UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended September 30, 2007March 31, 2008
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____

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

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

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

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

Columbus Southern Power Company, Indiana Michigan 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
October 31, 2007April 30, 2008
    
American Electric Power Company, Inc.        400,006,022
                 401,591,005
   ($6.50 par value)
Appalachian Power Company  13,499,500
   (no par value)
Columbus Southern Power Company  16,410,426
   (no par value)
Indiana Michigan Power Company  1,400,000
   (no par value)
Ohio Power Company  27,952,473
   (no par value)
Public Service Company of Oklahoma  9,013,000
   ($15 par value)
Southwestern Electric Power Company  7,536,640
   ($18 par value)


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX TO QUARTERLY REPORTS ON FORM 10-Q
September 30, 2007March 31, 2008

Glossary of Terms
 
Forward-Looking Information
 
Part I. FINANCIAL INFORMATION
  
 Items 1, 2 and 3 - Financial Statements, Management’s Financial Discussion and Analysis and Quantitative and Qualitative Disclosures About Risk Management Activities:
American Electric Power Company, Inc. and Subsidiary Companies:
 Management’s Financial Discussion and Analysis of Results of Operations
 Quantitative and Qualitative Disclosures About Risk Management Activities
 Condensed Consolidated Financial Statements
 Index to Condensed Notes to Condensed Consolidated Financial Statements
  
Appalachian Power Company and Subsidiaries:
 Management’s Financial Discussion and Analysis
 Quantitative and Qualitative Disclosures About Risk Management Activities
 Condensed Consolidated Financial Statements
 Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
  
Columbus Southern Power Company and Subsidiaries:
 Management’s Narrative Financial Discussion and Analysis
 Quantitative and Qualitative Disclosures About Risk Management Activities
 Condensed Consolidated Financial Statements
 Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
  
Indiana Michigan Power Company and Subsidiaries:
 Management’s Narrative Financial Discussion and Analysis
 Quantitative and Qualitative Disclosures About Risk Management Activities
 Condensed Consolidated Financial Statements
 Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
Ohio Power Company Consolidated:
 Management’s Financial Discussion and Analysis
 Quantitative and Qualitative Disclosures About Risk Management Activities
 Condensed Consolidated Financial Statements
 Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
  
Public Service Company of Oklahoma:
 Management’s 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., Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company.  Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.


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

Term
 
Meaning

ADITCAccumulated 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 SystemAmerican Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP System Power Pool or 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 System or the SystemAmerican Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility 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).Income.
APCo Appalachian Power Company, an AEP electric utility subsidiary.
AROAPSC Asset Retirement Obligations.Arkansas Public Service Commission.
CAA Clean Air Act.
CO2
 Carbon Dioxide.
Cook PlantDonald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CTC Competition Transition Charge.
DETMCWIP Duke Energy Trading and Marketing L.L.C., a risk management counterparty.Construction Work in Progress.
DOJ United States Department of Justice.
E&R Environmental compliance and transmission and distribution system reliability.
EDFITEaR Excess Deferred Federal Income Taxes.Earnings at Risk, a method to quantify risk exposure.
EITF Financial Accounting Standards Board’s Emerging Issues Task Force.
EITF 06-10EITF Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements.”
ERCOT Electric Reliability Council of Texas.
FASB Financial Accounting Standards Board.
Federal EPA United States Environmental Protection Agency.
FERC Federal Energy Regulatory Commission.
FIN FASB Interpretation No.
FIN 4646R FIN 46,46R, “Consolidation of Variable Interest Entities.”
FIN 48 
FIN 48, “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1 “Definition of Settlement in FASB Interpretation No. 48.”
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.
IRS Internal Revenue Service.
IURC Indiana Utility Regulatory Commission.
I&M Indiana Michigan Power Company, an AEP electric utility subsidiary.
JMG JMG Funding LP.
KPCo Kentucky Power Company, an AEP electric utility subsidiary.
KPSC Kentucky Public Service Commission.
kV Kilovolt.
KWH Kilowatthour.
LPSC Louisiana Public Service Commission.
MISO Midwest Independent Transmission System Operator.
MTM Mark-to-Market.
MW Megawatt.
MWH Megawatthour.
NOx
 Nitrogen oxide.
Nonutility Money Pool AEP System’s Nonutility Money Pool.
NRCNuclear Regulatory Commission.
NSR New Source Review.
NYMEX New York Mercantile Exchange.
OATTOpen Access Transmission Tariff.
OCC Corporation Commission of the State of Oklahoma.
OPCo Ohio Power Company, an AEP electric utility subsidiary.
OPEBOther Postretirement Benefit Plans.
OTC Over the counter.
PATHPotomac Appalachian Transmission Highline, LLC and its subsidiaries, a joint venture with Allegheny Energy Inc. formed to own and operate electric transmission facilities in PJM.
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; APCo, CSPCo, I&M, OPCo, PSO and SWEPCo.
REPTexas Retail Electric Provider.
Risk Management Contracts Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana, owned by AEGCo and I&M.
RSP Ohio Rate Stabilization Plan.
RTO Regional Transmission Organization.
S&P Standard and Poor’s.
SCRSelective Catalytic Reduction.
SEC United States Securities and Exchange Commission.
SECA Seams Elimination Cost Allocation.
SFAS Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board.
SFAS 71 Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation.”
SFAS 109Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes.”
SFAS 133 Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.”
SFAS 157 Statement of Financial Accounting Standards No. 157, “Fair Value Measurements.”
SFAS 158Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”
SFAS 159Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.”
SIA System Integration Agreement.
SNFSpent Nuclear Fuel.
SO2
 Sulfur Dioxide.
SPP Southwest Power Pool.
Stall Unit J. Lamar Stall Unit at Arsenal Hill Plant.
Sweeny Sweeny Cogeneration Limited Partnership, owner and operator of a four unit, 480 MW gas-fired generation facility, owned 50% by AEP.  AEP’s 50% interest in Sweeny was sold in October 2007.
SWEPCo Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC AEP Texas Central Company, an AEP electric utility subsidiary.
TEM SUEZ Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing, Inc.).
Texas Restructuring   Legislation Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC AEP Texas North Company, an AEP electric utility subsidiary.
True-up Proceeding A filing made under the Texas Restructuring Legislation to finalize the amount of stranded costs and other true-up items and the recovery of such amounts.
Turk Plant John W. Turk, Jr. Plant.
Utility Money Pool AEP System’s Utility Money Pool.
VaR Value at Risk, a method to quantify risk exposure.
Virginia SCC Virginia State Corporation Commission.
WPCo Wheeling Power Company, an AEP electric distribution subsidiary.
WVPSC Public Service Commission of West Virginia.


FORWARD-LOOKING INFORMATION

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

·Electric load and customer growth.
·Weather conditions, including storms.
·Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·Availability of generating capacity and the performance of our generating plants.
·Our ability to recover regulatory assets and stranded costs in connection with deregulation.
·Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·Our ability to build or acquire generating capacity (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs 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 forof new investments in generation, distribution and 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.
·Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to refinance existing debt at attractive rates.
·Our ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities.
·Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
·Actions of rating agencies, including changes in the ratings of debt.
·Volatility and changes in markets for electricity, natural gas, coal, nuclear fuel and other energy-related commodities.
·Changes in utility regulation, including the potential for new legislation in Ohio and membership in and integration intothe allocation of costs within RTOs.
·Accounting pronouncements periodically issued by accounting standard-setting bodies.
·The performanceimpact of volatility in the capital markets on the value of the investments held by our pension, and other postretirement benefit plans.plans and nuclear decommissioning trust.
·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

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 

Updates to our significant regulatory activities in 2008 include:

(a)·The difference betweenIn February 2008, APCo and WPCo filed for an increase of approximately $156 million including a $135 million increase in the Expanded Net Energy Cost recovery mechanism, a $17 million increase in construction cost surcharges and $4 million of reliability expenditures, to all become effective July 2008.
·In February 2008, the FERC approved a PATH request for a transmission formula rate and ordered that the formula rates go into effect in March 2008.  Settlement negotiations began and motions for rehearing were filed by intervening parties in March 2008.  PATH requested an incentive return of 14.3% on its equity investment using a 50/50 debt to equity ratio, the recovery of deferred pre-operating, pre-construction costs and implemented amountsthe recovery of annualconstruction financing costs through the inclusion of CWIP in rate increasebase with a true-up to actual for these costs.
·
In March 2008, the OCC approved a settlement for recovery of 2007 Oklahoma ice storm costs, subject to an audit of December ice storm costs to be filed in July 2008.  As a result, PSO recorded an $81 million regulatory asset for actual ice storm maintenance expenses and related carrying costs less $9 million of amortization expense to offset recognition of deferred gains from  sales of SO2 emission allowances.
·In March 2008, PSO and all other parties signed a settlement agreement that provides for recovery of $11 million of pre-construction costs related to PSO’s Red Rock Generating Facility.  PSO filed the settlement with the OCC for approval.  A hearing on the settlement is partially offset by approximately $35scheduled for May 2008.  As a result of the settlement, PSO wrote-off $10 million of its remaining unrecoverable deferred pre-construction costs/cancellation fees in the first quarter of 2008.
·In March 2008, the WVPSC granted APCo a Certificate of Public Convenience and Necessity and recovery of pre-construction and construction financing costs related to the planned construction of the IGCC plant in West Virginia.  Various intervenors filed petitions with the WVPSC to reconsider the order.  In April 2008, the Virginia SCC denied APCo’s request for approval of the plant and to recover pre-construction and construction financing costs.  In April 2008, APCo filed a petition for reconsideration in Virginia.
·In March 2008, the LPSC approved the application to construct the Turk Plant.  In January 2008, a Texas ALJ recommended that SWEPCo’s application be denied and subsequently, in March 2008,  the PUCT voted to reopen the record and conduct additional hearings.  SWEPCo expects a decision from the PUCT in the last half of 2008.
·In March 2008, APCo filed a notice with the Virginia SCC that it plans to file a general base rate case no sooner than May 2008.  APCo will also file for recovery of $46 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 subject to refund, a net $50 million reduction in credits to customers for off-system sales margins as part of its July 2007 fuel clause filing under the new re-regulation legislation.costs.
(b)·Management plansIn April 2008, the LPSC approved a settlement agreement between SWEPCo and the LPSC staff that established a formula rate plan with a three-year term.  Beginning August 2008, rates shall be established to seek rehearingallow SWEPCo to earn an adjusted return on common equity of the PUCO decision.10.565%.
(c)·Implemented $9 million in July 2007, increasedIn April 2008, the Ohio legislature passed legislation which allows utilities to $10 million upon OCC order in October 2007.set prices by filing an Electric Security Plan along with the ability to simultaneously file a Market Rate Option.  The PUCO would have authority to approve or modify the utility’s request to set prices.  Both alternatives would involve earnings tests monitored by the PUCO.  The legislation still must be signed by the Ohio governor and will become law 90 days after the Governor’s signature.

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

 
 
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)
We expected coal costs to increase by 13% in 2008, but due to escalating domestic prices and increased needs, our current estimate is in the range of a 14% to 18% increase.  We continue to see increases in prices due to expiring lower priced coal and transportation contracts being replaced with higher priced contracts.  Prices for fuel oil are at record highs and very volatile.  Going forward, we have some exposure to price risk related to our open positions for coal, natural gas and fuel oil especially since we do not currently have an active fuel cost recovery adjustment mechanism in Ohio, which represents approximately 20% of our fuel costs.  However, the current pending legislation in Ohio includes a fuel cost recovery mechanism.  Fuel cost adjustment rate clauses in our other jurisdictions will help offset future negative impacts of fuel price increases on our gross margins.

(a)Subject to refund.  Proceeding is on-going.
RESULTS OF OPERATIONS

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.

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 OPERATIONSSegments

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 3435 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and lowerLower Mississippi rivers.Rivers.  Approximately 35%39% of the barging operations relates tois for the transportation of coal, 30% relates to agricultural products, 18% relates to30% for coal, 14% for steel and 17% relates tofor other commodities.

Generation and Marketing
·IPPs, windWind 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 Net Income Before Discontinued Operations and Extraordinary Lossby segment for the three and nine months ended September 30, 2007March 31, 2008 and 2006.  We reclassified prior year amounts to conform to the current year’s segment presentation.2007.
 
Three Months Ended September 30,
  
Nine Months Ended September 30,
 
Three Months Ended
March 31,
 
 
2007
  
2006
  
2007
  
2006
 2008 2007 
 
(in millions)
 (in millions) 
Utility Operations $388  $378  $879  $902  $410  $253 
MEMCO Operations  18   19   40   54   7   15 
Generation and Marketing  3   4   17   10   1   (1)
All Other (a)  (2)  (136)  (1)  (151)  155   4 
Income Before Discontinued Operations
and Extraordinary Loss
 $407  $265  $935  $815 
Net Income $573  $271 

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

ThirdAEP Consolidated

First Quarter of 20072008 Compared to ThirdFirst Quarter of 20062007

Net Income Before Discontinued Operations and Extraordinary Loss in 20072008 increased $142$302 million compared to 20062007 primarily due to income of $163 million (net of tax)  from the cash settlement of a $136 million after-tax impairment ofpower purchase and sale agreement with TEM related to the Plaquemine Cogeneration Facility recordedwhich was sold in August 2006.the fourth quarter of 2006 and an increase in Utility Operations segment earnings of $157 million.  The increase in Utility Operations segment earnings primarily relates to lower operation and maintenance expenses as a result of a favorable Oklahoma ice storm settlement and rate increases implemented since the first quarter of 2007 in Ohio, Virginia, West Virginia, Texas and Oklahoma.

Average basic shares outstanding for the three-month period increased to 399401 million in 2008 from 397 million in 2007 from 394 million in 2006 primarily due to the issuance of shares under our incentive compensation and dividend reinvestment plans.  At September 30, 2007, actualActual shares outstanding were 400 million.402 million as of March 31, 2008.

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 in 2007 from 394 million in 2006 primarily due to the issuance of 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.

Utility Operations Income Summary
For the Three and Nine Months Ended September 30, 2007 and 2006
  Three Months Ended 
  March 31, 
  2008  2007 
  (in millions) 
Revenues $3,294  $3,033 
Fuel and Purchased Power  1,213   1,119 
Gross Margin  2,081   1,914 
Depreciation and Amortization  355   383 
Other Operating Expenses  941   991 
Operating Income  785   540 
Other Income, Net  42   18 
Interest Charges and Preferred Stock Dividend Requirements  210   179 
Income Tax Expense  207   126 
Net Income $410  $253 

  
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 September 30,March 31, 2008 and 2007 and 2006

 
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
  2008  2007 
Energy/Delivery Summary
 
2007
  
2006
  
2007
  
2006
 
 
(in millions of KWH)
 
Energy
            
Energy Summary (in millions of KWH) 
Retail:                  
Residential  13,749   13,482   38,015   36,010   14,500   14,139 
Commercial  11,164   10,799   30,750   29,149   9,547   9,359 
Industrial  14,697   13,468   43,110   40,405   14,350   13,565 
Miscellaneous  686   719   1,932   1,991   609   614 
Total Retail  40,296   38,468   113,807   107,555   39,006   37,677 
                        
Wholesale  13,493   13,464   31,648   35,132   11,666   8,778 
                        
Delivery
                
Texas Wires – Energy delivered to customers served
by AEP’s Texas Wires Companies
  7,721   7,877   20,297   20,338 
Texas Wires – Energy Delivered to Customers Served by TNC
and TCC in ERCOT
  5,823   5,831 
Total KWHs
  61,510   59,809   165,752   163,025   56,495   52,286 

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.  Cooling degree days and heating degree days in our service territory for the three months ended March 31, 2008 and 2007 were as follows:

Summary of Heating and Cooling Degree Days for Utility Operations
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 degree days)
  2008 2007 
Weather Summary
            Weather Summary (in degree days) 
Eastern Region            Eastern Region     
Actual – Heating (a)  2   10   2,041   1,573 Actual – Heating (a) 1,824 1,816 
Normal – Heating (b)  7   7   1,973   1,999 Normal – Heating (b) 1,767 1,792 
                      
Actual – Cooling (c)  808   685   1,189   914 Actual – Cooling (c) - 14 
Normal – Cooling (b)  685   688   963   970 Normal – Cooling (b) 3 3 
                      
Western Region (d)                
Western Region (d)
     
Actual – Heating (a)  0   0   994   664 Actual – Heating (a) 949 902 
Normal – Heating (b)  2   2   993   1,007 Normal – Heating (b) 931 959 
                      
Actual – Cooling (c)  1,406   1,468   2,084   2,325 Actual – Cooling (c) 26 56 
Normal – Cooling (b)  1,411   1,410   2,084   2,079 Normal – Cooling (b) 20 18 

(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.

ThirdFirst Quarter of 2008 Compared to First Quarter of 2007

Reconciliation of First Quarter of 2007 Compared to ThirdFirst Quarter of 20062008
Net Income from Utility Operations
(in millions)

Reconciliation of Third Quarter of 2006 to Third Quarter of 2007
First Quarter of 2007    $253 
        
Changes in Gross Margin:       
Retail Margins  114     
Off-system Sales  40     
Transmission Revenues  8     
Other Revenues  5     
Total Change in Gross Margin      167 
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  81     
Gain on Dispositions of Assets, Net  (21)    
Depreciation and Amortization  28     
Taxes Other Than Income Taxes  (10)    
Carrying Costs Income  10     
Interest Income  11     
Other Income, Net  3     
Interest and Other Charges  (31)    
Total Change in Operating Expenses and Other      71 
         
Income Tax Expense      (81)
         
First Quarter of 2008     $410 

Net Income from Utility Operations Before Discontinued Operations and Extraordinary Loss
(in millions)

Third Quarter of 2006
    $378 
        
Changes in Gross Margin:
       
Retail Margins  155     
Off-system Sales  36     
Transmission Revenues, Net  (58)    
Other Revenues  1     
Total Change in Gross Margin
      134 
         
Changes in Operating Expenses and Other:
        
Other Operation and Maintenance  (69)    
Taxes Other Than Income Taxes  (6)    
Carrying Costs Income  11     
Other Income, Net  (2)    
Interest and Other Charges  (53)    
Total Change in Operating Expenses and Other
      (119)
         
Income Tax Expense      (5)
         
Third Quarter of 2007
     $388 

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss increased $10$157 million to $388$410 million in 2007.2008.  The key driver of the increase was a $134$167 million increase in Gross Margin partially offset byand a $119$71 million increasedecrease in Operating Expenses and Other and a $5offset by an $81 million increase in Income Tax Expense.

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

·Retail Margins increased $155$114 million primarily due to the following:
 ·A $29$44 million increase at APCo related to theRSP rate increases implemented in our Ohio jurisdictions with PUCO approval, a $14 million increase related to recovery of E&R costs in Virginia base rate case and theconstruction financing costs in West Virginia, construction surcharge.a $9 million increase in base rates in Texas and an $8 million increase in base rates in Oklahoma.
 ·A $29$58 million increase related to Ormet, a new industrial customeran OPCo coal contract amendment which reduced future deliveries to OPCo in Ohio, effective January 1, 2007.  See “Ormet” section of Note 3.exchange for consideration received.
 ·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.
·A $15 million increase related to new rates in Texas.
·A $14$21 million increase related to increased sales to municipal, cooperative and other customers primarily resulting from new power supply contracts.usage by Ormet, an industrial customer in Ohio.  See “Ormet” section of Note 3.
 These increases were partially offset by:
 ·
A $15$55 million decrease related to increased fuel, consumable and allowance costs 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.
Ohio.
·Margins from Off-system Sales increased $36$40 million primarily due to favorable fuel reconciliations in our western territory, benefits from our eastern natural gas fleet, higher power prices, and highereast physical off-system sales volumes in the east.
·Transmission Revenues, Net decreased $58 million primarilymargins mostly 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 were essentially flat as a result of higher securitization revenue at TCC from the $1.7 billion securitization in October 2006volumes and stronger prices, 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.trading margins.

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

·Other Operation and Maintenance expenses increased $69decreased $81 million primarily due to the NSRa deferral of storm restoration costs of $80 million in Oklahoma as a result of a rate settlement to recover 2007 storm restoration costs partially offset by an abandonmentincrease in generation expenses from base operations and the write-off of digital turbine control equipment at$10 million of unrecoverable pre-construction costs for PSO’s canceled Red Rock Generating Facility.
·Gain on Disposition of Assets, Net decreased $21 million due to the Cook Plant recordedcessation of the earnings sharing agreement with Centrica from the sale of our Texas REPs in 2002.  In 2007, we received the prior year.  See “Federal EPA Complaint and Noticefinal earnings sharing payment of Violation” section in Note 4.$20 million.
·Depreciation and Amortization expense was flat as a result of increaseddecreased $28 million primarily due to lower commission-approved depreciation rates in Indiana, Michigan, Virginia, Oklahoma and Texas and lower Ohio regulatory asset amortization, of the securitized transition assets and overallpartially offset by higher depreciable property balances, offset by lower depreciation expense at I&M and APCo.  The decrease at I&M relatesbalances.
·Taxes Other Than Income Taxes increased $10 million primarily due 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 periodhigher property taxes related to the 2006 Virginia E&R case.property additions.
·Carrying Costs Income increased $11$10 million primarily due to higherincreased carrying cost income related to APCo’s Virginia E&Ron cost deferrals offset by TCC’s start in recovering stranded costs in October 2006, thus eliminating future TCC carrying costs income.Virginia and Oklahoma.
·Interest and Other Charges increased $53$31 million primarily due to additional debt issued in the twelve months ended September 30, 2007 including TCC securitization bonds as well asand higher interest rates on variable rate debt.
·Income Tax Expense increased $5$81 million due to an increase in pretax income.

Nine Months Ended September 30, 2007MEMCO Operations

First Quarter of 2008 Compared to Nine Months Ended September 30, 2006First Quarter of 2007

Reconciliation of Nine Months Ended September 30, 2006 to Nine Months Ended September 30, 2007
Net 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 from plant outages and base operations and distribution expenses associated with service reliability and storm restoration primarily in 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 expired.
·Depreciation and Amortization expense increased $62 million primarily due to increased Ohio regulatory asset amortization related to recovery of IGCC pre-construction costs, increased Texas amortization of the securitized transition assets and higher depreciable property balances, partially offset by commission-approved lower depreciation rates in Indiana and Virginia.
·Carrying Costs Income decreased $28 million primarily due to TCC’s start in recovering stranded costs in October 2006, thus eliminating future TCC carrying costs income, offset by higher carrying costs income related to APCo’s Virginia E&R cost deferrals.
·Interest and Other Charges increased $124 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 decreased $18 million due to a decrease in pretax income.

MEMCO Operations

Third Quarter of 2007 Compared to Third Quarter of 2006

Income Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations segment decreased from $19$15 million in 20062007 to $18$7 million in 2007.2008 primarily due to high water conditions and reduced northbound loadings.  Operating expenses increased $2 million mainlycosts were higher due to the sustained high water conditions on all major rivers and existing river regulations resulting in reduced tow sizes and restricted operating hours which increased fleet size, rising fuel costs and wage increases.consumption.  Northbound loadings continue to be depressed as a result of reduced imports through the Gulf.

Nine Months Ended September 30, 2007Generation and Marketing

First Quarter of 2008 Compared to Nine Months Ended September 30, 2006First Quarter of 2007

Net 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 steel and cement continued to depress freight rates and reduce northbound loadings.  Operating expenses were up for the first nine months of 2007 compared to 2006 primarily due to the cost of the increased fleet size, rising fuel costs and wage increases.

Generation and Marketing

Third Quarter of 2007 Compared to Third 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 All Other decreased from $136 million in 2006 to $2 million in 2007.  The decrease was primarily due to a $136 million after-tax impairment of the Plaquemine Cogeneration Facility recorded in August 2006.

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

Loss Before Discontinued Operations and Extraordinary Loss from All Other decreased from $151 million in 2006 to $1 million in 2007.2008 from a loss of $1 million in 2007 primarily due to an increase in income from wind farm operations.
All Other

First Quarter of 2008 Compared to First Quarter of 2007

Net Income from All Other increased from $4 million in 2007 to $155 million in 2008.  In 2006,2008, we recordedhad after-tax income of $163 million from a $136 million after-tax impairmentlitigation settlement of a power purchase and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006.  The settlement was recorded as a  pretax credit to Asset Impairments and Other Related Items of $255 million in the accompanying Condensed Consolidated Statements of Income ($163 million, net of tax).  In 2007, we had an after-taxa $16 million pretax gain ($10 million, net of $10 milliontax) on the sale of a portion of our investment securities.in Intercontinental Exchange, Inc. (ICE).

AEP System Income Taxes

Income Tax Expense increased $72$163 million in the third quarter of 2007 compared to the third quarter of 2006 primarily due to an 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
 
September 30, 2007
  
December 31, 2006
  March 31, 2008  December 31, 2007 
 
($ in millions)
  ($ in millions) 
Long-term Debt, Including Amounts Due
Within One Year
 $14,776   58.3% $13,698   59.1%
Long-term Debt, including amounts due within one year $15,636   58.8% $14,994   58.1%
Short-term Debt  587   2.3   18   0.0   409   1.5   660   2.6 
Total Debt  15,363   60.6   13,716   59.1   16,045   60.3   15,654   60.7 
Common Equity  9,909   39.1   9,412   40.6   10,489   39.5   10,079   39.1 
Preferred Stock  61   0.3   61   0.3   61   0.2   61   0.2 
                                
Total Debt and Equity Capitalization
 $25,333   100.0% $23,189   100.0% $26,595   100.0% $25,794   100.0%

Our ratio of debt to total capital increased, as planned,decreased from 59.1%60.7% to 60.6%60.3% in 20072008 due to our increased borrowings to support our construction program.common equity from stock issuances through stock compensation and dividend reinvestment plans.

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability.  We are committed to maintaining adequate liquidity.  We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of  long-term debt, sale-leaseback or leasing agreements or common stock.

Credit Markets

We believe we have adequate liquidity under our credit facilities and the ability to issue long-term debt in the current credit markets.  As of March 31, 2008, we had $1.4 billion outstanding of tax-exempt long-term debt sold at auction rates that reset every 7, 28 or 35 days.  This debt is insured by bond insurers previously AAA-rated, namely Ambac Assurance Corporation, Financial Guaranty Insurance Co., MBIA Insurance Corporation and XL Capital Assurance Inc.  Due to the exposure that these bond insurers have in connection with developments in the subprime credit market, the credit ratings of these insurers have been downgraded or placed on negative outlook.  These market factors have contributed to higher interest rates in successful auctions and increasing occurrences of failed auctions, including many of the auctions of our tax-exempt long-term debt.  The instruments under which the bonds are issued allow us to convert to other short-term variable-rate structures, term-put structures and fixed-rate structures.  During the first quarter of 2008, we reduced our outstanding auction rate securities by redeeming or repurchasing $95 million of such debt securities.  In April 2008, we converted, refunded or provided notice to convert or refund $940 million of our outstanding auction rate securities.  We plan to continue this conversion and refunding process for the remaining $471 million to other permitted modes, including term-put and fixed-rate structures through the third quarter of 2008.  The conversions will likely result in higher interest charges compared to prior year but lower than the failed auction rates for this tax-exempt long-term debt.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  At September 30, 2007,March 31, 2008, our available liquidity was approximately $2.6$2.7 billion as illustrated in the table below:

   
Amount
 
Maturity
   
(in millions)
  
Commercial Paper Backup:      
 Revolving Credit Facility  $1,500 March 2011
 Revolving Credit Facility   1,500 April 2012
Total
   3,000  
Cash and Cash Equivalents   196  
Total Liquidity Sources
   3,196  
Less: AEP Commercial Paper Outstanding   559  
 Letters of Credit Drawn   69  
       
Net Available Liquidity
  $2,568  
AmountMaturity
(in millions)
Commercial Paper Backup:
Revolving Credit Facility$1,500  March 2011
Revolving Credit Facility1,500  April 2012
Total3,000  
Cash and Cash Equivalents155  
Total Liquidity Sources3,155  
Less: AEP Commercial Paper Outstanding409  
Letters of Credit Drawn57  
Net Available Liquidity$2,689  

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  In March 2008, the credit facilities were amended so that $750 million may be issued under each credit facility as letters of Receivablescredit.

In October 2007,April 2008, we renewed our sale of receivables agreement.  The sale of receivables agreement provides a commitment ofentered into an additional $650 million from a bank conduit to purchase receivables.  Under the3-year credit agreement the commitment will increase to $700and another $350 million for the months of August and September to accommodate seasonal demand.  This agreement expires in October 2008.364-day credit agreement.

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, 2008, we had credit facilities totaling $3 billion to support our commercial paper program.  The maximum amount of commercial paper outstanding during the first quarter of 2008 was $1.1 billion.  The weighted-average interest rate of our commercial paper during the first quarter of 2008 was 3.66%.

Investments in Auction-Rate Securities

As of March 31, 2008, we had $39 million invested in auction-rate securities.  During the first quarter of 2008, we transferred $135 million of these securities from fair value hierarchy level 2 to level 3 due to the deterioration of liquidity in the auction-rate security market and subsequently sold $96 million of such securities at par.  Issuers have given us notice that they will call a majority of our remaining investments in auction-rate securities at par.  Therefore, based on this fact and our review of the underlying credit quality of these securities, we have not recorded an impairment of these investments.

Debt Covenants and Borrowing Limitations

Our revolving credit agreements, including the new agreements entered into in April 2008, contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%.  The method for calculating our outstanding debt and other capital is contractually defined in our revolving credit agreements.defined. At September 30, 2007,March 31, 2008, this contractually-defined percentage was 56.3%54.9%.  Nonperformance of these covenants could result in an event of default under these credit agreements.  At September 30, 2007,March 31, 2008, we complied with all of the covenants contained in these credit agreements.  In addition, the acceleration of our payment obligations, or the obligations of certain of our major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements and permit the lenders to declare the outstanding amounts payable.

The twofour 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 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 September 30, 2007,March 31, 2008, we had not exceeded those authorized limits.

Credit RatingsDividend Policy and Restrictions

AEP’s ratingsWe have declared common stock dividends payable in cash in each quarter since July 1910.  The Board of Directors declared a quarterly dividend of $0.41 per share in April 2008.  Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time.  We have the option to defer interest payments on the AEP Junior Subordinated Debentures issued in March 2008 for one or more periods of up to 10 consecutive years per period.  During any period in which we defer interest payments, we may not been adjusted bydeclare or pay any rating agency during 2007dividends or distributions on, or redeem, repurchase or acquire, our common stock.  We believe that these restrictions will not have a material effect on our results of operations, cash flows, financial condition or limit any dividend payments in the foreseeable future.

Credit Ratings

In the first quarter of 2008, Moody’s changed its outlook from stable to negative for APCo, SWEPCo, OPCo and AEP is currently on aTCC.  Moody’s affirmed its stable outlook by the rating agencies.for AEP and our other subsidiaries.  Fitch downgraded PSO and SWEPCo from A- to BBB+ for senior unsecured debt.  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
 Three Months Ended 
 
September 30,
 March 31, 
 
2007
  
2006
 2008 2007 
 
(in millions)
 (in millions) 
Cash and Cash Equivalents at Beginning of Period
 $301  $401  $178  $301 
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 Cash Flows from Operating Activities  628   351 
Net Cash Flows Used for Investing Activities  (894)  (628) 
Net Cash Flows from Financing Activities  243   235 
Net Decrease in Cash and Cash Equivalents
  (105)  (142)   (23)  (42) 
Cash and Cash Equivalents at End of Period
 $196  $259  $155  $259 

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 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 $865 million.  The weighted-average interest rate of our commercial paper for the nine months ended September 30, 2007 was 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
 
Nine Months Ended
 Three Months Ended 
 
September 30,
 March 31, 
 
2007
  
2006
 2008 2007 
 
(in millions)
 (in millions) 
Net Income
 $858  $821  $573  $271 
Less: Discontinued Operations, Net of Tax  (2)  (6)
Income Before Discontinued Operations
  856   815 
Depreciation and Amortization  1,144   1,084   363   391 
Other  (370)  297   (308)  (311)
Net Cash Flows From Operating Activities
 $1,630  $2,196 
Net Cash Flows from Operating Activities $628  $351 

Net Cash Flows Fromfrom Operating Activities decreasedincreased in 20072008 primarily due to lower fuel costs recovery, higher tax paymentsincreased income reflecting an improvement in 2007 in conjunction with the filing of the 2006 tax return and increased customer accounts receivable reflecting September 2007 weather’s impactgross margins on energy sales and new contracts in the Generation and Marketing segment.TEM settlement.

Net Cash Flows Fromfrom Operating Activities were $1.6 billion$628 million in 2007. We produced2008 consisting primarily of Net Income Before Discontinued Operations of $856$573 million adjusted forand $363 million of noncash expense items, primarily depreciation and amortization.  Other changes in assets and liabilities representrepresents 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 activitySignificant changes in these asset and liability accounts relatesother items resulted in lower cash from operations due to a numberpayment of items the most significant of which relates to the Texas CTC refund of fuel over-recovery.accrued at December 31, 2007.

Net Cash Flows Fromfrom Operating Activities were $2.2 billion$351 million in 2006.  We produced2007 consisting primarily of Net Income Before Discontinued Operations of $815$271 million adjusted forand $391 million of noncash expense items, primarily depreciation and 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 representrepresents 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 activitySignificant changes in these asset and liability accounts relates to a number of items; the most significant is a $235 million decreaseother items resulted in lower cash related to customer deposits held for trading activities generallyfrom operations due to lower gas and power market prices.payment of items accrued at December 31, 2006.

Investing Activities
 
Nine Months Ended
 Three Months Ended 
 
September 30,
 March 31, 
 
2007
  
2006
 2008 2007 
 
(in millions)
 (in millions) 
Construction Expenditures $(2,595) $(2,428)  $(778) $(907) 
Acquisition of Darby, Dresden and Lawrenceburg Plants  (512)  - 
Proceeds from Sales of Assets  78   120   18   68 
Other  94   (149)   (134)  211 
Net Cash Flows Used For Investing Activities
 $(2,935) $(2,457) 
Net Cash Flows Used for Investing Activities $(894) $(628)

Net Cash Flows Used Forfor Investing Activities were $2.9 billion$894 million in 2008 and $628 million in 2007 primarily due to Construction Expenditures for our environmental, distribution and new generation investment planplan.  Construction expenditures decreased compared to 2007 due to a decline in environmental, fossil, hydro and purchases of gas-fired generating units.nuclear projects partially offset by increased expenditures for new generation and transmission projects.

Net Cash Flows Used For Investing Activities were $2.5 billionIn our normal course of business, we purchase investment securities including variable rate demand notes with cash available for short-term investments and purchase and sell securities within our nuclear trusts.  The net amount of these activities is included in 2006 primarily due to Construction Expenditures for our environmental investment plan, consistent with our budgeted cash flows.Other.

We forecast approximately $1$3 billion of construction expenditures for the remainder of 2007.2008.  Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  These construction expenditures will be funded with cash fromthrough results of operations and financing activities.

Financing Activities
 
Nine Months Ended
 Three Months Ended 
 
September 30,
 March 31, 
 
2007
  
2006
 2008 2007 
 
(in millions)
 (in millions) 
Issuance of Common Stock $45  $54 
Issuance/Retirement of Debt, Net $1,623  $529   376   355 
Dividends Paid on Common Stock  (467)  (437)   (165)  (155) 
Other  44   27   (13)  (19) 
Net Cash Flows From Financing Activities
 $1,200  $119 
Net Cash Flows from Financing Activities $243  $235 

Net Cash Flows Fromfrom Financing Activities in 20072008 were $1.2 billion$243 million primarily due to issuing $1.9 billionthe issuance of debt securities including $1 billion$315 million of new debt for plant acquisitionsjunior subordinated debentures and construction$500 million of senior unsecured notes partially offset by the retirement of $95 million of pollution control bonds, $52 million of senior unsecured notes and increasing$34 million of mortgage notes and the reduction of our short-term commercial paper borrowings.  We paid common stock dividends of $467outstanding by $250 million.  See Note 9 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows Fromfrom Financing Activities in 20062007 were $119 million.  During 2006, we issued $115$235 million primarily due to $150 million of obligations relating to pollution control bonds, issued $1 billion of senior unsecured notesshort-term commercial paper borrowings under our credit facilities and retired $396issuing $251 million of notes for a net increase in notes outstanding of $604 million and retired $100 million of first mortgage bonds and $52 million of securitization bonds.debt securities.

We expect to issue debt in the capital markets of approximately $675 million to fund ourOur capital investment plans for 2008 will require additional funding from the remainder of 2007.capital markets.

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 internalcurrent guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements and sales of customer accounts receivable that we enter in the normal course of business.  Our significant off-balance sheet arrangements  are as follows:
 
September 30,
2007
  
December 31,
2006
 
March 31,
2008
 
December 31,
2007
 
 
(in millions)
 (in millions)
AEP Credit Accounts Receivable Purchase Commitments $530  $536  $502  $507 
Rockport Plant Unit 2 Future Minimum Lease Payments  2,290   2,364   2,216   2,216 
Railcars Maximum Potential Loss From Lease Agreement  30   31   30   30 

For complete information on each of these off-balance sheet arrangements see the “Off-balance Sheet Arrangements” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 20062007 Annual Report.

Summary Obligation Information

A summary of our contractual obligations is included in our 20062007 Annual Report and has not changed significantly from year-end other than the debt issuances discussed in “Cash Flow” and “Financing Activities” 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.above.

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“Management’s Financial Discussion and Analysis of Results of OperationsOperations” in our 20062007 Annual Report.  The 20062007 Annual Report should be read in conjunction with this report in order to understand significant factors without material changeswhich have not materially changed in status since the issuance of our 20062007 Annual Report, but may have a material impact on our future results of operations, cash flows and financial condition.

Ohio Restructuring

As permitted by theThe current Ohio restructuring legislation permits CSPCo and OPCo canto implement market-based rates effective January 2009, following the expiration of itstheir RSPs on December 31, 2008.  The RSP plans include generation rates which are between PUCO approved rates and higher market rates.  In August 2007,April 2008, the Ohio legislature passed legislation was introduced thatwhich allows utilities to set prices by filing an Electric Security Plan along with the ability to simultaneously file a Market Rate Option.  The PUCO would significantly reducehave authority to approve or modify the likelihoodutility’s request to set prices.  Both alternatives would involve earnings tests monitored by the PUCO.  The legislation still must be signed by the Ohio governor and will become law 90 days after the governor’s signature.  Management is analyzing the financial statement implications of the pending legislation on CSPCo’s and OPCo’s ability to charge market-based rates for generation atsupply business, more specifically, whether the expirationfuel management operations 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 meet the criteria for application of SFAS 71.    The financial statement impact of the pending legislation will transition to market pricing, extend their RSP rates, with or without modification, or become subject tonot be known until the PUCO acts on specific proposals made by CSPCo and OPCo.  Management expects a legislative reinstatementPUCO decision in the fourth quarter of some form of cost-based regulation for their generation supply business on January 1, 2009.2008.

Texas Restructuring

Pursuant to PUCT orders, TCC recoveredsecuritized its net recoverable stranded generation costs throughof $2.5 billion and is recovering such costs over a securitization financing andperiod ending in 2020.  TCC is also refunding its net other true-up items of $375 million through 2008 via a CTC credit rate rider credit under 2006 PUCT orders.rider.  TCC appealed the PUCT stranded costs true-up and related orders seeking relief in both state and federal court on the grounds that certain aspects of the orders are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law and fail to fully compensate TCC for its net stranded cost and other true-up items.

Municipal customers and other intervenors also appealed the PUCT true-up and related orders seeking to further reduce TCC’s true-up recoveries.  In March 2007, the Texas District Court judge hearing the appeal of the true-up order affirmed the PUCT’s April 4, 2006 final true-up order for TCC with two significant exceptions.  The judge determined that the PUCT erred by applying an invalid rule to determine the carrying cost rate for the true-up of stranded costs.  However, the District Court did not rule that the carrying cost rate was inappropriate.  If the District Court’s ruling onPUCT reevaluates the carrying cost rate is ultimately upheld on appealremand and remanded to the PUCT for reconsideration, the PUCT could either confirm the existing weighted average carrying cost (WACC) rate or determine a new rate.  If the PUCT reduces 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 that 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 true-up order rulingsdecision to the Texas Court of Appeals.  Management cannot predict the outcome of these true-up and relatedcourt 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

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. 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.  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.  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
                Commercial
     
Total
          
Operation
     Total        Nominal Operation
Operating
 
Project
   
Projected
        
MW
 
Date
 Project   Projected        MW Date
Company
 
Name
 
Location
 
Cost (a)
 
CWIP
 
Fuel Type
 
Plant Type
 
Capacity
 
(Projected)
 Name Location Cost (a) CWIP (b) Fuel Type Plant Type Capacity (Projected)
     
(in millions)
 
(in millions)
             (in millions) (in millions)        
SWEPCo Mattison Arkansas $122(b)$52 Gas Simple-cycle 340(b)2007
PSO Southwestern Oklahoma  59(c) 45 Gas Simple-cycle 170 2008 Southwestern(c)Oklahoma $58 $- Gas Simple-cycle 170 2008
PSO Riverside Oklahoma  58(c) 45 Gas Simple-cycle 170 2008 Riverside Oklahoma  59  57 Gas Simple-cycle 170 2008
AEGCo Dresden(d)Ohio  265(d) 88 Gas Combined-cycle 580 2009 Dresden(d)Ohio  305(d) 101 Gas Combined-cycle 580 2010
SWEPCo Stall Louisiana  375  15 Gas Combined-cycle 480 2010 Stall Louisiana  378  76 Gas Combined-cycle 500 2010
SWEPCo Turk(e)Arkansas  1,300(e) 206 Coal Ultra-supercritical 600(e)2011 Turk(e)Arkansas  1,522(e) 313 Coal Ultra-supercritical 600(e)2012
APCo Mountaineer West Virginia  2,230  - Coal IGCC 629 2012 Mountaineer West Virginia  2,230  - Coal IGCC 629 2012
CSPCo/OPCo Great Bend Ohio  2,230(f) - Coal IGCC 629 2017 Great Bend Ohio  2,700(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.Amount includes AFUDC.
(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 plantSouthwestern Units were placed in service at the time these units are placed in service.on February 29, 2008.
(d)In September 2007, AEGCo purchased the under-constructionpartially completed Dresden plant from Dresden Energy LLC, a subsidiary of Dominion Resources, Inc., for $85 million, which is included in the “Total Projected Cost” section above.
(e)SWEPCo plans to own approximately 73%, or 438440 MW, totaling about $950$1,110 million in capital investment.  The increase in the cost estimate relates to cost escalations due to the delay in receipt of permits and approvals.  See “Turk Plant” section below.
(f)Front-end engineering and design study is complete.  Cost estimates, updated to reflect cost escalations due to revised commercial operation date of 2017, 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.PUCO.  See “Ohio IGCC Plant” section below.of Note 3.

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 CreekTurk 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 twelve months effective July 1, 2006.  Through September 30, 2007, CSPCo and OPCo each recorded pre-construction IGCC regulatory assets of $10 million and each collected the entire $12 million approved by the PUCO.  As of September 30, 2007, CSPCo and OPCo have recorded a liability of $2 million each for the 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 Phase 1 costs collected for pre-construction costs, associated with items that may be utilized in projects at other sites, must be refunded to Ohio ratepayers with interest.  The PUCO deferred ruling on cost recovery for Phases 2 and 3 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 pre-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 1 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 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 be re-considering various alternative options to meet its capacity needs in the future.

Turk Plant

In August 2006, SWEPCo announced plans to build the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas named Turk Plant.Arkansas.  Ultra-supercritical technology uses higher temperatures and higher pressures to produce electricity more efficiently – thereby using less fuel and providing substantial emissions reductions.  SWEPCo submitted filings with the Arkansas Public Service Commission (APSC) in December 2006 andAPSC, the PUCT and the LPSC in February 2007 to seek approvals to proceed withseeking certification of the plant.  In September 2007, OMPA signed a joint ownership agreement and agreed toSWEPCo will 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.  During 2007, SWEPCo signed joint ownership agreements with the Oklahoma Municipal Power Authority (OMPA), the Arkansas Electric Cooperative Corporation (AECC) and the East Texas Electric Cooperative (ETEC) for the remaining 27% of the Turk facility.  The Turk Plant is estimated to cost $1.3$1.5 billion in total with SWEPCo’s portion estimated to cost $950 million,$1.1 billion, excluding AFUDC.  If approved on a timely basis, the plant is expected to be in-service in mid-2011.2012.  As of September 2007,March 31, 2008, if the plant were to be cancelled then including the joint owners’ share, SWEPCo incurred and capitalized approximately $206$313 million of expenditures and has significant contractual construction commitments for an additional $875$838 million.  IfAs of March 31, 2008, if the Turk Plant is not approved,plant were to be cancelled, then cancellation fees may be required toof $67 million would terminate SWEPCo’s commitment.these construction commitments.

In AugustNovember 2007, hearings began before the APSC seeking pre-approvalgranted approval to build the plant.  Certain landowners filed a notice of appeal to the Arkansas State Court of Appeals.  SWEPCo is still awaiting permit approvals from the Arkansas Department of Environmental Quality and the U.S. Army Corps of Engineers.  Both permits are expected to be received by the third quarter of 2008.  The PUCT held hearings in October 2007.  In January 2008, a Texas ALJ issued a report, which concluded that SWEPCo failed to prove there was a need for 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 staffTexas ALJ recommended that SWEPCo’s application be denied suggestingdenied.  The PUCT has voted to reopen the constructionrecord and conduct additional hearings.  SWEPCo expects a decision from the PUCT in the last half of 2008.  In March 2008, the LPSC approved the certificate to construct 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.Plant.  If SWEPCo isdoes not authorizedreceive appropriate authorizations and permits to build the Turk plant,Plant, SWEPCo could incur significant cancellation fees to terminate its commitments and would be responsible to reimburse OMPA, AECC and ETEC for their share of paid costs.  If that occurred, SWEPCo would seek recovery of incurred costs including any cancellation fees.  If SWEPCo cannot recover incurredits capitalized costs including any cancellation fees and joint owner reimbursements.  If SWEPCo cannot recover its costs, it could adversely affecthave an adverse effect on future results of operations, cash flows and possibly financial condition.

Electric Transmission Texas LLC Joint Venture (Utility Operations segment)APCo’s IGCC Plant

In January 2007, we signed2006, APCo filed a participation agreement with MidAmerican Energy Holdings Company (MidAmerican) to form a joint venture company, Electric Transmission Texas, LLC (ETT), to fund, own and operate electric transmission assets in ERCOT.  ETT filedpetition with the PUCT in January 2007WVPSC 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 PUCTits approval of initial rates based on an 11.25%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 June 2007, APCo filed testimony with the WVPSC supporting the requests for a CCN and for pre-approval of a surcharge rate mechanism to provide for the timely recovery of both pre-construction costs and the ongoing finance costs of the project during the construction period as well as the capital costs, operating costs and a return on equity.  A hearing was held inequity once the facility is placed into commercial operation.  In July 2007.  On October 31, 2007, APCo filed a request with the PUCT issued an order approvingVirginia SCC for a rate adjustment clause to recover pre-construction and future construction financing costs associated with the transactionIGCC plant.

In March 2008, the WVPSC granted APCo the CCN to build the plant and initial rates based on  9.96% return on equity.  ETT and MidAmerican are reviewingthe request for cost recovery.  Various intervenors filed petitions with the WVPSC to reconsider the order.

In February 2007, TCC also made a regulatory filing at the FERC regarding the transfer of 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 financial 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 PUCTThe Virginia SCC issued an interim order in August 2007.  In that order, the PUCT directed ERCOT to perform studies by April 2008 denying APCo’s requests on the basis of their belief that determine the necessary transmission upgrades to accommodate between 10,000 and 22,800 MW of wind development from CREZs acrossestimated cost may be significantly understated.  The Virginia SCC also expressed concern that 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 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 Amos-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 occur in 2008.

The total$2.2 billion estimated cost of the Amos-to-Kemptown Line is estimated to be approximately $1.8 billionIGCC plant did not include a retrofitting of carbon capture and AEP’s estimated sharesequestration facilities.  In April 2008, APCo filed a petition for reconsideration  in Virginia.  If necessary, APCo will be approximately $600seek recovery of its prudently incurred deferred pre-construction costs.

Through March 31, 2008, APCo deferred for future recovery pre-construction IGCC costs of $16 million.  The PATH companies willIf these deferred costs are not be consolidated with AEP for financial or tax reporting purposes.recoverable, it would have an adverse effect on future results of operations and cash flows.

Litigation

In the ordinary course of business, we, andalong with our subsidiaries, are involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome 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 if the loss amount can be estimated.  For details on our 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 20062007 Annual Report.  Additionally, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies included herein.  Adverse results in these proceedings have the potential to materially affect our results of operations.

Environmental Litigation

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

In 2007, the AEP System settled their complaints under a consent decree.  Litigation continues against two plants CSPCo jointly-owns with Duke and DP&L, which they operate.  We are unable to predict the outcome of these cases.  We believe we can recover any capital and operating costs of additional pollution control equipment that may be required through future regulated rates or market prices for electricity.  If we are unable to recover such costs or if material penalties are imposed, it would adversely affect future results of operations and cash flows and financial condition of AEP and its subsidiaries.flows.

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)CAA to reduce emissions of sulfur dioxide (SOSO2), nitrogen oxide (NONOx), 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 (COCO2)and other greenhouse gases (GHG) emissions to address concerns about global climate change.  All of these matters are discussed in the “Environmental Matters” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 20062007 Annual Report.

Environmental Litigation

New Source Review (NSR) Litigation:  In 1999, the Federal EPA, a number of states and certain special interest groups filed complaints alleging that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities including 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.  In April 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 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, 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 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.

Under the consent decree, we 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.  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 predict the outcome of these cases.   We believe we can recover any capital and operating costs of additional pollution control equipment that may be required through regulated rates or 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 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.  We expected additional capital and operating expenses, which the Federal EPA estimated could be $193 million for our plants.  We undertook site-specific studies and have been evaluating site-specific compliance or mitigation measures that could significantly change these cost estimates.

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 seeksought further review orand filed for relief from the schedules included in our permits.

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

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 20062007 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

In September 2006, the FASB issued SFAS 157 “Fair Value Measurements” (SFAS 157), enhancing existing guidance for fair value measurement of assets and liabilities and instruments measured at fair value that are classified in shareholders’ equity.  The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures.  It emphasizes that fair value is market-based with the highest measurement hierarchy level being market prices in active markets.  The standard requires fair value measurements be disclosed by hierarchy level, an entity include its own credit standing in the measurement of its liabilities and modifies the transaction price presumption.  The standard also nullifies the consensus reached in EITF Issue No. 02-3 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3) that prohibited the recognition of trading gains or losses at the inception of a derivative contract, unless the fair value of such derivative is supported by observable market data.  In February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-1 “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” which amends SFAS 157 to exclude SFAS 13 “Accounting for Leases” and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under SFAS 13.  In February 2008, the FASB issued FSP FAS 157-2 “Effective Date of FASB Statement No. 157” which delays the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The provisions of SFAS 157 are applied prospectively, except for a) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF 02-3, b) existing hybrid financial instruments measured initially at fair value using the transaction price and c) blockage discount factors.  Although the statement is applied prospectively upon adoption, in accordance with the provisions of SFAS 157 related to EITF 02-3, we recorded an immaterial transition adjustment to beginning retained earnings.  The impact of considering our own credit risk when measuring the fair value of liabilities, including derivatives, had an immaterial impact on fair value measurements upon adoption.  We partially adopted SFAS 157 effective January 1, 2008.  We will fully adopt SFAS 157 effective January 1, 2009 for items within the scope of FSP FAS 157-2.  See “SFAS 157 “Fair Value Measurements” (SFAS 157)” section of Note 2.

