Activities

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 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 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.

Net Cash Flows From Operating Activities were $470 million in 2006.  OPCo produced Net Income of $202 million during the period and a noncash expense item of $239 million for Depreciation and Amortization.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital primarily included two significant items.  Accounts Receivable, Net had a $78 million cash inflow primarily due to the collection of receivables related to power sales to affiliates.  Accounts Payable had a $45 million cash outflow primarily due to timing differences for payments to affiliates related to emission allowances and the AEP Power Pool.

Investing Activities

Net Cash Flows Used For Investing Activities were $743 million and $704 million in 2007 and 2006, respectively.  Construction Expenditures were $751 million and $715 million in 2007 and 2006, 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 January 2007, environmental upgrades were completed for Unit 1 and 2 at the Mitchell Plant.  Based upon OPCo’s current forecast, OPCo expects construction expenditures to be approximately $150 million for the remainder of 2007, excluding AFUDC.

Financing Activities

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.

Net Cash Flows From Financing Activities were $233 million for 2006.  OPCo issued $350 million of Senior Unsecured Notes and $65 million of Pollution Control Bonds.  OPCo retired Notes Payable-Affiliated of $200 million.  OPCo received a Capital Contribution from Parent of $70 million.

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2007 were:

Issuances
Type of Debt
 
Principal
Amount
  
Interest Rate
 
Due Date
  
(in thousands)
  
(%)
  
Pollution Control Bonds $65,000   4.90 2037
Senior Unsecured Notes  400,000  Variable 2010

Retirements
Type of Debt
 
Principal
Amount
  
Interest Rate
 
Due Date
  
(in thousands)
  
(%)
  
Notes Payable – Nonaffiliated $2,927   6.81 2008
Notes Payable – Nonaffiliated  6,000   6.27 2009

Liquidity

OPCo has solid investment grade ratings, which provide ready access to capital markets in order to issue new debt, refinance short-term debt or refinance long-term debt maturities.  In addition, OPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.

Summary Obligation Information

A summary of contractual obligations is included in the 2006 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 the obligations resulting from the settlement agreement regarding alleged violations of the NSR provisions of the CAA.  See “Federal EPA Complaint and Notice of Violations” section of Note 4.

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 pending litigation and regulatory proceedings, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2006 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, 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 2006 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 us.OPCo.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in ourthe condensed consolidated balance sheet as of March 31,September 30, 2007 and the reasons for changes in our total MTM value as compared to December 31, 2006.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of March 31,September 30, 2007
(in thousands)

 
MTM Risk Management Contracts
 
Cash Flow Hedges
 
DETM Assignment (a)
 
Total
  
MTM Risk Management Contracts
  
Cash Flow Hedges
  
DETM Assignment (a)
  
Total
 
Current Assets $49,092 $756 $- $49,848  $45,622  $1,401  $-  $47,023 
Noncurrent Assets  57,316  96  -  57,412   55,412   987   -   56,399 
Total MTM Derivative Contract Assets
  106,408  852  -  107,260   101,034   2,388   -   103,422 
                             
Current Liabilities  (42,532) (3,980) (2,071) (48,583)  (35,178)  (229)  (2,616)  (38,023)
Noncurrent Liabilities  (35,731) (312) (5,493) (41,536)  (33,907)  (402)  (4,370)  (38,679)
Total MTM Derivative Contract Liabilities
  (78,263) (4,292) (7,564) (90,119)  (69,085)  (631)  (6,986)  (76,702)
                             
Total MTM Derivative Contract Net Assets (Liabilities)
 $28,145 $(3,440)$(7,564)$17,141  $31,949  $1,757  $(6,986) $26,720 

(a)See “Natural Gas Contracts with DETM” section of Note 16 in the 2006 Annual Report.

MTM Risk Management Contract Net Assets
ThreeNine Months Ended March 31,September 30, 2007
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2006
 $33,042  $33,042 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period  (4,433) (6,663)
Fair Value of New Contracts at Inception When Entered During the Period (a)  311  3,267 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period  (23) 340 
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts  -  - 
Changes in Fair Value Due to Market Fluctuations During the Period (b)  (317) 2,411 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)  (435)  (448)
Total MTM Risk Management Contract Net Assets
  28,145  31,949 
Net Cash Flow Hedge Contracts  (3,440) 1,757 
DETM Assignment (d)  (7,564)  (6,986)
Total MTM Risk Management Contract Net Assets at March 31, 2007
 $17,141 
Total MTM Risk Management Contract Net Assets at September 30, 2007
 $26,720 

(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)Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)“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 liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(d)See “Natural Gas Contracts with DETM” section of Note 16 in ourthe 2006 Annual Report.
 
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

The following table presents:

·The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
·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
Fair Value of Contracts as of March 31,September 30, 2007
(in thousands)


  
Remainder
2007
 
2008
 
2009
 
2010
 
2011
 
After
2011
 
Total
 
Prices Actively Quoted - Exchange Traded Contracts $11,122 $(399)$464 $- $- $- $11,187 
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)
  (621) 9,668  7,524  2,985  -  -  19,556 
Prices Based on Models and Other Valuation Methods (b)  (5,725) (3,527) 1,165  3,608  812  1,069  (2,598)
Total
 $4,776 $5,742 $9,153 $6,593 $812 $1,069 $28,145 
  
Remainder
2007
 
2008
 
2009
 
2010
 
2011
 
After
2011
 
Total
 
Prices Actively Quoted –     Exchange Traded Contracts $2,927 $(4,308)$857 $(30)$- $- $(554)
Prices Provided by Other External
  Sources – OTC Broker Quotes (a)
  110  11,983  9,396  6,954  -  -  28,443 
Prices Based on Models and Other   Valuation Methods (b)  42  (557) 661  1,132  1,424  1,358  4,060 
Total
 $3,079 $7,118 $10,914 $8,056 $1,424 $1,358 $31,949 

(a)“Prices Provided by Other External Sources -– OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)“Prices Based on Models and Other Valuation Methods” is used in absence of pricingindependent information from external sources.  Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources.  In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled.  The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.
Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available.available including values determinable by other third party transactions.


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

We areOPCo is exposed to market fluctuations in energy commodity prices impacting our power operations.  We monitorManagement monitors 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 doManagement does not hedge all commodity price risk.

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

We use forward contracts and collars as cash flow hedgesManagement uses foreign currency derivatives to lock in prices on certain transactions denominated in foreign currencies where deemed necessary. We donecessary, and designate qualifying instruments as cash flow hedge strategies.  Management does not hedge all foreign currency exposure.currency.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on ourthe Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2006 to March 31,September 30, 2007.  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
ThreeNine Months Ended March 31,September 30, 2007
(in thousands)

 
Power
 
Foreign
Currency
 
Interest Rate
 
Total
  
Power
  
Foreign
Currency
  
Interest Rate
  
Total
 
Beginning Balance in AOCI December 31, 2006
 $4,040 $(331)$3,553 $7,262  $4,040  $(331) $3,553  $7,262 
Changes in Fair Value  (4,677) -  -  (4,677)  537   (4)  (139)  394 
Reclassifications from AOCI to Net Income for
Cash Flow Hedges Settled
  (1,595) 3  (202) (1,794)  (3,280)  10   (610)  (3,880)
Ending Balance in AOCI March 31, 2007
 $(2,232)$(328)$3,351 $791 
Ending Balance in AOCI September 30, 2007
 $1,297  $(325) $2,804  $3,776 

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $1,292$1,576 thousand loss.gain.

Credit Risk

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

VaR Associated with Risk Management Contracts

We useManagement uses 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 March 31,September 30, 2007, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, 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:

Three Months Ended March 31, 2007
    
Twelve Months Ended December 31, 2006
(in thousands)
    
(in thousands)
End
 
High
 
Average
 
Low
    
End
 
High
 
Average
 
Low
$678 $2,054 $924 $255    $573 $1,451 $500 $271

The High VaR for the twelve months ended December 31, 2006 occurred in the third quarter due to volatility in the ECAR/PJM region.
Nine Months Ended September 30, 2007
  
Twelve Months Ended December 31, 2006
 
(in thousands)
  
(in thousands)
 
End
  
High
  
Average
  
Low
  
End
  
High
  
Average
  
Low
 
$208  $2,054  $594  $159  $573  $1,451  $500  $271 

VaR Associated with Debt Outstanding

We utilizeManagement utilizes a VaR model to measure interest rate market risk exposure.  The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period.  The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $131$138 million and $110 million at March 31,September 30, 2007 and December 31, 2006, respectively.  WeManagement would not expect to liquidate ourthe entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or consolidated financial position.



OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended March 31,September 30, 2007 and 2006
(in thousands)
(Unaudited)

 
Three Months Ended
  
Nine Months Ended
 
 
2007
 
2006
  
2007
  
2006
  
2007
  
2006
 
REVENUES
                 
Electric Generation, Transmission and Distribution $492,534 $544,639  $543,404  $558,490  $1,516,383  $1,556,193 
Sales to AEP Affiliates  178,894  149,259   205,193   198,640   564,292   502,547 
Other - Affiliated  4,038  3,709   5,749   4,400   16,604   11,975 
Other - Nonaffiliated  3,975  4,999   3,397   3,378   10,838   12,806 
TOTAL
  679,441  702,606   757,743   764,908   2,108,117   2,083,521 
                       
EXPENSES
                       
Fuel and Other Consumables Used for Electric Generation  198,293  235,130   254,310   280,593   653,941   727,261 
Purchased Electricity for Resale  24,854  21,714   33,178   28,324   85,900   76,351 
Purchased Electricity from AEP Affiliates  20,966  28,572   43,147   35,423   92,858   92,086 
Other Operation  102,987  86,629   102,850   100,265   292,809   286,083 
Maintenance  59,148  47,524   45,663   44,503   155,428   163,443 
Depreciation and Amortization  84,276  78,821   84,400   82,755   253,455   239,431 
Taxes Other Than Income Taxes  48,385  47,153   47,506   47,945   146,211   143,634 
TOTAL
  538,909  545,543   611,054   619,808   1,680,602   1,728,289 
                       
OPERATING INCOME
  140,532  157,063   146,689   145,100   427,515   355,232 
                       
Other Income (Expense):
                       
Interest Income  412  637   108   840   992   2,072 
Carrying Costs Income  3,541  3,383   3,644   3,502   10,779   10,336 
Allowance for Equity Funds Used During Construction  571  738   590   755   1,607   1,891 
Interest Expense  (25,931) (23,414)  (36,262)  (24,610)  (95,927)  (72,461)
                       
INCOME BEFORE INCOME TAXES
  119,125  138,407   114,769   125,587   344,966   297,070 
                       
Income Tax Expense  39,864  43,375   39,507   42,245   116,103   95,297 
                       
NET INCOME
  79,261  95,032   75,262   83,342   228,863   201,773 
                       
Preferred Stock Dividend Requirements  183  183   183   183   549   549 
                       
EARNINGS APPLICABLE TO COMMON STOCK
 $79,078 $94,849  $75,079  $83,159  $228,314  $201,224 

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 ThreeNine Months Ended March 31,September 30, 2007 and 2006
(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, 2005
 $321,201 $466,637 $979,354 $755 $1,767,947  $321,201  $466,637  $979,354  $755  $1,767,947 
                                
Capital Contribution From Parent    35,000     35,000       70,000           70,000 
Preferred Stock Dividends      (183)    (183)          (549)      (549)
Gain on Reacquired Preferred Stock      2           2 
TOTAL
              1,802,764                   1,837,400 
                                
COMPREHENSIVE INCOME
                                    
Other Comprehensive Income, Net of Taxes:
                                
Cash Flow Hedges, Net of Tax of $3,326        6,176 6,176 
Cash Flow Hedges, Net of Tax of $3,393              6,300   6,300 
NET INCOME
        95,032     95,032           201,773       201,773 
TOTAL COMPREHENSIVE INCOME
              101,208                   208,073 
                                
MARCH 31, 2006
 $321,201 $501,637 $1,074,203 $6,931 $1,903,972 
SEPTEMBER 30, 2006
 $321,201  $536,639  $1,180,578  $7,055  $2,045,473 
                                
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      (183)    (183)          (549)      (549)
TOTAL
              2,002,779                   2,002,413 
                                
COMPREHENSIVE INCOME
                                    
Other Comprehensive Loss, Net of Taxes:
                                
Cash Flow Hedges, Net of Tax of $3,485        (6,471) (6,471)
Cash Flow Hedges, Net of Tax of $1,878              (3,486)  (3,486)
NET INCOME
        79,261     79,261           228,863       228,863 
TOTAL COMPREHENSIVE INCOME
              72,790                   225,377 
                                
MARCH 31, 2007
 $321,201 $536,639 $1,280,963 $(63,234)$2,075,569 
SEPTEMBER 30, 2007
 $321,201  $536,639  $1,430,199  $(60,249) $2,227,790 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31,September 30, 2007 and December 31, 2006
(in thousands)
(Unaudited)

 
2007
 
2006
  
2007
  
2006
 
CURRENT ASSETS
             
Cash and Cash Equivalents $1,261 $1,625  $12,726  $1,625 
Accounts Receivable:               
Customers  114,608  86,116   96,217   86,116 
Affiliated Companies  109,029  108,214   102,771   108,214 
Accrued Unbilled Revenues  17,082  10,106   28,193   10,106 
Miscellaneous  3,620  1,819   1,235   1,819 
Allowance for Uncollectible Accounts  (838) (824)  (1,079)  (824)
Total Accounts Receivable  243,501  205,431   227,337   205,431 
Fuel  139,950  120,441   125,583   120,441 
Materials and Supplies  78,866  74,840   82,377   74,840 
Emission Allowances  12,302  10,388   6,218   10,388 
Risk Management Assets  49,848  86,947   47,023   86,947 
Accrued Tax Benefits  3,181  22,909   8,476   22,909 
Prepayments and Other  28,395  18,416   27,332   18,416 
TOTAL
  557,304  540,997   537,072   540,997 
               
PROPERTY, PLANT AND EQUIPMENT
               
Electric:               
Production  4,747,459  4,413,340   5,553,893   4,413,340 
Transmission  1,038,642  1,030,934   1,059,631   1,030,934 
Distribution  1,336,874  1,322,103   1,372,724   1,322,103 
Other  300,054  299,637   312,305   299,637 
Construction Work in Progress  1,226,985  1,339,631   676,841   1,339,631 
Total
  8,650,014  8,405,645   8,975,394   8,405,645 
Accumulated Depreciation and Amortization  2,867,416  2,836,584   2,921,494   2,836,584 
TOTAL - NET
  5,782,598  5,569,061   6,053,900   5,569,061 
               
OTHER NONCURRENT ASSETS
               
Regulatory Assets  387,201  414,180   354,499   414,180 
Long-term Risk Management Assets  57,412  70,092   56,399   70,092 
Deferred Charges and Other  209,873  224,403   176,964   224,403 
TOTAL
  654,486  708,675   587,862   708,675 
               
TOTAL ASSETS
 $6,994,388 $6,818,733  $7,178,834  $6,818,733 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31,September 30, 2007 and December 31, 2006
(Unaudited)

 
2007
 
2006
  
2007
  
2006
 
CURRENT LIABILITIES
 
(in thousands)
  
(in thousands)
 
Advances from Affiliates $397,127 $181,281  $85,341  $181,281 
Accounts Payable:               
General  225,809  250,025   136,467   250,025 
Affiliated Companies  116,297  145,197   104,106   145,197 
Short-term Debt - Nonaffiliated  4,503  1,203 
Long-term Debt Due Within One Year - Nonaffiliated  17,854  17,854 
Short-term Debt – Nonaffiliated  2,097   1,203 
Long-term Debt Due Within One Year – Nonaffiliated  22,390   17,854 
Risk Management Liabilities  48,583  73,386   38,023   73,386 
Customer Deposits  31,547  31,465   36,407   31,465 
Accrued Taxes  148,057  165,338   126,995   165,338 
Accrued Interest  34,561  35,497   45,151   35,497 
Other  126,845  123,631   119,987   123,631 
TOTAL
  1,151,183  1,024,877   716,964   1,024,877 
               
NONCURRENT LIABILITIES
               
Long-term Debt - Nonaffiliated  2,176,601  2,183,887 
Long-term Debt - Affiliated  200,000  200,000 
Long-term Debt – Nonaffiliated  2,635,957   2,183,887 
Long-term Debt – Affiliated  200,000   200,000 
Long-term Risk Management Liabilities  41,536  52,929   38,679   52,929 
Deferred Income Taxes  891,761  911,221   895,839   911,221 
Regulatory Liabilities and Deferred Investment Tax Credits  173,946  185,895   167,182   185,895 
Deferred Credits and Other  249,254  219,127   263,136   219,127 
TOTAL
  3,733,098  3,753,059   4,200,793   3,753,059 
               
TOTAL LIABILITIES
  4,884,281  4,777,936   4,917,757   4,777,936 
               
Minority Interest  17,910  15,825   16,660   15,825 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption  16,628  16,630   16,627   16,630 
               
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 
Common Stock – No Par Value:        
Authorized – 40,000,000 Shares        
Outstanding – 27,952,473 Shares  321,201   321,201 
Paid-in Capital  536,639  536,639   536,639   536,639 
Retained Earnings  1,280,963  1,207,265   1,430,199   1,207,265 
Accumulated Other Comprehensive Income (Loss)  (63,234) (56,763)  (60,249)  (56,763)
TOTAL
  2,075,569  2,008,342   2,227,790   2,008,342 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 $6,994,388 $6,818,733  $7,178,834  $6,818,733 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the ThreeNine Months Ended March 31,September 30, 2007 and 2006
(in thousands)
(Unaudited)

 
2007
 
2006
  
2007
  
2006
 
OPERATING ACTIVITIES
             
Net Income
 $79,261 $95,032  $228,863  $201,773 
Adjustments for Noncash Items:
       
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
        
Depreciation and Amortization  84,276  78,821   253,455   239,431 
Deferred Income Taxes  2,851  3,604   3,938   (18,399)
Carrying Costs Income  (3,541) (3,383)  (10,779)  (10,336)
Mark-to-Market of Risk Management Contracts  3,958  (3,616)  (424)  668 
Deferred Property Taxes  17,920  17,331   54,036   54,073 
Change in Other Noncurrent Assets  (4,406) 2,455   (21,882)  1,732 
Change in Other Noncurrent Liabilities  (4,434) 13,855   8,026   15,923 
Changes in Certain Components of Working Capital:
               
Accounts Receivable, Net  (38,070) 101,866   (32,723)  78,307 
Fuel, Materials and Supplies  (23,535) (18,238)  (1,245)  (25,375)
Accounts Payable  (25,807) (60,411)  (59,925)  (44,817)
Customer Deposits  82  (12,497)
Accrued Taxes, Net  6,360  3,116   (19,997)  (27,733)
Accrued Interest  (2,986) (10,998)
Other Current Assets  1,706  (739)  (10,544)  36,333 
Other Current Liabilities  3,229  (24,196)  12,181   (31,400)
Net Cash Flows From Operating Activities
  96,864  182,002   402,980   470,180 
               
INVESTING ACTIVITIES
               
Construction Expenditures  (301,635) (222,600)  (751,161)  (715,200)
Change in Other Cash Deposits, Net  (7,988) (1,651)
Proceeds from Sale of Assets  2,797  2,389 
Proceeds From Sales of Assets  7,924   13,301 
Other  (23)  (1,651)
Net Cash Flows Used For Investing Activities
  (306,826) (221,862)  (743,260)  (703,550)
               
FINANCING ACTIVITIES
               
Capital Contributions from Parent Company  -  35,000 
Change in Short-term Debt, Net - Nonaffiliated  3,300  636 
Capital Contribution from Parent  -   70,000 
Issuance of Long-term Debt – Nonaffiliated  461,324   405,841 
Change in Short-term Debt, Net – Nonaffiliated  895   (3,264)
Change in Advances from Affiliates, Net  215,846  10,972   (95,940)  (21,908)
Retirement of Long-term Debt - Nonaffiliated  (7,463) (4,713)
Retirement of Long-term Debt – Nonaffiliated  (8,927)  (10,890)
Retirement of Long-term Debt – Affiliated  -   (200,000)
Retirement of Cumulative Preferred Stock  (2)  (7)
Principal Payments for Capital Lease Obligations  (1,902) (2,135)  (5,420)  (5,768)
Dividends Paid on Cumulative Preferred Stock  (183) (183)  (549)  (549)
Net Cash Flows From Financing Activities
  209,598  39,577   351,381   233,455 
               
Net Decrease in Cash and Cash Equivalents
  (364) (283)
Net Increase in Cash and Cash Equivalents
  11,101   85 
Cash and Cash Equivalents at Beginning of Period
  1,625  1,240   1,625   1,240 
Cash and Cash Equivalents at End of Period
 $1,261 $957  $12,726  $1,325 
        
SUPPLEMENTARY INFORMATION
        
Cash Paid for Interest, Net of Capitalized Amounts $85,851  $71,666 
Net Cash Paid for Income Taxes  61,459   72,175 
Noncash Acquisitions Under Capital Leases  1,620   2,529 
Construction Expenditures Included in Accounts Payable at September 30,  42,055   117,638 

SUPPLEMENTARY INFORMATION
       
Cash Paid for Interest, Net of Capitalized Amounts $29,646 $29,152 
Net Cash Paid (Received) for Income Taxes  (8,899) 922 
Noncash Acquisitions Under Capital Leases  608  927 
Construction Expenditures Included in Accounts Payable at March 31,  98,653  82,024 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
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 NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations

FirstThird Quarter of 2007 Compared to FirstThird Quarter of 2006

Reconciliation of FirstThird Quarter of 2006 to FirstThird Quarter of 2007
Net LossIncome
(in millions)

First Quarter of 2006
    $(5)
Third Quarter of 2006
    $42 
              
Changes in Gross Margin:
              
Retail and Off-system Sales Margins  5      1     
Transmission Revenues  1    
Transmission Revenues, Net  1     
Other  (1)     2     
Total Change in Gross Margin
     5       4 
               
Changes in Operating Expenses and Other:
               
Other Operation and Maintenance  (27)     (3)    
Depreciation and Amortization  (2)     (2)    
Taxes Other Than Income Taxes  (6)    
Interest Expense  (2)     (1)    
Total Change in Operating Expenses and Other
     (31)      (12)
               
Income Tax Credit     11 
Income Tax Expense      3 
               
First Quarter of 2007
    $(20)
Third Quarter of 2007
     $37 

Net Loss increased $15Income decreased $5 million to $20$37 million in 2007.  The key driverdrivers of the increased loss wasdecrease were a $31$12 million increase in Operating Expenses and Other, partially offset by an $11 million increase in Income Tax Credit and a $5$4 million increase in Gross Margin.Margin and a $3 million decrease in Income Tax Expense .

The major componentcomponents of our increasethe change in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances and purchased power was a $5 million increase in Retail and Off-system Sales Margins primarily due to a $4 million increase in retail margins resulting from an increase in heating degree days.were as follows:

·Retail and Off-system Sales Margins increased $1 million primarily due to an increase in retail margins attributable to new base rates partially offset by a reduction in off-system sales volumes.
·Other revenues increased $2 million primarily due to higher gains on sales of emission allowances.

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

·Other Operation and Maintenance expenses increased $27$3 million primarily due to:to an increase in transmission expense resulting from higher SPP administration fees and transmission services from other utilities.
·A $21Taxes Other Than Income Taxes increased $6 million increase in distribution maintenance expense primarily due to a January 2007 ice storm.
·A $2 million increasesales and use tax adjustment recorded in administrative and general expenses, mostly due to increased employee-related expenses.2006.
·InterestIncome Tax Expense increased $2decreased $3 million primarily due to increased borrowings.a decrease in pretax book income.

Income Taxes

Income Tax Credit increased $11 million primarily due to an increase in pretax book loss and a decrease in state income taxes.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in our 2006 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

Our risk management assets and liabilities are managed by AEPSC as agent for us. The related risk management policies and procedures are instituted and administered by AEPSC. See the complete discussion and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

VaR Associated with Debt Outstanding

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $42 million and $39 million at March 31, 2007 and December 31, 2006, respectively. We would not expect to liquidate our entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or financial position.






PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF OPERATIONS
For the ThreeNine Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
REVENUES
     
Electric Generation, Transmission and Distribution $290,080 $339,601 
Sales to AEP Affiliates  24,593  14,068 
Other  640  1,060 
TOTAL
  315,313  354,729 
        
EXPENSES
       
Fuel and Other Consumables Used for Electric Generation  142,515  213,173 
Purchased Electricity for Resale  67,409  33,217 
Purchased Electricity from AEP Affiliates  13,484  21,231 
Other Operation  41,007  36,756 
Maintenance  43,085  20,307 
Depreciation and Amortization  22,706  21,132 
Taxes Other Than Income Taxes  10,294  10,076 
TOTAL
  340,500  355,892 
        
OPERATING LOSS
  (25,187) (1,163)
        
Other Income (Expense):
       
Interest Income  646  569 
Interest Expense  (11,383) (9,135)
        
LOSS BEFORE INCOME TAXES
  (35,924) (9,729)
        
Income Tax Credit  (15,498) (4,372)
        
NET LOSS
  (20,426) (5,357)
        
Preferred Stock Dividend Requirements  53  53 
        
LOSS APPLICABLE TO COMMON STOCK
 $(20,479)$(5,410)

The common stock of PSO is owned by a wholly-owned subsidiary of 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 Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2005
 $157,230 $230,016 $162,615 $(1,264)$548,597 
                 
Preferred Stock Dividends        (53)    (53)
TOTAL
              548,544 
                 
COMPREHENSIVE LOSS
                
Other Comprehensive Income, Net of Taxes:
                
Cash Flow Hedges, Net of Tax of $749           1,391  1,391 
NET LOSS
        (5,357)    (5,357)
TOTAL COMPREHENSIVE LOSS
              (3,966)
                 
MARCH 31, 2006
 $157,230 $230,016 $157,205 $127 $544,578 
                 
DECEMBER 31, 2006
 $157,230 $230,016 $199,262 $(1,070)$585,438 
                 
FIN 48 Adoption, Net of Tax        (386)    (386)
Capital Contribution from Parent Company     20,000        20,000 
Preferred Stock Dividends        (53)    (53)
TOTAL
              604,999 
                 
COMPREHENSIVE LOSS
                
Other Comprehensive Income, Net of Taxes:
                
Cash Flow Hedges, Net of Tax of $24           45  45 
NET LOSS
        (20,426)    (20,426)
TOTAL COMPREHENSIVE LOSS
              (20,381)
                 
MARCH 31, 2007
 $157,230 $250,016 $178,397 $(1,025)$584,618 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
March 31, 2007 and December 31, 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
CURRENT ASSETS
    
Cash and Cash Equivalents $1,584 $1,651 
Accounts Receivable:       
Customers  51,680  70,319 
Affiliated Companies  73,191  73,318 
Miscellaneous  13,004  10,270 
Allowance for Uncollectible Accounts  (89) (5)
   Total Accounts Receivable  137,786  153,902 
Fuel  19,028  20,082 
Materials and Supplies  52,951  48,375 
Risk Management Assets  56,139  100,802 
Accrued Tax Benefits  25,206  4,679 
Regulatory Asset for Under-Recovered Fuel Costs  -  7,557 
Margin Deposits  22,705  35,270 
Prepayments and Other  5,718  5,732 
TOTAL
  321,117  378,050 
        
PROPERTY, PLANT AND EQUIPMENT
       
Electric:       
Production  1,095,466  1,091,910 
Transmission  505,326  503,638 
Distribution  1,248,077  1,215,236 
Other  237,383  234,227 
Construction Work in Progress  158,637  141,283 
Total
  3,244,889  3,186,294 
Accumulated Depreciation and Amortization  1,200,212  1,187,107 
TOTAL - NET
  2,044,677  1,999,187 
        
OTHER NONCURRENT ASSETS
       
Regulatory Assets  138,815  142,905 
Long-term Risk Management Assets  13,748  17,066 
Employee Benefits and Pension Assets  29,761  30,161 
Deferred Charges and Other  34,237  11,677 
TOTAL
  216,561  201,809 
        
TOTAL ASSETS
 $2,582,355 $2,579,046 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2007 and December 31, 2006
(Unaudited)

  
2007
 
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates $135,694 $76,323 
Accounts Payable:       
General  173,021  165,618 
Affiliated Companies  68,782  65,134 
Risk Management Liabilities  46,530  88,469 
Customer Deposits  41,404  51,335 
Accrued Taxes  35,144  19,984 
Regulatory Liability for Over-Recovered Fuel Costs  9,015  - 
Other  29,898  58,651 
TOTAL
  539,488  525,514 
        
NONCURRENT LIABILITIES
       
Long-term Debt - Nonaffiliated  670,042  669,998 
Long-term Risk Management Liabilities  8,514  11,448 
Deferred Income Taxes  407,365  414,197 
Regulatory Liabilities and Deferred Investment Tax Credits  306,194  315,584 
Deferred Credits and Other  60,872  51,605 
TOTAL
  1,452,987  1,462,832 
        
TOTAL LIABILITIES
  1,992,475  1,988,346 
        
Cumulative Preferred Stock Not Subject to Mandatory Redemption  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 
Paid-in Capital  250,016  230,016 
Retained Earnings  178,397  199,262 
Accumulated Other Comprehensive Income (Loss)  (1,025) (1,070)
TOTAL
  584,618  585,438 
        
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 $2,582,355 $2,579,046 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

  
2007
 
2006
 
OPERATING ACTIVITIES
       
Net Loss
 $(20,426)$(5,357)
Adjustments for Noncash Items:
       
Depreciation and Amortization  22,706  21,132 
Deferred Income Taxes  1,039  (23,436)
Mark-to-Market of Risk Management Contracts  3,108  9,106 
Deferred Property Taxes  (24,809) (24,295)
Change in Other Noncurrent Assets  4,393  11,118 
Change in Other Noncurrent Liabilities  (11,269) (20,806)
Changes in Certain Components of Working Capital:
       
Accounts Receivable, Net  16,116  33,852 
Fuel, Materials and Supplies  (3,513) (26)
Margin Deposits  12,565  5,065 
Accounts Payable  6,941  (77,217)
Customer Deposits  (9,931) (13,056)
Accrued Taxes, Net  (4,378) 34,196 
Fuel Over/Under Recovery, Net  16,572  74,281 
Other Current Assets  (139) 1,021 
Other Current Liabilities  (26,677) (23,048)
Net Cash Flows From (Used for) Operating Activities
  (17,702) 2,530 
        
INVESTING ACTIVITIES
       
Construction Expenditures  (61,301) (45,539)
Change in Other Cash Deposits, Net  (29) 6 
Proceeds from Sales of Assets  17  - 
Net Cash Flows Used For Investing Activities
  (61,313) (45,533)
        
FINANCING ACTIVITIES
     �� 
Capital Contributions from Parent Company  20,000  - 
Change in Advances from Affiliates, Net  59,371  42,932 
Principal Payments for Capital Lease Obligations  (370) (206)
Dividends Paid on Cumulative Preferred Stock  (53) (53)
Net Cash Flows From Financing Activities
  78,948  42,673 
        
Net Decrease in Cash and Cash Equivalents
  (67) (330)
Cash and Cash Equivalents at Beginning of Period
  1,651  1,520 
Cash and Cash Equivalents at End of Period
 $1,584 $1,190 

SUPPLEMENTARY INFORMATION
       
Cash Paid for Interest, Net of Capitalized Amounts $12,921 $8,681 
Net Cash Paid for Income Taxes  2,623  575 
Noncash Acquisitions Under Capital Leases  283  564 
Construction Expenditures Included in Accounts Payable at March 31,  19,038  6,052 

 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 PronouncementsNote 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
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

First Quarter ofSeptember 30, 2007 Compared to First Quarter ofNine Months Ended September 30, 2006

Reconciliation of First Quarter ofNine Months Ended September 30, 2006 to First Quarter ofNine Months Ended September 30, 2007
Net Income
(in millions)

First Quarter of 2006
    $18 
        
Changes in Gross Margin:
       
Retail and Off-system Sales Margins (a)  (1)   
Other  (4)   
Total Change in Gross Margin
     (5)
        
Changes in Operating Expenses and Other:
       
Other Operation and Maintenance  (6)   
Depreciation and Amortization  (1)   
Other Income  1    
Interest Expense  (3)   
Total Change in Operating Expenses and Other
     (9)
        
Income Tax Expense     6 
        
First Quarter of 2007
    $10 

(a)Includes firm wholesale sales to municipals and cooperatives.
Nine Months Ended September 30, 2006
    $51 
        
Changes in Gross Margin:
       
Retail and Off-system Sales Margins  3     
Transmission Revenues, Net  2     
Other  (1)    
Total Change in Gross Margin
      4 
         
Changes in Operating Expenses and Other:
        
Other Operation and Maintenance  (32)    
Depreciation and Amortization  (5)    
Taxes Other than Income Taxes  (6)    
Interest Expense  (7)    
Total Change in Operating Expenses and Other
      (50)
         
Income Tax Expense      17 
         
Nine Months Ended September 30, 2007
     $22 

Net Income decreased $8$29 million to $10$22 million in 2007.  The key drivers of the decrease were a $9$50 million increase in Operating Expenses and Other, and a $5 million decrease in Gross Margin,partially offset by a $6$17 million decrease in Income Tax Expense.Expense and a $4 million increase in Gross Margin.

The major componentcomponents of our decreasethe change in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power was a $4 million decrease in Other changes in gross margin, primarily due to lower gains on sales of emission allowances.were as follows:

·Retail and Off-system Sales Margins increased $3 million primarily due to an increase in retail margins attributable to new base rates.

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

·Other Operation and Maintenance expenses increased $32 million primarily due to an $18 million increase in distribution expense resulting primarily from the January 2007 ice storm and a $9 million increase in generation expense primarily due to scheduled maintenance outages.  Transmission expense increased $5 million primarily due to $4 million in higher SPP administration fees and transmission services from other utilities and $1 million in higher overhead line maintenance.
·Depreciation and Amortization increased $5 million primarily due to higher depreciable asset balances.
·Taxes Other Than Income Taxes increased $6 million primarily due to a $2 million increasesales and use tax adjustment recorded in generation operation and maintenance, a $1 million increase in transmission expenses due to higher SPP administration fees and a $1 million increase in administrative and general expenses, primarily associated with outside services and employee-related expenses.2006.
·Interest Expense increased $3$7 million primarily due to increased long-term debt.

Income Taxes

Income Tax Expense decreased $6 million primarily due to a decrease in pretax book income and state income taxes.
Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

Moody’s
S&P
Fitch
borrowings.
·
First Mortgage BondsA3A-A
Senior Unsecured DebtBaa1BBBA-Income Tax Expense decreased $17 million primarily due to a decrease in pretax book income.

Cash Flow

Cash flows for the three months ended March 31, 2007 and 2006 were as follows:

  
2007
 
2006
 
  
(in thousands)
 
Cash and Cash Equivalents at Beginning of Period
 $2,618 $3,049 
Cash Flows From (Used For):       
Operating Activities  65,590  41,293 
Investing Activities  (120,639) (54,294)
Financing Activities  54,331  12,501 
Net Decrease in Cash and Cash Equivalents
  (718) (500)
Cash and Cash Equivalents at End of Period
 $1,900 $2,549 

Operating Activities

Net Cash Flows From Operating Activities were $66 million in 2007. We produced Net Income of $10 million during the period and a noncash expense item of $34 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. The $36 million inflow from Accrued Taxes, Net was the result of increased accruals related to property and income taxes. The $22 million inflow from Margin Deposits was due to decreased trading-related deposits resulting from normal trading activities. The $20 million inflow from Accounts Receivable, Net was primarily due to the assignment of certain ERCOT contracts to an affiliate company.

Our Net Cash Flows From Operating Activities were $41 million in 2006. We produced Net Income of $18 million during the period and noncash expense items of $33 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items. The $27 million inflow from Accounts Receivable, Net was due to lower affiliated energy transactions. The $18 million outflow from Fuel, Materials and Supplies was the result of reduced fuel consumption during scheduled power plant outages. The $45 million inflow from Accrued Taxes, Net was due to increased income taxes. We did not make a federal income tax payment in 2006. The $16 million outflow from Customer Deposits was due to lower trading-related deposits. In addition, our cash flow related to Over/Under Fuel Recovery was favorably impacted by the new fuel surcharges effective December 2005 in our Arkansas service territory and in January 2006 in our Texas service territory. The $15 million outflow from Accounts Payable was the result of lower expenditures related to tree trimming and right-of-way clearing, energy purchases and general operations.

Investing Activities

Cash Flows Used For Investing Activities during 2007 and 2006 were $121 million and $54 million, respectively. The $108 million of cash flows for Construction Expenditures during 2007 were primarily related to new generation facilities. In addition, we had a net increase of $9 million in loans to the Utility Money Pool. The cash flows during 2006 were comprised primarily of Construction Expenditures related to projects for improved transmission and distribution service reliability.

Financing Activities

Cash Flows From Financing Activities were $54 million during 2007. We issued $250 million of Senior Unsecured Notes. We had a net decrease of $189 million in borrowings from the Utility Money Pool.

Cash Flows From Financing Activities were $13 million during 2006. We had a net increase of $21 million in borrowings from the Utility Money Pool. We paid $10 million in common stock dividends.

Financing Activity

Long-term debt issuances and retirements during the first three months of 2007 were:

Issuances
  
Principal
Amount Paid
 
Interest
 
Due
Type of Debt
  
Rate
 
Date
   
(in thousands)
 
(%)
  
Senior Unsecured Notes $250,000 5.55 2017

Retirements
  
Principal
Amount Paid
 
Interest
 
Due
Type of Debt
  
Rate
 
Date
   
(in thousands)
 
(%)
  
Notes Payable - Nonaffiliated $1,645 4.47 2011
Notes Payable - Nonaffiliated  4,000 6.36 2007
Notes Payable - Nonaffiliated  750 Variable 2008

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt or refinance long-term debt maturities. In addition, we participate in the Utility Money Pool, which provides access to AEP’s liquidity.

Summary Obligation Information

A summary of our contractual obligations is included in our 2006 Annual Report and has not changed significantly since year-end other than the debt issuance discussed in “Financing Activity” above and Energy and Capacity Purchase Contracts. Effective January 1, 2007, we transferred a significant amount of ERCOT energy marketing contracts to AEPEP; thereby decreasing our future obligations in Energy and Capacity Purchase Contracts. See “ERCOT Contracts Transferred to AEPEP” section of Note 1.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual 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 our pending litigation and regulatory proceedings, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies in our 2006 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 our results of operations, financial condition and cash flows.
New Generation

In December 2005, we sought proposals for new peaking, intermediate and base load generation to be online between 2008 and 2011. In May 2006, we announced plans to construct new generation to satisfy the demands of its customers. We will build up to 480 MW of simple-cycle natural gas combustion turbine peaking generation in Tontitown, Arkansas and will build a 480 MW combined-cycle natural gas fired plant at its existing Arsenal Hill Power Plant in Shreveport, Louisiana. We also plan to build a new 600 MW base load coal plant, of which our investment will be 73%, in Hempstead County, Arkansas by 2011 to meet the long-term generation needs of its customers. Preliminary cost estimates our share of the new facilities are approximately $1.4 billion (this total excludes the related transmission investment and AFUDC). These new facilities are subject to regulatory approvals from our three state commissions. The peaking generation facility in Tontitown, Arkansas has been approved by all three state commissions and Units 3 and 4 are projected to be online in July 2007 and the remaining two units by 2008. Construction is expected to begin in 2007 on the intermediate and base load facilities upon approval from the state regulatory commissions. Expenditures related to construction of these facilities are expected to total $349 million in 2007.

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

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2006 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

Our riskRisk management assets and liabilities are managed by AEPSC as agentagent.  The related risk management policies and procedures are instituted and administered by AEPSC.  See the complete discussion and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for us.disclosures about risk management activities.

VaR Associated with Debt Outstanding

Management utilizes a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period.  The risk of potential loss in fair value attributable to exposure to interest rates primarily related to long-term debt with fixed interest rates was $42 million and $39 million at September 30, 2007 and December 31, 2006, respectively.  Management would not expect to liquidate the entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect results of operations or financial position.

PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2007 and 2006
(in thousands)
(Unaudited)

  
Three Months Ended
  
Nine Months Ended
 
  
2007
  
2006
  
2007
  
2006
 
REVENUES
            
Electric Generation, Transmission and Distribution $433,737  $443,593  $1,028,637  $1,116,507 
Sales to AEP Affiliates  12,737   14,034   53,605   40,647 
Other  1,562   814   2,746   3,062 
TOTAL
  448,036   458,441   1,084,988   1,160,216 
                 
EXPENSES
                
Fuel and Other Consumables Used for Electric Generation  182,680   202,836   438,828   566,985 
Purchased Electricity for Resale  75,875   68,547   213,429   158,122 
Purchased Electricity from AEP Affiliates  16,216   17,706   48,679   54,817 
Other Operation  44,030   40,644   127,382   117,385 
Maintenance  24,128   25,072   89,390   67,412 
Depreciation and Amortization  24,430   22,215   70,128   65,060 
Taxes Other Than Income Taxes  10,007   3,844   30,191   23,997 
TOTAL
  377,366   380,864   1,018,027   1,053,778 
                 
OPERATING INCOME
  70,670   77,577   66,961   106,438 
                 
Other Income  1,086   1,050   2,294   1,830 
Interest Expense  (12,381)  (10,954)  (36,549)  (29,723)
                 
INCOME BEFORE INCOME TAXES
  59,375   67,673   32,706   78,545 
                 
Income Tax Expense  22,804   25,650   10,266   27,241 
                 
NET INCOME
  36,571   42,023   22,440   51,304 
                 
Preferred Stock Dividend Requirements  53   53   159   159 
                 
EARNINGS APPLICABLE TO COMMON STOCK
 $36,518  $41,970  $22,281  $51,145 

The common stock of PSO is owned by a wholly-owned subsidiary of 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 Nine Months Ended September 30, 2007 and 2006
(in thousands)
(Unaudited)

  
Common Stock
  
Paid-in Capital
  
Retained Earnings
  
Accumulated Other Comprehensive Income (Loss)
  
Total
 
DECEMBER 31, 2005
 $157,230  $230,016  $162,615  $(1,264) $548,597 
                     
Preferred Stock Dividends          (159)      (159)
TOTAL
                  548,438 
                     
COMPREHENSIVE INCOME
                    
Other Comprehensive Loss, Net of Taxes:
                    
Cash Flow Hedges, Net of Tax of $2              (4)  (4)
NET INCOME
          51,304       51,304 
TOTAL COMPREHENSIVE INCOME
                  51,300 
                     
SEPTEMBER 30, 2006
 $157,230  $230,016  $213,760  $(1,268) $599,738 
                     
DECEMBER 31, 2006
 $157,230  $230,016  $199,262  $(1,070) $585,438 
                     
FIN 48 Adoption, Net of Tax          (386)      (386)
Capital Contributions from Parent      60,000           60,000 
Preferred Stock Dividends          (159)      (159)
TOTAL
                  644,893 
                     
COMPREHENSIVE INCOME
                    
Other Comprehensive Income, Net of Taxes:
                    
Cash Flow Hedges, Net of Tax of $74              137   137 
NET INCOME
          22,440       22,440 
TOTAL COMPREHENSIVE INCOME
                  22,577 
                     
SEPTEMBER 30, 2007
 $157,230  $290,016  $221,157  $(933) $667,470 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2007 and December 31, 2006
(in thousands)
(Unaudited)

  
2007
  
2006
 
CURRENT ASSETS
   
Cash and Cash Equivalents $1,490  $1,651 
Accounts Receivable:        
  Customers  42,848   70,319 
  Affiliated Companies  94,920   73,318 
  Miscellaneous  47,769   10,270 
  Allowance for Uncollectible Accounts  (18)  (5)
 Total Accounts Receivable  185,519   153,902 
Fuel  17,922   20,082 
Materials and Supplies  52,655   48,375 
Risk Management Assets  43,004   100,802 
Accrued Tax Benefits  9,499   4,679 
Regulatory Asset for Under-Recovered Fuel Costs  15,817   7,557 
Margin Deposits  2,526   35,270 
Prepayments and Other  4,424   5,732 
TOTAL
  332,856   378,050 
         
PROPERTY, PLANT AND EQUIPMENT
        
Electric:        
  Production  1,106,110   1,091,910 
  Transmission  556,760   503,638 
  Distribution  1,311,738   1,215,236 
Other  243,575   234,227 
Construction Work in Progress  158,499   141,283 
Total
  3,376,682   3,186,294 
Accumulated Depreciation and Amortization  1,212,294   1,187,107 
TOTAL - NET
  2,164,388   1,999,187 
         
OTHER NONCURRENT ASSETS
        
Regulatory Assets  156,708   142,905 
Long-term Risk Management Assets  5,329   17,066 
Employee Benefits and Pension Assets  28,962   30,161 
Deferred Charges and Other  17,386   11,677 
TOTAL
  208,385   201,809 
         
TOTAL ASSETS
 $2,705,629  $2,579,046 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2007 and December 31, 2006
(Unaudited)

  
2007
  
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates $187,492  $76,323 
Accounts Payable:        
General  173,364   165,618 
Affiliated Companies  69,044   65,134 
Risk Management Liabilities  31,867   88,469 
Customer Deposits  42,891   51,335 
Accrued Taxes  43,540   19,984 
Other  32,376   58,651 
TOTAL
  580,574   525,514 
         
NONCURRENT LIABILITIES
        
Long-term Debt – Nonaffiliated  670,132   669,998 
Long-term Risk Management Liabilities  5,483   11,448 
Deferred Income Taxes  430,307   414,197 
Regulatory Liabilities and Deferred Investment Tax Credits  284,970   315,584 
Deferred Credits and Other  61,431   51,605 
TOTAL
  1,452,323   1,462,832 
         
TOTAL LIABILITIES
  2,032,897   1,988,346 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  5,262   5,262 
         
Commitments and Contingencies (Note 4)        
         
COMMON SHAREHOLDER’S EQUITY
        
Common Stock – Par Value – $15 Per Share:        
Authorized – 11,000,000 Shares        
Issued – 10,482,000 Shares        
Outstanding – 9,013,000 Shares  157,230   157,230 
Paid-in Capital  290,016   230,016 
Retained Earnings  221,157   199,262 
Accumulated Other Comprehensive Income (Loss)  (933)  (1,070)
TOTAL
  667,470   585,438 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 $2,705,629  $2,579,046 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2007 and 2006
(in thousands)
(Unaudited)

  
2007
  
2006
 
OPERATING ACTIVITIES
      
Net Income
 $22,440  $51,304 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
        
Depreciation and Amortization  70,128   65,060 
Deferred Income Taxes  23,220   (18,661)
Mark-to-Market of Risk Management Contracts  6,968   8,901 
Deferred Property Taxes  (8,353)  (8,098)
Change in Other Noncurrent Assets  (10,050)  17,850 
Change in Other Noncurrent Liabilities  (31,165)  (24,838)
Changes in Certain Components of Working Capital:
        
Accounts Receivable, Net  (31,617)  (2,389)
Fuel, Materials and Supplies  (2,110)  (6,990)
Margin Deposits  32,744   (25,811)
Accounts Payable  10,226   1,585 
Customer Deposits  (8,444)  (2,737)
Accrued Taxes, Net  19,725   48,845 
Fuel Over/Under Recovery, Net  (8,260)  76,938 
Other Current Assets  177   (3,828)
Other Current Liabilities  (23,587)  (13,755)
Net Cash Flows From Operating Activities
  62,042   163,376 
         
INVESTING ACTIVITIES
        
Construction Expenditures  (235,089)  (140,998)
Change in Advances to Affiliates, Net  -   (43,538)
Other  3,173   6 
Net Cash Flows Used For Investing Activities
  (231,916)  (184,530)
         
FINANCING ACTIVITIES
        
Capital Contributions from Parent  60,000   - 
Issuance of Long-term Debt – Nonaffiliated  12,488   148,747 
Change in Advances from Affiliates, Net  111,169   (75,883)
Retirement of Long-term Debt – Affiliated  (12,660)  (50,000)
Principal Payments for Capital Lease Obligations  (1,125)  (794)
Dividends Paid on Cumulative Preferred Stock  (159)  (159)
Net Cash Flows From Financing Activities
  169,713   21,911 
         
Net Increase (Decrease) in Cash and Cash Equivalents
  (161)  757 
Cash and Cash Equivalents at Beginning of Period
  1,651   1,520 
Cash and Cash Equivalents at End of Period
 $1,490  $2,277 
         
SUPPLEMENTARY INFORMATION
        
Cash Paid for Interest, Net of Capitalized Amounts $34,427  $25,491 
Net Cash Paid (Received) for Income Taxes  (18,004)  7,471 
Noncash Acquisitions Under Capital Leases  600   2,639 
Construction Expenditures Included in Accounts Payable at September 30,  16,358   6,591 

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
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Third Quarter of 2007 Compared to Third Quarter of 2006

Reconciliation of Third Quarter of 2006 to Third Quarter of 2007
Net Income
(in millions)

Third Quarter of 2006
    $50 
        
Changes in Gross Margin:
       
Retail and Off-system Sales Margins (a)  (1)    
Transmission Revenues, Net  1     
Other  (7)    
Total Change in Gross Margin
      (7)
         
Changes in Operating Expenses and Other:
        
Other Operation and Maintenance  (7)    
Depreciation and Amortization  (1)    
Other Income  3     
Interest Expense  (2)    
Total Change in Operating Expenses and Other
      (7)
         
Income Tax Expense      8 
         
Third Quarter of 2007
     $44 

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

Net Income decreased $6 million to $44 million in 2007.  The key drivers of the decrease were a $7 million decrease in Gross Margin and a $7 million increase in Operating Expenses and Other, partially offset by an $8 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:

·Other revenues decreased $7 million primarily due to a $5 million decrease in gains on sales of emission allowances and a $1 million decrease in revenue from coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite Company, LLC, to outside parties.  The decreased revenue from coal deliveries was offset by a corresponding decrease in Other Operation and Maintenance expenses from mining operations as discussed below.

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

·Other Operation and Maintenance expenses increased $7 million primarily due to a $5 million increase in transmission expenses resulting from higher SPP administration fees and transmission services from other utilities, and a $3 million increase in generation expenses due to planned and forced outages at the Welsh, Dolet Hills, Flint Creek, Knox Lee and Pirkey Plants.  These increases were partially offset by a $1 million decrease in expenses primarily resulting from decreased coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite Company, LLC, due to planned and forced outages at the Dolet Hills Generating Station, which is jointly-owned by SWEPCo and Cleco Corporation, a nonaffiliated entity.
·Other Income increased $3 million primarily due to an increase in the equity component of AFUDC as a result of new generation projects.
·Interest Expense increased $2 million primarily due to $4 million of interest related to increased long-term debt partially offset by a $2 million increase in the debt component of AFUDC due to new generation projects.
·Income Tax Expense decreased $8 million primarily due to a decrease in pretax book income and state income taxes.
Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

Reconciliation of Nine Months Ended September 30, 2006 to Nine Months Ended September 30, 2007
Net Income
(in millions)

Nine Months Ended September 30, 2006
    $96 
        
Changes in Gross Margin:
       
Retail and Off-system Sales Margins (a)  (29)    
Other  (15)    
Total Change in Gross Margin
      (44)
         
Changes in Operating Expenses and Other:
        
Other Operation and Maintenance  (17)    
Depreciation and Amortization  (5)    
Taxes Other Than Income Taxes  (1)    
Other Income  7     
Interest Expense  (8)    
Total Change in Operating Expenses and Other
      (24)
         
Minority Interest Expense      (1)
Income Tax Expense      28 
         
Nine Months Ended September 30, 2007
     $55 

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

Net Income decreased $41 million to $55 million in 2007.  The key drivers of the decrease were a $44 million decrease in Gross Margin and a $24 million increase in Operating Expenses and Other, offset by a $28 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 $29 million primarily due to a $24 million provision related to a SWEPCo Texas fuel reconciliation proceeding.  See “SWEPCo Fuel Reconciliation – Texas” section of Note 3.
·Other revenues decreased $15 million primarily due to an $8 million decrease in gains on sales of emission allowances and a $7 million decrease in revenue from coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite Company, LLC, to outside parties.  The decreased revenue from coal deliveries was offset by a corresponding decrease in Other Operation and Maintenance expenses from mining operations as discussed below.

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

·Other Operation and Maintenance expenses increased $17 million primarily due to the following:
·A $9 million increase in generation expenses from planned and forced outages at the Welsh, Dolet Hills, Flint Creek, Knox Lee and Pirkey Plants.
·An $8 million increase in transmission expenses related to higher SPP administration fees and transmission services from other utilities.
·A  $6 million increase in distribution expenses including increased overhead line maintenance.
These increases were partially offset by:
·An $8 million decrease in expenses primarily resulting from decreased coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite Company, LLC, due to planned and forced outages at the Dolet Hills Generating Station, which is jointly-owned by SWEPCo and Cleco Corporation, a nonaffiliated entity.
·Other Income increased $7 million primarily due to an increase in the equity component of AFUDC as a result of new generation projects.
·Interest Expense increased $8 million primarily due to $13 million of interest related to increased long-term debt partially offset by a $5 million increase in the debt component of AFUDC due to new generation projects.
·Income Tax Expense decreased $28 million primarily due to a decrease in pretax book income.

Financial Condition

Credit Ratings

The rating agencies currently have SWEPCo on stable outlook.  Current ratings are as follows:

Moody’s
S&P
Fitch
Senior Unsecured DebtBaa1BBB A-

Cash Flow

Cash flows for the nine months ended September 30, 2007 and 2006 were as follows:

  
2007
  
2006
 
  
(in thousands)
 
Cash and Cash Equivalents at Beginning of Period
 $2,618  $3,049 
Cash Flows From (Used For):        
Operating Activities  180,146   242,721 
Investing Activities  (353,001)  (186,631)
Financing Activities  172,089   (56,343)
Net Decrease in Cash and Cash Equivalents
  (766)  (253)
Cash and Cash Equivalents at End of Period
 $1,852  $2,796 

Operating Activities

Net Cash Flows From Operating Activities were $180 million in 2007.  SWEPCo produced Net Income of $55 million during the period and had noncash expense items of $103 million for Depreciation and Amortization and $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 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 $48 million inflow from Accounts Receivable, Net was primarily due to the assignment of certain ERCOT contracts to an affiliate company.  The $37 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.

Net Cash Flows From Operating Activities were $243 million in 2006.  SWEPCo produced Net Income of $96 million during the period and had noncash expense items of $99 million for Depreciation and Amortization.  The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The activity in working capital relates to a number of items.  The $54 million inflow from Accounts Payable was the result of higher energy purchases.  The $28 million outflow for Margin Deposits was due to increased trading-related deposits resulting from the amended SIA.  In addition, the $64 million inflow related to Over/Under Fuel Recovery was primarily due to the new fuel surcharges effective December 2005 in SWEPCo’s Arkansas service territory and in January 2006 in SWEPCo’s Texas service territory.  The $27 million outflow from Fuel, Materials and Supplies was the result of increased fuel purchases.

Investing Activities

Net Cash Flows Used For Investing Activities during 2007 and 2006 were $353 million and $187 million, respectively.  The $353 million of cash flows for Construction Expenditures during 2007 were primarily related to new generation facilities.  The cash flows during 2006 were comprised primarily of Construction Expenditures related to projects for improved transmission and distribution service reliability as well as projects related to generation facilities.  Based upon SWEPCo’s current forecast, SWEPCo expects construction expenditures to be approximately $210 million for the remainder of 2007, excluding AFUDC.

Financing Activities

Net Cash Flows From Financing Activities were $172 million during 2007.  SWEPCo issued $250 million of Senior Unsecured Notes and retired $90 million of First Mortgage Bonds.  SWEPCo received a Capital Contribution from Parent of $55 million.  SWEPCo also reduced its borrowings from the Utility Money Pool by $33 million.

Net Cash Flows Used for Financing Activities were $56 million during 2006.  SWEPCo refinanced $82 million of Pollution Control Bonds.  SWEPCo reduced its borrowings from the Utility Money Pool by $28 million and paid $30 million in common stock dividends.
Financing Activity

Long-term debt issuances and retirements during the first nine months of 2007 were:

Issuances
  
Principal
Amount
 
Interest
 
Due
Type of Debt
  
Rate
 
Date
   
(in thousands)
 
(%)
  
Senior Unsecured Notes $250,000 5.55 2017

Retirements
  
Principal
Amount
 
Interest
 
Due
Type of Debt
  
Rate
 
Date
   
(in thousands)
 
(%)
  
Notes Payable – Nonaffiliated $4,210 4.47 2011
Notes Payable – Nonaffiliated  4,000 6.36 2007
Notes Payable – Nonaffiliated  2,250 Variable 2008
First Mortgage Bonds  90,000 7.00 2007

Liquidity

SWEPCo has solid investment grade ratings, which provides ready access to capital markets in order to issue new debt or refinance long-term debt maturities.  In addition, SWEPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity.

Summary Obligation Information

A summary of SWEPCo’s contractual obligations is included in its 2006 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, Energy and Capacity Purchase Contracts, and contractual commitments related to the proposed Turk Plant.  Effective January 1, 2007, SWEPCo transferred a significant amount of ERCOT energy marketing contracts to AEP Energy Partners (AEPEP), thereby decreasing its future obligations in Energy and Capacity Purchase Contracts.  See “ERCOT Contracts Transferred to AEPEP” section of Note 1.  SWEPCo has entered into additional contractual commitments related to the construction of the proposed Turk Plant announced in August 2006.  See “Turk Plant” in the “Arkansas Rate Matters” section of Note 3.

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, SWEPCo 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 pending litigation and regulatory proceedings, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2006 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 SWEPCo’s results of operations, financial condition and cash flows.

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

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2006 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 us.SWEPCo.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in ourthe condensed consolidated balance sheet as of March 31,September 30, 2007 and the reasons for changes in our total MTM value as compared to December 31, 2006.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of March 31,September 30, 2007
(in thousands)

 
MTM Risk Management Contracts
 
Cash Flow Hedges
 
Total
  
MTM Risk Management Contracts
  
Cash Flow Hedges
  
Total
 
Current Assets $66,352 $582 $66,934  $51,042  $75  $51,117 
Noncurrent Assets  16,264  37  16,301   6,481   33   6,514 
Total MTM Derivative Contract Assets
  82,616  619  83,235   57,523   108   57,631 
                      
Current Liabilities  (55,257) (6) (55,263)  (38,334)  (11)  (38,345)
Noncurrent Liabilities  (10,158) (16) (10,174)  (6,729)  -   (6,729)
Total MTM Derivative Contract Liabilities
  (65,415) (22) (65,437)  (45,063)  (11)  (45,074)
                      
Total MTM Derivative Contract Net Assets (Liabilities)
 $17,201 $597 $17,798  $12,460  $97  $12,557 

MTM Risk Management Contract Net Assets
ThreeNine Months Ended March 31,September 30, 2007
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2006
 $20,166  $20,166 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period  (1,013) (3,501)
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  -  - 
Changes in Fair Value Due to Market Fluctuations During the Period (b)  21  1,201 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)  (1,973)  (5,406)
Total MTM Risk Management Contract Net Assets
  17,201  12,460 
Net Cash Flow Hedge Contracts  597   97 
Total MTM Risk Management Contract Net Assets at March 31, 2007
 $17,798 
Total MTM Risk Management Contract Net Assets at September 30, 2007
 $12,557 

(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)Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)“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 liabilities/assets for those subsidiaries that operate in regulated jurisdictions.

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

The following table presents:

·The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
·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
Fair Value of Contracts as of March 31,September 30, 2007
(in thousands)

  
Remainder
2007
 
2008
 
2009
 
2010
 
2011
 
After
2011
 
Total
 
Prices Actively Quoted - Exchange Traded Contracts $(16,029)$1,742 $(283)$- $- $- $(14,570)
Prices Provided by Other External
   Sources - OTC Broker Quotes (a)
  29,194  4,143  (813) -  -  -  32,524 
Prices Based on Models and Other
   Valuation Methods (b)
  (2,551) 335  1,461  2  -  -  (753)
Total
 $10,614 $6,220 $365 $2 $- $- $17,201 
  
Remainder
2007
 
2008
 
2009
 
2010
 
2011
 
After
2011
 
Total
 
Prices Actively Quoted – Exchange
 Traded Contracts
 $(3,730)$1,544 $(237)$(8)$- $- $(2,431)
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)
  10,247  5,930  (728) -  -  -  15,449 
Prices Based on Models and Other
 Valuation Methods (b)
  (772) (1,286) 1,502  (2) -  -  (558)
Total
 $5,745 $6,188 $537 $(10)$- $- $12,460 

(a)“Prices Provided by Other External Sources -– OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)“Prices Based on Models and Other Valuation Methods” is used in absence of pricingindependent information from external sources.  Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources.  In addition, where external pricing information or market liquidity are limited, such valuations are classified as modeled.  The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.
Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available.available including values determinable by other third party transactions.

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

We areSWEPCo is exposed to market fluctuations in energy commodity prices impacting our power operations.  We monitorManagement monitors 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 doManagement does not hedge all commodity price risk.