FIN 48 clarifiesIn February 2007, the accountingFASB issued SFAS 159 “The Fair Value Option for uncertainty in income taxes recognized in an enterprise’sFinancial Assets and Financial Liabilities” (SFAS 159), permitting entities to choose to measure many financial statements by prescribing a recognition threshold (whether a tax positioninstruments and certain other items at fair value.  The standard also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities.  If the fair value option is more likely than not to be sustained) without which,elected, 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 bethe first remeasurement to fair value is reported and disclosed as ana cumulative effect adjustment to the opening balance of retained earnings for that fiscal year and presented separately.earnings.  The statement is applied prospectively upon adoption.  We adopted FIN 48SFAS 159 effective January 1, 2007.  The2008.  At adoption, we did not elect the fair value option for any assets or liabilities.

In March 2007, the FASB ratified EITF Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements” (EITF 06-10), a consensus on collateral assignment split-dollar life insurance arrangements in which an employee owns and controls the insurance policy.  Under EITF 06-10, an employer should recognize a liability for the postretirement benefit related to a collateral assignment split-dollar life insurance arrangement in accordance with SFAS 106 “Employers' Accounting for Postretirement Benefits Other Than Pension” or Accounting Principles Board Opinion No. 12 “Omnibus Opinion – 1967” if the employer has agreed to maintain a life insurance policy during the employee's retirement or to provide the employee with a death benefit based on a substantive arrangement with the employee.  In addition, an employer should recognize and measure an asset based on the nature and substance of the collateral assignment split-dollar life insurance arrangement.  EITF 06-10 requires recognition of the effects of its application as either (a) a change in accounting principle through a cumulative effect of this interpretation on our financial statements was an unfavorable adjustment to retained earnings or other components of $17 million.  See “FIN 48equity or net assets in the statement of financial position at the beginning of the year of adoption or (b) a change in accounting principle through retrospective application to all prior periods.  We adopted EITF 06-10 effective January 1, 2008 with a cumulative effect reduction of $10 million (net of tax of $6 million) to beginning retained earnings.

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


In April 2007, the FASB issued FASB Staff Position FIN 48-1 “Definition39-1 “Amendment ofSettlement in FASB Interpretation No. 48”39” (FIN 39-1).  It amends FASB Interpretation No. 39 “Offsetting of Amounts Related to Certain Contracts” by replacing the interpretation’s definition of contracts with the definition of derivative instruments per SFAS 133.  It also requires entities that offset fair values of derivatives with the same party under a netting agreement to net the fair values (or approximate fair values) of related cash collateral.  The entities must disclose whether or not they offset fair values of derivatives and related cash collateral and amounts recognized for cash collateral payables and receivables at the end of each reporting period. We adopted FIN 39-1 effective January 1, 2008.  This standard changed our method of netting certain balance sheet amounts and reduced assets and liabilities.  It requires retrospective application as a change in accounting principle.  Consequently, we reduced total assets and liabilities on  the December 31, 2007 balance sheet by $47 million each.  See “FASB Staff  Position 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1)” section of Note 2 and Note 8 – Income Taxes.2.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

AsOur Utility Operations segment is exposed to certain 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.allowances.  These risks include commodity price risk, interest rate risk and credit risk.  In addition, we may be exposed to foreign currency exchange risk because occasionally we procure various services and materials used in our energy business from foreign suppliers.  These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

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

All Other includes natural gas operations which holds forward natural gas contracts that were not sold with the natural gas pipeline and storage assets.  These contracts are 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 with 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, swapsfinancial forward purchase and other derivative contracts to offset price risk where appropriate.sale contracts.  We engage in risk management of electricity, natural gas, coal, and emissions and to a lesser degree other commodities associated with our energy business.  As a result, we are subject to price risk.  The amount of risk taken is determined by the commercial operations group in accordance with the market risk policy approved by the Finance Committee of our Board of Directors.  Our market risk managementoversight 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.Chief Risk Officer.  When commercial activities exceed predetermined limits, we modify the positions to reduce the risk to be within the limits unless specifically approved by the CORC.

We actively participate in 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 sheetCondensed Consolidated Balance Sheet as of September 30, 2007March 31, 2008 and the reasons for changes in our total MTM value included on our condensed consolidated balance sheetCondensed Consolidated Balance Sheet as compared to December 31, 2006.2007.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
September 30, 2007March 31, 2008
(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
 
Current Assets $233  $47  $62  $342  $9  $351 
Noncurrent Assets  199   63   79   341   6   347 
Total Assets
  432   110   141   683   15   698 
                         
Current Liabilities  (148)  (53)  (64)  (265)  (2)  (267)
Noncurrent Liabilities  (101)  (21)  (85)  (207)  (3)  (210)
Total Liabilities
  (249)  (74)  (149)  (472)  (5)  (477)
                         
Total MTM
   Derivative
   Contract Net
   Assets
   (Liabilities)
 $183  $36  $(8) $211  $10  $221 

  Utility Operations  
Generation and
Marketing
  All Other  
Sub-Total
MTM Risk Management Contracts
  
MTM
of Cash Flow and Fair Value Hedges
  
 
Collateral
Deposits
  Total 
Current Assets $411  $215  $95  $721  $25  $(48) $698 
Noncurrent Assets  199   101   71   371   8   (37)  342 
Total Assets  610   316   166   1,092   33   (85)  1,040 
                             
Current Liabilities  (365)  (231)  (96)  (692)  (82)  94   (680)
Noncurrent Liabilities  (104)  (43)  (77)  (224)  (3)  6   (221)
Total Liabilities  (469)  (274)  (173)  (916)  (85)  100   (901)
                             
Total MTM Derivative Contract Net
  Assets (Liabilities)
 $141  $42  $(7) $176  $(52)    15  $139 

MTM Risk Management Contract Net Assets (Liabilities)
NineThree Months Ended September 30, 2007March 31, 2008
(in millions)
  
Utility Operations
  
Generation
and
Marketing
  
All Other
  
Total
 
Total MTM Risk Management Contract Net Assets   (Liabilities) at December 31, 2006
 $236  $2  $(5) $233 
(Gain) Loss from Contracts Realized/Settled During 
  the Period and Entered in a Prior Period
  (50)  (1)  (2)  (53)
Fair Value of New Contracts at Inception When Entered
  During the Period (a)
  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)
  7   (14)  (1)  (8)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)  (18)  -   -   (18)
Total MTM Risk Management Contract Net Assets 
  (Liabilities) at September 30, 2007
 $183  $36  $(8)  211 
Net Cash Flow and Fair Value Hedge Contracts
              10 
Total MTM Risk Management Contract Net Assets at
  September 30, 2007
             $221 
  Utility Operations  
Generation
and
Marketing
  All Other  Total 
Total MTM Risk Management Contract Net Assets   
   (Liabilities) at December 31, 2007
 $156  $43  $(8) $191 
(Gain) Loss from Contracts Realized/Settled During   
   the Period and Entered in a Prior Period
  (28)  1   -   (27)
Fair Value of New Contracts at Inception When Entered
  During the Period (a)
  1   -   -   1 
Changes in Fair Value Due to Valuation Methodology
  Changes on Forward Contracts (b)
  4   2   1   7 
Changes in Fair Value Due to Market Fluctuations During 
  the Period (c)
  3   (4)  -   (1)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)  5   -   -   5 
Total MTM Risk Management Contract Net Assets         
   (Liabilities) at March 31, 2008
 $141  $42  $(7) $176 
Net Cash Flow and Fair Value Hedge Contracts
              (52)
Collateral Deposits              15 
Ending Net Risk Management Assets at March  31, 2008             $139 

(a)Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term.  The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)Represents the impact of applying AEP’s credit risk when measuring the fair value of derivative liabilities according to SFAS 157.
(c)Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)(d)“ChangesChange 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:presents the maturity, by year, of our net assets/liabilities, to give an indication of when these MTM amounts will settle and generate cash:

·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 September 30, 2007March 31, 2008
(in millions)
  
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 
  
Remainder
2008
  2009  2010  2011  2012  
After
2012 (f)
  Total 
Utility Operations:                     
Level 1 (a) $(6) $(3) $-  $-  $-  $-   (9)
Level 2 (b)  28   43   29   2   1   -   103 
Level 3 (c)  -   4   (7)  -   -   -   (3)
Total  22   44   22   2   1   -   91 
                             
Generation and Marketing:                            
Level 1 (a)  (21)  5   -   -   -   -   (16)
Level 2 (b)  4   (6)  2   3   3   -   6 
Level 3 (c)  -   1   9   9   8   25   52 
Total  (17)  -   11   12   11   25   42 
                             
All Other:                            
Level 1 (a)  -   -   -   -   -   -   - 
Level 2 (b)  (1)  (4)  (4)  2   -   -   (7)
Level 3 (c)  -   -   -   -   -   -   - 
Total  (1)  (4)  (4)  2   -   -   (7)
                             
Total:                            
Level 1 (a)  (27)  2   -   -   -   -   (25)
Level 2 (b)  31   33   27   7   4   -   102 
Level 3 (c) (d)  -   5   2   9   8   25   49 
Total $4  $40  $29  $16  $12  $25  $126 

Dedesignated Risk Management   Contracts (e)  11  14  14  6  5  -  50 
Total MTM Risk Management   Contract Net Assets $15 $54 $43 $22 $17 $25 
 
$
176 

(a)Prices Provided by Other External Sources – OTC Broker Quotes reflectsLevel 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.  Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information obtained from over-the-counter brokers (OTC), industry services, or multiple-party online platforms.on an ongoing basis.
(b)Prices Based on Models and Other Valuation Methods is used in the absence of independent 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 ofLevel 2 inputs are inputs other than quoted 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 valuesincluded within Level 1 that are measured using modelsobservable for the asset or valuation methods other than active quotesliability, either directly or indirectly.  If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability.  Level 2 inputs primarily consist of OTC broker quotes (because ofin moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1, and OTC broker quotes that are corroborated by the lack of such data for all delivery quantities, locations and periods) incorporatesame or similar transactions that have occurred in the modelmarket.
(c)Level 3 inputs are unobservable inputs for the asset or other valuation methods,liability.  Unobservable inputs shall be used to measure fair value to the extent possible, OTC broker quotes and active quotesthat the observable inputs are not available, thereby allowing for deliveriessituations in years andwhich there is little, if any, market activity for the asset or liability at locations for which such quotesthe measurement date.  Level 3 inputs primarily consist of unobservable market data or are available including values determinable by other third party transactions.valued based on models and/or assumptions.
(c)(d)A significant portion of the total volumetric position within the consolidated level 3 balance has been economically hedged.
(e)Dedesignated Risk Management Contracts are contracts that were originally MTM but were subsequently elected as normal under SFAS 133.  At the time of the normal election the MTM value was frozen and no longer fair valued.  This will be amortized within Utility Operations Revenues over the remaining life of the contract.
(f)There is mark-to-market value of $35$25 million in individual periods beyond 2011.  $142012.  $8 million of this mark-to-market value is in 2012,2013, $8 million is in 2013, $7 million is in 2014, $2$3 million is in 2015, $2$3 million is in 2016 and $2$3 million is in 2017.

The determination of the point at which a market is no longer supported 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 September 30, 2007March 31, 2008

Commodity
 
Transaction Class
 
Market/Region
 
Tenor
      
(in Months)
Natural Gas Futures NYMEX / Henry Hub 60
  Physical Forwards Gulf Coast, Texas 1821
  Swaps Northeast,Gas East, Mid-Continent, Gulf Coast, Texas 1821
  Exchange Option Volatility NYMEX / Henry Hub 12
Power Futures AEPPower East -– PJM 2736
  Physical Forwards AEPPower East -– Cinergy 3945
  Physical Forwards AEP -Power East – PJM West 3957
  Physical Forwards Power East – AEP - Dayton (PJM) 3957
  Physical Forwards AEP -Power East – ERCOT 2733
  Physical Forwards AEP -Power East – Entergy 1533
  Physical Forwards Power West Coast– PV, NP15, SP15, MidC, Mead 3957
  Peak Power Volatility (Options)AEP East - Cinergy, PJM 12
Emissions Credits 
SO2, NOx
 3945
Coal Physical Forwards PRB, NYMEX, CSX 3933


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

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

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

We use foreign currency derivatives to lock in prices on certain transactions denominated in foreign currencies where deemed 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, 20062007 to September 30, 2007.March 31, 2008.  The following table also indicates what portion of designated, effective hedges are expected to be reclassified into net income in the next 12 months.  Only contracts designated as cash flow hedges are recorded in AOCI.  Therefore, economic hedge contracts which are not designated as effective cash flow hedges are marked-to-market and are included in the previous risk management tables.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
NineThree Months Ended September 30, 2007March 31, 2008
(in millions)
     
Interest
    
     
Rate and
    
     
Foreign
    
  
Power
  
Currency
  
Total
 
Beginning Balance in AOCI, December 31, 2006
 $17  $(23) $(6)
Changes in Fair Value  4   (2)  2 
Reclassifications from AOCI to Net Income for
  Cash Flow Hedges Settled
  (15)  2   (13)
Ending Balance in AOCI, September 30, 2007
 $6  $(23) $(17)
             
After Tax Portion Expected to be Reclassified 
  to Earnings During Next 12 Months
 $4  $(2) $2 
  Power  
Interest Rate and
Foreign
Currency
  Total 
Beginning Balance in AOCI, December 31, 2007 $(1) $(25) $(26)
Changes in Fair Value  (26)  (6)  (32)
Reclassifications from AOCI for
  Cash Flow Hedges Settled
  2   -   2 
Ending Balance in AOCI, March 31, 2008 $(25) $(31) $(56)
             
After Tax Portion Expected to be Reclassified to   
  Earnings During Next 12 Months
 $(31) $(6) $(37)

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 meetshas met 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/parental/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 September 30, 2007,March 31, 2008, our credit exposure net of credit collateral to sub investment grade counterparties was approximately 4.6%11.8%, expressed in terms of net MTM assets and net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).  As of September 30, 2007,March 31, 2008, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable (in millions, except number of counterparties):

 
Exposure
        
Number of
  
Net Exposure
 
 
Before
        
Counterparties
  
of
 
 
Credit
  
Credit
  
Net
  
>10% of
  
Counterparties
 
Counterparty Credit Quality
 
Collateral
  
Collateral
  
Exposure
  
Net Exposure
  
>10%
  Exposure Before Credit Collateral  Credit Collateral  Net Exposure  
Number of Counterparties >10% of
Net Exposure
  Net Exposure of Counterparties >10% 
Investment Grade $649  $60  $589   -  $-  $659  $75  $584   1  $93 
Split Rating  25   11   14   2   13   15   -   15   4   14 
Noninvestment Grade  24   3   21   2   19   100   47   53   1   48 
No External Ratings:                                        
Internal Investment Grade  68   -   68   1   39   125   -   125   3   95 
Internal Noninvestment Grade  13   2   11   3   8   47   3   44   2   42 
Total as of September 30, 2007
 $779  $76  $703   8  $79 
Total as of March 31, 2008 $946  $125  $821   11  $292 
                                        
Total as of December 31, 2006
 $998  $161  $837   9  $169 
Total as of December 31, 2007 $673  $42  $631   6  $74 


Generation Plant Hedging Information

This table provides information on operating measures regarding the proportion of output of our generation facilities (based on economic availability projections) economically hedged, including both contracts designated as cash flow hedges under SFAS 133 and contracts not designated as cash flow hedges.  This information is forward-looking and provided on a prospective basis through December 31, 2009.2010.  This table is a point-in-time estimate, subject to changes in market conditions and our decisions on how to manage operations and risk.  “Estimated Plant Output Hedged” represents the portion of MWHs of future generation/production, taking into consideration scheduled plant outages, for which we have sales commitments or estimated requirement obligations to customers.

Generation Plant Hedging Information
Estimated Next Three Years
As of September 30, 2007March 31, 2008

 
Remainder
    
 
2007
 
2008
 
2009
Estimated Plant Output Hedged95% 88% 91%
 Remainder    
 2008 2009 2010
Estimated Plant Output Hedged89% 89% 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 September 30, 2007,March 31, 2008, 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

Nine Months Ended
    
Twelve Months Ended
September 30, 2007
    
December 31, 2006
(in millions)
    
(in millions)
End
 
High
 
Average
 
Low
    
End
 
High
 
Average
 
Low
$1 $6 $2 $1    $3 $10 $3 $1
Three Months Ended
March 31, 2008
    
Twelve Months Ended
December 31, 2007
(in millions)    (in millions)
End High Average Low    End High Average Low
$2 $2 $1 $1    $1 $6 $2 $1

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

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

Interest Rate Risk

We utilize a VaRan Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which AEP’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest rate VaR model is based on a Monte Carlo simulationexpense for the next twelve months could exceed expected interest expense with a 95% confidence level and a one-year holding period.one-in-twenty chance of occurrence.  The volatilities and correlations were based on three yearsprimary drivers of daily prices. The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related toEaR are from the existing floating rate debt (including short-term debt) as well as long-term debt with fixed interest rates, was $925 million at September 30, 2007 and $870 million at December 31, 2006.  We would not expect to liquidateissuances in the next twelve months.  The estimated EaR on 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.
was $36 million.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30,March 31, 2008 and 2007 and 2006
(in millions, except per-share amounts and shares outstanding)
(Unaudited)
  
Three Months Ended
 
Nine Months Ended
 
  
2007
 
2006
 
2007
 
2006
 
REVENUES
           
Utility Operations $3,423 $3,478 $9,127 $9,259 
Other  366  116  977  379 
TOTAL
  3,789  3,594  10,104  9,638 
              
EXPENSES
             
Fuel and Other Consumables Used for Electric Generation  1,099  1,113  2,853  2,962 
Purchased Energy for Resale  358  271  895  674 
Other Operation and Maintenance  964  898  2,783  2,615 
Gain on Disposition of Assets, Net  (2) -  (28) (68)
Asset Impairments and Other Related Charges  -  209  -  209 
Depreciation and Amortization  381  382  1,144  1,084 
Taxes Other Than Income Taxes  191  186  565  567 
TOTAL
  2,991  3,059  8,212  8,043 
              
OPERATING INCOME
  798  535  1,892  1,595 
              
Interest and Investment Income  8  22  39  41 
Carrying Costs Income  14  3  38  66 
Allowance For Equity Funds Used During Construction  9  12  23  25 
Gain on Disposition of Equity Investments, Net  -  -  -  3 
              
INTEREST AND OTHER CHARGES
             
Interest Expense  216  174  615  518 
Preferred Stock Dividend Requirements of Subsidiaries  1  1  2  2 
TOTAL
  217  175  617  520 
              
INCOME BEFORE INCOME TAX EXPENSE, MINORITY 
    INTEREST EXPENSE AND EQUITY EARNINGS
  612  397  1,375  1,210 
              
Income Tax Expense  205  133  443  394 
Minority Interest Expense  1  1  3  2 
Equity Earnings of Unconsolidated Subsidiaries  1  2  6  1 
              
INCOME BEFORE DISCONTINUED OPERATIONS AND
    EXTRAORDINARY LOSS
  407  265  935  815 
              
DISCONTINUED OPERATIONS, NET OF TAX
  -  -  2  6 
              
INCOME BEFORE EXTRAORDINARY LOSS
  407  265  937  821 
              
EXTRAORDINARY LOSS, NET OF TAX
  -  -  (79) - 
              
NET INCOME
 $407 $265 $858 $821 
              
WEIGHTED AVERAGE NUMBER OF BASIC
    SHARES OUTSTANDING
  399,222,569  393,913,463  398,412,473  393,763,946 
              
BASIC EARNINGS PER SHARE
             
Income Before Discontinued Operations and Extraordinary Loss $1.02 $0.67 $2.35 $2.07 
Discontinued Operations, Net of Tax  -  -  -  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
 $1.02 $0.67 $2.15 $2.08 
              
WEIGHTED AVERAGE NUMBER OF DILUTED
    SHARES OUTSTANDING
  400,215,911  396,266,250  399,552,630  395,783,241 
              
DILUTED EARNINGS PER SHARE
             
Income Before Discontinued Operations and Extraordinary Loss $1.02 $0.67 $2.34 $2.06 
Discontinued Operations, Net of Tax  -  -  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
 $1.02 $0.67 $2.15 $2.07 
              
CASH DIVIDENDS PAID PER SHARE
 $0.39 $0.37 $1.17 $1.11 

  2008  2007 
REVENUES      
Utility Operations $3,010  $2,886 
Other  457   283 
TOTAL  3,467   3,169 
         
EXPENSES        
Fuel and Other Consumables Used for Electric Generation  980   886 
Purchased Energy for Resale  263   246 
Other Operation and Maintenance  878   938 
Gain on Disposition of Assets, Net  (3)  (23)
Asset Impairments and Other Related Items  (255)  - 
Depreciation and Amortization  363   391 
Taxes Other Than Income Taxes  198   186 
TOTAL  2,424   2,624 
         
OPERATING INCOME  1,043   545 
         
Interest and Investment Income  16   23 
Carrying Costs Income  17   8 
Allowance For Equity Funds Used During Construction  10   8 
         
INTEREST AND OTHER CHARGES        
Interest Expense  220   186 
Preferred Stock Dividend Requirements of Subsidiaries  1   1 
TOTAL  221   187 
         
INCOME BEFORE INCOME TAX EXPENSE, MINORITY
  INTEREST EXPENSE AND EQUITY EARNINGS
  865   397 
         
Income Tax Expense  293   130 
Minority Interest Expense  1   1 
Equity Earnings of Unconsolidated Subsidiaries  2   5 
         
NET INCOME $573  $271 
         
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING  400,797,993   397,314,642 
         
BASIC EARNINGS PER SHARE $1.43  $0.68 
         
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING  402,072,098   398,552,113 
         
DILUTED EARNINGS PER SHARE $1.43  $0.68 
         
CASH DIVIDENDS PAID PER SHARE $0.41  $0.39 

See Condensed Notes to Condensed Consolidated Financial Statements.

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


  
2007
 
2006
 
CURRENT ASSETS
      
Cash and Cash Equivalents $196  $301 
Other Temporary Investments  231   425 
Accounts Receivable:        
  Customers  780   676 
  Accrued Unbilled Revenues  376   350 
  Miscellaneous  87   44 
  Allowance for Uncollectible Accounts  (41)  (30)
  Total Accounts Receivable  1,202   1,040 
Fuel, Materials and Supplies  961   913 
Risk Management Assets  351   680 
Regulatory Asset for Under-Recovered Fuel Costs  23   38 
Margin Deposits  61   120 
Prepayments and Other  86   71 
TOTAL
  3,111   3,588 
         
PROPERTY, PLANT AND EQUIPMENT
        
Electric:        
   Production  19,749   16,787 
   Transmission  7,354   7,018 
   Distribution  11,894   11,338 
Other (including coal mining and nuclear fuel)  3,363   3,405 
Construction Work in Progress  2,809   3,473 
Total
  45,169   42,021 
Accumulated Depreciation and Amortization  16,139   15,240 
TOTAL - NET
  29,030   26,781 
         
OTHER NONCURRENT ASSETS
        
Regulatory Assets  2,365   2,477 
Securitized Transition Assets  2,115   2,158 
Spent Nuclear Fuel and Decommissioning Trusts  1,315   1,248 
Goodwill  76   76 
Long-term Risk Management Assets  347   378 
Employee Benefits and Pension Assets  293   327 
Deferred Charges and Other  804   910 
TOTAL
  7,315   7,574 
         
Assets Held for Sale
  -   44 
         
TOTAL ASSETS
 $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’ EQUITYASSETS
September 30, 2007March 31, 2008 and December 31, 20062007
(in millions)
(Unaudited)


  
2007
 
2006
 
CURRENT LIABILITIES
 
(in millions)
 
Accounts Payable $1,121 $1,360 
Short-term Debt  587  18 
Long-term Debt Due Within One Year  910  1,269 
Risk Management Liabilities  267  541 
Customer Deposits  326  339 
Accrued Taxes  616  781 
Accrued Interest  246  186 
Other  835  962 
TOTAL
  4,908  5,456 
        
NONCURRENT LIABILITIES
       
Long-term Debt  13,866  12,429 
Long-term Risk Management Liabilities  210  260 
Deferred Income Taxes  4,585  4,690 
Regulatory Liabilities and Deferred Investment Tax Credits  2,886  2,910 
Asset Retirement Obligations  1,059  1,023 
Employee Benefits and Pension Obligations  855  823 
Deferred Gain on Sale and Leaseback – Rockport Plant Unit 2  141  148 
Deferred Credits and Other  976  775 
TOTAL
  24,578  23,058 
        
TOTAL LIABILITIES
  29,486  28,514 
        
Cumulative Preferred Stock Not Subject to Mandatory Redemption  61  61 
        
Commitments and Contingencies (Note 4)       
        
COMMON SHAREHOLDERS’ EQUITY
       
Common Stock Par Value $6.50:       
 2007 2006        
Shares Authorized600,000,000 600,000,000        
Shares Issued421,328,600 418,174,728        
(21,499,992 shares were held in treasury at September 30, 2007 and December 31, 2006)  2,739  2,718 
Paid-in Capital  4,328  4,221 
Retained Earnings  3,070  2,696 
Accumulated Other Comprehensive Income (Loss)  (228) (223)
TOTAL
  9,909  9,412 
        
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 $39,456 $37,987 
  2008  2007 
CURRENT ASSETS      
Cash and Cash Equivalents $155  $178 
Other Temporary Investments  339   365 
Accounts Receivable:        
   Customers  662   730 
   Accrued Unbilled Revenues  343   379 
   Miscellaneous  88   60 
   Allowance for Uncollectible Accounts  (43)   (52) 
   Total Accounts Receivable  1,050   1,117 
Fuel, Materials and Supplies  947   967 
Risk Management Assets  698   271 
Margin Deposits  51   47 
Prepayments and Other  121   81 
TOTAL  3,361   3,026 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
  Production  20,502   20,233 
  Transmission  7,498   7,392 
  Distribution  12,217   12,056 
Other (including coal mining and nuclear fuel)  3,472   3,445 
Construction Work in Progress  3,001   3,019 
Total  46,690   46,145 
Accumulated Depreciation and Amortization  16,319   16,275 
TOTAL - NET  30,371   29,870 
         
OTHER NONCURRENT ASSETS        
Regulatory Assets  2,224   2,199 
Securitized Transition Assets  2,109   2,108 
Spent Nuclear Fuel and Decommissioning Trusts  1,324   1,347 
Goodwill  76   76 
Long-term Risk Management Assets  342   319 
Employee Benefits and Pension Assets  484   486 
Deferred Charges and Other  1,026   888 
TOTAL  7,585   7,423 
         
TOTAL ASSETS $41,317  $40,319 

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


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWSBALANCE SHEETS
For the Nine Months Ended September 30,LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2008 and December 31, 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   - 
                      2008 2007 
CURRENT LIABILITIES  (in millions) 
Accounts Payable  $1,176 $1,324 
Short-term Debt   409  660 
Long-term Debt Due Within One Year   931  792 
Risk Management Liabilities   680  240 
Customer Deposits   308  301 
Accrued Taxes   743  601 
Accrued Interest   196  235 
Other   729  1,008 
TOTAL   5,172  5,161 
         
NONCURRENT LIABILITIES        
Long-term Debt   14,705  14,202 
Long-term Risk Management Liabilities   221  188 
Deferred Income Taxes   4,854  4,730 
Regulatory Liabilities and Deferred Investment Tax Credits   2,883  2,952 
Asset Retirement Obligations   1,071  1,075 
Employee Benefits and Pension Obligations   703  712 
Deferred Gain on Sale and Leaseback – Rockport Plant Unit 2   136  139 
Deferred Credits and Other   1,022  1,020 
TOTAL   25,595  25,018 
         
TOTAL LIABILITIES   30,767  30,179 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption   61  61 
         
Commitments and Contingencies (Note 4)        
         
COMMON SHAREHOLDERS’ EQUITY        
Common Stock Par Value $6.50 Per Share:        
 2008 2007         
Shares Authorized600,000,000 600,000,000         
Shares Issued423,005,402 421,926,696         
(21,499,992 shares were held in treasury at March 31, 2008 and December 31, 2007,   respectively)   2,750  2,743 
Paid-in Capital   4,391  4,352 
Retained Earnings   3,535  3,138 
Accumulated Other Comprehensive Income (Loss)   (187) (154)
TOTAL   10,489  10,079 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY  $41,317 $40,319 

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


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2008 and 2007
(in millions)
(Unaudited)


  2008  2007 
OPERATING ACTIVITIES      
Net Income $573  $271 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
Depreciation and Amortization  363   391 
Deferred Income Taxes  111   5 
Deferred Investment Tax Credits  (5)  (6) 
Carrying Costs Income  (17)  (8) 
Allowance for Equity Funds Used During Construction  (10)  (8) 
Mark-to-Market of Risk Management Contracts  (26)  21 
Amortization of Nuclear Fuel  22   16 
Deferred Property Taxes  (64)  (67) 
Fuel Over/Under-Recovery, Net  (57)  (62) 
Gain on Sales of Assets and Equity Investments, Net  (3)  (23) 
Change in Other Noncurrent Assets  (119)  52 
Change in Other Noncurrent Liabilities  (66)  16 
Changes in Certain Components of Working Capital:        
    Accounts Receivable, Net  61   (29) 
    Fuel, Materials and Supplies  20   (3) 
    Margin Deposits  (4)  19 
    Accounts Payable  (7)  (31) 
    Customer Deposits  6   (8) 
    Accrued Taxes  149   32 
    Accrued Interest  (44)  25 
    Other Current Assets  (21)  (40) 
    Other Current Liabilities  (234)  (212) 
Net Cash Flows from Operating Activities  628   351 
         
INVESTING ACTIVITIES        
Construction Expenditures  (778)  (907) 
Change in Other Temporary Investments, Net  (26)  (20) 
Purchases of Investment Securities  (491)  (3,693) 
Sales of Investment Securities  500   3,929 
Proceeds from Sales of Assets  18   68 
Other  (117)  (5) 
Net Cash Flows Used for Investing Activities  (894)  (628) 
         
FINANCING ACTIVITIES        
Issuance of Common Stock  45   54 
Change in Short-term Debt, Net  (251)  157 
Issuance of Long-term Debt  916   247 
Retirement of Long-term Debt  (289)  (49) 
Dividends Paid on Common Stock  (165)  (155) 
Other  (13)  (19) 
Net Cash Flows from Financing Activities  243   235 
         
Net Decrease in Cash and Cash Equivalents  (23)  (42) 
Cash and Cash Equivalents at Beginning of Period  178   301 
Cash and Cash Equivalents at End of Period $155  $259 
         
SUPPLEMENTARY INFORMATION        
Cash Paid for Interest, Net of Capitalized Amounts $252  $152 
Net Cash Paid for Income Taxes  36   66 
Noncash Acquisitions Under Capital Leases  19   11 
Noncash Acquisition of Land/Mineral Rights  42   - 
Construction Expenditures Included in Accounts Payable at March 31,  284   323 

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 NineThree Months Ended September 30,March 31, 2008 and 2007 and 2006
(in millions)
(Unaudited)

  Common Stock             
  Shares  Amount  
Paid-in
Capital
  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
                   
DECEMBER 31, 2006  418  $2,718  $4,221  $2,696  $(223) $9,412 
                         
FIN 48 Adoption, Net of Tax              (17)      (17)
Issuance of Common Stock  2   10   44           54 
Common Stock Dividends              (155)      (155)
Other          5           5 
TOTAL                      9,299 
                         
COMPREHENSIVE INCOME                        
Other Comprehensive Loss, Net of
  Tax:
                        
Cash Flow Hedges, Net of Tax of $12                  (22)  (22)
Securities Available for Sale, Net of Tax
 of $4
                  (8)  (8)
NET INCOME              271       271 
TOTAL COMPREHENSIVE
  INCOME
                      241 
MARCH 31, 2007  420  $2,728  $4,270  $2,795  $(253) $9,540 
                         
DECEMBER 31, 2007  422  $2,743  $4,352  $3,138  $(154) $10,079 
EITF 06-10 Adoption, Net of Tax of $6              (10)      (10)
SFAS 157 Adoption, Net of Tax of $0              (1)      (1)
Issuance of Common Stock  1   7   38           45 
Common Stock Dividends              (165)      (165)
Other          1           1 
TOTAL                      9,949 
                         
COMPREHENSIVE INCOME                        
Other Comprehensive Income (Loss),
  Net of Tax:
                        
Cash Flow Hedges, Net of Tax of $17                  (30)  (30)
Securities Available for Sale, Net of Tax
 of $3
                  (6)  (6)
Amortization of Pension and OPEB
 Deferred Costs, Net of Tax of $2
                  3   3 
NET INCOME              573       573 
TOTAL COMPREHENSIVE
  INCOME
                      540 
MARCH 31, 2008  423  $2,750  $4,391  $3,535  $(187) $10,489 
 
  
Common Stock
     
Accumulated
   
  
Shares
 
Amount
 
Paid-in Capital
 
Retained
Earnings
 
Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2005
  415 $2,699 $4,131 $2,285 $(27)$9,088 
Issuance of Common Stock  1  5  19        24 
Common Stock Dividends           (437)    (437)
Other        3        3 
TOTAL
                 8,678 
                    
COMPREHENSIVE INCOME
                   
Other Comprehensive Income, Net of Tax:
                   
 Cash Flow Hedges, Net of Tax of $10              18  18 
 Securities Available for Sale, Net of Tax of $4              8  8 
NET INCOME
           821     821 
TOTAL COMPREHENSIVE INCOME
                 847 
SEPTEMBER 30, 2006
  416 $2,704 $4,153 $2,669 $(1)$9,525 
                    
DECEMBER 31, 2006
  418 $2,718 $4,221 $2,696 $(223)$9,412 
FIN 48 Adoption, Net of Tax           (17)    (17)
Issuance of Common Stock  3  21  95        116 
Common Stock Dividends           (467)    (467)
Other        12        12 
TOTAL
                 9,056 
                    
COMPREHENSIVE INCOME
                   
Other Comprehensive Income
    (Loss), Net of Tax:
                   
 Cash Flow Hedges, Net of Tax of $6              (11) (11)
 Securities Available for Sale, Net of Tax of $3              (5) (5)
 
SFAS 158 Costs Established as a Regulatory
  Asset for the Reapplication of SFAS 71, Net
  of Tax of $6
              11  11 
NET INCOME
           858     858 
TOTAL COMPREHENSIVE INCOME
                 853 
SEPTEMBER 30, 2007
  421 $2,739 $4,328 $3,070 $(228)$9,909 
See Condensed Notes to Condensed Consolidated Financial Statements.

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 SaleDispositions
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.
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
SIGNIFICANT ACCOUNTING MATTERS

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

In the opinion of management, the unaudited interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods.  The results of operations for the three or nine months ended September 30, 2007March 31, 2008 are not necessarily indicative of results that may be expected for the year ending December 31, 2007.2008.  The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 20062007 consolidated financial statements and notes thereto, which are included in our Annual Report on Form 10-K for the year ended December 31, 20062007 as filed with the SEC on February 28, 2007.2008.

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:

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

At September 30, 2007, during the next twelve months, we expect to reclassify approximately $2 million of net gains 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.

At September 30, 2007, thirty-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 September 30,
 
  
2007
  
2006
 
  
(in millions, except per share data)
 
     
$/share
     
$/share
 
Earnings Applicable to Common Stock
 $407     $265    
               
Average Number of Basic Shares Outstanding  399.2  $1.02   393.9  $0.67 
Average Dilutive Effect of:                
Performance Share Units  0.5   -   2.0   - 
Stock Options  0.3   -   0.2   - 
Restricted Stock Units  0.1   -   0.1   - 
Restricted Shares  0.1   -   0.1   - 
Average Number of Diluted Shares
  Outstanding
  400.2  $1.02   396.3  $0.67 




 
Nine Months Ended September 30,
  Three Months Ended March 31, 
 
2007
  
2006
  2008  2007 
 
(in millions, except per share data)
  (in millions, except per share data) 
    
$/share
     
$/share
     $/share     $/share 
Earnings Applicable to Common Stock
 $858     $821     $573     $271    
                            
Average Number of Basic Shares Outstanding  398.4  $2.15   393.8  $2.08   400.8  $1.43   397.3  $0.68 
Average Dilutive Effect of:                                
Performance Share Units  0.6   -   1.6   (0.01)  0.9   -   0.6   - 
Stock Options  0.4   -   0.2   -   0.2   -   0.5   - 
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
  399.6  $2.15   395.8  $2.07   402.1  $1.43   398.6  $0.68 

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

Options to purchase 0.1 million146,900 and 0.4 million117,050 shares of common stock were outstanding at September 30,March 31, 2008 and 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 averagequarter-end market price of the common shares for the period and, therefore, the effect would not be dilutive.antidilutive.

Supplementary Information
 
Three Months Ended
  
Nine Months Ended
 
 
September 30,
  
September 30,
  Three Months Ended March 31, 
 
2007
  
2006
  
2007
  
2006
  2008  2007 
Related Party Transactions
 
(in millions)
  
(in millions)
  (in millions) 
AEP Consolidated Purchased Energy:            
AEP Consolidated Revenues – Utility Operations:      
Power Pool Purchases – Ohio Valley Electric Corporation (43.47% owned) $(13) $- 
AEP Consolidated Revenues – Other:        
Ohio Valley Electric Corporation – Barging and Other Transportation Services
(43.47% Owned)
  9   9 
AEP Consolidated Expenses – Purchased Energy for Resale:        
Ohio Valley Electric Corporation (43.47% Owned) $59  $54  $164  $167   63   49 
Sweeny Cogeneration Limited Partnership (a)  27   30   86   92   -   30 
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  See “FASB Staff Position FIN 39-1 Amendment 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.FASB Interpretation No. 39” section of Note 2 for discussion of changes in netting certain balance sheet amounts.  These reclassifications totaled $6 million and $19 million for the three and nine months ended 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 $7 million and $23 million for the three and nine months ended 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

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 20072008 and standards issued but not implemented that we have determined relate to our operations.

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

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

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

SFAS 157 “Fair Value Measurements” (SFAS 157)

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

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

In February 2008, the FASB issued FSP FAS 157-2 “Effective Date of FASB Statement No. 157” which delays the effective for interim and annual periods indate of SFAS 157 to fiscal years beginning after November 15, 2007.  2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).

We expect thatpartially adopted SFAS 157 effective January 1, 2008.  We will fully adopt SFAS 157 effective January 1, 2009 for items within the adoptionscope of this standard will impact MTM valuations of certain contracts.  We are evaluating the effect of the adoptionFSP FAS 157-2.  The provisions of SFAS 157 on our resultsare applied prospectively, except for a) changes in fair value measurements of operationsexisting derivative financial instruments measured initially using the transaction price under EITF 02-3, b) existing hybrid financial instruments measured initially at fair value using the transaction price and financial condition.c) blockage discount factors.  Although the statement is applied prospectively upon adoption, in accordance with the effectprovisions of certain transactions is applied retrospectively as of the beginning of the fiscal year of application, with a cumulative effectSFAS 157 related to EITF 02-3, we recorded an immaterial transition adjustment to beginning retained earnings.  The impact of considering our own credit risk when measuring the appropriate balance sheet items.  Although we have not completed our analysis, we expect this cumulative effect adjustment will havefair value of liabilities, including derivatives, had an immaterial impact on our financial statements.  We will adopt SFAS 157 effective January 1, 2008.fair value measurements upon adoption.

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

As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).

Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.  Level 1 inputs primarily consist of exchange traded contracts, listed equities and U.S. government treasury securities that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 inputs are inputs other than quoted prices included within level 1 that are observable for the asset or liability, either directly or indirectly.  If the asset or liability has a specified (contractual) term, a level 2 input must be observable for substantially the full term of the asset or liability.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in level 1, OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market and certain non-exchange-traded debt securities.

Level 3 inputs are unobservable inputs for the asset or liability.  Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.

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

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2008.  As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of March 31, 2008 
  Level 1  Level 2  Level 3  Other  Total 
Assets: (in millions) 
                
Cash and Cash Equivalents (a) $109  $-  $-  $46  $155 
 
Other Temporary Investments:
                    
Cash and Cash Equivalents (b) $147  $-  $-  $32  $179 
Debt Securities  120   -   22   -   142 
Equity Securities  18   -   -   -   18 
Total Other Temporary Investments $285  $-  $22  $32  $339 
                     
Risk Management Assets:                    
Risk Management Contracts (c) $206  $3,201  $116  $(2,566) $957 
Cash Flow and Fair Value Hedges (c)  -   46   -   (13)  33 
Dedesignated Risk Management Contracts (d)  -   -   -   50   50 
Total Risk Management Assets $206  $3,247  $116  $(2,529) $1,040 
                     
Spent Nuclear Fuel and Decommissioning Trusts:                    
Cash and Cash Equivalents (e) $-  $13  $-  $10  $23 
Debt Securities  343   492   -   -   835 
Equity Securities  466   -   -   -   466 
Total Spent Nuclear Fuel and Decommissioning
  Trusts
 $809  $505  $-  $10  $1,324 
                     
Investments in Debt Securities – Noncurrent (f) $-  $-  $17  $-  $17 
                     
Total Assets $1,409  $3,752  $155  $(2,441) $2,875 
                     
Liabilities:                    
                     
Risk Management Liabilities:                    
Risk Management Contracts (c) $231  $3,099  $67  $(2,581) $816 
Cash Flow and Fair Value Hedges (c)  5   93   -   (13)  85 
Total Risk Management Liabilities $236  $3,192  $67  $(2,594) $901 
                     
Long-term Debt (g) $-  $50  $-  $-  $50 
                     
Total Liabilities $236  $3,242  $67  $(2,594) $951 

(a)Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions.  Level 1 amounts primarily represent investments in money market funds.
(b)Amounts in “Other” column primarily represent cash deposits with third parties.  Level 1 amounts primarily represent investments in money market funds.
(c)Amounts in “Other” column primarily represent counterparty netting of risk management contracts and associated cash collateral under FASB Staff Position FIN 39-1.
(d)“Dedesignated Risk Management Contracts” are contracts that were originally MTM but were subsequently elected as normal under SFAS 133.  At the time of the normal election the MTM value was frozen and no longer fair valued.  This will be amortized into Utility Operations Revenues over the remaining life of the contract.
(e)Amounts in “Other” column primarily represent deposits-in-transit and accrued interest receivables to/from financial institutions.  Level 2 amounts primarily represent investments in money market funds.
(f)“Investments in Debt Securities – Noncurrent” represent investments in auction-rate securities where redemption has not been publicly noticed by the issuer and are included in Deferred Charges and Other on the accompanying Condensed Consolidated Balance Sheets.
(g)Amount represents the fair valued portion of long-term debt designated as a fair value hedge.

The following table sets forth a reconciliation primarily of changes in the fair value of net trading derivatives and other investments classified as level 3 in the fair value hierarchy:

  Net Risk Management Assets (Liabilities)  Other Temporary Investments  Investments in Debt Securities 
  (in millions) 
Balance as of January 1, 2008 $49  $-  $- 
Realized (Gain) Loss Included in Earnings (or Changes in Net Assets) (a)  (3)  -   - 
Unrealized Gain (Loss) Included in Earnings (or Changes in Net Assets)   
  Relating to Assets Still Held at the Reporting Date (a)
  5   -   - 
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income  -   -   - 
Purchases, Issuances and Settlements  -   (96)  - 
Transfers in and/or out of Level 3 (b)  (5)  118   17 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)  3   -   - 
Balance as of March 31, 2008 $49  $22  $17 

(a)Included in revenues on our Condensed Consolidated Statement of Income for the Three Months Ended March 31, 2008.
(b)“Transfers in and/or out of Level 3” represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.
(c)“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected on the Condensed Consolidated Statements of Income.  These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.

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.  IfThe statement is applied prospectively upon adoption.

We adopted SFAS 159 effective January 1, 2008.  At adoption, we did not elect the fair value option promulgatedfor any assets or liabilities.

SFAS 160 “Noncontrolling Interest in Consolidated Financial Statements” (SFAS 160)

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

SFAS 160 is effective for interim and annual periods in fiscal years beginning after December 15, 2008.  The statement is applied prospectively upon adoption.  WeEarly adoption is prohibited.  Upon adoption, prior period financial statements will adopt SFAS 159 effective January 1, 2008.be restated for the presentation of the noncontrolling interest for comparability.  Although we have not completed our analysis, we expect that the adoption of this standard towill have an immaterial impact on our financial statements.  We will adopt SFAS 160 effective January 1, 2009.

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

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

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

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

In March 2007, the FASB ratified EITF 06-10, a consensus on collateral assignment split-dollar life insurance arrangements in which an employee owns and controls the insurance policy.  Under EITF 06-10, an employer should recognize a liability for the postretirement benefit related to a collateral assignment split-dollar life insurance arrangement in accordance with SFAS 106 “Employers' Accounting for Postretirement Benefits Other Than Pension” or Accounting Principles Board Opinion No. 12 “Omnibus Opinion – 1967” if the employer has agreed to maintain a life insurance policy during the employee's retirement or to provide the employee with a death benefit based on a substantive arrangement with the employee.  In addition, an employer should recognize and measure an asset based on the nature and substance of the collateral assignment split-dollar life insurance arrangement.  EITF 06-10 requires recognition of the effects of its application as either (a) a change in accounting principle through a cumulative effect adjustment to retained earnings or other components of equity or net assets in the statement of financial position at the beginning of the year of adoption or (b) a change in accounting principle through retrospective application to all prior periods.  We adopted EITF 06-10 effective January 1, 2008 with a cumulative effect reduction of $10 million (net of tax of $6 million) to beginning retained earnings.

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

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

We adopted EITF 06-11 will beeffective January 1, 2008.  EITF 06-11 is applied prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years beginning after September 15, 2007.  We expect that theThe adoption of this standard will havehad 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 of Settlement in FASB
   Interpretation No. 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.

We adopted FIN 39-1 is effective for fiscal years beginning after November 15, 2007.  We expect thisJanuary 1, 2008.  This standard to changechanged our method of netting certain balance sheet amounts but are unable to quantify the effect.and reduced assets and liabilities.  It requires retrospective application as a change in accounting principle for all periods presented.  We will adopt FIN 39-1 effective January 1, 2008.principle.  Consequently, we reclassified the following amounts on the December 31, 2007 Condensed Consolidated Balance Sheet as shown:

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

For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the March 31, 2008 balance sheet, we netted $85 million of cash collateral received from third parties against short-term and long-term risk management assets and $100 million of cash collateral paid to third parties against short-term and long-term risk management liabilities.

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued by the FASB, we cannot determine the impact on the reporting of our operations and financial position that may result from any such future changes.  The FASB is currently working on several projects including 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.

3.
RATE MATTERS

As discussed in our 2006the 2007 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within our 20062007 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 20072008 and updates the 20062007 Annual Report.

Ohio Rate Matters

Ohio Restructuring and Rate Stabilization Plans

Ending December 31, 2008, the approved three-year RSPs provideThe current Ohio restructuring legislation permits CSPCo and OPCo increases into implement market-based rates effective January 2009, following the expiration of their RSPs on December 31, 2008.  The RSP plans include generation rates which are between PUCO approved rates and higher market rates.  In April 2008, the Ohio legislature passed legislation which allows utilities to set prices by 3%filing an Electric Security Plan along with the ability to simultaneously file a Market Rate Option.  The PUCO would have authority to approve or modify the utility’s request to set prices.  Both alternatives would involve earnings tests monitored by the PUCO.  The legislation still must be signed by the Ohio governor and 7%, respectively, effective January 1 each yearwill become law 90 days after the governor’s signature.  Management is analyzing the financial statement implications of the pending legislation on CSPCo’s and allow possible additional annualOPCo’s generation rate increasessupply business, more specifically, whether the fuel management operations of up to an average of 4% per year to recover governmentally-mandated costs.  In January 2007, CSPCo and OPCo filed withmeet the criteria for application of SFAS 71.    The financial statement impact of the pending legislation will not be known until the PUCO pursuantacts on specific proposals made by CSPCo and OPCo.  Management expects a PUCO decision in the fourth quarter of 2008.

2008 Generation Rider and Transmission Rider Rate Settlement

On January 30, 2008, the PUCO approved under the RSPs a settlement agreement, among CSPCo, OPCo and other parties, related to thean additional average 4% generation rate provisionincrease and transmission cost recovery rider (“TCRR”) adjustments to recover additional governmentally-mandated costs including increased environmental costs.  Under the settlement, the PUCO also approved recovery through the TCRR of their RSPsincreased PJM costs associated with transmission line losses of $39 million each for CSPCo and OPCo.  As a result, CSPCo and OPCo established regulatory assets in the first quarter of 2008 of $12 million and $14 million, respectively, related to increase their annual generation ratesincreased PJM costs from June 2007 to December 2007.  The PUCO also approved a credit applied to the TCRR of $10 million for 2007 by $24 millionOPCo and $8 million respectively, to recover new governmentally-mandatedfor CSPCo for a reduction in PJM net congestion costs.  To the extent that collections for the TCRR items are over/under actual net costs, CSPCo and OPCo implemented these proposed increases in May 2007 subjectwill adjust billings to refund.  In October 2007,reflect actual costs including carrying costs.  Under the PUCO issued an order interms of 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 consistentsettlement, although the increased PJM costs associated with the rate revenues granted by the PUCO.  Management expects that the average 4% ridertransmission line losses will be reducedrecovered through the TCRR, these recoveries will still be applied to implementreduce the required refunds, while OPCo would implement a credit to customers’ bills.  CSPCo and OPCo intend to seek rehearing of the PUCO decision.

In October 2007, CSPCo and OPCo made a new filing with the PUCO pursuant to theannual average 4% generation rate provision of their RSPs for an additional increase in their annuallimitation.  In addition, the PUCO approved recoveries through generation rates effectiveof environmental costs and related carrying costs of $29 million for CSPCo and $5 million for OPCo.  These rate adjustments were implemented in February 2008.

In February 2008, Ormet, a major industrial customer, filed a motion to intervene and an application for rehearing of the PUCO’s January 2008 of $35RSP order claiming the settlement inappropriately shifted $4 million and $12 million, respectively,in cost recovery to recover governmentally-mandated costs and increased costs related to marginal-loss pricing.  CSPCo and OPCo will implement these proposed increases in JanuaryOrmet.  In March 2008, subject to refund until the PUCO granted Ormet’s motion to intervene.  Ormet’s rehearing application also was granted for the purpose of providing the PUCO with additional time to consider the issues a final order in the matter.raised by Ormet.  Management is unable tocannot predict the outcome of this filing and its impact on future results of operations and cash flows.matter.

In March 2007, CSPCo filed an application under the average 4% generation rate provision of their RSP to adjust the Power Acquisition Rider (PAR) related to CSPCo's acquisition of Monongahela Power Company's certified territory in Ohio. The PAR was increased to recover the cost of a new purchase power market contract to serve the load for that service territory.  The PUCO approved the requested increase in the PAR, which is expected to increase CSPCo's revenues 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 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.  The Office of Consumers’ Counsel, the Ohio Partners for Affordable Energy, the Ohio Energy Group and the PUCO staff supported this settlement agreement.  In May 2007, the PUCO adopted the settlement agreement in its entirety.

Customer Choice Deferrals

CSPCo’s and OPCo’s restructuring settlement agreement, approved by the PUCO in 2000, allows CSPCo and OPCo to 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 changesfor the distribution rates.business.  Through September 30, 2007,March 31, 2008, CSPCo and OPCo incurred $53$54 million and $54$55 million, respectively, of such costs and established regulatory assets for future recovery of $27 million each, for the future recovery of such costs.  CSPCo and OPCo also have the right to recover $6 million and $7 million, respectively,net of equity carrying costs in addition to these regulatory assets.  In 2007,of $7 million for CSPCo and OPCo incurred $3$8 million and $4 million, respectively, of such costs and established regulatory assets of $2 million each for such costs.OPCo.  Management believes that the deferred customer choice implementationthese costs were prudently incurred to implement customer choice in Ohio and are probable of recovery in future distribution rates.  However, failure of the PUCO to recoverultimately approve recovery of 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;costs; Phase 2, concurrent recovery of construction-financing costs; and Phase 3, recovery or refund in distribution rates of any difference between the generation rates which may be a market-based standard service offer price for generation and the expected higher cost of operating and maintaining the plant, including a return on and return of the ultimateprojected 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.plant.