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

We use forward contracts and collars as cash flow hedgesManagement uses foreign currency derivatives to lock in prices on certain transactions denominated in foreign currencies where deemed necessary. We donecessary, and designate qualifying instruments as cash flow hedge strategies.  Management does not hedge all foreign currency exposure.currency.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on ourthe Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2006 to March 31,September 30, 2007.  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
ThreeNine Months Ended March 31,September 30, 2007
(in thousands)

 
Interest Rate
 
Foreign
Currency
 
Total
  
Interest Rate
  
Foreign
Currency
  
Total
 
Beginning Balance in AOCI December 31, 2006
 $(6,435)$25 $(6,410) $(6,435) $25  $(6,410)
Changes in Fair Value  (1,019) 509  (510)  (1,019)  589   (430)
Reclassifications from AOCI to Net Income for
Cash Flow Hedges Settled
  183  -  183   598   -   598 
Ending Balance in AOCI March 31, 2007
 $(7,271)$534 $(6,737)
Ending Balance in AOCI September 30, 2007
 $(6,856) $614  $(6,242)

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $249$829 thousand loss.

Credit Risk

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

VaR Associated with Risk Management Contracts

We useManagement uses 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 March 31,September 30, 2007, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, 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:

Three Months Ended March 31, 2007
    
Twelve Months Ended December 31, 2006
(in thousands)
    
(in thousands)
End
 
High
 
Average
 
Low
    
End
 
High
 
Average
 
Low
$83 $245 $100 $25    $447 $2,171 $794 $68

The High VaR for the twelve months ended December 31, 2006 occurred in the fourth quarter due to volatility in the ERCOT region.
Nine Months Ended September 30, 2007
  
Twelve Months Ended December 31, 2006
 
(in thousands)
  
(in thousands)
 
End
  
High
  
Average
  
Low
  
End
  
High
  
Average
  
Low
 
$26  $245  $92  $23  $447  $2,171  $794  $68 

VaR Associated with Debt Outstanding

WeManagement also utilizeutilizes a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period.  The risk of potential loss in fair value attributable to our exposure to interest rates primarily related to long-term debt with fixed interest rates was $43$41 million and $25 million at March 31,September 30, 2007 and December 31, 2006, respectively.  WeManagement would not expect to liquidate ourthe entire debt portfolio in a one-year holding period; therefore, a near term change in interest rates should not negatively affect our results of operations or consolidated financial position.


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended March 31,September 30, 2007 and 2006
(in thousands)
(Unaudited)

 
Three Months Ended
  
Nine Months Ended
 
 
2007
 
2006
  
2007
  
2006
  
2007
  
2006
 
REVENUES
                 
Electric Generation, Transmission and Distribution $327,284 $293,993  $445,169  $440,542  $1,101,703  $1,084,185 
Sales to AEP Affiliates  16,415  10,765   2,839   14,692   35,491   34,871 
Other  400  374   502   1,466   1,437   2,260 
TOTAL
  344,099  305,132   448,510   456,700   1,138,631   1,121,316 
                       
EXPENSES
                       
Fuel and Other Consumables Used for Electric Generation  111,987  90,661   141,837   158,992   379,818   367,924 
Purchased Electricity for Resale  52,498  29,218   73,438   61,816   182,806   135,918 
Purchased Electricity from AEP Affiliates  22,917  23,337   22,282   18,140   61,284   58,303 
Other Operation  53,783  49,700   59,759   55,173   163,746   158,089 
Maintenance  26,339  24,657   23,205   21,120   79,265   68,008 
Depreciation and Amortization  34,122  32,617   34,605   33,079   103,395   98,655 
Taxes Other Than Income Taxes  15,991  15,982   16,767   17,107   50,298   49,254 
TOTAL
  317,637  266,172   371,893   365,427   1,020,612   936,151 
                       
OPERATING INCOME
  26,462  38,960   76,617   91,273   118,019   185,165 
                       
Other Income (Expense):
                       
Interest Income  705  543   518   822   1,999   2,277 
Allowance for Equity Funds Used During Construction  1,391  185   3,681   287   7,634   400 
Interest Expense  (15,490) (12,771)  (15,966)  (13,844)  (48,691)  (40,688)
                       
INCOME BEFORE INCOME TAXES AND MINORITY
INTEREST EXPENSE
  13,068  26,917   64,850   78,538   78,961   147,154 
                       
Income Tax Expense  2,621  8,823   19,811   27,873   20,879   49,187 
Minority Interest Expense  842  222   919   959   2,733   2,077 
                       
NET INCOME
  9,605  17,872   44,120   49,706   55,349   95,890 
                       
Preferred Stock Dividend Requirements  57  57   58   57   172   172 
                       
EARNINGS APPLICABLE TO COMMON STOCK
 $9,548 $17,815  $44,062  $49,649  $55,177  $95,718 

The common stock of SWEPCo is owned by a wholly-owned subsidiary of AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
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 ThreeNine Months Ended March 31,September 30, 2007 and 2006
(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, 2005
 $135,660 $245,003 $407,844 $(6,129)$782,378  $135,660  $245,003  $407,844  $(6,129) $782,378 
                                
Common Stock Dividends      (10,000)   (10,000)          (30,000)      (30,000)
Preferred Stock Dividends        (57)    (57)          (172)      (172)
TOTAL
              772,321                   752,206 
                                
COMPREHENSIVE INCOME
                                    
Other Comprehensive Income, Net of Taxes:
            
Cash Flow Hedges, Net of Tax of $930        1,728 1,728 
Other Comprehensive Loss, Net of Taxes:
                    
Cash Flow Hedges, Net of Tax of $817              (1,516)  (1,516)
NET INCOME
        17,872     17,872           95,890       95,890 
TOTAL COMPREHENSIVE INCOME
              19,600                   94,374 
                                
MARCH 31, 2006
 $135,660 $245,003 $415,659 $(4,401)$791,921 
SEPTEMBER 30, 2006
 $135,660  $245,003  $473,562  $(7,645) $846,580 
                                
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      55,000           55,000 
Preferred Stock Dividends        (57)    (57)          (172)      (172)
TOTAL
              819,503                   874,388 
                                
COMPREHENSIVE INCOME
                                    
Other Comprehensive Loss, Net of Taxes:
            
Cash Flow Hedges, Net of Tax of $39        (327) (327)
Other Comprehensive Income, Net of Taxes:
                    
Cash Flow Hedges, Net of Tax of $90              168   168 
NET INCOME
        9,605     9,605           55,349       55,349 
TOTAL COMPREHENSIVE INCOME
              9,278                   55,517 
                                
MARCH 31, 2007
 $135,660 $245,003 $467,244 $(19,126)$828,781 
SEPTEMBER 30, 2007
 $135,660  $300,003  $512,873  $(18,631) $929,905 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31,September 30, 2007 and December 31, 2006
(in thousands)
(Unaudited)

 
2007
 
2006
  
2007
  
2006
 
CURRENT ASSETS
             
Cash and Cash Equivalents $1,900 $2,618  $1,852  $2,618 
Advances to Affiliates  8,959  - 
Accounts Receivable:               
Customers  74,382  88,245   50,382   88,245 
Affiliated Companies  48,598  59,679   47,982   59,679 
Miscellaneous  13,077  8,595   10,057   8,595 
Allowance for Uncollectible Accounts  (137) (130)  (24)  (130)
Total Accounts Receivable  135,920  156,389   108,397   156,389 
Fuel  73,479  69,426   78,295   69,426 
Materials and Supplies  46,101  46,001   48,716   46,001 
Risk Management Assets  66,934  120,036   51,117   120,036 
Regulatory Asset for Under-Recovered Fuel Costs  7,300   - 
Margin Deposits  19,353  41,579   4,199   41,579 
Prepayments and Other  28,581  18,256   19,925   18,256 
TOTAL
  381,227  454,305   319,801   454,305 
               
PROPERTY, PLANT AND EQUIPMENT
               
Electric:               
Production  1,586,238  1,576,200   1,650,597   1,576,200 
Transmission  690,384  668,008   719,033   668,008 
Distribution  1,262,203  1,228,948   1,298,926   1,228,948 
Other  611,255  595,429   627,145   595,429 
Construction Work in Progress  301,251  259,662   412,704   259,662 
Total
  4,451,331  4,328,247   4,708,405   4,328,247 
Accumulated Depreciation and Amortization  1,868,974  1,834,145   1,910,411   1,834,145 
TOTAL - NET
  2,582,357  2,494,102   2,797,994   2,494,102 
               
OTHER NONCURRENT ASSETS
               
Regulatory Assets  153,080  156,420   131,264   156,420 
Long-term Risk Management Assets  16,301  20,531   6,514   20,531 
Employee Benefits and Pension Assets  25,302  26,029 
Deferred Charges and Other  68,855  39,581   75,529   65,610 
TOTAL
  263,538  242,561   213,307   242,561 
               
TOTAL ASSETS
 $3,227,122 $3,190,968  $3,331,102  $3,190,968 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31,September 30, 2007 and December 31, 2006
(Unaudited)

 
2007
 
2006
  
2007
  
2006
 
CURRENT LIABILITIES
 
(in thousands)
  
(in thousands)
 
Advances from Affiliates $- $188,965  $155,869  $188,965 
Accounts Payable:               
General  155,206  140,424   136,071   140,424 
Affiliated Companies  72,448  68,680   65,692   68,680 
Short-term Debt - Nonaffiliated  20,433  17,143 
Long-term Debt Due Within One Year - Nonaffiliated  97,768  102,312 
Short-term Debt – Nonaffiliated  25,897   17,143 
Long-term Debt Due Within One Year – Nonaffiliated  6,655   102,312 
Risk Management Liabilities  55,263  109,578   38,345   109,578 
Customer Deposits  36,798  48,277   39,225   48,277 
Accrued Taxes  64,418  31,591   54,784   31,591 
Regulatory Liability for Over-Recovered Fuel Costs  33,791  26,012   30,495   26,012 
Other  66,871  85,086   67,680   85,086 
TOTAL
  602,996  818,068   620,713   818,068 
               
NONCURRENT LIABILITIES
               
Long-term Debt - Nonaffiliated  822,519  576,694 
Long-term Debt - Affiliated  50,000  50,000 
Long-term Debt – Nonaffiliated  818,429   576,694 
Long-term Debt – Affiliated  50,000   50,000 
Long-term Risk Management Liabilities  10,174  14,083   6,729   14,083 
Deferred Income Taxes  362,321  374,548   354,175   374,548 
Regulatory Liabilities and Deferred Investment Tax Credits  347,951  346,774   330,070   346,774 
Deferred Credits and Other  196,064  183,087   214,505   183,087 
TOTAL
  1,789,029  1,545,186   1,773,908   1,545,186 
               
TOTAL LIABILITIES
  2,392,025  2,363,254   2,394,621   2,363,254 
               
Minority Interest  1,619  1,815   1,879   1,815 
               
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 
Common Stock – Par Value – $18 Per Share:        
Authorized – 7,600,000 Shares        
Outstanding – 7,536,640 Shares  135,660   135,660 
Paid-in Capital  245,003  245,003   300,003   245,003 
Retained Earnings  467,244  459,338   512,873   459,338 
Accumulated Other Comprehensive Income (Loss)  (19,126) (18,799)  (18,631)  (18,799)
TOTAL
  828,781  821,202   929,905   821,202 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 $3,227,122 $3,190,968  $3,331,102  $3,190,968 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the ThreeNine Months Ended March 31,September 30, 2007 and 2006
(in thousands)
(Unaudited)

 
2007
 
2006
  
2007
  
2006
 
OPERATING ACTIVITIES
             
Net Income
 $9,605 $17,872  $55,349  $95,890 
Adjustments for Noncash Items:
       
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
        
Depreciation and Amortization  34,122  32,617   103,395   98,655 
Deferred Income Taxes  (6,677) (9,101)  (17,863)  (24,642)
Provision for Fuel Disallowance  24,074   - 
Mark-to-Market of Risk Management Contracts  2,965  10,468   7,706   10,870 
Deferred Property Taxes  (28,815) (28,997)  (9,172)  (9,438)
Change in Other Noncurrent Assets  (3,198) 9,458   2,536   20,733 
Change in Other Noncurrent Liabilities  (178) (19,121)  (7,134)  (33,256)
Changes in Certain Components of Working Capital:
               
Accounts Receivable, Net  20,469  26,848   47,992   (9,872)
Fuel, Materials and Supplies  (4,141) (17,521)  (11,572)  (26,739)
Margin Deposits  22,226  7,915   37,380   (28,492)
Accounts Payable  13,806  (15,304)  (21,603)  54,264 
Customer Deposits  (11,479) (15,861)
Accrued Taxes, Net  36,113  45,238   25,556   45,514 
Fuel Over/Under Recovery, Net  4,212  15,216   (26,891)  63,862 
Other Current Assets  (2,868) 2,821   (687)  2,635 
Other Current Liabilities  (20,572) (21,255)  (28,920)  (17,263)
Net Cash Flows From Operating Activities
  65,590  41,293   180,146   242,721 
               
INVESTING ACTIVITIES
               
Construction Expenditures  (107,613) (54,238)  (353,107)  (179,117)
Change in Advances to Affiliates, Net  (8,959) -   -   (7,018)
Other  (4,067) (56)  106   (496)
Net Cash Flows Used For Investing Activities
  (120,639) (54,294)  (353,001)  (186,631)
               
FINANCING ACTIVITIES
               
Issuance of Long-term Debt - Nonaffiliated  247,548  - 
Change in Short-term Debt, Net - Nonaffiliated  3,290  4,394 
Capital Contribution from Parent  55,000   - 
Issuance of Long-term Debt – Nonaffiliated  247,496   80,593 
Change in Short-term Debt, Net – Nonaffiliated  8,754   14,282 
Change in Advances from Affiliates, Net  (188,965) 20,988   (33,096)  (28,210)
Retirement of Long-term Debt - Nonaffiliated  (6,395) (2,457)
Retirement of Long-term Debt – Nonaffiliated  (100,460)  (88,989)
Retirement of Cumulative Preferred Stock  -   (2)
Principal Payments for Capital Lease Obligations  (1,090) (367)  (5,433)  (3,845)
Dividends Paid on Common Stock  -  (10,000)  -   (30,000)
Dividends Paid on Cumulative Preferred Stock  (57) (57)  (172)  (172)
Net Cash Flows From Financing Activities
  54,331  12,501 
Net Cash Flows From (Used For) Financing Activities
  172,089   (56,343)
               
Net Decrease in Cash and Cash Equivalents
  (718) (500)  (766)  (253)
Cash and Cash Equivalents at Beginning of Period
  2,618  3,049   2,618   3,049 
Cash and Cash Equivalents at End of Period
 $1,900 $2,549  $1,852  $2,796 
        
SUPPLEMENTARY INFORMATION
        
Cash Paid for Interest, Net of Capitalized Amounts $44,662  $37,372 
Net Cash Paid for Income Taxes  37,479   53,509 
Noncash Acquisitions Under Capital Leases  19,567   17,110 
Construction Expenditures Included in Accounts Payable at September 30,  41,978   8,924 

SUPPLEMENTARY INFORMATION
       
Cash Paid for Interest, Net of Capitalized Amounts $16,747 $11,892 
Net Cash Paid for Income Taxes  580  1,282 
Noncash Acquisitions Under Capital Leases  3,192  3,412 
Construction Expenditures Included in Accounts Payable at March 31,  32,460  12,800 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

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 MattersAEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo TCC, TNC
2.New Accounting Pronouncements and Extraordinary ItemAEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo TCC, TNC
3.Rate MattersAPCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo TCC, TNC
4.Commitments, Guarantees and ContingenciesAEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo TCC, TNC
5.Acquisitions, Dispositions and Assets Held for SaleAcquisitionAEGCo, CSPCo TCC
6.Benefit PlansAPCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo TCC, TNC
7.Business SegmentsAEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo TCC, TNC
8.Income TaxesAEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo TCC, TNC
9.Financing ActivitiesAEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo TCC, TNC


         1.
1.
SIGNIFICANT ACCOUNTING MATTERS

General

The accompanying unaudited condensed financial statements and footnotes were prepared in accordance with accounting principles generally accepted in the United States of America (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, financial position and cash flows for the interim periods for each Registrant Subsidiary.  The results of operations for the threenine months March 31,ended September 30, 2007 are not necessarily indicative of results that may be expected for the year ending December 31, 2007.  The accompanying condensed financial statements are unaudited and should be read in conjunction with the audited 2006 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2006 as filed with the SEC on February 28, 2007.

Property, Plant and Equipment and Equity Investments

Electric utility property, plant and equipment are stated at original purchase cost. Property, plant and equipment of nonregulated operations and other investments are stated at fair market value at acquisition (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals.  Additions, major replacements and betterments are added to the plant accounts.  Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for both cost-based rate-regulated and nonregulated operations under the group composite method of depreciation.  The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss.  The equipment in each primary electric plant account is identified as a separate group.  Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in the original cost, less salvage, being charged to accumulated depreciation.  For the nonregulated generation assets, a gain or loss would be recorded if the retirement is not considered an interim routine replacement.  The depreciation rates that are established for the generating plants take into account the past history of interim capital replacements and the amount of salvage received.  These rates and the related lives are subject to periodic review.  Removal costs are charged to regulatory liabilities for cost-based rate-regulated operations and charged to expense for nonregulated operations.  The costs of labor, materials and overhead incurred to operate and maintain the plants are included in operating expenses.

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held for sale criteria under SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.”  Equity investments are required to be tested for impairment when it is determined there may be an other than temporary loss in value.

The fair value of an asset or investment is the amount at which that asset or investment could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets or investments in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.

Inventory

Fossil fuel inventories are carried at average cost for APCo, I&M, and SWEPCo.  OPCo and CSPCo value fossil fuel inventories at the lower of average cost or market.  PSO carries fossil fuel inventories utilizing a LIFO method.  Excess of replacement or current cost over stated LIFO value for PSO was $9 million and $4 million as of September 30, 2007 and December 31, 2006, respectively. The materials and supplies inventories are carried at average cost.

Revenue Recognition

Traditional Electricity Supply and Delivery Activities

Registrant Subsidiaries recognize revenues from retail and wholesale electricity supply sales and electricity transmission and distribution delivery services.  Registrant Subsidiaries recognize the revenues in the financial statements upon delivery of the energy to the customer and include unbilled as well as billed amounts.  In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue.

Most of the power produced at the generation plants of the AEP East companies is sold to PJM, the RTO operating in the east service territory, and the AEP East companies purchase power back from the same RTO to supply power to their respective loads.  These power sales and purchases are reported on a net basis as revenues in the financial statements.  Other RTOs in which the Registrant Subsidiaries operate do not function in the same manner as PJM.  They function as balancing organizations and not as an exchange.

Physical energy purchases including those from all RTOs that are identified as non-trading, but excluding PJM purchases described in the preceding paragraph, are accounted for on a gross basis in Purchased Electricity for Resale in the financial statements.

In general, Registrant Subsidiaries record expenses upon receipt of purchased electricity and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated, such as in Ohio and the ERCOT portion of Texas.  In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

Beginning in July 2004, as a result of the sale of generation assets in AEP’s west zone, AEP’s west zone is short capacity and must purchase physical power to supply retail and wholesale customers.  For power purchased under derivative contracts in AEP’s west zone where the AEP West companies are short capacity, they recognize as revenues the unrealized gains and losses (other than those subject to regulatory deferral) that result from measuring these contracts at fair value during the period before settlement.  If the contract results in the physical delivery of power from a RTO or any other counterparty, the Registrant Subsidiaries reverse the previously recorded unrealized gains and losses from MTM valuations and record the settled amounts gross as Purchased Energy for Resale.  If the contract does not result in physical delivery, the Registrant Subsidiaries reverse the previously recorded unrealized gains and losses from MTM valuations and record the settled amounts as revenues in the financial statements on a net basis.

Energy Marketing and Risk Management Activities

All of the Registrant Subsidiaries engage in wholesale electricity, coal and emission allowances marketing and risk management activities focused on wholesale markets where the AEP System owns assets.  Registrant Subsidiaries’ activities include the purchase and sale of energy under forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options, and over-the-counter options and swaps.  The Registrant Subsidiaries engage in certain energy marketing and risk management transactions with RTOs.

Registrant Subsidiaries recognize revenues and expenses from wholesale marketing and risk management transactions that are not derivatives upon delivery of the commodity.  Registrant Subsidiaries use MTM accounting for wholesale marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow or fair value hedge relationship, or as a normal purchase or sale.  The unrealized and realized gains and losses on wholesale marketing and risk management transactions that are accounted for using MTM are included in revenues in the financial statements on a net basis.  In jurisdictions subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).  Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate.

Certain wholesale marketing and risk management transactions are designated as hedges of future cash flows as a result of forecasted transactions (cash flow hedge) or a hedge of a recognized asset, liability or firm commitment (fair value hedge).  The gains or losses on derivatives designated as fair value hedges are recognized in revenues in the financial statements in the period of change together with the offsetting losses or gains on the hedged item attributable to the risks being hedged.  For derivatives designated as cash flow hedges, the effective portion of the derivative’s gain or loss is initially reported as a component of Accumulated Other Comprehensive Income (Loss) and, depending upon the specific nature of the risk being hedged, subsequently reclassified into revenues or expenses in the financial statements when the forecasted transaction is realized and affects earnings.  The ineffective portion of the gain or loss is recognized in revenues in the financial statements immediately, except in those jurisdictions subject to cost-based regulation.  In those regulated jurisdictions the Registrant Subsidiaries defer the ineffective portion as regulatory assets (for losses) and regulatory liabilities (for gains).
Components of Accumulated Other Comprehensive Income (Loss) (AOCI)

AOCI is included on the balance sheets in the common shareholder’s equity section.  AOCI for Registrant Subsidiaries as of March 31,September 30, 2007 and December 31, 2006 is shown in the following table.table:
 
March 31,
 
December 31,
  
September 30,
  
December 31,
 
 
2007
 
2006
  
2007
  
2006
 
Components
 
(in thousands)
  
(in thousands)
 
Cash Flow Hedges:
             
APCo $(10,031)$(2,547) $(3,547) $(2,547)
CSPCo  (1,878) 3,398   1,113   3,398 
I&M  (14,255) (8,962)  (10,709)  (8,962)
KPCo  (490) 1,552 
OPCo  791  7,262   3,776   7,262 
PSO  (1,025) (1,070)  (933)  (1,070)
SWEPCo  (6,737) (6,410)  (6,242)  (6,410)
TNC  -  (702)
               
SFAS 158 Adoption:
       
SFAS 158 Costs:
        
APCo $(52,244)$(52,244) $(40,999) $(52,244)
CSPCo  (25,386) (25,386)  (25,386)  (25,386)
I&M  (6,089) (6,089)  (6,089)  (6,089)
OPCo  (64,025) (64,025)  (64,025)  (64,025)
SWEPCo  (12,389) (12,389)  (12,389)  (12,389)
TNC  (9,457) (9,457)

As shown in the following table, during the next twelve months, the Registrant Subsidiaries expect to reclassify net gains and losses from cash flow hedges in AOCI to Net Income at the time the hedged transactions affect Net Income.  The actual amounts that are reclassified from AOCI to Net Income can differ as a result of market fluctuations.  Also shown in the following table is the maximum length of time that the Registrant Subsidiary’s exposure to variability in future cash flows is hedged with contracts designated as cash flow hedges.

  
September 30, 2007
 
  
(in thousands)
  
(in months)
 
APCo $740   20 
CSPCo  643   20 
I&M  (390)  20 
OPCo  1,576   20 
PSO  (183)  - 
SWEPCo  (829)  33 

Related Party Transactions

Oklaunion PPALawrenceburg Unit Power Agreement (UPA) between TNCCSPCo and AEP Energy PartnersAEGCo

On January 1,In March 2007, TNC beganCSPCo and AEGCo entered into a 20-year Power Purchase & Sale Agreement (PPA)10-year UPA for the entire output from the Lawrenceburg Plant effective with AEGCo’s purchase of the plant in May 2007.  The UPA has an affiliate, AEP Energy Partners (AEPEP), whereby TNC agrees to sell AEPEP 100% of TNC’s capacity and associated energy from its undivided interest (54.69%) inoption for an additional 2-year period.  I&M operates the Oklaunion plant. AEPEP is to pay TNCplant under an agreement with AEGCo.

Under the UPA, CSPCo pays AEGCo for the capacity, and associated energy delivered to the delivery point, the sum ofdepreciation, fuel, operation and maintenance depreciation, capacity and all taxes other than federal income taxes applicable. A portion of the payment is fixed and is payabletax expenses.  These payments are due regardless of whether the level of output. Thereplant is operating.  The fuel and operation and maintenance payments are no penalties if TNC fails to maintain a minimum availability level or exceeds a maximum heat rate level. The PPA was approved by the FERCbased on July 12, 2006.actual costs incurred.  All expenses are trued up periodically.

TNC recorded revenue of $23.4CSPCo paid AEGCo $41.9 million from AEPEP inand $57.8 million for the first quarter ofthree and nine months ended September 30, 2007, which is included in Sales to AEP Affiliates onrespectively.  On its 2007 Condensed Consolidated Statement of Income.Income, CSPCo recorded these purchases in Other Operation expense for the capacity and depreciation portion, and in Purchased Electricity from AEP Affiliates for the variable cost portion.

ERCOT Contracts Transferred to AEPEP

Effective January 1, 2007, PSO and SWEPCo transferred certain existing ERCOT energy marketing contracts to AEPEP and entered into intercompany financial and physical purchase and sale agreements with AEPEP.  This was done to lock in PSO and SWEPCo’s margins on ERCOT trading and marketing contracts and to transfer the future associated commodity price and credit risk to AEPEP.  The contracts will mature over the next three years.

PSO and SWEPCo have historically presented third party ERCOT trading and marketing activity on a net basis in Revenues - Electric Generation, Transmission and Distribution.  The applicable ERCOT third party trading and marketing contracts that were not transferred to AEPEP will remain until maturity on PSO and SWEPCo and will be presented on a net basis in Sales to AEP Affiliates on PSO’s and SWEPCo’s Statements of Income.

The following table indicates the sales to AEPEP and the amounts reclassified from third party to affiliate:

 
For the Three Months Ended September 30, 2007
 
   
Third Party Amounts
 
Net Amount
 
 
Net Settlement
 
Reclassified to
 
included in Sales
 
 
For the Three Months Ended March 31, 2007
  
With AEPEP
 
Affiliate
 
to AEP Affiliates
 
Company
 
Net Settlement
With AEPEP
 
Third Party Amounts
Reclassified to Affiliate
 
Net Amount
included in Sales
to AEP Affiliates
  
(in thousands)
 
 
(in thousands)
 
PSO $43,150 $(35,837)$7,313  $61,702 $(67,759)$6,057 
SWEPCo  46,876  (38,259) 8,617  77,784  (84,920) 7,136 

  
For the Nine Months Ended September 30, 2007
 
    
Third Party Amounts
 
Net Amount
 
  
Net Settlement
 
Reclassified to
 
included in Sales
 
  
With AEPEP
 
Affiliate
 
to AEP Affiliates
 
Company
 
(in thousands)
 
PSO $138,145 $(133,903)$(4,242)
SWEPCo  171,338  (166,339) (4,999)

The following table indicates the affiliated portion of risk management assets and liabilities reflected on PSO’s and SWEPCo’s balance sheets associated with these contracts:
 
As of March 31, 2007
  
As of September 30, 2007
 
 
PSO
 
SWEPCo
  
PSO
 
SWEPCo
 
Current
 
(in thousands)
  
(in thousands)
 
Risk Management Assets $- $-  $19,116 $22,546 
Risk Management Liabilities  (8,282) (9,758) (520) (614)
            
Noncurrent
            
Long-term Risk Management Assets $584 $688  $2,510 $2,960 
Long-term Risk Management Liabilities  (2,097) (2,471) - - 

Texas Restructuring -– SPP - Affecting TNC and SWEPCo

In August 2006, the PUCT adopted a rule extending the delay in implementation of customer choice in the SPP area of Texas until no sooner than January 1, 2011.  SWEPCo’s and approximately 3% of TNC’s businesses were in SPP.  A petition was filed in May 2006 requesting approval to transfer Mutual Energy SWEPCO L.P.’s (a subsidiary of AEP C&I Company, LLC) customers and TNC’s facilities and certificated service territory located in the SPP area to SWEPCo.  In January 2007, the final regulatory approval was received for the transfers.  The transfers were effective February 2007 and were recorded at net book value of $11.6 million.  The Arkansas Public Service Commission’s approval requires SWEPCo to amend its fuel recovery tariff so that Arkansas customers do not pay the incremental cost of serving the additional load.

Reclassifications

Certain prior period financial statement items have been reclassified to conform to current period presentation.  These revisions had no impact on the Registrant Subsidiaries’ previously reported results of operations or changes in shareholders’ equity.

On their statements of income, the Registrant Subsidiaries reclassified regulatory credits related to regulatory asset cost deferral on ARO from Depreciation and Amortization to Other Operation and Maintenance to offset the ARO accretion expense.  The following table shows the credits reclassified by the Registrant Subsidiaries in 2006:

 
Three Months Ended
  
Three Months Ended
 
Nine Months Ended
 
 
March 31, 2006
  
September 30, 2006
 
September 30, 2006
 
Company
 
(in thousands)
  
(in thousands)
 
AEGCo $27 
APCo  296  $110 $708 
I&M  5,589   5,509 17,216 

2.
NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM

         2.NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of exposure drafts or final pronouncements, wemanagement thoroughly reviewreviews the new accounting literature to determine the relevance, if any, to ourthe Registrant Subsidiaries’ business.  The following represents a summary of new pronouncements issued or implemented in 2007 and standards issued but not implemented that we havemanagement has determined relate to ourthe Registrant Subsidiaries’ operations.

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 being market prices in active markets.  The standard requires fair value measurements be disclosed by hierarchy level, and an entity include its own credit standing in the measurement of its liabilities and modifies the transaction price presumption.

SFAS 157 is effective for interim and annual periods in fiscal years beginning after November 15, 2007.  Management expects that the adoption of this standard will impact MTM valuations of certain contracts, butcontracts.  Management is unable to quantifyevaluating the effect.effect of the adoption of SFAS 157 on the Registrant Subsidiaries’ results of operations and financial condition.  Although the statement is applied prospectively upon adoption, the effect of certain transactions is applied retrospectively as of the beginning of the fiscal year of application, with a cumulative effect adjustment to the appropriate balance sheet items.  Although management has not completed its analysis, management expects this cumulative effect adjustment will have an immaterial impact on the Registrant Subsidiaries’ financial statements.  The Registrant Subsidiaries will adopt SFAS 157 effective January 1, 2008.

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.

SFAS 159 is effective for annual periods in fiscal years beginning after November 15, 2007.  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.  InIf the event weRegistrant Subsidiaries elect the fair value option promulgated by this standard, the valuations of certain assets and liabilities may be impacted.  The statement is applied prospectively upon adoption.  The Registrant Subsidiaries will adopt SFAS 159 effective January 1, 2008.  Although management has not completed its analysis, management expects the adoption of this standard to have an immaterial impact on the financial statements.

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 will be applied prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years beginning after September 15, 2007.  Management expects that the adoption of this standard will have an immaterial impact on the financial statements.  The Registrant Subsidiaries will adopt EITF 06-11 effective January 1, 2008.

FIN 48 “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1 "Definition“Definition of Settlement in FASB 
Interpretation No. 48"48” (FIN 48)

In July 2006, the FASB issued FASB Interpretation No. 48 "Accounting“Accounting for Uncertainty in Income Taxes"Taxes” and in May 2007, the FASB issued FASB Staff Position FIN 48-1 "Definition“Definition of Settlement in FASB Interpretation No. 48."”  FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold (whether a tax position is more likely than not to be sustained) without which, the benefit of that position is not recognized in the financial statements.  It requires a measurement determination for recognized tax positions based on the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.  FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

FIN 48 requires that the cumulative effect of applying this interpretation be reported and disclosed as an adjustment to the opening balance of retained earnings for that fiscal year and presented separately.  The Registrant Subsidiaries adopted FIN 48 effective January 1, 2007.  The impact of this interpretation was an unfavorable (favorable) adjustment to retained earnings as follows:

Company
 
(in thousands)
  
(in thousands)
 
AEGCo $(27)
APCo  2,685  $2,685 
CSPCo  3,022   3,022 
I&M  (327)  (327)
KPCo  786 
OPCo  5,380   5,380 
PSO  386   386 
SWEPCo  1,642   1,642 
TCC  2,187 
TNC  557 

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.

FIN 39-1 is effective for fiscal years beginning after November 15, 2007.  Management expects this standard to change the method of netting certain balance sheet amounts but is unable to quantify the effect.  It requires retrospective application as a change in accounting principle for all periods presented.  The Registrant Subsidiaries will adopt FIN 39-1 effective January 1, 2008.

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued by the FASB, wemanagement 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 business combinations, revenue recognition, liabilities and equity, derivatives disclosures, emission allowances, leases, insurance, subsequent events and related tax impacts.  WeManagement also expectexpects 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 operations and financial position.

         3.RATE MATTERSEXTRAORDINARY ITEM

TheAPCo 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.  See “Virginia Restructuring” in Note 3.

3.
RATE MATTERS

As discussed in the 2006 Annual Report, the Registrant subsidiariesSubsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within the 2006 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, cash flows and possibly financial condition.  The following discusses ratemaking developments in 2007 and updates the 2006 Annual Report.

Ohio Rate Matters

Ohio Restructuring and Rate Stabilization Plans -– Affecting CSPCo and OPCo

Ending December 31, 2008, the approved three-year RSPs provide CSPCo and OPCo increases in their generation rates by 3% and 7%, respectively, effective January 1 each year and allow possible additional annual generation rate increases of up to an average of 4% per year to recover governmentally-mandated costs.  In January 2007, CSPCo and OPCo filed with the PUCO underpursuant to the average 4% generation rate provision of their RSPs to increase their annual generation rates for 2007 by $24 million and $8 million, respectively, to recover new governmentally-mandated costs. Pursuant to the RSPs,  CSPCo and OPCo implemented these proposed increases effectivein May 2007 subject to refund.  In October 2007, the PUCO issued an order in the average 4% proceeding which granted CSPCo and OPCo an annual generation rate increase through December 2008 of $19 million and $4 million, respectively.  In September 2007, CSPCo and OPCo recorded a provision for refund to adjust revenues consistent with the beginningrate revenues granted by the PUCO.  Management expects that the average 4% rider will be reduced to implement the required refunds, while OPCo would implement a credit to customers’ bills.  CSPCo and OPCo intend to seek rehearing of the MayPUCO decision.

In October 2007, billing cycle. TheseCSPCo and OPCo made a new filing with the PUCO pursuant to the average 4% generation rate provision of their RSPs for an additional increase in their annual generation rates effective January 2008 of $35 million and $12 million, respectively, to recover governmentally-mandated costs and increased costs related to marginal-loss pricing.  CSPCo and OPCo will implement these proposed increases arein January 2008 subject to refund until the PUCO issues a final order in the matter.  The hearingManagement is scheduledunable to begin in late May 2007.predict the outcome of this filing and its impact on future results of operations and cash flows.

In March 2007, CSPCo filed an application under the average 4% generation rate provision of thetheir RSP to adjust the Power Acquisition Rider (PAR) which was authorized in 2005 by the PUCO in connection withrelated to CSPCo's acquisition of Monongahela Power Company's certified territory in Ohio. The PAR is intendedwas increased to recover the difference between CSPCo's tariffed generation service rates and the cost of a new purchase power acquiredmarket contract to serve the former Monongahela Power load.load for that service territory.  The PAR was set for an initial 17-month period of January 2006 through May 2007. The filing would adjustPUCO approved the requested increase in the PAR, for the nineteen month period of June 2007 through December 2008. The filing reflects a true up for estimated under-recoveries during the initial period, $8 million as of March 31, 2007, as well as the power acquisition costs for the upcoming nineteen-month period. If approved,which is expected to increase CSPCo's revenues would increase by $22 million and $38 million for 2007 and 2008, respectively.

In March 2007, CSPCo and OPCo filed a settlement agreement at the PUCO resolving the Ohio Supreme Court's remand of the PUCO’s RSP order.  The Supreme Court indicated concern with the absence of a competitive bid process as an alternative to the generation rates set by the RSP. In response, the settling parties agreed to have CSPCo and OPCo take bids for Renewable Energy Certificates (RECs).  CSPCo and OPCo will give customers the option to pay a generation rate premium that would encourage the development of renewable energy sources by reimbursing CSPCo and OPCo for the cost of the RECs and the administrative costs of the program.  This settlement agreement was supported by theThe Office of Consumers'Consumers’ Counsel, the Ohio Partners for Affordable Energy, the Ohio Energy Group and the PUCO staff.staff supported this settlement agreement.  In May 2007, the PUCO adopted the settlement agreement in its entirety.
CSPCo and OPCo are involved in discussions with various stakeholders in Ohio about potential legislation to address the period following the expiration of the RSPs on December 31, 2008. At this time, management is unable to predict whether CSPCo and OPCo will transition to market pricing, as permitted by the current Ohio restructuring legislation, extend their RSP rates, with or without modification, or become subject to a legislative reinstatement of some form of cost-based regulation for their generation supply business on January 1, 2009 when the RSP period ends.

Customer Choice Deferrals -– Affecting CSPCo and OPCo

As provided in theCSPCo’s and OPCo’s restructuring settlement agreement approved by the PUCO in 2000, allows CSPCo and OPCo establishedto establish regulatory assets for customer choice implementation costs and related carrying costs in excess of $20 million each for recovery in the next general base rate filing which changes distribution rates after December 31, 2007 for OPCo and December 31, 2008 for CSPCo. Pursuant to the RSPs, recovery of these amounts for OPCo was further deferred until the next base rate filing to change distribution rates after the end of the RSP period of December 31, 2008.rates.  Through March 31,September 30, 2007, CSPCo and OPCo incurred $50$53 million and $51$54 million, respectively, of such costs and established regulatory assets of $25$27 million each for the future recovery of such costs.  CSPCo and OPCo also have not recognized $5the right to recover $6 million and $6$7 million, respectively, of equity carrying costs which are recognizable when collected.in addition to these regulatory assets.  In 2007, CSPCo and OPCo incurred $3 million and $4 million, respectively, of such costs and established regulatory assets of $2 million each for such costs.  Management believes that the deferred customer choice implementation costs were prudently incurred to implement customer choice in Ohio and are probable of recovery in future distribution rates.  However, failure to recover such costs would have an adverse effect on results of operations and cash flows.

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 during 2006; Phase 2, concurrent recovery of construction-financing costs; and Phase 3, recovery or refund in distribution rates of any difference between the market-based standard service offer price for generation and the cost of operating and maintaining the plant, including a return on and return of the ultimate cost to construct the plant, originally projected to be $1.2 billion, along with fuel, consumables and replacement power costs.  The proposed recoveries in Phases 1 and 2 would be applied against the average 4% limit on additional generation rate increases CSPCo and OPCo could request under their RSPs.

In April 2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase 1 of the cost recovery proposal.  In June 2006, the PUCO issued another order approving a tariff to recover Phase 1 pre-construction costs over a period of no more than a twelve-month periodtwelve months effective July 1, 2006.  Through March 31,September 30, 2007, CSPCo and OPCo each recorded pre-construction IGCC regulatory assets of $10 million and each recovered $9collected the entire $12 million approved by the PUCO.  As of those costs.September 30, 2007, CSPCo and OPCo will recoverhave recorded a liability of $2 million each for the remaining amounts through June 30, 2007. over-recovered portion. CSPCo and OPCo expect to incur additional pre-construction costs equal to or greater than the $12 million each recovered.  
The PUCO indicated 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 chargesPhase 1 costs collected for pre-construction costs, associated with items that may be utilized in IGCC projects at other sites, must be refunded to Ohio ratepayers with interest.  The PUCO deferred ruling on cost recovery for Phases 2 and 3 cost recovery until further hearings are held.  A date for further rehearings has not been set.

In August 2006, the Ohio Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order in the IGCC proceeding.  The Ohio Supreme Court heard oral arguments for these appeals in October 2007.  Management believes that the PUCO’s authorization to begin collection of Phase 1 rates is lawful.  Management, however, cannot predict the outcome of these appeals.  If the PUCO’s order is found to be unlawful, CSPCo and OPCo could be required to refund Phase I1 cost-related recoveries.

Pending the outcome of the Supreme Court litigation, CSPCo and OPCo announced they may delay the start of construction of the IGCC plant. Recent estimates of the cost to build an IGCC plant have escalated to $2.2 billion.  CSPCo and OPCo may need to request an extension to the 5-year start of construction requirement if the commencement of construction is delayed beyond 2011.

Distribution Reliability Plan -– Affecting CSPCo and OPCo

In January 2006, CSPCo and OPCo initiated a proceeding at the PUCO seeking a new distribution rate rider to fund enhanced distribution reliability programs. In the fourth quarter of 2006, as directed by the PUCO, CSPCo and OPCo filed a proposed enhanced reliability plan.  The plan contemplated CSPCo and OPCo recovering approximately $28 million and $43 million, respectively, in additional distribution revenue during an eighteen montheighteen-month period beginning July 2007. In January 2007, the OCC filed testimony, which argued that CSPCo and OPCo should be required to improve distribution service reliability with funds from their existing rates.

In April 2007, CSPCo and OPCo filed a joint motion with the PUCO staff, the Ohio Consumers’ Counsel, the Appalachian People’s Action Coalition, the Ohio Partners for Affordable Energy and the Ohio Manufacturers Association to withdraw the proposed enhanced reliability plan.  The motion was granted in May 2007.  CSPCo and OPCo do not intend to implement the enhanced reliability plan without recovery of any incremental costs.

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 underin accordance with a PUCO encouraged settlement agreement. The settlement agreement between CSPCo and OPCo, Ormet, its employees’ union and certain other interested parties that was approved by the PUCO in November 2006.  The settlement agreement provides for the recovery in 2007 and 2008 by CSPCo and OPCo of the difference between $43 per MWH to be paid by Ormet for power and a PUCO approvedPUCO-approved market price, if higher.  The recovery will be accomplished by the amortization of a $57 million ($15 million for CSPCo and $42 million for OPCo) Ohio franchise tax phase-out regulatory liability recorded in 2005 and, if that is not sufficient,insufficient, an increase in RSP generation rates under the additional average 4% generation rate provision of the RSPs. The $43 per MWH price to be paid by Ormet for generation services is above the industrial RSP generation tariff but below current market prices.

In December 2006, CSPCo and OPCo submitted a market price of $47.69 per MWH for 2007, which is pendingwas approved by the PUCO approval.in June 2007.  CSPCo and OPCo have each amortized $5 million of their Ohio Franchise Tax phase-out tax regulatory liability to income through September 30, 2007.  If the PUCO approves a lower market price in 2008, it could have an adverse effect on future results of operations and cash flows.  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 off-system sales margins, which could have an adverse effect on future results of operations and cash flows.margins.

Texas Rate Matters

TCC TEXAS RESTRUCTURING - Affecting TCC

Texas District Court Appeal Proceedings

TCC recovered its net recoverable stranded generation costs through a securitization financing and is refunding its net other true-up items through a CTC rate rider credit under 2006 PUCT orders. TCC appealed the PUCT stranded costs true-up 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, 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 statute 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 it failed to determine a minimum price at which it would reject bids for the sale of its nuclear generating plant and it 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 cost, and
·The two federal matters regarding the allocation of off-system sales related to fuel recoveries and the potential tax normalization violation. See “TCC and TNC Deferred Fuel” and“TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes” sections below.

Municipal customers and other intervenors also appealed the PUCT true-up orders seeking to further reduce TCC’s true-up recoveries. On February 1, 2007, the Texas District Court judge hearing the various appeals issued a letter containing his preliminary determinations. He generally affirmed the PUCT’s April 4, 2006 final true-up order for TCC with two significant exceptions. The judge determined that the PUCT erred when it determined TCC’s stranded cost using the sale of assets method instead of the Excess Cost Over Market (ECOM) method to value TCC’s nuclear plant. The judge also determined that the PUCT erred when it concluded it was required to use the carrying cost rate specified in the true-up order. However, the District Court did not rule that the carrying cost rate was inappropriate. The judge directed that these matters should be remanded to the PUCT to determine the specific impact on TCC’s future true-up revenues.

In March 2007, the District Court judge reversed his earlier preliminary decision and concluded the sale of assets method to value TCC’s nuclear plant was appropriate. The District Court judge did not reconsider his preliminary ruling that the PUCT erred when it concluded it was required to use the carrying cost rate specified in the true-up order. The District Court judge also determined the PUCT improperly reduced TCC’s net stranded plant costs from the sale of its generating units through the commercial unreasonableness disallowance, which could have a materially favorable effect on TCC.  Management cannot predict the ultimate outcome of any future court appeals or any future remanded PUCT proceeding. If the District Court’s carrying cost rate remand ruling is ultimately upheld on appeal and remanded to the PUCT for reconsideration, the PUCT could either confirm the existing weighted average carrying cost (WACC) rate or redetermine a new rate. If the PUCT changes the rate, it could result in a material adverse change to TCC’s recoverable carrying costs, results of operations, cash flows and financial condition. TCC, the PUCT and intervenors appealed the District Court ruling to the Court of Appeals.  Management cannot predict what actions, if any, the PUCT will take regarding the carrying costs.

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.

OTHER TEXAS RESTRUCTURING MATTERS

TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes - Affecting TCC

In TCC’s 2006 true-up and securitization orders, the PUCT reduced net regulatory assets and the amount to be securitized by $51 million related to the present value of ADITC and by $10 million related to EDFIT associated with TCC’s generation assets for a total reduction of $61 million.

TCC filed a request for a private letter ruling with the IRS in June 2005 regarding the permissibility under the IRS rules and regulations of the ADITC and EDFIT reduction proposed by the PUCT. The IRS issued its private letter ruling in May 2006, which stated that the PUCT’s flow-through to customers of the present value of the ADITC and EDFIT benefits would result in a normalization violation. To address the matter and avoid a normalization violation, the PUCT agreed to allow TCC to defer an amount of the CTC refund totaling $103 million ($61 million in present value of ADITC and EDFIT associated with TCC’s generation assets plus $42 million of related carrying costs) pending resolution of the normalization issue. If it is ultimately determined that a refund to customers through the true-up process of the ADITC and EDFIT, discussed above, is not a normalization violation, then TCC will be required to refund the $103 million, plus additional carrying costs. However, if such refund of ADITC and EDFIT is ultimately determined to cause a normalization violation, TCC anticipates it will be permitted to retain the $61 million present value of ADITC and EDFIT plus carrying costs, favorably impacting future results of operations.

If a normalization violation occurs, it could result in TCC’s repayment to the IRS of ADITC on all property, including transmission and distribution property, which approximates $104 million as of March 31, 2007, and a loss of TCC’s right to claim accelerated tax depreciation in future tax returns. Tax counsel advised management that a normalization violation should not occur until all remedies under law have been exhausted and the tax benefits are returned to ratepayers under a nonappealable order. Management intends to continue its efforts to avoid a normalization violation that would adversely affect future results of operations and cash flows.

TCC and TNC Deferred Fuel - Affecting TCC and TNC

The TCC deferred fuel over-recovery regulatory liability is a component of the other true-up items net regulatory liability refunded through the CTC rate rider credit. In 2002, TCC and TNC filed with the PUCT seeking to reconcile fuel costs and establish their final deferred fuel balances. In its final fuel reconciliation orders, the PUCT ordered a reduction in TCC’s and TNC’s recoverable fuel costs for, among other things, the reallocation of additional AEP System off-system sales margins under a FERC-approved SIA. Both TCC and TNC appealed the PUCT’s rulings regarding a number of issues in the fuel orders in state court and challenged the jurisdiction of the PUCT over the allocation of off-system sales margin allocations in the federal court. Intervenors also appealed the PUCT’s rulings in state court.

In 2006, the Federal District Court issued orders precluding the PUCT from enforcing the off-system sales reallocation portion of its ruling in the final TNC and TCC fuel reconciliation proceedings. The Federal court ruled, in both cases, that the FERC, not the PUCT, has jurisdiction over the allocation. The PUCT appealed both Federal District Court decisions to the United States Court of Appeals. In TNC’s case, the Court of Appeals affirmed the District Court’s decision. The PUCT has indicated they will appeal this ruling to the United States Supreme Court. TCC has filed a Motion for Summary Affirmance based on the outcome of the TNC appeal. For TCC, the PUCT has conceded the issue concerning the allocation of off-system sales margins to AEP West companies under the SIA as governed by the TNC case. However, the PUCT continues to challenge the allocation of those margins among AEP West companies under the CSW Operating Agreement. If the PUCT’s appeals are ultimately unsuccessful, TCC and TNC could record income of $16 million and $8 million, respectively, related to the reversal of the previously recorded fuel over-recovery regulatory liabilities.

If the PUCT is unsuccessful in the federal court system, it or another interested party may file a complaint at the FERC to address the allocation issue. If a complaint at the FERC results in the PUCT’s decisions being adopted by the FERC, there could be an adverse effect on results of operations and cash flows. An unfavorable FERC ruling may result in a retroactive reallocation of off-system sales margins from AEP East companies to AEP West companies under the then existing SIA allocation method. If the adjustments were applied retroactively, the AEP East companies may be unable to recover the amounts reallocated to the West companies from their customers due to past frozen rates, past inactive fuel clauses and fuel clauses that do not include off-system sales credits. Although management cannot predict the ultimate outcome of this federal litigation, management believes that its allocations were in accordance with the then existing FERC-approved SIA and that it should not have to allocate additional off-system sales margins to the West companies including TCC and TNC.

In January 2007, TCC began refunding as part of the CTC rate rider credit described above, $149 million of its $165 million over-recovered deferred fuel regulatory liability. The remaining $16 million refund related to the favorable Federal District Court order has been deferred pending the outcome of the federal court appeal and would be subject to refund only upon a successful appeal by the PUCT.

Excess Earnings - Affecting TCC

In 2005, the Texas Court of Appeals issued a decision finding the PUCT’s prior order from the unbundled cost of service case requiring TCC to refund excess earnings prior to and outside of the true-up process was unlawful under the Texas Restructuring Legislation. TCC refunded $55 million of excess earnings, including interest, of which $30 million went to the affiliated REP. In November 2005, the PUCT filed a petition for review with the Supreme Court of Texas seeking reversal of the Texas Court of Appeals’ decision. The Supreme Court of Texas requested briefing, which has been provided, but it has not decided whether it will hear the case. If the Court of Appeals decision is upheld and the refund mechanism is found to be unlawful, the impact on TCC would then depend on: (a) how and if TCC is ordered by the PUCT to refund the excess earnings through the true-up process to ultimate customers and (b) whether TCC will be able to recover the amounts previously refunded to the REPs including the REP TCC sold to Centrica. Management is unable to predict the ultimate outcome of this litigation and its effect on future results of operations and cash flows.

OTHER TEXAS RATE MATTERS

TCC and TNC Energy Delivery Base Rate Filings - Affecting TCC and TNC

TCC and TNC each filed a base rate case seeking to increase transmission and distribution energy delivery services (wires) base rates in Texas. TCC and TNC requested $81 million and $25 million in annual increases, respectively. Both requests include a return on common equity of 11.25% and the impact of the expiration of the CSW merger savings rate credits. In March 2007, various intervenors and the PUCT staff filed their recommendations. Though the recommendations varied, the range of recommended increase was $8 million to $30 million for TCC and $1 million to $14 million for TNC. The recommended return on common equity ranged from 9.00% to 9.75%. In April 2007, TCC and TNC filed rebuttal testimony reducing the requested annual increases to $70 million for TCC and $22 million for TNC including a reduced requested return on common equity of 10.75%. Hearings began in April 2007 and are scheduled to be concluded in May 2007.Management expects the new base wires rates to become effective, subject to refund, in the second quarter of 2007 with a decision from the PUCT expected in the third quarter of 2007. Management is unable to predict the ultimate effect of this filing on future results of operations, cash flows and financial condition.

SWEPCo Fuel Reconciliation -– Texas -– Affecting SWEPCo

In June 2006, SWEPCo filed a fuel reconciliation proceeding with the PUCT for its Texas retail operations.operations for the three-year reconciliation period ended December 31, 2005.  SWEPCo sought, in the proceedings, to include under-recoveries related to the reconciliation period of $50 million.  In January 2007, intervenors filed testimony recommending that SWEPCo’s reconcilable fuel costs be reduced.  The PUCT staff and intervenor recommendationsdisallowances ranged from a $10 million to $28 million.  In June 2007, an ALJ issued a proposal for decision recommending a $17 million reduction.disallowance.  Results of operations for the second quarter of 2007 were adversely affected by $25 million to reflect the ALJ’s decision that apply to the reconciliation period and subsequent periods through 2007.  In FebruaryAugust 2007, the PUCT staffissued a final order affirming the ALJ report.  In September 2007, SWEPCo filed testimony recommending that SWEPCo’s reconcilable fuel costs be reduced by $10 million. SWEPCo does not agree with the intervenor’s or staff’s recommendations and filed rebuttal testimony in February 2007. Hearings have been held and briefs have been filed. Results of operations could be adversely affected by $28 million plus carrying costs ifa motion for rehearing.  In October 2007, the PUCT adopts allgranted SWEPCo’s motion for rehearing.  The PUCT reversed its prior determination that SO2 allowance gains should be credited through the fuel clause.  However, the PUCT ruled SWEPCo was obligated to credit the fuel clause with gains from sales of emissions allowances through June 30, 2006.  This change affects allowances sold after June 2006 and its impact will be considered in the fourth quarter of 2007.  In October 2007, the PUCT issued a revised order which should allow SWEPCo to reverse $7 million of its earlier provision in the fourth quarter of 2007.  SWEPCO is considering whether to challenge other parts of the intervenor and staff recommendations. Management is unable to predict the outcome of this proceeding or its effect on future results of operations and cash flows.order.

Stall Unit – Affecting SWEPCo

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

Turk Plant – Affecting SWEPCo

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

Virginia Rate Matters

Virginia Restructuring -– Affecting APCo

In April 2004, Virginia enacted legislation that extendedamended the Virginia Electric Utility Restructuring Act extending the transition period to market rates for the generation and supply of electricity, restructuring, including the extension of capped rates, through December 31, 2010.  The legislation providesprovided APCo with specified cost recovery opportunities during the extended capped rate period, including two optional bundled general base rate changes and an opportunity for timely recovery, through a separate rate mechanism, of certain unrecovered incremental environmental and reliability costs incurred on and after July 1, 2004.  Under the amended restructuring law, APCo continues to have an active fuel clause recovery mechanism in Virginia and continues to practice deferred fuel accounting. Also, underhave the restructuring law, APCo defersopportunity to recover incremental environmental generation costs and incremental transmission and distribution reliability costs for future recovery, to the extent such costs are not being recovered when incurred, and amortizes a portion of such deferrals commensurate with recovery.E&R costs.

In April 2007, the Virginia legislature adopted a comprehensive law providing for the re-regulation of electric utilities’ generation/generation and supply rates.  TheThese amendments shorten the transition period by two years (from 2010 to 2008) after which rates for retail generation/generation and supply will return to a formcost-based regulation in lieu of cost-based regulation.market-based rates.  The legislation provides for, among other things, biennial rate reviews beginning in 2009,2009; rate adjustment clauses for the recovery of the costs of (a) transmission services and new transmission investment,investments, (b) Demand Side Management,demand side management, load management, and energy efficiency programs, (c) renewable energy programs, and (d) environmental retrofit and new generation investments,investments; significant return on equity enhancements for large investments in new generation and, subject to Virginia SCC approval, certain environmental retrofits, and a floor on the allowed return on equity based on the average earned return on equities’ of regional vertically integrated electric utilities.  Effective July 1, 2007, the amendments allow utilities to retain a minimum of 25% of the margins from off-system sales with the remaining margins from such sales credited against fuel factor expenses.expenses with a true-up to actual.  The legislation also allows APCo to continue to defer and recover incremental environmental and reliability costs incurred through December 31, 2008.  APCo expects thisThe new form of cost-based ratemakingre-regulation legislation should improve its annual returnresult in significant positive effects on APCo’s future earnings and cash flows from the mandated enhanced future returns on equity, the reduction of regulatory lag from the opportunities to adjust base rates on a biennial basis and cash flow from operations whenthe new ratemaking beginsopportunities to request timely recovery of certain new costs not included in 2009. However, withbase rates.

With the return of cost-based regulation,new re-regulation legislation, APCo’s generation business will again meetmet the criteria for application of regulatory accounting principles under SFAS 71.  Results of operationsThe extraordinary pretax reduction in APCo’s earnings and financial condition could be adversely affected when APCo is required to re-establish certain net regulatory liabilities applicable to its generation/supply business. The timing and earnings effectshareholder’s equity from such reapplication of SFAS 71 regulatory accounting of $118 million ($79 million, net of tax) was recorded in the second quarter of 2007.  This extraordinary net loss relates to the reestablishment of $139 million in net generation-related customer-provided removal costs as a regulatory liability, offset by the restoration of $21 million of deferred state income taxes as a regulatory asset.  In addition, APCo established a regulatory asset of $17 million for APCo’s Virginia generation/supply businessqualifying SFAS 158 pension costs of the generation operations that, for ratemaking purposes, are uncertain at this time.deferred for future recovery under the new re-regulation legislation.  AOCI and Deferred Income Taxes increased by $11 million and $6 million, respectively.

APCo Virginia Base Rate Case -– Affecting APCo

In May 2006, APCo filed a request with the Virginia SCC seeking an increase in base rates of $225 million to recover increasing costs including the cost of its investment in environmental equipment and a return on equity of 11.5%.  In addition, APCo requested to move off-system sales margins, currently credited to customers through base rates, to theits active fuel factor where they can be trued-up to actual.clause.  APCo also proposed to share the off-system sales margins with customers with 40% going to reduce rates and 60% being retained by APCo.  This proposed off-system sales fuel rate credit, which iswas estimated to be $27 million, partially offsets the $225 million requested increase in base rates for a net increase in base rate revenues of $198 million.  The major components of the $225 million base rate request include $73 million for the impact of removing off-system sales margins from the rate year ending September 30, 2007, $60 million mainly due to projected net environmental plant additions through September 30, 2007 and $48 million for return on equity.

In May 2006, the Virginia SCC issued an order consistent with Virginia law, placing the net requested base rate increase of $198 million into effect on October 2, 2006, subject to refund. The $198 million base rate increase being collected, subject to refund, includes recovery of incremental environmental compliance and transmission and distribution system reliability (E&R) costs projected to be incurred during the rate year beginning October 2006. These incremental E&R costs can be deferred and recovered through the E&R surcharge mechanism if not recovered through this base rate request.

In October 2006,May 2007, the Virginia SCC staff filed its direct testimony recommendingissued a final order approving an overall annual base rate increase of $13$24 million witheffective as of October 2006 and approving a return on equity of 9.9% and no off-system sales margin sharing. Other intervenors have recommended base rate increases ranging from10.0%.  As a result of the final order, APCo’s second quarter pretax earnings decreased by approximately $3 million due to a decrease in revenues of $42 million net of a recorded provision for refund and related interest offset by (a) a $15 million net effect from the deferral of unrecovered incremental E&R costs incurred from October 1, 2006 through June 30, 2007 to $112 million.be collected in a future E&R filing, (b) a $9 million net deferral of ARO costs to be recovered over 10 years and (c) a $15 million retroactive decrease in depreciation expense.  As a result of the Virginia SCC decision to limit the recovery of incremental E&R costs through the new base rates, APCo will continue to defer for future recovery unrecovered incremental E&R costs incurred through 2008 utilizing the E&R surcharge mechanism.  APCo completed the $127 million refund in August 2007.

Virginia E&R Costs Recovery Filing – Affecting APCo

In July 2007, APCo filed rebuttala request with the Virginia SCC seeking recovery over the twelve months beginning December 1, 2007 of approximately $60 million of unrecovered incremental E&R costs inclusive of carrying costs thereon incurred from October 1, 2005 through September 30, 2006.  In August 2007, the Virginia SCC issued a scheduling order to begin the proceeding before a hearing examiner on November 5, 2007.  In October 2007, the Virginia SCC staff and the Attorney General both filed testimony recommending that APCo recover $49 million of its $60 million of requested E&R costs.  The two differences between APCo’s request and the Virginia SCC staff and the Attorney General’s recommendations relate to the recovery of carrying costs on the unrecovered incremental E&R costs and the appropriate return on equity rate.  APCo intends to file in November 2006. Hearings were held in December2008 for recovery of additional incurred incremental E&R costs recorded and deferred after September 30, 2006.

In MarchAPCo is currently recovering $21 million of incurred E&R costs through the initial E&R surcharge that will expire on November 30, 2007.  Through September 30, 2007, APCo deferred $70 million in incremental E&R costs to be recovered in the Hearing Examiner (HE) issued a report recommending a $76current and future E&R filings.  APCo has not recognized $15 million increase in APCo’s base ratesof equity carrying charges, which are recognizable when collected.  The $70 million regulatory asset does not include carrying costs on the unrecovered incremental E&R costs and $45 million credit to the fuel factor for off-system sales margins. The HE’s recommendations includeis based on a return on equity of 10.1%rate which would reduce APCo’s revenue requirement by approximately $23 million. The HE also recommended limiting forward looking ratemaking adjustments to June 30, 2006 as opposed to September 30, 2007, which would reduce APCo’s revenue requirement by approximately $72approximates the Virginia SCC staff and Attorney General’s recommendations.  As a result, if APCo is awarded only $49 million of which approximately $60 million relates to incrementalfor the E&R costs that can be deferredincurred for future recovery through the E&R surcharge mechanism. The HE further proposed to share the off-system sales margins using the twelve months ended JuneSeptember 30, 2006 as recommended by the Virginia SCC staff and the Attorney General, it will not have to reverse any of $101its regulatory asset deferrals.