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 anotheran order approving a tariff to recover Phase 1 pre-construction costs over a period of no more than twelve months effective July 1, 2006.  Through September 30, 2007,During that period CSPCo and OPCo each recorded pre-construction IGCC regulatory assets of $10 million and each collected the entire $12 million approved by the PUCO.  As of September 30, 2007, CSPCo and OPCo have recorded a liability of $2 million each for the over-recovered portion.  CSPCo and OPCo expect to incur additionalin pre-construction costs equal to or greater than the $12 million each recovered.  costs.

The PUCO indicatedorder also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant within five years of the June 2006 PUCO order, all Phase 1 costs collected for pre-construction costs associated with items that may be utilized in projects at other sites, must be refunded to Ohio ratepayers with interest.  The PUCO deferred ruling on cost recovery for Phases 2 and 3 untilpending further hearings are held.  A date for further rehearings has not been set.hearings.

In August 2006, the Ohio Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy Solutions and Ohio Energy Groupintervenors filed four separate appeals of the PUCO’s order in the IGCC proceeding.  In March 2008, the Ohio Supreme Court issued its opinion affirming in part, and reversing in part the PUCO’s order and remanded the matter back to the PUCO.  The Ohio Supreme Court heard oral arguments for these appeals in October 2007.  Management believesheld 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 OPCowhile there could be requiredan opportunity under existing law to refund Phase 1 cost-related recoveries.

Pending the outcome of the Supreme Court litigation, CSPCo and OPCo announced they may delay the start of constructionrecover a portion of the IGCC plant. costs, traditional rate making procedures would apply.  The Ohio Supreme Court did not address the matter of refunding the Phase 1 cost recovery and declined to create an exception to its precedent of denying claims for refund from approved orders of the PUCO.

Recent estimates of the cost to build anthe proposed IGCC plant have escalated to $2.2are approximately $2.7 billion.  In light of the Ohio Supreme Court’s decision, CSPCo and OPCo may needwill not start construction of the IGCC plant and will await the outcome of the ongoing legislative process in Ohio to request an extensiondetermine if it provides sufficient assurance of cost recovery to the 5-year start of construction requirement if the commencement of construction is delayed beyond 2011.warrant commencing construction.

Distribution Reliability Plan

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-month period beginning July 2007.

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, in accordance with a settlement agreement between CSPCo and OPCo, Ormet, its employees’ union and certain other interested parties that was approved by the PUCO in November 2006.PUCO.  The settlement agreement providesallows for the recovery in 2007 and 2008 by CSPCo and OPCo of the difference between the $43 per MWH to be paid by Ormet pays for power and a PUCO-approved market price, if higher.  The PUCO approved a $47.69 per MWH market price for 2007.  The recovery will be accomplished by the amortization of a $57 million ($15 million for CSPCo and $42 million for OPCo) excess deferred tax regulatory liability resulting from an Ohio franchise tax phase-out regulatory liability recorded in 2005 and, if that is insufficient, an increase in RSP generation rates under the additional average 4% generation rate provision of the RSPs.2005.

CSPCo and OPCo each amortized $2 million of this regulatory liability to income for the quarter ended March 31, 2008 based on the previously approved 2007 price of $47.69 per MWH.  In December 2006,2007, CSPCo and OPCo submitted for approval a market price of $47.69$53.03 per MWH for 2007, which was approved by the PUCO 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, 2007.2008.  If the PUCO approves a lower market price infor 2008 below the 2007 price, 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.sales.

Texas Rate Matters

TCC TEXAS RESTRUCTURING

Texas District Court Appeal Proceedings

TCC recoveredTexas Restructuring Appeals

Pursuant to PUCT orders, TCC securitized its net recoverable stranded generation costs throughof $2.5 billion and is recovering such costs over a securitization financing andperiod ending in 2020.  TCC is also refunding its net other true-up items of $375 million through 2008 via a CTC credit rate rider credit under 2006 PUCT orders.rider.  TCC appealed the PUCT stranded costs true-up and related orders seeking relief in both state and federal court on the grounds that certain aspects of the orders are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law and fail to fully compensate TCC for its net stranded cost and other true-up items.  The significant items appealed by TCC are:

·The PUCT ruling that TCC did not comply with the Texas Restructuring Legislation and PUCT rules regarding the required auction of 15% of its Texas jurisdictional installed capacity, which led to a significant disallowance of capacity auction true-up revenues,revenues.
·The PUCT ruling that TCC acted in a manner that was commercially unreasonable, because TCC failed to determine a minimum price at which it would reject bids for the sale of its nuclear generating plant and itTCC bundled out-of-the-money gas units with the sale of its coal unit, which led to the disallowance of a significant portion of TCC’s net stranded generation plant costs, andcosts.
·The two federal matters regarding the allocation of off-system sales related to fuel recoveries and thea potential tax normalization violation.  See “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.  In March 2007, the Texas District Court judge hearing the appeal 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 by applying an invalid rule to determine the carrying cost rate for the true-up of stranded costs.costs and remanded this matter to the PUCT for further consideration.  However, the District Court did not rule that the carrying cost rate was inappropriate.  If the District Court’s ruling onPUCT reevaluates the carrying cost rate is ultimately upheld on appealremand and remanded to the PUCT for reconsideration, the PUCT could either confirm the existing weighted average carrying cost (WACC) rate or determine a new rate.  If the PUCT reduces 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 that 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 true-up order rulingsdecision to the Texas Court of Appeals.  Management cannot predict the outcome of these true-up and relatedcourt 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 TCC’s stranded generation costs and the amount to be securitized by $51 millionAppeals remain outstanding related to the present value of ADITCstranded costs true-up and by $10 million of EDFIT associated with TCC’s generation assets for a total reduction of $61 million.  The reductions were ordered afterrelated orders regarding whether the PUCT concluded such reductions would not represent a violationmay require TCC to refund certain tax benefits to customers. The PUCT requested that the Texas Court of Appeals remand the Internal Revenue Codetax normalization requirements.

TCC filed a requestissue 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.PUCT to consider additional evidence. The IRS issued its private letter ruling in May 2006, which stated 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 CTCa $103 million refund totaling $103 millionto customers ($61 million in present value of ADITC and EDFITthe tax benefits associated with TCC’s generation assets plus $42 million of related carrying costs) pending resolution of whether the PUCT’s proposed refund is an IRS normalization issue. If it is ultimately determinedviolation.

The IRS issued final regulations on March 20, 2008 addressing Accumulated Deferred Investment Tax Credit (ADITC) and Excess Deferred Federal Income Tax (EDFIT) normalization requirements. Consistent with the Private Letter Ruling TCC received in 2006, the regulations clearly state that a refund to customers through the true-up process of the ADITC and EDFIT is notTCC will sustain a normalization violation thenif the PUCT orders TCC will be required to refundflow the $103 million, plus additional carrying costs adversely affecting future cash flows.  However, if an ADITC and EDFIT reduction is ultimately determinedtax benefits to cause a normalization violation,customers.  TCC anticipatesnotified the PUCT that the final regulations were issued.  TCC expects that the PUCT will permitallow TCC to retain the $61 million present value of ADITC and EDFIT plus carrying costs, favorably impactingthese amounts, which will have a favorable effect on future results of operations and cash flows.flows as the ADITC and EDFIT are recorded in income due to the sale of the generating plants.

If the PUCT orders TCC to flow the tax benefits to customers, thereby causing TCC to have 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$103 million as of September 30, 2007,March 31, 2008, 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 resolve the issue and avoid a normalization violation that would adversely affect future results of operations and cash flows.violation.

TCC and TNC Deferred Fuel

TCC’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 withand the PUCT seeking to reconcile fuel costs and establish their final deferred fuel balances.  In its final fuel reconciliation orders,have been involved in litigation in the federal courts concerning whether the PUCT ordered substantial reductions in TCC’s and TNC’s recoverable fuel costs for, among other things,has the reallocation of additional AEP System off-system sales marginsright to TCC and TNC under a FERC-approved 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 allocationorder reallocation of off-system sales margins in the federal court.  Intervenors also appealed the PUCT’s finalthereby reducing recoverable fuel rulings in state court seeking to increase the various allowances.

costs.  In 2006, the Federal District Court issued orders precluding2005, TCC and TNC recorded provisions for refunds after the PUCT from enforcingordered such reallocation.  After receipt of favorable federal court decisions and the off-system sales reallocation portionrefusal of its ruling in the final TNC and TCC fuel reconciliation proceedings.  The Federal court ruled, in both cases, that the FERC, not theU.S. Supreme Court to hear a PUCT has jurisdiction over the allocation.  The PUCT appealed both Federal District Court decisions to the United States Courtappeal of Appeals.  The Court of Appeals affirmed the District Court’s decision in the TNC case.  In April 2007, the PUCT petitioned the United States Supreme Court for a review of the Court of Appeals’ order.  In October 2007, the United States Supreme Court denied review of TNC’s case.  As a result,decision, TCC and TNC recorded income of $9 millionreversed their provisions in the third quarter of 2007 by reversing the previously recorded provision resulting from the PUCT’s ordered reallocation of off-system sales margins.  Since it is probable the outcome in the TCC case, still before the U.S. Court of Appeals, will be the same as in the TNC case, TCC also recorded income of $16 million by reversing its provision in the third quarter of 2007.  Based on the TNC case, TCC reduced its deferred fuel regulatory liability by $16and $9 million, in the third quarter of 2007.respectively.

The PUCT or another interested party maycould file a complaint at the FERC to addresschallenge the allocation issue.of off-system sales margins under the FERC-approved allocation agreement.  In December 2007, some cities served by TNC requested the PUCT to initiate, or order TNC to initiate a proceeding at the FERC to determine if TNC misapplied its allocation under the FERC-approved agreement.  In January 2008, TNC filed a response with the PUCT recommending the cities’ request be denied.  Although management cannot predict if a complaint maywill be filed at the FERC, management believes theits allocations used were in accordance with the then-existing FERC-approved SIAallocation agreement and additional off-system sales margins should not be retroactively reallocated to the AEP West companies including TCC and TNC.

TCC Excess Earnings

In 2005, thea Texas Court of Appealsappellate court issued a decision finding that the PUCT’s priora PUCT 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, including interest, under the overturned PUCT order, including interest.order. On remand, the PUCT must determine how to implement the Court of Appeals decision given that the unauthorized refunds were made.made in lieu of reducing stranded cost recoveries in the True-up Proceeding.  As a result, TCC’s stranded cost recovery, which is currently on appeal, may be affected by a PUCT remedy.

In December 2007, the remedy ordered asTexas Court of Appeals issued a result ofdecision in CenterPoint’s, a nonaffiliated Texas utility, true-up proceeding determining that even though excess earnings had been previously refunded to the unauthorized refunds.affiliated REP, CenterPoint still must reduce stranded cost recoveries in its true-up proceeding.  In 2005, managementTCC reflected the obligation to refund excess earnings to customers through the true-up process and recorded a regulatory asset for the expected refund to be received from the REPs, and believes its accounting is correct.REPs. However, certain parties continue to takehave taken positions that, if adopted, could result in TCC being required to payrefund additional amounts of excess earnings or interest which would adversely affect future results of operations and cash flows.  Management cannot predictthrough the outcome of these matters.

TCC Oklaunion Refund

In 2005, TCC filedtrue-up process without receiving 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 to include the net economic benefitrefund back from the operation of the Oklaunion power plant in the CTC credit rider.  As of September 30, 2007, TCC has recorded a $4 million regulatory liability for the net economic benefit relatedREPs. If this were to the operation of the Oklaunion power plant.  Management is unable to predict the ultimate outcome of this filing.  If the PUCT orders a refund greater than the $4 million recorded liability,occur it would have an adverse effect on future results of operations and cash flows.

OTHER TEXAS RATE MATTERS

  AEP sold its affiliate REPs in December 2002.  While AEP owned the affiliate REPs, 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 ratesrefunded $11 million of $81 million and $25 million, respectively.  Both requests included a return on common equity of 11.25% and a favorable impact from an expiration of the CSW merger savings rate credits (merger credits).  In March 2007, various intervenors and the PUCT staff filed their recommendations with increases ranging from $8 million to $30 million for TCC.  The recommended return on common equity ranged from 9.00% to 9.75%.  In April 2007, TCC filed rebuttal testimony reducing its requested increase to $70 million including a reduced requested return on common equity of 10.75%.  In May 2007, TNC reached a settlement agreement for a revenue increase of $14 million including an $8 million increase in base rates and a $6 million increase relatedexcess earnings to the impactaffiliate REPs.  Management cannot predict the outcome of the expiration of the merger credits.  TNC received a final order in May 2007these matters and began billing the increase in June 2007.

Beginning in June 2007, TCC implemented an interim base 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 termination of the merger credits.  In June 2007, the PUCT affirmed 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 expiration of TCC’s merger credits and a return on common equity of 9.96%.  TCC estimates the base rate annual impact of this final orderwhether they 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 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 disallowances ranged from $10 million to $28 million.  In June 2007, an ALJ issued a proposal for decision recommending a $17 million 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 August 2007, the PUCT issued a final order affirming the ALJ report.  In September 2007, SWEPCo filed a motion for rehearing.  In October 2007, the PUCT granted 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 order.

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

Several parties including the Office of Public Utility Counsel and the cities served by both TCC and TNC appealed the PUCT’s December 2001 orders establishing initial PTB fuel factors for Mutual Energy CPL and Mutual 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 TNC’s PTB fuel factor.  The Court of Appeals upheld the District Court regarding the UFE issue.  AEP’s third quarter 2005 pretax earnings were adversely affected by $3 million at 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 a different UFE factor on remand,affect future results of operations, cash flows and financial condition.

OTHER TEXAS RATE MATTERS

Stall Unit

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

Turk Plant

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

Virginia Rate Matters

Virginia Base Rate Filing

In March 2008, APCo filed a notice with the Virginia SCC that it plans to file a general base rate case no sooner than May 2008.  The rate case will be based on a test year ending December 31, 2007, with adjustments through June 2008.

Virginia E&R Costs Recovery Filing

As of March 31, 2008, APCo has $85 million of deferred Virginia incremental E&R costs.  Currently APCo is recovering $26 million of the deferral for incremental costs incurred through September 30, 2006.  APCo intends to file in May 2008 for recovery of deferred incremental E&R costs incurred from October 1, 2006 through December 31, 2007 which totals $46 million.  The remaining deferral will be requested in a 2009 filing.  As of March 31, 2008, APCo has $21 million of unrecorded E&R equity carrying costs of which $7 million should increase 2008 annual earnings as collected.  In connection with the 2009 filing, the Virginia SCC will determine the level of incremental E&R costs being collected in base revenues since October 2006 that APCo has estimated to be $48 million annually.  If the Virginia SCC were to determine that these recovered base revenues are in excess of $48 million a year, it would require that the E&R deferrals be reduced by the excess amount, thus adversely affecting future earnings and cash flowsflows. In addition, if the Virginia SCC were to disallow any additional portion of APCo’s deferral, it would be adversely affected.  Management is unable to predict the outcome of this remand or its impactalso have an adverse affect 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 amended the Virginia Electric Utility Restructuring Act extending the transition period to market rates for the generation and supply of electricity, including the extension of capped rates, through December 31, 2010.  The legislation provided 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 have the opportunity to recover incremental E&R costs.

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.

With the new re-regulation legislation, APCo’s generation business again met the criteria for application of regulatory accounting principles under SFAS 71.  The extraordinary pretax reduction in APCo’s earnings and shareholder’s equity from 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 qualifying SFAS 158 pension costs of the generation operations that, for ratemaking purposes, are deferred for future recovery under the new re-regulation legislation.  AOCI and Deferred Income Taxes increased by $11 million and $6 million, respectively.

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 its active fuel 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 was 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.  In May 2006, the Virginia SCC issued an order placing the net requested base rate increase of $198 million into effect on October 2, 2006, subject to refund.

In May 2007, the Virginia SCC issued a final order approving an overall annual base rate increase of $24 million effective as of October 2006 and approving a return on equity of 10.0%.  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 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

In July 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 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 2008 for 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 $70 million regulatory asset does not include carrying costs on the unrecovered incremental E&R costs and is based on a return on equity rate which approximates the Virginia SCC staff and Attorney General’s recommendations.  As a result, if APCo is awarded only $49 million for the E&R costs incurred for the twelve months ended September 30, 2006 as recommended by the Virginia SCC staff and the Attorney General, it will not have to reverse any of its 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 off-system sales.

In February 2008, the benefits ofVirginia SCC issued an order that approved a reduced fuel factor effective with the February 2008 billing cycle.  The order terminated the off-system sales between APComargin rider and its customers.  This filing was made in compliance with the minimum 25% retentionapproved a 75%-25% sharing of off-system sales margins provision of the new re-regulation legislation which is effective with the first fuel clause 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,between customers and APCo requested authorization to 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.

In August 2007, the Virginia SCC issued a scheduling order that implemented APCo’s proposed termination of its base rate off-system sales margin rider on an interim basis, subject to refund, on 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 foras required by the sharingre-regulation legislation in Virginia.  The order also allows APCo to include in its monthly under/over recovery deferrals the Virginia jurisdictional share of 75% of off-system sales margins with customers in compliance with the new law.  In October 2007, APCo,PJM transmission line loss back to June 1, 2007.  The adjusted factor will increase annual revenues by $4 million.  The order authorized the Virginia SCC staff and certain intervenors filed memorandums addressing legal issues identified byother parties to make specific recommendations to the Virginia SCC regardingin APCo’s next fuel factor proceeding in the appropriatenessfourth quarter of 2008 to ensure accurate assignment of the timingprudently incurred PJM transmission line loss costs to APCo’s Virginia jurisdictional operations.  APCo believes the incurred PJM transmission line loss costs are prudently incurred and are being properly assigned to APCo’s Virginia jurisdictional operations.

In February 2008, the Old Dominion Committee for Fair Utility Rates filed a notice of appeal to the implementationSupreme Court of the new expandedVirginia.

If costs included in APCo’s Virginia fuel factor and off-system sales margins sharing with customers.  Hearingsunder/over recovery deferrals 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 existsdisallowed, it could result in the statute requiring implementation of off-system sales margin sharing any earlier than 2011.  Futurean adverse effect on future results of operations and cash flows could be adversely affected if theflows.

APCo’s Virginia SCC delays the effective date of the new expanded fuel clause beyond APCo’s filed request.

West VirginiaFiling for an IGCC Plant

In July 2007, APCo filed a request with the Virginia SCC for a rate adjustment clause to recover over the twelve months beginning January 1, 2009, a return on projected construction work in progress including development, design and planninginitial costs from July 1, 2007 through December 31, 2009 estimated to be $45 million associated with thea proposed 629 MW IGCC plant to be constructed in Mason County, West Virginia adjacent to APCo’s existing Mountaineer Generating Station for an estimated cost of $2.2 billion.  The filing requests recovery of an estimated $45 million over twelve months beginning January 1, 2009 including a return on projected CWIP and development, design and planning pre-construction costs incurred from July 1, 2007 through December 31, 2009.  APCo is requestingalso requested authorization to defer a return on actualdeferred pre-construction costs incurred beginning July 1, 2007 until such costs are recovered, starting January 1, 2009 in accordance withrecovered.  Through March 31, 2008, APCo has deferred for future recovery pre-construction IGCC costs of $7 million applicable to Virginia.  The rate adjustment clause provisions of the new re-regulation legislation.  The new2007 re-regulation legislation provides for full recovery of all costs plusof this type of new clean coal technology including recovery of an enhanced return on equity incentivesequity.  The Virginia SCC issued an order in April 2008 denying APCo’s requests on the basis of their belief that the estimated cost may be significantly understated.  The Virginia SCC also expressed concern that the $2.2 billion estimated cost did not include a retrofitting of carbon capture and sequestration facilities.  In April 2008, APCo filed a petition for such new capacity oncereconsideration in Virginia.  If necessary, APCo will seek recovery of its prudently incurred deferred pre-construction costs.  If the plant is placed in service.  See “West Virginia IGCC Plant” section within West Virginia Rate Matters.deferred costs are not recoverable, it would have an adverse effect on future results of operations and cash flows.

West Virginia Rate Matters

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

In April 2007,February 2008, APCo and WPCo filed for an increase of approximately $156 million including a $135 million increase in the WVPSC issued an order establishing an investigationENEC itself, a $17 million increase in construction cost surcharges and hearing concerning APCo’s and WPCo’s 2007 ENEC compliance filing.$4 million of reliability expenditures, to become effective July 2008.  The ENEC is an expanded form of fuel clause mechanism, which includes all energy-related costs including fuel, purchased power expenses, off-system sales credits, PJM costs associated with transmission line losses due to the implementation of marginal loss pricing and other energy/transmission items.   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.  In June 2007, the WVPSC 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 subject to a true-up, whichtrue up to actuals and should avoid anhave no earnings affect from an effect due to the deferral of any over/under-recovery of actual ENEC costs.  However, if the WVPSC were to disallow the deferral of any costs if they exceedincluding the $55 million.incremental cost of PJM’s recently revised costs associated with transmission line losses, it would have an adverse affect on future results of operations and cash flows.  An order is expected by June 2008.

APCo’s West Virginia IGCC Plant Filing

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

In June 2007, APCo filed testimony with the WVPSC supporting the requests for a CCN and for pre-approval of a surcharge rate mechanism to provide for the timely recovery of both pre-construction costs and the ongoing finance costs of the project during the construction period as well as the capital costs, operating costs and a return on equity once the facility is placed into commercial operation.  In March 2008, the WVPSC granted APCo the CCN to build the plant and the request for cost recovery.  Various intervenors filed petitions with the WVPSC to reconsider the order.  If APCo receives all necessary approvals, the plant could be completed as early as mid-2012 and currently is expectedmid-2012.  At the time of the filing, the cost of the plant was estimated at $2.2 billion.  The Virginia SCC’s decision to costdeny APCo’s request to build an estimated $2.2 billionIGCC plant may have an impact on the project (See the “APCo’s Virginia SCC Filing for an IGCC Plant” above).  In July 2007, the WVPSC staff and intervenors filed to delay the procedural schedule by 90 days.  APCo supported the changes to the procedural schedule.  The statutory decision deadline was revised toThrough March 2008.  In July 2007, the WVPSC approved the revised procedural schedule.  Through September 30, 2007,31, 2008, APCo deferred for future recovery pre-construction IGCC costs totaling $11 million.of $7 million applicable to the West Virginia jurisdiction and $2 million applicable to the FERC jurisdiction. If the plant is not built and these deferred costs are not recoverable, it would have an adverse effect on future results of operations and cash flows would be adversely affected.flows.

Indiana Rate Matters

Indiana Depreciation StudyRate Filing

In February 2007,January 2008, 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 were 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 were 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.  In June 2007, the IURC approved the settlement agreement, but modified the effective date of the new book depreciation rates 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 for 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 subject to further review in the general rate case.  Management expects newits Indiana base rates will become effective in early 2009.

Indiana Rate Filing

In June 2007, I&M filedof $82 million including a rate notification petition with the IURC regarding its intent to file for areturn on equity of 11.5%.  The base rate increase withincludes a proposed test year ended September 30, 2007.previously approved $69 million annual reduction in depreciation expense. The petition indicated, among other things, the filing would include a request to implement rate tracker mechanismsrequests trackers for certain variable components of the cost of service including recently increased PJM costs associated with transmission line losses due to the implementation of marginal loss pricing and other RTO costs, reliability enhancement costs, demand side management/energy efficiency program costs, off-system sales margins and net environmental compliance costs.  This filing will also reflect the revenue requirement reduction associatedThe trackers would initially increase annual revenues by an additional $46 million.  I&M proposes to share with an annual reduction in book depreciation expense. In August 2007, the IURC approved the September 30, 2007 test year and the inclusionratepayers, through a tracker, 50% of the above trackers in the rate filingoff-system sales margins initially estimated to be $96 million annually with a rate caseguaranteed credit to be filed no later than January 31, 2008.  Management expects to filecustomers of $20 million.  A decision is expected from the case in early 2008 with a decision expectedIURC in early 2009.

IndianaKentucky Rate CapMatters

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 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 through June 30, 2007.  Future results of operations should no longer be adversely impacted by fuel 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 November 2007 and reduce wholesale rates for the remaining customers in June 2008.

Kentucky Rate Matters

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 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 specifically as it relates to the recovery of affiliated AEP Power Pool costs.  In KPCo’s order, the KPSC approved 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 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.  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 County Circuit Court concluded the KPSC did not have the authority to order a surcharge for a gas company subsidiary of Duke Energy absent a full cost of service rate proceeding due to the lack of statutory authority.  The ruling results from the AG’s appeal of the KPSC’s approval of a natural gas distribution surcharge for replacement of gas mains.  The AGKentucky Attorney General (AG) notified the KPSC that the Franklin County Circuit Court judge’s order in the Duke Energy case can be interpreted to include other existing surcharges, rates or fees established outside of the context of a general rate case proceeding and not specifically authorized by statute, including fuel clauses.  The KPSC and Duke Energy are appealingappealed 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 anchallenge KPCo’s existing surcharge KPCo is collecting to the Franklin County Circuit Court.surcharges, which are not specifically authorized by statute.  These include KPCo’s fuel clause surcharge, annual Rockport Plant capacity surcharge, merger surcredit and off-system sales credit system sales rider are not specifically authorized by statute.rider. 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 positionAG stated 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, theThe KPSC issued an order stating despite the Franklin County Circuit Court decision, the KPSCthat it has the authority to provide for surcharges and surcredits at least until athe Court of Appeals ruling.rules.  The appeals process could take up to two years to complete.  In August 2007, theThe AG agreed to stipulate to a stay order over the Franklin County Circuit Court’s decision pending the appeal decision.its challenge during that time.  KPCo’s exposure is indeterminable at this time.time since it is not known whether a final adverse appeal could result in a refund of prior amounts collected, which would have an adverse effect on future results of operations and cash flows.

2008 Fuel Cost Reconciliation

In January 2008, KPCo filed its semi-annual fuel cost reconciliation covering the period May 2007 through October 2007.  As part of this filing, KPCo sought recovery of incremental costs associated with transmission line losses billed by PJM since June 2007 due to the implementation of marginal loss pricing.  KPCo expensed these incremental PJM costs associated with transmission line losses pending a determination that they are recoverable through the Kentucky fuel clause back to June 2007.  If recovery of the appealincremental PJM costs through the fuel clause is unfavorable,denied, future results of operations and cash flows couldwould be adversely affected.  A decision is expected in May 2008.

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 clause 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 2004, an Oklahomaintervenors and the OCC staff argued that AEP had inappropriately under allocated off-system sales credits to PSO by $37 million for the period June 2000 to December 2004 under a FERC-approved allocation agreement.  An ALJ assigned to hear intervenor claims found that the OCC lackslacked authority to examine whether AEP deviated from the FERC-approved allocation methodology for off-system sales margins and held that any such complaints should be addressed at the FERC.  In 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 stayed its final order regarding the FERC jurisdictional issue. In October 2007, the OCC lifted its stay statingorally directed the OCC does not have jurisdiction regarding the allocation methodology for off-system sales margins.

The OIEC or another party could filestaff to explore filing a complaint at the FERC alleging the allocation of off-system sales margins to PSO is improper,not in compliance with the FERC-approved methodology which could result in an adverse effect on future results of operations and cash flows for AEP Consolidated and the AEP East companies.  However, toTo date, thereno claim has been no claim asserted at the FERC and management continues to believe that the AEP System deviated fromallocation is consistent with the FERC-approved allocation methodologies, but even if one were asserted, management believes that 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.  In August 2007, an ALJ issued a report recommending that PSO’s fuel procurement practices were prudent and no adjustments were warranted.  No parties appealed the recommendation.  In October 2007, the OCC issued a final order adopting the ALJ’s report.

In February 2006, the OCC enacted a rule, requiring the OCC staff to conduct prudence reviews on allPSO’s 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 periodic reviews.basis.  PSO filed its testimony in June 2007 covering a prudence review for the year 2005. The OCC Staff and intervenors filed testimony in September 2007, and hearings were held in November 2007.

In   PSO also filed prudence testimony in November 2007 covering the year 2006.  The OCC staff and intervenors filed testimony in April 2008.  Hearings are scheduled in May 2007, PSO submitted a filing2008.  The only major issue raised in each of those proceedings was the alleged under allocation of off-system sales credits under the FERC-approved allocation agreements, which was determined not to be jurisdictional to the OCC.  OCC orders applicable to adjust its fuel/purchase power rates.  Inboth 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,2005 and 2006 prudence proceedings are expected 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.2008.

Management cannot predict the outcome of the pending fuel and purchased power costscost recovery filings and prudence reviews, or planned future reviews, butreviews.  However, PSO believes that PSO’sits fuel and purchased power procurement practices and costs arewere prudent and properly incurred.incurred and that it allocated off-system sales credits consistent with governing FERC-approved agreements.

Oklahoma 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 also proposed a formula rate plan that, if approved as filed, would 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 prevent the capitalization of a significant amount of AFUDC that would have been recorded during the construction period and recovered in the future through depreciation expense.

The ALJ issued a report in May 2007 recommending a 10.5% return on equity but did not compute an overall revenue requirement.  The ALJ’s report did not recommend adopting a formula rate plan, but did recommend recovery through a rider of certain generation and transmission projects’ financing costs during construction.  However, the report also contained an alternative recommendation that the OCC could delay a decision on the rider and take up this issue in PSO’s application seeking regulatory approval of a new coal-fueled generating unit.  PSO implemented interim rates, subject to refund, for residential customers beginning July 2007.

In 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 file a plan with the OCC to promote energy efficiency and conservation programs within 60 days.  PSO implemented the approved rates in October 2007.

Lawton and Peaking Generation Settlement Agreement

In November 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 in June 2005, affirming portions of the OCC’s order and remanding certain provisions.  The Court affirmed the OCC’s finding that Lawton established a legally-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 including permits, options and engineering studies.  PSO paid 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, 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 occur 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.

Red Rock Generating Facility

In July 2006, PSO announced plans to enter into an agreement with Oklahoma Gas and Electric Company (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.unit.  PSO would own 50% of the new unit, OG&E would own approximately 42% andunit.  Under the Oklahoma Municipal Power Authority (OMPA) would own approximately 8%.agreement, OG&E would manage construction of the plant.  OG&E and PSO requested pre-approvalpreapproval to construct the Red Rock Generating Facility and to 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 applicationapplications for construction pre-approval statingpreapproval.  The OCC stated that PSO and OG&E failed to fully study other alternatives.  Since PSO and OG&E could not obtain pre-approvalpreapproval to build the coal-fired Red Rock Generating Facility, PSO and OG&E cancelledcanceled the third party construction contract and their joint venture development contract.  Management believesAs a result of the OCC’s decision, PSO will restudy various alternative options to meet its capacity and energy needs.

In December 2007, PSO filed an application at the OCC requesting recovery of the $21 million in pre-construction costs capitalized, including anyand contract cancellation fees were prudently incurred, as evidenced byassociated with Red Rock.  In March 2008, PSO and all other parties in this docket signed a settlement agreement that provides for recovery of $11 million of Red Rock costs, and provides carrying costs at PSO’s AFUDC rate beginning in March 2008 and continuing until the $11 million is included in PSO’s next base rate case.  PSO will recover the costs over the expected life of the peaking facilities at the Southwestern Station, and include the costs in rate base beginning in its next base rate filing.  The settlement was filed with the OCC staff andin March 2008.  A hearing on the ALJ’s recommendations thatsettlement is scheduled for May 2008.  As a result of the settlement, PSO wrote off $10 million of its deferred pre-construction costs/cancellation fees in the first quarter of 2008.  Should the OCC not approve PSO’s filing,the settlement agreement and established aif recovery of the remaining regulatory asset for future recovery.  Management believes such pre-construction costs arebecomes no longer probable of recovery and intends to seek full recovery of such costs in the near future.  If recoveryor is denied, future results of operations and cash flows would be adversely affected.  As a resultaffected by the write off of the OCC’s decision, PSO will consider various alternative options to meet its capacity needs in the future.remaining regulatory asset.

Oklahoma 2007 Oklahoma Ice StormStorms

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

In February 2008, PSO entered into a settlement agreement for recovery of costs from both ice storms.  In March 2008, the OCC approved the settlement subject to an audit of the final December ice storm costs to be filed in July 2008. As a result, PSO recorded an $81 million regulatory asset for ice storm maintenance expenses and related carrying costs less $9 million of amortization expense to offset recognition of deferred gains from sales of SO2 emission allowances.  Under the settlement agreement, PSO will apply proceeds from sales of excess SO2 emission allowances made during 2007of an estimated $26 million to recover part of the ice storm regulatory asset.  PSO will amortize and thereafter until such gains provide forrecover the full recoveryremaining amount of the regulatory asset.  Ifasset through a rider over a period of five years beginning in the OCC adoptsfourth quarter of 2008.  The regulatory asset will earn a return of 10.92% on the PSO proposal, it would have a favorable impact on future results of operations and cash flows.unrecovered balance.

Louisiana Rate Matters

Louisiana Compliance Filing

In October 2002,connection with SWEPCo’s merger related compliance filings, the LPSC approved a settlement agreement in April 2008 that prospectively resolves all issues regarding claims that SWEPCo had over-earned its allowed return.  SWEPCo agreed to a formula rate plan (FRP) with a three-year term.  Beginning August 2008, rates shall be established to allow SWEPCo to earn an adjusted return on common equity of 10.565%.  The adjustments are standard Louisiana rate filing adjustments.  In April 2008, SWEPCo filed detailed financial information typically utilizedthe first FRP anticipating that the LPSC would approve the settlement agreement.  Based on the FRP, SWEPCo proposes to increase its annual Louisiana retail rates by $11 million in August 2008 to earn an adjusted return on common equity of 10.565%.

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

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

In addition, the settlement provides for a jurisdictionalreduction in depreciation rates effective October 2007.  SWEPCo will defer as a regulatory liability, the effects of the expected depreciation reduction through July 2008.  SWEPCo will amortize this regulatory liability over the three year term of the FRP as a reduction to the cost of service withused to determine 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-authorized return on equity of 11.1%.adjusted earned return.

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 jurisdictional customers, based on a proposed 10% return on equity.  The recommended reduction range was 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.  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 affect future results of operations, cash flows and possibly financial condition.

Stall Unit

In May 2006, SWEPCo announced plans to build a new intermediate load 480500 MW natural gas-fired combustion turbine combined cycle generating unit (the Stall Unit) at its existing Arsenal Hill Plant location in Shreveport, Louisiana.  SWEPCo submitted the appropriate filings with the PUCT, the APSC, the LPSC and the Arkansas Public Service Commission (APSC) during the third quarterLouisiana Department of 2006 and the LPSC during the first quarter of 2007Environmental Quality to seek approvals to construct the unit.  The Stall Unit is estimated to cost $375$378 million, excluding AFUDC, and is expected to be in servicein-service in mid-2010.  As of September 2007,March 31, 2008, SWEPCo incurred andhas capitalized approximately $15pre-construction costs of $76 million and has contractual construction commitments of an additional $17$219 million.  IfAs of March 31, 2008, if the Stall Unit is not approved,plant were to be cancelled, then cancellation fees may be required toof $59 million would terminate SWEPCo’s commitment.these construction commitments.

In March 2007, the PUCT approved SWEPCo’s request.certificate for the facility.  In Louisiana, this request has been separated from the original request, which included the Turk Plant.  NeitherFebruary 2008, the LPSC norstaff submitted testimony in support of the Stall Unit and one intervenor submitted testimony opposing the Stall Unit due to the increase in cost.  The LPSC held hearings in April 2008.  The APSC have sethas not established a procedural schedule for the project.at this time.  The project is contingent upon obtaining pre-approval from the APSC, the LPSC, the PUCT and the Louisiana Department of Environmental Quality.Quality issued an air permit for the unit in March 2008.  If SWEPCo isdoes not authorizedreceive appropriate authorizations and permits to build the Stall Unit, SWEPCo would seek recovery of incurredthe capitalized pre-construction costs including any cancellation fees.  If SWEPCo cannot recover incurredits capitalized costs, including any cancellation fees, it could adversely affectwould have an adverse effect on future results of operations and cash flows and possibly financial condition.flows.

Turk Plant

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

Arkansas Rate Matters

Turk Plant

In August 2006, SWEPCo announced plans to build the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas named Turk Plant.Arkansas.  Ultra-supercritical technology uses higher temperatures and higher pressures to produce electricity more efficiently – thereby using less fuel and providing substantial emissions reductions.  SWEPCo submitted filings with the APSC, in December 2006 and the PUCT and the LPSC in February 2007 to seek approvals to proceed withseeking certification of the plant.  In September 2007, OMPA signed a joint ownership agreement and agreed toSWEPCo will 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.  During 2007, SWEPCo signed joint ownership agreements with the Oklahoma Municipal Power Authority (OMPA), the Arkansas Electric Cooperative Corporation (AECC) and the East Texas Electric Cooperative (ETEC) for the remaining 27% of the Turk Plant.  The Turk Plant is estimated to cost $1.3$1.5 billion in total with SWEPCo’s portion estimated to cost $950 million,$1.1 billion, excluding AFUDC.  If approved on a timely basis, the plant is expected to be in-service in mid-2011.2012.  As of September 2007,March 31, 2008, including the joint owners’ share, SWEPCo incurred and capitalized approximately $206$313 million of expenditures and has significant contractual construction commitments for an additional $875$838 million.  IfAs of March 31, 2008, if the Turk Plant is not approved,plant were to be cancelled, then cancellation fees may be required toof $67 million would terminate SWEPCo’s commitment.these construction commitments.

In AugustNovember 2007, hearings began before the APSC seeking pre-approvalgranted approval to build the plant.  Certain landowners filed a notice of appeal to the Arkansas State Court of Appeals.  SWEPCo is still awaiting approvals from the Arkansas Department of Environmental Quality and the U.S. Army Corps of Engineers.  Both approvals are expected to be received by the third quarter of 2008.  The PUCT held hearings in October 2007.  In January 2008, a Texas ALJ issued a report, which concluded that SWEPCo failed to prove there was a need for 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 staffTexas ALJ recommended that SWEPCo’s application be denied suggestingdenied.  The PUCT has voted to reopen the constructionrecord and conduct additional hearings.  SWEPCo expects a decision from the PUCT in the last half of 2008.  In March 2008, the LPSC approved the application to construct 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.Plant.  If SWEPCo isdoes not authorizedreceive appropriate authorizations and permits to build the Turk plant,Plant, SWEPCo could incur significant cancellation fees to terminate its commitments and would be responsible to reimburse OMPA, AECC and ETEC for their share of paid costs.  If that occurred, SWEPCo would seek recovery of incurred costs including any cancellation fees.  If SWEPCo cannot recover incurredits capitalized costs including any cancellation fees and joint owner reimbursements.  If SWEPCo cannot recover its costs, it could adversely affecthave an adverse effect on 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

SECA Revenue Subject to Refund

Effective December 1, 2004, AEP and other transmission owners in the region covered by PJM and the Midwest ISO (MISO) eliminated transaction-based through-and-out transmission service (T&O) charges in accordance with FERC orders and collected at FERC’s direction load-based charges, referred to as RTO SECA, to partially mitigate the loss of T&O revenues on a temporary basis through March 31, 2006.  Intervenors objected to the temporary SECA rates, raising various issues.  As a result, the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund or surcharge.refund.  The AEP East companies paid SECA rates to other utilities at considerably lesser amounts than they collected.  If a refund is ordered, the AEP East companies would also receive refunds related to the SECA rates they paid to third parties.  The AEP East companies recognized gross SECA revenues of $220 million. Approximately $10 million of these recordedfrom December 2004 through March 2006 when the SECA revenues billed by PJM were not collected.  Therates terminated leaving AEP East companies filed a motion withand ultimately its internal load customers to make up the FERC to force payment of these uncollected SECA billings.short fall in revenues.

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

In 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.  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 togetherfiled briefs jointly with Exelon Corporation and The Dayton Power and Light Company, filed an extensive post-hearing brief and reply briefother affected companies 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 ALJ’s initial decision because it contradicts prior related FERC decisions, which are presently subject to rehearing.  Furthermore, management believes the ALJ’s findings on key issues are largely without merit.  As directed by the FERC, management is workinga result, SECA ratepayers have been willing to engage with AEP in settlement discussions.  AEP has been engaged in settlement discussions in an effort to settle the remainingSECA issue.  However, if the ALJ’s initial decision is upheld in its entirety, it could result in a disallowance of a large portion on any unsettled SECA revenues.

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

Completed and in-process settlements cover $105 million of the $220 million of SECA revenues and will consume about $7 million of the reserve for refund, leaving approximately $115 million of unsettledcontested SECA 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$35 million of ongoing settlement talks and, if necessary, any future FERC proceedings or court appeals.  refund reserves.

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,reserved for refunds, it will have an adverse effect on future results of operations and cash flowsflows. Based on advice of external FERC counsel, recent settlement experience and financial condition.the expectation that most of the unsettled SECA revenues will be settled, management believes that the remaining reserve of $35 million is adequate to cover all remaining settlements.  However, management cannot predict the ultimate outcome of ongoing settlement discussions or future FERC proceedings or court appeals, if such are necessary.  

The FERC PJM Regional Transmission Rate Proceeding

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 andafter considerable administrative litigation at AEP’s urging, the FERC instituted an investigationin which AEP sought to mitigate the effect of PJM’s zonalT&O rate regime indicating thatelimination, the presentFERC failed to implement a regional rate regime may need to be replaced through establishment of regional rates that would compensatein PJM.  As a result, the AEP East companies and other transmission owners forcompanies’ retail customers incur the regional transmission facilities they provide to PJM, which provides service forbulk of the benefitcost 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 existingAEP east transmission zone 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 futureany new 500 kV and higher voltage transmission facilities built in PJM would be shared by all customers in the region.  It is expected that most of which are expected tothe new 500 kV and higher voltage transmission facilities will be upgrades of the facilitiesbuilt in other zones of PJM.PJM, not AEP’s zone.  The AEP East companies will need to obtain regulatory approvals for recovery of any costs of new facilities that are assigned to them as a result of this order, if upheld.them.  AEP hashad requested rehearing of this order.order, which the FERC denied.    AEP filed a Petition for Review of the FERC orders in this case in February 2008 in the United States Court of Appeals.  Management cannot estimate at this time what effect, if any, this order will have on the AEP East companies’ future construction of new east transmission facilities, results of operations and cash flows and financial condition.  In May 2007, theflows.

The AEP East companies filed for rehearing relatedand in 2006 obtained increases in its wholesale transmission rates to this FERC decision.

Since the FERC’s decisionrecover lost revenues previously applied to reduce those rates.  AEP has also sought and received retail rate increases in 2005 to cease through-and-out ratesOhio, Virginia, West Virginia 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 TennesseeKentucky to recover lost T&O and SECA revenues.  Therevenues previously applied to reduce retail rates.  As a result, AEP East companies presently recover from retail customersis now recovering approximately 85% of the lost T&O/&O transmission revenues.  AEP received net SECA transmission revenues of $128 million a year.in 2005.  I&M requested recovery of these lost revenues in its Indiana rate filing in late January 2008 but does not expect to commence recovering the new rates until early 2009.  Future results of operations and cash flows and financial condition will continue to be adversely affected in Indiana and Michigan and Tennessee until thesethe remaining 15% of the lost T&O/SECA&O transmission revenues are recovered in retail rates.

The FERC PJM and MISO Regional Transmission Rate Proceeding

In the SECA proceedings, the FERC ordered the RTOs and transmission owners in the PJM/MISO region (the Super Region) to file, by August 1, 2007, a proposal to establish a permanent transmission rate design for the Super Region to be effective February 1, 2008.  All of the transmission owners in PJM and MISO, with the exception of AEP and one MISO transmission owner, votedelected to continuesupport continuation of zonal rates in both RTOs.  In September 2007, AEP filed a formal complaint proposing a highway/byway rate design be implemented for the Super Region.Region where users pay based on their use of the transmission system.  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 that 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.  In January 2008, the FERC denied AEP’s complaint.  AEP filed a rehearing request with the FERC in March 2008.  Should this effort be successful, AEP East companies would reduce future retail revenues in their next fuel or base rate proceedings.  Management is unable to predict the outcome of this case.

SPPPotomac-Appalachian Transmission FormulaHighline (PATH) Rate Filing

In JuneSeptember 2007, AEPSCAEP and Allegheny Energy Inc. (Allegheny) formed a joint venture by creating Potomac-Appalachian Transmission Highline, LLC and its subsidiaries (PATH).  The PATH subsidiaries will operate as transmission utilities owning certain electric transmission assets within PJM.  Subsidiaries of both AEP and Allegheny provide services to the PATH companies through service agreements.  PATH is not consolidated with AEP for financial reporting purposes.

In December 2007, PATH filed revised tariff sheetsan application with the FERC for approval of a transmission formula rate to be collected during construction to recover its costs, including costs incurred prior to the formula rates going into effect.  PATH requested an incentive return of 14.3% on behalfits equity investment using a 50/50 debt to equity ratio, the recovery of PSOdeferred pre-operating, pre-construction costs and SWEPCothe recovery of construction financing costs through the inclusion of CWIP in rate base with a true-up to actual for these costs.  The transmission formula rate will be collected from all PJM load serving entities.  In addition to the AEP pricing zonerate recovery sought through the FERC, the PATH operating companies will seek certification and other regulatory approvals from the state commissions following completion of a routing study.

In February 2008, the SPP OATT.  The revised tariff sheets seek to establish an up-to-date revenue requirementFERC approved all of PATH’s requests except 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 implementation protocols and requested return on equity are approved,ordered that the 2008 network transmission service revenues from nonaffiliates will increaseformula rates go into effect in March 2008. Settlement negotiations began and motions for rehearing were filed by approximately $10 million compared tointervening parties in March 2008.  Management cannot predict 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 judgeoutcome of these 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.

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 20062007 Annual Report should be read in conjunction with this report.

GUARANTEES

There are certain immaterial liabilities recorded for guarantees.guarantees in accordance with FASB Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”  There is no collateral held in relation to any guarantees in excess of our ownership percentages.  In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letters 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,Parent, we issued all of these LOCs in our ordinary course of business on behalf of our subsidiaries.  At September 30, 2007,March 31, 2008, the maximum future payments for all the LOCs wereare approximately $69$57 million with maturities ranging from November 2007April 2008 to October 2008.March 2009.

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 $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 46.46R.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study, we estimate the reserves will be depleted in 2029 with final reclamation completed by 2036, at an estimated cost of approximately $39 million.  As of September 30, 2007,March 31, 2008, SWEPCo has collected approximately $33$35 million through a rider for final mine closure costs, of which approximately $15$17 million is recorded in Deferred Credits and Other and approximately $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 20062007 Annual Report, “Dispositions” section of Note 8.  These sale agreements include indemnifications with a maximum exposure related to the collective purchase price, which is approximately $1.3 billion (approximately $1 billion relates to the Bank of America (BOA) litigation, see “Enron Bankruptcy” section of this note).  There are no material liabilities recorded for any indemnifications.indemnifications other than amounts recorded related to the BOA litigation.

Master Operating Lease

We lease certain equipment under a master operating lease.  Under the lease agreement, the lessor is guaranteed receipt of up to 87% of the unamortized balance of the equipment at the end of the lease term.  If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, we are committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance.  AssumingHistorically, at the end of the lease term the fair market value has been in excess of the unamortized balance.  At March 31, 2008, the maximum potential loss for these lease agreements was approximately $62 million ($40 million, net of tax) assuming the fair market value of the equipment is zero at the end of the lease term, the maximum potential loss for these lease agreements was approximately $59 million ($39 million, net of tax) as of September 30, 2007.term.

Railcar Lease

In June 2003, weAEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease 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.  Assuming
In January 2008, AEP Transportation assigned the fair market valueremaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignment is accounted for as new operating leases for I&M and SWEPCo.  The future minimum lease obligation is $46 million as of March 31, 2008.  I&M and SWEPCo intend to renew these leases for the equipment is zero atfull remaining terms and have assumed the end ofguarantee under the current lease term, thereturn-and-sale option.  I&M’s maximum potential loss wasrelated to the guarantee discussed above is approximately $30$14 million ($209 million, net of tax) asand SWEPCo’s is approximately $16 million ($11 million, net of September 30, 2007.  tax).

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 allegealleged 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,OPCo modified certain units at their 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 20-year period.  In April 2007, the U.S. Supreme Court reversed the Fourth Circuit Court of Appeals’ decision that had supported the statutory construction argument ofCases with similar allegations against CSPCo, Dayton Power and Light Company (DP&L) and Duke Energy 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 agreedOhio, Inc. were also filed related 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 consent decree, we will pay a $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.their jointly-owned units.

The consent decree will resolve all issues related to various parties’ claims against usAEP System settled their cases 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 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 may be required as a result of the consent decree through regulated rates or market prices of electricity.  If we are unable to recover such costs, it would adversely affect our future results of 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.  No trial date has yet been established in theThe Stuart case, but the units, operated by Dayton Power and Light Company,DP&L, are equipped with SCR controls and flue gas desulfurization equipment (FGD or scrubbers) controls.  A trial on liability issues was scheduled for August 2008.  The Court issued a stay to allow the installation of FGD controls will be completedparties to pursue settlement discussions and scheduled a settlement conference in 2007.May 2008.  The Beckjord and Zimmer case is scheduled for a liability trial in May 2008.  ZimmerBeckjord 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.

We are unable to estimate the loss or range of loss related to any contingent liability, if any, we might have for civil penalties under the pending CAA proceedings for our jointly-owned 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 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.  SWEPCoIn April 2008, the parties filed a responseproposed consent decree to resolve all claims in this case and in the pending appeal of the altered permit for the Welsh Plant.  The consent decree requires SWEPCo to install continuous particulate emission monitors at the Welsh Plant, secure 65 MW of renewable energy capacity by 2010, fund $2 million in emission reduction, energy efficiency or environmental mitigation projects by 2012 and pay a portion of plaintiffs’ attorneys’ fees and costs.  The consent decree has been submitted to the complaint in May 2005.  A trial in this matter is scheduledFederal EPA and the DOJ for a 45-day comment period prior to commence during the first quarter of 2008.entry.

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.Plant.  In April 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition(Report) 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 violationsSWEPCo.  TCEQ filed an amended Report during the fourth quarter of 2007, eliminating certain representations regarding heat input in SWEPCo’s permit applicationclaims and reducing the violations of certain recordkeeping and reporting requirements.  SWEPCo respondedrecommended penalty amount to the preliminary report and petition in May 2005.$122 thousand.  The enforcement order containsmatter was remanded to TCEQ to pursue settlement discussions.  The original Report contained a recommendation limitingto limit the heat input on each Welsh unit to the referenced heat input contained within the state permit application within 10 days of the issuance of a final TCEQ order and until athe permit amendment is issued.changed.  SWEPCo had previously requested a permit alteration to remove the reference to a specific heat input value for each Welsh unit and to clarify the sulfur content requirement for fuels consumed at the plant.  A permit alteration was issued in March 2007 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.2007.  The Sierra Club and Public Citizen filed a motion to overturn the permit alteration.  In June 2007, TCEQ denied that motion.  The permit alteration was appealed to the Travis County District Court, but would be resolved by entry of the consent decree in the federal citizen suit action.  The District Court issued a stay while approval of the consent decree is pending.

On February 8, 2008, the Federal EPA issued a Notice of Violation (NOV) based on alleged violations of a percent sulfur in fuel limitation and the heat input values listed in the previous state permit.  The NOV also alleges that the permit alteration issued by TCEQ was improper.  SWEPCo met with the Federal EPA to discuss the alleged violations in early March 2008.

We are unable to predict the timing of any future action by TCEQ, the Federal EPA 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 of this lawsuit was appealed to the Second Circuit Court of Appeals.  Briefing and oral argument have concluded.   OnIn 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 U.S. Supreme Court’s decision on this case.  We believe the actions are without merit and intend to defend against the claims.

Alaskan Villages’ Claims

TEM LitigationIn February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska  filed a lawsuit in federal court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil & gas companies, a coal company, and other electric generating companies.  The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together.  The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance.  The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million.  We believe the action is without merit and intend to defend against the claims.

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

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

Superfund addresses clean-up of hazardous substances that have been released to the environment.  The Federal EPA administers the clean-up programs.  Several states have enacted similar laws.  In March 2008, I&M received  a letter from the Michigan Department Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm.  I&M requested  remediation proposals from environmental consulting firms due May 2008.  I&M cannot predict the cost of remediation or the amount of costs recoverable from third parties.

In those instances where we have been named a Potentially Responsible Party (PRP) or defendant, our disposal or recycling activities were in accordance with the then-applicable laws and regulations.  Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories.  Liability has been resolved for a number of sites with no significant effect on results of operations.

We evaluate the potential liability for each Superfund site separately, but several general statements can be made regarding our potential future liability.  Disposal of materials at a particular site is often unsubstantiated and the quantity of materials deposited at a site was small and often nonhazardous.  Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises.  At present, our estimates do not anticipate material cleanup costs for any of our identified Superfund sites.

TEM Litigation

We agreed to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) (now known as SUEZ Energy Marketing NA, Inc.) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA).  Beginning May 1, 2003, OPCowe tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming.

In 2003, TEM and AEP separately filed declaratory judgment actions in the United States District Court for the Southern District of New York.  We alleged that TEM breached the PPA and 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’sour breaches.  The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) provided a limited guaranty.

In 2005,January 2008, we reached a federal judge ruled thatsettlement with TEM had breachedto resolve all litigation regarding the contract and awardedPPA.  TEM paid us damages of $123$255 million.  We recorded the $255 million plus prejudgment interest.  Any eventual proceeds will be recorded as a gain when received.
In May 2007, the United States Courtin January 2008 under Asset Impairments and Other Related Items on our Condensed Consolidated Statements of Appeals for the Second Circuit ruled that the lower court was correct in finding that TEM breachedIncome.  This settlement and 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 entitledrelated to the benefit of our bargainPlaquemine Cogeneration Facility which was impaired 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 expect TEM to pay the amount of those damages, approximately $8 million, including interest,sold in the fourth quarter of 2007.2006.

Enron Bankruptcy

In 2001, we purchased HPL from Enron.  Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.  In connection with the 2001our acquisition of HPL, we entered into an agreement with BAM Lease Company, which granted HPL the exclusive right to use approximately 6555 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)BOA and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of 65 BCF ofthe 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 HPLThis dispute is being litigated in Texas state court seeking a declaratory judgment that the BOA Syndicate has a validcourts, Enron bankruptcy proceedings and enforceable security interest in gas purportedlyFederal courts in the Bammel storage facility.  Texas and New York.

In 2003, the Texas state court granted partial summary judgment in favor of the BOA Syndicate.  In August 2006, the Court of Appeals for the First District of Texas vacated the trial court’s judgment2002 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 lawsuitlawsuits 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

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 adverse decision on its motionadversary proceeding contesting Enron’s right 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.reject these agreements.

In 2003, AEP filed a lawsuit against BOA in the United States District Court for the Southern District of Texas.  BOA led athe lending syndicate involving the 1997monetization of the cushion gas monetization thatto Enron and its subsidiaries undertook and the leasing of the Bammel underground gas storage facility to HPL.subsidiaries.  The lawsuit asserts that BOA made misrepresentations and engaged in fraud to induce and promote the stock sale of HPL, that BOA directly benefited from the sale of HPL and that AEP undertook the stock purchase and entered into the 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 thatfalse.  In April 2005, 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,Judge entered an order severing and transferring 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 judgmentsjudgment claims involving the Bammel facility and the right to use and cushion gas consent agreements be transferred to the Southern District of New York and thatretaining 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 caseTrial 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 August 2007, the Judgejudge in the New York action issued a decision granting BOA summary judgment without awarding any damages and dismissingdismissed our claims.  In December 2007, the judge held that BOA is entitled to recover damages of approximately $347 million ($432 million and $427 million including interest at March 31, 2008 and December 31, 2007, respectively) less a to be determined amount BOA would have incurred to remove 55 BCF of natural gas from the Bammel storage facility.  The Judge held another hearingjudge denied our Motion for Reconsideration.  We plan to appeal the court’s decision once the court enters a final judgment.  If the Court enters a final judgment adverse to us and we appeal from the judgment, we will be required under court rules to post security in September 2007 and said that he plansthe form of a further hearing onbond or stand-by letter of credit covering the damages issue.  We asked the Judge to certify an appealamount 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, described below, 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 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.entered against us.

In 2005, we sold our interest in HPL.  We indemnified the buyer of HPL against any damages resulting from the BOA litigation up to the purchase price.  The determination and recognition of the gain on the saleamounts discussed above 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 a 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.  In August 2007, the appeals court reversed the trial court’s decision and held that the plaintiff did have standing to pursue his claim. The appeals court remanded the case to the trial court to consider the issue of whether the plaintiff is an adequate representative for the class of plan participants on whose behalf the litigation would be pursued.participants.  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 fortynumerous 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 also filed in California.  In addition, a number of other cases were filedCalifornia and 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.defendants in some of these cases.  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 a number of the remaining 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 because the market for power was allegedly dysfunctional at the time such contracts were executed.  An ALJ recommended rejection of the complaint, holding 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 affirmingrejected the ALJ’s decision.complaint.  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,That decision was appealed and argued before the U.S. Supreme Court decided to review the Ninth Circuit’s decision.in February 2008.  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.
ACQUISITIONS DISPOSITIONS, DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE
DISPOSITIONS

ACQUISITIONS

20072008

None

2007

Darby Electric Generating Station (Utility Operations segment)

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

Lawrenceburg Generating Station (Utility Operations segment)

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

Dresden Plant (Utility Operations segment)DISPOSITIONS

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.

20062008

None

DISPOSITIONS2007

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$43 million plus working capital adjustments.  The sale did not have an impact on our results of operations nor do we expect theany remaining litigation to have a significant effect on our results of operations.

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

DuringIn March 2007, we sold 130,000 shares of ICE and recognized a $16 million pretax gain ($10 million, net of tax).  We recorded the gainsgain in Interest and Investment Income on our 2007 Condensed Consolidated Statement of Income.  We recorded ourOur remaining investment of approximately 138,000 shares at March 31, 2008 and December 31, 2007 is recorded in Other Temporary 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.  WeIn 2007, we received the final earnings sharing payment of $20 million and $70 million payments in 2007 and 2006, respectively, for our share in earnings.  These payments aremillion.  This payment is reflected in Gain/LossGain on Disposition of Assets, Net on our March 31, 2007 Condensed Consolidated StatementsStatement of Income.  The payment we received in 2007 was the final payment under the earnings sharing agreement.

Sweeny Cogeneration Plant (Generation and Marketing segment)6.       BENEFIT PLANS

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.  In February 2006, we completed the sale of the 50% interest in Bajio for $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 provided by operating, investing or financing activities related to our discontinued operations for the nine months ended September 30, 2007 and 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.  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 did not meet the “component-of-an-entity” criteria because the plant did not have cash flows that can be clearly distinguished operationally.  The plant also did not meet the “component-of-an-entity” criteria for financial reporting purposes because the plant did not operate individually, but rather as a part of the AEP System.

Assets Held for Sale were as follows:

  
September 30,
  
December 31,
 
  
2007
  
2006
 
Texas Plants
 
(in millions)
 
Other Current Assets $-  $1 
Property, Plant and Equipment, Net  -   43 
Total Assets Held for Sale
 $-  $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 are 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 September 30, 2007March 31, 2008 and 2006:2007:
    
Other
   Other 
    
Postretirement
   Postretirement 
 
Pension Plans
  
Benefit Plans
 Pension Plans Benefit Plans 
 
2007
  
2006
  
2007
  
2006
 Three Months Ended March 31, Three Months Ended March 31, 
Three Months Ended September 30, 2007 and 2006
 
(in millions)
 
2008 2007 2008 2007 
(in millions) 
Service Cost $24  $23  $11  $10  $25  $24  $10  $10 
Interest Cost  59   57   26   26   63   59   28   26 
Expected Return on Plan Assets  (85)  (82)  (26)  (24)  (84)  (85)  (28)  (26)
Amortization of Transition Obligation  -   -   6   7   -   -   7   7 
Amortization of Net Actuarial Loss  15   20   3   5   9   15   3   3 
Net Periodic Benefit Cost
 $13  $18  $20  $24  $13  $13  $20  $20 

     
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 20062007 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 continues to have commission-determined transitionrates transitioning from cost-based to market-based rates.   The legislature in Ohio is currently considering possibly returning to some form of cost-based rate-regulation or a hybrid form of rate-regulation for generation.  While our Utility Operations segment remains our primary business segment, other segments include our MEMCO Operations segment with significant barging activities and our Generation and Marketing segment, which includes our nonregulated generating, marketing and risk management activities in the ERCOT market area.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

Our principal operating businessreportable 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 3435 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi rivers.Rivers.  Approximately 35%39% of the barging operations relates to theis for transportation of coal, 30% relates to agricultural products, 18% relates to30% for coal, 14% for steel and 17% relates tofor other commodities.

Generation and Marketing
·IPPs, windWind 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 activities is presented as All Other.  While not considered a business segment, All Other includes:

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

The tables below present our reportable segment information for the three and nine months ended September 30,March 31, 2008 and 2007 and 2006 and balance sheet information as of September 30, 2007March 31, 2008 and December 31, 2006.2007.  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
          
  
Utility Operations
  
MEMCO
Operations
  
Generation
and
Marketing
  
All Other (a)
  
Reconciling Adjustments
  
Consolidated
 
  
(in millions)
 
Three Months Ended September 30, 2007
                  
Revenues from:                  
External Customers $3,423  $134  $241  $(9) $-  $3,789 
Other Operating Segments  177   4   (161)  19   (39)  - 
Total Revenues
 $3,600  $138  $80  $10  $(39) $3,789 
                         
Net Income (Loss) $388  $18  $3  $(2) $-  $407 
  See “FASB Staff Position FIN 39-1 Amendment of FASB No. 39” section of Note 2 for discussion of changes in netting certain balance sheet amounts.

    
Nonutility Operations
              Nonutility Operations          
 
Utility Operations
  
MEMCO
Operations
  
Generation
and
Marketing
  
All Other (a)
  
Reconciling Adjustments
  
Consolidated
  Utility Operations  
MEMCO
Operations
  
Generation
and
Marketing
  All Other (a)  Reconciling Adjustments  Consolidated 
 
(in millions)
  (in millions) 
Three Months Ended September 30, 2006
                  
Three Months Ended March 31, 2008                  
Revenues from:                                    
External Customers $3,478  $135  $14  $(33) $-  $3,594  $3,010(d)  $138  $271  $48  $-  $3,467 
Other Operating Segments  (41)  4   -   52   (15)  -   284(d)   4   (212)  (43)  (33)  - 
Total Revenues
 $3,437  $139  $14  $19  $(15) $3,594  $3,294  $142  $59  $5  $(33) $3,467 
                                                
Net Income (Loss) $378  $19  $4  $(136) $-  $265 
Net Income $410  $7  $1  $155  $-  $573 

     
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) 
Three Months Ended March 31, 2007                  
Revenues from:                  
External Customers $2,886(d)  $117  $115  $51  $-  $3,169 
Other Operating Segments  147(d)   3   (73)  (45)  (32)  - 
Total Revenues $3,033  $120  $42  $6  $(32) $3,169 
                         
Net Income (Loss) $253  $15  $(1) $4  $-  $271 

     
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
(c)
  Consolidated 
  (in millions) 
March 31, 2008                  
Total Property, Plant and Equipment $46,055  $265  $575  $40  $(245) $46,690 
Accumulated Depreciation and
  Amortization
  16,144   63   119   8   (15)  16,319 
Total Property, Plant and
  Equipment – Net
 $29,911  $202  $456  $32  $(230) $30,371 
                         
Total Assets $40,287  $340  $902  $12,707  $(12,919)(b) $41,317 

    
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
          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
(c)
 Consolidated 
December 31, 2006
 
(in millions)
 
December 31, 2007(in millions) 
Total Property, Plant and Equipment $41,420 $239 $327 $35 $- $42,021  $45,514  $263  $567  $38  $(237) $46,145 
Accumulated Depreciation and
Amortization
  15,101  51  83  5  -  15,240   16,107   61   112   7   (12)  16,275 
Total Property, Plant and Equipment – Net
 $26,319 $188 $244 $30 $- $26,781  $29,407  $202  $455  $31  $(225) $29,870 
                                      
Total Assets $36,632 $315 $342 $11,460 $(10,762)(c)$37,987  $39,298  $340  $697  $12,117  $(12,133)(b) $40,319 
Assets Held for Sale 44 - - - -  44 

(a)All Other includes:
 ·Parent’s guarantee revenue received from affiliates, interest incomeThe first quarter 2008 cash settlement of a purchase power and interest expense and other nonallocated costs.
·Other energy supplysale agreement with TEM related businesses, includingto the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006.  The cash settlement of $255 million ($163 million, net of tax) is included in Net Income.
(b)Reconciling Adjustments·Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs, which netted to a $7 million after-tax loss 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 2007.2008.
(c)·Revenue sharing related to the Plaquemine Cogeneration Facility.
·Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005.  These contracts are financial derivatives which will gradually liquidate and completely expire in 2011.
(b)Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies.
(c)Includes eliminations due to an intercompany capital lease.
(d)PSO and SWEPCo transferred certain existing ERCOT energy marketing contracts to AEPEP (Generation and Marketing segment) and entered into intercompany financial and physical purchase and sales agreements with AEPEP.  As a result, we reported third-party net purchases for these energy marketing contracts as a reduction of Revenues from External Customers for the Utility Operations segment.  This is offset by the Utility Operations segment’s related sales to AEPEP in Revenues from Other Operating Segments of $212 million.  The Generation and Marketing segment reports purchases related to these contracts as a reduction to Revenues from Other Operating segments.

8.     INCOME TAXES

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

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

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

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

We have settled withState Tax Legislation

In March 2008, the IRS on all issues fromGovernor of West Virginia signed legislation providing for, among other things, a reduction in the audits of our consolidated federalWest Virginia corporate income tax returns for years priorrate from 8.75% 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 2005 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.

8.5% beginning in 2009.  The IRS has proposed certain adjustments to our foreign tax credit and interest allocation positions.  Management has evaluated the proposed adjustments and has agreed to pay the related taxes.  Management does not anticipate that the adjustments will 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 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 effectivecorporate income tax rate is $73 million.  There are $66 millioncould also be reduced to 7.75% in 2012 and 7% in 2013 contingent upon the state government achieving certain minimum levels of tax positions for which the ultimate deductibility is highly certain but the timing of such deductibility is uncertain.  Because ofshortfall reserve funds.  We continue to evaluate the impact of deferred tax accounting, other than interest and penalties, the disallowancelaw change, but do not expect the law change to have a material impact on our results of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment ofoperations, 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 incomeflows or expense as applicable, and penalties in Other Operation and Maintenance.  As of January 1, 2007, we accrued $25 million for the payment of uncertain interest and penalties.

Michigan Tax Restructuringfinancial condition.

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 iswas effective January 1, 2008 and replacesreplaced the Michigan Single Business Tax that is scheduled to expireexpired 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,
 
 
2007
  
2006
  March 31,  December 31, 
Type of Debt
 
(in millions)
  2008  2007 
 (in millions) 
Senior Unsecured Notes $9,752  $8,653  $10,349  $9,905 
Pollution Control Bonds  2,134   1,950   2,216   2,190 
First Mortgage Bonds  -   90   -   19 
Defeased First Mortgage Bonds (a)  19   27 
Notes Payable  303   337   264   311 
Securitization Bonds  2,257   2,335   2,183   2,257 
Junior Subordinated Debentures  315   - 
Notes Payable To Trust  113   113   113   113 
Spent Nuclear Fuel Obligation (b)(a)  257   247   261   259 
Other Long-term Debt  2   2   3   2 
Unamortized Discount (net)  (61)  (56)  (68)  (62)
Total Long-term Debt Outstanding
  14,776   13,698   15,636   14,994 
Less Portion Due Within One Year
  910   1,269   716   792 
Long-term Portion
 $13,866  $12,429  $14,920  $14,202 

(a)In May 2004, 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 September 30, 2007 and December 31, 2006.  Trust Fund Assets related to this obligation of $22 million and $2 million at September 30, 2007 and December 31, 2006, respectively, are included in Other Temporary Investments and $21 million at December 31, 2006, is included in Other Noncurrent Assets on our Condensed Consolidated Balance Sheets.  In December 2005, 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  December 31, 2006.  Trust fund assets related to this obligation of $9 million at December 31, 2006, are included in Other Temporary 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 withto 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 Fundfund assets related to this obligation of $280$289 million and $274$285 million at September 30, 2007March 31, 2008 and December 31, 2006,2007, respectively, are included in Spent Nuclear Fuel and Decommissioning Trusts on our Condensed Consolidated Balance Sheets.


Long-term debt and other securities issued, retired and principal payments made during the first ninethree months of 20072008 are shown in the tables below.
 
Company
 
Type of Debt
 
Principal Amount
 
Interest Rate
 
Due Date
  Type of Debt Principal Amount Interest Rate Due Date 
   
(in millions)
 
(%)
      (in millions) (%)   
Issuances:
                  
AEP Junior Subordinated Debentures $315 8.75 2063 
APCo Pollution Control Bonds $75 Variable 2037  Senior Unsecured Notes 500 7.00 2038 
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  Pollution Control Bonds  120 5.125 2030 
TNC Pollution Control Bonds  44 4.45 2020 
Total Issuances
   $1,943(b)       $935(a)    

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

(a)AEGCo’s senior unsecured notes due 2037 are payable over
Other than the lifepossible dividend restrictions of the notes as a $7.3 million annual principal amount plus accrued interest paid semiannually in March and September.AEP Junior Subordinated Debentures, the above borrowing arrangements does not contain guarantees, collateral or dividend restrictions.
(b)
(a)Amount indicated on statement of cash flows of $1,924$916 million is net of issuance costs and unamortized premium or discount.
The net proceeds from the sale of Junior Subordinated Debentures will be used for general corporate purposes including the payment of short-term indebtedness.

 
Company
 Type of Debt Principal Amount Paid Interest Rate Due Date 
    (in millions) (%)   
Retirements and   Principal Payments:         
CSPCo Senior Unsecured Notes $52 6.51 2008 
I&M Pollution Control Bonds  45 Variable 2009 
I&M Pollution Control Bonds  50 Variable 2025 
OPCo Notes Payable  1 6.81 2008 
OPCo Notes Payable  6 6.27 2009 
SWEPCo Notes Payable  1 4.47 2011 
SWEPCo Notes Payable  1 Variable 2008 
           
Non-Registrant:          
AEP Subsidiaries Notes Payable  2 Variable 2017 
AEGCo Senior Unsecured Notes  4 6.33 2037 
AEPSC Mortgage Notes  34 9.60 2008 
TCC Securitization Bonds  29 5.01 2008 
TCC Securitization Bonds  45 4.98 2010 
TCC First Mortgage Bonds  19 7.125 2008 
Total Retirements and   Principal Payments  $289     

In May 2007,April 2008, I&M issued $40 million of 5.25% Pollution Control Bonds due in 2025.  TNC issued $30 million of 5.89% and $70 million of 6.76% Senior Unsecured Notes due in 2018 and 2038, respectively.

In April 2008, CSPCo remarketed its outstanding $50$44.5 million and $56 million Pollution Control Bonds, resulting in new interest rates of 4.85% and 5.10%, respectively.  SWEPCo remarketed its outstanding $81.7 million Pollution Control Bonds, resulting in a new interest rate of 4.625%4.95%.  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$40.9 million Pollution Control Bonds, resulting in a new interest rate of 5.20%5.625%.  No proceeds were received related to this remarketing.these remarketings.  The principal amountamounts of the Pollution Control Bonds isare reflected in Long-term Debt on our Condensed Consolidated Balance SheetSheets as of September 30, 2007.March 31, 2008.

    
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     
In April 2008, APCo repurchased its $40 million and $30 million of variable rate interest Pollution Control Bonds, each due in 2019, and $17.5 million of variable rate interest Pollution Control Bonds due in 2021.  CSPCo repurchased its $48.6 million of variable rate interest Pollution Control Bonds due in 2038.

(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 October 2007, KPCoApril 2008, TCC retired $48$60 million and $60.3 million of 6.91% Senior Unsecured Notesvariable interest rate Pollution Control Bonds, each due in 2007.2028.

Short-term DebtAs of March 31, 2008, we had $1.4 billion outstanding of tax-exempt long-term debt (Pollution Control Bonds) sold at auction rates that reset every 7, 28 or 35 days.  This debt is insured by bond insurers previously AAA-rated, namely Ambac Assurance Corporation, Financial Guaranty Insurance Co., MBIA Insurance Corporation and XL Capital Assurance Inc.  Due to the exposure that these bond insurers have in connection with developments in the subprime credit market, the credit ratings of these insurers have been downgraded or placed on negative outlook.  These market factors have contributed to higher interest rates in successful auctions and increasing occurrences of failed auctions, including many of the auctions of our tax-exempt long-term debt.  The instruments under which the bonds are issued allow us to convert to other short-term variable-rate structures, term-put structures and fixed-rate structures.  During the first quarter of 2008, we reduced our outstanding auction rate securities by redeeming or repurchasing $95 million of such debt securities.  In April 2008, we converted, refunded or provided notice to convert or refund $940 million of our outstanding auction rate securities.  We plan to continue this conversion and refunding process for the remaining $471 million to other permitted modes, including term-put and fixed-rate structures through the third quarter of 2008.  The conversions will likely result in higher interest charges compared to prior year but lower than the failed auction rates for this tax-exempt long-term debt.

Dividend Restrictions

We have the option to defer interest payments on the AEP Junior Subordinated Debentures issued in March 2008 for one or more periods of up to 10 consecutive years per period.  During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.  We believe that these restrictions will not have a material effect on our results of operations, cash flows, financial condition or limit any dividend payments in the foreseeable future.

Short-term debt is used to fund our corporate borrowing program and fund other short-term cash needs.  Debt

Our outstanding short-term debt wasis as follows:
 
September 30, 2007
 
December 31, 2006
 
 
Outstanding
 
Interest
 
Outstanding
 
Interest
  March 31, 2008  December 31, 2007 
 
Amount
 
Rate
 
Amount
 
Rate
  
Outstanding
Amount
 
Interest
Rate (a)
  
Outstanding
Amount
 
Interest
Rate (a)
 
Type of Debt
 
(in millions)
   
(in millions)
    (in thousands)    (in thousands)   
Commercial Paper – AEP $559 5.60%(a)$- -  $408,959 3.66% $659,135 5.54%
Commercial Paper – JMG (b) 2 5.3588%  1 5.56% - -  701 5.35%
Line of Credit – Sabine (c)  26 6.07%  17 6.38%
Line of Credit – Sabine Mining Company (c)  - -   285 5.25%
Total
 $587   $18    $408,959    $660,121   

(a)Weighted average rate.
(b)This commercial paper is specifically associated with the Gavin Scrubber and is backed by a separate credit facility.  This commercial paper does not reduce available liquidity under AEP’s credit facilities.
(c)Sabine Mining Company is consolidated under FIN 46.46R.  This line of credit does not reduce available liquidity under AEP’s credit facilities.

Credit Facilities

InAs of March 2007,31, 2008, we amended the terms ofhad credit facilities totaling $3 billion to support our credit facilities.commercial paper program.  The amended facilities are structured as two $1.5 billion credit facilities with an option inof which $300 million may be issued under each to issue up to $300 millioncredit facility as letters of credit.  In March 2008, the 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 outfacilities were amended so that $750 million may be issued under each credit facility as letters of stated capital.

Sale of Receivables – AEP Creditcredit.

In October 2007,April 2008, we renewed AEP Credit’s sale of receivables agreement.  The sale of receivables agreement providesentered into a commitment of $650 million from3-year credit agreement and a bank conduit to purchase receivables from AEP Credit.  Under the agreement, the commitment will increase to $700$350 million for the months of August and September to accommodate seasonal demand.  This agreement will expire in October 2008.364-day credit agreement.
 















APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
 
 
 
 
 
 
 
 
 
 
 

 


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
First Quarter of 2008 Compared to First Quarter of 2007

ResultsReconciliation of Operations
ThirdFirst Quarter of 2007 Compared to ThirdFirst Quarter of 20062008
Net Income
(in millions)

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

Third Quarter of 2006
    $31 
First Quarter of 2007    $70 
              
Changes in Gross Margin:
              
Retail Margins  13       (20)    
Off-system Sales  18       16     
Transmission Revenues, Net  (22)    
Other  (14)    
Transmission Revenues  1     
Total Change in Gross Margin
      (5)      (3)
                
Changes in Operating Expenses and Other:
                
Other Operation and Maintenance  (27)      (20)    
Depreciation and Amortization  9       (3)    
Taxes Other Than Income Taxes  1       (3)    
Carrying Costs Income  36       6     
Other Income, Net  (8)    
Other Income  1     
Interest Expense  (18)      (12)    
Total Change in Operating Expenses and Other
      (7)      (31)
                
Income Tax Expense      5       19 
                
Third Quarter of 2007
     $24 
First Quarter of 2008     $55 

Net Income decreased $7$15 million to $24 million.  The key drivers of the decrease were a $5$55 million decrease in Gross Margin and a $7 million2008 primarily due to an increase in Operating Expenses and Other of $31 million, partially offset by a $5 million decrease in Income Tax Expense.Expense of $19 million.

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

·Retail Margins increased $13decreased $20 million primarily due to higher capacity settlement expenses under the impactInterconnection Agreement and an increase in refunds to customers of the Virginia base rate order issued in May 2007, the Virginia E&R and fuel cost recovery filings and increased demandoff-system sales margins.  These decreases were partially offset by an increase in the residential class associated with favorable weather conditions.  Cooling degree days increased approximately 22%.recovery of APCo’s environmental and reliability costs and an increase in retail sales related to customer usage.
·Margins from Off-System salesOff-system Sales increased $18$16 million primarily due to higher physical sales volumes and power prices in the east, benefits from AEP’s eastern natural gas fleet, and highermargins partially offset by lower trading margins.
·Transmission Revenues, Net decreased $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 reversal in the third quarter of 2006 of previously deferred gains on sales of allowances associated with the 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 $27$20 million primarily due to a $9 million increase in steam generation expenses primarily for maintenance at the settlement agreement regarding alleged violationsMountaineer Plant and an increase of the NSR provisions of the CAA, of which $26$5 million was allocatedin distribution maintenance expenses resulting from Virginia and West Virginia wind storm damage.  In addition, operational expenses increased by $8 million due to APCo.  See “Federal EPA Complaintdecreased Transmission Equalization Agreement credits resulting from APCo’s peak demand set in February 2007 and Notice of Violation” section of Note 4.increased employee-related expenses.
·Depreciation and Amortization expenses decreased $9increased $3 million primarily due to the write-offamortization of carrying charges and depreciation expense that are being collected through the Virginia E&R surcharges.
·Taxes Other Than Income Taxes increased $3 million primarily due to higher franchise taxes which resulted from an amended tax return recognized in the third quarter of 2006 of previously deferred depreciation expenses associated with the E&R case.2007.
·Carrying Costs Income increased $36$6 million primarily duerelated to the write-off in the third quarter of 2006 of previously recorded carrying costs income associated with the Virginia 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$12 million primarily due to an $8 million increase in interest expense from long-term debt issuances and a $9$3 million decrease in the debt component of AFUDC resulting from AFUDC recorded in the third quarterreapplication 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.SFAS 71.
·Income Tax Expense decreased $5$19 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.taxes.

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

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

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 ExpensesS&P 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 for the Wyoming-Jacksons Ferry 765 kV line, which was energized and placed in service in June 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 increased $36 million primarily due to the write-off in the third quarter of 2006 of previously recorded carrying costs income associated with the 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.

Financial Condition

Credit Ratings

The rating agenciesFitch currently have APCo on stable outlook.outlook, while Moody’s placed APCo on negative outlook in the first quarter of 2008.  Current ratings are as follows:

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

Cash Flow

Cash flows for the ninethree months ended September 30,March 31, 2008 and 2007 and 2006 were as follows:

 
2007
 
2006
  2008  2007 
 
(in thousands)
  (in thousands) 
Cash and Cash Equivalents at Beginning of Period
Cash and Cash Equivalents at Beginning of Period
 $2,318 $1,741  $2,195  $2,318 
Cash Flows From (Used For):Cash Flows From (Used For):              
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  (1,049) (492)
Operating Activities  118,832   176,029 
Investing Activities  (409,179)  (200,894)
Financing Activities  290,804   24,534 
Net Increase (Decrease) in Cash and Cash Equivalents  457   (331)
Cash and Cash Equivalents at End of Period
Cash and Cash Equivalents at End of Period
 $1,269 $1,249  $2,652  $1,987 

Operating Activities

Net Cash Flows From Operating Activities were $222$119 million in 2007.2008.  APCo produced Net Incomeincome of $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$55 million during the period and a noncash expense item of $158$63 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 includedrelates to a number of items in 2008.  The $32 million cash inflow from Accounts Receivable, Net was primarily due to a settlement of allowance sales to affiliated companies.  The $20 million cash inflow from Fuel, Materials and Supplies was primarily due to a reduction in fuel inventory to reflect planned outages.  The $27 million change in Fuel Over/Under Recovery, Net resulted in a net under recovery of fuel cost in both Virginia and West Virginia.

Net Cash Flows From Operating Activities were $176 million in 2007.  APCo produced income of $70 million during the period and a noncash expense item of $59 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 had no significant items.items in 2007.

Investing Activities

Net Cash Flows Used For Investing Activities during 2008 and 2007 and 2006 primarily reflect construction expenditures of $538were $409 million and $633$201 million, respectively.  Construction expenditures areExpenditures were $159 million and $202 million in 2008 and 2007, respectively, primarily for projectsrelated to improvetransmission and distribution service reliability for transmission and distribution,projects, 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 APCo’s plants and the flue gas desulfurization projectsproject at the Amos and Mountaineer plants.Plants.  In February 2007, the flue gas desulfurization project wasenvironmental upgrades were completed atfor the Mountaineer plant.  Based upon APCo’s current forecast, APCo expects construction expenditures to be approximately $200 million for the remainder of 2007, excluding AFUDC.Plant.  In addition, APCo’s investments in the Utility Money Pool increased by $39 million and $94$262 million in 2007 and 2006, respectively.2008.  For the remainder of 2008, APCo expects construction expenditures to be approximately $620 million.

Financing Activities

Net Cash Flows From Financing Activities in 2007 were $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.  APCo also reduced its short-term borrowings from the Utility Money Pool by $35 million.

Net Cash Flows From Financing Activities were $288$291 million in 2006.  In 2006,2008.  APCo received Capital Contributions from AEP of $75 million.  APCo issued $500 million in Senior Notes and $50senior unsecured notes in March 2008.  APCo had a net decrease of $275 million in Pollution Control Bonds.borrowings from the Utility Money Pool.

Net Cash Flows From Financing Activities were $25 million in 2007.  APCo also retired First Mortgage Bondshad a net increase of $100$48 million and reduced its short-termin borrowings from the Utility Money Pool by $194 million.  In addition, APCo received funds of $68and paid $15 million related to a long-term coal purchase contract amended in March 2006.dividends on common stock.

Financing Activity

Long-term debt issuances and retirements during the first ninethree months of 20072008 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
  
Principal
Amount
 Interest Due
Type of Debt  Rate Date
  (in thousands) (%)  
Senior Unsecured Debt $500,000 7.000 2038

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

None

Liquidity

APCo has solid investment grade ratings, which provide ready access to capital markets in order to issue new debt or refinance long-term debt maturities.  In addition, APCo 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 20062007 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.above.

Significant Factors

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 a form of 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.

Litigation and Regulatory Activity

In the ordinary course of business, APCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be.  Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases which have a probable likelihood of loss and the loss amount can be estimated.  For details on regulatory proceedings and pending litigation, and regulatory proceedings, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 20062007 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 20062007 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

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

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

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

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included on the condensed consolidated balance sheetin APCo’s Condensed Consolidated Balance Sheet as of September 30, 2007March 31, 2008 and the reasons for changes in total MTM value as compared to December 31, 2006.2007.
 
Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of September 30, 2007March 31, 2008
(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)  
 
Collateral
Deposits
  Total 
Current Assets $65,385  $3,806  $-  $69,191  $139,911  $5,003  $-  $(3,346) $141,568 
Noncurrent Assets  80,970   2,240   -   83,210   77,550   852   -   (4,827)  73,575 
Total MTM Derivative Contract Assets
  146,355   6,046   -   152,401   217,461   5,855   -   (8,173)  215,143 
                                    
Current Liabilities  (47,471)  (1,129)  (3,878)  (52,478)  (129,250)  (23,448)  (3,734)  11,797   (144,635)
Noncurrent Liabilities  (48,866)  (214)  (6,478)  (55,558)  (48,108)  (54)  (4,306)  554   (51,914)
Total MTM Derivative Contract Liabilities
  (96,337)  (1,343)  (10,356)  (108,036)  (177,358)  (23,502)  (8,040)  12,351   (196,549)
                                    
Total MTM Derivative Contract Net Assets (Liabilities)
 $50,018  $4,703  $(10,356) $44,365  $40,103  $(17,647) $(8,040) $4,178  $18,594 

(a)See “Natural Gas Contracts with DETM” section of Note 16 of the 20062007 Annual Report.
 
MTM Risk Management Contract Net Assets
NineThree Months Ended September 30, 2007March 31, 2008
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2006
 $52,489 
Total MTM Risk Management Contract Net Assets at December 31, 2007 $45,870 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period (10,155) (8,194)
Fair Value of New Contracts at Inception When Entered During the Period (a) 255  - 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period 503  - 
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts(b) -  864 
Changes in Fair Value Due to Market Fluctuations During the Period (b)(c) 3,858  (204)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)(d)  3,068   1,767 
Total MTM Risk Management Contract Net Assets
 50,018  40,103 
Net Cash Flow & Fair Value Hedge Contracts 4,703  (17,647)
DETM Assignment (d)(e)  (10,356) (8,040)
Total MTM Risk Management Contract Net Assets at September 30, 2007
 $44,365 
Collateral Deposits  4,178 
Ending Net Risk Management Assets at March 31, 2008 $18,594 

(a)Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term.  The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)Represents the impact of applying AEP’s credit risk when measuring the fair value of derivative liabilities according to SFAS 157.
(c)Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)(d)“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income.  These net gains (losses) are recorded as regulatory liabilities/assetsassets/ liabilities for those subsidiaries that operate in regulated jurisdictions.
(d)(e)See “Natural Gas Contracts with DETM” section of Note 16 of the 20062007 Annual Report.
 
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

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

·The method of measuring fair value used in determining the carrying amount of total MTM asset or liability (external sources or modeled internally).
·The maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash.

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2007March 31, 2008
(in thousands)

  
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 
  
Remainder
2008
  2009  2010  2011  2012  
After
2012
  Total 
Level 1 (a) $(3,547) $(893) $(20) $-  $-  $-  $(4,460)
Level 2 (b)  6,543   12,561   9,182   637   470   -   29,393 
Level 3 (c)  25   1,152   (2,090)  (19)  (11)  -   (943)
Total $3,021  $12,820  $7,072  $618  $459  $-  $23,990 

Dedesignated Risk Management 
  Contracts (d)
  3,577   4,602   4,565   1,778   1,591   -   16,113 
Total MTM Risk Management   Contract Net Assets $6,598  $17,422  $11,637  $2,396  $2,050  $-  $40,103 

(a)“Prices Provided by Other External Sources – OTC Broker Quotes” reflectsLevel 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.  Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.on an ongoing basis.
(b)“Prices Based on Models and Other Valuation Methods” is used in absence of independent information from external sources.  Modeled information is derived using valuation models developed byLevel 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of pricesasset or liability, either directly or indirectly.  If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for underlying commodities beyondsubstantially 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 determinationfull term 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 modelsasset or valuation methods other than active quotes orliability.  Level 2 inputs primarily consist of OTC broker quotes (because ofin moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1, and OTC broker quotes that are corroborated by the lack of such data for all delivery quantities, locations and periods) incorporatesame or similar transactions that have occurred in the modelmarket.
(c)Level 3 inputs are unobservable inputs for the asset or other valuation methods,liability.  Unobservable inputs shall be used to measure fair value to the extent possible, OTC broker quotesthat the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.
(d)Dedesignated Risk Management Contracts are contracts that were originally MTM but were subsequently elected as normal under SFAS 133.  At the time of the normal election the MTM value was frozen and active quotes for deliveries in years and at locations for which such quotes are available including values determinable by other third party transactions.no longer fair valued.  This will be amortized into Revenues over the remaining life of the contract.

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

APCo is exposed to market fluctuations in energy commodity prices impacting its power operations.  Management  monitors these risks on 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.  Management does not hedge all commodity price risk.

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

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

The following table provides the detail on designated, effective cash flow hedges included in AOCI on theAPCo’s Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 20062007 to September 30, 2007.March 31, 2008.  Only contracts designated as cash flow hedges are recorded in AOCI.  Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables.  All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
NineThree Months Ended September 30, 2007March 31, 2008
(in thousands)

  
Power
  
Foreign
Currency
  
Interest
Rate
  
Total
 
Beginning Balance in AOCI December 31, 2006
 $5,332  $(164) $(7,715) $(2,547)
Changes in Fair Value  3,049   (2)  (313)  2,734 
Reclassifications from AOCI to Net Income for   
   Cash Flow Hedges Settled
  (4,788)  5   1,049   (3,734)
Ending Balance in AOCI September 30, 2007
 $3,593  $(161) $(6,979) $(3,547)
  Power  
Interest
Rate
  
Foreign
Currency
  Total 
Beginning Balance in AOCI December 31, 2007 $783  $(6,602) $(125) $(5,944)
Changes in Fair Value  (11,413)  (3,105)  206   (14,312)
Reclassifications from AOCI for Cash Flow Hedges Settled  110   387   2   499 
Ending Balance in AOCI March 31, 2008 $(10,520) $(9,320) $83  $(19,757)

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $740 thousand gain.$12.7 million loss.

Credit Risk

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

VaR Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates Value at Risk (VaR) to measure commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, at September 30, 2007,March 31, 2008, a near term typical change in commodity prices is not expected to have a material effect on APCo’s 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:

Nine Months Ended
September 30, 2007
  
Twelve Months Ended
December 31, 2006
 
Three Months Ended
March 31, 2008
Three Months Ended
March 31, 2008
  
Twelve Months Ended
December 31, 2007
 
(in thousands)
(in thousands)
  
(in thousands)
 (in thousands)  (in thousands) 
End
End
  
High
  
Average
  
Low
  
End
  
High
  
Average
  
Low
   High  Average  Low  End  High  Average  Low 
$231  $2,328  $683  $168  $756  $1,915  $658  $358 
$566          $709          $356          $161           $455        $2,328          $569         $117 

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

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

Interest Rate Risk

Management utilizes a VaRan Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which APCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest rate VaR model is based on a Monte Carlo simulationexpense for the next twelve months could exceed expected interest expense with a 95% confidence level and a one-year holding period.one-in-twenty chance of occurrence.  The riskprimary drivers of potential loss in fair value attributable to exposure to interest rates primarily related toEaR are from the existing floating rate debt (including short-term debt) as well as long-term debt with fixed interest rates was $219 million and $153 million at September 30, 2007 and December 31, 2006, respectively. Management would not expect to liquidateissuances in the entirenext twelve months.  The estimated EaR on APCo’s 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.was $4.6 million.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30,March 31, 2008 and 2007 and 2006
(in thousands)
(Unaudited)

 
Three Months Ended
  
Nine Months Ended
 
 
2007
  
2006
  
2007
  
2006
  2008  2007 
REVENUES
                  
Electric Generation, Transmission and Distribution $639,830  $588,684  $1,740,565  $1,612,735  $641,457  $601,546 
Sales to AEP Affiliates  64,099   57,177   181,015   177,557   90,090   61,545 
Other  2,647   2,740   8,134   7,338   3,480   2,637 
TOTAL
  706,576   648,601   1,929,714   1,797,630   735,027   665,728 
                        
EXPENSES
                        
Fuel and Other Consumables Used for Electric Generation  200,702   184,275   535,906   506,368   173,830   171,186 
Purchased Electricity for Resale  47,430   41,027   117,708   98,622   43,199   35,950 
Purchased Electricity from AEP Affiliates  171,288   130,826   443,519   356,682   189,595   127,601 
Other Operation  94,190   63,149   236,944   210,206   75,531   67,629 
Maintenance  49,708   53,874   146,875   138,381   57,844   45,753 
Depreciation and Amortization  51,864   61,270   142,100   158,226   62,572   59,160 
Taxes Other Than Income Taxes  23,561   24,464   67,811   70,355   23,991   21,275 
TOTAL
  638,743   558,885   1,690,863   1,538,840   626,562   528,554 
                        
OPERATING INCOME
  67,833   89,716   238,851   258,790   108,465   137,174 
                        
Other Income (Expense):
                        
Interest Income  510   2,463   1,539   6,228   2,769   639 
Carrying Costs Income (Expense)  8,701   (27,316)  22,817   (13,532)
Carrying Costs Income  9,586   3,166 
Allowance for Equity Funds Used During Construction  1,084   6,748   5,442   13,307   1,496   2,777 
Interest Expense  (44,980)  (27,103)  (121,758)  (89,024)  (44,140)  (31,823)
                        
INCOME BEFORE INCOME TAXES
  33,148   44,508   146,891   175,769 
INCOME BEFORE INCOME TAX EXPENSE  78,176   111,933 
                        
Income Tax Expense  9,090   13,972   49,325   61,992   22,863   41,706 
                        
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
  24,058   30,536   18,803   113,777   55,313   70,227 
                        
Preferred Stock Dividend Requirements Including Capital Stock Expense
and Other
  238   238   714   714 
Preferred Stock Dividend Requirements including Capital Stock Expense
  238   238 
                        
EARNINGS APPLICABLE TO COMMON STOCK
 $23,820  $30,298  $18,089  $113,063  $55,075  $69,989 

The common stock of APCo is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2007 and 2006
(in thousands)
(Unaudited)

  
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 
                     
Common Stock Dividends          (7,500)      (7,500)
Preferred Stock Dividends          (600)      (600)
Capital Stock Expense and Other      118   (114)      4 
TOTAL
                  1,795,605 
                     
COMPREHENSIVE INCOME
                    
Other Comprehensive Income, Net of Taxes:
                    
Cash Flow Hedges, Net of Tax of $7,007
              13,014   13,014 
NET INCOME
          113,777       113,777 
TOTAL COMPREHENSIVE INCOME
                  126,791 
                     
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 
                     
FIN 48 Adoption, Net of Tax          (2,685)      (2,685)
Common Stock Dividends          (25,000)      (25,000)
Preferred Stock Dividends          (600)      (600)
Capital Stock Expense and Other      117   (114)      3 
TOTAL
                  2,007,892 
                     
COMPREHENSIVE INCOME
                    
Other Comprehensive Income (Loss), Net of   Taxes:
                    
Cash Flow Hedges, Net of Tax of $539              (1,000)  (1,000)
SFAS 158 Costs Established as a Regulatory
  Asset Related to the Reapplication of
  SFAS 71, Net of Tax of $6,055
              11,245   11,245 
NET INCOME
          18,803       18,803 
TOTAL COMPREHENSIVE INCOME
                  29,048 
                     
SEPTEMBER 30, 2007
 $260,458  $1,025,111  $795,917  $(44,546) $2,036,940 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
APPALACHIAN 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 $1,269  $2,318 
Advances to Affiliates  38,573   - 
Accounts Receivable:        
  Customers  200,173   180,190 
  Affiliated Companies  79,576   98,237 
  Accrued Unbilled Revenues  34,668   46,281 
  Miscellaneous  3,366   3,400 
  Allowance for Uncollectible Accounts  (10,379)  (4,334)
 Total Accounts Receivable  307,404   323,774 
Fuel  85,468   77,077 
Materials and Supplies  66,387   56,235 
Risk Management Assets  69,191   105,376 
Accrued Tax Benefits  8,881   3,748 
Regulatory Asset for Under-Recovered Fuel Costs  -   29,526 
Prepayments and Other  39,402   20,126 
TOTAL
  616,575   618,180 
         
PROPERTY, PLANT AND EQUIPMENT
        
Electric:        
  Production  3,499,672   2,844,803 
  Transmission  1,663,553   1,620,512 
  Distribution  2,341,513   2,237,887 
Other  348,901   339,450 
Construction Work in Progress  678,095   957,626 
Total
  8,531,734   8,000,278 
Accumulated Depreciation and Amortization  2,578,083   2,476,290 
TOTAL - NET
  5,953,651   5,523,988 
         
OTHER NONCURRENT ASSETS
        
Regulatory Assets  680,644   622,153 
Long-term Risk Management Assets  83,210   88,906 
Deferred Charges and Other  149,137   163,089 
TOTAL
  912,991   874,148 
         
TOTAL ASSETS
 $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
September 30, 2007 and December 31, 2006
(Unaudited)

  
2007
  
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates $-  $34,975 
Accounts Payable:        
General  218,212   296,437 
Affiliated Companies  88,326   105,525 
Long-term Debt Due Within One Year – Nonaffiliated  399,214   324,191 
Risk Management Liabilities  52,478   81,114 
Customer Deposits  56,143   56,364 
Accrued Taxes  52,072   60,056 
Accrued Interest  62,775   30,617 
Other  109,085   142,326 
TOTAL
  1,038,305   1,131,605 
         
NONCURRENT LIABILITIES
        
Long-term Debt – Nonaffiliated  2,547,043   2,174,473 
Long-term Debt – Affiliated  100,000   100,000 
Long-term Risk Management Liabilities  55,558   64,909 
Deferred Income Taxes  931,955   957,229 
Regulatory Liabilities and Deferred Investment Tax Credits  502,425   309,724 
Deferred Credits and Other  253,239   224,439 
TOTAL
  4,390,220   3,830,774 
         
TOTAL LIABILITIES
  5,428,525   4,962,379 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  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 
Paid-in Capital  1,025,111   1,024,994 
Retained Earnings  795,917   805,513 
Accumulated Other Comprehensive Income (Loss)  (44,546)  (54,791)
TOTAL
  2,036,940   2,036,174 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 $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 Nine Months Ended September 30, 2007 and 2006
(in thousands)
(Unaudited)
  
2007
  
2006
 
OPERATING ACTIVITIES
      
Net Income
 $18,803  $113,777 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
        
  Depreciation and Amortization  142,100   158,226 
  Deferred Income Taxes  32,021   (7,753)
  Extraordinary Loss, Net of Tax  78,763   - 
  Carrying Costs (Income) Expense  (22,817)  13,532 
  Mark-to-Market of Risk Management Contracts  1,603   (3,817)
  Change in Other Noncurrent Assets  (14,627)  1,714 
  Change in Other Noncurrent Liabilities  27,247   20,171 
Changes in Certain Components of Working Capital:
        
  Accounts Receivable, Net  (87)  24,423 
  Fuel, Materials and Supplies  (11,387)  3,446 
  Margin Deposits  (2,300)  27,103 
  Accounts Payable  (38,724)  22,063 
  Customer Deposits  (221)  (23,591)
  Accrued Taxes, Net  (9,990)  43,071 
  Accrued Interest  28,596   30,780 
  Fuel Over/Under Recovery, Net  35,770   830 
  Other Current Assets  (17,520)  4,972 
  Other Current Liabilities  (25,696)  1,788 
Net Cash Flows From Operating Activities
  221,534   430,735 
         
INVESTING ACTIVITIES
        
Construction Expenditures  (537,930)  (633,164)
Change in Other Cash Deposits, Net  (29)  (873)
Change in Advances to Affiliates, Net  (38,573)  (93,764)
Proceeds from Sales of Assets  6,713   8,211 
Other  (200)  - 
Net Cash Flows Used For Investing Activities
  (570,019)  (719,590)
         
FINANCING ACTIVITIES
        
Issuance of Long-term Debt – Nonaffiliated  568,778   544,364 
Change in Advances from Affiliates, Net  (34,975)  (194,133)
Retirement of Long-term Debt – Nonaffiliated  (125,009)  (100,008)
Retirement of Cumulative Preferred Stock  (9)  (16)
Principal Payments for Capital Lease Obligations  (3,316)  (4,008)
Funds From Amended Coal Contract  -   68,078 
Amortization of Funds From Amended Coal Contract  (32,433)  (17,814)
Dividends Paid on Common Stock  (25,000)  (7,500)
Dividends Paid on Cumulative Preferred Stock  (600)  (600)
Net Cash Flows From Financing Activities
  347,436   288,363 
         
Net Decrease in Cash and Cash Equivalents
  (1,049)  (492)
Cash and Cash Equivalents at Beginning of Period
  2,318   1,741 
Cash and Cash Equivalents at End of Period
 $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 
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 Three Months Ended March 31, 2008 and 2007
(in thousands)
(Unaudited)

  Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
                
DECEMBER 31, 2006 $260,458  $1,024,994  $805,513  $(54,791) $2,036,174 
                     
FIN 48 Adoption, Net of Tax          (2,685)      (2,685)
Common Stock Dividends          (15,000)      (15,000)
Preferred Stock Dividends          (200)      (200)
Capital Stock Expense      38   (38)      - 
TOTAL                  2,018,289 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Loss, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $4,030              (7,484)  (7,484)
NET INCOME          70,227       70,227 
TOTAL COMPREHENSIVE INCOME                  62,743 
                     
MARCH 31, 2007 $260,458  $1,025,032  $857,817  $(62,275) $2,081,032 
                     
DECEMBER 31, 2007 $260,458  $1,025,149  $831,612  $(35,187) $2,082,032 
                     
EITF 06-10 Adoption, Net of Tax of $1,175          (2,181)      (2,181)
SFAS 157 Adoption, Net of Tax of $154          (286)      (286)
Capital Contribution from Parent      75,000           75,000 
Preferred Stock Dividends          (200)      (200)
Capital Stock Expense      39   (38)      1 
TOTAL                  2,154,366 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income (Loss), 
  Net of Taxes:
                    
Cash Flow Hedges, Net of Tax of $7,438
              (13,813)  (13,813)
Amortization of Pension and OPEB Deferred 
   Costs, Net of Tax of $449
              833   833 
NET INCOME          55,313       55,313 
TOTAL COMPREHENSIVE INCOME                  42,333 
                     
MARCH 31, 2008 $260,458  $1,100,188  $884,220  $(48,167) $2,196,699 

   See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


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

  2008  2007 
CURRENT ASSETS      
Cash and Cash Equivalents $2,652  $2,195 
Advances to Affiliates  261,823   - 
Accounts Receivable:        
   Customers  165,994   176,834 
   Affiliated Companies  85,530   113,582 
   Accrued Unbilled Revenues  30,578   38,397 
   Miscellaneous  1,736   2,823 
   Allowance for Uncollectible Accounts  (5,861)  (13,948) 
   Total Accounts Receivable  277,977   317,688 
Fuel  61,287   82,203 
Materials and Supplies  77,159   76,685 
Risk Management Assets  141,568   62,955 
Prepayments and Other  24,396   16,369 
TOTAL  846,862   558,095 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
   Production  3,623,812   3,625,788 
   Transmission  1,677,426   1,675,081 
   Distribution  2,400,382   2,372,687 
Other  356,552   351,827 
Construction Work in Progress  779,850   713,063 
Total  8,838,022   8,738,446 
Accumulated Depreciation and Amortization  2,610,635   2,591,833 
TOTAL - NET  6,227,387   6,146,613 
         
OTHER NONCURRENT ASSETS        
Regulatory Assets  666,207   652,739 
Long-term Risk Management Assets  73,575   72,366 
Deferred Charges and Other  205,816   191,871 
TOTAL  945,598   916,976 
         
TOTAL ASSETS $8,019,847  $7,621,684 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


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

  2008  2007 
CURRENT LIABILITIES (in thousands) 
Advances from Affiliates $-  $275,257 
Accounts Payable:        
   General  226,940   241,871 
   Affiliated Companies  102,784   106,852 
Long-term Debt Due Within One Year – Nonaffiliated  287,229   239,732 
Risk Management Liabilities  144,635   51,708 
Customer Deposits  48,828   45,920 
Accrued Taxes  53,966   58,519 
Accrued Interest  53,051   41,699 
Other  88,254   139,476 
TOTAL  1,005,687   1,201,034 
         
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated  2,952,929   2,507,567 
Long-term Debt – Affiliated  100,000   100,000 
Long-term Risk Management Liabilities  51,914   47,357 
Deferred Income Taxes  973,047   948,891 
Regulatory Liabilities and Deferred Investment Tax Credits  505,872   505,556 
Deferred Credits and Other  215,947   211,495 
TOTAL  4,799,709   4,320,866 
         
TOTAL LIABILITIES  5,805,396   5,521,900 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  17,752   17,752 
         
Commitments and Contingencies (Note 4)        
         
COMMON SHAREHOLDER’S EQUITY        
Common Stock – No Par Value:        
   Authorized – 30,000,000 Shares        
   Outstanding – 13,499,500 Shares  260,458   260,458 
Paid-in Capital  1,100,188   1,025,149 
Retained Earnings  884,220   831,612 
Accumulated Other Comprehensive Income (Loss)  (48,167)  (35,187)
TOTAL  2,196,699   2,082,032 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $8,019,847  $7,621,684 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2008 and 2007
(in thousands)
(Unaudited)

  2008  2007 
OPERATING ACTIVITIES      
Net Income $55,313  $70,227 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
 Depreciation and Amortization  62,572   59,160 
 Deferred Income Taxes  25,066   (3,901) 
 Carrying Costs Income  (9,586)  (3,166) 
 Allowance for Equity Funds Used During Construction  (1,496)  (2,777) 
 Mark-to-Market of Risk Management Contracts  (1,658)  (3,255) 
 Change in Other Noncurrent Assets  (13,102)  (9,970) 
 Change in Other Noncurrent Liabilities  (5,555)  30,172 
 Changes in Certain Components of Working Capital:        
        Accounts Receivable, Net  32,344   8,849 
        Fuel, Materials and Supplies  20,442   (1,034) 
        Accounts Payable  4,235   (19,891) 
        Accrued Taxes, Net  (2,942)  29,539 
        Accrued Interest  11,351   21,608 
        Fuel Over/Under Recovery, Net  (26,584)  12,987 
        Other Current Assets  (6,690)  2,074 
        Other Current Liabilities  (24,878)  (14,593) 
Net Cash Flows from Operating Activities  118,832   176,029 
         
INVESTING ACTIVITIES        
Construction Expenditures  (158,722)  (202,007) 
Change in Other Cash Deposits, Net  -   (29) 
Change in Advances to Affiliates, Net  (261,823)  - 
Proceeds from Sales of Assets  11,366   1,142 
Net Cash Flows Used for Investing Activities  (409,179)  (200,894) 
         
FINANCING ACTIVITIES        
Capital Contribution from Parent  75,000   - 
Issuance of Long-term Debt – Nonaffiliated  492,325   - 
Change in Advances from Affiliates, Net  (275,257)  47,885 
Retirement of Long-term Debt – Nonaffiliated  (3)  (3) 
Principal Payments for Capital Lease Obligations  (1,061)  (1,112) 
Amortization of Funds From Amended Coal Contract  -   (7,036) 
Dividends Paid on Common Stock  -   (15,000) 
Dividends Paid on Cumulative Preferred Stock  (200)  (200) 
Net Cash Flows from Financing Activities  290,804   24,534 
         
Net Increase (Decrease) in Cash and Cash Equivalents  457   (331) 
Cash and Cash Equivalents at Beginning of Period  2,195   2,318 
Cash and Cash Equivalents at End of Period $2,652  $1,987 

SUPPLEMENTARY INFORMATION      
Cash Paid for Interest, Net of Capitalized Amounts $35,527  $7,084 
Net Cash Paid for Income Taxes  338   7,775 
Noncash Acquisitions Under Capital Leases  478   444 
Construction Expenditures Included in Accounts Payable at March 31,  83,766   113,021 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


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

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

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



 




 
 
 
 
 
 

 

COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
First Quarter of 2008 Compared to First Quarter of 2007

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 purchaseReconciliation 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

ThirdFirst Quarter of 2007 Compared to ThirdFirst Quarter of 20062008
Net Income
(in millions)

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

Third Quarter of 2006
    $84 
First Quarter of 2007    $47 
              
Changes in Gross Margin:
              
Retail Margins  40       52     
Off-system Sales  7       10     
Transmission Revenues, Net  (13)    
Other  1     
Transmission Revenues  1     
Total Change in Gross Margin
      35       63 
                
Changes in Operating Expenses and Other:
                
Other Operation and Maintenance  (27)      (13)    
Depreciation and Amortization  4       2     
Taxes Other Than Income Taxes  (3)      (4)    
Other Income, Net  (1)    
Interest Expense  (4)      (4)    
Other  3     
Total Change in Operating Expenses and Other
      (31)      (16)
                
Income Tax Expense      (3)      (18)
                
Third Quarter of 2007
     $85 
First Quarter of 2008     $76 

Net Income remained relatively flatincreased $29 million to $76 million in the third quarter of 2007 compared to the third quarter of 2006.2008.  The key componentsdriver of the $1 million increase in Net Income werewas a $35$63 million increase in Gross Margin offset by an $18 million increase in Income Tax Expense and a $31$16 million increase in Operating Expenses and Other and a $3 million increase in Income Tax Expense.Other.