Virginia Fuel Clause Filing – 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 a sharing of the benefits of off-system sales between APCo and its customers.  This filing was made in compliance with 50% reducing base rates, 45% reducing fuel rates and 5% retained by APCo to determine the revenue requirement. APCo’s proposal did not reduce base rates forminimum 25% retention of off-system sales margins but reducedprovision of the new re-regulation legislation which is effective with the first fuel rates approximately $27 million forclause filing after July 1, 2007.  This sharing requirement in the new law also includes a true-up to actual off-system sales margins.  In addition, APCo expects a final orderrequested authorization to be issued during 2007.defer for future recovery the difference between off-system sales margins credited to customers at 100% of the ordered amount through the current base rate margin rider and 75% of actual off-system sales margins as provided in the new law from July 1, 2007 until the new fuel rate becomes effective.

APCo is providing forIn August 2007, the Virginia SCC issued a possible refundscheduling order that implemented APCo’s proposed termination of revenues collectedits base rate off-system sales margin rider on an interim basis, subject to refund, consistenton September 1, 2007.  The order also implemented APCo’s proposed new fuel factor on an interim basis, effective September 1, 2007, which includes a credit for the sharing of 75% of off-system sales margins with customers in compliance with the HE recommendations. Management is unable to predictnew law.  In October 2007, APCo, the ultimate effectVirginia SCC staff and certain intervenors filed memorandums addressing legal issues identified by the Virginia SCC regarding the appropriateness of this filing on futurethe timing of the implementation of the new expanded fuel factor and off-system sales margins sharing with customers.  Hearings are scheduled for November 2007.  In October 2007, the Virginia SCC staff submitted testimony stating off-system sales margin sharing for July and August 2007 should be denied.  In addition, the Virginia SCC staff asserted that no language exists in the statute requiring implementation of off-system sales margin sharing any earlier than 2011.  Future results of operations and cash flows could be adversely affected if the Virginia SCC delays the effective date of the new expanded fuel clause beyond APCo’s filed request.

West Virginia IGCC Plant – Affecting APCo

In July 2007, APCo filed a request with the Virginia SCC to recover, over the twelve months beginning January 1, 2009, a return on projected construction work in progress including development, design and financial condition.planning costs from July 1, 2007 through December 31, 2009 estimated to be $45 million associated with the proposed 629 MW IGCC plant to be constructed in West Virginia for an estimated cost of $2.2 billion.  APCo is requesting authorization to defer a return on actual pre-construction costs incurred beginning July 1, 2007 until such costs are recovered, starting January 1, 2009 in accordance with the new re-regulation legislation.  The new re-regulation legislation provides for full recovery of all costs plus return on equity incentives for such new capacity once the plant is placed in service.  See “West Virginia IGCC Plant” section within West Virginia Rate Matters.

West Virginia Rate Matters

APCo Expanded Net Energy Cost (ENEC) Filing -– Affecting APCo

In April 2007, the WVPSC issued an order establishing an investigation and hearing ofconcerning APCo’s and WPCo’s 2007 ENEC joint compliance filing.  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 and other energy/transmission items.   In the March 2007 ENEC joint compliance filing, APCo filed for an increase of approximately $91 million including a $65 million increase in ENEC and a $26 million increase in construction cost surcharges to become effective July 1, 2007.  A hearing onIn June 2007, the WVPSC issued an order approving, without modification, a joint compliance filingstipulation and agreement for settlement reached among the parties.  The settlement agreement provided for an increase in annual non-base revenues of approximately $77 million effective July 1, 2007.  This annual revenue increase primarily includes $50 million of ENEC and $26 million of construction cost surcharges.  The ENEC portion of the increase is scheduled for May 2007.subject to a true-up, which should avoid an earnings affect from an under-recovery of ENEC costs if they exceed the $50 million.

APCoWest Virginia IGCC -Plant – 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, WV.

In JanuaryJune 2007, at APCo’s request,APCo filed testimony with the WVPSC issuedsupporting the requests for a CCN and for pre-approval of a surcharge rate mechanism to provide for the timely recovery of both 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.  If APCo receives all necessary approvals, the plant could be completed as early as mid-2012 and currently is expected to cost an order delayingestimated $2.2 billion.  In July 2007, the Commission’sWVPSC staff and intervenors filed to delay the procedural schedule by 90 days.  APCo supported the changes to the procedural schedule.  The statutory decision deadline for issuing an order onwas revised to March 2008.  In July 2007, the certificate to December 2007.WVPSC approved the revised procedural schedule.  Through March 31,September 30, 2007, APCo deferred pre-construction IGCC costs totaling $10$11 million.  If the plant is not built and these costs are not recoverable, future results of operations and cash flows would be adversely affected.

Indiana Rate Matters

I&MIndiana Depreciation Study Filing -– Affecting I&M

In February 2007, I&M filed a request with the IURC for approval of revised book depreciation rates effective January 1, 2007.  The filing included a settlement agreement entered into with the Indiana Office of the Utility Consumer Counsel (OUCC) that would provide direct benefits to I&M's customers if new lower book depreciation rates arewere approved by the IURC.  The direct benefits would include a $5 million credit to fuel costs and an approximate $8 million smart metering pilot program.  In addition, if the agreement iswere to be approved, I&M would initiate a general rate proceeding on or before July 1, 2007 and initiate two studies, one to investigate a general smart metering program and the other to study the market viability of demand side management programs.  Based on the depreciation study included in the filing, I&M recommended and parties to the settlement agreed to a decrease in pretax annual depreciation expense on an Indiana jurisdictional basis of approximately $69 million reflecting an NRC-approved 20-year extension of the Cook Plant licenses for Units 1 and 2 and an extension of the service life of the Tanners Creek coal-fired generating units.  This petition was not a request for a change in customers’ electric service rates.  As proposed,In June 2007, the IURC approved the settlement agreement, but modified the effective date of the new book depreciation reductionrates to the date I&M filed a general rate petition.  On June 19, 2007, I&M and the OUCC notified the IURC that the parties would accept the modification to the settlement agreement.  Therefore, I&M filed its rate petition and reduced its book depreciation rates as agreed upon in the settlement agreement.

The settlement agreement modification reduced book depreciation rates, which will result in an increase of $37 million in pretax earnings but would not impact cash flows untilfor the period June 19, 2007 to December 31, 2007.  The $37 million increase is partially offset by a $5 million regulatory liability, recorded in June 2007, to provide for the agreed-upon fuel credit.  I&M’s approved book depreciation rates are revised.subject to further review in the general rate case.  Management expects new base rates will become effective in early 2009.

Indiana Rate Filing – Affecting I&M

In June 2007, I&M filed a rate notification petition with the IURC regarding its intent to file for a base rate increase with a proposed test year ended September 30, 2007.  The IURC heldpetition indicated, among other things, the filing would include a public hearing in April 2007. I&M requested expeditious review and approval of its filing, but management cannot predict the outcomerequest to implement rate tracker mechanisms for certain variable components of the request orcost of service including PJM RTO costs, reliability enhancement costs, demand side management/energy efficiency program costs, off-system sales margins, and net environmental compliance costs.  This filing will also reflect the timingrevenue requirement reduction associated with an annual reduction in book depreciation expense. In August 2007, the IURC approved the September 30, 2007 test year and the inclusion of the above trackers in the rate filing with a rate case to be filed no later than January 31, 2008.  Management expects to file the case in early 2008 with a decision expected in early 2009.

Indiana Rate Cap – Affecting I&M

Effective July 1, 2007, I&M’s rate cap ended for both base and fuel rates in Indiana.  As a result, I&M’s fuel factor in Indiana increased with the July 2007 billing month to recover the projected cost of fuel.  I&M will resume deferring through revenues any approved depreciation reduction. If approved as filed,under/over-recovered fuel costs for future recovery/refund.  Under the capped rates, I&M was unable to recover $44 million of fuel costs since 2004 of which $7 million adversely impacted 2007 pretax earnings would increasethrough June 30, 2007.  Future results of operations should no longer be adversely impacted by $64 million in 2007.fuel costs.

KentuckyMichigan Rate Matters

KPCo Environmental SurchargeMichigan Depreciation Study Filing -– Affecting KPCoI&M

In JulyDecember 2006, KPCoI&M filed for approval of an amended environmental compliance plan and revised tariffa depreciation study in Michigan seeking to reduce its book depreciation rates.  In September 2007, the Michigan Public Service Commission (MPSC) approved a settlement agreement authorizing I&M to implement an adjusted environmental surcharge. KPCo estimatesnew book depreciation rates.  Based on the amended environmental compliance plan and revised tariff would increase revenues over 2006 levelsdepreciation study included in the settlement, I&M agreed to decrease pretax annual depreciation expense, on a Michigan jurisdictional basis, by approximately $2 million in 2007$10 million.  This settlement reflects an NRC-approved 20-year extension of the Cook Plant licenses for Units 1 and $6 million in 20082 and an extension of the service life of the Tanners Creek coal-fired generating units.  This petition was not a request for a total of $8 million of additional revenue at current cost projections. change in retail customers’ electric service rates.  In January 2007, the KPSC issued an order approving KPCo’s proposed planaddition and surcharge. Future recovery is based upon actual environmental costs and is subject to periodic review and approval of those actual costs by the KPSC.

In November 2006, the Kentucky Attorney General and the Kentucky Industrial Utility Consumers (KIUC) filed an appeal with the Kentucky Court of Appeals of the Franklin Circuit Court’s 2006 order upholding the KPSC’s 2005 Environmental Surcharge order. In its order, the KPSC approved KPCo’s recovery of its environmental costs at its Big Sandy Plant and its share of environmental costs incurred as a result of the AEP Power Pool capacity settlement. The KPSC has allowed KPCo to recover these FERC-approved allocated costs, vianew MPSC-approved rates, I&M will decrease pretax annual depreciation expense, on a FERC jurisdictional basis, by approximately $11 million which will reduce wholesale rates for customers representing approximately half the environmental surcharge, sinceload beginning in November 2007 and reduce wholesale rates for the KPSC’s first environmental surcharge orderremaining customers in 1997. KPCo presently recovers $7 million a year in environmental surcharge revenues.June 2008.

In March 2007, the KPSC issued an order, at the request of the Kentucky Attorney General, stating the environmental surcharge collections authorized in the January 2007 order that are associated with out-of-state generating facilities should be collected over the six months beginning March 2007, subject to refund, pending the outcome of the court of appeals process. At this time, management is unable to predict the outcome of this proceeding and its effect on KPCo’s current environmental surcharge revenues or on the January 2007 KPSC order increasing KPCo’s environmental rates.

Oklahoma Rate Matters

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

In 2002, PSO under-recovered $44 million of purchased power costs through its fuel costsclause resulting from a reallocation among AEP West companies of purchased power costs for periods prior to January 1, 2002.  In July 2003, PSO proposed collection of those reallocated costs over eighteen months.  In August 2003, the OCC staff filed testimony recommending PSO recover $42 million of the reallocated purchased power costs over three years and PSO reduced its regulatory asset deferral by $2 million.  The OCC subsequently expanded the case to include a full prudence review of PSO’s 2001 fuel and purchased power practices. In January 2006, the OCC staff and intervenors issued supplemental testimony alleging that AEP deviated from the FERC-approved method of allocating off-system sales margins between AEP East companies and AEP West companies and among AEP West companies. The OCC staff proposed that the OCC offset the $42 million of under-recovered fuel with the proposed reallocation of off-system sales margins of $27 million to $37 million and with $9 million attributed to wholesale customers, which they claimed had not been refunded. In February 2006, the OCC staff filed a report concluding that the $9 million of reallocated purchased power costs assigned to wholesale customers had been refunded, thus removing that issue from its recommendation.

In 2004, an Oklahoma ALJ found that the OCC lacks authority to examine whether PSOAEP 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 August 2007, the OCC issued an order adopting the ALJ’s recommendation that the allocation of system sales/trading margins is a FERC jurisdictional issue.  The Oklahoma Industrial Energy Customers (OIEC) filed a motion asking the OCC to reconsider its order on the jurisdictional issue.  The OCC hasstayed its final order regarding the FERC jurisdictional issue. In October 2007, the OCC lifted its stay stating the OCC does not ruled on appeals by intervenors ofhave jurisdiction regarding the ALJ’s finding. The United States District Courtallocation methodology for the Western District of Texas issued orders in September 2005 regarding a TNC fuel proceeding and in August 2006 regarding a TCC fuel proceeding, preempting the PUCT from reallocating off-system sales margins between the AEP East companies and AEP West companies. The federal court agreed that the FERC has sole jurisdiction over that allocation. The PUCT appealed the ruling. The United States Court of Appeals for the Fifth Circuit, issued a decision in December 2006 regarding the TNC fuel proceeding that affirmed the United States District Court ruling.margins.

PSO does not agree with the intervenors’ and the OCC staff’s recommendations and proposals other than the staff’s original recommendation that PSO be allowed to recover the $42 million over three years and will defend its right to recover its under-recovered fuel balance. Management believes that if the position taken by the federal courts in the Texas proceeding is applied to PSO’s case, then the OCC should be preempted from disallowing fuel recoveries for alleged improper allocations of off-system sales margins between AEP East companies and AEP West companies. The OCCOIEC or another party could file a complaint at the FERC alleging the allocation of off-system sales margins to PSO is improper, which could result in an adverse effect on future results of operations and cash flows for AEP and the AEP East companies.  However, to date, there has been no claim asserted at the FERC that the AEP System deviated from the approvedFERC-approved allocation methodologies, but even if one were asserted, management believes that it would not prevail. its allocation of off-system sales margins under the FERC-approved SIA agreement was consistent with that agreement.  In October 2007, the OCC directed OCC Staff to file a complaint at FERC concerning this matter.

In June 2005, the OCC issued an order directing its staff to conduct a prudence review of PSO’s fuel and purchased power practices for the year 2003.  The OCC staff filed testimony finding no disallowances in the test year data.  The Attorney General of Oklahoma filed testimony stating that they could not determine if PSO’s gas procurement activities were prudent, but did not include a recommended disallowance.  However, an intervenor filed testimony in June 2006 proposing the disallowance of $22 million in fuel costs based on a historical review of potential hedging opportunities PSO failed to achieve that he alleges existed during the year.  A hearing was held inIn August 20062007, an ALJ issued a report recommending that PSO’s fuel procurement practices were prudent and management expectsno adjustments were warranted.  No parties appealed the recommendation.  In October 2007, the OCC issued a recommendation fromfinal order adopting the ALJ in 2007.ALJ’s report.

In February 2006, the OCC enacted a law was enactedrule, requiring the OCC to conduct prudence reviews on all generation and fuel procurement processes, practices and costs on either a two or three-year cycle depending on the number of customers served.  PSO is subject to the required biennialperiodic reviews.  In compliance with an OCC order, PSO is required to filefiled its testimony byin June 15, 2007. This proceeding will cover2007 covering the year 2005. The OCC Staff and intervenors filed testimony in September 2007.

In May 2007, PSO submitted a filing to the OCC to adjust its fuel/purchase power rates.  In the filing, PSO netted the $42 million of under-recovered pre-2002 reallocated purchased power costs against their $48 million over-recovered fuel balance as of April 30, 2007.  The $6 million net over-recovered fuel/purchased power cost deferral balance will be refunded over the twelve-month period beginning June 2007.  However, in August 2007, the OIEC filed a motion asking the OCC to order a refund of the $42 million pre-2002 reallocated purchased power costs netted against the current over-recovered fuel balance.  In October 2007, the OCC denied the OIEC’s request for refund of the $42 million of under-recovered pre-2002 reallocated purchased power costs.

Management cannot predict the outcome of the pending fuel and purchased power costs and prudence reviews, or planned future reviews, but believes that PSO’s fuel and purchased power procurement practices and costs are prudent and properly incurred. If the OCC disagrees and disallows fuel or purchased power costs including the unrecovered 2002 reallocation of such costs incurred by PSO, it would have an adverse effect on future results of operations and cash flows.

PSOOklahoma Rate Filing -– Affecting PSO

In November 2006, PSO filed a request to increase base rates by $50 million for Oklahoma jurisdictional customers and set return on equity at 11.75% with a proposed effective date in the second quarter of 2007.  PSO sought a return on equity of 11.75%. PSO also proposed a formula rate plan that, if approved as filed, willwould permit PSO to defer any unrecovered costs as a result of a revenue deficiency that exceeds 50 basis points of the allowed return on equity for recovery within twelve months beginning six months after the test year.  The proposed formula rate plan would enable PSO to recover on a timely basis the cost of its new generation, transmission and distribution construction (including carrying costs during construction), provide the opportunity to achieve the approved return on equity and avoid recordingprevent the capitalization of a significant amount of AFUDC that would have been recorded during the construction time period.period and recovered in the future through depreciation expense.

In MarchThe ALJ issued a report in May 2007 the OCC staff and various intervenors filed testimony. The recommendations were base rate reductions that ranged from $18 million to $52 million. The recommended returnsrecommending a 10.5% return on equity ranged from 9.25% to 10.09%. These recommendations included reductions in depreciation expense of approximately $25 million, which has no earnings impact.but did not compute an overall revenue requirement.  The OCC staff filed testimony supportingALJ’s report did not recommend adopting a formula rate plan, generally similar tobut did recommend recovery through a rider of certain generation and transmission projects’ financing costs during construction.  However, the one proposed by PSO. In April 2007, PSO filed rebuttal testimony regarding various issues raised byreport also contained an alternative recommendation that the OCC Staffcould delay a decision on the rider and the intervenors. Astake up this issue in PSO’s application seeking regulatory approval of a result of rebuttal testimony,new coal-fueled generating unit.  PSO reduced its base rate request by $2 million. Hearings commenced on May 1,implemented interim rates, subject to refund, for residential customers beginning July 2007.

Management is unableIn October 2007, the OCC issued a final order providing for a $10 million annual increase in base rates with a return on equity of 10%.  The final order also provides for lower depreciation rates, which PSO estimates will decrease depreciation expense by approximately $10 million on an annual basis.  PSO estimates the annual impact of this final order will increase PSO’s pretax income by $20 million.  The final order also requires PSO to predictfile a plan with the outcome of these proceedings, however, ifOCC to promote energy efficiency and conservation programs within 60 days.  PSO implemented the approved rates are not increased in an amount sufficient to recover expected unavoidable cost increases future results of operations, cash flows and possibly financial condition could be adversely affected.October 2007.

PSO Lawton and Peaking Generation Settlement Agreement -– Affecting PSO

OnIn November 26, 2003, pursuant to an application by Lawton Cogeneration, L.L.C. (Lawton) seeking approval of a Power Supply Agreement (the Agreement) with PSO and associated avoided cost payments, the OCC issued an order approving the Agreement and setting the avoided costs. The order did not address recovery by PSO of the resultant purchased power costs.

In December 2003, PSO filed an appeal of the OCC’s order with the Oklahoma Supreme Court (the Court).  In the appeal, PSO maintained that the OCC exceeded its authority under state and federal laws to require PSO to enter into the Agreement.  The Court issued a decision onin June 21, 2005, affirming portions of the OCC’s order and remanding certain provisions.  The Court affirmed the OCC’s finding that Lawton established a legally enforceablelegally-enforceable obligation and ruled that it was within the OCC’s discretion to award a 20-year contract and to base the capacity payment on a peaking unit.  The Court directed the OCC to revisit its determination of PSO’s avoided energy cost. Hearings were held on the remanded issues in April and May 2006.

In April 2007, all parties in the case filed a settlement agreement with the OCC resolving all issues. The OCC approved the settlement agreement in April 2007.  The OCC staff, the Attorney General, the Oklahoma Industrial Energy Consumers and Lawton Cogeneration, L.L.C. supported this settlement agreement.  The settlement agreement provides for a purchase fee of $35 million to be paid by PSO to Lawton and for Lawton to provide, at PSO’s direction, all rights to the Lawton Cogeneration Facility forincluding permits, options and engineering studies.  PSO will recordpaid the $35 million purchase fee in June 2007 and recorded the purchase fee as a regulatory asset and will recover it through a rider over a three-year period with a carrying charge of 8.25% beginning in September 2007.  In addition, PSO will recover through a rider, subject to a $135 million cost cap, all of the traditional costs associated with plant in service of its new peaking units to be located at the Southwestern Station and Riverside Station at the time these units are placed in service.service, currently expected to be 2008.  PSO expects these units will have a substantially lower plant-in-service cost than the proposed Lawton Cogeneration Facility.  PSO may request approval from the OCC for recovery of costs exceeding the cost cap if special circumstances occurredoccur necessitating a higher level of costs.  Such costs will continue to be recovered through the rider until cost recovery occurs through base rates or formula rates in a subsequent proceeding.  Under the settlement, PSO must file a rate case within eighteen months of the beginning of recovery through the rider unless the OCC approves a formula-based rate mechanism that provides for recovery of the peaking units. Once

Red Rock Generating Facility – Affecting PSO

In July 2006, PSO announced plans to enter into an agreement with Oklahoma Gas and Electric (OG&E) to build a 950 MW pulverized coal ultra-supercritical generating unit at the site of OG&E’s existing Sooner Plant near Red Rock, in north central Oklahoma.  PSO would own 50% of the new unit, OG&E would own approximately 42% and the Oklahoma Municipal Power Authority (OMPA) would own approximately 8%.  OG&E would manage construction of the plant.  OG&E and PSO requested pre-approval to construct the Red Rock Generating Facility and implement a recovery rider.  In March 2007, the OCC consolidated PSO’s pre-approval application with OG&E’s request.  The Red Rock Generating Facility was estimated to cost $1.8 billion and was expected to be in service in 2012.  The OCC staff and the ALJ recommended the OCC approve PSO’s and OG&E’s filing.  As of September 2007, PSO incurred approximately $20 million of pre-construction costs and contract cancellation fees.

In October 2007, the OCC issued a final order approving PSO’s need for 450 MWs of additional capacity by the year 2012, but denied PSO’s and OG&E’s application for construction pre-approval stating PSO and OG&E failed to fully study other alternatives.  Since PSO and OG&E could not obtain pre-approval to build the Red Rock Generating Facility, PSO and OG&E cancelled the third party construction contract and their joint venture development contract.  Management believes the pre-construction costs capitalized, including any cancellation fees, were prudently incurred, as evidenced by the OCC staff and the ALJ’s recommendations that the OCC approve PSO’s filing, and established a regulatory asset for future recovery.  Management believes such pre-construction costs are probable of recovery and intends to seek full recovery of such costs in the near future.  If recovery is denied, future results of operations and cash flows would be adversely affected.  As a result of the OCC’s decision, PSO will consider various alternative options to meet its capacity needs in the future.

2007 Oklahoma Ice Storm – Affecting PSO

In October 2007, PSO filed with the OCC requesting recovery of $13 million of operation and maintenance expenses related to service restoration effort after a January 2007 ice storm.  PSO proposed to establish a regulatory asset of $13 million and to amortize this asset coincident with the gains from the sale of SO2 allowances made during 2007 and thereafter until such gains provide for the new peaking units begins in mid-2008, PSO expects annual revenues of an estimated $36 million related to costfull recovery of the peaking units and the purchase fee. This settlement agreement was supported byregulatory asset.  If the OCC Staff,adopts the Attorney General, the Oklahoma Industrial Energy ConsumersPSO proposal, it would have a favorable impact on future results of operations and Lawton Cogeneration, L.L.C.cash flows.

Louisiana Rate Matters

SWEPCo Louisiana Compliance Filing -– Affecting SWEPCo

In October 2002, SWEPCo filed with the LPSC detailed financial information typically utilized in a revenue requirement filing, including a jurisdictional cost of service.service, with the LPSC.  This filing was required by the LPSC as a result of its order approving the merger between AEP and CSW.  Due to multiple delays, in April 2006, the LPSC and SWEPCo agreed to update the financial information based on a 2005 test year.  SWEPCo filed updated financial review schedules in May 2006 showing a return on equity of 9.44% compared to the previously authorizedpreviously-authorized return on equity of 11.1%.

In July 2006, the LPSC staff’s consultants filed direct testimony recommending a base rate reduction in the range of $12 million to $20 million for SWEPCo’s Louisiana jurisdictionjurisdictional customers, based on a proposed 10% return on equity.  The recommended reduction range iswas subject to SWEPCo validating certain ongoing operations and maintenance expense levels.  SWEPCo filed rebuttal testimony in October 2006 strongly refuting the consultants’ recommendations.  In December 2006, the LPSC staff’s consultants filed reply testimony asserting that SWEPCo’s Louisiana base rates are excessive by $17 million which includes a proposed return on equity of 9.8%.  SWEPCo filed rebuttal testimony in January 2007.  A decision is not expected until mid or late 2007.Constructive settlement negotiations are making meaningful progress.  At this time, management is unable to predict the outcome of this proceeding.  If a rate reduction is ultimately ordered, it would adversely impactaffect future results of operations, cash flows and possibly financial condition.

Stall Unit – Affecting SWEPCo

In May 2006, SWEPCo announced plans to build a new intermediate load 480 MW natural gas-fired combustion turbine combined cycle generating unit at its existing Arsenal Hill Plant location in Shreveport, Louisiana.  SWEPCo submitted the appropriate filings with the PUCT and the Arkansas Public Service Commission (APSC) during the third quarter of 2006 and the LPSC during the first quarter of 2007 to seek approvals to construct the unit.  The Stall Unit is estimated to cost $375 million, excluding AFUDC, and expected to be in service in mid-2010.  As of September 2007, SWEPCo incurred and capitalized approximately $15 million and has contractual commitments of an additional $17 million.

In March 2007, the PUCT approved SWEPCo’s request.  In Louisiana, this request has been separated from the original request, which included the Turk Plant.  Neither the LPSC nor the APSC have set a procedural schedule for the project.  The project is contingent upon obtaining pre-approval from the APSC, the LPSC, the PUCT and the Louisiana Department of Environmental Quality.  If SWEPCo is not authorized to build the Stall Unit, SWEPCo would seek recovery of incurred costs including any cancellation fees.  If SWEPCo cannot recover incurred costs, including any cancellation fees, it could adversely affect future results of operations, cash flows and 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 a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas named Turk Plant.  SWEPCo submitted filings with the APSC in December 2006 and the PUCT and LPSC in February 2007 to seek approvals to proceed with the plant.  In September 2007, OMPA signed a joint ownership agreement and agreed to own approximately 7% of the Turk Plant.  SWEPCo continues discussions with Arkansas Electric Cooperative Corporation and North Texas Electric Cooperative to become potential partners in the Turk Plant.  SWEPCo anticipates owning approximately 73% of the Turk Plant and will operate the facility.  The Turk Plant is estimated to cost $1.3 billion in total with SWEPCo’s portion estimated to cost $950 million, excluding AFUDC.  If approved on a timely basis, the plant is expected to be in-service in mid-2011.  As of September 2007, SWEPCo incurred and capitalized approximately $206 million and has contractual commitments for an additional $875 million.  If SWEPCo is not authorized to build the Turk plant, SWEPCo would seek recovery of incurred costs including any cancellation fees.  If SWEPCo cannot recover incurred cots, including any cancellation fees, it could adversely affect future results of operations, cash flows and possibly financial condition.

In August 2007, hearings began before the APSC seeking pre-approval of the plant. The APSC staff recommended the application be approved and intervenors requested the motion be denied.  In October 2007, final briefs and closing arguments were completed by all parties during which the APSC staff and Attorney General supported the plant.  A decision by the APSC will occur within 60 days from October 22, 2007.  In September 2007, the PUCT staff recommended that SWEPCo’s application be denied suggesting the construction of the Turk Plant would adversely impact the development of competition in the SPP zone.  The PUCT hearings were held in October 2007.  The LPSC held hearings in September 2007 and during this proceeding, the LPSC staff expressed support for the project.   If SWEPCo is not authorized to build the Turk plant, it could adversely affect future results of operations, cash flows and possibly financial condition if SWEPCo cannot recover incurred costs, including any cancellation fees.

Stall Unit – Affecting SWEPCo

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

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

The FERC PJM Regional Transmission Rate Proceeding

At AEP’s urging, the FERC instituted an investigation of PJM’s zonal rate regime, indicating that the present rate regime may need to be replaced through establishment of regional rates that would compensate AEP and other transmission owners for the regional transmission facilities they provide to PJM, which provides service for the benefit of customers throughout PJM. In September 2005, AEP and a nonaffiliated utility (Allegheny Power or AP) jointly filed a regional transmission rate design proposal with the FERC. This filing proposes and supports a new PJM rate regime generally referred to as Highway/Byway.

Parties to the regional rate proceeding proposed the following rate regimes:

·AEP/AP proposed a Highway/Byway rate design in which:
·The cost of all transmission facilities in the PJM region operated at 345 kV or higher would be included in a “Highway” rate that all load serving entities (LSEs) would pay based on peak demand. The AEP/AP proposal would produce about $125 million in additional revenues per year for AEP from users in other zones of PJM.
·The cost of transmission facilities operating at lower voltages would be collected in the zones where those costs are presently charged under PJM’s existing rate design.
·Two other utilities, Baltimore Gas & Electric Company (BG&E) and Old Dominion Electric Cooperative (ODEC), proposed a Highway/Byway rate that includes transmission facilities above 200 kV, which would produce lower revenues for AEP than the AEP/AP proposal.
·In another competing Highway/Byway proposal, a group of LSEs proposed rates that would include existing 500 kV and higher voltage facilities and new facilities above 200 kV in the Highway rate, which would produce considerably lower revenues for AEP than the AEP/AP proposal.
·In January 2006, the FERC staff issued testimony and exhibits supporting a PJM-wide flat rate or “Postage Stamp” type of rate design that would include all transmission facilities, which would produce higher transmission revenues for AEP than the AEP/AP proposal.