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

·Retail Margins increased $40$52 million primarily due to:
 ·A $35$32 million increase in rate revenues related to CSPCo’s RSP (see “Ohio Rate Matters” section of Note 3).
·A $32 million decrease in capacity settlementssettlement charges due to recent plant acquisitions and changes in relative peak demands of AEP Power Pool members under the Interconnection Agreement.
 ·A $15An $11 million increase in industrial revenue due to the addition ofincreased usage by 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 $13 million increase in CSPCo’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.customer.
 These increases were partially offset by:
 ·A $28$14 million decrease in fuel margins.
·Margins from Off-system Sales increased $7$10 million primarily due to higher physical sales volumes and power prices in the east, benefits from AEP’s eastern natural gas fleet,margins 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$13 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 UPAUnit Power Agreement for AEGCo’s Lawrenceburg Plant which began in May 2007.
·A $7$3 million increase in overhead lineboiler plant maintenance expenses due to the 2006 recognition of a regulatory assetprimarily related to PUCO orders regarding distribution service reliabilitywork performed at the Conesville and restoration costs.Stuart Plants.
·Depreciation and Amortization decreased $4$2 million primarily due to the end of amortization of IGCC preconstructionpre-construction costs, which ended in the second quarter of 2007.  The decrease in amortization of IGCC preconstructionpre-construction costs was offset by a corresponding decreaseincrease in Retail Margins.  CSPCo’s recovery of Phase 1 of IGCC preconstruction costs endedMargins in July 2007.
·Taxes Other Than Income Taxes increased $3$4 million due to increases in property taxes, and state excise taxes and gross receipt taxes.
·Interest Expense increased $4 million partiallyprimarily due to increases in long-term borrowings and short-term borrowings from the Utility Money Pool and a decreasereduction 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 recovery of storm costs and a $3 million increase related to 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.  CSPCo’s recovery of Phase 1 of IGCC preconstruction costs ended in July 2007.
·A $36 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.
·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 increased $7 million primarily due to higher trading margins.
·Transmission Revenues, Net decreased $20 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 $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 $45 million primarily due to:
·A $15 million increase in overhead line expenses, of which $7 million relates to the recognition in 2006 of a regulatory asset related to PUCO 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 $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 expenses related to CSPCo’s UPA for AEGCo’s Lawrenceburg Plant which began in May 2007.
·Depreciation and Amortization increased $4 million primarily due to the amortization of IGCC preconstruction costs beginning in 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.
·Income Tax Expense increased $27$18 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 the 20062007 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 OutstandingInterest Rate Risk

Management utilizes a VaRan Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which CSPCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest rate VaR model is based on a Monte Carlo simulationexpense for the next twelve months could exceed expected interest expense with a 95% confidence level and a one-year holding period.one-in-twenty chance of occurrence.  The riskprimary drivers of potential loss in fair value attributable to exposure to interest rates primarily related toEaR are from the existing floating rate debt (including short-term debt) as well as 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 liquidateissuances in the entirenext twelve months.  The estimated EaR on CSPCo’s 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.was $4.7 million.


 
 

 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30,March 31, 2008 and 2007 and 2006
(in thousands)
(Unaudited)

 
Three Months Ended
  
Nine Months Ended
 
 
2007
  
2006
  
2007
  
2006
  2008  2007 
REVENUES
                  
Electric Generation, Transmission and Distribution $553,518  $513,643  $1,446,632  $1,321,422  $505,324  $423,466 
Sales to AEP Affiliates  52,331   24,806   110,700   60,337   35,108   23,013 
Other  1,292   1,449   3,743   4,016   1,217   1,433 
TOTAL
  607,141   539,898   1,561,075   1,385,775   541,649   447,912 
                        
EXPENSES
                        
Fuel and Other Consumables Used for Electric Generation  103,560   90,510   255,764   231,543   85,127   75,862 
Purchased Electricity for Resale  49,619   35,449   113,765   87,902   42,186   31,311 
Purchased Electricity from AEP Affiliates  107,386   102,669   278,715   272,334   94,104   83,541 
Other Operation  83,625   66,188   207,300   179,993   73,066   61,159 
Maintenance  24,250   14,704   73,537   56,140   23,231   22,564 
Depreciation and Amortization  47,589   51,156   147,332   143,524   48,602   50,297 
Taxes Other Than Income Taxes  41,382   38,586   117,760   119,875   44,556   40,582 
TOTAL
  457,411   399,262   1,194,173   1,091,311   410,872   365,316 
                        
OPERATING INCOME
  149,730   140,636   366,902   294,464   130,777   82,596 
                        
Other Income (Expense):
                        
Interest Income  166   989   782   1,919   2,339   422 
Carrying Costs Income  1,261   1,046   3,492   3,082   1,766   1,092 
Allowance for Equity Funds Used During Construction  738   659   2,130   1,466   855   772 
Interest Expense  (19,530)  (15,813)  (51,193)  (50,247)  (19,239)  (15,281)
                        
INCOME BEFORE INCOME TAXES
  132,365   127,517   322,113   250,684 
INCOME BEFORE INCOME TAX EXPENSE  116,498   69,601 
                        
Income Tax Expense  46,911   43,496   109,656   83,064   40,345   22,620 
                        
NET INCOME
  85,454   84,021   212,457   167,620   76,153   46,981 
                        
Capital Stock Expense  39   39   118   118   39   39 
                        
EARNINGS APPLICABLE TO COMMON STOCK
 $85,415  $83,982  $212,339  $167,502  $76,114   $46,942  

The common stock of CSPCo is wholly-owned by AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
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 NineThree Months Ended September 30,March 31, 2008 and 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
 $41,026  $580,035  $361,365  $(880) $981,546 
                                   
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          (67,500)      (67,500)          (20,000)      (20,000)
Capital Stock Expense      118   (118)      -       39   (39)      - 
TOTAL
                  914,046                   1,032,995 
                                        
COMPREHENSIVE INCOME
                                        
Other Comprehensive Income, Net of Taxes:
                    
Cash Flow Hedges, Net of Tax of $2,121              3,940   3,940 
Other Comprehensive Loss, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $2,841              (5,276)  (5,276)
NET INCOME
          167,620       167,620           46,981       46,981 
TOTAL COMPREHENSIVE INCOME
                  171,560                   41,705 
                                        
SEPTEMBER 30, 2006
 $41,026  $580,153  $461,367  $3,060  $1,085,606 
MARCH 31, 2007 $41,026  $580,231  $480,707  $(27,264) $1,074,700 
                                        
DECEMBER 31, 2006
 $41,026  $580,192  $456,787  $(21,988) $1,056,017 
DECEMBER 31, 2007 $41,026  $580,349  $561,696  $(18,794) $1,164,277 
                                        
FIN 48 Adoption, Net of Tax          (3,022)      (3,022)
EITF 06-10 Adoption, Net of Tax of $589          (1,095)      (1,095)
SFAS 157 Adoption, Net of Tax of $170          (316)      (316)
Common Stock Dividends          (90,000)      (90,000)          (37,500)      (37,500)
Capital Stock Expense and Other      118   (118)      - 
Capital Stock Expense      39   (39)      - 
TOTAL
                  962,995                   1,125,366 
                                        
COMPREHENSIVE INCOME
                                        
Other Comprehensive Loss, Net of Taxes:
                    
Cash Flow Hedges, Net of Tax of $1,231              (2,285)  (2,285)
Other Comprehensive Income (Loss), Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $3,553              (6,598)  (6,598)
Amortization of Pension and OPEB Deferred Costs, Net of
Tax of $152
              283   283 
NET INCOME
          212,457       212,457           76,153       76,153 
TOTAL COMPREHENSIVE INCOME
                  210,172                   69,838 
                                        
SEPTEMBER 30, 2007
 $41,026  $580,310  $576,104  $(24,273) $1,173,167 
MARCH 31, 2008 $41,026  $580,388  $598,899  $(25,109) $1,195,204 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


 

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2007March 31, 2008 and December 31, 20062007
(in thousands)
(Unaudited)

 
2007
  
2006
  2008  2007 
CURRENT ASSETS
            
Cash and Cash Equivalents $1,695  $1,319  $1,616  $1,389 
Other Cash Deposits  45,511   1,151   53,760   53,760 
Accounts Receivable:                
Customers  53,919   49,362   68,611   57,268 
Affiliated Companies  36,934   62,866   19,614   32,852 
Accrued Unbilled Revenues  33,756   11,042   20,685   14,815 
Miscellaneous  7,792   4,895   9,354   9,905 
Allowance for Uncollectible Accounts  (842)  (546)  (2,604)  (2,563) 
Total Accounts Receivable  131,559   127,619   115,660   112,277 
Fuel  42,518   37,348   29,677   35,849 
Materials and Supplies  36,784   31,765   36,313   36,626 
Emission Allowances  3,103   3,493   14,594   16,811 
Risk Management Assets  38,776   66,238   78,080   33,558 
Prepayments and Other  15,305   19,719   14,369   9,960 
TOTAL
  315,251   288,652   344,069   300,230 
                
PROPERTY, PLANT AND EQUIPMENT
                
Electric:                
Production  2,055,590   1,896,073   2,073,747   2,072,564 
Transmission  498,180   479,119   553,853   510,107 
Distribution  1,538,056   1,475,758   1,565,111   1,552,999 
Other  204,395   191,103   202,962   198,476 
Construction Work in Progress  360,560   294,138   436,001   415,327 
Total
  4,656,781   4,336,191   4,831,674   4,749,473 
Accumulated Depreciation and Amortization  1,672,118   1,611,043   1,721,170   1,697,793 
TOTAL - NET
  2,984,663   2,725,148   3,110,504   3,051,680 
                
OTHER NONCURRENT ASSETS
                
Regulatory Assets  263,054   298,304   227,062   235,883 
Long-term Risk Management Assets  47,634   56,206   43,808   41,852 
Deferred Charges and Other  95,464   152,379   163,218   181,563 
TOTAL
  406,152   506,889   434,088   459,298 
                
TOTAL ASSETS
 $3,706,066  $3,520,689  $3,888,661  $3,811,208 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


 

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY
September 30, 2007March 31, 2008 and December 31, 20062007
(Unaudited)

 
2007
  
2006
  2008  2007 
CURRENT LIABILITIES
 
(in thousands)
  (in thousands) 
Advances from Affiliates $123,043  $696  $163,999  $95,199 
Accounts Payable:                
General  104,217   112,431   119,321   113,290 
Affiliated Companies  44,320   59,538   58,734   65,292 
Long-term Debt Due Within One Year - Nonaffiliated  112,000   - 
Long-term Debt Due Within One Year – Nonaffiliated  108,550   112,000 
Risk Management Liabilities  29,305   49,285   81,151   28,237 
Customer Deposits  41,467   34,991   43,029   43,095 
Accrued Taxes  109,477   166,551   177,810   179,831 
Other  74,852   58,011   65,117   96,892 
TOTAL
  638,681   481,503   817,711   733,836 
                
NONCURRENT LIABILITIES
                
Long-term Debt – Nonaffiliated  1,030,123   1,097,322   1,037,769   1,086,224 
Long-term Debt – Affiliated  100,000   100,000   100,000   100,000 
Long-term Risk Management Liabilities  31,907   40,477   30,982   27,419 
Deferred Income Taxes  451,456   475,888   446,119   437,306 
Regulatory Liabilities and Deferred Investment Tax Credits  171,431   179,048   162,382   165,635 
Deferred Credits and Other  109,301   90,434   98,494   96,511 
TOTAL
  1,894,218   1,983,169   1,875,746   1,913,095 
                
TOTAL LIABILITIES
  2,532,899   2,464,672   2,693,457   2,646,931 
                
Commitments and Contingencies (Note 4)                
                
COMMON SHAREHOLDER’S EQUITY
                
Common Stock – No Par Value:                
Authorized – 24,000,000 Shares                
Outstanding – 16,410,426 Shares  41,026   41,026   41,026   41,026 
Paid-in Capital  580,310   580,192   580,388   580,349 
Retained Earnings  576,104   456,787   598,899   561,696 
Accumulated Other Comprehensive Income (Loss)  (24,273)  (21,988)  (25,109)  (18,794)
TOTAL
  1,173,167   1,056,017   1,195,204   1,164,277 
                
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY
 $3,706,066  $3,520,689  $3,888,661  $3,811,208 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the NineThree Months Ended September 30,March 31, 2008 and 2007 and 2006
(in thousands)
(Unaudited)


 
2007
  
2006
  2008  2007 
OPERATING ACTIVITIES
            
Net Income
 $212,457  $167,620  $76,153  $46,981 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
                
Depreciation and Amortization  147,332   143,524   48,602   50,297 
Deferred Income Taxes  (13,959)  (5,097)  872   (716) 
Carrying Costs Income  (3,492)  (3,082)
Allowance for Equity Funds Used During Construction  (855)  (772) 
Mark-to-Market of Risk Management Contracts  3,982   (4,502)  (1,499)  1,936 
Deferred Property Taxes  57,890   49,518   21,728   18,954 
Change in Other Noncurrent Assets  (31,329)  (24,692)  (11,440)  (1,232) 
Change in Other Noncurrent Liabilities  2,713   11,752   1,292   (15,510) 
Changes in Certain Components of Working Capital:
                
Accounts Receivable, Net  (13,040)  (3,374)  (3,383)  19,839 
Fuel, Materials and Supplies  (2,332)  (8,200)  6,485   3,218 
Accounts Payable  (13,336)  31,765   (6,756)  (7,659) 
Customer Deposits  6,476   (14,565)
Accrued Taxes, Net  (44,295)  (8,981)  (2,001)  (8,651) 
Other Current Assets  (415)  26,838   (2,211)  4,531 
Other Current Liabilities  8,817   (2,878)  (20,972)  (4,515) 
Net Cash Flows From Operating Activities
  317,469   355,646 
Net Cash Flows from Operating Activities  106,015   106,701 
                
INVESTING ACTIVITIES
                
Construction Expenditures  (246,130)  (207,875)  (84,513)  (85,641) 
Change in Other Cash Deposits, Net  (44,360)  (1,151)
Change in Advances to Affiliates, Net  -   (60,417)  -   (922) 
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)
Other  150   169 
Net Cash Flows Used for Investing Activities  (84,363)  (86,394) 
                
FINANCING ACTIVITIES
                
Issuance of Long-term Debt – Nonaffiliated  44,257   - 
Change in Advances from Affiliates, Net  122,347   (17,609)  68,800   (696) 
Retirement of Long-term Debt – Nonaffiliated  (52,000)  - 
Principal Payments for Capital Lease Obligations  (2,191)  (2,308)  (725)  (693) 
Dividends Paid on Common Stock  (90,000)  (67,500)  (37,500)  (20,000) 
Net Cash Flows From (Used For) Financing Activities
  74,413   (87,417)
Net Cash Flows Used for Financing Activities  (21,425)  (21,389) 
                
Net Increase in Cash and Cash Equivalents
  376   311 
Net Increase (Decrease) in Cash and Cash Equivalents  227   (1,082) 
Cash and Cash Equivalents at Beginning of Period
  1,319   940   1,389   1,319 
Cash and Cash Equivalents at End of Period
 $1,695  $1,251  $1,616  $237 
        
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.
SUPPLEMENTARY INFORMATION        
Cash Paid for Interest, Net of Capitalized Amounts $24,351  $20,132 
Net Cash Paid (Received) for Income Taxes  2,494   (2,907)
Noncash Acquisitions Under Capital Leases  355   275 
Construction Expenditures Included in Accounts Payable at March 31,  48,392   20,636 

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

ThirdFirst Quarter of 2008 Compared to First Quarter of 2007

Reconciliation of First Quarter of 2007 Compared to ThirdFirst Quarter of 20062008
Net Income
(in millions)

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

Third Quarter of 2006
    $35 
First Quarter of 2007    $29 
              
Changes in Gross Margin:
              
Retail Margins  7       1     
FERC Municipals and Cooperatives  14       4     
Off-system Sales  7       9     
Transmission Revenues, Net  (11)    
Transmission Revenues  (1)    
Other  7     
Total Change in Gross Margin
      17       20 
                
Changes in Operating Expenses and Other:
                
Other Operation and Maintenance  (11)      (8)    
Depreciation and Amortization  18       25     
Taxes Other Than Income Taxes  (1)      (2)    
Other Income  (2)      1     
Interest Expense  (1)    
Total Change in Operating Expenses and Other
      3       16 
                
Income Tax Expense      (6)      (10)
                
Third Quarter of 2007
     $49 
First Quarter of 2008     $55 

Net Income increased $14$26 million to $49$55 million in 2007.2008.  The key drivers of the increase were a $17$20 million increase in Gross Margin and a $3$16 million decrease in Operating Expenses and Other partially offset by a $6$10 million increase in Income Tax Expense.

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

·FERC Municipals and Cooperatives margins increased $4 million due to higher prices in 2008.
·Margins from Off-system Sales increased $9 million primarily due to higher physical sales margins partially offset by lower trading margins.
·Other revenues increased $7 million primarily due to increased River Transportation Division (RTD) revenues for barging services.  RTD’s related expenses which offset the RTD revenue increase are included in Other Operation on the Condensed Consolidated Statements of Income resulting in a return approved under a regulatory order impacting I&M’s earnings.

Operating Expenses and Other changed between years as follows:

·Other Operation and Maintenance expenses increased $8 million primarily due to higher operation and maintenance expenses for RTD caused by increased barging activity.
·Depreciation and Amortization expense decreased $25 million primarily due to reduced depreciation rates reflecting longer estimated lives for Cook and Tanners Creek Plants.  Depreciation rates were reduced for the Indiana jurisdiction in June 2007 and the FERC and Michigan jurisdictions in October 2007.  See “Indiana Depreciation Study Filing” and “Michigan Depreciation Study Filing” sections of Note 4 in the 2007 Annual Report.
·Income Tax Expense increased $10 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 the 2007 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

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



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

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

Interest Rate Risk

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



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2008 and 2007
(in thousands)
(Unaudited)

  2008  2007 
REVENUES      
Electric Generation, Transmission and Distribution $431,592  $405,164 
Sales to AEP Affiliates  76,512   67,429 
Other – Affiliated  23,219   12,667 
Other – Nonaffiliated  5,826   7,609 
TOTAL  537,149   492,869 
         
EXPENSES        
Fuel and Other Consumables Used for Electric Generation  101,241   96,117 
Purchased Electricity for Resale  21,483   17,940 
Purchased Electricity from AEP Affiliates  92,641   77,513 
Other Operation  120,366   120,733 
Maintenance  51,221   42,430 
Depreciation and Amortization  31,722   56,307 
Taxes Other Than Income Taxes  19,902   17,994 
TOTAL  438,576   429,034 
         
OPERATING INCOME  98,573   63,835 
         
Other Income (Expense):        
Interest Income  829   588 
Allowance for Equity Funds Used During Construction  880   265 
Interest Expense  (19,202)  (19,821)
         
INCOME BEFORE INCOME TAX EXPENSE  81,080   44,867 
         
Income Tax Expense  25,822   15,404 
         
NET INCOME  55,258   29,463 
         
Preferred Stock Dividend Requirements  85   85 
         
EARNINGS APPLICABLE TO COMMON STOCK $55,173  $29,378 

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, 2008 and 2007
(in thousands)
(Unaudited)

  Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
DECEMBER 31, 2006 $56,584  $861,290  $386,616  $(15,051) $1,289,439 
                     
FIN 48 Adoption, Net of Tax          327       327 
Common Stock Dividends          (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 
                     
DECEMBER 31, 2007 $56,584  $861,291  $483,499  $(15,675) $1,385,699 
                     
EITF 06-10 Adoption, Net of Tax of $753          (1,398)      (1,398)
Common Stock Dividends          (18,750)      (18,750)
Preferred Stock Dividends          (85)      (85)
TOTAL                  1,365,466 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income (Loss),
  Net of Taxes:
                    
Cash Flow Hedges, Net of Tax of $3,208              (5,958)  (5,958)
Amortization of Pension and OPEB Deferred Costs, Net of         Tax of $59              110   110 
NET INCOME          55,258       55,258 
TOTAL COMPREHENSIVE INCOME                  49,410 
                     
MARCH 31, 2008 $56,584  $861,291  $518,524  $(21,523) $1,414,876 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



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

  2008  2007 
CURRENT ASSETS      
Cash and Cash Equivalents $1,731  $1,139 
Accounts Receivable:        
   Customers  69,932   70,995 
   Affiliated Companies  61,930   92,018 
   Accrued Unbilled Revenues  19,501   16,207 
   Miscellaneous  1,783   1,335 
   Allowance for Uncollectible Accounts  (2,769)  (2,711) 
   Total Accounts Receivable  150,377   177,844 
Fuel  50,379   61,342 
Materials and Supplies  142,240   141,384 
Risk Management Assets  73,579   32,365 
Accrued Tax Benefits  786   4,438 
Prepayments and Other  20,718   11,091 
TOTAL  439,810   429,603 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
   Production  3,488,509   3,529,524 
   Transmission  1,088,696   1,078,575 
   Distribution  1,211,073   1,196,397 
Other (including nuclear fuel and coal mining)  624,600   626,390 
Construction Work in Progress  134,279   122,296 
Total  6,547,157   6,553,182 
Accumulated Depreciation, Depletion and Amortization  2,969,464   2,998,416 
TOTAL - NET  3,577,693   3,554,766 
         
OTHER NONCURRENT ASSETS        
Regulatory Assets  252,438   246,435 
Spent Nuclear Fuel and Decommissioning Trusts  1,324,398   1,346,798 
Long-term Risk Management Assets  41,740   40,227 
Deferred Charges and Other  138,219   128,623 
TOTAL  1,756,795   1,762,083 
         
TOTAL ASSETS $5,774,298  $5,746,452 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




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

  2008  2007 
CURRENT LIABILITIES (in thousands) 
Advances from Affiliates $185,938  $45,064 
Accounts Payable:        
 General  91,756   184,435 
 Affiliated Companies  58,556   61,749 
Long-term Debt Due Within One Year – Nonaffiliated  50,000   145,000 
Risk Management Liabilities  76,295   27,271 
Customer Deposits  27,146   26,445 
Accrued Taxes  97,369   60,995 
Obligations Under Capital Leases  43,749   43,382 
Other  107,027   130,232 
TOTAL  737,836   724,573 
         
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated  1,424,713   1,422,427 
Long-term Risk Management Liabilities  29,587   26,348 
Deferred Income Taxes  336,058   321,716 
Regulatory Liabilities and Deferred Investment Tax Credits  755,477   789,346 
Asset Retirement Obligations  863,680   852,646 
Deferred Credits and Other  203,991   215,617 
TOTAL  3,613,506   3,628,100 
         
TOTAL LIABILITIES  4,351,342   4,352,673 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  8,080   8,080 
         
Commitments and Contingencies (Note 4)        
         
COMMON SHAREHOLDER’S EQUITY        
Common Stock – No Par Value:        
 Authorized – 2,500,000 Shares        
 Outstanding – 1,400,000 Shares  56,584   56,584 
Paid-in Capital  861,291   861,291 
Retained Earnings  518,524   483,499 
Accumulated Other Comprehensive Income (Loss)  (21,523)  (15,675)
TOTAL  1,414,876   1,385,699 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $5,774,298  $5,746,452 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2008 and 2007
(in thousands)
(Unaudited)

  2008  2007 
OPERATING ACTIVITIES      
Net Income $55,258  $29,463 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
 Depreciation and Amortization  31,722   56,307 
 Deferred Income Taxes  5,191   (3,638) 
 Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net  (881)  12,191 
 Allowance for Equity Funds Used During Construction  (880)  (265) 
 Mark-to-Market of Risk Management Contracts  (1,308)  2,316 
 Amortization of Nuclear Fuel  21,619   16,372 
 Deferred Property Taxes  (11,412)  (10,836) 
 Change in Other Noncurrent Assets  658   5,994 
 Change in Other Noncurrent Liabilities  14,234   (1,971) 
 Changes in Certain Components of Working Capital:        
     Accounts Receivable, Net  27,467   38,789 
     Fuel, Materials and Supplies  10,107   14,985 
     Accounts Payable  408   (38,233) 
     Accrued Taxes, Net  40,026   39,525 
     Accrued Rent – Rockport Plant Unit 2  18,464   18,464 
     Other Current Assets  (6,718)  737 
     Other Current Liabilities  (39,998)  (35,427) 
Net Cash Flows from Operating Activities  163,957   144,773 
         
INVESTING ACTIVITIES        
Construction Expenditures  (67,945)  (62,252) 
Purchases of Investment Securities  (132,311)  (204,874) 
Sales of Investment Securities  113,951   183,927 
Acquisitions of Nuclear Fuel  (98,385)  (5,366) 
Proceeds from Sales of Assets and Other  2,815   248 
Net Cash Flows Used for Investing Activities  (181,875)  (88,317) 
         
FINANCING ACTIVITIES        
Change in Advances from Affiliates, Net  140,874   (45,414) 
Retirement of Long-term Debt – Nonaffiliated  (95,000)  - 
Principal Payments for Capital Lease Obligations  (8,529)  (1,573) 
Dividends Paid on Common Stock  (18,750)  (10,000) 
Dividends Paid on Cumulative Preferred Stock  (85)  (85) 
Net Cash Flows from (Used for) Financing Activities  18,510   (57,072) 
         
Net Increase (Decrease) in Cash and Cash Equivalents  592   (616) 
Cash and Cash Equivalents at Beginning of Period  1,139   1,369 
Cash and Cash Equivalents at End of Period $1,731  $753 

SUPPLEMENTARY INFORMATION      
Cash Paid for Interest, Net of Capitalized Amounts $20,216  $15,048 
Net Cash Received for Income Taxes  (1,118)  (2,768)
Noncash Acquisitions Under Capital Leases  2,023   369 
Construction Expenditures Included in Accounts Payable at March 31,  16,280   20,243 
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










OHIO POWER COMPANY CONSOLIDATED



OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

First Quarter of 2008 Compared to First Quarter of 2007

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

First Quarter of 2007    $79 
        
Changes in Gross Margin:       
Retail Margins  41     
Off-system Sales  13     
Other  7     
Total Change in Gross Margin      61 
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  24     
Depreciation and Amortization  16     
Taxes Other Than Income Taxes  (3)    
Other Income  2     
Interest Expense  (8)    
Total Change in Operating Expenses and Other      31 
         
Income Tax Expense      (33)
         
First Quarter of 2008     $138 

Net Income increased $59 million to $138 million in 2008.  The key drivers of the increase were a $61 million increase in Gross Margin and a $31 million decrease in Operating Expenses and Other offset by a $33 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$41 million primarily due to higher fuel marginsthe following:
·A $58 million increase related to a coal contract amendment which reduced future deliveries to OPCo in exchange for consideration received.
·An $11 million increase related to new rates implemented as approved by the PUCO in OPCo’s RSP.
·A $6 million increase primarily related to increased usage by Ormet, an industrial customer.  See “Ormet” section 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 marketNote 3.
These increases were partially offset the increases.by:
·FERC MunicipalsA $40 million decrease related to increased fuel, consumable and Cooperatives margins increased $14 million due to the addition of new municipal contracts effective January 2007 including new rates and increased customer demand.allowance costs.
·Margins from Off-system Sales increased $7$13 million primarily due to higher physical sales volumes and power prices in the east, benefits from AEP’s eastern natural gas fleet,margins and higher trading margins.
·Transmission Revenues, Net decreased $11Other revenues increased $7 million primarily due to PJM’s revisionincreased gains on sales 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.emission allowances.

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

·Other Operation and Maintenance expenses increased $11decreased $24 million primarily due to a settlement agreement regarding alleged violations of the NSR provisions ofhigher maintenance and removal costs for planned and forced outages at the CAA, of which $14 million was allocated to I&M.  See “Federal EPA ComplaintGavin and Notice of Violation” section of Note 4.Mitchell Plants in 2007.
·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$16 million primarily due to:
 ·A $17An $18 million increase due to the settlement agreement regarding alleged violationsdecrease in amortization as a result of the NSR provisionscompletion of the CAA.  The $17 million represents OPCo’s allocationamortization of the settlement.  See “Federal EPA Complaint and Notice of Violation” section of Note 4.regulatory assets in December 2007.
 ·A $7$3 million increase in overhead line expensesdecrease due to the 2006 recognitionamortization of IGCC pre-construction costs, which ended in the second quarter of 2007.  The amortization of IGCC pre-construction costs was offset by a regulatory asset related to PUCO orders regarding distribution service reliability and restoration costs.corresponding increase in Retail Margins in 2007.
 These increasesdecreases 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 ofPlant during 2007.
·Taxes Other Than Income Taxes increased $3 million and a $2 million amortization of a regulatory liability relatedprimarily due 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.increased taxable property value.
·Interest Expense increased $11$8 million primarily due to the issuance of 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 increaseby a decrease in overhead line expenses due to the 2006 recognition of a regulatory assetinterest expense related to PUCO orders regarding distribution service reliability and restoration costs andOPCo's borrowing from the amortizationUtility Money Pool as a result 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.reduced borrowings.
·Income Tax Expense increased $21$33 million primarily due to an increase in pretax book income and state income taxes.income.

Financial Condition

Credit Ratings

The rating agenciesS&P and Fitch currently have OPCo on stable outlook.outlook, while Moody's placed OPCo on negative outlook in the first quarter of 2008. Current ratings are as follows:

 
Moody’s 
S&P
 
Fitch
      
Senior Unsecured DebtA3 BBB BBB+

Cash Flow

Cash flows for the ninethree months ended September 30,March 31, 2008 and 2007 and 2006 were as follows:
 
2007
  
2006
  2008  2007 
 
(in thousands)
  (in thousands) 
Cash and Cash Equivalents at Beginning of Period
 $1,625  $1,240  $6,666  $1,625 
Cash Flows From (Used For):                
Operating Activities  402,980   470,180   151,617   96,864 
Investing Activities  (743,260)  (703,550)  (140,253)  (306,826)
Financing Activities  351,381   233,455   (14,413)  209,598 
Net Increase in Cash and Cash Equivalents  11,101   85 
Net Decrease in Cash and Cash Equivalents  (3,049)  (364)
Cash and Cash Equivalents at End of Period
 $12,726  $1,325  $3,617  $1,261 

Operating Activities

Net Cash Flows From Operating Activities were $403$152 million in 2007.2008.  OPCo produced Net Income of $229$138 million during the period and a noncash expense item of $253$69 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.relates to 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.Receivable, Net.  Accounts Receivable, Net had a $33$22 million cash outflow partiallyprimarily due to the timing of collections of receivables.a coal contract amendment which reduced future deliveries in exchange for consideration received.

Net Cash Flows From Operating Activities were $470$97 million in 2006.2007.  OPCo produced Net Incomeincome of $202$79 million during the period and a noncash expense item of $239$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 primarily included two significantrelates to a number of items.  Accounts Receivable, Net had a $78$38 million cash inflow primarilyoutflow due to the collectiontemporary timing differences of rent receivables relatedand an increase in billed revenue for electric customers.  Fuel, Materials and Supplies had a $20 million outflow due to power sales to affiliates.an increase in coal inventories.  Accounts Payable had a $45$26 million cash outflow primarily due to timing differences foremission allowance payments to affiliates related to emission allowances and the AEP Power Pool.in January 2007.

Investing Activities

Net Cash Flows Used For Investing Activities were $743$140 million and $704$307 million in 20072008 and 2006,2007, respectively.  Construction Expenditures were $751$142 million and $715$302 million in 20072008 and 2006,2007, respectively, primarily related to environmental upgrades, as well as projects to improve service reliability for transmission and distribution.  Environmental upgrades include the installation of selective catalytic reduction equipment and the flue gas desulfurization projects at the Cardinal, Amos and Mitchell Plants.plants.  In January 2007, environmental upgrades were completed for Unit 1 and 2 at the Mitchell Plant.  Based upon OPCo’s current forecast,plant.  For the remainder of 2008, OPCo expects construction expenditures to be approximately $150 million for the remainder of 2007, excluding AFUDC.$530 million.

Financing Activities

Net Cash Flows FromUsed for Financing Activities were $351$14 million in 2007.  OPCo issued $4002008 primarily due to a net decrease of $14 million of Senior Unsecured Notes and $65 million of Pollution Control Bonds.  OPCo reducedin borrowings by $96 million from the Utility Money Pool.

Net Cash Flows From Financing Activities were $233$210 million for 2006.  OPCo issued $350in 2007 primarily due to a net increase of $216 million of Senior Unsecured Notes and $65 million of Pollution Control Bonds.  OPCo retired Notes Payable-Affiliated of $200 million.  OPCo received a Capital Contributionin borrowings from Parent of $70 million.the Utility Money Pool.

Financing Activity

Long-term debt issuances and retirements during the first ninethree months of 20072008 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
None

Retirements
Type of Debt 
Principal
Amount Paid
 Interest Rate Due Date
  (in thousands) (%)  
Notes Payable – Nonaffiliated $1,463 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 20062007 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.year-end.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, OPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be.  Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases which have a probable likelihood of loss and the loss amount can be estimated.  For details on regulatory proceedings and pending litigation, and regulatory proceedings, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 20062007 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 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 2007 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

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



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

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

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in OPCo’s Condensed Consolidated Balance sheet as of March 31, 2008 and the reasons for changes in total MTM value as compared to December 31, 2007.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of March 31, 2008
(in thousands)

  MTM Risk Management Contracts  
Cash Flow &
Fair Value Hedges
  DETM Assignment (a)  
 
Collateral
Deposits
  Total 
Current Assets $113,255  $1,939  $-  $(2,420) $112,774 
Noncurrent Assets  58,242   596   -   (3,378)  55,460 
Total MTM Derivative Contract Assets  171,497   2,535   -   (5,798)  168,234 
                     
Current Liabilities  (107,058)  (18,774)  (2,613)  10,016   (118,429)
Noncurrent Liabilities  (35,767)  (37)  (3,013)  443   (38,374)
Total MTM Derivative Contract Liabilities  (142,825)  (18,811)  (5,626)  10,459��  (156,803)
                     
Total MTM Derivative Contract Net Assets (Liabilities) $28,672  $(16,276) $(5,626) $4,661  $11,431 

(a)See “Natural Gas Contracts with DETM” section of Note 16 of the 2007 Annual Report.
MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2008
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2007 $30,248 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period  (6,055)
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  (64)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b)  1,434 
Changes in Fair Value Due to Market Fluctuations During the Period (c)  451 
Changes in Fair Value Allocated to Regulated Jurisdictions (d)  2,658 
Total MTM Risk Management Contract Net Assets  28,672 
Net Cash Flow & Fair Value Hedge Contracts  (16,276)
DETM Assignment (e)  (5,626)
Collateral Deposits  4,661 
Ending Net Risk Management Assets at March 31, 2008 $11,431 

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

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

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

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of March 31, 2008
(in thousands)

  
Remainder
2008
  2009  2010  2011  2012  
After
2012
  Total 
Level 1 (a) $(2,482) $(625) $(14) $-  $-  $-  $(3,121)
Level 2 (b)  3,427   10,392   6,762   446   329   -   21,356 
Level 3 (c)  (168)  809   (1,457)  (13)  (8)  -   (837)
Total $777  $10,576  $5,291  $433  $321  $-  $17,398 

Dedesignated Risk Management   Contracts (d)  2,503  3,220   3,194   1,244   1,113   -   11,274 
Total MTM Risk Management
  Contract Net Assets
 $3,280 $13,796  $8,485  $1,677  $1,434  $-  $28,672 


(a)Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.  Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.
(b)Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.  If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1, and OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market.
(c)Level 3 inputs are unobservable inputs for the asset or liability.  Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.
(d)Dedesignated Risk Management Contracts are contracts that were originally MTM but were subsequently elected as normal under SFAS 133.  At the time of the normal election the MTM value was frozen and no longer fair valued.  This will be amortized into Revenues over the remaining life of the contract.
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed Consolidated Balance Sheet

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

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

Management uses forward contracts and collars as cash flow hedges to lock in prices on certain transactions denominated in foreign currencies where deemed necessary.  Management does not hedge all foreign currency exposure.

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

Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2008
(in thousands)

  Power  Interest Rate  
Foreign
Currency
  Total 
Beginning Balance in AOCI December 31, 2007 $(756) $2,167  $(254) $1,157 
Changes in Fair Value  (8,025)  (1,097)  409   (8,713)
Reclassifications from AOCI for Cash Flow Hedges Settled  338   (203)  (233)  (98)
Ending Balance in AOCI March 31, 2008 $(8,443) $867  $(78) $(7,654)

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $9.9 million loss.

Credit Risk

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

VaR Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates Value at Risk (VaR) to measure commodity price risk in the risk management portfolio.  The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, at March 31, 2008, a near term typical change in commodity prices is not expected to have a material effect on OPCo’s 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, 2008  Twelve Months Ended December 31, 2007 
(in thousands)  (in thousands) 
End  High  Average  Low  End  High  Average  Low 
        $652         $780         $342         $132         $325        $2,054         $490          $90 

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

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

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which OPCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  The estimated EaR on OPCo’s debt portfolio was $10.3 million.


OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2008 and 2007
(in thousands)
(Unaudited)

  2008  2007 
REVENUES      
Electric Generation, Transmission and Distribution $555,478  $492,534 
Sales to AEP Affiliates  236,848   178,894 
Other - Affiliated  5,299   4,038 
Other - Nonaffiliated  4,563   3,975 
TOTAL  802,188   679,441 
         
EXPENSES        
Fuel and Other Consumables Used for Electric Generation  238,934   198,293 
Purchased Electricity for Resale  34,577   24,854 
Purchased Electricity from AEP Affiliates  32,516   20,966 
Other Operation  89,882   102,987 
Maintenance  48,697   59,148 
Depreciation and Amortization  68,566   84,276 
Taxes Other Than Income Taxes  51,578   48,385 
TOTAL  564,750   538,909 
         
OPERATING INCOME  237,438   140,532 
         
Other Income (Expense):        
Interest Income  2,908   412 
Carrying Costs Income  4,229   3,541 
Allowance for Equity Funds Used During Construction  544   571 
Interest Expense  (34,382)  (25,931)
         
INCOME BEFORE INCOME TAX EXPENSE  210,737   119,125 
         
Income Tax Expense  72,910   39,864 
         
NET INCOME  137,827   79,261 
         
Preferred Stock Dividend Requirements  183   183 
         
EARNINGS APPLICABLE TO COMMON STOCK $137,644  $79,078 

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

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 Three Months Ended March 31, 2008 and 2007
(in thousands)
(Unaudited)

  Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
                
DECEMBER 31, 2006 $321,201  $536,639  $1,207,265  $(56,763) $2,008,342 
                     
FIN 48 Adoption, Net of Tax          (5,380)      (5,380)
Preferred Stock Dividends          (183)      (183)
TOTAL                  2,002,779 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Loss, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $3,485              (6,471)  (6,471)
NET INCOME          79,261       79,261 
TOTAL COMPREHENSIVE INCOME                  72,790 
                     
MARCH 31, 2007 $321,201  $536,639  $1,280,963  $(63,234) $2,075,569 
                     
DECEMBER 31, 2007 $321,201  $536,640  $1,469,717  $(36,541) $2,291,017 
                     
EITF 06-10 Adoption, Net of Tax of $1,004          (1,864)      (1,864)
SFAS 157 Adoption, Net of Tax of $152          (282)      (282)
Preferred Stock Dividends          (183)      (183)
TOTAL                  2,288,688 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income (Loss), 
  Net of Taxes:
                    
  Cash Flow Hedges, Net of Tax of $4,745              (8,811)  (8,811)
  Amortization of Pension and OPEB Deferred Costs, Net of      Tax of $379              703   703 
NET INCOME          137,827       137,827 
TOTAL COMPREHENSIVE INCOME                  129,719 
                     
MARCH 31, 2008 $321,201  $536,640  $1,605,215  $(44,649) $2,418,407 

   See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2008 and December 31, 2007
(in thousands)
(Unaudited)

  2008  2007 
CURRENT ASSETS      
Cash and Cash Equivalents $3,617  $6,666 
Accounts Receivable:        
   Customers  94,852   104,783 
   Affiliated Companies  121,141   119,560 
   Accrued Unbilled Revenues  36,275   26,819 
   Miscellaneous  22,113   1,578 
   Allowance for Uncollectible Accounts  (3,451)  (3,396) 
   Total Accounts Receivable  270,930   249,344 
Fuel  96,984   92,874 
Materials and Supplies  108,467   108,447 
Risk Management Assets  112,774   44,236 
Prepayments and Other  31,207   18,300 
TOTAL  623,979   519,867 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
   Production  5,898,316   5,641,537 
   Transmission  1,073,766   1,068,387 
   Distribution  1,410,479   1,394,988 
Other  370,583   318,805 
Construction Work in Progress  531,974   716,640 
Total  9,285,118   9,140,357 
Accumulated Depreciation and Amortization  3,008,893   2,967,285 
TOTAL - NET  6,276,225   6,173,072 
         
OTHER NONCURRENT ASSETS        
Regulatory Assets  322,170   323,105 
Long-term Risk Management Assets  55,460   49,586 
Deferred Charges and Other  254,286   272,799 
TOTAL  631,916   645,490 
         
TOTAL ASSETS $7,532,120  $7,338,429 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2008 and December 31, 2007
(Unaudited)

  2008  2007 
CURRENT LIABILITIES (in thousands) 
Advances from Affiliates $87,408  $101,548 
Accounts Payable:        
   General  156,776   141,196 
   Affiliated Companies  112,964   137,389 
Short-term Debt – Nonaffiliated  -   701 
Long-term Debt Due Within One Year – Nonaffiliated  137,225   55,188 
Risk Management Liabilities  118,429   40,548 
Customer Deposits  30,682   30,613 
Accrued Taxes  200,688   185,011 
Accrued Interest  37,532   41,880 
Other  115,627   149,658 
TOTAL  997,331   883,732 
         
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated  2,505,088   2,594,410 
Long-term Debt – Affiliated  200,000   200,000 
Long-term Risk Management Liabilities  38,374   32,194 
Deferred Income Taxes  937,500   914,170 
Regulatory Liabilities and Deferred Investment Tax Credits  157,453   160,721 
Deferred Credits and Other  243,402   229,635 
TOTAL  4,081,817   4,131,130 
         
TOTAL LIABILITIES  5,079,148   5,014,862 
         
Minority Interest  17,938   15,923 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  16,627   16,627 
         
Commitments and Contingencies (Note 4)        
         
COMMON SHAREHOLDER’S EQUITY        
Common Stock – No Par Value:        
   Authorized – 40,000,000 Shares        
   Outstanding – 27,952,473 Shares  321,201   321,201 
Paid-in Capital  536,640   536,640 
Retained Earnings  1,605,215   1,469,717 
Accumulated Other Comprehensive Income (Loss)  (44,649)  (36,541) 
TOTAL  2,418,407   2,291,017 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $7,532,120  $7,338,429 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2008 and 2007
(in thousands)
(Unaudited)

  2008  2007 
OPERATING ACTIVITIES      
Net Income $137,827  $79,261 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:        
 Depreciation and Amortization  68,566   84,276 
 Deferred Income Taxes  10,850   2,851 
 Carrying Costs Income  (4,229)  (3,541) 
 Allowance for Equity Funds Used During Construction  (544)  (571) 
 Mark-to-Market of Risk Management Contracts  (5,035)  980 
 Deferred Property Taxes  20,574   17,920 
 Change in Other Noncurrent Assets  (46,438)  (3,835) 
 Change in Other Noncurrent Liabilities  7,412   (4,434) 
 Changes in Certain Components of Working Capital:        
      Accounts Receivable, Net  (21,586)  (38,070) 
      Fuel, Materials and Supplies  (4,130)  (19,684) 
      Accounts Payable  9,005   (25,807) 
      Customer Deposits  69   4,443 
      Accrued Taxes, Net  15,790   6,360 
      Accrued Interest  (4,348)  (2,986) 
      Other Current Assets  (13,020)  (3,528) 
      Other Current Liabilities  (19,146)  3,229 
Net Cash Flows from Operating Activities  151,617   96,864 
         
INVESTING ACTIVITIES        
Construction Expenditures  (142,257)  (301,635) 
Change in Other Cash Deposits, Net  -   (7,988) 
Proceeds from Sales of Assets  2,004   2,797 
Net Cash Flows Used for Investing Activities  (140,253)  (306,826) 
         
FINANCING ACTIVITIES        
Change in Short-term Debt, Net – Nonaffiliated  (701)  3,300 
Change in Advances from Affiliates, Net  (14,140)  215,846 
Retirement of Long-term Debt – Nonaffiliated  (7,463)  (7,463) 
Funds from Amended Coal Contact  10,000   - 
Principal Payments for Capital Lease Obligations  (1,926)  (1,902) 
Dividends Paid on Cumulative Preferred Stock  (183)  (183) 
Net Cash Flows from (Used for) Financing Activities  (14,413)  209,598 
         
Net Decrease in Cash and Cash Equivalents  (3,049)  (364) 
Cash and Cash Equivalents at Beginning of Period  6,666   1,625 
Cash and Cash Equivalents at End of Period $3,617  $1,261 

SUPPLEMENTARY INFORMATION      
Cash Paid for Interest, Net of Capitalized Amounts $37,491  $29,646 
Net Cash Paid (Received) for Income Taxes  10,850   (8,899)
Noncash Acquisitions Under Capital Leases  687   608 
Noncash Acquisition of Coal Land Rights  41,600   - 
Construction Expenditures Included in Accounts Payable at March 31,  21,828   98,653 
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 PronouncementsNote 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

First Quarter of 2008 Compared to First Quarter of 2007

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

First Quarter of 2007    $(20)
        
Changes in Gross Margin:       
Retail and Off-system Sales Margins  14     
Transmission Revenues  1     
Other  10     
Total Change in Gross Margin      25 
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  (7)    
Deferral of Ice Storm Costs  80     
Depreciation and Amortization  (4)    
Taxes Other Than Income Taxes  (1)    
Other Income  4     
Interest Expense  (4)    
Total Change in Operating Expenses and Other      68 
         
Income Tax Expense      (36)
         
First Quarter of 2008     $37 

Net Income (Loss) increased $57 million in 2008.  The key drivers of the increase were a $68 million decrease in Operating Expenses and Other and a $25 million increase in Gross Margin, partially offset by a $36 million increase in Income Tax Expense.

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

·Retail and Off-system Sales Margins increased $14 million primarily due to:
·A $15 million increase in retail sales margins mainly due to base rate adjustments during the year and a slight increase in KWH sales.
This increase was offset by:
·A $1 million decrease in off-system margins retained from a net decrease of $3 million from lower physical margins and lower trading margins.
·
Other revenues increased $10 million primarily due to the recognition of the sale of SO2 allowances.  See “Oklahoma 2007 Ice Storms” section of Note 3.

Operating Expenses and Other decreased between years as follows:

·Other Operation and Maintenance expenses increased $7 million primarily due to:
·A $10 million increase in production expenses primarily due to a write-off of pre-construction costs related to the cancelled Red Rock Generating Facility.  See “Red Rock Generating Facility” section of Note 3.
·An $8 million increase due to amortization of the ice storm Regulatory Asset.  See “Oklahoma 2007 Ice Storms” section of Note 3.
·A $3 million increase in transmission expense primarily due to an increase in transmission services from nonaffiliated utilities and SPP charges and fees.
·A $2 million increase in distribution maintenance expense due to increased vegetation management activities to enhance customer reliability.
This increase was partially offset by:
·A $17 million decrease due to the $21 million ice storm repair costs expensed in the first quarter 2007 compared to the $4 million ice storm repair costs expensed in the first quarter 2008.
·Deferral of Ice Storm Costs in 2008 of $80 million results from an OCC order approving recovery of ice storm costs related to storms in January and December 2007.  See “Oklahoma 2007 Ice Storms” section of Note 3.
·Depreciation and Amortization expenses increased $4 million primarily due to the amortization of regulatory assets related to the Lawton Settlement and the ice storm regulatory asset.
·Other Income increased $4 million primarily due to an increase in carrying charges related to the deferred ice storm costs and the Lawton Settlement.
·Interest Expense increased $4 million primarily due to increased long-term borrowings.
·Income Tax Expense increased $36 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 the 2007 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

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




QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

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

Interest Rate Risk

Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which PSO’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short- term debt) as well as long-term debt issuances in the next twelve months.  The estimated EaR on PSO’s debt portfolio was $600 thousand.






PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 2008 and 2007
(in thousands)
(Unaudited)

  2008  2007 
REVENUES      
Electric Generation, Transmission and Distribution $318,880  $290,080 
Sales to AEP Affiliates  15,935   24,593 
Other  1,185   640 
TOTAL  336,000   315,313 
         
EXPENSES        
Fuel and Other Consumables Used for Electric Generation  153,205   142,515 
Purchased Electricity for Resale  48,582   67,409 
Purchased Electricity from AEP Affiliates  17,269   13,484 
Other Operation  55,999   41,007 
Maintenance  34,587   43,085 
Deferral of Ice Storm Costs  (79,902)  - 
Depreciation and Amortization  26,167   22,706 
Taxes Other Than Income Taxes  10,952   10,294 
TOTAL  266,859   340,500 
         
OPERATING INCOME (LOSS)  69,141   (25,187)
         
Other Income (Expense):        
Other Income  2,487   646 
Carrying Costs Income  1,634   - 
Interest Expense  (14,941)  (11,383)
         
INCOME (LOSS) BEFORE INCOME TAX EXPENSE (CREDIT)  58,321   (35,924)
         
Income Tax Expense (Credit)  20,922   (15,498)
         
NET INCOME (LOSS)  37,399   (20,426)
         
Preferred Stock Dividend Requirements  53   53 
         
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $37,346  $(20,479)

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, 2008 and 2007
(in thousands)
(Unaudited)

  Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
                
DECEMBER 31, 2006 $157,230  $230,016  $199,262  $(1,070) $585,438 
                     
FIN 48 Adoption, Net of Tax          (386)      (386)
Capital Contribution from Parent      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 
                     
DECEMBER 31, 2007 $157,230  $310,016  $174,539  $(887) $640,898 
                     
EITF 06-10 Adoption, Net of Tax of $596          (1,107)      (1,107)
Preferred Stock Dividends          (53)      (53)
TOTAL                  639,738 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $24              45   45 
NET INCOME          37,399       37,399 
TOTAL COMPREHENSIVE INCOME                  37,444 
                     
MARCH 31, 2008 $157,230  $310,016  $210,778  $(842) $677,182 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
March 31, 2008 and December 31, 2007
(in thousands)
(Unaudited)

  2008  2007 
CURRENT ASSETS   
Cash and Cash Equivalents $1,435  $1,370 
Advances to Affiliates  -   51,202 
Accounts Receivable:        
   Customers  42,505   74,330 
   Affiliated Companies  94,257   59,835 
   Miscellaneous  14,450   10,315 
   Total Accounts Receivable  151,212   144,480 
Fuel  23,348   19,394 
Materials and Supplies  48,823   47,691 
Risk Management Assets  99,625   33,308 
Accrued Tax Benefits  27,513   31,756 
Margin Deposits  1,844   8,980 
Prepayments and Other  18,297   18,137 
TOTAL  372,097   356,318 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
   Production  1,170,963   1,110,657 
   Transmission  579,163   569,746 
   Distribution  1,369,834   1,337,038 
Other  245,669   241,722 
Construction Work in Progress  154,375   200,018 
Total  3,520,004   3,459,181 
Accumulated Depreciation and Amortization  1,187,333   1,182,171 
TOTAL - NET  2,332,671   2,277,010 
         
OTHER NONCURRENT ASSETS        
Regulatory Assets  197,860   158,731 
Long-term Risk Management Assets  5,784   3,358 
Deferred Charges and Other  75,678   48,454 
TOTAL  279,322   210,543 
         
TOTAL ASSETS $2,984,090  $2,843,871 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2008 and December 31, 2007
(Unaudited)

  2008  2007 
CURRENT LIABILITIES (in thousands) 
Advances from Affiliates $62,159  $- 
Accounts Payable:        
 General  157,712   189,032 
 Affiliated Companies  79,293   80,316 
Long-term Debt Due Within One Year – Nonaffiliated  33,700   - 
Risk Management Liabilities  82,378   27,118 
Customer Deposits  41,775   41,477 
Accrued Taxes  36,238   18,374 
Regulatory Liability for Over-Recovered Fuel Costs  16,269   11,697 
Other  37,501   57,708 
TOTAL  547,025   425,722 
         
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated  884,677   918,316 
Long-term Risk Management Liabilities  4,382   2,808 
Deferred Income Taxes  495,817   456,497 
Regulatory Liabilities and Deferred Investment Tax Credits  314,622   338,788 
Deferred Credits and Other  55,123   55,580 
TOTAL  1,754,621   1,771,989 
         
TOTAL LIABILITIES  2,301,646   2,197,711 
         
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  310,016   310,016 
Retained Earnings  210,778   174,539 
Accumulated Other Comprehensive Income (Loss)  (842)  (887) 
TOTAL  677,182   640,898 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $2,984,090  $2,843,871 

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, 2008 and 2007
(in thousands)
(Unaudited)

  2008  2007 
OPERATING ACTIVITIES      
Net Income (Loss) $37,399  $(20,426) 
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows Used for Operating Activities:        
Depreciation and Amortization  26,167   22,706 
Deferred Income Taxes  37,899   1,039 
Deferral of Ice Storm Costs  (79,902)  - 
Allowance for Equity Funds Used During Construction  (1,359)  (646) 
Mark-to-Market of Risk Management Contracts  (11,881)  4,732 
Deferred Property Taxes  (26,694)  (24,809) 
Change in Other Noncurrent Assets  22,022   5,039 
Change in Other Noncurrent Liabilities  (20,541)  (11,269) 
Changes in Certain Components of Working Capital:        
    Accounts Receivable, Net  (5,027)  16,116 
    Fuel, Materials and Supplies  (5,086)  (3,513) 
    Accounts Payable  (25,698)  6,941 
    Accrued Taxes, Net  22,107   (4,378) 
    Fuel Over/Under Recovery, Net  4,572   16,572 
    Other Current Assets  6,976   5,656 
    Other Current Liabilities  (20,759)  (31,462) 
Net Cash Flows Used for Operating Activities  (39,805)  (17,702) 
         
INVESTING ACTIVITIES        
Construction Expenditures  (73,203)  (61,301) 
Change in Advances to Affiliates, Net  51,202   - 
Other  148   (12) 
Net Cash Flows Used for Investing Activities  (21,853)  (61,313) 
         
FINANCING ACTIVITIES        
Capital Contribution from Parent  -   20,000 
Change in Advances from Affiliates, Net  62,159   59,371 
Principal Payments for Capital Lease Obligations  (383)  (370) 
Dividends Paid on Cumulative Preferred Stock  (53)  (53)
Net Cash Flows from Financing Activities  61,723   78,948 
         
Net Increase (Decrease) in Cash and Cash Equivalents  65   (67) 
Cash and Cash Equivalents at Beginning of Period  1,370   1,651 
Cash and Cash Equivalents at End of Period $1,435  $1,584 

SUPPLEMENTARY INFORMATION      
Cash Paid for Interest, Net of Capitalized Amounts $12,380  $12,921 
Net Cash Paid (Received) for Income Taxes  (19,408)  2,623 
Noncash Acquisitions Under Capital Leases  135   283 
Construction Expenditures Included in Accounts Payable at March 31,  21,086   19,038 

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 of 2008 Compared to First Quarter of 2007

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

First Quarter of 2007    $10 
        
Changes in Gross Margin:       
Retail and Off-system Sales Margins (a)  4     
Transmission Revenues  1     
Other  (1)    
Total Change in Gross Margin      4 
         
Changes in Operating Expenses and Other:        
Other Operation and Maintenance  (11)    
Depreciation and Amortization  (2)    
Taxes Other Than Income Taxes  (1)    
Other Income  2     
Interest Expense  (2)    
Total Change in Operating Expenses and Other      (14)
         
Income Tax Expense      5 
         
First Quarter of 2008     $5 

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

Net Income decreased $5 million to $5 million in 2008.  The key driver of the decrease was a $14 million increase in Operating Expenses and Other, offset by a $5 million decrease in Income Tax Expense and a $4 million increase in Gross Margin.

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

·Retail and Off-system Sales Margins increased $4 million primarily due to:
·A $3 million increase in retail sales margins related to higher fuel recovery with regards to wholesale customers.
·A $2 million increase from lower sharing of net realized off-system sales margins.
·Other revenues decreased $1 million primarily due to a $6 million decrease in gains on sales of emission allowances partially offset by a $5 million increase in revenue from coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite Company, LLC, to outside parties.

Operating Expenses and Other changed between years as follows:
·Other Operation and Maintenance expenses increased $11 million primarily due to:
·A $6 million increase in operating expenses from SWEPCo’s affiliated mining operations.
·A $2 million increase in administrative and general expenses, primarily associated with outside services and employee-related expenses.
·A $1 million increase in Maintenance expenses from planned and forced outages at the Welsh, Dolet Hills, Flint Creek, Knox Lee and Pirkey Plants.
·Depreciation and Amortization increased $2 million primarily due to higher depreciable asset balances.
·Other Income increased $2 million primarily due to an increase in the equity component of AFUDC as a result of new generation projects at the Turk Plant, Mattison Plant and Stall Unit.
·Interest Expense increased $2 million primarily due to higher interest of $3 million related to higher long-term debt partially offset by a $2 million increase in the debt component of AFUDC due to new generation projects at the Turk Plant, Mattison Plant and Stall Unit.
·Income Tax Expense decreased $5 million primarily due to a decrease in pretax book income and state income taxes.

Financial Condition

Credit Ratings

S&P and Fitch currently have SWEPCo on stable outlook, while Moody’s placed SWEPCo on negative outlook in the first quarter of 2008.  For Senior Unsecured Debt, Fitch downgraded SWEPCo from A- to BBB+.  Current ratings are as follows:

Moody’sS&PFitch
Senior Unsecured DebtBaa1BBB BBB+

Cash Flow

Cash flows for the three months ended March 31, 2008 and 2007 were as follows:

  2008  2007 
  (in thousands) 
Cash and Cash Equivalents at Beginning of Period $1,742  $2,618 
Cash Flows From (Used for):        
 Operating Activities  (4,102)  65,590 
 Investing Activities  (125,877)  (120,639)
 Financing Activities  134,140   54,331 
Net Increase (Decrease) in Cash and Cash Equivalents  4,161   (718)
Cash and Cash Equivalents at End of Period $5,903  $1,900 

Operating Activities

Net Cash Flows Used for Operating Activities were $4 million in 2008.  SWEPCo produced Net Income of $5 million during the period and had a noncash expense item of $36 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 $40 million outflow from Fuel Over/Under Recovery, Net was the result of higher fuel costs.  The $22 million inflow from Accounts Receivable, Net was primarily due to the assignment of certain ERCOT contracts to an affiliate company.  The $21 million inflow from Accrued Taxes, Net was the result of increased accruals related to property and income taxes.

Net Cash Flows From Operating Activities were $66 million in 2007.  SWEPCo produced Net Income of $10 million during the period and had 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 $20 million inflow from Accounts Receivable, Net was primarily due to the assignment of certain ERCOT contracts to an affiliate company.

Investing Activities

Cash Flows Used for Investing Activities during 2008 and 2007 were $126 million and $121 million, respectively.  Construction Expenditures of $125 million and $108 million in 2008 and 2007, respectively, were primarily related to new generation projects at the Turk Plant, Mattison Plant and Stall Unit.  In addition, during 2007, SWEPCo had a net increase of $9 million in loans to the Utility Money Pool.  For the remainder of 2008, SWEPCo expects construction expenditures to be approximately $510 million.

Financing Activities

Cash Flows From Financing Activities were $134 million during 2008.  SWEPCo received a Capital Contribution from Parent of $50 million.  SWEPCo had a net increase of $88 million in borrowings from the Utility Money Pool.

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

Financing Activity

Long-term debt issuances and retirements during the first three months of 2008 were:

Issuances

None

Retirements
Type of Debt 
Principal
Amount Paid
 Interest Rate Due Date
  (in thousands) (%)  
Notes Payable – Nonaffiliated $1,101 4.47               2011
Notes Payable – Nonaffiliated  750 Variable 2008

Liquidity

SWEPCo has solid investment grade ratings, which provide 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 contractual obligations is included in the 2007 Annual Report and has not changed significantly from year-end.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, SWEPCo is involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be.  Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases which have a probable likelihood of loss and the loss amount can be estimated.  For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 2007 Annual Report.  Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section.  Adverse results in these proceedings have the potential to materially affect results of operations, 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 20062007 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

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



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

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

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included in the condensed consolidated balance sheetSWEPCo’s Condensed Consolidated Balance Sheet as of September 30, 2007March 31, 2008 and the reasons for changes in total MTM value as compared to December 31, 2006.2007.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of September 30, 2007March 31, 2008
(in thousands)

 
MTM Risk Management Contracts
  
Cash Flow Hedges
  
DETM Assignment (a)
  
Total
  MTM Risk Management Contracts  
Cash Flow &
Fair Value Hedges
  DETM Assignment (a)  
 
Collateral
Deposits
  Total 
Current Assets $45,622  $1,401  $-  $47,023  $119,952  $160  $-  $(1,132) $118,980 
Noncurrent Assets  55,412   987   -   56,399   7,125   75   -   (26)  7,174 
Total MTM Derivative Contract Assets
  101,034   2,388   -   103,422   127,077   235   -   (1,158)  126,154 
                                    
Current Liabilities  (35,178)  (229)  (2,616)  (38,023)  (113,496)  (6)  (91)  15,096   (98,497)
Noncurrent Liabilities  (33,907)  (402)  (4,370)  (38,679)  (6,167)  -   (105)  961   (5,311)
Total MTM Derivative Contract Liabilities
  (69,085)  (631)  (6,986)  (76,702)  (119,663)  (6)  (196)  16,057   (103,808)
                                    
Total MTM Derivative Contract Net Assets (Liabilities)
 $31,949  $1,757  $(6,986) $26,720  $7,414  $229  $(196) $14,899  $22,346 

(a)See “Natural Gas Contracts with DETM” section of Note 16 inof the 20062007 Annual Report.

MTM Risk Management Contract Net Assets
NineThree Months Ended September 30, 2007March 31, 2008
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2006
 $33,042 
Total MTM Risk Management Contract Net Assets at December 31, 2007 $8,131 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period (6,663) (1,643)
Fair Value of New Contracts at Inception When Entered During the Period (a) 3,267  - 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period 340  - 
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts(b) -  326 
Changes in Fair Value Due to Market Fluctuations During the Period (b)(c) 2,411  (141)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)(d)  (448)  741 
Total MTM Risk Management Contract Net Assets
 31,949  7,414 
Net Cash Flow Hedge Contracts 1,757 
Net Cash Flow & Fair Value Hedge Contracts 229 
DETM Assignment (d)(e)  (6,986) (196)
Total MTM Risk Management Contract Net Assets at September 30, 2007
 $26,720 
Collateral Deposits  14,899 
Ending Net Risk Management Assets at March 31, 2008 $22,346 

(a)Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term.  The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)Represents the impact of applying AEP’s credit risk when measuring the fair value of derivative liabilities according to SFAS 157.
(c)Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)(d)“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income.  These net gains (losses) are recorded as regulatory liabilities/assetsassets/ liabilities for those subsidiaries that operate in regulated jurisdictions.
(d)(e)See “Natural Gas Contracts with DETM” section of Note 16 inof the 20062007 Annual Report.

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

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

·The method of measuring fair value used in determining the carrying amount of total MTM asset or liability (external sources or modeled internally).
·The maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash.

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2007March 31, 2008
(in thousands)

  
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 
  
Remainder
2008
  2009  2010  2011  2012  
After
2012
  Total 
Level 1 (a) $2,884  $(283) $-  $-  $-  $-  $2,601 
Level 2 (b)  3,168   1,551   143   (14)  -   -   4,848 
Level 3 (c)  (38)  1   2   -   -   -   (35)
Total $6,014  $1,269  $145  $(14) $-  $-  $7,414 

(a)“Prices Provided by Other External Sources – OTC Broker Quotes” reflectsLevel 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.  Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.on an ongoing basis.
(b)“Prices Based on Models and Other Valuation Methods” is used in absence of independent information from external sources.  Modeled information is derived using valuation models developed byLevel 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of pricesasset or liability, either directly or indirectly.  If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for underlying commodities beyondsubstantially 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 determinationfull term 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 modelsasset or valuation methods other than active quotes orliability.  Level 2 inputs primarily consist of OTC broker quotes (because ofin moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1, and OTC broker quotes that are corroborated by the lack of such data for all delivery quantities, locations and periods) incorporatesame or similar transactions that have occurred in the modelmarket.
(c)Level 3 inputs are unobservable inputs for the asset or other valuation methods,liability.  Unobservable inputs shall be used to measure fair value to the extent possible, OTC broker quotes and active quotesthat the observable inputs are not available, thereby allowing for deliveriessituations in years andwhich there is little, if any, market activity for the asset or liability at locations for which such quotesthe measurement date.  Level 3 inputs primarily consist of unobservable market data or are available including values determinable by other third party transactions.valued based on models and/or assumptions.


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

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

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

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

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

  
Power
  
Foreign
Currency
  
Interest Rate
  
Total
 
Beginning Balance in AOCI December 31, 2006
 $4,040  $(331) $3,553  $7,262 
Changes in Fair Value  537   (4)  (139)  394 
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled  (3,280)  10   (610)  (3,880)
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 $1,576 thousand gain.

Credit Risk

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

VaR Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates Value at Risk (VaR) to measure commodity price risk in the risk management portfolio.  The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, at September 30, 2007, a near term typical change in commodity prices is not expected to have a material effect on 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:

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

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 $138 million and $110 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.
OHIO POWER COMPANY CONSOLIDATED
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 $543,404  $558,490  $1,516,383  $1,556,193 
Sales to AEP Affiliates  205,193   198,640   564,292   502,547 
Other - Affiliated  5,749   4,400   16,604   11,975 
Other - Nonaffiliated  3,397   3,378   10,838   12,806 
TOTAL
  757,743   764,908   2,108,117   2,083,521 
                 
EXPENSES
                
Fuel and Other Consumables Used for Electric Generation  254,310   280,593   653,941   727,261 
Purchased Electricity for Resale  33,178   28,324   85,900   76,351 
Purchased Electricity from AEP Affiliates  43,147   35,423   92,858   92,086 
Other Operation  102,850   100,265   292,809   286,083 
Maintenance  45,663   44,503   155,428   163,443 
Depreciation and Amortization  84,400   82,755   253,455   239,431 
Taxes Other Than Income Taxes  47,506   47,945   146,211   143,634 
TOTAL
  611,054   619,808   1,680,602   1,728,289 
                 
OPERATING INCOME
  146,689   145,100   427,515   355,232 
                 
Other Income (Expense):
                
Interest Income  108   840   992   2,072 
Carrying Costs Income  3,644   3,502   10,779   10,336 
Allowance for Equity Funds Used During Construction  590   755   1,607   1,891 
Interest Expense  (36,262)  (24,610)  (95,927)  (72,461)
                 
INCOME BEFORE INCOME TAXES
  114,769   125,587   344,966   297,070 
                 
Income Tax Expense  39,507   42,245   116,103   95,297 
                 
NET INCOME
  75,262   83,342   228,863   201,773 
                 
Preferred Stock Dividend Requirements  183   183   549   549 
                 
EARNINGS APPLICABLE TO COMMON STOCK
 $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.
 OHIO POWER COMPANY CONSOLIDATED
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
 $321,201  $466,637  $979,354  $755  $1,767,947 
                     
Capital Contribution From Parent      70,000           70,000 
Preferred Stock Dividends          (549)      (549)
Gain on Reacquired Preferred Stock      2           2 
TOTAL
                  1,837,400 
                     
COMPREHENSIVE INCOME
                    
Other Comprehensive Income, Net of Taxes:
                    
Cash Flow Hedges, Net of Tax of $3,393              6,300   6,300 
NET INCOME
          201,773       201,773 
TOTAL COMPREHENSIVE INCOME
                  208,073 
                     
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 
                     
FIN 48 Adoption, Net of Tax          (5,380)      (5,380)
Preferred Stock Dividends          (549)      (549)
TOTAL
                  2,002,413 
                     
COMPREHENSIVE INCOME
                    
Other Comprehensive Loss, Net of Taxes:
                    
Cash Flow Hedges, Net of Tax of $1,878              (3,486)  (3,486)
NET INCOME
          228,863       228,863 
TOTAL COMPREHENSIVE INCOME
                  225,377 
                     
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
September 30, 2007 and December 31, 2006
(in thousands)
(Unaudited)

  
2007
  
2006
 
CURRENT ASSETS
      
Cash and Cash Equivalents $12,726  $1,625 
Accounts Receivable:        
  Customers  96,217   86,116 
  Affiliated Companies  102,771   108,214 
  Accrued Unbilled Revenues  28,193   10,106 
  Miscellaneous  1,235   1,819 
  Allowance for Uncollectible Accounts  (1,079)  (824)
 Total Accounts Receivable  227,337   205,431 
Fuel  125,583   120,441 
Materials and Supplies  82,377   74,840 
Emission Allowances  6,218   10,388 
Risk Management Assets  47,023   86,947 
Accrued Tax Benefits  8,476   22,909 
Prepayments and Other  27,332   18,416 
TOTAL
  537,072   540,997 
         
PROPERTY, PLANT AND EQUIPMENT
        
Electric:        
  Production  5,553,893   4,413,340 
  Transmission  1,059,631   1,030,934 
  Distribution  1,372,724   1,322,103 
Other  312,305   299,637 
Construction Work in Progress  676,841   1,339,631 
Total
  8,975,394   8,405,645 
Accumulated Depreciation and Amortization  2,921,494   2,836,584 
TOTAL - NET
  6,053,900   5,569,061 
         
OTHER NONCURRENT ASSETS
        
Regulatory Assets  354,499   414,180 
Long-term Risk Management Assets  56,399   70,092 
Deferred Charges and Other  176,964   224,403 
TOTAL
  587,862   708,675 
         
TOTAL ASSETS
 $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
September 30, 2007 and December 31, 2006
(Unaudited)

  
2007
  
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates $85,341  $181,281 
Accounts Payable:        
  General  136,467   250,025 
  Affiliated Companies  104,106   145,197 
Short-term Debt – Nonaffiliated  2,097   1,203 
Long-term Debt Due Within One Year – Nonaffiliated  22,390   17,854 
Risk Management Liabilities  38,023   73,386 
Customer Deposits  36,407   31,465 
Accrued Taxes  126,995   165,338 
Accrued Interest  45,151   35,497 
Other  119,987   123,631 
TOTAL
  716,964   1,024,877 
         
NONCURRENT LIABILITIES
        
Long-term Debt – Nonaffiliated  2,635,957   2,183,887 
Long-term Debt – Affiliated  200,000   200,000 
Long-term Risk Management Liabilities  38,679   52,929 
Deferred Income Taxes  895,839   911,221 
Regulatory Liabilities and Deferred Investment Tax Credits  167,182   185,895 
Deferred Credits and Other  263,136   219,127 
TOTAL
  4,200,793   3,753,059 
         
TOTAL LIABILITIES
  4,917,757   4,777,936 
         
Minority Interest  16,660   15,825 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  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 
Paid-in Capital  536,639   536,639 
Retained Earnings  1,430,199   1,207,265 
Accumulated Other Comprehensive Income (Loss)  (60,249)  (56,763)
TOTAL
  2,227,790   2,008,342 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 $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 Nine Months Ended September 30, 2007 and 2006
(in thousands)
(Unaudited)

  
2007
  
2006
 
OPERATING ACTIVITIES
      
Net Income
 $228,863  $201,773 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
        
Depreciation and Amortization  253,455   239,431 
Deferred Income Taxes  3,938   (18,399)
Carrying Costs Income  (10,779)  (10,336)
Mark-to-Market of Risk Management Contracts  (424)  668 
Deferred Property Taxes  54,036   54,073 
Change in Other Noncurrent Assets  (21,882)  1,732 
Change in Other Noncurrent Liabilities  8,026   15,923 
Changes in Certain Components of Working Capital:
        
Accounts Receivable, Net  (32,723)  78,307 
Fuel, Materials and Supplies  (1,245)  (25,375)
Accounts Payable  (59,925)  (44,817)
Accrued Taxes, Net  (19,997)  (27,733)
Other Current Assets  (10,544)  36,333 
Other Current Liabilities  12,181   (31,400)
Net Cash Flows From Operating Activities
  402,980   470,180 
         
INVESTING ACTIVITIES
        
Construction Expenditures  (751,161)  (715,200)
Proceeds From Sales of Assets  7,924   13,301 
Other  (23)  (1,651)
Net Cash Flows Used For Investing Activities
  (743,260)  (703,550)
         
FINANCING ACTIVITIES
        
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  (95,940)  (21,908)
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  (5,420)  (5,768)
Dividends Paid on Cumulative Preferred Stock  (549)  (549)
Net Cash Flows From Financing Activities
  351,381   233,455 
         
Net Increase in Cash and Cash Equivalents
  11,101   85 
Cash and Cash Equivalents at Beginning of Period
  1,625   1,240 
Cash and Cash Equivalents at End of Period
 $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 

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

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

Net Income decreased $5 million to $37 million in 2007.  The key drivers of the decrease were a $12 million increase in Operating Expenses and Other, partially offset by a $4 million increase in Gross Margin and a $3 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 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 and Income Taxes changed between years as follows:

·Other Operation and Maintenance expenses increased $3 million primarily due to an increase in transmission expense resulting from higher SPP administration fees and transmission services from other utilities.
·Taxes Other Than Income Taxes increased $6 million primarily due to a sales and use tax adjustment recorded in 2006.
·Income Tax Expense decreased $3 million primarily due to a decrease in pretax book 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
Net Income
(in millions)

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

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 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 sales and use tax adjustment recorded in 2006.
·Interest Expense increased $7 million primarily due to increased borrowings.
·Income Tax Expense decreased $17 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 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 $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 SWEPCo.

MTM Risk Management Contract Net Assets

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

  
MTM Risk Management Contracts
  
Cash Flow Hedges
  
Total
 
Current Assets $51,042  $75  $51,117 
Noncurrent Assets  6,481   33   6,514 
Total MTM Derivative Contract Assets
  57,523   108   57,631 
             
Current Liabilities  (38,334)  (11)  (38,345)
Noncurrent Liabilities  (6,729)  -   (6,729)
Total MTM Derivative Contract Liabilities
  (45,063)  (11)  (45,074)
             
Total MTM Derivative Contract Net Assets (Liabilities)
 $12,460  $97  $12,557 
MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2007
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2006
 $20,166 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period  (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)  1,201 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)  (5,406)
Total MTM Risk Management Contract Net Assets
  12,460 
Net Cash Flow Hedge Contracts  97 
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 total MTM asset or liability (external sources or modeled internally).
·The maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash.

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2007
(in thousands)

  
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 independent 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 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

SWEPCo is exposed to market fluctuations in energy commodity prices impacting power operations.  ManagementManagment monitors these risks on 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.  Management does not hedge all commodity price risk.

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

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

The following table provides the detail on designated, effective cash flow hedges included in AOCI on theSWEPCo’s Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 20062007 to September 30, 2007.March 31, 2008.  Only contracts designated as cash flow hedges are recorded in AOCI.  Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables.  All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
NineThree Months Ended September 30, 2007March 31, 2008
(in thousands)

  
Interest Rate
  
Foreign
Currency
  
Total
 
Beginning Balance in AOCI December 31, 2006
 $(6,435) $25  $(6,410)
Changes in Fair Value  (1,019)  589   (430)
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled  598   -   598 
Ending Balance in AOCI September 30, 2007
 $(6,856) $614  $(6,242)
  Interest Rate  
Foreign
Currency
  Total 
Beginning Balance in AOCI December 31, 2007 $(6,650) $629  $(6,021)
Changes in Fair Value  -   68   68 
Reclassifications from AOCI for Cash Flow Hedges Settled
  207   (544)  (337)
Ending Balance in AOCI March 31, 2008 $(6,443) $153  $(6,290)

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $829 thousand loss.

Credit Risk

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

VaR Associated with Risk Management Contracts

Management uses a risk measurement model, which calculates Value at Risk (VaR) to measure commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period.  Based on this VaR analysis, at September 30, 2007,March 31, 2008, a near term typical change in commodity prices is not expected to have a material effect on SWEPCo’s 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:

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
Three Months Ended March 31, 2008  Twelve Months Ended December 31, 2007 
(in thousands)  (in thousands) 
End  High  Average  Low  End  High  Average  Low 
         $84          $143           $52           $11            $17          $245            $75            $7 

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

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

Interest Rate Risk

Management utilizes a VaRan Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which SWEPCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest rate VaR model is based on a Monte Carlo simulationexpense for the next twelve months could exceed expected interest expense with a 95% confidence level and a one-year holding period.one-in-twenty chance of occurrence.  The riskprimary drivers of potential loss in fair value attributable to exposure to interest rates primarily related toEaR are from the existing floating rate debt (including short-term debt) as well as long-term debt with fixed interest rates was $41 million and $25 million at September 30, 2007 and December 31, 2006, respectively.  Management would not expect to liquidateissuances in the entirenext twelve months.  The estimated EaR on SWEPCo’s 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.was $4.3 million.


 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30,March 31, 2008 and 2007 and 2006
(in thousands)
(Unaudited)

 
Three Months Ended
  
Nine Months Ended
 
 
2007
  
2006
  
2007
  
2006
  2008  2007 
REVENUES
                  
Electric Generation, Transmission and Distribution $445,169  $440,542  $1,101,703  $1,084,185  $325,901  $327,284 
Sales to AEP Affiliates  2,839   14,692   35,491   34,871   13,592   16,415 
Other  502   1,466   1,437   2,260   300   400 
TOTAL
  448,510   456,700   1,138,631   1,121,316   339,793   344,099 
                        
EXPENSES
                        
Fuel and Other Consumables Used for Electric Generation  141,837   158,992   379,818   367,924   117,661   111,987 
Purchased Electricity for Resale  73,438   61,816   182,806   135,918   40,270   52,498 
Purchased Electricity from AEP Affiliates  22,282   18,140   61,284   58,303   20,440   22,917 
Other Operation  59,759   55,173   163,746   158,089   63,579   53,783 
Maintenance  23,205   21,120   79,265   68,008   27,468   26,339 
Depreciation and Amortization  34,605   33,079   103,395   98,655   36,136   34,122 
Taxes Other Than Income Taxes  16,767   17,107   50,298   49,254   17,419   15,991 
TOTAL
  371,893   365,427   1,020,612   936,151   322,973   317,637 
                        
OPERATING INCOME
  76,617   91,273   118,019   185,165   16,820   26,462 
                        
Other Income (Expense):
                        
Interest Income  518   822   1,999   2,277   877   705 
Allowance for Equity Funds Used During Construction  3,681   287   7,634   400   3,063   1,391 
Interest Expense  (15,966)  (13,844)  (48,691)  (40,688)  (17,142)  (15,490)
                        
INCOME BEFORE INCOME TAXES AND MINORITY
INTEREST EXPENSE
  64,850   78,538   78,961   147,154 
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND MINORITY
INTEREST EXPENSE
  3,618   13,068 
                        
Income Tax Expense  19,811   27,873   20,879   49,187 
Income Tax Expense (Credit)  (1,987)  2,621 
Minority Interest Expense  919   959   2,733   2,077   995   842 
                        
NET INCOME
  44,120   49,706   55,349   95,890   4,610   9,605 
                        
Preferred Stock Dividend Requirements  58   57   172   172   57   57 
                        
EARNINGS APPLICABLE TO COMMON STOCK
 $44,062  $49,649  $55,177  $95,718  $4,553  $9,548 
The common stock of SWEPCo is owned by a wholly-owned subsidiary of AEP.
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.

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

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the 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
 $135,660  $245,003  $407,844  $(6,129) $782,378 
                     
Common Stock Dividends          (30,000)      (30,000)
Preferred Stock Dividends          (172)      (172)
TOTAL
                  752,206 
                     
COMPREHENSIVE INCOME
                    
Other Comprehensive Loss, Net of Taxes:
                    
Cash Flow Hedges, Net of Tax of $817              (1,516)  (1,516)
NET INCOME
          95,890       95,890 
TOTAL COMPREHENSIVE INCOME
                  94,374 
                     
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 
                     
FIN 48 Adoption, Net of Tax          (1,642)      (1,642)
Capital Contribution from Parent      55,000           55,000 
Preferred Stock Dividends          (172)      (172)
TOTAL
                  874,388 
                     
COMPREHENSIVE INCOME
                    
Other Comprehensive Income, Net of Taxes:
                    
Cash Flow Hedges, Net of Tax of $90              168   168 
NET INCOME
          55,349       55,349 
TOTAL COMPREHENSIVE INCOME
                  55,517 
                     
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
September 30, 2007 and December 31, 2006
(in thousands)
(Unaudited)

  
2007
  
2006
 
CURRENT ASSETS
      
Cash and Cash Equivalents $1,852  $2,618 
Accounts Receivable:        
  Customers  50,382   88,245 
  Affiliated Companies  47,982   59,679 
  Miscellaneous  10,057   8,595 
  Allowance for Uncollectible Accounts  (24)  (130)
 Total Accounts Receivable  108,397   156,389 
Fuel  78,295   69,426 
Materials and Supplies  48,716   46,001 
Risk Management Assets  51,117   120,036 
Regulatory Asset for Under-Recovered Fuel Costs  7,300   - 
Margin Deposits  4,199   41,579 
Prepayments and Other  19,925   18,256 
TOTAL
  319,801   454,305 
         
PROPERTY, PLANT AND EQUIPMENT
        
Electric:        
  Production  1,650,597   1,576,200 
  Transmission  719,033   668,008 
  Distribution  1,298,926   1,228,948 
Other  627,145   595,429 
Construction Work in Progress  412,704   259,662 
Total
  4,708,405   4,328,247 
Accumulated Depreciation and Amortization  1,910,411   1,834,145 
TOTAL - NET
  2,797,994   2,494,102 
         
OTHER NONCURRENT ASSETS
        
Regulatory Assets  131,264   156,420 
Long-term Risk Management Assets  6,514   20,531 
Deferred Charges and Other  75,529   65,610 
TOTAL
  213,307   242,561 
         
TOTAL ASSETS
 $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
September 30, 2007 and December 31, 2006
(Unaudited)

  
2007
  
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates $155,869  $188,965 
Accounts Payable:        
General  136,071   140,424 
Affiliated Companies  65,692   68,680 
Short-term Debt – Nonaffiliated  25,897   17,143 
Long-term Debt Due Within One Year – Nonaffiliated  6,655   102,312 
Risk Management Liabilities  38,345   109,578 
Customer Deposits  39,225   48,277 
Accrued Taxes  54,784   31,591 
Regulatory Liability for Over-Recovered Fuel Costs  30,495   26,012 
Other  67,680   85,086 
TOTAL
  620,713   818,068 
         
NONCURRENT LIABILITIES
        
Long-term Debt – Nonaffiliated  818,429   576,694 
Long-term Debt – Affiliated  50,000   50,000 
Long-term Risk Management Liabilities  6,729   14,083 
Deferred Income Taxes  354,175   374,548 
Regulatory Liabilities and Deferred Investment Tax Credits  330,070   346,774 
Deferred Credits and Other  214,505   183,087 
TOTAL
  1,773,908   1,545,186 
         
TOTAL LIABILITIES
  2,394,621   2,363,254 
         
Minority Interest  1,879   1,815 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  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 
Paid-in Capital  300,003   245,003 
Retained Earnings  512,873   459,338 
Accumulated Other Comprehensive Income (Loss)  (18,631)  (18,799)
TOTAL
  929,905   821,202 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 $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 Nine Months Ended September 30, 2007 and 2006
(in thousands)
(Unaudited)

  
2007
  
2006
 
OPERATING ACTIVITIES
      
Net Income
 $55,349  $95,890 
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
        
Depreciation and Amortization  103,395   98,655 
Deferred Income Taxes  (17,863)  (24,642)
Provision for Fuel Disallowance  24,074   - 
Mark-to-Market of Risk Management Contracts  7,706   10,870 
Deferred Property Taxes  (9,172)  (9,438)
Change in Other Noncurrent Assets  2,536   20,733 
Change in Other Noncurrent Liabilities  (7,134)  (33,256)
Changes in Certain Components of Working Capital:
        
Accounts Receivable, Net  47,992   (9,872)
Fuel, Materials and Supplies  (11,572)  (26,739)
Margin Deposits  37,380   (28,492)
Accounts Payable  (21,603)  54,264 
Accrued Taxes, Net  25,556   45,514 
   Fuel Over/Under Recovery, Net  (26,891)  63,862 
Other Current Assets  (687)  2,635 
Other Current Liabilities  (28,920)  (17,263)
Net Cash Flows From Operating Activities
  180,146   242,721 
         
INVESTING ACTIVITIES
        
Construction Expenditures  (353,107)  (179,117)
Change in Advances to Affiliates, Net  -   (7,018)
Other  106   (496)
Net Cash Flows Used For Investing Activities
  (353,001)  (186,631)
         
FINANCING ACTIVITIES
        
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  (33,096)  (28,210)
Retirement of Long-term Debt – Nonaffiliated  (100,460)  (88,989)
Retirement of Cumulative Preferred Stock  -   (2)
Principal Payments for Capital Lease Obligations  (5,433)  (3,845)
Dividends Paid on Common Stock  -   (30,000)
Dividends Paid on Cumulative Preferred Stock  (172)  (172)
Net Cash Flows From (Used For) Financing Activities
  172,089   (56,343)
         
Net Decrease in Cash and Cash Equivalents
  (766)  (253)
Cash and Cash Equivalents at Beginning of Period
  2,618   3,049 
Cash and Cash Equivalents at End of Period
 $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 

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 Three Months Ended March 31, 2008 and 2007
(in thousands)
(Unaudited)

  Common Stock  Paid-in Capital  Retained Earnings  Accumulated Other Comprehensive Income (Loss)  Total 
                
DECEMBER 31, 2006 $135,660  $245,003  $459,338  $(18,799) $821,202 
                     
FIN 48 Adoption, Net of Tax          (1,642)      (1,642)
Preferred Stock Dividends          (57)      (57)
TOTAL                  819,503 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Loss, Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $39              (327)  (327)
NET INCOME          9,605       9,605 
TOTAL COMPREHENSIVE INCOME                  9,278 
                     
MARCH 31, 2007 $135,660  $245,003  $467,244  $(19,126) $828,781 
                     
DECEMBER 31, 2007 $135,660  $330,003  $523,731  $(16,439) $972,955 
                     
EITF 06-10 Adoption, Net of Tax of $622          (1,156)      (1,156)
SFAS 157 Adoption, Net of Tax of $6          10       10 
Capital Contribution from Parent      50,000           50,000 
Preferred Stock Dividends          (57)      (57)
TOTAL                  1,021,752 
                     
COMPREHENSIVE INCOME                    
Other Comprehensive Income (Loss), Net of Taxes:                    
Cash Flow Hedges, Net of Tax of $145              (269)  (269)
Amortization of Pension and OPEB Deferred Costs,
   Net of Tax of $127
              235   235 
NET INCOME          4,610       4,610 
TOTAL COMPREHENSIVE INCOME                  4,576 
                     
MARCH 31, 2008 $135,660  $380,003  $527,138  $(16,473) $1,026,328 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2008 and December 31, 2007
(in thousands)
(Unaudited)

  2008  2007 
CURRENT ASSETS      
Cash and Cash Equivalents $5,903  $1,742 
Accounts Receivable:        
   Customers  56,777   91,379 
   Affiliated Companies  41,862   33,196 
   Miscellaneous  14,213   10,544 
   Allowance for Uncollectible Accounts  (45)  (143) 
   Total Accounts Receivable  112,807   134,976 
Fuel  77,463   75,662 
Materials and Supplies  48,746   48,673 
Risk Management Assets  118,980   39,850 
Regulatory Asset for Under-Recovered Fuel Costs  22,868   5,859 
Margin Deposits  2,229   10,650 
Prepayments and Other  35,091   28,147 
TOTAL  424,087   345,559 
         
PROPERTY, PLANT AND EQUIPMENT        
Electric:        
   Production  1,743,766   1,743,198 
   Transmission  743,285   737,975 
   Distribution  1,331,547   1,312,746 
Other  633,446   631,765 
Construction Work in Progress  546,248   451,228 
Total  4,998,292   4,876,912 
Accumulated Depreciation and Amortization  1,952,226   1,939,044 
TOTAL - NET  3,046,066   2,937,868 
         
OTHER NONCURRENT ASSETS        
Regulatory Assets  118,218   133,617 
Long-term Risk Management Assets  7,174   4,073 
Deferred Charges and Other  108,267   67,269 
TOTAL  233,659   204,959 
         
TOTAL ASSETS $3,703,812  $3,488,386 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2008 and December 31, 2007
(Unaudited)

  2008  2007 
CURRENT LIABILITIES (in thousands) 
Advances from Affiliates $89,210  $1,565 
Accounts Payable:        
General  148,373   152,305 
Affiliated Companies  67,172   51,767 
Short-term Debt – Nonaffiliated  -   285 
Long-term Debt Due Within One Year – Nonaffiliated  5,156   5,906 
Risk Management Liabilities  98,497   32,629 
Customer Deposits  37,788   37,473 
Accrued Taxes  53,395   26,494 
Regulatory Liability for Over-Recovered Fuel Costs  -   22,879 
Other  72,623   76,554 
TOTAL  572,214   407,857 
         
NONCURRENT LIABILITIES        
Long-term Debt – Nonaffiliated  1,140,303   1,141,311 
Long-term Debt – Affiliated  50,000   50,000 
Long-term Risk Management Liabilities  5,311   3,334 
Deferred Income Taxes  367,814   361,806 
Regulatory Liabilities and Deferred Investment Tax Credits  327,117   334,014 
Deferred Credits and Other  208,291   210,725 
TOTAL  2,098,836   2,101,190 
         
TOTAL LIABILITIES  2,671,050   2,509,047 
         
Minority Interest  1,737   1,687 
         
Cumulative Preferred Stock Not Subject to Mandatory Redemption  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 
Paid-in Capital  380,003   330,003 
Retained Earnings  527,138   523,731 
Accumulated Other Comprehensive Income (Loss)  (16,473)  (16,439)
TOTAL  1,026,328   972,955 
         
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $3,703,812  $3,488,386 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2008 and 2007
(in thousands)
(Unaudited)

  2008  2007 
OPERATING ACTIVITIES      
Net Income $4,610  $9,605 
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating   Activities:        
Depreciation and Amortization  36,136   34,122 
Deferred Income Taxes  3,804   (6,677) 
Allowance for Equity Funds Used During Construction  (3,063)  (1,391) 
Mark-to-Market of Risk Management Contracts  (14,231)  4,857 
Deferred Property Taxes  (29,799)  (28,815) 
Change in Other Noncurrent Assets  6,589   (1,807) 
Change in Other Noncurrent Liabilities  (14,634)  (178) 
Changes in Certain Components of Working Capital:        
   Accounts Receivable, Net  22,169   20,469 
   Fuel, Materials and Supplies  (1,874)  (4,141) 
   Accounts Payable  7,398   13,806 
   Accrued Taxes, Net  21,279   36,113 
   Fuel Over/Under Recovery, Net  (39,888)  4,212 
   Other Current Assets  7,683   11,381 
   Other Current Liabilities  (10,281)  (25,966) 
Net Cash Flows from (Used for) Operating Activities  (4,102)  65,590 
         
INVESTING ACTIVITIES        
Construction Expenditures  (125,358)  (107,613) 
Change in Advances to Affiliates, Net  -   (8,959) 
Other  (519)  (4,067) 
Net Cash Flows Used for Investing Activities  (125,877)  (120,639) 
         
FINANCING ACTIVITIES        
Capital Contribution from Parent  50,000   - 
Issuance of Long-term Debt – Nonaffiliated  -   247,548 
Change in Short-term Debt, Net – Nonaffiliated  (285)  3,290 
Change in Advances from Affiliates, Net  87,645   (188,965) 
Retirement of Long-term Debt – Nonaffiliated  (1,851)  (6,395) 
Principal Payments for Capital Lease Obligations  (1,312)  (1,090) 
Dividends Paid on Cumulative Preferred Stock  (57)  (57) 
Net Cash Flows from Financing Activities  134,140   54,331 
         
Net Increase (Decrease) in Cash and Cash Equivalents  4,161   (718) 
Cash and Cash Equivalents at Beginning of Period  1,742   2,618 
Cash and Cash Equivalents at End of Period $5,903  $1,900 

SUPPLEMENTARY INFORMATION      
Cash Paid for Interest, Net of Capitalized Amounts $14,049  $16,747 
Net Cash Paid for Income Taxes  641   580 
Noncash Acquisitions Under Capital Leases  6,796   3,192 
Construction Expenditures Included in Accounts Payable at March 31,  63,973   32,460 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

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

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



 
CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to condensed financial statements that follow are a combined presentation for the Registrant Subsidiaries.  The following list indicates the registrants to which the footnotes apply:
   
1.Significant Accounting MattersAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
2.New Accounting Pronouncements and Extraordinary ItemAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
3.Rate MattersAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
4.Commitments, Guarantees and ContingenciesAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
5.AcquisitionCSPCo
6.Benefit PlansAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
7.Business SegmentsAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
8.Income TaxesAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo
9.Financing ActivitiesAPCo, CSPCo, I&M, OPCo, PSO, SWEPCo

 

1.
SIGNIFICANT ACCOUNTING MATTERS

General

The accompanying unaudited condensed financial statements and footnotes were prepared in accordance with accounting principles generally accepted in the United States of America (GAAP)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 ninethree months ended September 30, 2007March 31, 2008 are not necessarily indicative of results that may be expected for the year ending December 31, 2007.2008.  The accompanying condensed financial statements are unaudited and should be read in conjunction with the audited 20062007 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 20062007 as filed with the SEC on February 28, 2007.2008.

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 September 30, 2007 and December 31, 2006 is shown in the following table:

  
September 30,
  
December 31,
 
  
2007
  
2006
 
Components
 
(in thousands)
 
Cash Flow Hedges:
      
APCo $(3,547) $(2,547)
CSPCo  1,113   3,398 
I&M  (10,709)  (8,962)
OPCo  3,776   7,262 
PSO  (933)  (1,070)
SWEPCo  (6,242)  (6,410)
         
SFAS 158 Costs:
        
APCo $(40,999) $(52,244)
CSPCo  (25,386)  (25,386)
I&M  (6,089)  (6,089)
OPCo  (64,025)  (64,025)
SWEPCo  (12,389)  (12,389)

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

Lawrenceburg Unit Power Agreement (UPA) between CSPCo and AEGCo

In March 2007, CSPCo and AEGCo entered into a 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 option for an additional 2-year period.  I&M operates the plant under an agreement with AEGCo.

Under the UPA, CSPCo pays AEGCo for the capacity, depreciation, fuel, operation and maintenance and tax expenses.  These payments are due regardless of whether the plant is operating.  The fuel and operation and maintenance payments are based on actual costs incurred.  All expenses are trued up periodically.

CSPCo paid AEGCo $41.9 million and $57.8 million for the three and nine months ended September 30, 2007, respectively.  On its 2007 Condensed Consolidated Statement of 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
 
  
With AEPEP
 
Affiliate
 
to AEP Affiliates
 
Company
 
(in thousands)
 
PSO $61,702 $(67,759)$6,057 
SWEPCo  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 September 30, 2007
 
  
PSO
 
SWEPCo
 
Current
 
(in thousands)
 
Risk Management Assets $19,116 $22,546 
Risk Management Liabilities  (520) (614)
        
Noncurrent
       
Long-term Risk Management Assets $2,510 $2,960 
Long-term Risk Management Liabilities  -  - 

Texas Restructuring – SPP

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.  See “FASB Staff Position FIN 39-1 Amendment of FASB Interpretation No. 39” section of Note 2 for discussion of changes in netting certain balance sheet amounts.  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
 
Nine Months Ended
 
  
September 30, 2006
 
September 30, 2006
 
Company
 
(in thousands)
 
APCo $110 $708 
I&M  5,509  17,216 

2.
NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM

NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of exposure drafts or final pronouncements, management thoroughly reviews the new accounting literature to determine the relevance, if any, to the Registrant Subsidiaries’ business.  The following represents a summary of new pronouncements issued or implemented in 20072008 and standards issued but not implemented that management has determined relate to the Registrant Subsidiaries’ operations.

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

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

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

SFAS 157 “Fair Value Measurements” (SFAS 157)

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

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

In February 2008, the FASB issued FSP FAS 157-2 “Effective Date of FASB Statement No. 157” which delays the effective for interim and annual periods indate of SFAS 157 to fiscal years beginning after November 15, 2007.  Management expects2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the adoptionfinancial statements on a recurring basis (at least annually).

The Registrant Subsidiaries partially adopted SFAS 157 effective January 1, 2008.  The Registrant Subsidiaries will fully adopt SFAS 157 effective January 1, 2009 for items within the scope of this standard will impact MTM valuations of certain contracts.  Management is evaluating the effect of the adoptionFSP FAS 157-2.  The provisions of SFAS 157 onare applied prospectively, except for a) changes in fair value measurements of existing derivative financial instruments measured initially using the Registrant Subsidiaries’ results of operationstransaction price under EITF 02-3, b) existing hybrid financial instruments measured initially at fair value using the transaction price and financial condition.c) blockage discount factors.  Although the statement is applied prospectively upon adoption, in accordance with the effectprovisions of certain transactions is applied retrospectively asSFAS 157 related to EITF 02-3, APCo, CSPCo and OPCo reduced beginning retained earnings by $286 thousand (net of tax of $154 thousand), $316 thousand (net of tax of $170 thousand) and $282 thousand (net of tax of $152 thousand), respectively, for the beginningtransition adjustment.  SWEPCo’s transition adjustment was a favorable $10 thousand (net of the fiscal yeartax of application, with a cumulative effect$6 thousand) adjustment to beginning retained earnings.  The impact of considering AEP’s credit risk when measuring the appropriate balance sheet items.  Although management has not completed its analysis, management expects this cumulative effect adjustment will havefair value of liabilities, including derivatives, had an immaterial impact on fair value measurements upon adoption.

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

As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).  SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).

Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.  Level 1 inputs primarily consist of exchange traded contracts, listed equities and U.S. government treasury securities that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 inputs are inputs other than quoted prices included within level 1 that are observable for the asset or liability, either directly or indirectly.  If the asset or liability has a specified (contractual) term, a level 2 input must be observable for substantially the full term of the asset or liability.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in level 1, OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market and certain non-exchange-traded debt securities.

Level 3 inputs are unobservable inputs for the asset or liability.  Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.  Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.