All of these proposals were challenged by a majority of other transmission owners in the PJM region, who favor continuation of the existing PJM rate design which provides AEP with no compensation for through and out traffic on its east zone transmission system. Hearings were held in April 2006 and the ALJ issued an initial decision in July 2006. The ALJ found the existing PJM zonal rate design to be unjust and determined that it should be replaced. The ALJ found that the Highway/Byway rates proposed by AEP/AP and BG&E/ODEC and the Postage Stamp rate proposed by the FERC staff to be just and reasonable alternatives. The ALJ also found FERC staff’s proposed Postage Stamp rate to be just and reasonable and recommended that it be adopted. The ALJ also found that the effective date of the rate change should be April 1, 2006 to coincide with SECA rate elimination. Because the Postage Stamp rate was found to produce greater cost shifts than other proposals, the judge also recommended that the design be phased-in. Without a phase-in, the Postage Stamp method would produce more revenue for AEP than the AEP/AP proposal. The phase-in of Postage Stamp rates would delay the full impact of that result until about 2012.

AEP filed briefs noting exceptions to the initial decision and replies to the exceptions of other parties. AEP argued that a phase-in should not be required. Nevertheless, AEP argued that if the FERC adopts the Postage Stamp rate and a phase-in plan, the revenue collections curtailed by the phase-in should be deferred and paid later with interest.

During 2006, the AEP East companies sought to increase retail rates in most of their states to recover lost T&O and SECA revenues. The status of such state retail rate proceedings is as follows:

·In Kentucky, KPCo settled a rate case, which provided for the recovery of its share of the transmission revenue reduction in new rates effective March 30, 2006.
·In Ohio, CSPCo and OPCo recover their FERC-approved OATT that reflects their share of the full transmission revenue requirement retroactive to April 1, 2006 under a May 2006 PUCO order.
·In West Virginia, APCo settled a rate case, which provided for the recovery of its share of the T&O/SECA transmission revenue reduction beginning July 28, 2006.
·In Virginia, APCo filed a request for revised rates, which includes recovery of its share of the T&O/SECA transmission revenue reduction starting October 2, 2006, subject to refund.
·In Indiana, I&M is precluded by a rate cap from raising its rates until July 1, 2007.
·In Michigan, I&M has not filed to seek recovery of the lost transmission revenues.

In April 2007, the FERC issued an order reversing the ALJ decision. The FERC ruled that the current PJM rate design is just and reasonable. The FERC further ruled that the cost of new facilities of 500 kV and above would be shared among all PJM participants. As a result of this order, the AEP East companies retail customers will be asked to bear the full cost of the existing AEP east transmission zone facilities. However, the AEP East companies customers will also be charged a share of the cost of new 500 kV and higher voltage transmission facilities built in PJM, of which the vast majority for the foreseeable future will not be needed by their customers, but will bolster service and reduce costs in other zones of PJM. The AEP East companies will need to obtain regulatory approvals for recovery of any costs of new facilities that are assigned to them as a result of this order, if upheld. AEP will request rehearing of this order. Management cannot estimate at this time what effect, if any, this order will have on their future construction of new east transmission facilities, results of operations, cash flows and financial condition.

The AEP East companies presently recover from retail customers approximately 85% of the reduction in transmission revenues of $128 million a year. Future results of operations, cash flows and financial condition will continue to be adversely affected in Indiana and Michigan until these lost transmission revenues are recovered in retail rates.

SECA Revenue Subject to Refund

TheEffective December 1, 2004, AEP East companies ceased collectingand other transmission owners in the region covered by PJM and MISO eliminated transaction-based through-and-out transmission service (T&O) revenuescharges in accordance with FERC orders and collected load-based charges, referred to as RTO SECA, rates to mitigate the loss of T&O revenues from December 1, 2004on a temporary basis through March 31, 2006, when SECA rates expired.2006.  Intervenors objected to the 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 or surcharge.  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. APCo’s, CSPCo’s, I&M’s and OPCo’s portions of recognized gross SECA revenues are as follows:

  
Year Ended December 31,
 
  
2006 (a)
 
2005
 
2004
 
Company
 
(in millions)
 
APCo $13.4 $52.4 $4.4 
CSPCo  7.9  28.4  2.5 
I&M  8.1  30.4  2.8 
KPCo  3.2  12.4  1.0 
OPCo  10.4  39.4  3.5 

(a)
Represents revenues through March 31, 2006, when SECA rates expired, and excludes all provisions for refund.
Company
 
(in millions)
 
APCo $70.2 
CSPCo  38.8 
I&M  41.3 
OPCo  53.3 

Approximately $19$10 million of these recorded SECA revenues billed by PJM were nevernot collected.  The AEP East companies filed a motion with the FERC to force payment of these uncollected SECA billings.

In August 2006, thea 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 was not 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.

Since the implementation of SECA rates in December 2004,In 2006, the AEP East companies recorded approximately $220provided reserves of $37 million in net refunds for current and future SECA settlements with all of grossthe AEP East companies’ SECA revenues, subject to refund. customers.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the reserve are as follows:

Company
 
(in millions)
 
APCo $12.0 
CSPCo  6.7 
I&M  7.0 
OPCo  9.1 

The AEP East companies reached settlements with certain SECA customers related to approximately $70$69 million of such revenues.revenues for a net refund of $3 million.  The unsettled grossAEP East companies are in the process of completing two settlements-in-principle on an additional $36 million of SECA revenues totaland expect to make net refunds of $4 million when those settlements are approved.  Thus, completed and in-process settlements cover $105 million of SECA revenues and will consume about $7 million of the reserves for refunds, leaving approximately $150 million.$115 million of contested SECA revenues and $30 million of refund reserves.  If the ALJ’s initial decision iswere upheld in its entirety, it would disallow $126approximately $90 million of the AEP East companies’ remaining $115 million of unsettled gross SECA revenues.

The AEP East companies provided for net refunds as shown in  Based on recent settlement experience and the following table:

  
Year Ended December 31,
 
  
2006
 
2005
 
Company
 
(in millions)
 
APCo $11.0 $1.0 
CSPCo  6.1  0.6 
I&M  6.4  0.6 
KPCo  2.6  0.2 
OPCo  8.3  0.8 
expectation that most of the $115 million of unsettled SECA revenues will be settled, management believes that the remaining reserve of $30 million will be adequate to cover all remaining settlements.

In September 2006, AEP, together with Exelon Corporation and DP&L,The Dayton Power and Light Company, filed an extensive post-hearing brief and reply brief noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part.  Management believes that the FERC should reject the initial decision because it is contrary tocontradicts 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 directed by the FERC, management is working to settle the remaining $115 million of unsettled revenues within the remaining reserve balance.  Although management believes they haveit has meritorious arguments and can settle with the remaining customers within the amount provided, management cannot predict the ultimate outcome of ongoing settlement talks and, if necessary, any future FERC proceedings or court appeals.  If the FERC adopts the ALJ’s decision and/or AEP cannot settle a significant portion of the remaining unsettled claims within the amount provided, it will have an adverse effect on future results of operations, cash flows and financial condition.

The FERC PJM Regional Transmission Rate Proceeding

In January 2005, certain transmission owners in PJM proposed continuation of the zonal rate design in PJM after the June 2005 FERC deadline.  With the elimination of T&O rates and the expiration of SECA rates, zonal rates would provide the AEP System no revenue for use of its transmission facilities by other parties in PJM and the MISO.  AEP protested the zonal rate proposal and at AEP’s urging, the FERC instituted an investigation of PJM’s zonal rate regime indicating that the present rate regime may need to be replaced through establishment of regional rates that would compensate the AEP East companies and other transmission owners for the regional transmission facilities they provide to PJM, which provides service for the benefit of customers throughout PJM.  In September 2005, AEP and a nonaffiliated utility (Allegheny Power or AP) jointly filed a regional transmission rate design proposal with the FERC.  This filing proposed and supported a new PJM rate regime generally referred to as a Highway/Byway rate design.

Hearings were held in April 2006 and the ALJ issued an initial decision in July 2006.  The ALJ found the existing PJM zonal rate design to be unjust and determined that it should be replaced.  The ALJ found the Highway/Byway proposed rates to be just and reasonable alternatives.  The ALJ also found FERC staff’s proposed Postage Stamp rate to be just and reasonable and recommended that it be adopted.  The ALJ also found that the effective date of the rate change should be April 1, 2006 to coincide with SECA rate elimination.

In April 2007, the FERC issued an order reversing the ALJ’s decision.  The FERC ruled that the current PJM rate design is just and reasonable for existing transmission facilities.  However, the FERC ruled that the cost of new facilities of 500 kV and above would be shared among all PJM participants.  As a result of this order, the AEP East companies’ retail customers will bear the full cost of the existing AEP east transmission zone facilities.  Presently AEP is collecting the full cost of those facilities from its retail customers with the exception of Indiana and Michigan customers.  As a result of this order, the AEP East companies’ customers will also be charged a share of the cost of future new 500 kV and higher voltage transmission facilities built in PJM, most of which are expected to be upgrades of the facilities in other zones of PJM.  The AEP East companies will need to obtain regulatory approvals for recovery of any costs of new facilities that are assigned to them as a result of this order, if upheld.  AEP has requested rehearing of this order.  Management cannot estimate at this time what effect, if any, this order will have on the AEP East companies’ future construction of new east transmission facilities, results of operations, cash flows and financial condition.  In May 2007, the AEP East companies filed for rehearing related to this FERC decision.

Since the FERC’s decision in 2005 to cease through-and-out rates and replace them temporarily with SECA rates, which ceased on April 1, 2006, the AEP East companies increased their retail rates in all states except Indiana, Michigan and Tennessee to recover lost T&O and SECA revenues.  The AEP East companies presently recover from retail customers approximately 85% of the lost T&O/SECA transmission revenues of $128 million a year.  Future results of operations, cash flows and financial condition will continue to be adversely affected in Indiana, Michigan and Tennessee until these lost T&O/SECA 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 effective February 1, 2008.  All of the transmission owners in PJM and MISO, with the exception of AEP and one MISO transmission owner, voted to continue 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.  AEP argues 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 the provision and use of transmission service in the Super Region since it is not sufficiently uniform between transmission owners and users to justify zonal rates.  Management is unable to predict the outcome of this case.

SPP Transmission Formula Rate Filing – Affecting PSO and SWEPCo

In June 2007, AEPSC filed revised tariff sheets on behalf of PSO and SWEPCo for the AEP pricing zone of the SPP OATT.  The revised tariff sheets seek to establish an up-to-date revenue requirement for SPP transmission services over the facilities owned by PSO and SWEPCo and implement a transmission cost of service formula rate.

PSO and SWEPCo requested an effective date of September 1, 2007 for the revised tariff.  The primary impact of the filed revised tariff will be an increase in network transmission service revenues from nonaffiliated municipal and rural cooperative utilities in the AEP pricing zone of SPP.  If the proposed formula rate and requested return on equity are approved, the 2008 network transmission service revenues from nonaffiliates will increase by approximately $10 million compared to the revenues that would result from the presently approved network transmission rate.  PSO and SWEPCo take service under the same rate, and will also incur the increased OATT charges resulting from the filing, but will receive corresponding revenue to offset the increase.  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 hearing and settlement judge proceedings. In October 2007, AEPSC submitted a compliance filing on behalf of PSO and SWEPCo.  Multiple intervenors have protested or requested re-hearing of the order.  Discovery and settlement discussions have begun.

PJM Marginal-Loss Pricing – Affecting APCo, CSPCo, I&M and OPCo

On June 1, 2007, in response to a 2006 FERC order, PJM revised its methodology for considering transmission line losses in generation dispatch and the calculation of locational marginal prices.   Marginal-loss dispatch recognizes the varying delivery costs of transmitting electricity from individual generator locations to the places where customers consume the energy.  Prior to the implementation of marginal-loss dispatch, PJM used average losses in dispatch and in the calculation of locational marginal prices.  Locational marginal prices in PJM now include the real-time impact of transmission losses from individual sources to loads.  Due to the implementation of marginal-loss pricing, for the period June 1, 2007 through September 30, 2007, AEP experienced an increase in the cost of delivering energy from the generating plant locations to customer load zones partially offset by cost recoveries and increased off-system sales resulting in a net loss of approximately $25 million.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the loss are as follows:

Company
 
(in millions)
 
APCo $6 
CSPCo  5 
I&M  5 
OPCo  5 

AEP has initiated discussions with PJM regarding the impact it is experiencing from the change in methodology and will pursue through the appropriate stakeholder processes a modification of such methodology.  Management believes these additional costs should be recoverable through retail and/or cost-based wholesale rates and is seeking recovery in current and future fuel or base rate filings as appropriate in each of its eastern zone states.  In the interim, these costs will have an adverse effect on future results of operations and cash flows.  Management is unable to predict whether full recovery will ultimately be approved.

         4.
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 2006 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.FIN 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 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, debt service reserves and credit enhancements for issued bonds.  All of these LOCs were issued in the subsidiaries’ ordinary course of business.  At March 31,September 30, 2007, the maximum future payments of the LOCs include $1 million and $4 million for I&M and SWEPCo, respectively, with maturities ranging from JuneDecember 2007 to March 2008.

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 $85$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 46.  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 March 31,September 30, 2007, SWEPCo collected approximately $30$33 million through a rider for final mine closure costs, which 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 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 March 31,September 30, 2007, the Registrant Subsidiaries entered into sale agreements including indemnifications with a maximum exposure that was not significant for any individual Registrant Subsidiary except TCC. TCC sale agreements include indemnifications with a maximum exposure of $456 million related to the sale price of its generation assets. See “Texas Plants - South Texas Project”, “Texas Plants - TCC Generation Assets” and “Texas Plants - Oklaunion Power Station” sections of Note 8 of the 2006 Annual Report.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 has 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.  At March 31, 2007, the maximum potential loss by subsidiary for these lease agreements assumingAssuming the fair market value of the equipment is zero at the end of the lease term, isthe maximum potential loss for these lease agreements as of September 30, 2007 was as follows:
 
 
Maximum
 
 
Potential
 
 
Maximum Potential Loss
  
Loss
 
Company
 
(in millions)
  
(in millions)
 
APCo $7  $9 
CSPCo  4   4 
I&M  5   6 
KPCo  2 
OPCo  7   8 
PSO  5   5 
SWEPCo  6   6 
TCC  6 
TNC  3 

CONTINGENCIES

Federal EPA Complaint and Notice of Violation -– Affecting APCo, CSPCo, I&M, and OPCo

The Federal EPA, certain special interest groups and a number of states allege that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities including the Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric Company, Ohio Edison Company, Southern Indiana Gas & Electric Company, Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company and Duke Energy, modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA.  The Federal EPA filed its complaints against AEP subsidiaries in U.S. District Court for the Southern District of Ohio.  The alleged modifications occurred at ourthe AEP System’s generating units over a twenty-year20-year period.  A bench trial on the liability issues was held during July 2005. In June 2006, the judge stayed the liability decision pending the issuance of a decision byApril 2007, the U.S. Supreme Court inreversed the Fourth Circuit Court of Appeals’ decision that had supported the statutory construction argument of Duke Energy case.in its NSR proceeding.

On October 9, 2007, management announced that the AEP System had entered into a consent decree with the Federal EPA, the DOJ, the states and the special interest groups. Under the consent decree the AEP System agreed to annual SO2 and NOx emission caps for sixteen coal-fired power plants located in Indiana, Kentucky, Ohio, Virginia and West Virginia. In addition to completing the installation of previously announced environmental retrofit projects at many of the plants, including the installation of flue gas desulfurization (FGD or scrubbers) equipment at KPCo’s Big Sandy Plant and at OPCo’s Muskingum River Plant by the end of 2015, AEGCo and I&M agreed to install selective catalytic reduction (SCR) and FGD emissions control equipment on their jointly owned generating units at the Rockport Plant. Unit 1 at the Rockport Plant will be retrofit by the end of 2017, and Unit 2 will be retrofit by the end of 2019.  APCo also agreed to install selective non-catalytic reduction, a NOx-reduction technology, by the end of 2009 at the Clinch River Plant.

Since 2004, the AEP System spent nearly $2.6 billion on installation of emissions control equipment on coal-fueled plants in Kentucky, Ohio, Virginia and West Virginia as part of a larger plan to invest more than $5.1 billion by 2010 to reduce the emissions of the generating fleet.  Capital amounts by Registrant Subsidiary are as follows:

  
Incurred Capital
   
  
Amount Through
  
Budgeted Capital
  
December 31,  2006
  
2007 - 2010
  
(in millions)
APCo $923  $944
CSPCo  194   374
I&M  98   77
OPCo  1,253   891

Management agreed to operate SCRs year round during 2008 at APCo’s Mountaineer Plant, OPCo’s Muskingum River Plant and APCo’s and OPCo’s jointly owned Amos Plant, and agreed to plant-specific SO2 emission limits for Clinch River Plant and OPCo’s Kammer Plant.
Under the CAA, ifconsent decree, the AEP System will pay a plant undertakes a major modification that results$15 million civil penalty and provide $36 million for environmental projects coordinated with the federal government and $24 million to the states for environmental mitigation.  The Registrant Subsidiaries expensed their share of these amounts in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities suchthird quarter of 2007 as routine maintenance, replacement of degraded equipment or failed components or other repairs needed for the reliable, safe and efficient operation of the plant. The CAA authorizes civil penalties of up to $27,500 ($32,500 after March 15, 2004) per day per violation at each generating unit. In 2001, the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief.follows:

     
Environmental
 
Total Expensed in
  
Penalty
  
Mitigation Costs
 
September 2007
  
(in thousands)
APCo $4,974  $20,659 $25,633
CSPCo  2,883   11,973  14,856
I&M  2,770   11,503  14,273
OPCo  3,355   13,935  17,290

The Federal EPA and eight northeastern states each filed an additional complaint containing additional allegationsconsent decree will resolve all issues related to various parties’ claims against the AmosRegistrant Subsidiaries in the two pending NSR cases. The consent decree has been filed with the U.S. District Court. The consent decree is subject to a 30-day public comment period and Conesville plants.final approval by the Court.  A hearing on the motion to approve the consent decree is scheduled for December 10, 2007.
Management believes that APCo, CSPCo, I&M and CSPCo filed an answerOPCo can recover any capital and operating costs of additional pollution control equipment that may be required as a result of the consent decree through regulated rates or market prices of electricity.  If they are unable to the northeastern states’ complaintrecover such costs, it would adversely affect their future results of operations, cash flows and the Federal EPA’s complaint, denying the allegations and stating their defenses. possibly financial condition.
Cases are also pending that could affect CSPCo’s share of jointly-owned units at Beckjord (12.5% owned), Zimmer (25.4% owned), and Stuart (26% owned) Stations.stations.  No trial date has yet been established in the Stuart case, but the units, operated by Dayton Power and Light Company, are equipped with SCR controls and the installation of FGD controls will be completed in 2007.  The Beckjord and Zimmer case is scheduled for a liability trial in May 2008.  Zimmer is equipped with both FGD and SCR controls.  Beckjord and Zimmer are operated by Duke Energy Ohio, Inc.  Similar cases have been filed against other nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk.  Several of these cases were resolved through consent decrees.

Courts have reached different conclusions regarding whether the activities at issue in these cases are routine maintenance, repair, or replacement, and therefore are excluded from NSR. Similarly, courts have reached different results regarding whether the activities at issue increased emissions from the power plants. Appeals on these and other issues were filed in certain appellate courts, including a petition to appeal to the U.S. Supreme Court that was granted in the Duke Energy case. The Federal EPA issued a final rule that would exclude activities similar to those challenged in these cases from NSR as “routine replacements.” In March 2006, the Court of Appeals for the District of Columbia Circuit issued a decision vacating the rule. The Court denied the Federal EPA’s request for rehearing, and the Federal EPA and other parties filed a petition for review by the U.S. Supreme Court. In April 2007, the Supreme Court denied the petition for review. The Federal EPA also proposed a rule that would define “emissions increases” in a way that most of the challenged activities would be excluded from NSR.

On April 2, 2007, the U.S. Supreme Court reversed the Fourth Circuit Court of Appeals’ decision that had supported the statutory construction argument of Duke Energy in its NSR proceeding. In a unanimous decision, the Court ruled that the Federal EPA was not obligated to define “major modification” in two different CAA provisions in the same way. The Court also found that the Fourth Circuit’s interpretation of “major modification” as applying only to projects that increased hourly emission rates amounted to an invalidation of the relevant Federal EPA regulations, which under the CAA can only be challenged in the Court of Appeals within 60 days of the Federal EPA rulemaking. The U.S. Supreme Court did acknowledge, however, that Duke Energy may argue on remand that the Federal EPA has been inconsistent in its interpretations of the CAA and the regulations and may not retroactively change 20 years of accepted practice.

In addition to providing guidance on certain of the merits of the NSR proceedings brought against APCo, CSPCo, I&M and OPCo in U.S. District Court for the Southern District of Ohio, the U.S. Supreme Court’s issuance of a ruling in the Duke Energy cases has an impact on the timing of our NSR proceedings. First, the court in the case for which a trial on liability issues has been conducted has indicated an intent to issue a decision on liability. Second, the bench trial on remedy issues, if necessary, is likely to be scheduled to begin in the third quarter of 2007.

Management is unable to estimate the loss or range of loss related to any contingent liability, if any, AEP subsidiariesCSPCo might have for civil penalties under the pending CAA proceedings.proceedings for the jointly-owned plants.  Management is also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court.  If AEP subsidiaries doCSPCo does not prevail, management believes AEP subsidiariesCSPCo can recover any capital and operating costs of additional pollution control equipment that may be required through regulated rates and market prices for electricity.  If any of the AEP subsidiaries are unable to recover suchtheir capital and operating costs or if material penalties are imposed for CSPCo’s jointly-owned plants, 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 Court for the Eastern District of Texas alleging violations of the CAA at SWEPCo’s Welsh Plant.  SWEPCo filed a response to the complaint in May 2005.  A trial in this matter is scheduled forto commence during the secondfirst quarter of 2007.2008.

In 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary of findings resulting from a compliance investigation at the plant.  In April 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of approximately $228 thousand against SWEPCo based on alleged violations of certain representations regarding heat input in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements.  SWEPCo responded to the preliminary report and petition in May 2005.  The enforcement order contains a recommendation that would limit the heat input on each Welsh unit to the referenced heat input contained within the permit application within 10 days of the issuance of a final TCEQ order and until a permit amendment is issued.  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 removing the heat input references from the Welsh permit and clarifying the sulfur content of fuels burned at the plant is limited to 0.5% on an as-received basis.  The Sierra Club and Public Citizen filed a motion to overturn the permit alteration.  In June 2007, TCEQ denied that motion.

Management is unable to predict the timing of any future action by TCEQ or the special interest groups or the effect of such actions on results of operations, 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 defendant’sdefendants’ 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 defendants’ motion to dismiss the lawsuits was granted in September 2005.  The dismissal was appealed to the Second Circuit Court of Appeals.  Briefing and oral argument have concluded.  On April 2, 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 Supreme Court’s decision on this case.  Management believes the actions are without merit and intends to defend against the claims.

TEM Litigation -– Affecting OPCo

OPCo 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 dated November 15, 2000 (PPA).  Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming.

In September 2003, TEM and OPCo separately filed declaratory judgment actions in the United States District Court for the Southern District of New York.  OPCo alleged that TEM breached the PPA, and sought a determination of its rights under the PPA.  TEM alleged that the PPA never became enforceable, or alternatively, that the PPA was terminated as the result of OPCo’s breaches.  The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) provided a limited guaranty.

In August 2005, a federal judge ruled that TEM had breached the contract and awarded damages to OPCo of $123 million plus prejudgment interest.  Any eventual proceeds will be recorded asnot impact OPCo’s income statement due to the indemnification agreement with AEP Resources (AEPR), a gain when received.nonutility subsidiary of AEP, whereby AEPR held OPCo harmless from market exposure related to the PPA.

In September 2005, TEM posted a $142 million letter of credit as security pending appeal of the judgment. Both parties filed Notices of Appeal withMay 2007, the United States Court of Appeals for the Second Circuit which heard oral argument onruled that the appealslower court was correct in December 2006. Management cannot predictfinding that TEM breached the ultimate outcomePPA and OPCo did not breach the PPA.  It also ruled that the lower court applied an incorrect standard in denying OPCo any damages for TEM’s breach of this proceeding.the 20-year term of the PPA holding that OPCo is entitled to the benefit of its bargain and that the trial court must determine damages.  The Court of Appeals vacated approximately $117 million of the $123 million judgment for damages against TEM related to replacement products and remanded the issue for further proceedings to determine the correct amount of those damages.  One part of the judgment is final, that involves TEM’s liability for damages applicable to gas peaking and post-actual commercial operation date products.  OPCo expects TEM to pay the amount of those damages, approximately $8 million, including interest, in the fourth quarter of 2007.

Coal Transportation Dispute -– Affecting PSO TCC and TNC

PSO, TCC, TNC, the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsville, Texas, as joint owners of a generating station, disputed transportation costs for coal received between July 2000 and the present time.  The joint plant remitted less than the amount billed and the dispute is pending beforebilled.  In September 2007, the Surface Transportation Board.Board ruled that the disputed rates were not unreasonable under the standalone cost rate test.  The joint owners filed a Petition for Reconsideration.  Based upon a weighted average probability analysis of possible outcomes,this ruling, PSO, as operator of the plant, adjusted the provision recorded provisions for possible loss in 2004, 2005, 2006 andprior periods.  PSO deferred its immaterial share of the first quarter of 2007. The provision was deferred as a regulatory asset under PSO’sits fuel mechanism and immaterially affected income for TCC and TNC for their respective ownership shares. Management continues to work toward mitigating the disputed amounts to the extent possible.after mitigation by certain contractual rights.

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 work toward mitigating the disputed amounts to the extent possible.
Claims by the City of Brownsville, Texas Against TCC - Affecting TCC

On April 27, 2007, the City of Brownsville, Texas served its Fifth Amended Answer and Cross-Claims in litigation pending in the District Court of Dallas County, Texas. The cross-claims seek recovery against TCC based on allegations of breach of contract, breach of fiduciary duty, unjust enrichment, constructive trust, conversion, breach of the Texas theft liability act and fraud allegedly occurring in connection with a transaction in which Brownsville purchased TCC’s interest in the Oklaunion electric generating station. Management believes that the claims are without merit and intends to defend against them vigorously.

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. In December 2002, a FERC ALJ ruled in AEP’s favor and dismissed the complaint filed by the Nevada utilities. In 2001, the Nevada utilities filed complaints asserting that the prices for power supplied under those contracts should be lowered because the market for power was allegedly dysfunctional at the time such contracts were executed.  TheAn ALJ rejectedrecommended rejection of the complaint, heldholding that the markets for future delivery were not dysfunctional, and that the Nevada utilities failed to demonstrate that the public interest required that changes be made to the contracts.  In June 2003, the FERC issued an order affirming the ALJ’s decision.  In December 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.  On September 25, 2007, the U.S. Supreme Court decided to review the Ninth Circuit’s decision.  Management is unable to predict the outcome of these proceedings or their impact on future results of operations and cash flows.  We haveThe Registrant Subsidiaries asserted claims against certain companies that sold power to us,them, which wewas resold to the Nevada utilities, seeking to recover a portion of any amounts wethe Registrant Subsidiaries may owe to the Nevada utilities.

         5.ACQUISITIONS, DISPOSITIONS AND ASSETS HELD FOR SALE

ACQUISITIONS

2007
5.
ACQUISITION

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 approximately $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 - Affecting AEGCo
 6.
BENEFIT PLANS

In January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station (Lawrenceburg) from an affiliate of Public Service Enterprise Group (PSEG) for approximately $325 million and the assumption of liabilities of approximately $2 million. AEGCo will complete 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.

2006

None

DISPOSITIONS

2007

Texas Plants - Oklaunion Power Station - Affecting TCC

In February 2007, TCC sold its 7.81% share of Oklaunion Power Station to the Public Utilities Board of the City of Brownsville for $42.8 million plus adjustments. The sale did not have a significant effect on TCC’s results of operations. See "Claims by the City of Brownsville, Texas Against TCC" section of Note 4.
2006

None

ASSETS HELD FOR SALE

Texas Plants - Oklaunion Power Station - Affecting TCC

In February 2007, TCC sold its 7.81% share of Oklaunion Power Station to the Public Utilities Board of the City of Brownsville. The sale did not have a significant effect on TCC’s results of operations nor does TCC expect any remaining litigation to have a significant effect on its results of operations.

TCC’s assets related to the Oklaunion Power Station were classified in Assets Held for Sale - Texas Generation Plant on TCC’s Condensed Consolidated Balance Sheet at December 31, 2006. The plant does not meet the “component-of-an-entity” criteria because it does not have cash flows that can be clearly distinguished operationally. The plant also does not meet the “component-of-an-entity” criteria for financial reporting purposes because it does not operate individually, but rather as a part of the AEP System, which includes all of the generation facilities owned by the Registrant Subsidiaries except TNC.

The Assets Held for Sale were as follows:

  
March 31,
 
December 31,
 
  
2007
 
2006
 
Texas Plants (TCC)
 
(in millions)
 
Assets:
       
Other Current Assets $- $1 
Property, Plant and Equipment, Net  -  43 
Total Assets Held for Sale - Texas Generation Plant
 $- $44 

         6.BENEFIT PLANS

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC 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, KPCo, OPCo, PSO, SWEPCo, TCC and TNCthe Registrant Subsidiaries participate in other postretirement benefit plans sponsored by AEP to provide medical and death benefits for retired employees.

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNCThe Registrant Subsidiaries adopted SFAS 158 as of December 31, 2006.  TheyThe Registrant Subsidiaries recorded a SFAS 71 regulatory asset for their qualifying SFAS 158 costs of regulated operations that for ratemaking purposes will beare deferred for future recovery.

Components of Net Periodic Benefit Cost

The following table provides the components of AEP’s net periodic benefit cost for the plans for the three and nine months ended March 31,September 30, 2007 and 2006:
     
Other
 
     
Postretirement
 
  
Pension Plans
  
Benefit Plans
 
  
2007
  
2006
  
2007
  
2006
 
Three Months Ended September 30, 2007 and 2006
 
(in millions)
 
Service Cost $24  $23  $11  $10 
Interest Cost  59   57   26   26 
Expected Return on Plan Assets  (85)  (82)  (26)  (24)
Amortization of Transition Obligation  -   -   6   7 
Amortization of Net Actuarial Loss  15   20   3   5 
Net Periodic Benefit Cost
 $13  $18  $20  $24 
   
Other
     
Other
 
   
Postretirement
     
Postretirement
 
 
Pension Plans
 
Benefit Plans
  
Pension Plans
  
Benefit Plans
 
 
2007
 
2006
 
2007
 
2006
  
2007
  
2006
  
2007
  
2006
 
 
(in millions)
 
Nine Months Ended September 30, 2007 and 2006
 
(in millions)
 
Service Cost $24 $24 $10 $10  $72  $71  $32  $30 
Interest Cost  59  57  26  25   176   171   78   76 
Expected Return on Plan Assets  (85) (83) (26) (23)  (254)  (248)  (78)  (70)
Amortization of Transition Obligation  -  -  7  7   -   -   20   21 
Amortization of Net Actuarial Loss  15  20  3  5   44   59   9   15 
Net Periodic Benefit Cost
 $13 $18 $20 $24  $38  $53  $61  $72 

The following table provides the net periodic benefit cost (credit) for the plans by Registrant Subsidiary for the three and nine months ended March 31,September 30, 2007 and 2006:
 
Pension Plans
 
Other Postretirement
Benefit Plans
     
Other Postretirement
 
 
2007
 
2006
 
2007
 
2006
  
Pension Plans
  
Benefit Plans
 
Company
 
(in thousands)
 
 
2007
  
2006
  
2007
  
2006
 
Three Months Ended September 30, 2007 and 2006
 
(in thousands)
 
APCo $842 $1,468 $3,560 $4,489  $841  $1,469  $3,560  $4,487 
CSPCo  (257) 205  1,491  1,805   (258)  205   1,491   1,807 
I&M  1,900  2,331  2,530  2,953   1,900   2,331   2,530   2,949 
KPCo  255  358  426  513 
OPCo  245  826  2,802  3,396   362   823   2,802   3,395 
PSO  424  977  1,431  1,588   425   979   1,431   1,588 
SWEPCo ��746  1,225  1,419  1,578   747   1,222   1,420   1,578 
TCC  101  773  1,575  1,696 
TNC  70  325  631  715 

         7.
     
Other Postretirement
 
  
Pension Plans
  
Benefit Plans
 
  
2007
  
2006
  
2007
  
2006
 
Nine Months Ended September 30, 2007 and 2006
 
(in thousands)
 
APCo $2,525  $4,406  $10,680  $13,465 
CSPCo  (773)  615   4,473   5,417 
I&M  5,700   6,992   7,591   8,855 
OPCo  1,088   2,478   8,405   10,187 
PSO  1,273   2,935   4,292   4,764 
SWEPCo  2,240   3,672   4,258   4,734 

7.
BUSINESS SEGMENTS

All of AEP’s Registrant Subsidiaries have one reportable segment.  The one reportable segment is an integrated electricity generation, transmission and distribution business except AEGCo, which is an electricity generation business, and TCC and TNC, which are transmission and distribution businesses.business.  All of the Registrant Subsidiaries’ other activities are insignificant.  The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.

         8.
 8.
INCOME TAXES

WeThe Registrant Subsidiaries join in the filing of a consolidated federal income tax return with our subsidiariestheir affiliates in the American Electric Power (AEP)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 expense.  The tax benefit of the parentParent is allocated to ourits subsidiaries with taxable income.  With the exception of the loss of the parent company,Parent, the method of allocation approximates a separate return result for each company in the consolidated group.

Audit Status

AEP System companiesThe Registrant Subsidiaries also file income tax returns in various state local, and foreignlocal jurisdictions.  With few exceptions, wethe Registrant Subsidiaries are no longer subject to U.S. federal, state and local or non-U.S. income tax examinations by tax authorities for years before 2000.  The IRS and other taxing authorities routinely examine ourthe tax returns.  We believeManagement believes that wethe Registrant Subsidiaries have filed tax returns with positions that may be challenged by thesethe tax authorities.  WeThe Registrant Subsidiaries are currently under examexamination in several state and local jurisdictions.  However, management does not believe that the ultimate resolution of these audits will materially impact results of operations.

We haveThe AEP System settled with the IRS on all issues from the audits of our consolidated federal income tax returns for years prior to 1997.  We haveThe AEP System effectively settled all outstanding proposed IRS adjustments for years 1997 through 1999 and through June 2000 for the CSW pre-merger tax period and anticipateanticipates payment for the agreed adjustments to occur during 2007.  Returns for the years 2000 through 20032005 are presently being audited by the IRS and we anticipatemanagement anticipates that the audit of the 2000 through 2003 years will be completed by the end of 2007.

The IRS has proposed certain significant adjustments to AEP’s foreign tax credit and interest allocation positions. Management is currently evaluating those proposed adjustments to determine if it agrees, but if accepted, we do not anticipate the adjustments would result in a material change to our financial position.

FIN 48 Adoption

WeThe Registrant Subsidiaries adopted the provisions of FIN 48 on January 1, 2007.  As a result of the implementation of FIN 48, the approximate increase (decrease) 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 was recognized by each Registrant Subsidiary as follows:

Company
 
(in thousands)
  
(in thousands)
 
AEGCo $(27)
APCo  2,685  $2,685 
CSPCo  3,022   3,022 
I&M  (327)  (327)
KPCo  786 
OPCo  5,380   5,380 
PSO  386   386 
SWEPCo  1,642   1,642 
TCC  2,187 
TNC  557 

At January 1, 2007, the total amount of unrecognized tax benefits under FIN 48 for each Registrant Subsidiary was as follows:
 
Company
 
(in millions)
  
(in millions)
 
AEGCo $0.1 
APCo  21.7  $21.7 
CSPCo  25.0   25.0 
I&M  18.2   18.2 
KPCo  3.4 
OPCo  49.8   49.8 
PSO  8.9   8.9 
SWEPCo  7.1   7.1 
TCC  20.7 
TNC  6.9 

We believeManagement believes it is reasonably possible that there will be a net decrease in unrecognized tax benefits due to the settlement of audits and the expiration of statute of limitations within 12 months of the reporting date for each Registrant Subsidiary as follows:
 
Company
 
(in millions)
  
(in millions)
 
AEGCo $0.5 
APCo  5.5  $5.5 
CSPCo  9.3   9.3 
I&M  6.0   6.0 
KPCo  1.4 
OPCo  9.0   9.0 
PSO  4.4   4.4 
SWEPCo  2.8   2.8 
TCC  3.4 
TNC  1.6 

At January 1, 2007, the total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for each Registrant Subsidiary was as follows:

Company
 
(in millions)
  
(in millions)
 
APCo $5.4  $5.4 
CSPCo  13.8   13.8 
I&M  5.4   5.4 
KPCo  0.6 
OPCo  23.4   23.4 
PSO  1.2   1.2 
SWEPCo  1.2   1.2 
TCC  9.3 
TNC  2.6 

At January 1, 2007, tax positions for each Registrant Subsidiary, for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility is uncertain, was as follows:

Company
 
(in millions)
  
(in millions)
 
AEGCo $0.1 
APCo  13.7  $13.7 
CSPCo  3.9   3.9 
I&M  10.3   10.3 
KPCo  2.5 
OPCo  14.2   14.2 
PSO  7.1   7.1 
SWEPCo  5.1   5.1 
TCC  6.4 
TNC  2.9 

Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

Prior to the adoption of FIN 48, wethe Registrant Subsidiaries recorded interest and penalty accruals related to income tax positions in tax accrual accounts.  With the adoption of FIN 48, wethe Registrant Subsidiaries began recognizing interest accruals related to income tax positions in interest income or expense as applicable, and penalties in operating expenses.Other Operations.  As of January 1, 2007, each Registrant Subsidiary accrued for the payment of uncertain interest and penalties as follows:

Company
 
(in millions)
  
(in millions)
 
AEGCo $0.1 
APCo  4.6  $4.6 
CSPCo  1.7   1.7 
I&M  2.8   2.8 
KPCo  1.2 
OPCo  4.3   4.3 
PSO  2.7   2.7 
SWEPCo  2.0   2.0 
TCC  2.5 
TNC  1.0 
Michigan Tax Restructuring (Affecting I&M)

9.On July 12, 2007, the Governor of Michigan signed Michigan Senate Bill 0094 (MBT Act) and related companion bills into law providing a comprehensive restructuring of Michigan’s principal business tax.  The new law is effective January 1, 2008 and replaces the Michigan Single Business Tax that is scheduled to expire at the end of 2007.  The MBT Act is composed of a new tax which will be calculated based upon two components:  (a) a business income tax (BIT) imposed at a rate of 4.95% and (b) a modified gross receipts tax (GRT) imposed at a rate of 0.80%, which will collectively be referred to as the BIT/GRT tax calculation.  The new law also includes significant credits for engaging in Michigan-based activity.

On September 30, 2007, the Governor of Michigan signed House Bill 5198 which amends the MBT Act to provide for a new deduction on the BIT and GRT tax returns equal to the book-tax basis difference triggered as a result of the enactment of the MBT Act.  This new state-only temporary difference will be deducted over a 15 year period on the MBT Act tax returns starting in 2015.  The purpose of the new MBT Act state deduction was to provide companies relief from the recordation of the SFAS 109 Income Tax Liability.  The registrant subsidiaries have evaluated the impact of the MBT Act and the application of the MBT Act will not materially affect their results of operations, 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 threenine months of 2007 were:

Company
 
Type of Debt
 
Principal Amount
 
Interest Rate
 
Due Date
    
(in thousands)
 
(%)
  
Issuances:
         
SWEPCo Senior Unsecured Notes $250,000 5.55 2017


   
Principal
 
Interest
 
Due
Company
 
Type of Debt
 
Principal Amount
 
Interest Rate
 
Due Date
 
Type of Debt
 
Amount
 
Rate
 
Date
   
(in thousands)
 
(%)
     
(in thousands)
 
(%)
  
Retirements and
Principal Payments:
         
Issuances:
         
APCo Pollution Control Bonds $75,000 Variable 2037
APCo Senior Unsecured Notes  250,000 5.65 2012
APCo Senior Unsecured Notes  250,000 6.70 2037
CSPCo Pollution Control Bonds  44,500 Variable 2040
OPCo Notes Payable $1,463 6.81 2008 Pollution Control Bonds  65,000 4.90 2037
OPCo Notes Payable  6,000 6.27 2009 Senior Unsecured Notes  400,000 Variable 2010
PSO Pollution Control Bonds  12,660 4.45 2020
SWEPCo Notes Payable  1,645 4.47 2011 Senior Unsecured Notes  250,000 5.55 2017
SWEPCo Notes Payable  4,000 6.36 2007
SWEPCo Notes Payable  750 Variable 2008
TCC Securitization Bonds  32,125 5.01 2008

In AprilMay 2007, OPCo issued $400I&M remarketed its outstanding $50 million of three-year floating rate notes at an initialPollution Control Bonds, resulting in a new interest rate of 5.53% due4.625%.  No proceeds were received related to this remarketing.  The principal amount of the Pollution Control Bonds is reflected in 2010. The proceeds from this issuance will contribute to our investment in environmental equipment.Long-term Debt on I&M’s Condensed Consolidated Balance Sheet as of September 30, 2007.

    
Principal
 
Interest
 
Due
Company
 
Type of Debt
 
Amount
 
Rate
 
Date
    
(in thousands)
 
(%)
  
Retirements and Principal Payments:
       
APCo Senior Unsecured Notes $125,000 Variable 2007
APCo Other  9 13.718 2026
OPCo Notes Payable – Nonaffiliated  2,927 6.81 2008
OPCo Notes Payable – Nonaffiliated  6,000 6.27 2009
PSO Pollution Control Bonds  12,660 6.00 2020
SWEPCo First Mortgage Bonds  90,000 7.00 2007
SWEPCo Notes Payable – Nonaffiliated  4,210 4.47 2011
SWEPCo Notes Payable – Nonaffiliated  4,000 6.36 2007
SWEPCo Notes Payable – Nonaffiliated  2,250 Variable 2008
Lines of Credit and Short-term Debt -– AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of its subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility 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 March 31,September 30, 2007 and December 31, 2006 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 threenine months ended March 31,September 30, 2007 are described in the following table:

  
Maximum Borrowings
from Utility
Money Pool
 
Maximum
Loans to Utility Money Pool
 
Average
Borrowings from Utility Money Pool
 
Average Loans to Utility Money Pool
 
Loans (Borrowings) to/from Utility Money Pool as of March 31, 2007
 
Authorized
Short-Term Borrowing Limit
 
Company
 
(in thousands)
 
AEGCo $75,425 $- $44,340 $- $(29,997)$125,000(a)
APCo  109,259  -  71,378  -  (82,860) 600,000 
CSPCo  15,693  35,270  6,204  14,543  922  350,000 
I&M  100,374  -  66,570  -  (45,759) 500,000 
KPCo  46,317  -  30,845  -  (20,769) 200,000 
OPCo  444,153  -  333,467  -  (397,127) 600,000 
PSO  135,694  -  76,776  -  (135,694) 300,000 
SWEPCo  240,786  48,979  215,207  30,267  8,959  350,000 
TCC  -  394,180  -  295,542  216,953  600,000 
TNC (b)  35,191  3,200  22,179  2,365  (24,487) 250,000 

(a)In April 2007, limit increased by $285 million under regulatory orders.
(b)Does not include short-term lending activity of TNC’s wholly-owned subsidiary, AEP Texas North Generation Company LLC (TNGC), who is a participant in the Nonutility Money Pool. As of March 31, 2007, TNGC had $13.3 million in outstanding loans to the Nonutility Money Pool.
              
Loans/
    
  
Maximum
  
Maximum
  
Average
  
Average
  
(Borrowings)
  
Authorized
 
  
Borrowings
  
Loans to
  
Borrowings
  
Loans to
  
to/from Utility
  
Short-Term
 
  
from Utility
  
Utility
  
from Utility
  
Utility Money
  
Money Pool as of
  
Borrowing
 
  
Money Pool
  
Money Pool
  
Money Pool
  
Pool
  
September 30, 2007
  
Limit
 
Company
 
(in thousands)
 
APCo $406,262  $96,543  $147,582  $48,303  $38,573  $600,000 
CSPCo  137,696   35,270   51,927   13,551   (123,043)  350,000 
I&M  100,374   52,748   50,998   34,749   (24,234)  500,000 
OPCo  447,335   1,564   161,746   1,564   (85,341)  600,000 
PSO  242,097   -   133,404   -   (187,492)  300,000 
SWEPCo  240,786   48,979   79,890   29,653   (155,869)  350,000 

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:
 
 
Three Months Ended March 31,
  
Nine Months Ended September 30,
 
2007
 
2006
  
2007
 
2006
Maximum Interest Rate  5.43% 4.85% 5.94% 5.41%
Minimum Interest Rate  5.30% 4.37% 5.30% 3.63%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the threenine months ended March 31,September 30, 2007 and 2006 are summarized for all Registrant Subsidiaries in the following table:

 
Average Interest Rate for Funds
  
Average Interest Rate for Funds
 
Borrowed from the Utility Money
  
Loaned to the Utility Money
 
Pool for
  
Pool for
 
Average Interest Rate for Funds
Borrowed from the Utility Money
Pool for
Three Months Ended March 31,
 
 Average Interest Rate for Funds
Loaned to the Utility Money
Pool for
Three Months Ended March 31,
  
Nine Months Ended September 30,
  
Nine Months Ended September 30,
 
2007
 
2006
 
 2007
 
2006
  
2007
 
2006
  
2007
 
2006
Company
 
(in percentage)
  
(in percentage)
AEGCo  5.34  4.57  -  - 
APCo  5.34  4.60  -  -  5.41 4.62  5.84 4.98
CSPCo  5.35  4.58  5.33  4.66  5.48 4.73  5.39 4.63
I&M  5.34  4.59  -  -  5.38 4.81  5.84 -
KPCo  5.34  4.54  -  4.75 
OPCo  5.34  4.60  -  -  5.39 4.83  5.43 5.12
PSO  5.34  4.63  -  -  5.47 5.02  - 4.36
SWEPCo  5.35  4.60  5.34  -  5.54 5.01  5.34 4.36
TCC  -  4.47  5.34  4.68 
TNC (a)  5.34  4.57  5.34  4.54 

(a)Does not include short-term lending activity for TNGC, who is a participant in the Nonutility Money Pool. For the three months ended March 31, 2007, the average interest rate for funds loaned to the Nonutility Money Pool by TNGC was 5.31%.

Short-term Debt

The Registrant Subsidiaries’ outstanding short-term debt was as follows:

   
September 30, 2007
 
December 31, 2006
 
   
March 31, 2007
 
December 31, 2006
    
Outstanding
 
Interest
 
Outstanding
 
Interest
 
 
Type of Debt
 
Outstanding
Amount
 
Interest
Rate
 
Outstanding
Amount
 
Interest
Rate
  
Type of Debt
 
Amount
 
Rate
 
Amount
 
Rate
 
Company
   
(in millions)
   
(in millions)
      
(in millions)
   
(in millions)
    
OPCo Commercial Paper - JMG $5 5.56% $1 5.56% Commercial Paper – JMG $2 5.3588% $1  5.56%
SWEPCo Line of Credit - Sabine 20 6.52% 17 6.38% Line of Credit – Sabine  26 6.07%  17  6.38%


Dividend Restrictions


Under the Federal Power Act, the Registrant Subsidiaries are restricted from paying dividends out of stated capital.

Sale of Receivables – AEP Credit

In October 2007, AEP renewed AEP Credit’s sale of receivables agreement.  The sale of receivables agreement provides a commitment of $650 million from a bank conduit to purchase receivables from AEP Credit.  Under the agreement, the commitment will increase to $700 million in August and September to accommodate seasonal demand.  This agreement will expire in October 2008.  AEP Credit purchases accounts receivable through purchase agreements with CSPCo, I&M, OPCo, PSO, SWEPCo and a portion of APCo.  Since APCo does not have regulatory authority to sell accounts receivable in all of its regulatory jurisdictions, only a portion of APCo’s accounts receivable are sold to AEP Credit.


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 operations 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 2006 Annual Report should also be read in conjunction with this report.

Significant Factors

Ohio Restructuring

As permitted by the current Ohio restructuring legislation, CSPCo and OPCo can implement market-based rates effective January 2009, following the expiration of its RSPs on December 31, 2008.  In August 2007, legislation was introduced that would significantly reduce the likelihood of CSPCo’s and OPCo’s ability to charge market-based rates for generation at the expiration of their RSPs.  In place of market-based rates, it is more likely that some form of cost-based rates or hybrid-based rates would be required.  The legislation passed through the Ohio Senate and still must be considered by the Ohio House of Representatives.  Management continues to analyze the proposed legislation and is working with various stakeholders to achieve a principled, fair and well-considered approach to electric supply pricing.  At this time, management is unable to predict whether CSPCo and OPCo will transition to market pricing, extend their RSP rates, with or without modification, or become subject to a legislative reinstatement of some form of cost-based regulation for their generation supply business on January 1, 2009.

SECA Revenue Subject to Refund

Effective December 1, 2004, AEP and other transmission owners in the region covered by PJM and MISO eliminated transaction-based through-and-out transmission service (T&O) charges in accordance with FERC orders and collected load-based charges, referred to as RTO SECA, to mitigate the loss of T&O revenues on a temporary basis through March 31, 2006.  Intervenors objected to the 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 or surcharge.  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.  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 

Approximately $10 million of these recorded SECA revenues billed by PJM were not collected.  The AEP East companies filed a motion with the FERC to force payment of these uncollected SECA billings.

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 was not 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 2006, the AEP East companies provided reserves of $37 million in net refunds for current and future SECA settlements with all of the AEP East companies’ SECA customers.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the reserve are as follows:

Company
 
(in millions)
 
APCo $12.0 
CSPCo  6.7 
I&M  7.0 
OPCo  9.1 

The AEP East companies reached settlements with certain SECA customers related to approximately $69 million of such revenues for a net refund of $3 million.  The AEP East companies are in the process of completing two settlements-in-principle on an additional $36 million of SECA revenues and expect to make net refunds of $4 million when those settlements are approved.  Thus, completed and in-process settlements cover $105 million of SECA revenues and will consume about $7 million of the reserves for refunds, leaving approximately $115 million of contested SECA revenues and $30 million of refund reserves.  If the ALJ’s initial decision were upheld in its entirety, it would disallow approximately $90 million of the AEP East companies’ remaining $115 million of unsettled gross SECA revenues.  Based on recent settlement experience and the expectation that most of the $115 million of unsettled SECA revenues will be settled, management believes that the remaining reserve of $30 million will be adequate to cover all remaining settlements.

In September 2006, AEP, together with Exelon Corporation and The Dayton Power and Light Company, filed an extensive post-hearing brief and reply brief noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part.  Management believes that the FERC should reject the 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 directed by the FERC, management is working to settle the remaining $115 million of unsettled revenues within the remaining reserve balance.  Although management believes it has meritorious arguments and can settle with the remaining customers within the amount provided, management cannot predict the ultimate outcome of ongoing settlement talks and, if necessary, any future FERC proceedings or court appeals.  If the FERC adopts the ALJ’s decision and/or AEP cannot settle a significant portion of the remaining unsettled claims within the amount provided, it will have an adverse effect on future results of operations, cash flows and financial condition.

PJM Marginal-Loss Pricing

On June 1, 2007, in response to a 2006 FERC order, PJM revised its methodology for considering transmission line losses in generation dispatch and the calculation of locational marginal prices.   Marginal-loss dispatch recognizes the varying delivery costs of transmitting electricity from individual generator locations to the places where customers consume the energy.  Prior to the implementation of marginal-loss dispatch, PJM used average losses in dispatch and in the calculation of locational marginal prices.  Locational marginal prices in PJM now include the real-time impact of transmission losses from individual sources to loads.  Due to the implementation of marginal-loss pricing, for the period June 1, 2007 through September 30, 2007, AEP experienced an increase in the cost of delivering energy from the generating plant locations to customer load zones partially offset by cost recoveries and increased off-system sales resulting in a net loss of approximately $25 million.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the loss are as follows:

Company
 
(in millions)
 
APCo $6 
CSPCo  5 
I&M  5 
OPCo  5 

AEP has initiated discussions with PJM regarding the impact it is experiencing from the change in methodology and will pursue through the appropriate stakeholder processes a modification of such methodology.  Management believes these additional costs should be recoverable through retail and/or cost-based wholesale rates and is seeking recovery in current and future fuel or base rate filings as appropriate in each of its eastern zone states.  In the interim, these costs will have an adverse effect on future results of operations and cash flows.  Management is unable to predict whether full recovery will ultimately be approved.

New Generation

AEP is in various stages of construction of the following generation facilities.  Certain plants are pending regulatory approval:

                 
Commercial
      
Total
          
Operation
Operating
 
Project
   
Projected
        
MW
 
Date
Company
 
Name
 
Location
 
Cost (a)
 
CWIP
 
Fuel Type
 
Plant Type
 
Capacity
 
(Projected)
      
(in millions)
 
(in millions)
        
SWEPCo Mattison Arkansas $122(b)$52 Gas Simple-cycle 340(b)2007
PSO Southwestern Oklahoma  59(c) 45 Gas Simple-cycle 170 2008
PSO Riverside Oklahoma  58(c) 45 Gas Simple-cycle 170 2008
AEGCo Dresden(d)Ohio  265(d) 88 Gas Combined-cycle 580 2009
SWEPCo Stall Louisiana  375  15 Gas Combined-cycle 480 2010
SWEPCo Turk(e)Arkansas  1,300(e) 206 Coal Ultra-supercritical 600(e)2011
APCo Mountaineer West Virginia  2,230  - Coal IGCC 629 2012
CSPCo/OPCo Great Bend Ohio  2,230(f) - Coal IGCC 629 2017

(a)Amount excludes AFUDC.
(b)Includes Unites 3 and 4, 150 MW, declared in commercial operation on July 12, 2007 with construction costs totaling $55 million.
(c)In April 2007, the OCC approved that PSO will recover through a rider, subject to a $135 million cost cap, all of the traditional costs associated with plant in service at the time these units are placed in service.
(d)In September 2007, AEGCo purchased the under-construction 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.
(e)SWEPCo plans to own approximately 73%, or 438 MW, totaling about $950 million in capital investment.  See “Turk Plant” section below.
(f)Front-end engineering and design study is complete.  Cost estimates are not yet filed with the PUCO due to the pending appeals to the Supreme Court of Ohio resulting from the PUCO’s April 2006 opinion and order.  See “Ohio IGCC Plant” section below.

AEP acquired the following generation facilities:

               
Operating
           
MW
 
Purchase
Company
 
Plant Name
 
Location
 
Cost
 
Fuel Type
 
Plant Type
 
Capacity
 
Date
      
(in millions)
        
CSPCo Darby(a)Ohio $102 Gas Simple-cycle 480 April 2007
AEGCo Lawrenceburg(b)Indiana  325 Gas Combined-cycle 1,096 May 2007

(a)CSPCo purchased Darby Electric Generating Station (Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light Company.
(b)AEGCo purchased Lawrenceburg Generating Station (Lawrenceburg), adjacent to I&M’s Tanners Creek Plant, from an affiliate of Public Service Enterprise Group (PSEG).  AEGCo sells the power to CSPCo under a FERC-approved unit power agreement.

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 during 2006; Phase 2, concurrent recovery of construction-financing costs; and Phase 3, recovery or refund in distribution rates of any difference between the market-based standard service offer price for generation and the cost of operating and maintaining the plant, including a return on and return of the ultimate cost to construct the plant, originally projected to be $1.2 billion, along with fuel, consumables and replacement power costs.  The proposed recoveries in Phases 1 and 2 would be applied against the average 4% limit on additional generation rate increases CSPCo and OPCo could request under their RSPs.

In April 2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase 1 of the cost recovery proposal.  In June 2006, the PUCO issued another order approving a tariff to recover Phase 1 pre-construction costs over a period of no more than a twelve-month periodtwelve months effective July 1, 2006.  Through March 31,September 30, 2007, CSPCo and OPCo each recorded pre-construction IGCC regulatory assets of $10 million and each recovered $9collected the entire $12 million approved by the PUCO.  As of those costs.September 30, 2007, CSPCo and OPCo will recoverhave recorded a liability of $2 million each for the remaining amounts through June 30, 2007. over-recovered portion.  CSPCo and OPCo expect to incur additional pre-construction costs equal to or greater than the $12 million each recovered.  
The PUCO indicated 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 chargesPhase 1 costs collected for pre-construction costs, associated with items that may be utilized in IGCC projects at other sites, must be refunded to Ohio ratepayers with interest.  The PUCO deferred ruling on cost recovery for Phases 2 and 3 cost recovery until further hearings are held.  A date for further rehearings has not been set.

In August 2006, the Ohio Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order in the IGCC proceeding.  CSPCo and OPCo believeThe Ohio Supreme Court heard oral arguments for these appeals in October 2007.  Management believes that the PUCO’s authorization to begin collection of Phase 1 ratespre-construction costs is lawful.  Management, however, cannot predict the outcome of these appeals.  If the PUCO’s order is found to be unlawful, CSPCo and OPCo could be required to refund Phase I1 cost-related recoveries.

Pending the outcome of the Supreme Court litigation, CSPCo and OPCo announced they may delay the start of construction of the IGCC plant. Recent estimates of the cost to build an IGCC plant have escalated to $2.2 billion.  CSPCo and OPCo may need to request an extension to the 5-year start of construction requirement if the commencement of construction is delayed beyond 2011.

SECA Revenue Subject to RefundRed Rock Generating Facility

In July 2006, PSO announced plans to enter into an agreement with Oklahoma Gas and Electric (OG&E) to build a 950 MW pulverized coal ultra-supercritical generating unit at the site of OG&E’s existing Sooner Plant near Red Rock, in north central Oklahoma.  PSO would own 50% of the new unit, OG&E would own approximately 42% and the Oklahoma Municipal Power Authority (OMPA) would own approximately 8%.  OG&E would manage construction of the plant.  OG&E and PSO requested pre-approval to construct the Red Rock Generating Facility and implement a recovery rider.  In March 2007, the OCC consolidated PSO’s pre-approval application with OG&E’s request.  The AEP East Companies ceased collecting through-and-out transmissionRed Rock Generating Facility was estimated to cost $1.8 billion and was expected to be in service (T&O) revenues in accordance with FERC orders2012.  The OCC staff and implemented SECA rates to mitigate the loss of T&O revenues from December 1, 2004 through March 31, 2006, when SECA rates expired. Intervenors objected to the SECA rates, raising various issues. In August 2006, the ALJ issued an initial decision, finding thatrecommended the rate design for the recoveryOCC approve PSO’s and OG&E’s filing.  As of SECA charges was flawed and that a large portion of the “lost revenues” reflected in the SECA rates was not recoverable. The ALJ found that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made.

Since the implementation of SECA rates in December 2004, the AEP East companies recordedSeptember 2007, PSO incurred approximately $220$20 million of gross SECA revenues, subject to refund. The AEP East companies have reached settlements with certain customers related to approximately $70 million of such revenues. The unsettled gross SECA revenues total approximately $150 million. If the ALJ’s initial decision is upheld in its entirety, it would disallow $126 million of the AEP East companies’ unsettled gross SECA revenues. In the second half of 2006, the AEP East companies provided a reserve of $37 million in net refunds.pre-construction costs and contract cancellation fees.

In September 2006, AEP, together with ExelonOctober 2007, the OCC issued a final order approving PSO’s need for 450 MWs of additional capacity by the year 2012, but denied PSO’s and OG&E’s application for construction pre-approval stating PSO and OG&E failed to fully study other alternatives.  Since PSO and OG&E could not obtain pre-approval to build the Red Rock Generating Facility, PSO and OG&E cancelled the third party construction contract and their joint venture development contract.  Management believes the pre-construction costs capitalized, including any cancellation fees, were prudently incurred, as evidenced by the OCC staff and the Dayton PowerALJ’s recommendations that the OCC approve PSO’s filing, and Light Company, filed an extensive post hearing brief and reply brief noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part.established a regulatory asset for future recovery.  Management believes thatsuch pre-construction costs are probable of recovery and intends to seek full recovery of such costs in the FERC should reject the initial decision because itnear future.  If recovery is contrary to prior related FERC decisions, which are presently subject to rehearing. Furthermore, management believes the ALJ’s findings on key issues are largely without merit. Although management believes they have meritorious arguments, management cannot predict the ultimate outcome of any future FERC proceedings or court appeals. If the FERC adopts the ALJ’s decision, it will have an adverse effect ondenied, future results of operations and cash flows.flows would be adversely affected.  As a result of the OCC’s decision, PSO will be re-considering various alternative options to meet its capacity needs in the future.

Turk Plant

In August 2006, SWEPCo announced plans to build a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas named Turk Plant.  SWEPCo submitted filings with the Arkansas Public Service Commission (APSC) in December 2006 and the PUCT and LPSC in February 2007 to seek approvals to proceed with the plant.  In September 2007, OMPA signed a joint ownership agreement and agreed to own approximately 7% of the Turk Plant.  SWEPCo continues discussions with Arkansas Electric Cooperative Corporation and North Texas Electric Cooperative to become potential partners in the Turk Plant.  SWEPCo anticipates owning approximately 73% of the Turk Plant and will operate the facility.  The Turk Plant is estimated to cost $1.3 billion in total with SWEPCo’s portion estimated to cost $950 million, excluding AFUDC.  If approved on a timely basis, the plant is expected to be in-service in mid-2011.  As of September 2007, SWEPCo incurred and capitalized approximately $206 million and has contractual commitments for an additional $875 million.  If the Turk Plant is not approved, cancellation fees may be required to terminate SWEPCo’s commitment.