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

The following table sets forth by level within the fair value hierarchy the Registrant Subsidiaries’ financial statements.  The Registrant Subsidiaries will adoptassets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2008.  As required by SFAS 157, effective January 1, 2008.financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Management’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of March 31, 2008

APCo               
  Level 1  Level 2  Level 3  Other  Total 
Assets: (in thousands) 
                
Risk Management Assets:               
Risk Management Contracts (a) $14,644  $658,242  $9,808  $(489,519) $193,175 
Cash Flow and Fair Value Hedges (a)  -   8,651   -   (2,796)  5,855 
Dedesignated Risk Management Contracts (b)  -   -   -   16,113   16,113 
Total Risk Management Assets $14,644  $666,893  $9,808  $(476,202) $215,143 
                     
Liabilities:                    
                     
Risk Management Liabilities:                    
Risk Management Contracts (a) $19,104  $628,849  $10,750  $(493,696) $165,007 
Cash Flow and Fair Value Hedges (a)  -   26,298   -   (2,796)  23,502 
DETM Assignment (c)  -   -   -   8,040   8,040 
Total Risk Management Liabilities $19,104  $655,147  $10,750  $(488,452) $196,549 
                     
Long-term Debt (e) $-  $49,714  $-  $-  $49,714 
                     
Total Liabilities $19,104  $704,861  $10,750  $(488,452) $246,263 
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of March 31, 2008

CSPCo               
  Level 1  Level 2  Level 3  Other  Total 
Assets: (in thousands) 
                
Other Cash Deposits (f) $52,589  $-  $-  $1,171  $53,760 
                     
Risk Management Assets:                    
Risk Management Contracts (a) $8,794  $374,975  $5,874  $(279,296) $110,347 
Cash Flow and Fair Value Hedges (a)  -   3,544   -   (1,679)  1,865 
Dedesignated Risk Management Contracts (b)  -   -   -   9,676   9,676 
Total Risk Management Assets $8,794  $378,519  $5,874  $(271,299) $121,888 
                     
Liabilities:                    
                     
Risk Management Liabilities:                    
Risk Management Contracts (a) $11,473  $357,104  $6,426  $(281,641) $93,362 
Cash Flow and Fair Value Hedges (b)  -   15,621   -   (1,679)  13,942 
DETM Assignment (c)  -   -   -   4,829   4,829 
Total Risk Management Liabilities $11,473  $372,725  $6,426  $(278,491) $112,133 

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of March 31, 2008

I&M               
  Level 1  Level 2  Level 3  Other  Total 
Assets: (in thousands) 
                
Risk Management Assets:               
Risk Management Contracts (a) $8,449  $348,611  $5,627  $(258,654) $104,033 
Cash Flow and Fair Value Hedges (a)  -   3,617   -   (1,627)  1,990 
Dedesignated Risk Management Contracts (b)  -   -   -   9,296   9,296 
Total Risk Management Assets $8,449  $352,228  $5,627  $(250,985) $115,319 
                     
Spent Nuclear Fuel and Decommissioning Trusts:                    
Cash and Cash Equivalents (d) $-  $13,386  $-  $10,286  $23,672 
Debt Securities  343,078   491,865   -   -   834,943 
Equity Securities  465,783   -   -   -   465,783 
Total Spent Nuclear Fuel and Decommissioning Trusts $808,861  $505,251  $-  $10,286  $1,324,398 
                     
Total Assets $817,310  $857,479  $5,627  $(240,699) $1,439,717 
                     
Liabilities:                    
                     
Risk Management Liabilities:                    
Risk Management Contracts (a) $11,022  $331,435  $6,146  $(260,756) $87,847 
Cash Flow and Fair Value Hedges (a)  -   15,022   -   (1,627)  13,395 
DETM Assignment (c)  -   -   -   4,640   4,640 
Total Risk Management Liabilities $11,022  $346,457  $6,146  $(257,743) $105,882 
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of March 31, 2008

OPCo               
  Level 1  Level 2  Level 3  Other  Total 
Assets: (in thousands) 
                
Risk Management Assets:               
Risk Management Contracts (a) $10,246  $585,650  $7,039  $(448,510) $154,425 
Cash Flow and Fair Value Hedges (a)  -   4,492   -   (1,957)  2,535 
Dedesignated Risk Management Contracts (b)  -   -   -   11,274   11,274 
Total Risk Management Assets $10,246  $590,142  $7,039  $(439,193) $168,234 
                     
Liabilities:                    
                     
Risk Management Liabilities:                    
Risk Management Contracts (a) $13,367  $564,294  $7,876  $(453,171) $132,366 
Cash Flow and Fair Value Hedges (a)  -   20,768   -   (1,957)  18,811 
DETM Assignment (c)  -   -   -   5,626   5,626 
Total Risk Management Liabilities $13,367  $585,062  $7,876  $(449,502) $156,803 
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of March 31, 2008

PSO               
  Level 1  Level 2  Level 3  Other  Total 
Assets: (in thousands) 
                
Risk Management Assets:               
Risk Management Contracts (a) $31,254  $429,634  $47  $(355,526) $105,409 
Cash Flow and Fair Value Hedges (a)  -   -   -   -   - 
Total Risk Management Assets $31,254  $429,634  $47  $(355,526) $105,409 
                     
Liabilities:                    
                     
Risk Management Liabilities:                    
Risk Management Contracts (a) $29,049  $425,533  $68  $(368,056) $86,594 
Cash Flow and Fair Value Hedges (a)  -   -   -   -   - 
DETM Assignment (c)  -   -   -   166   166 
Total Risk Management Liabilities $29,049  $425,533  $68  $(367,890) $86,760 

Assets and Liabilities Measured at Fair Value on a Recurring Basis as of March 31, 2008

SWEPCo               
  Level 1  Level 2  Level 3  Other  Total 
Assets: (in thousands) 
                
Risk Management Assets:               
Risk Management Contracts (a) $36,861  $516,029  $68  $(427,039) $125,919 
Cash Flow and Fair Value Hedges (a)  -   242   -   (7)  235 
Total Risk Management Assets $36,861  $516,271  $68  $(427,046) $126,154 
                     
Liabilities:                    
                     
Risk Management Liabilities:                    
Risk Management Contracts (a) $34,260  $511,181  $103  $(441,938) $103,606 
Cash Flow and Fair Value Hedges (a)  -   13   -   (7)  6 
DETM Assignment (c)  -   -   -   196   196 
Total Risk Management Liabilities $34,260  $511,194  $103  $(441,749) $103,808 

(a)Amounts in “Other” column primarily represent counterparty netting of risk management contracts and associated cash collateral under FASB Staff Position FIN 39-1.
(b)“Dedesignated Risk Management Contracts” are contracts that were originally MTM but were subsequently elected as normal under SFAS 133.  At the time of the normal election the MTM value was frozen and no longer fair valued.  This will be amortized into Utility Operations Revenues over the remaining life of the contract.
(c)See “Natural Gas Contracts with DETM” section of Note 16 in the 2007 Annual Report.
(d)Amounts in “Other” column primarily represent deposits-in-transit and accrued interest receivables to/from financial institutions.  Level 2 amounts primarily represent investments in money market funds.
(e)Amount represents the fair valued portion of long-term debt designated as a fair value hedge.
(f)Amounts in “Other” column primarily represent cash deposits with third parties.  Level 1 amounts primarily represent investments in money market funds.

The following table sets forth a reconciliation primarily of changes in the fair value of net trading derivatives and other investments classified as level 3 in the fair value hierarchy:

Net Risk Management Assets (Liabilities) APCo  CSPCo  I&M  OPCo  PSO  SWEPCo 
  (in thousands) 
Balance as of January 1, 2008 $(697) $(263) $(280) $(1,607) $(243) $(408)
Realized (Gain) Loss Included in Earnings 
   (or Changes in Net Assets) (a)
  (657)  (414)  (391)  (176)  29   63 
Unrealized Gain (Loss) Included in Earnings 
   (or Changes in Net Assets) Relating to 
   Assets Still Held at the Reporting Date (a)
  -   721   -   1,639   -   106 
Realized and Unrealized Gains (Losses)  
   Included in Other Comprehensive Income
  -   -   -   -   -   - 
Purchases, Issuances and Settlements  -   -   -   -   -   - 
Transfers in and/or out of Level 3 (b)  (1,026)  (596)  (572)  (693)  -   - 
Changes in Fair Value Allocated to    Regulated Jurisdictions (c)  1,438   -   724   -   193   204 
Balance as of March 31, 2008 $(942) $(552) $(519) $(837) $(21) $(35)

(a)Included in revenues on the Condensed Statement of Income for the three months ended March 31, 2008.
(b)“Transfers in and/or out of Level 3” represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.
(c)“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected on the Condensed Statements of Income.  These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.

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.  IfThe statement is applied prospectively upon adoption.

The Registrant Subsidiaries adopted SFAS 159 effective January 1, 2008.  At adoption, the Registrant Subsidiaries did not elect the fair value option promulgatedfor any assets or liabilities.

SFAS 160 “Noncontrolling Interest in Consolidated Financial Statements” (SFAS 160)

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

SFAS 160 is effective for interim and annual periods in fiscal years beginning after December 15, 2008.  The statement is applied prospectively upon adoption.  The Registrant SubsidiariesEarly adoption is prohibited.  Upon adoption, prior period financial statements will adopt SFAS 159 effective January 1, 2008.be restated for the presentation of the noncontrolling interest for comparability.  Although management has not completed its analysis, management expects that the adoption of this standard towill have an immaterial impact on the financial statements.  The Registrant Subsidiaries will adopt SFAS 160 effective January 1, 2009.

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

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

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

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

In March 2007, the FASB ratified EITF 06-10, a consensus on collateral assignment split-dollar life insurance arrangements in which an employee owns and controls the insurance policy.  Under EITF 06-10, an employer should recognize a liability for the postretirement benefit related to a collateral assignment split-dollar life insurance arrangement in accordance with SFAS 106 “Employers' Accounting for Postretirement Benefits Other Than Pension” or Accounting Principles Board Opinion No. 12 “Omnibus Opinion – 1967” if the employer has agreed to maintain a life insurance policy during the employee's retirement or to provide the employee with a death benefit based on a substantive arrangement with the employee.  In addition, an employer should recognize and measure an asset based on the nature and substance of the collateral assignment split-dollar life insurance arrangement.  EITF 06-10 requires recognition of the effects of its application as either (a) a change in accounting principle through a cumulative effect adjustment to retained earnings or other components of equity or net assets in the statement of financial position at the beginning of the year of adoption or (b) a change in accounting principle through retrospective application to all prior periods.  The Registrant Subsidiaries adopted EITF 06-10 effective January 1, 2008.  The impact of this standard was an unfavorable cumulative effect adjustment, net of tax, to beginning retained earnings as follows:
  Retained   
  Earnings Tax 
Company Reduction Amount 
  (in thousands) 
APCo $2,181 $1,175 
CSPCo  1,095  589 
I&M  1,398  753 
OPCo  1,864  1,004 
PSO  1,107  596 
SWEPCo  1,156  622 

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

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

The Registrant Subsidiaries adopted EITF 06-11 will beeffective January 1, 2008.  EITF 06-11 is applied prospectively to the income tax benefits of dividends on equity-classified employee share-based payment awards that are declared in fiscal years beginning after September 15, 2007.  Management expects that theThe adoption of this standard will havehad 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 of Settlement in FASB 
             Interpretation No. 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.  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)
 
APCo $2,685 
CSPCo  3,022 
I&M  (327)
OPCo  5,380 
PSO  386 
SWEPCo  1,642 

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

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

The Registrant Subsidiaries adopted FIN 39-1 is effective for fiscal years beginning after November 15, 2007.  Management expects thisJanuary 1, 2008.  This standard to changechanged the method of netting certain balance sheet amounts but is unable to quantify the effect.and reduced assets and liabilities.  It requires retrospective application as a change in accounting principle for all periods presented.  Theprinciple.  Consequently, the Registrant Subsidiaries will adopt FIN 39-1 effective January 1, 2008.reclassified the following amounts on their December 31, 2007 balance sheets as shown:

APCo         
Balance Sheet
Line Description
 
As Reported for
the December 2007
10-K
  
FIN 39-1
Reclassification
  
As Reported for
the March 2008
10-Q
 
Current Assets: (in thousands) 
  Risk Management Assets $64,707  $(1,752) $62,955 
  Prepayments and Other  19,675   (3,306)  16,369 
Long-term Risk Management Assets  74,954   (2,588)  72,366 
             
Current Liabilities:            
  Risk Management Liabilities  54,955   (3,247)  51,708 
  Customer Deposits  50,260   (4,340)  45,920 
Long-term Risk Management Liabilities  47,416   (59)  47,357 

CSPCo         
Balance Sheet
Line Description
 
As Reported for
the December 2007
10-K
  
FIN 39-1
Reclassification
  
As Reported for
the March 2008
10-Q
 
Current Assets: (in thousands) 
  Risk Management Assets $34,564  $(1,006) $33,558 
  Prepayments and Other  11,877   (1,917)  9,960 
Long-term Risk Management Assets  43,352   (1,500)  41,852 
             
Current Liabilities:            
  Risk Management Liabilities  30,118   (1,881)  28,237 
  Customer Deposits  45,602   (2,507)  43,095 
Long-term Risk Management Liabilities  27,454   (35)  27,419 

I&M         
Balance Sheet
Line Description
 
As Reported for
the December 2007
10-K
  
FIN 39-1
Reclassification
  
As Reported for
the March 2008
10-Q
 
Current Assets: (in thousands) 
  Risk Management Assets $33,334  $(969) $32,365 
  Prepayments and Other  12,932   (1,841)  11,091 
Long-term Risk Management Assets  41,668   (1,441)  40,227 
             
Current Liabilities:            
  Risk Management Liabilities  29,078   (1,807)  27,271 
  Customer Deposits  28,855   (2,410)  26,445 
Long-term Risk Management Liabilities  26,382   (34)  26,348 
OPCo         
Balance Sheet
Line Description
 
As Reported for
the December 2007
10-K
  
FIN 39-1
Reclassification
  
As Reported for
the March 2008
10-Q
 
Current Assets: (in thousands) 
  Risk Management Assets $45,490  $(1,254) $44,236 
  Prepayments and Other  20,532   (2,232)  18,300 
Long-term Risk Management Assets  51,334   (1,748)  49,586 
             
Current Liabilities:            
  Risk Management Liabilities  42,740   (2,192)  40,548 
  Customer Deposits  33,615   (3,002)  30,613 
Long-term Risk Management Liabilities  32,234   (40)  32,194 
PSO         
Balance Sheet
Line Description
 
As Reported for
the December 2007
10-K
  
FIN 39-1
Reclassification
  
As Reported for
the March 2008
10-Q
 
Current Assets: (in thousands) 
  Risk Management Assets $33,338  $(30) $33,308 
  Margin Deposits  9,119   (139)  8,980 
Long-term Risk Management Assets  3,376   (18)  3,358 
             
Current Liabilities:            
  Risk Management Liabilities  27,151   (33)  27,118 
  Customer Deposits  41,525   (48)  41,477 
Long-term Risk Management Liabilities  2,914   (106)  2,808 
SWEPCo        
Balance Sheet
Line Description
��
As Reported for
the December 2007
10-K
  
FIN 39-1
Reclassification
  
As Reported for
the March 2008
10-Q
Current Assets: (in thousands)
  Risk Management Assets $39,893  $(43) $39,850 
  Margin Deposits  10,814   (164)  10,650 
Long-term Risk Management Assets  4,095   (22)  4,073 
             
Current Liabilities:            
  Risk Management Liabilities  32,668   (39)  32,629 
  Customer Deposits  37,537   (64)  37,473 
Long-term Risk Management Liabilities  3,460   (126)  3,334 

For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles.  For the March 31, 2008 balance sheets, the Registrant Subsidiaries netted collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:

 March 31, 2008 
 Cash Collateral Cash Collateral 
 Received Paid 
 Netted Against Netted Against 
 Risk Management Risk Management 
 Assets Liabilities 
 (in thousands) 
APCo$8,173 $12,351 
CSPCo 4,900  7,245 
I&M 4,701  6,803 
OPCo 5,798  10,459 
PSO 977  13,507 
SWEPCo 1,158  16,057 
Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued by the FASB, management cannot determine the impact on the reporting of the Registrant Subsidiaries’ operations and financial position that may result from any such future changes.  The FASB is currently working on several projects including business combinations, revenue recognition, liabilities and equity, derivatives disclosures, emission allowances, leases, insurance, subsequent events and related tax impacts.  Management also expects to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP.  The ultimate pronouncements resulting from these and future projects could have an impact on future results of operations and financial position.

EXTRAORDINARY ITEM

APCo recorded an extraordinary loss of $118 million ($79 million, net of tax) during the second quarter of 2007 for the establishment of regulatory assets and liabilities related to the Virginia generation operations.  In 2000, APCo discontinued SFAS 71 regulatory accounting for the Virginia jurisdiction due to the passage of legislation for customer choice and deregulation.  In April 2007, Virginia passed legislation to establish electric regulation again.  See “Virginia Restructuring” in Note 3.

3.
RATE MATTERS

As discussed in the 2006 Annual Report, theThe Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.  The Rate Matters note within the 20062007 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 20072008 and updates the 20062007 Annual Report.

Ohio Rate Matters

Ohio Restructuring and Rate Stabilization Plans – Affecting CSPCo and OPCo

Ending December 31, 2008, the approved three-year RSPs provideThe current Ohio restructuring legislation permits CSPCo and OPCo increases into implement market-based rates effective January 2009, following the expiration of their RSPs on December 31, 2008.  The RSP plans include generation rates which are between PUCO approved rates and higher market rates.  In April 2008, the Ohio legislature passed legislation which allows utilities to set prices by 3%filing an Electric Security Plan along with the ability to simultaneously file a Market Rate Option.  The PUCO would have authority to approve or modify the utility’s request to set prices.  Both alternatives would involve earnings tests monitored by the PUCO.  The legislation still must be signed by the Ohio governor and 7%, respectively, effective January 1 each yearwill become law 90 days after the governor’s signature.  Management is analyzing the financial statement implications of the pending legislation on CSPCo’s and allow possible additional annualOPCo’s generation rate increasessupply business, more specifically, whether the fuel management operations of up to an average of 4% per year to recover governmentally-mandated costs.  In January 2007, CSPCo and OPCo filed withmeet the criteria for application of SFAS 71.    The financial statement impact of the pending legislation will not be known until the PUCO pursuantacts on specific proposals made by CSPCo and OPCo.  Management expects a PUCO decision in the fourth quarter of 2008.

2008 Generation Rider and Transmission Rider Rate Settlement – Affecting CSPCo and OPCo

On January 30, 2008, the PUCO approved under the RSPs a settlement agreement, among CSPCo, OPCo and other parties, related to thean additional average 4% generation rate provisionincrease and transmission cost recovery rider (“TCRR”) adjustments to recover additional governmentally-mandated costs including increased environmental costs.  Under the settlement, the PUCO also approved recovery through the TCRR of their RSPsincreased PJM costs associated with transmission line losses of $39 million each for CSPCo and OPCo.  As a result, CSPCo and OPCo established regulatory assets in the first quarter of 2008 of $12 million and $14 million, respectively, related to increase their annual generation ratesincreased PJM costs from June 2007 to December 2007.  The PUCO also approved a credit applied to the TCRR of $10 million for 2007 by $24 millionOPCo and $8 million respectively, to recover new governmentally-mandatedfor CSPCo for a reduction in PJM net congestion costs.  To the extent that collections for the TCRR items are over/under actual net costs, CSPCo and OPCo implemented these proposed increases in May 2007 subjectwill adjust billings to refund.  In October 2007,reflect actual costs including carrying costs.  Under the PUCO issued an order interms of 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 consistentsettlement, although the increased PJM costs associated with the rate revenues granted by the PUCO.  Management expects that the average 4% ridertransmission line losses will be reducedrecovered through the TCRR, these recoveries will still be applied to implementreduce the required refunds, while OPCo would implement a credit to customers’ bills.  CSPCo and OPCo intend to seek rehearing of the PUCO decision.

In October 2007, CSPCo and OPCo made a new filing with the PUCO pursuant to theannual average 4% generation rate provision of their RSPs for an additional increase in their annuallimitation.  In addition, the PUCO approved recoveries through generation rates effectiveof environmental costs and related carrying costs of $29 million for CSPCo and $5 million for OPCo.  These rate adjustments were implemented in February 2008.

In February 2008, Ormet, a major industrial customer, filed a motion to intervene and an application for rehearing of the PUCO’s January 2008 of $35RSP order claiming the settlement inappropriately shifted $4 million and $12 million, respectively,in cost recovery to recover governmentally-mandated costs and increased costs related to marginal-loss pricing.  CSPCo and OPCo will implement these proposed increases in JanuaryOrmet.  In March 2008, subject to refund until the PUCO granted Ormet’s motion to intervene.  Ormet’s rehearing application also was granted for the purpose of providing the PUCO with additional time to consider the issues a final order in the matter.raised by Ormet.  Management is unable tocannot predict the outcome of this filing and its impact on future results of operations and cash flows.matter.

In March 2007, CSPCo filed an application under the average 4% generation rate provision of their RSP to adjust the Power Acquisition Rider (PAR) related to CSPCo's acquisition of Monongahela Power Company's certified territory in Ohio. The PAR was increased to recover the cost of a new purchase power market contract to serve the load for that service territory.  The PUCO approved the requested increase in the PAR, which is expected to increase CSPCo's revenues 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 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.  The Office of Consumers’ Counsel, the Ohio Partners for Affordable Energy, the Ohio Energy Group and the PUCO staff supported this settlement agreement.  In May 2007, the PUCO adopted the settlement agreement in its entirety.

Customer Choice Deferrals – Affecting CSPCo and OPCo

CSPCo’s and OPCo’s restructuring settlement agreement, approved by the PUCO in 2000, allows CSPCo and OPCo to 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 changesfor the distribution rates.business.  Through September 30, 2007,March 31, 2008, CSPCo and OPCo incurred $53$54 million and $54$55 million, respectively, of such costs and established regulatory assets for future recovery of $27 million each, for the future recovery of such costs.  CSPCo and OPCo also have the right to recover $6 million and $7 million, respectively,net of equity carrying costs in addition to these regulatory assets.  In 2007,of $7 million for CSPCo and OPCo incurred $3$8 million and $4 million, respectively, of such costs and established regulatory assets of $2 million each for such costs.OPCo.  Management believes that the deferred customer choice implementationthese costs were prudently incurred to implement customer choice in Ohio and are probable of recovery in future distribution rates.  However, failure of the PUCO to recoverultimately approve recovery of 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;costs; Phase 2, concurrent recovery of construction-financing costs; and Phase 3, recovery or refund in distribution rates of any difference between the generation rates which may be a market-based standard service offer price for generation and the expected higher cost of operating and maintaining the plant, including a return on and return of the ultimateprojected 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.plant.

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 anotheran order approving a tariff to recover Phase 1 pre-construction costs over a period of no more than twelve months effective July 1, 2006.  Through September 30, 2007,During that period CSPCo and OPCo each recorded pre-construction IGCC regulatory assets of $10 million and each collected the entire $12 million approved by the PUCO.  As of September 30, 2007, CSPCo and OPCo have recorded a liability of $2 million each for the over-recovered portion. CSPCo and OPCo expect to incur additionalin pre-construction costs equal to or greater than the $12 million each recovered.  costs.

The PUCO indicatedorder also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant within five years of the June 2006 PUCO order, all Phase 1 costs collected for pre-construction costs associated with items that may be utilized in projects at other sites, must be refunded to Ohio ratepayers with interest.  The PUCO deferred ruling on cost recovery for Phases 2 and 3 untilpending further hearings are held.  A date for further rehearings has not been set.hearings.

In August 2006, the Ohio Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy Solutions and Ohio Energy Groupintervenors filed four separate appeals of the PUCO’s order in the IGCC proceeding.  In March 2008, the Ohio Supreme Court issued its opinion affirming in part, and reversing in part the PUCO’s order and remanded the matter back to the PUCO.  The Ohio Supreme Court heard oral arguments for these appeals in October 2007.  Management believesheld 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 OPCowhile there could be requiredan opportunity under existing law to refund Phase 1 cost-related recoveries.

Pending the outcome of the Supreme Court litigation, CSPCo and OPCo announced they may delay the start of constructionrecover a portion of the IGCC plant. costs, traditional rate making procedures would apply.  The Ohio Supreme Court did not address the matter of refunding the Phase 1 cost recovery and declined to create an exception to its precedent of denying claims for refund from approved orders of the PUCO.

Recent estimates of the cost to build anthe proposed IGCC plant have escalated to $2.2are approximately $2.7 billion.  In light of the Ohio Supreme Court’s decision, CSPCo and OPCo may needwill not start construction of the IGCC plant and will await the outcome of the ongoing legislative process in Ohio to request an extensiondetermine if it provides sufficient assurance of cost recovery to the 5-year start of construction requirement if the commencement of construction is delayed beyond 2011.warrant commencing construction.

Distribution Reliability Plan – Affecting CSPCo and OPCo

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-month period beginning July 2007.

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, in accordance with a settlement agreement between CSPCo and OPCo, Ormet, its employees’ union and certain other interested parties that was approved by the PUCO in November 2006.PUCO.  The settlement agreement providesallows for the recovery in 2007 and 2008 by CSPCo and OPCo of the difference between the $43 per MWH to be paid by Ormet pays for power and a PUCO-approved market price, if higher.  The PUCO approved a $47.69 per MWH market price for 2007.  The recovery will be accomplished by the amortization of a $57 million ($15 million for CSPCo and $42 million for OPCo) excess deferred tax regulatory liability resulting from an Ohio franchise tax phase-out regulatory liability recorded in 2005 and, if that is insufficient, an increase in RSP generation rates under the additional average 4% generation rate provision of the RSPs.2005.

CSPCo and OPCo each amortized $2 million of this regulatory liability to income for the quarter ended March 31, 2008 based on the previously approved 2007 price of $47.69 per MWH.  In December 2006,2007, CSPCo and OPCo submitted for approval a market price of $47.69$53.03 per MWH for 2007, which was approved by the PUCO 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, 2007.2008.  If the PUCO approves a lower market price infor 2008 below the 2007 price, 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.sales.

TexasVirginia Rate Matters

SWEPCo Fuel Reconciliation – TexasVirginia Base Rate Filing – Affecting SWEPCo

In June 2006, SWEPCo filed a fuel reconciliation proceeding with the PUCT for its Texas retail 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 disallowances ranged from $10 million to $28 million.  In June 2007, an ALJ issued a proposal for decision recommending a $17 million 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 August 2007, the PUCT issued a final order affirming the ALJ report.  In September 2007, SWEPCo filed a motion for rehearing.  In October 2007, the PUCT granted 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 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 amended the Virginia Electric Utility Restructuring Act extending the transition period to market rates for the generation and supply of electricity, including the extension of capped rates, through December 31, 2010.  The legislation provided 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 have the opportunity to recover incremental E&R costs.

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.

With the new re-regulation legislation, APCo’s generation business again met the criteria for application of regulatory accounting principles under SFAS 71.  The extraordinary pretax reduction in APCo’s earnings and shareholder’s equity from 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 qualifying SFAS 158 pension costs of the generation operations that, for ratemaking purposes, are deferred for future recovery under the new re-regulation legislation.  AOCI and Deferred Income Taxes increased by $11 million and $6 million, respectively.

Virginia Base Rate Case – Affecting APCo

In May 2006,March 2008, APCo filed a requestnotice with the Virginia SCC seeking an increase in base rates of $225 millionthat it plans to recover increasing costs including the cost of its investment in environmental equipment andfile 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 its active fuel 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 was estimated to be $27 million, partially offsets the $225 million requested increase in base rates for a net increase ingeneral base rate revenues of $198 million.  Incase no sooner than May 2006, the Virginia SCC issued an order placing the net requested base2008.  The rate increase of $198 million into effectcase will be based on October 2, 2006, subject to refund.a test year ending December 31, 2007, with adjustments through June 2008.

In May 2007, the Virginia SCC issued a final order approving an overall annual base rate increaseE&R Costs Recovery Filing – Affecting APCo

As of $24March 31, 2008, APCo has $85 million effective as of October 2006 and approving a return on equity of 10.0%.  As a resultdeferred Virginia incremental E&R costs.  Currently APCo is recovering $26 million of the final order, APCo’s second quarter pretax earnings decreased by approximately $3 million duedeferral for incremental costs incurred through September 30, 2006.  APCo intends to a decreasefile in revenuesMay 2008 for recovery 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 unrecovereddeferred incremental E&R costs incurred from October 1, 2006 through June 30,December 31, 2007 towhich totals $46 million.  The remaining deferral will be collectedrequested in a future2009 filing.  As of March 31, 2008, APCo has $21 million of unrecorded E&R filing, (b) a $9equity carrying costs of which $7 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 ofshould increase 2008 annual earnings as collected.  In connection with the 2009 filing, the Virginia SCC decision to limitwill determine the recoverylevel of incremental E&R costs throughbeing collected in base revenues since October 2006 that APCo has estimated to be $48 million annually.  If the newVirginia SCC were to determine that these recovered base rates, APCo will continue to defer for future recovery unrecovered incremental E&R costs incurred through 2008 utilizingrevenues are in excess of $48 million a year, it would require that the E&R surcharge mechanism.  APCo completeddeferrals be reduced by the $127 million refund in August 2007.

Virginia E&R Costs Recovery Filing – Affecting APCo

excess amount, thus adversely affecting future earnings and cash flows. In July 2007, APCo filed a request withaddition, if the Virginia SCC seeking recovery over the twelve months beginning December 1, 2007were to disallow any additional portion of approximately $60 millionAPCo’s deferral, it would also have an adverse affect on future results 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 staffoperations 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 2008 for recovery of additional incurred incremental E&R costs recorded and deferred after September 30, 2006.cash flows.

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 $70 million regulatory asset does not include carrying costs on the unrecovered incremental E&R costs and is based on a return on equity rate which approximates the Virginia SCC staff and Attorney General’s recommendations.  As a result, if APCo is awarded only $49 million for the E&R costs incurred for the twelve months ended September 30, 2006 as recommended by the Virginia SCC staff and the Attorney General, it will not have to reverse any of its 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 off-system sales.

In February 2008, the benefits ofVirginia SCC issued an order that approved a reduced fuel factor effective with the February 2008 billing cycle.  The order terminated the off-system sales between APComargin rider and its customers.  This filing was made in compliance with the minimum 25% retentionapproved a 75%-25% sharing of off-system sales margins provision of the new re-regulation legislation which is effective with the first fuel clause 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,between customers and APCo requested authorization to 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.

In August 2007, the Virginia SCC issued a scheduling order that implemented APCo’s proposed termination of its base rate off-system sales margin rider on an interim basis, subject to refund, on 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 foras required by the sharingre-regulation legislation in Virginia.  The order also allows APCo to include in its monthly under/over recovery deferrals the Virginia jurisdictional share of 75% of off-system sales margins with customers in compliance with the new law.  In October 2007, APCo,PJM transmission line loss back to June 1, 2007.  The adjusted factor will increase annual revenues by $4 million.  The order authorized the Virginia SCC staff and certain intervenors filed memorandums addressing legal issues identified byother parties to make specific recommendations to the Virginia SCC regardingin APCo’s next fuel factor proceeding in the appropriatenessfourth quarter of 2008 to ensure accurate assignment of the timingprudently incurred PJM transmission line loss costs to APCo’s Virginia jurisdictional operations.  APCo believes the incurred PJM transmission line loss costs are prudently incurred and are being properly assigned to APCo’s Virginia jurisdictional operations.

In February 2008, the Old Dominion Committee for Fair Utility Rates filed a notice of appeal to the implementationSupreme Court of the new expandedVirginia.

If costs included in APCo’s Virginia fuel factor and off-system sales margins sharing with customers.  Hearingsunder/over recovery deferrals 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 existsdisallowed, it could result in the statute requiring implementation of off-system sales margin sharing any earlier than 2011.  Futurean adverse effect on future results of operations and cash flows could be adversely affected if theflows.

APCo’s Virginia SCC delays the effective date of the new expanded fuel clause beyond APCo’s filed request.

West VirginiaFiling for an IGCC Plant – Affecting APCo

In July 2007, APCo filed a request with the Virginia SCC for a rate adjustment clause to recover over the twelve months beginning January 1, 2009, a return on projected construction work in progress including development, design and planninginitial costs from July 1, 2007 through December 31, 2009 estimated to be $45 million associated with thea proposed 629 MW IGCC plant to be constructed in Mason County, West Virginia adjacent to APCo’s existing Mountaineer Generating Station for an estimated cost of $2.2 billion.  The filing requests recovery of an estimated $45 million over twelve months beginning January 1, 2009 including a return on projected CWIP and development, design and planning pre-construction costs incurred from July 1, 2007 through December 31, 2009.  APCo is requestingalso requested authorization to defer a return on actualdeferred pre-construction costs incurred beginning July 1, 2007 until such costs are recovered, starting January 1, 2009 in accordance withrecovered.  Through March 31, 2008, APCo has deferred for future recovery pre-construction IGCC costs of $7 million applicable to Virginia.  The rate adjustment clause provisions of the new re-regulation legislation.  The new2007 re-regulation legislation provides for full recovery of all costs plusof this type of new clean coal technology including recovery of an enhanced return on equity incentivesequity.  The Virginia SCC issued an order in April 2008 denying APCo’s requests on the basis of their belief that the estimated cost may be significantly understated.  The Virginia SCC also expressed concern that the $2.2 billion estimated cost did not include a retrofitting of carbon capture and sequestration facilities.  In April 2008, APCo filed a petition for such new capacity oncereconsideration in Virginia.  If necessary, APCo will seek recovery of its prudently incurred deferred pre-construction costs.  If the plant is placed in service.  See “West Virginia IGCC Plant” section within West Virginia Rate Matters.deferred costs are not recoverable, it would have an adverse effect on future results of operations and cash flows.

West Virginia Rate Matters

APCoAPCo’s 2008 Expanded Net Energy Cost (ENEC) Filing – Affecting APCo

In April 2007,February 2008, APCo filed for an increase of approximately $140 million including a $122 million increase in the WVPSC issued an order establishing an investigationENEC itself, a $15 million increase in construction cost surcharges and hearing concerning APCo’s and WPCo’s 2007 ENEC compliance filing.$3 million of reliability expenditures, to become effective July 2008.  The ENEC is an expanded form of fuel clause mechanism, which includes all energy-related costs including fuel, purchased power expenses, off-system sales credits, PJM costs associated with transmission line losses due to the implementation of marginal loss pricing and other energy/transmission items.   In the March 2007 ENEC joint 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.  In June 2007, the WVPSC 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 $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 subject to a true-up, whichtrue up to actuals and should avoid anhave no earnings affect from an effect due to the deferral of any over/under-recovery of actual ENEC costs.  However, if the WVPSC were to disallow the deferral of any costs if they exceedincluding the $50 million.incremental cost of PJM’s recently revised costs associated with transmission line losses, it would have an adverse affect on future results of operations and cash flows.  An order is expected by June 2008.

APCo’s West Virginia IGCC Plant Filing – Affecting APCo

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

In June 2007, APCo filed testimony with the WVPSC supporting the requests for a CCN and for pre-approval of a surcharge rate mechanism to provide for the timely recovery of both pre-construction costs and the ongoing finance costs of the project during the construction period as well as the capital costs, operating costs and a return on equity once the facility is placed into commercial operation.  In March 2008, the WVPSC granted APCo the CCN to build the plant and the request for cost recovery.  Various intervenors filed petitions with the WVPSC to reconsider the order.  If APCo receives all necessary approvals, the plant could be completed as early as mid-2012 and currently is expectedmid-2012.  At the time of the filing, the cost of the plant was estimated at $2.2 billion.  The Virginia SCC’s decision to costdeny APCo’s request to build an estimated $2.2 billionIGCC plant may have an impact on the project (See the “APCo’s Virginia SCC Filing for an IGCC Plant” above).  In July 2007, the WVPSC staff and intervenors filed to delay the procedural schedule by 90 days.  APCo supported the changes to the procedural schedule.  The statutory decision deadline was revised toThrough March 2008.  In July 2007, the WVPSC approved the revised procedural schedule.  Through September 30, 2007,31, 2008, APCo deferred for future recovery pre-construction IGCC costs totaling $11 million.of $7 million applicable to the West Virginia jurisdiction and $2 million applicable to the FERC jurisdiction. If the plant is not built and these deferred costs are not recoverable, it would have an adverse effect on future results of operations and cash flows would be adversely affected.flows.

Indiana Rate Matters

Indiana 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 were 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 were 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.  In June 2007, the IURC approved the settlement agreement, but modified the effective date of the new book depreciation rates 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 for 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 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,January 2008, I&M filed for an increase in its Indiana base rates of $82 million including a rate notification petition with the IURC regarding its intent to file for areturn on equity of 11.5%.  The base rate increase withincludes a proposed test year ended September 30, 2007.previously approved $69 million annual reduction in depreciation expense. The petition indicated, among other things, the filing would include a request to implement rate tracker mechanismsrequests trackers for certain variable components of the cost of service including recently increased PJM costs associated with transmission line losses due to the implementation of marginal loss pricing and other RTO costs, reliability enhancement costs, demand side management/energy efficiency program costs, off-system sales margins and net environmental compliance costs.  This filing will also reflect the revenue requirement reduction associatedThe trackers would initially increase annual revenues by an additional $46 million.  I&M proposes to share with an annual reduction in book depreciation expense. In August 2007, the IURC approved the September 30, 2007 test year and the inclusionratepayers, through a tracker, 50% of the above trackers in the rate filingoff-system sales margins initially estimated to be $96 million annually with a rate caseguaranteed credit to be filed no later than January 31, 2008.  Management expects to filecustomers of $20 million.  A decision is expected from the case in early 2008 with a decision expectedIURC in early 2009.

IndianaOklahoma Rate Cap – Affecting I&MMatters

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 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 through June 30, 2007.  Future results of operations should no longer be adversely impacted by fuel costs.

Michigan Rate Matters

Michigan Depreciation Study Filing– Affecting I&M

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 approximately half the load beginning in November 2007 and reduce wholesale rates for the remaining customers in June 2008.
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 clause 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 2004, an Oklahomaintervenors and the OCC staff argued that AEP had inappropriately under allocated off-system sales credits to PSO by $37 million for the period June 2000 to December 2004 under a FERC-approved allocation agreement.  An ALJ assigned to hear intervenor claims found that the OCC lackslacked authority to examine whether AEP deviated from the FERC-approved allocation methodology for off-system sales margins and held that any such complaints should be addressed at the FERC.  In 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 stayed its final order regarding the FERC jurisdictional issue. In October 2007, the OCC lifted its stay statingorally directed the OCC does not have jurisdiction regarding the allocation methodology for off-system sales margins.

The OIEC or another party could filestaff to explore filing a complaint at the FERC alleging the allocation of off-system sales margins to PSO is improper,not in compliance with the FERC-approved methodology which could result in an adverse effect on future results of operations and cash flows for AEP Consolidated and the AEP East companies.  However, toTo date, thereno claim has been no claim asserted at the FERC and management continues to believe that the AEP System deviated fromallocation is consistent with the FERC-approved allocation methodologies, but even if one were asserted, management believes that 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.  In August 2007, an ALJ issued a report recommending that PSO’s fuel procurement practices were prudent and no adjustments were warranted.  No parties appealed the recommendation.  In October 2007, the OCC issued a final order adopting the ALJ’s report.

In February 2006, the OCC enacted a rule, requiring the OCC staff to conduct prudence reviews on allPSO’s 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 periodic reviews.basis.  PSO filed its testimony in June 2007 covering a prudence review for the year 2005. The OCC Staff and intervenors filed testimony in September 2007, and hearings were held in November 2007.

In   PSO also filed prudence testimony in November 2007 covering the year 2006.  The OCC staff and intervenors filed testimony in April 2008.  Hearings are scheduled in May 2007, PSO submitted a filing2008.  The only major issue raised in each of those proceedings was the alleged under allocation of off-system sales credits under the FERC-approved allocation agreements, which was determined not to be jurisdictional to the OCC.  OCC orders applicable to adjust its fuel/purchase power rates.  Inboth 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,2005 and 2006 prudence proceedings are expected 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.2008.

Management cannot predict the outcome of the pending fuel and purchased power costscost recovery filings and prudence reviews, or planned future reviews, butreviews.  However, PSO believes that PSO’sits fuel and purchased power procurement practices and costs arewere prudent and properly incurred.incurred and that it allocated off-system sales credits consistent with governing FERC-approved agreements.

Oklahoma 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 also proposed a formula rate plan that, if approved as filed, would 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 prevent the capitalization of a significant amount of AFUDC that would have been recorded during the construction period and recovered in the future through depreciation expense.

The ALJ issued a report in May 2007 recommending a 10.5% return on equity but did not compute an overall revenue requirement.  The ALJ’s report did not recommend adopting a formula rate plan, but did recommend recovery through a rider of certain generation and transmission projects’ financing costs during construction.  However, the report also contained an alternative recommendation that the OCC could delay a decision on the rider and take up this issue in PSO’s application seeking regulatory approval of a new coal-fueled generating unit.  PSO implemented interim rates, subject to refund, for residential customers beginning July 2007.

In 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 file a plan with the OCC to promote energy efficiency and conservation programs within 60 days.  PSO implemented the approved rates in October 2007.

Lawton and Peaking Generation Settlement Agreement – Affecting PSO

In November 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 in June 2005, affirming portions of the OCC’s order and remanding certain provisions.  The Court affirmed the OCC’s finding that Lawton established a legally-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 including permits, options and engineering studies.  PSO paid 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, 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 occur 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.

Red Rock Generating Facility – Affecting PSO

In July 2006, PSO announced plans to enter into an agreement with Oklahoma Gas and Electric Company (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.unit.  PSO would own 50% of the new unit, OG&E would own approximately 42% andunit.  Under the Oklahoma Municipal Power Authority (OMPA) would own approximately 8%.agreement, OG&E would manage construction of the plant.  OG&E and PSO requested pre-approvalpreapproval to construct the Red Rock Generating Facility and to 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 applicationapplications for construction pre-approval statingpreapproval.  The OCC stated that PSO and OG&E failed to fully study other alternatives.  Since PSO and OG&E could not obtain pre-approvalpreapproval to build the coal-fired Red Rock Generating Facility, PSO and OG&E cancelledcanceled the third party construction contract and their joint venture development contract.  Management believesAs a result of the OCC’s decision, PSO will restudy various alternative options to meet its capacity and energy needs.

In December 2007, PSO filed an application at the OCC requesting recovery of the $21 million in pre-construction costs capitalized, including anyand contract cancellation fees were prudently incurred, as evidenced byassociated with Red Rock.  In March 2008, PSO and all other parties in this docket signed a settlement agreement that provides for recovery of $11 million of Red Rock costs, and provides carrying costs at PSO’s AFUDC rate beginning in March 2008 and continuing until the $11 million is included in PSO’s next base rate case.  PSO will recover the costs over the expected life of the peaking facilities at the Southwestern Station, and include the costs in rate base beginning in its next base rate filing.  The settlement was filed with the OCC staff andin March 2008.  A hearing on the ALJ’s recommendations thatsettlement is scheduled for May 2008.  As a result of the settlement, PSO wrote off $10 million of its deferred pre-construction costs/cancellation fees in the first quarter of 2008.  Should the OCC not approve PSO’s filing,the settlement agreement and established aif recovery of the remaining regulatory asset for future recovery.  Management believes such pre-construction costs arebecomes no longer probable of recovery and intends to seek full recovery of such costs in the near future.  If recoveryor is denied, future results of operations and cash flows would be adversely affected.  As a resultaffected by the write off of the OCC’s decision, PSO will consider various alternative options to meet its capacity needs in the future.remaining regulatory asset.

Oklahoma 2007 Oklahoma Ice StormStorms – Affecting PSO

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

In February 2008, PSO entered into a settlement agreement for recovery of costs from both ice storms.  In March 2008, the OCC approved the settlement subject to an audit of the final December ice storm costs to be filed in July 2008. As a result, PSO recorded an $81 million regulatory asset for ice storm maintenance expenses and related carrying costs less $9 million of amortization expense to offset recognition of deferred gains from sales of SO2 emission allowances.  Under the settlement agreement, PSO will apply proceeds from sales of excess SO2 emission allowances made during 2007of an estimated $26 million to recover part of the ice storm regulatory asset.  PSO will amortize and thereafter until such gains provide forrecover the full recoveryremaining amount of the regulatory asset.  Ifasset through a rider over a period of five years beginning in the OCC adoptsfourth quarter of 2008.  The regulatory asset will earn a return of 10.92% on the PSO proposal, it would have a favorable impact on future results of operations and cash flows.unrecovered balance.

Louisiana Rate Matters

Louisiana Compliance Filing – Affecting SWEPCo

In October 2002,connection with SWEPCo’s merger related compliance filings, the LPSC approved a settlement agreement in April 2008 that prospectively resolves all issues regarding claims that SWEPCo had over-earned its allowed return.  SWEPCo agreed to a formula rate plan (FRP) with a three-year term.  Beginning August 2008, rates shall be established to allow SWEPCo to earn an adjusted return on common equity of 10.565%.  The adjustments are standard Louisiana rate filing adjustments.  In April 2008, SWEPCo filed detailed financial information typically utilizedthe first FRP anticipating that the LPSC would approve the settlement agreement.  Based on the FRP, SWEPCo proposes to increase its annual Louisiana retail rates by $11 million in August 2008 to earn an adjusted return on common equity of 10.565%.

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

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

In addition, the settlement provides for a jurisdictionalreduction in depreciation rates effective October 2007.  SWEPCo will defer as a regulatory liability, the effects of the expected depreciation reduction through July 2008.  SWEPCo will amortize this regulatory liability over the three year term of the FRP as a reduction to the cost of service withused to determine 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-authorized return on equity of 11.1%.adjusted earned return.

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 jurisdictional customers, based on a proposed 10% return on equity.  The recommended reduction range was 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.  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 affect 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 480500 MW natural gas-fired combustion turbine combined cycle generating unit (the Stall Unit) at its existing Arsenal Hill Plant location in Shreveport, Louisiana.  SWEPCo submitted the appropriate filings with the PUCT, the APSC, the LPSC and the Arkansas Public Service Commission (APSC) during the third quarterLouisiana Department of 2006 and the LPSC during the first quarter of 2007Environmental Quality to seek approvals to construct the unit.  The Stall Unit is estimated to cost $375$378 million, excluding AFUDC, and is expected to be in servicein-service in mid-2010.  As of September 2007,March 31, 2008, SWEPCo incurred andhas capitalized approximately $15pre-construction costs of $76 million and has contractual construction commitments of an additional $17$219 million.  As of March 31, 2008, if the plant were to be cancelled, then cancellation fees of $59 million would terminate these construction commitments.

In March 2007, the PUCT approved SWEPCo’s request.certificate for the facility.  In Louisiana, this request has been separated from the original request, which included the Turk Plant.  NeitherFebruary 2008, the LPSC norstaff submitted testimony in support of the Stall Unit and one intervenor submitted testimony opposing the Stall Unit due to the increase in cost.  The LPSC held hearings in April 2008.  The APSC have sethas not established a procedural schedule for the project.at this time.  The project is contingent upon obtaining pre-approval from the APSC, the LPSC, the PUCT and the Louisiana Department of Environmental Quality.Quality issued an air permit for the unit in March 2008.  If SWEPCo isdoes not authorizedreceive appropriate authorizations and permits to build the Stall Unit, SWEPCo would seek recovery of incurredthe capitalized pre-construction costs including any cancellation fees.  If SWEPCo cannot recover incurredits capitalized costs, including any cancellation fees, it could adversely affectwould have an adverse effect on future results of operations and cash flows and possibly financial condition.flows.

Turk Plant – Affecting SWEPCo

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

Arkansas Rate Matters

Turk Plant – Affecting SWEPCo

In August 2006, SWEPCo announced plans to build the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas named Turk Plant.Arkansas.  Ultra-supercritical technology uses higher temperatures and higher pressures to produce electricity more efficiently – thereby using less fuel and providing substantial emissions reductions.  SWEPCo submitted filings with the APSC, in December 2006 and the PUCT and the LPSC in February 2007 to seek approvals to proceed withseeking certification of the plant.  In September 2007, OMPA signed a joint ownership agreement and agreed toSWEPCo will 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.  During 2007, SWEPCo signed joint ownership agreements with the Oklahoma Municipal Power Authority (OMPA), the Arkansas Electric Cooperative Corporation (AECC) and the East Texas Electric Cooperative (ETEC) for the remaining 27% of the Turk Plant.  The Turk Plant is estimated to cost $1.3$1.5 billion in total with SWEPCo’s portion estimated to cost $950 million,$1.1 billion, excluding AFUDC.  If approved on a timely basis, the plant is expected to be in-service in mid-2011.2012.  As of September 2007,March 31, 2008, including the joint owners’ share, SWEPCo incurred and capitalized approximately $206$313 million of expenditures and has significant contractual construction commitments for an additional $875$838 million.  As of March 31, 2008, if the plant were to be cancelled, then cancellation fees of $67 million would termiante these construction commitments.

In November 2007, the APSC granted approval to build the plant.  Certain landowners filed a notice of appeal to the Arkansas State Court of Appeals.  SWEPCo is still awaiting approvals from the Arkansas Department of Environmental Quality and the U.S. Army Corps of Engineers.  Both approvals are expected to be received by the third quarter of 2008.  The PUCT held hearings in October 2007.  In January 2008, a Texas ALJ issued a report, which concluded that SWEPCo failed to prove there was a need for the plant.  The Texas ALJ recommended that SWEPCo’s application be denied.  The PUCT has voted to reopen the record and conduct additional hearings.  SWEPCo expects a decision from the PUCT in the last half of 2008.  In March 2008, the LPSC approved the application to construct the Turk Plant.  If SWEPCo isdoes not authorizedreceive appropriate authorizations and permits to build the Turk plant,Plant, SWEPCo could incur significant cancellation fees to terminate its commitments and would be responsible to reimburse OMPA, AECC and ETEC for their share of paid costs.  If that occurred, SWEPCo would seek recovery of incurredits capitalized costs including any cancellation fees.fees and joint owner reimbursements.  If SWEPCo cannot recover incurred cots, including any cancellation fees,its costs, it could adversely affecthave an adverse effect on 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 and OPCo

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 at FERC’s direction load-based charges, referred to as RTO SECA, to partially mitigate the loss of T&O revenues on a temporary basis through March 31, 2006.  Intervenors objected to the temporary SECA rates, raising various issues.  As a result, the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund or surcharge.refund.  The AEP East companies paid SECA rates to other utilities at considerably lesser amounts than they collected.  If a refund is ordered, the AEP East companies would also receive refunds related to the SECA rates they paid to third parties.  The AEP East companies recognized gross SECA revenues of $220 million.million from December 2004 through March 2006 when the SECA rates terminated leaving AEP and ultimately its internal load customers to make up the short fall in revenues.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of recognized gross SECA revenues are as follows:

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

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 wasshould not have been recoverable.   The ALJ found that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made.  The ALJ also found that the unpaid SECA rates must be paid in the recommended reduced amount.

In 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 togetherfiled briefs jointly with Exelon Corporation and The Dayton Power and Light Company, filed an extensive post-hearing brief and reply briefother affected companies 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 ALJ’s initial decision because it contradicts prior related FERC decisions, which are presently subject to rehearing.  Furthermore, management believes the ALJ’s findings on key issues are largely without merit.  As directed by the FERC, management is workinga result, SECA ratepayers have been willing to engage with AEP in settlement discussions.  AEP has been engaged in settlement discussions in an effort to settle the remainingSECA issue.  However, if the ALJ’s initial decision is upheld in its entirety, it could result in a disallowance of a large portion on any unsettled SECA revenues.

During 2006, the AEP East companies provided reserves of $37 million for net refunds for current and future SECA settlements.  After reviewing existing settlements, the AEP East companies increased their reserves by an additional $5 million in December 2007.  APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the provision are as follows:

  2007  2006 
Company (in millions) 
APCo $1.7  $12.0 
CSPCo  0.9��  6.7 
I&M  1.0   7.0 
OPCo  1.3   9.1 

Completed and in-process settlements cover $105 million of the $220 million of SECA revenues and will consume about $7 million of the reserve for refund, leaving approximately $115 million of unsettledcontested SECA 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$35 million of ongoing settlement talks and, if necessary, any future FERC proceedings or court appeals.  refund reserves.

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,reserved for refunds, it will have an adverse effect on future results of operations and cash flowsflows. Based on advice of external FERC counsel, recent settlement experience and financial condition.the expectation that most of the unsettled SECA revenues will be settled, management believes that the remaining reserve of $35 million is adequate to cover all remaining settlements.  However, management cannot predict the ultimate outcome of ongoing settlement discussions or future FERC proceedings or court appeals, if such are necessary.

The FERC PJM Regional Transmission Rate Proceeding

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 andafter considerable administrative litigation at AEP’s urging, the FERC instituted an investigationin which AEP sought to mitigate the effect of PJM’s zonalT&O rate regime indicating thatelimination, the presentFERC failed to implement a regional rate regime may need to be replaced through establishment of regional rates that would compensatein PJM.  As a result, the AEP East companies and other transmission owners forcompanies’ retail customers incur the regional transmission facilities they provide to PJM, which provides service forbulk of the benefitcost 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 existingAEP east transmission zone 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 futureany new 500 kV and higher voltage transmission facilities built in PJM would be shared by all customers in the region.  It is expected that most of which are expected tothe new 500 kV and higher voltage transmission facilities will be upgrades of the facilitiesbuilt in other zones of PJM.PJM, not AEP’s zone.  The AEP East companies will need to obtain regulatory approvals for recovery of any costs of new facilities that are assigned to them as a result of this order, if upheld.them.  AEP hashad requested rehearing of this order.order, which the FERC denied.    AEP filed a Petition for Review of the FERC orders in this case in February 2008 in the United States Court of Appeals.  Management cannot estimate at this time what effect, if any, this order will have on the AEP East companies’ future construction of new east transmission facilities, results of operations and cash flows and financial condition.  In May 2007, theflows.

The AEP East companies filed for rehearing relatedand in 2006 obtained increases in its wholesale transmission rates to this FERC decision.

Since the FERC’s decisionrecover lost revenues previously applied to reduce those rates.  AEP has also sought and received retail rate increases in 2005 to cease through-and-out ratesOhio, Virginia, West Virginia 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 TennesseeKentucky to recover lost T&O and SECA revenues.  Therevenues previously applied to reduce retail rates.  As a result, AEP East companies presently recover from retail customersis now recovering approximately 85% of the lost T&O/&O transmission revenues.  AEP received net SECA transmission revenues of $128 million a year.in 2005.  I&M requested recovery of these lost revenues in its Indiana rate filing in late January 2008 but does not expect to commence recovering the new rates until early 2009.  Future results of operations and cash flows and financial condition will continue to be adversely affected in Indiana and Michigan and Tennessee until thesethe remaining 15% of the lost T&O/SECA&O transmission revenues are recovered in retail rates.

The FERC PJM and MISO Regional Transmission Rate Proceeding

In the SECA proceedings, the FERC ordered the RTOs and transmission owners in the PJM/MISO region (the Super Region) to file, by August 1, 2007, a proposal to establish a permanent transmission rate design for the Super Region to be effective February 1, 2008.  All of the transmission owners in PJM and MISO, with the exception of AEP and one MISO transmission owner, votedelected to continuesupport continuation of zonal rates in both RTOs.  In September 2007, AEP filed a formal complaint proposing a highway/byway rate design be implemented for the Super Region.Region where users pay based on their use of the transmission system.  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 that 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.  In January 2008, the FERC denied AEP’s complaint.  AEP filed a rehearing request with the FERC in March 2008.  Should this effort be successful, AEP East companies would reduce future retail revenues in their next fuel or base rate proceedings.  Management is unable to predict the outcome of this case.

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 seektariffs to establish an up-to-date revenue requirement for SPP transmission services over the facilities owned by PSO and SWEPCo and to implement a transmission cost of service formula rate.

PSO and SWEPCo requested an effective date of September 1, 2007 for the revised tariff.  The primary impact ofIf approved as filed, the filed revised tariff will be an increase inannual 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 increaseSPP 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.million.  In August 2007, the FERC issued an order conditionally accepting PSO’s and SWEPCo’s proposed formula rate, subject to a compliance filing, suspended the effective date until February 1, 2008 and established a hearing schedule and settlement judge proceedings.  In October 2007, AEPSC submitted a compliance filing on behalfNew rates, subject to refund, were implemented in February 2008.  Management believes that the appropriate amount of PSO and SWEPCo.revenues is being recognized.  Multiple intervenors have protested or requested re-hearing of the order.  Discovery and settlement discussions have begun.

begunPJM 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.the outcome of this proceeding.

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 20062007 Annual Report should be read in conjunction with this report.

GUARANTEES

There are certain immaterial liabilities recorded for guarantees in accordance with 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 September 30, 2007,March 31, 2008, the maximum future payments of the LOCs include $1 million and $4 million for I&M and SWEPCo, respectively, with maturities ranging from December 20072008 to March 2008.2009.


Guarantees of Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation in the amount of approximately $65 million.  Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), an entity consolidated under FIN 46.46R.  This guarantee ends upon depletion of reserves and completion of final reclamation.  Based on the latest study, it is estimated the reserves will be depleted in 2029 with final reclamation completed by 2036, at an estimated cost of approximately $39 million.  As of September 30, 2007,March 31, 2008, SWEPCo collected approximately $33$35 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 September 30, 2007, theMarch 31, 2008, Registrant Subsidiaries entered into sale agreements includingwhich included indemnifications with a maximum exposure that was not significant for any individual Registrant Subsidiary.  There are no material liabilities recorded for any indemnifications.

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

Master Operating Lease

Certain Registrant Subsidiaries lease certain equipment under a master operating lease.  Under the lease agreement, the lessor is guaranteed to receive up to 87% of the unamortized balance of the equipment at the end of the lease term.  If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, the subsidiary 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.  AssumingHistorically, at the end of the lease term the fair market value has been in excess of the unamortized balance.  At March 31, 2008, the maximum potential loss by subsidiary for these lease agreements assuming the fair market value of the equipment is zero at the end of the lease term is as follows:
  Maximum Potential Loss 
Company (in millions) 
APCo $9 
CSPCo  4 
I&M  6 
OPCo  9 
PSO  5 
SWEPCo  6 

Railcar Lease

In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars.  The lease has an initial term of five years.  At the end of each lease term, AEP 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.  AEP intends to renew the lease for the full remaining terms.  This operating lease agreement allows AEP to avoid a large initial capital expenditure and to spread its 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. 

In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars).  The assignment is accounted for as new operating leases for I&M and SWEPCo.  The future minimum lease obligation is $46 million as of March 31, 2008.  I&M and SWEPCo intend to renew these leases for the full remaining terms and have assumed the guarantee under the return-and-sale option.  I&M’s maximum potential loss for these lease agreements asrelated to the guarantee discussed above is approximately $14 million ($9 million, net of September 30, 2007 was as follows:
  
Maximum
 
  
Potential
 
  
Loss
 
Company
 
(in millions)
 
APCo $9 
CSPCo  4 
I&M  6 
OPCo  8 
PSO  5 
SWEPCo  6 

CONTINGENCIEStax) and SWEPCo’s is approximately $16 million ($11 million, net of tax).

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

CONTINGENCIES

Federal EPA Complaint and Notice of Violation –��� Affecting APCo, CSPCo I&M, and OPCo

The Federal EPA, certain special interest groups and a number of states allegealleged 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,OPCo modified certain units at their 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 the AEP System’s generating units over a 20-year period.  In April 2007, the U.S. Supreme Court reversed the Fourth Circuit Court of Appeals’ decision that had supported the statutory construction argument ofCases with similar allegations against CSPCo, Dayton Power and Light Company (DP&L) and Duke Energy 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 agreedOhio, Inc. were also filed related 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 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 third quarter of 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
jointly-owned units.

The consent decree will resolve all issues related to various parties’ claims against the Registrant SubsidiariesAEP System settled their cases 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 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 OPCo 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  Cases are unable to recover such costs, it would adversely affect their future results of operations, cash flows and possibly financial condition.
Cases arestill 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.  No trial date has yet been established in theThe Stuart case, but the units, operated by Dayton Power and Light Company,DP&L, are equipped with SCR controls and flue gas desulfurization equipment (FGD or scrubbers) controls.  A trial on liability issues was scheduled for August 2008.  The Court issued a stay to allow the installation of FGD controls will be completedparties to pursue settlement discussions and scheduled a settlement conference in 2007.May 2008.  The Beckjord and Zimmer case is scheduled for a liability trial in May 2008.  ZimmerBeckjord 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.

Management is unable to estimate the loss or range of loss related to any contingent liability, if any, CSPCo might have for civil penalties under the pending CAA proceedings for theits 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 CSPCo does not prevail, management believes CSPCo can recover any capital and operating costs of additional pollution control equipment that may be required through market prices forof electricity.  If any of the AEP subsidiaries areCSPCo is unable to recover their capital and operatingsuch 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.  SWEPCoIn April 2008, the parties filed a responseproposed consent decree to resolve all claims in this case and in the pending appeal of the altered permit for the Welsh Plant.  The consent decree requires SWEPCo to install continuous particulate emission monitors at the Welsh Plant, secure 65 MW of renewable energy capacity by 2010, fund $2 million in emission reduction, energy efficiency or environmental mitigation projects by 2012 and pay a portion of plaintiffs’ attorneys’ fees and costs.  The consent decree has been submitted to the complaint in May 2005.  A trial in this matter is scheduledFederal EPA and the DOJ for a 45-day comment period prior to commence during the first quarter of 2008.entry.

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.Plant.  In April 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition(Report) 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 violationsSWEPCo.  TCEQ filed an amended Report during the fourth quarter of 2007, eliminating certain representations regarding heat input in SWEPCo’s permit applicationclaims and reducing the violations of certain recordkeeping and reporting requirements.  SWEPCo respondedrecommended penalty amount to the preliminary report and petition in May 2005.$122 thousand.  The enforcement order containsmatter was remanded to TCEQ to pursue settlement discussions.  The original Report contained a recommendation that wouldto limit the heat input on each Welsh unit to the referenced heat input contained within the state permit application within 10 days of the issuance of a final TCEQ order and until athe permit amendment is issued.changed.  SWEPCo had previously requested a permit alteration to remove the reference to a specific heat input value for each Welsh unit and to clarify the sulfur content requirement for fuels consumed at the plant.  A permit alteration was issued in March 2007 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.2007.  The Sierra Club and Public Citizen filed a motion to overturn the permit alteration.  In June 2007, TCEQ denied that motion.  The permit alteration was appealed to the Travis County District Court, but would be resolved by entry of the consent decree in the federal citizen suit action.  The District Court issued a stay while approval of the consent decree is pending.

On February 8, 2008, the Federal EPA issued a Notice of Violation (NOV) based on alleged violations of a percent sulfur in fuel limitation and the heat input values listed in the previous state permit.  The NOV also alleges that the permit alteration issued by TCEQ was improper.  SWEPCo met with the Federal EPA to discuss the alleged violations in early March 2008.

Management is unable to predict the timing of any future action by TCEQ, the Federal EPA 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 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 of this lawsuit was appealed to the Second Circuit Court of Appeals.  Briefing and oral argument have concluded.  OnIn 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 LitigationAlaskan Villages’ Claims – Affecting OPCoAEP East Companies and AEP West Companies

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska  filed a lawsuit in federal court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil & gas companies, a coal company, and other electric generating companies.  The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together.  The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance.  The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million.  Management believes the action is without merit and intends to defend against the claims.

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

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF.  Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized.  In addition, the generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls (PCBs) and other hazardous and nonhazardous materials.  The Registrant Subsidiaries currently incur costs to sell up to approximately 800 MWsafely dispose of energy to Tractebel Energy Marketing, Inc. (TEM) (now known as SUEZ Energy Marketing NA, Inc.) for a periodthese substances.

Superfund addresses clean-up 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 pursuanthazardous substances that have been released to the PPA that TEM rejected as nonconforming.environment.  The Federal EPA administers the clean-up programs.  Several states have enacted similar laws.  In March 2008, I&M received a letter from the Michigan Department Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm.  I&M requested  remediation proposals from environmental consulting firms due May 2008.  I&M cannot predict the cost of remediation or the amount of costs recoverable from third parties.

In 2003, TEMthose instances where AEP subsidiaries have been named a Potentially Responsible Party (PRP) or defendant,  disposal or recycling activities were in accordance with the then-applicable laws and OPCo separately filed declaratory judgment actions in the United States District Courtregulations.  Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories.  Liability has been resolved for the Southern Districta number of New York.  OPCo alleged that TEM breached the PPA, and sought a determinationsites with no significant effect on results 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.operations.

In 2005,The Registrant Subsidiaries evaluate the potential liability for each Superfund site separately, but several general statements can be made regarding their potential future liability.  Disposal of materials at a federal judge ruled that TEM had breachedparticular site is often unsubstantiated and the contractquantity of materials deposited at a site was small and awarded damages to OPCooften nonhazardous.  Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of $123 million plus prejudgment interest.  Any eventual proceeds willthe parties are financially sound enterprises.  At present, management’s estimates do not impact OPCo’s income statement due toanticipate material cleanup costs for any of the indemnification agreement with AEP Resources (AEPR), a nonutility subsidiary of AEP, whereby AEPR held OPCo harmless from market exposure related to the PPA.identified Superfund sites.

In May 2007, the United States Court of Appeals for the Second Circuit ruled that the lower court was correct in finding that TEM breached the PPA 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 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

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.  In September 2007, the Surface Transportation 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 this ruling, PSO, as operator of the plant, adjusted the provision recorded in prior periods.  PSO deferred its immaterial share of the provision under its fuel mechanism 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 disputeddefend its position that PSO paid BNSF all amounts to the extent possible.owed.

FERC Long-term Contracts – Affecting AEP East Companies and AEP West Companies

In 2002, the FERC held a hearing related to a complaint filed by Nevada Power Company and Sierra Pacific Power Company (the Nevada utilities).  The complaint sought to break long-term contracts entered during the 2000 and 2001 California energy price spike which the customers alleged were “high-priced.”  The complaint alleged that AEP subsidiaries sold power at unjust and unreasonable prices because the market for power was allegedly dysfunctional at the time such contracts were executed.  An ALJ recommended rejection of the complaint, holding 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 affirmingrejected the ALJ’s decision.complaint.  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,That decision was appealed and argued before the U.S. Supreme Court decided to review the Ninth Circuit’s decision.in February 2008.  Management is unable to predict the outcome of these proceedings or their impact on future results of operations and cash flows.  The Registrant Subsidiaries asserted claims against certain companies that sold power to them, which was resold to the Nevada utilities, seeking to recover a portion of any amounts the Registrant Subsidiaries may owe to the Nevada utilities.

5.
ACQUISITION

2008

None

2007

Darby Electric Generating Station – Affecting CSPCo

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

 6.
BENEFIT PLANS

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

The Registrant Subsidiaries adopted SFAS 158 as of December 31, 2006.  The Registrant Subsidiaries recorded a SFAS 71 regulatory asset for qualifying SFAS 158 costs of regulated operations that for ratemaking purposes are 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 September 30, 2007March 31, 2008 and 2006:2007:
     
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
 Three Months Ended March 31, Three Months Ended March 31, 
 
2007
  
2006
  
2007
  
2006
 2008 2007 2008 2007 
Nine Months Ended September 30, 2007 and 2006
 
(in millions)
 
(in millions) 
Service Cost $72  $71  $32  $30 $25 $24 $10 $10 
Interest Cost  176   171   78   76  63  59  28  26 
Expected Return on Plan Assets  (254)  (248)  (78)  (70) (84) (85) (28) (26)
Amortization of Transition Obligation  -   -   20   21  -  -  7  7 
Amortization of Net Actuarial Loss  44   59   9   15  9  15  3  3 
Net Periodic Benefit Cost
 $38  $53  $61  $72 $13 $13 $20 $20 

The following table provides Registrant Subsidiaries’ the net periodic benefit cost (credit) for the plans by Registrant Subsidiary for the three and nine months ended September 30, 2007March 31, 2008 and 2006:2007:
     
Other Postretirement
 
  
Pension Plans
  
Benefit Plans
 
  
2007
  
2006
  
2007
  
2006
 
Three Months Ended September 30, 2007 and 2006
 
(in thousands)
 
APCo $841  $1,469  $3,560  $4,487 
CSPCo  (258)  205   1,491   1,807 
I&M  1,900   2,331   2,530   2,949 
OPCo  362   823   2,802   3,395 
PSO  425   979   1,431   1,588 
SWEPCo  747   1,222   1,420   1,578 

    
Other Postretirement
    Other Postretirement 
 
Pension Plans
  
Benefit Plans
  Pension Plans Benefit Plans 
 
2007
  
2006
  
2007
  
2006
  Three Months Ended March 31, Three Months Ended March 31, 
Nine Months Ended September 30, 2007 and 2006
 
(in thousands)
 
 2008 2007 2008 2007 
Company (in thousands) 
APCo $2,525  $4,406  $10,680  $13,465  $835 $842 $3,699 $3,560 
CSPCo  (773)  615   4,473   5,417  (349) (257) 1,498  1,491 
I&M  5,700   6,992   7,591   8,855  1,821  1,900  2,423  2,530 
OPCo  1,088   2,478   8,405   10,187  319  245  2,816  2,802 
PSO  1,273   2,935   4,292   4,764  508  424  1,387  1,431 
SWEPCo  2,240   3,672   4,258   4,734  935  746  1,376  1,419 

 
7.
BUSINESS SEGMENTS

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

 8.
INCOME TAXES

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

The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System.  The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense.  The tax benefit of the Parent is allocated to its subsidiaries with taxable income.  With the exception of the loss of the Parent, the method of allocation approximatesreflects a separate return result for each company in the consolidated group.

Audit StatusThe Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2000. However, AEP has filed refund claims with the IRS for years 1997 through 2000 for the CSW pre-merger tax period, which are currently being reviewed. The Registrant Subsidiaries have completed the exam for the years 2001 through 2003 and have issues that will be pursued at the appeals level. The returns for the years 2004 through 2006 are presently under audit by the IRS.  Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions.  Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations.

The Registrant Subsidiaries also file income tax returns in various state and local jurisdictions. With few exceptions, the Registrant Subsidiaries are no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years before 2000.  The IRS and otherThese taxing authorities routinely examine the tax returns.  Management believes that the Registrant Subsidiaries have filedtheir tax returns with positions that may be challenged byand the tax authorities.  The Registrant Subsidiaries are currently under examination in several state and local jurisdictions.  Management believes that previously filed tax returns have positions that may be challenged by these tax authorities.  However, management does not believe that the ultimate resolution of these audits will materially impact results of operations. With few exceptions, the Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2000.

The AEP System settled withState Tax Legislation

In March 2008, the IRS on all issues fromGovernor of West Virginia signed legislation providing for, among other things, a reduction in the audits of consolidated federalWest Virginia corporate income tax returns for years priorrate from 8.75% to 1997.8.5% beginning in 2009.  The 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 anticipates payment for the agreed adjustments to occur during 2007.  Returns for the years 2000 through 2005 are presently being audited by the IRS and management anticipates that the audit of the 2000 through 2003 years will be completed by the end of 2007.

FIN 48 Adoption

The 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)
 
APCo $2,685 
CSPCo  3,022 
I&M  (327)
OPCo  5,380 
PSO  386 
SWEPCo  1,642 
At January 1, 2007, the total amount of unrecognized tax benefits under FIN 48 for each Registrant Subsidiary was as follows:
Company
 
(in millions)
 
APCo $21.7 
CSPCo  25.0 
I&M  18.2 
OPCo  49.8 
PSO  8.9 
SWEPCo  7.1 

Management 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)
 
APCo $5.5 
CSPCo  9.3 
I&M  6.0 
OPCo  9.0 
PSO  4.4 
SWEPCo  2.8 

At January 1, 2007, the total amount of unrecognized tax benefits that, if recognized, would affect the effectivecorporate income tax rate for each Registrant Subsidiary was as follows:

Company
 
(in millions)
 
APCo $5.4 
CSPCo  13.8 
I&M  5.4 
OPCo  23.4 
PSO  1.2 
SWEPCo  1.2 

At January 1, 2007, tax positions for each Registrant Subsidiary, for whichcould also be reduced to 7.75% in 2012 and 7% in 2013 contingent upon the ultimate deductibility is highlystate government achieving certain but the timingminimum levels of such deductibility is uncertain, was as follows:

Company
 
(in millions)
 
APCo $13.7 
CSPCo  3.9 
I&M  10.3 
OPCo  14.2 
PSO  7.1 
SWEPCo  5.1 

Because ofshortfall reserve funds.  Management continues to evaluate the impact of deferred tax accounting, other than interest and penalties, the disallowancelaw change, but does not expect the law change to have a material impact on results of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment ofoperations, cash to the taxing authority to an earlier period.

Prior to the adoption of FIN 48, the Registrant Subsidiaries recorded interest and penalty accruals related to income tax positions in tax accrual accounts.  With the adoption of FIN 48, the Registrant Subsidiaries began recognizing interest accruals related to income tax positions in interest expense and penalties in Other Operations.  As of January 1, 2007, each Registrant Subsidiary accrued for the payment of uncertain interest and penalties as follows:

Company
 
(in millions)
 
APCo $4.6 
CSPCo  1.7 
I&M  2.8 
OPCo  4.3 
PSO  2.7 
SWEPCo  2.0 
Michigan Tax Restructuring (Affecting I&M)flows or financial condition.

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 iswas effective January 1, 2008 and replacesreplaced the Michigan Single Business Tax that is scheduled to expireexpired 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 1515- 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 subsidiariesRegistrant 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.

 9.9.       FINANCING ACTIVITIES
FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first ninethree months of 20072008 were:

   
Principal
 
Interest
 
Due
Company
 
Type of Debt
 
Amount
 
Rate
 
Date
 Type of Debt 
Principal
Amount
 
Interest
Rate
 
Due
Date
   
(in thousands)
 
(%)
     (in thousands) (%)  
Issuances:
                 
APCo Pollution Control Bonds $75,000 Variable 2037 Senior Unsecured Notes $500,000 7.00 2038
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 Pollution Control Bonds  65,000 4.90 2037
OPCo Senior Unsecured Notes  400,000 Variable 2010
PSO Pollution Control Bonds  12,660 4.45 2020
SWEPCo Senior Unsecured Notes  250,000 5.55 2017

Company Type of Debt 
Principal
Amount Paid
 
Interest
Rate
 
Due
Date
    (in thousands) (%)  
Retirements and   
   Principal Payments:
         
APCo Other $3 13.718 2026
CSPCo Senior Unsecured Notes  52,000 6.51 2008
I&M Pollution Control Bonds  45,000 Variable 2009
I&M Pollution Control Bonds  50,000 Variable 2025
OPCo Notes Payable  1,463 6.81 2008
OPCo Notes Payable  6,000 6.27 2009
SWEPCo Notes Payable  1,101 4.47 2011
SWEPCo Notes Payable  750 Variable 2008

In May 2007,April 2008, I&M issued $40 million of 5.25% Pollution Control Bonds due in 2025.

In April 2008, CSPCo remarketed its outstanding $50$44.5 million and $56 million Pollution Control Bonds, resulting in new interest rates of 4.85% and 5.10%, respectively.  No proceeds were received related to these remarketings.  The principal amounts of the Pollution Control Bonds are reflected in Long-term Debt on CSPCo's Condensed Consolidated Balance Sheet as of March 31, 2008.

In April 2008, SWEPCo remarketed its outstanding $81.7 million Pollution Control Bonds, resulting in a new interest rate of 4.625%4.95%.  No proceeds were received related to this remarketing.  The principal amount of the Pollution Control Bonds is reflected in Long-term Debt on I&M’sSWEPCo's Condensed Consolidated Balance Sheet as of September 30, 2007.March 31, 2008.

    
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
In April 2008, APCo repurchased its $40 million and $30 million of variable rate interest Pollution Control Bonds, each due in 2019, and $17.5 million variable rate interest Pollution Control Bonds due in 2021.

In April 2008, CSPCo repurchased its $48.6 million of variable rate interest Pollution Control Bonds due in 2038.

As of March 31, 2008, the Registrant Subsidiaries had tax-exempt long-term debt (Pollution Control Bonds) sold at auction rates that are reset every 7, 28 or 35 days.  This debt is insured by bond insurers previously AAA-rated, namely Ambac Assurance Corporation, Financial Guaranty Insurance Co., MBIA Insurance Corporation and XL Capital Assurance Inc.  The amounts outstanding by Registrant Subsidiary are as follows:

  As of March 31, 
  2008 
  (in millions) 
APCo $213 
CSPCo  193 
I&M  167 
OPCo  468 
PSO  34 
SWEPCo  176 

Due to the exposure that these bond insurers have in connection with recent developments in the subprime credit market, the credit ratings of these insurers have been downgraded or placed on negative outlook.  These market factors have contributed to higher interest rates in successful auctions and increasing occurrences of failed auctions, including many of the auctions of the Registrant Subsidiaries’ tax-exempt long-term debt.  The instruments under which the bonds are issued allow for conversion to other short-term variable-rate structures, term-put structures and fixed-rate structures.  During the first quarter of 2008, the Registrant Subsidiaries reduced their outstanding auction rate securities by redeeming or repurchasing $95 million of such debt securities.  In April 2008, they converted, refunded or provided notice to convert or refund $779 million of the outstanding auction rate securities.  Management plans to continue this conversion and refunding process for the remaining $471 million to other permitted modes, including term-put and fixed-rate structures through the third quarter of 2008.  The conversions will likely result in higher interest charges compared to prior year but lower than the failed auction rates for this tax-exempt long-term debt.

Lines of Credit – AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of its subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries.  The AEP System 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 September 30, 2007March 31, 2008 and December 31, 20062007 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 ninethree months ended September 30, 2007March 31, 2008 are described in the following table:

             
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
  
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, 2008  
Authorized
Short-Term Borrowing
Limit
 
Company
 
(in thousands)
  (in thousands) 
APCo $406,262  $96,543  $147,582  $48,303  $38,573  $600,000  $307,226  $269,987  $261,154  $264,528  $261,823  $600,000 
CSPCo  137,696   35,270   51,927   13,551   (123,043)  350,000   195,038   -   139,127   -   (163,999)  350,000 
I&M  100,374   52,748   50,998   34,749   (24,234)  500,000   239,125   -   102,772   -   (185,938)  500,000 
OPCo  447,335   1,564   161,746   1,564   (85,341)  600,000   201,263   -   102,902   -   (87,408)  600,000 
PSO  242,097   -   133,404   -   (187,492)  300,000   62,159   59,384   20,089   30,664   (62,159)  300,000 
SWEPCo  240,786   48,979   79,890   29,653   (155,869)  350,000   89,210   -   48,654   -   (89,210)  350,000 

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:
 
 
Nine Months Ended September 30,
 Three Months Ended March 31,
 
2007
 
2006
 2008 2007
Maximum Interest Rate 5.94% 5.41% 5.37% 5.43%
Minimum Interest Rate 5.30% 3.63% 3.39% 5.30%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the ninethree months ended September 30,March 31, 2008 and 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
 
Nine Months Ended September 30,
  
Nine Months Ended September 30,
 
Average Interest Rate for Funds
Borrowed from the Utility Money
Pool for the
Three Months Ended March 31,
 
Average Interest Rate for Funds
Loaned to the Utility Money
Pool for the
Three Months Ended March 31,
 
2007
 
2006
  
2007
 
2006
 2008 2007 2008 2007
Company
 
(in percentage)
   
APCo 5.41 4.62  5.84 4.98  4.21% 5.34% 3.46% -%
CSPCo 5.48 4.73  5.39 4.63  4.01% 5.35% -% 5.33%
I&M 5.38 4.81  5.84 -  3.99% 5.34% -% -%
OPCo 5.39 4.83  5.43 5.12  4.29% 5.34% -% -%
PSO 5.47 5.02  - 4.36  3.51% 5.34% 4.57% -%
SWEPCo 5.54 5.01  5.34 4.36  4.00% 5.35% -% 5.34%

Short-term Debt

The Registrant Subsidiaries’ outstanding short-term debt was as follows:

   
September 30, 2007
 
December 31, 2006
 
   
Outstanding
 
Interest
 
Outstanding
 
Interest
   March 31, 2008  December 31, 2007 
 
Type of Debt
 
Amount
 
Rate
 
Amount
 
Rate
 Type of Debt 
Outstanding
Amount
 
Interest
Rate
  
Outstanding
Amount
 
Interest
Rate
 
Company
   
(in millions)
   
(in millions)
      (in thousands)    (in thousands)   
OPCo Commercial Paper – JMG $2 5.3588% $1  5.56%Commercial Paper – JMG $- -% $701 5.35%
SWEPCo Line of Credit – Sabine  26 6.07%  17  6.38%Line of Credit – Sabine Mining Company - -%  285 5.25%

Dividend Restrictions
Credit Facilities

UnderIn April 2008, the Federal Power Act,Parent, the Registrant Subsidiaries are restricted from paying dividends out of stated capital.
Sale of Receivables – AEP CreditEast companies and the AEP West companies entered into a $650 million 3-year credit agreement with a third party.  Concurrently, the Parent, the AEP East companies and the AEP West companies also entered into a $350 million 364-day credit agreement with a third party. 

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 20062007 Annual Report should also be read in conjunction with this report.

Significant Factors

Ohio Restructuring

As permitted by theThe current Ohio restructuring legislation permits CSPCo and OPCo canto implement market-based rates effective January 2009, following the expiration of itstheir RSPs on December 31, 2008.  The RSP plans include generation rates which are between PUCO approved rates and higher market rates.  In August 2007,April 2008, the Ohio legislature passed legislation was introduced thatwhich allows utilities to set prices by filing an Electric Security Plan along with the ability to simultaneously file a Market Rate Option.  The PUCO would significantly reducehave authority to approve or modify the likelihoodutility’s request to set prices.  Both alternatives would involve earnings tests monitored by the PUCO.  The legislation still must be signed by the Ohio governor and will become law 90 days after the governor’s signature.  Management is analyzing the financial statement implications of the pending legislation on CSPCo’s and OPCo’s ability to charge market-based rates for generation atsupply business, more specifically, whether the expirationfuel management operations 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 meet the criteria for application of SFAS 71.    The financial statement impact of the pending legislation will transition to market pricing, extend their RSP rates, with or without modification, or become subject tonot be known until the PUCO acts on specific proposals made by CSPCo and OPCo.  Management expects a legislative reinstatementPUCO decision in the fourth quarter of some form of cost-based regulation for their generation supply business on January 1, 2009.2008.

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
               Commercial
     
Total
          
Operation
     Total       Nominal Operation
Operating
 
Project
   
Projected
        
MW
 
Date
 Project   Projected       MW Date
Company
 
Name
 
Location
 
Cost (a)
 
CWIP
 
Fuel Type
 
Plant Type
 
Capacity
 
(Projected)
 Name Location Cost (a) CWIP (b) Fuel Type Plant Type Capacity (Projected)
     
(in millions)
 
(in millions)
             (in millions) (in millions)        
SWEPCo Mattison Arkansas $122(b)$52 Gas Simple-cycle 340(b)2007
PSO Southwestern Oklahoma  59(c) 45 Gas Simple-cycle 170 2008 Southwestern(c)Oklahoma $58  $-  Gas Simple-cycle  170 2008
PSO Riverside Oklahoma  58(c) 45 Gas Simple-cycle 170 2008 Riverside Oklahoma 59  57  Gas Simple-cycle  170 2008
AEGCo Dresden(d)Ohio  265(d) 88 Gas Combined-cycle 580 2009 Dresden(d)Ohio      305(d)  101  Gas Combined-cycle  580 2010
SWEPCo Stall Louisiana  375  15 Gas Combined-cycle 480 2010 Stall Louisiana 378  76  Gas Combined-cycle  500 2010
SWEPCo Turk(e)Arkansas  1,300(e) 206 Coal Ultra-supercritical 600(e)2011 Turk(e)Arkansas      1,522(e)  313  Coal Ultra-supercritical 
 
600(e)2012
APCo Mountaineer West Virginia  2,230  - Coal IGCC 629 2012 Mountaineer West Virginia 2,230  -  Coal IGCC  629 2012
CSPCo/OPCo Great Bend Ohio  2,230(f) - Coal IGCC 629 2017 Great Bend Ohio     2,700(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.Amount includes AFUDC.
(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 plantSouthwestern Units were placed in service at the time these units are placed in service.on February 29, 2008.
(d)In September 2007, AEGCo purchased the under-constructionpartially completed Dresden plant from Dresden Energy LLC, a subsidiary of Dominion Resources, Inc., for $85 million, which is included in the “Total Projected Cost” section above.
(e)SWEPCo plans to own approximately 73%, or 438440 MW, totaling about $950$1,110 million in capital investment.  The increase in the cost estimate relates to cost escalations due to the delay in receipt of permits and approvals.  See “Turk Plant” section below.
(f)Front-end engineering and design study is complete.  Cost estimates, updated to reflect cost escalations due to revised commercial operation date of 2017, 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.PUCO.  See “Ohio IGCC Plant” section below.of Note 3.

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 twelve months effective July 1, 2006.  Through September 30, 2007, CSPCo and OPCo each recorded pre-construction IGCC regulatory assets of $10 million and each collected the entire $12 million approved by the PUCO.  As of September 30, 2007, CSPCo and OPCo have recorded a liability of $2 million each for the 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 Phase 1 costs collected for pre-construction costs, associated with items that may be utilized in projects at other sites, must be refunded to Ohio ratepayers with interest.  The PUCO deferred ruling on cost recovery for Phases 2 and 3 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 pre-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 1 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 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 be re-considering various alternative options to meet its capacity needs in the future.

Turk Plant

In August 2006, SWEPCo announced plans to build the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas named Turk Plant.Arkansas.  Ultra-supercritical technology uses higher temperatures and higher pressures to produce electricity more efficiently – thereby using less fuel and providing substantial emissions reductions.  SWEPCo submitted filings with the Arkansas Public Service Commission (APSC) in December 2006 andAPSC, the PUCT and the LPSC in February 2007 to seek approvals to proceed withseeking certification of the plant.  In September 2007, OMPA signed a joint ownership agreement and agreed toSWEPCo will 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.  During 2007, SWEPCo signed joint ownership agreements with the Oklahoma Municipal Power Authority (OMPA), the Arkansas Electric Cooperative Corporation (AECC) and the East Texas Electric Cooperative (ETEC) for the remaining 27% of the Turk facility.  The Turk Plant is estimated to cost $1.3$1.5 billion in total with SWEPCo’s portion estimated to cost $950 million,$1.1 billion, excluding AFUDC.  If approved on a timely basis, the plant is expected to be in-service in mid-2011.2012.  As of September 2007,March 31, 2008, including the joint owners’ share, SWEPCo incurred and capitalized approximately $206$313 million of expenditures and has significant contractual construction commitments for an additional $875$838 million.  IfAs of March 31, 2008, if the Turk Plant is not approved,plant were to be cancelled, then cancellation fees may be required toof $67 million would terminate SWEPCo’s commitment.these construction commitments.

In AugustNovember 2007, hearings began before the APSC seeking pre-approvalgranted approval to build the plant.  Certain landowners filed a notice of appeal to the Arkansas State Court of Appeals.  SWEPCo is still awaiting permit approvals from the Arkansas Department of Environmental Quality and the U.S. Army Corps of Engineers.  Both permits are expected to be received by the third quarter of 2008.  The PUCT held hearings in October 2007.  In January 2008, a Texas ALJ issued a report, which concluded that SWEPCo failed to prove there was a need for 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 staffTexas ALJ recommended that SWEPCo’s application be denied suggestingdenied.  The PUCT has voted to reopen the constructionrecord and conduct additional hearings.  SWEPCo expects a decision from the PUCT in the last half of 2008.  In March 2008, the LPSC approved the certificate to construct 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.Plant.  If SWEPCo isdoes not authorizedreceive appropriate authorizations and permits to build the Turk plant,Plant, SWEPCo could incur significant cancellation fees to terminate its commitments and would be responsible to reimburse OMPA, AECC and ETEC for their share of paid costs.  If that occurred, SWEPCo would seek recovery of incurred costs including any cancellation fees.  If SWEPCo cannot recover incurredits capitalized costs including any cancellation fees and joint owner reimbursements.  If SWEPCo cannot recover its costs, it could adversely affecthave an adverse effect on future results of operations, cash flows and possibly financial condition.

APCo’s 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 June 2007, APCo filed testimony with the WVPSC supporting the requests for a CCN and for pre-approval of a surcharge rate mechanism to provide for the timely recovery of both pre-construction costs and the ongoing finance costs of the project during the construction period as well as the capital costs, operating costs and a return on equity once the facility is placed into commercial operation.  In July 2007, APCo filed a request with the Virginia SCC for a rate adjustment clause to recover pre-construction and future construction financing costs associated with the IGCC plant.

In March 2008, the WVPSC granted APCo the CCN to build the plant and the request for cost recovery.  Various intervenors filed petitions with the WVPSC to reconsider the order.

The Virginia SCC issued an order in April 2008 denying APCo’s requests on the basis of their belief that the estimated cost may be significantly understated.  The Virginia SCC also expressed concern that the $2.2 billion estimated cost of the IGCC plant did not include a retrofitting of carbon capture and sequestration facilities.  In April 2008, APCo filed a petition for reconsideration in Virginia.  If necessary, APCo will seek recovery of its prudently incurred deferred pre-construction costs.

Through March 31, 2008, APCo deferred for future recovery pre-construction IGCC costs of $16 million.  If these deferred costs are not recoverable, it would have an adverse effect on future results of operations and cash flows.

Environmental Matters

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

·
Requirements under the Clean Air Act (CAA)CAA to reduce emissions of sulfur dioxide (SOSO2), nitrogen oxide (NONOx), 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 (COCO2) and other greenhouse gases (GHG) emissions to address concerns about global climate change.  All of these matters are discussed in the “Environmental Matters” section of “Combined Management’s  Discussion and Analysis of Registrant Subsidiaries” in the 20062007 Annual Report.

Environmental Litigation

New Source Review (NSR) Litigation:  In 1999, the  The Federal EPA, a number of states and certain special interest groups filed complaints alleging that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities, including the Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric Company, Ohio EdisonDayton Power and Light Company Southern Indiana Gas & Electric Company, Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company(DP&L) and Duke Energy Ohio, Inc. (Duke), modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA.  In April 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 intosettled their complaints under a consent decreedecree.  Litigation continues against two plants CSPCo jointly-owns with the Federal EPA, the DOJ, the statesDuke 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, 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 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

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 CSPCo’s three jointly-owned plants, operated by Duke Energy Ohio, Inc. and Dayton Power and Light Company, continues.DP&L, which they operate.  Management is unable to predict the outcome of these cases.  Management believes the Registrant SubsidiariesCSPCo can recover any capital and operating costs of additional pollution control equipment that may be required through future regulated rates or market prices for electricity.  If the Registrant Subsidiaries areCSPCo is unable to recover such costs or if material penalties are imposed, it would adversely affect future results of operations and cash flows.

Clean Water Act RegulationsRegulation

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

 
Estimated
 
Compliance
 
Investments
 Estimated Compliance Investments 
Company
 
(in millions)
 (in millions) 
APCo $21 $21 
CSPCo 19  19 
I&M 118  118 
OPCo 31  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 seekThe Registrant Subsidiaries sought further review orand filed for relief from the schedules included in thetheir permits.

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

Adoption of New Accounting Pronouncements

FIN 48 clarifiesIn September 2006, the FASB issued SFAS 157, enhancing existing guidance for fair value measurement of assets and liabilities and instruments measured at fair value that are classified in shareholders’ equity.  The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures.  It emphasizes that fair value is market-based with the highest measurement hierarchy level being market prices in active markets.  The standard requires fair value measurements be disclosed by hierarchy level, an entity include its own credit standing in the measurement of its liabilities and modifies the transaction price presumption.  The standard also nullifies the consensus reached in EITF Issue No. 02-3 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3) that prohibited the recognition of trading gains or losses at the inception of a derivative contract, unless the fair value of such derivative is supported by observable market data.  In February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-1 “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13” which amends SFAS 157 to exclude SFAS 13 “Accounting for Leases” and other accounting pronouncements that address fair value measurements for uncertainty in income taxespurposes of lease classification or measurement under SFAS 13.  In February 2008, the FASB issued FSP FAS 157-2 “Effective Date of FASB Statement No. 157” which delays the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized 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 recognizedor disclosed at fair value in the financial statements.  It requiresstatements on a recurring basis (at least annually).  The provisions of SFAS 157 are applied prospectively, except for a) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF 02-3, b) existing hybrid financial instruments measured initially at fair value using the transaction price and c) blockage discount factors.  The Registrant Subsidiaries partially adopted SFAS 157 effective January 1, 2008.  The Registrant Subsidiaries will fully adopt SFAS 157 effective January 1, 2009 for items within the scope of FSP FAS 157-2.  Although the statement is applied prospectively upon adoption, in accordance with the provisions of SFAS 157 related to EITF 02-3, APCo, CSPCo and OPCo reduced beginning retained earnings by $286 thousand (net of tax of $154 thousand), $316 thousand (net of tax of $170 thousand) and $282 thousand (net of tax of $152 thousand), respectively, for the transition adjustment.  SWEPCo’s transition adjustment was a favorable $10 thousand (net of tax of $6 thousand) adjustment to beginning retained earnings.  The impact of considering AEP’s credit risk when measuring the fair value of liabilities, including derivatives, had an immaterial impact on fair value measurements upon adoption.  See “SFAS 157 “Fair Value Measurements” (SFAS 157)” section of Note 2.

In February 2007, the FASB issued SFAS 159, permitting entities to choose to measure many financial instruments and certain other items at fair value.  The standard also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement determinationattributes for recognized tax positions based onsimilar types of assets and liabilities.  If the largest amount of benefit thatfair value option 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 thatelected, the cumulative effect of applying this interpretation bethe first remeasurement to fair value is reported and disclosed as ana cumulative effect adjustment to the opening balance of retained earnings.  The statement is applied prospectively upon adoption.  The Registrant Subsidiaries adopted SFAS 159 effective January 1, 2008.  At adoption, the Registrant Subsidiaries did not elect the fair value option for any assets or liabilities.

In March 2007, the FASB ratified EITF 06-10, a consensus on collateral assignment split-dollar life insurance arrangements in which an employee owns and controls the insurance policy.  Under EITF 06-10, an employer should recognize a liability for the postretirement benefit related to a collateral assignment split-dollar life insurance arrangement in accordance with SFAS 106 “Employers' Accounting for Postretirement Benefits Other Than Pension” or Accounting Principles Board Opinion No. 12 “Omnibus Opinion – 1967” if the employer has agreed to maintain a life insurance policy during the employee's retirement or to provide the employee with a death benefit based on a substantive arrangement with the employee.  In addition, an employer should recognize and measure an asset based on the nature and substance of the collateral assignment split-dollar life insurance arrangement.  EITF 06-10 requires recognition of the effects of its application as either (a) a change in accounting principle through a cumulative effect adjustment to retained earnings or other components of equity or net assets in the statement of financial position at the beginning of the year of adoption or (b) a change in accounting principle through retrospective application to all prior periods.  The Registrant Subsidiaries adopted EITF 06-10 effective January 1, 2008.  The impact of this standard was an unfavorable cumulative effect adjustment, net of tax, to beginning retained earnings as follows:
  Retained   
  Earnings Tax 
Company Reduction Amount 
  (in thousands) 
APCo $2,181 $1,175 
CSPCo  1,095  589 
I&M  1,398  753 
OPCo  1,864  1,004 
PSO  1,107  596 
SWEPCo  1,156  622 

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

In April 2007, the FASB issued FASB Staff Position FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1).  It amends FASB Interpretation No. 39 “Offsetting of Amounts Related to Certain Contracts” by replacing the interpretation’s definition of contracts with the definition of derivative instruments per SFAS 133.  It also requires entities that offset fair values of derivatives with the same party under a netting agreement to net the fair values (or approximate fair values) of related cash collateral.  The entities must disclose whether or not they offset fair values of derivatives and presented separately.related cash collateral and amounts recognized for cash collateral payables and receivables at the end of each reporting period.  The Registrant Subsidiaries adopted FIN 4839-1 effective January 1, 2007.2008.  This standard changed the method of netting certain balance sheet amounts and reduced assets and liabilities.  It requires retrospective application as a change in accounting principle.  See “FIN 48 “Accounting for Uncertainty in Income Taxes” and FASB“FASB Staff Position FIN 48-1 “Definition39-1 “Amendment ofSettlement in FASB Interpretation No. 48”39” (FIN 39-1)” section of Note 22.  Consequently, the Registrant Subsidiaries reduced total assets and see Note 8 – Income Taxes.  The impact of this interpretation was an unfavorable (favorable) adjustment to retained earningsliabilities on  their December 31, 2007 balance sheet as follows:

Company
 
(in thousands)
  (in thousands) 
APCo $2,685  $7,646 
CSPCo  3,022   4,423 
I&M  (327)  4,251 
OPCo  5,380   5,234 
PSO  386   187 
SWEPCo  1,642   229 

CONTROLS AND PROCEDURES

During the thirdfirst quarter of 2007,2008, management, including the principal executive officer and principal financial officer of each of AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo (collectively, the Registrants), evaluated the Registrants’ disclosure controls and procedures.  Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.  Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of September 30, 2007March 31, 2008 these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives.  The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the thirdfirst quarter of 20072008 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.


PART II.  OTHER INFORMATION

Item 1.     Legal Proceedings

For a discussion of material legal proceedings, see Note 4, Commitments, Guarantees and Contingencies, incorporated herein by reference.

Item 1A.  Risk Factors

Our Annual Report on Form 10-K for the year ended December 31, 20062007 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 20062007 Annual Report on Form 10-K.

General Risks of Our Regulated OperationsRelated to Market, Economic or Financial Volatility

Downgrades in our credit ratings could negatively affect our ability to access capital and/or to operate our power trading businesses.  (Applies to each registrant.)

Our request for rate recoverySince the bankruptcy of plant construction costs may not be approved for SWEPCo. (Applies to AEP and 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 withEnron, the APSC in December 2006credit ratings agencies have periodically reviewed our capital structure and the PUCTquality and LPSC in February 2007stability of our earnings.  Any negative ratings actions could constrain the capital available to seek approvalsour industry and could limit our access to proceed with the plant.  In September 2007, OMPA signed a joint ownership agreementfunding for our operations.  Our business is capital intensive, and agreedwe are dependent upon our ability to own approximately 7% of the Turk Plant.  SWEPCo continues discussions with Arkansas Electric Cooperative Corporationaccess capital at rates 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 expectedterms we determine to be in-service in mid-2011.  As of September 2007, SWEPCo incurredattractive.  If our ability to access capital becomes significantly constrained, our interest costs will likely increase and capitalized approximately $206 millionour financial condition could be harmed 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.could be adversely affected.

Plant pre-constructionIf Moody’s or S&P were to downgrade the long-term rating of any of the securities of the registrants, particularly below investment grade, the borrowing costs may notof that registrant would increase, which would diminish its financial results.  In addition, the registrant’s potential pool of investors and funding sources could decrease.  In 2008, Fitch downgraded the senior unsecured debt rating of PSO and SWEPCo to BBB+ with stable outlook.  Moody’s placed the senior unsecured debt rating of APCo, OPCo, SWEPCo and TCC on negative outlook in January 2008.  Moody’s assigns the following ratings to the senior unsecured debt of these companies:  APCo Baa2, OPCo A3,  SWEPCo Baa1 and TCC Baa2.

Our power trading business relies on the investment grade ratings of our individual public utility subsidiaries’ senior unsecured long-term debt.  Most of our counterparties require the creditworthiness of an investment grade entity to stand behind transactions.  If those ratings were to decline below investment grade, our ability to operate our power trading business profitably would be recovered for PSO. diminished because we would likely have to deposit cash or cash-related instruments which would reduce our profits.

Risks Relating to State Restructuring

In Ohio, our future rates are uncertain. (Applies to AEP, OPCo and PSO.CSPCo.)

The current Ohio restructuring legislation permits CSPCo and OPCo to implement market-based rates effective January 2009, following the expiration of their RSPs on December 31, 2008.  The RSP plans include generation rates which are between PUCO approved rates and higher market rates.  In July 2006, PSO announced plansApril 2008, the Ohio legislature passed legislation which allows utilities to enter intoset prices by filing an agreementElectric Security Plan along with Oklahoma Gasthe ability to simultaneously file a Market Rate Option.  The PUCO would have authority to approve or modify the utility’s request to set prices.  Both alternatives would involve earnings tests monitored by the PUCO.  The legislation still must be signed by the Ohio governor and Electric (OG&E)will become law 90 days after the governor’s signature.  Management is analyzing the financial statement implications of the pending legislation on CSPCo’s and OPCo’s generation supply business, more specifically, whether the fuel management operations of CSPCo and OPCo meet the criteria for application of SFAS 71.    The financial statement impact of the pending legislation will not be known until the PUCO acts on specific proposals made by CSPCo and OPCo.  Management expects a PUCO decision in the fourth quarter of 2008. A return to build a 950 MW pulverized coal ultra-supercritical generating unit atfull cost-based regulation could have an adverse impact on the site of OG&E’s existing Sooner Plant near Red Rock, in north central Oklahoma.  In October 2007, the OCC issued a final order denying PSO’s application for construction pre-approval stating PSO failed to fully study other alternatives.  As of September 2007, PSO deferred approximately $20 million of pre-construction costs.  If recovery of pre-construction costs is denied,financial condition, future results of operations and cash flows would be adversely affected.of CSPCo and OPCo.

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 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 $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, it would disallow $90 million of the AEP East 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. 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 October 2007, CSPCo and OPCo made a filing with the PUCO under 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 in January 2008 and are subject to refund until the PUCO issues a final order in the matter.  Management is unable to predict the outcome of this filing and its impact on future results of operations and cash flows.

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.  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.  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.

There is uncertainty as to our recovery of stranded costs resulting from industry restructuring in Texas.  (Applies to 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.)

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.)

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.)

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 hearing on the motion 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 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 September 30, 2007March 31, 2008 of equity securities that are registered by AEP (or its publicly-traded subsidiaries) pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASES OF EQUITY SECURITIES
Period
 
Total Number
of Shares
Purchased
 
Average Price
Paid per Share
  
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 
Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
 
07/01/07 – 07/31/07  93(a)$81.25   - $- 
08/01/07 – 08/31/07  20(b) 75   -  - 
09/01/07 – 09/30/07  1(c) 78   -  - 

(a)PeriodAPCo repurchased 93 shares
Total Number
of its 4.5% cumulative preferred stock, in a privately-negotiated transaction outsideShares
Purchased
Average Price
Paid per Share
Total Number of an announced program.Shares Purchased as Part of Publicly Announced Plans or ProgramsMaximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
(b)01/01/08 – 01/31/08APCo repurchased 20 shares of its 4.5% cumulative preferred stock, in privately-negotiated transactions outside of an announced program.-$--$-
(c)02/01/08 – 02/29/08APCo repurchased 1 share of its 4.5% cumulative preferred stock, in privately-negotiated transactions outside of an announced program.----
03/01/08 – 03/31/08----

Item 4. Submission of Matters to a Vote of Security Holders5.  Other Information

NONE

Item 5.  Other Information6.  Exhibits

NONE

Item 6.  Exhibits

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

12 – Computation of Consolidated Ratio of Earnings to Fixed Charges.

AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

31(a) – Certification of AEP Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(c)31(b) – Certification of AEP Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

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, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo

32(a) – Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
32(b) – Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.

 

SIGNATURE




Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.  The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.


AMERICAN ELECTRIC POWER COMPANY, INC.



By: /s/Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer




APPALACHIAN POWER COMPANY
COLUMBUS SOUTHERN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY




By: /s/Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer




Date:  November 2, 2007May 1, 2008