In August 2007, hearings began before the APSC seeking pre-approval of the plant. The APSC staff recommended the application be approved and intervenors requested the motion be denied.  In October 2007, final briefs and closing arguments were completed by all parties during which the APSC staff and Attorney General supported the plant.  A decision by the APSC will occur within 60 days from October 22, 2007.  In September 2007, the PUCT staff recommended that SWEPCo’s application be denied suggesting the construction of the Turk Plant would adversely impact the development of competition in the SPP zone.  The PUCT hearings were held in October 2007.  The LPSC held hearings in September 2007 and during this proceeding, the LPSC staff expressed support for the project.   If SWEPCo is not authorized to build the Turk plant, SWEPCo would seek recovery of incurred costs including any cancellation fees.  If SWEPCo cannot recover incurred costs, including any cancellation fees, it could adversely affect future results of operations, cash flows and possibly financial condition.

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 Clean Air Act (CAA) to reduce emissions of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter (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 also monitors possible future requirements to reduce carbon dioxide (CO2) 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 2006 Annual Report.

Environmental Litigation

New Source Review (NSR) Litigation:  In 1999, the Federal EPA, and a number of states and certain special interest groups filed complaints alleging that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities including the Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric Company, Ohio Edison Company, Southern Indiana Gas & Electric Company, Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company and Duke Energy,  modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA.  A separate lawsuit, initiated by certain special interest groups, has been consolidated with the Federal EPA case. Several similar complaints were filed in 1999 and thereafter against nonaffiliated utilities including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these cases were resolved through consent decrees. The alleged modifications at the Registrant Subsidiaries’ power plants occurred over a twenty-year period. A bench trial on the liability issues was held during 2005. Briefing has concluded. In June 2006, the judge stayed the liability decision pending the issuance of a decision by the U.S. Supreme Court in the Duke Energy case.

Under the CAA, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components, or other repairs needed for the reliable, safe and efficient operation of the plant.

Courts that considered whether the activities at issue in these cases are routine maintenance, repair, or replacement, and therefore are excluded from NSR, reached different conclusions. Similarly, courts that considered whether the activities at issue increased emissions from the power plants have reached different results. Appeals on these and other issues were filed in certain appellate courts, including a petition to appeal to the U.S. Supreme Court that was granted in the Duke Energy case. The Federal EPA issued a final rule that would exclude activities similar to those challenged in these cases from NSR as “routine replacements.” In March 2006, the Court of Appeals for the District of Columbia Circuit issued a decision vacating the rule. The Court denied the Federal EPA’s request for rehearing, and the Federal EPA and other parties filed a petition for review by the U.S. Supreme Court. In April 2007, the Supreme Court denied the petition for review. The Federal EPA also proposed a rule that would define “emissions increases” in a way that would exclude most of the challenged activities from NSR.

On April 2, 2007, the U.S. Supreme Court reversed the Fourth Circuit Court of Appeals’ decision that had supported the statutory construction argument of Duke Energy in its NSR proceeding.

In October 2007, management announced that the AEP System had entered into a unanimous decision, the Court ruled thatconsent decree with the Federal EPA, was not obligated to define “major modification” in two different CAA provisions in the same way. The Court also found thatDOJ, the Fourth Circuit’s interpretation of “major modification” as applying only to projects that increased hourly emission rates amounted to an invalidation of the relevant Federal EPA regulations, which under the CAA can only be challenged in the Court of Appeals within 60 days of the Federal EPA rulemaking. The U.S. Supreme Court did acknowledge, however, that Duke Energy may argue on remand that the Federal EPA has been inconsistent in its interpretations of the CAAstates and the regulationsspecial interest groups. Under the consent decree, the AEP System agreed to annual SO2 and may not retroactively change 20 years of accepted practice.

NOx emission caps for sixteen coal-fired power plants located in Indiana, Kentucky, Ohio, Virginia and West Virginia. In addition to providing guidance on certaincompleting the installation of previously announced environmental retrofit projects at many of the meritsplants, I&M agreed to install selective catalytic reduction (SCR) and flue gas desulfurization (FGD or scrubbers) emissions control equipment on the Rockport Plant units.
Since 2004, the AEP System spent nearly $2.6 billion on installation of emissions control equipment on its coal-fueled plants in Kentucky, Ohio, Virginia and West Virginia as part of a larger plan to invest more than $5.1 billion by 2010 to reduce the emissions of the NSR proceedings broughtgenerating fleet.  Capital amounts by Registrant Subsidiary are as follows:

  
Incurred Capital
   
  
Amount Through
  
Budgeted Capital
  
December 31,  2006
  
2007 - 2010
  
(in millions)
APCo $923  $944
CSPCo  194   374
I&M  98   77
OPCo  1,253   891

Under the consent decree, the AEP System will pay a $15 million civil penalty and provide $36 million for environmental projects coordinated with the federal government and $24 million to the states for environmental mitigation.  The Registrant Subsidiaries expensed their share of these amounts in September 2007 as follows:

     
Environmental
 
Total Expensed in
  
Penalty
  
Mitigation Costs
 
September 2007
  
(in thousands)
APCo $4,974  $20,659 $25,633
CSPCo  2,883   11,973  14,856
I&M  2,770   11,503  14,273
OPCo  3,355   13,935  17,290

See “Federal EPA Complaint and Notice of Violation” section of Note 4.

Litigation against APCo, CSPCo, I&M and OPCo in U.S. District Court for the Southern District of Ohio, the U.S. Supreme Court’s issuance of a ruling in theCSPCo’s three jointly-owned plants, operated by Duke Energy cases has an impact on the timing of our NSR proceedings. First, the court in the case for which a trial on liability issues has been conducted has indicated an intent to issue a decision on liability. Second, the bench trial on remedy issues, if necessary, is likely to be scheduled to begin in the third quarter of 2007.

Ohio, Inc. and Dayton Power and Light Company, continues.  Management is unable to estimate the loss or range of loss related to any contingent liability, if any, the Registrant Subsidiaries might have for civil penalties under the CAA proceedings. Management is also unable to predict the timing of resolutionoutcome of these matters due to the number of alleged violations and the significant number of issues to be determined by the court. If the Registrant Subsidiaries do not prevail, managementcases.   Management believes the Registrant Subsidiaries can recover any capital and operating costs of additional pollution control equipment that may be required through regulated rates andor market prices for electricity.  If the Registrant Subsidiaries are unable to recover such costs or if material penalties are imposed, it would adversely affect future results of operations and cash flows and possibly financial condition.flows.
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.  Management expected additional capital and operating expenses, which the Federal EPA estimated could be $193 million for AEP System 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

The rule was challenged in the courts by states, advocacy organizations and industry.  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.  Management may seek further review or relief from the schedules included in the permits.
Adoption of New Accounting Pronouncements

FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements by prescribing a recognition threshold (whether a tax position is more likely than not to be sustained) without which, the benefit of that position is not recognized in the financial statements.  It requires a measurement determination for recognized tax positions based on the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement.  FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.  FIN 48 requires that the cumulative effect of applying this interpretation be reported and disclosed as an adjustment to the opening balance of retained earnings for that fiscal year and presented separately.  The Registrant Subsidiaries adopted FIN 48 effective January 1, 2007.  See “FIN 48 “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1 “Definition of Settlement in FASB Interpretation No. 48”” section of Note 2 and see Note 8 -– Income Taxes.  The impact of this interpretation was an unfavorable (favorable) adjustment to retained earnings as follows:

Company
 
(in thousands)
  
(in thousands)
 
AEGCo $(27)
APCo  2,685  $2,685 
CSPCo  3,022   3,022 
I&M  (327)  (327)
KPCo  786 
OPCo  5,380   5,380 
PSO  386   386 
SWEPCo  1,642   1,642 
TCC  2,187 
TNC  557 








CONTROLS AND PROCEDURES

During the firstthird quarter of 2007, management, including the principal executive officer and principal financial officer of each of AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO SWEPCo, TCC and TNCSWEPCo (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 March 31,September 30, 2007 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.

The onlyThere 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 firstthird quarter of 2007 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal controlscontrol over financial reporting, relates to the Southwest Power Pool’s (SPP) implementation of an Energy Imbalance Service Market. In connection with this market implementation, two of AEP’s subsidiaries (Public Service Company of Oklahoma and Southwestern Electric Power Company) implemented or modified a number of business processes and controls to facilitate participation in, and resultant settlement within, the SPP Energy Imbalance Service Market.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, 2006 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 2006 Annual Report on Form 10-K.

General Risks of Our Regulated Operations

Our request for rate recovery of additionalplant construction costs may not be approved in Virginia.for SWEPCo. (Applies to AEP and APCo.SWEPCo.)

APCo filedIn August 2006, SWEPCo announced plans to build a requestnew base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas named Turk Plant.  SWEPCo submitted filings with the Virginia SCCAPSC in MayDecember 2006 seekingand the PUCT and LPSC in February 2007 to seek approvals to proceed with the plant.  In September 2007, OMPA signed a net increase in base rates of $198 millionjoint ownership agreement and agreed to recover increasing costs, including a return on equity of 11.5%. APCo also requested to apply its off-system sales margins (currently credited to customers through base rates) to the fuel factor where they can be adjusted annually. APCo also requested to retain a portionown approximately 7% of the off-system sales margins. Turk Plant.  SWEPCo continues discussions with Arkansas Electric Cooperative Corporation and North Texas Electric Cooperative to become potential partners in the Turk Plant.  SWEPCo anticipates owning approximately 73% of the Turk Plant and will operate the facility.  The Turk Plant is estimated to cost $1.3 billion in total with SWEPCo’s portion estimated to cost $950 million, excluding AFUDC.  If approved on a timely basis, the plant is expected to be in-service in mid-2011.  As of September 2007, SWEPCo incurred and capitalized approximately $206 million and has contractual commitments for an additional $875 million.  If the Turk Plant is not approved, cancellation fees may be required to terminate SWEPCo’s commitment.

In May 2006,August 2007, hearings began before the Virginia SCC issued an order placingAPSC seeking pre-approval of the netplant. The APSC staff recommended the application be approved and intervenors requested base rate increase into effect as of October 2, 2006, subject to refund.the motion be denied.  In October 2006,2007, final briefs and closing arguments were completed by all parties during which the Virginia SCCAPSC staff filed direct testimony recommending a base rate increaseand Attorney General supported the plant.  A decision by the APSC will occur within 60 days from October 22, 2007.  In September 2007, the PUCT staff recommended that SWEPCo’s application be denied suggesting the construction of $13 million with a return on equitythe Turk Plant would adversely impact the development of 9.9% and no off-system sales margin sharing. Other intervenors have recommended base rate increases ranging from $42 million to $112 million. APCo has filed rebuttal testimony andcompetition in the SPP zone.  The PUCT hearings were held in December 2006. In MarchOctober 2007.  The LPSC held hearings in September 2007 and during this proceeding, the Hearing Examiner released a report recommending a base rate increaseLPSC staff expressed support for the project.   If SWEPCo is not authorized to build the Turk plant, SWEPCo would seek recovery of $31 million with a return on equity of 10.1% and a 5% retention of off-system sales margin sharing.incurred costs including any cancellation fees.  If the Virginia SCC denies the requested rate recovery,SWEPCo cannot recover incurred costs, including any cancellation fees, it could adversely impactaffect future results of operations, cash flows and possibly financial condition.

Our request for rate recovery of additionalPlant pre-construction costs may not be approved in Texas.(Applies to AEP, TCC and TNC.)

TCC and TNC have filed requests with the PUCT to increase their transmission and distribution rates. The rate requests include the amounts chargedrecovered for the delivery of electricity over TCC´s and TNC´s transmission and distribution lines. TCC is seeking approval of an $81 million increase, which includes the expiration of $20 million in billing credits that the PUCT required in approving the merger of CSW into AEP. The credits have been in place since 2000. TNC is seeking approval of a $25 million increase, which includes the expiration of $6 million in billing credits. TCC and TNC are requesting a return on equity of 11.25% with a capital structure of approximately 60% debt/40% equity. As part of rebuttal testimony filed in April 2007, TCC and TNC reduced their base rate request by $11 million and $3 million, respectively, and reduced their return on equity by 0.5%. If the PUCT denies the requested rate recovery, it could adversely impact future results of operations, cash flows and financial condition.

Our request for rate recovery of additional costs may not be approved in Oklahoma.PSO. (Applies to AEP and PSO.)

In July 2006, PSO filedannounced plans to enter into an agreement with Oklahoma Gas and Electric (OG&E) to build a request with950 MW pulverized coal ultra-supercritical generating unit at the site of OG&E’s existing Sooner Plant near Red Rock, in north central Oklahoma.  In October 2007, the OCC in November 2006 seeking approvalissued a final order denying PSO’s application for construction pre-approval stating PSO failed to fully study other alternatives.  As of a $50 million overall increase in base rates, an annually adjusted rate mechanism to recover the expected significant investment PSO will be making in new facilities, several new and restructured tariffs to allow PSO to begin to reduce the relationship between its revenues and its sales volumes, and to implement some demand side management tariffs. PSO´s planned investments over the next five years include new generation facilities ($1.12 billion), new and refurbished transmission substations and lines ($302 million) and new distribution lines and equipment ($582 million). In AprilSeptember 2007, PSO filed rebuttal testimony regarding various issues raised by the OCC Staff and the intervenors. As partdeferred approximately $20 million of rebuttal testimony, PSO reduced its base rate request by $2 million.pre-construction costs.  If the OCC denies the requested rate recovery it could adversely impactof pre-construction costs is denied, future results of operations and cash flows and financial condition.would be adversely affected.

The amount we charged third parties for using our transmission facilities has been reduced, is subject to refund and may not be completely restored in the future. (Applies to AEP, APCo, CSPCo, I&M and the AEP East companies.OPCo.)

In July 2003, the FERC issued an order directing PJM and MISO to make compliance filings for their respective tariffs to eliminate the transaction-based charges for through and out (T&O) transmission service on transactions where the energy is delivered within those RTOs.  The elimination of the T&O rates reduces the transmission service revenues collected by the RTOs and thereby reduces the revenues received by transmission owners under the RTOs’ revenue distribution protocols. To mitigate the impact of lost T&O revenues, the FERC approved temporary replacement seams elimination cost allocation (SECA) transition rates beginning in December 2004 and extending through March 2006.  Intervenors objected to this decision; therefore the SECA fees we collected ($220 million) are subject to refund.  Approximately $19$10 million of the SECA revenues that we billed were never collected.  AEP filed a motion with the FERC to force payment of these SECA billings.

A hearing was held in May 2006 to determine whether any of the SECA revenues should be refunded. In August 2006, the 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 was not 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 unpaid SECA rates must be paid in the recommended reduced amount.  The FERC has not ruled on the matter.  If the FERC upholds the decision of the ALJ, up to $126it would disallow $90 million of collected SECA rates could be refunded by the AEP East companies.companies’ remaining $115 million of unsettled gross SECA revenues.  We have recorded provisions in the aggregate amount of $37 million related to the potential refund of SECA rates pending settlement negotiations with various intervenors.rates. After completed and in-process settlements of SECA revenues that will consume about $7 million of the reserves for refunds, the AEP East companies will have a remaining reserve balance of $30 million to settle the remaining unsettled gross SECA revenues.

SECA transition rates expired on March 31, 2006 and did not fully compensate AEP East companies for ongoing lost T&O revenues.  As a result of rate relief in certain jurisdictions, however, approximately 85% of the ongoing lost T&O revenues are now being recovered from native load customers of AEP East companies in those jurisdictions.  The portion attributable to Virginia is being collected subject to refund.

In addition to seeking retail rate recovery from native load customers in the applicable states, AEP and another member of PJM have filed an application with the FERC seeking compensation from other unaffiliated members of PJM for the costs associated with those members’ use of the filers’ the AEP East companies respective transmission assets.  A majority of PJM members have filed in opposition to the proposal.  Hearings were held in April 2006.  An ALJ recommended a rate design that would result in greater recovery for AEP than the proposal AEP had submitted.  The ALJ also recommended, however, that the design be phased-in, which could limit the amount of recovery for AEP.  In April 2007, the FERC issued an order reversing the ALJ decision.  The FERC ruled that the current PJM rate design is just and reasonable.  The FERC further ruled that the cost of new facilities of 500 kV and above would be shared among all PJM participants.  Management cannot estimate at this time what affect, if any, this order will have on our future construction of new east transmission facilities, results of operations, cash flows and financial condition.

The increase in amount PJM charges for transmission line loss may not be recoverable.(Applies to AEP, APCo, CSPCo, I&M and OPCo.)

On June 1, 2007, in response to a 2006 FERC order, PJM revised its methodology for considering transmission line losses in generation dispatch and the calculation of locational marginal prices.   Marginal-loss dispatch recognizes the varying delivery costs of transmitting electricity from individual generator locations to the places where customers consume the energy.  Prior to the implementation of marginal-loss dispatch, PJM used average losses in dispatch and in the calculation of locational marginal prices.  Locational marginal prices in PJM now include the real-time impact of transmission losses from individual sources to loads.  Due to the implementation of marginal-loss pricing, for the period June 1, 2007 through September 30, 2007, AEP experienced an increase in the cost of delivering energy from the generating plant locations to customer load zones partially offset by cost recoveries and increased off-system sales resulting in a net loss of approximately $25 million.  AEP has initiated discussions with PJM regarding the impact it is experiencing from the change in methodology and will pursue through the appropriate stakeholder processes a modification of such methodology.  Management believes these additional costs should be recoverable through retail and/or cost-based wholesale rates and is seeking recovery in current and future fuel or base rate filings as appropriate in each of its eastern zone states.  In the interim, these costs will have an adverse effect on future results of operations and cash flows.  Management is unable to predict whether full recovery will ultimately be approved.

Our nonstatutory surcharges in Kentucky may be invalidated. (Applies to AEP.)
In August 2007, the Franklin 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 ruling results from the AG’s appeal of the KPSC’s approval of a natural gas distribution surcharge for replacement of gas mains.  The AG notified the KPSC that the Franklin County Circuit Court judge’s order in the Duke Energy case can be interpreted to include 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.

Although this order is not directly applicable to KPCo, it is possible that the AG or another intervenor could appeal an existing surcharge KPCo is collecting to the Franklin County Circuit Court.  KPCo’s fuel clause, annual Rockport Plant capacity surcharge, merger surcredit and credit system sales rider are not specifically authorized by statute. These surcharges are currently producing net annual revenues of approximately $10 million.  The KPSC has asked interested parties to brief the issue in KPCo’s outstanding fuel cost proceeding.  The AG’s filed brief took the position that the KPCo fuel clause should be invalidated because the KPSC lacked the authority by statute to implement a fuel clause for KPCo without a full rate case review.  In August 2007, the KPSC issued an order stating despite the Franklin County Circuit Court decision, the KPSC has the authority to provide for surcharges and surcredits at least until a Court of Appeals ruling.  In August 2007, the AG agreed to stipulate to a stay order over the Franklin County Circuit Court’s decision pending the appeal decision.  KPCo’s exposure is indeterminable at this time.  If the appeal is unfavorable, future results of operations and cash flows could be adversely affected.

We are exposed to losses resulting from the bankruptcy of Enron Corp.  (Applies to AEP.)

On June 1, 2001, we purchased HPL from Enron Corp. (Enron). Later that year, Enron and its subsidiaries filed bankruptcy proceedings in the U.S. Bankruptcy Court for the Southern District of New York. Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.  In connection with the 2001 acquisition of HPL, we entered into an agreement with BAM Lease Company, which granted HPL the exclusive right to use approximately 65 BCF of cushion gas required for the normal operation of the Bammel gas storage facility.  At the time of our acquisition of HPL, Bank of America (BOA) and certain other banks (together with BOA, BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of 65 BCF of cushion gas.  Additionally, 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, HPL was informed by the BOA Syndicate of a purported default by Enron under the terms of the financing arrangement.  We purchased 10 BCF of gas from Enron and are currently litigating the rights to the remaining 55 BCF of cushion gas.  In August 2007, the judge issued a decision granting BOA summary judgment without awarding any damages and dismissing our claims.  The judge in the case held another hearing in September 2007 and said that he plans a further hearing on the damages issue.  We asked the judge to certify an appeal of the legal issues decided by his summary judgment rulings prior to any ruling on damages.  At this time we are unable to predict how the Judge will rule on the pending request.  If the judge issues a judgment directing us to pay an amount in excess of the gain on the sale of HPL and if we are unsuccessful in having the judgment reversed or modified, the judgment could have a material adverse effect on results of operations, cash flows, and possibly financial condition.

In February 2004, in connection with BOA’s dispute, Enron filed Notices of Rejection regarding the cushion gas use agreement and other incidental agreements.  We have objected to Enron’s attempted rejection of these agreements.  In 2005, we sold HPL, including the Bammel gas storage facility.  We indemnified the purchaser for damages, if any, arising from the litigation with BOA.  Management is unable to predict the final resolution of these disputes, however the impact on results of operations, cash flows and financial condition could be material.

Risks Relating To State Restructuring

In Ohio, our costs may not be recovered and rates may be reduced. (Applies to AEP, OPCo and CSPCo.)

In January 2005, the PUCO approved RSPs for CSPCo and OPCo. The RSPs provide, among other things, for CSPCo and OPCo to raise their generation rates on an annual basis through 2008 by 3% and 7%, respectively. The RSPs also provide for possible additional annual generation rate increases of up to an average of 4% per year for specified costs. The RSPs also provide that CSPCo and OPCo can recover certain environmental carrying costs, PJM-related administrative costs and certain congestion costs. In 2006, CSPCo and OPCo collected an additional estimated $244 million in gross margin as a result of the RSPs. This amount is expected to increase in 2007 and 2008.

In 2005, the Ohio Consumers’ Counsel filed an appeal to the Ohio Supreme Court that challenged the validity of the RSPs under Ohio’s electricity restructuring law. In July 2006, the Ohio Supreme Court vacated the PUCO’s RSP orders for CSPCo and OPCo and remanded the case to the PUCO for further proceedings.

In August 2006, the PUCO directed CSPCo and OPCo to file a plan providing an option for customer participation in the electric market through competitive bids or other reasonable means. The PUCO also held that the RSPs shall remain effective. Accordingly, CSPCo and OPCo continued collecting RSP revenues. In September 2006, CSPCo and OPCo submitted their proposals to provide additional options for customer participation in the electric market.

In MarchOctober 2007, CSPCo and OPCo filedmade a settlement agreement atfiling with the PUCO resolvingunder the Ohio Supreme Court's remandaverage 4% generation rate provision of the PUCO’s RSP order. Management expectstheir RSPs for an additional increase in their annual generation rates effective January 2008 of $35 million and $12 million, respectively, to recover governmentally-mandated costs and increased costs related to marginal-loss pricing.  CSPCo and OPCo will implement these proposed increases in January 2008 and are subject to refund until the PUCO will approveissues a final order in the matter.  Management is unable to predict the outcome of this settlement agreement.filing and its impact on future results of operations and cash flows.

Some lawsCSPCo and regulations governing restructuringOPCo are involved in Virginia have not yet been interpreted or adopted and could harm our business, operating results and financial condition. (Appliesdiscussions with various stakeholders in Ohio about potential legislation to AEP and APCo.)

Virginia restructuringaddress the period following the expiration of the RSPs on December 31, 2008.  In August 2007, legislation was enacted in 1999 providing for retail choiceintroduced that would significantly reduce the likelihood of generation suppliersCSPCo’s and OPCo’s ability to be phased in over two years beginning January 1, 2002. It required jurisdictional utilities to unbundle their power supply and energy delivery rates and to file functional separation plans by January 1, 2002. APCo filed its plan with the Virginia SCC and, following Virginia SCC approval of a settlement agreement, now operates in Virginia as a functionally separated electric utility charging unbundledcharge market-based rates for its retail salesgeneration at the expiration of electricity.their RSPs.  In place of market-based rates, it is more likely that some form of cost-based rates or hybrid-based rates would be required.  The settlement agreement addressed functional separation, leaving decisions relatedlegislation passed through the Ohio Senate and still must be considered by the Ohio House of Representatives.  At this time, management is unable to legal separation for later Virginia SCC consideration. While the electric restructuring law in Virginia established the general framework governing the retail electricpredict whether CSPCo and OPCo will transition to market it required the Virginia SCCpricing, extend their RSP rates, with or without modification, or become subject to issue rules and determinations implementing the law.

In April 2007, Virginia enacted a law providing for cost-based regulationlegislative reinstatement of electric utilities’ generation/supply rates. With the returnsome form of cost-based regulation APCo’sfor their generation business will again meet the criteria for application of regulatory accounting principles under SFAS 71. Results of operations and financial condition could be adversely affected if and when APCo is required to re-establish certain net regulatory liabilities applicable to its generation/supply business. The timing and one-time earnings effect from such reapplication of SFAS 71 regulatory accounting for APCo’s Virginia generation/supply business are uncertain at this time.on January 1, 2009.

There is uncertainty as to our recovery of stranded costs resulting from industry restructuring in Texas.  (Applies to AEP and TCC.AEP.)

Restructuring legislation in Texas required utilities with stranded costs to use market-based methods to value certain generating assets for determining stranded costs.  We elected to use the sale of assets method to determine the market value of TCC’s generation assets for stranded cost purposes.  In general terms, the amount of stranded costs under this market valuation methodology is the amount by which the book value of generating assets, including regulatory assets and liabilities that were not securitized, exceeds the market value of the generation assets, as measured by the net proceeds from the sale of the assets. In May 2005, TCC filed its stranded cost quantification application with the PUCT seeking recovery of $2.4 billion of net stranded generation costs and other recoverable true-up items.  A final order was issued in April 2006.  In the final order, the PUCT determined TCC’s net stranded generation costs and other recoverable true-up items to be approximately $1.475 billion.  We have appealed the PUCT’s final order seeking additional recovery consistent with the Texas Restructuring Legislation and related rules, other parties have appealed the PUCT’s final order as unwarranted or too large.  In a preliminary ruling filed in February 2007, the Texas state district court (District Court) adjudicating the appeal of the final order in the true-up proceeding found that the PUCT erred in several respects, including the method used to determine stranded costs and the awarding of certain carrying costs.  Following the preliminary ruling, the court granted a rehearing of the issue regarding the method to determine stranded costs.

In March 2007, the District Court judge reversed the earlier preliminary decision concluding the sale of assets method to value TCC’s nuclear plant was appropriate.  It is expected that the parties and intervenors will appeal various portions of the District Court ruling along with other items to the Texas Court of Appeals.  Management cannot predict the ultimate outcome of any future court appeals or any future remanded PUCT proceeding.

Risks Related to Owning and Operating Generation Assets and Selling Power

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.(Applies to AEP and each Registrant Subsidiary other than TCC and TNC.Subsidiary.)

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.  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.  On April 2, 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.  Costs of compliance with environmental regulations could adversely affect our results of operations 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.

If Federal and/or State requirements are imposed on electric utility companies mandating further emission reductions, including limitations on CO2 emissions, such requirements could make some of our electric generating units uneconomical to maintain or operate.  (Applies to AEP and each Registrant Subsidiary other than TCC and TNC.Subsidiary.)

Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generating plants are potentially subject to increased regulations, controls and mitigation expenses.  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.  On April 2, 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.  Future changes in environmental regulations governing these pollutants could make some of our electric generating units uneconomical to maintain or operate.  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 mandatory requirements for further emission reductions from our fossil fleet do not appear to be imminent, we continue to monitor regulatory and legislative developments in this area.

Governmental authorities may assess penalties on us if it is determined that we have not complied with environmental laws and regulations. (Applies to AEP and each Registrant Subsidiary other than TCC and TNC.Subsidiary.)

If we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, that failure may result in the assessment of civil or criminal penalties and fines against us.  Recent lawsuits by the Federal EPA and various states filed against us highlight the environmental risks faced by generating facilities, in general, and coal-fired generating facilities, in particular.

Since 1999, we have been involved in litigation regarding generating plant emissions under the CAA.  The Federal EPA and a number of states alleged that we and other unaffiliated utilities modified certain units at coal-fired generating plants in violation of the CAA.  The Federal EPA filed complaints against certain AEP subsidiaries in U.S. District Court for the Southern District of Ohio.  A separate lawsuit initiated by certain special interest groups was consolidated with the Federal EPA case.  The alleged modification of the generating units occurred over a 20-year period.  In October 2007, we announced that we had entered into a consent decree with the Federal EPA, the DOJ, the states and the special interest groups.  The consent decree has been filed with the U.S. District Court. The consent decree is subject to a 30-day public comment period and final approval by the Court.  A bench trialhearing on the liability issues was held during July 2005. Briefing has concludedmotion to approve the consent decree is scheduled for December 10, 2007.  Cases are still pending that could affect CSPCo’s share of jointly-owned units at Beckjord, Zimmer, and the court has indicated an intent to issue a decision on liability.Stuart stations.  Additionally, in July 2004 attorneys general of eight states and others sued AEP and other utilities alleging that CO2 emissions from power generating facilities constitute a public nuisance under federal common law.  The trial court dismissed the suits and plaintiffs have appealed the dismissal.  While we believe the claims are without merit, the costs associated with reducing CO2 emissions could harm our business and our results of operations and financial position.

If these or other future actions are resolved against us, substantial modifications of our existing coal-fired power plants could be required.  In addition, we could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay penalties and/or halt operations.  Moreover, our results of operations and financial position could be reduced due to the timing of recovery of these investments and the expense of ongoing litigation.

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 March 31,September 30, 2007 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

(a)OPCoAPCo repurchased 3093 shares of its 4.40%4.5% cumulative preferred stock, in a privately-negotiated transaction outside of an announced program.
(b)APCo repurchased 20 shares of its 4.5% cumulative preferred stock, in privately-negotiated transactions outside of an announced program.
(c)APCo repurchased 1 share of its 4.5% cumulative preferred stock, in privately-negotiated transactions outside of an announced program.

Item 4. Submission of Matters to a Vote of Security Holders

NONE

Item 5.  Other Information

NONE

Item 6.  Exhibits

AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO SWEPCo, TCC and TNCSWEPCo

12 -– Computation of Consolidated Ratio of Earnings to Fixed Charges.

AEP

31(a) -– Certification of AEP Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(c) -– Certification of AEP Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO SWEPCo, TCC and TNCSWEPCo

31(b) -– Certification of Registrant Subsidiaries’ Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(d) -– Certification of Registrant Subsidiaries’ Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO SWEPCo, TCC and TNCSWEPCo

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



AEP TEXAS CENTRAL COMPANY
AEP TEXAS NORTH COMPANY
APPALACHIAN POWER COMPANY
COLUMBUS SOUTHERN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
KENTUCKY 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:  May 4,November 2, 2007