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, 2007
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____

Commission
 
Registrant, State of Incorporation,
 
I.R.S. Employer
File Number
 
Address of Principal Executive Offices, and Telephone Number
 
Identification No.
         
1-3525
 
AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation)
 
13-4922640
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, or a non-accelerated filer.  See definition of ‘accelerated filer and large accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check One)
 
Large accelerated filer     X                                         Accelerated filer                                           Non-accelerated filer         

Indicate by check mark whether 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, or non-accelerated filers.  See definition of ‘accelerated filer and large accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check One)
 
Large accelerated filer                                               Accelerated filer                                             Non-accelerated filer     X  
 
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
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, 2007
       
American Electric Power Company, Inc.
   
      400,006,022
     
($6.50 par value)
Appalachian Power Company
   
13,499,500
     
(no par value)
Columbus Southern Power Company
   
16,410,426
     
(no par value)
Indiana Michigan Power Company
   
1,400,000
     
(no par value)
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, 2007

 
Glossary of Terms
 
Forward-Looking Information
 
Part I. FINANCIAL INFORMATION
   
 
Items 1, 2 and 3 - Financial Statements, Management’s Financial Discussion and Analysis and Quantitative and Qualitative Disclosures About Risk Management Activities:
American Electric Power Company, Inc. and Subsidiary Companies:
 
Management’s Financial Discussion and Analysis of Results of Operations
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
Condensed Consolidated Financial Statements
 
Index to Condensed Notes to Condensed Consolidated Financial Statements
   
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

ADITC
 
Accumulated Deferred Investment Tax Credits.
AEGCo
 
AEP Generating Company, an AEP electric utility subsidiary.
AEP or Parent
 
American Electric Power Company, Inc.
AEP Consolidated
 
AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit
 
AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated domestic electric utility companies.
AEP East companies
 
APCo, CSPCo, I&M, KPCo and OPCo.
AEP System or the System
 
American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP System Power Pool or AEP
  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 companies
 
PSO, SWEPCo, TCC and TNC.
AEPEP
 
AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, asset management and commercial and industrial sales in the deregulated Texas market.
AEPSC
 
American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC
 
Allowance for Funds Used During Construction.
ALJ
 
Administrative Law Judge.
AOCI
 
Accumulated Other Comprehensive Income (Loss).
APCo
 
Appalachian Power Company, an AEP electric utility subsidiary.
ARO
 
Asset Retirement Obligations.
CAA
 
Clean Air Act.
CO2
 
Carbon Dioxide.
Cook Plant
 
Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo
 
Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW
 
Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CTC
 
Competition Transition Charge.
DETM
 
Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
DOJ
 
United States Department of Justice.
E&R
 
Environmental compliance and transmission and distribution system reliability.
EDFIT
 
Excess Deferred Federal Income Taxes.
EITF
 
Financial Accounting Standards Board’s Emerging Issues Task Force.
ERCOT
 
Electric Reliability Council of Texas.
FASB
 
Financial Accounting Standards Board.
Federal EPA
 
United States Environmental Protection Agency.
FERC
 
Federal Energy Regulatory Commission.
FIN
 
FASB Interpretation No.
FIN 46
 
FIN 46, “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.
NRC
 
Nuclear Regulatory Commission.
NSR
 
New Source Review.
NYMEX
 
New York Mercantile Exchange.
OATT
 
Open Access Transmission Tariff.
OCC
 
Corporation Commission of the State of Oklahoma.
OPCo
 
Ohio Power Company, an AEP electric utility subsidiary.
OTC
 
Over the counter.
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, SWEPCo.
Risk Management Contracts
 
Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
 
A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned by AEGCo and I&M.
RSP
 
Ohio Rate Stabilization Plan.
RTO
 
Regional Transmission Organization.
S&P
 
Standard and Poor’s.
SEC
 
United States Securities and Exchange Commission.
SECA
 
Seams Elimination Cost Allocation.
SFAS
 
Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board.
SFAS 71
 
Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation.”
SFAS 133
 
Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.”
SFAS 157
 
Statement of Financial Accounting Standards No. 157, “Fair Value Measurements.”
SFAS 158
 
Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”
SFAS 159
 
Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.”
SIA
 
System Integration Agreement.
SO2
 
Sulfur Dioxide.
SPP
 
Southwest Power Pool.
Stall 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.
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 for new investments, transmission service and environmental compliance).
·
Resolution of litigation (including pending Clean Air Act enforcement actions and disputes arising from the bankruptcy of Enron Corp. and related matters).
·
Our ability to constrain operation and maintenance costs.
·
The economic climate and growth in our service territory and changes in market demand and demographic patterns.
·
Inflationary and interest rate trends.
·
Our ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities.
·
Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
·
Actions of rating agencies, including changes in the ratings of debt.
·
Volatility and changes in markets for electricity, natural gas and other energy-related commodities.
·
Changes in utility regulation, including the potential for new legislation in Ohio and membership in and integration into RTOs.
·
Accounting pronouncements periodically issued by accounting standard-setting bodies.
·
The performance of our pension and other postretirement benefit plans.
·
Prices for power that we generate and sell at wholesale.
·
Changes in technology, particularly with respect to new, developing or alternative sources of generation.
·
Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events.


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



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

EXECUTIVE OVERVIEW

Regulatory Activity

The status of base rate filings ongoing or finalized this year with implemented rates are:

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


(a)
The difference between the requested and implemented amounts of annual rate increase is partially offset by approximately $35 million of incremental E&R costs which APCo has reflected as a regulatory asset.  APCo will file for recovery through the E&R surcharge mechanism in 2008.  APCo also implemented, beginning September 1, 2007 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.
(b)
Management plans to seek rehearing of the PUCO decision.
(c)
Implemented $9 million in July 2007, increased to $10 million upon OCC order in October 2007.

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

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

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

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 OPERATIONS

Our principal operating business segments and their related business activities are as follows:

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

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

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

The table below presents our consolidated Income Before Discontinued Operations and Extraordinary Loss for the three and nine months ended September 30, 2007 and 2006.  We reclassified prior year amounts to conform to the current year’s segment presentation.
   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2007
   
2006
   
2007
   
2006
 
   
(in millions)
 
Utility Operations
  $
388
    $
378
    $
879
    $
902
 
MEMCO Operations
   
18
     
19
     
40
     
54
 
Generation and Marketing
   
3
     
4
     
17
     
10
 
All Other (a)
    (2 )     (136 )     (1 )     (151 )
Income Before Discontinued Operations
  and Extraordinary Loss
  $
407
    $
265
    $
935
    $
815
 

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

Third Quarter of 2007 Compared to Third Quarter of 2006

Income Before Discontinued Operations and Extraordinary Loss in 2007 increased $142 million compared to 2006 primarily due to a $136 million after-tax impairment of the Plaquemine Cogeneration Facility recorded in August 2006.

Average basic shares outstanding for the three-month period increased to 399 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.

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
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, 2007 and 2006

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

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

Summary of Heating and Cooling Degree 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)
 
Weather Summary
                       
Eastern Region
                       
Actual – Heating (a)
   
2
     
10
     
2,041
     
1,573
 
Normal – Heating (b)
   
7
     
7
     
1,973
     
1,999
 
                                 
Actual – Cooling (c)
   
808
     
685
     
1,189
     
914
 
Normal – Cooling (b)
   
685
     
688
     
963
     
970
 
                                 
Western Region (d)
                               
Actual – Heating (a)
   
0
     
0
     
994
     
664
 
Normal – Heating (b)
   
2
     
2
     
993
     
1,007
 
                                 
Actual – Cooling (c)
   
1,406
     
1,468
     
2,084
     
2,325
 
Normal – Cooling (b)
   
1,411
     
1,410
     
2,084
     
2,079
 

(a)
Eastern region and western region heating degree days are calculated on a 55 degree temperature base.
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
(c)
Eastern region and western region cooling degree days are calculated on a 65 degree temperature base.
(d)
Western region statistics represent PSO/SWEPCo customer base only.

Third Quarter of 2007 Compared to Third Quarter of 2006

Reconciliation of Third Quarter of 2006 to Third Quarter of 2007
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 million to $388 million in 2007.  The key driver of the increase was a $134 million increase in Gross Margin partially offset by a $119 million increase in Operating Expenses and Other and a $5 million increase in Income Tax Expense.

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

·
Retail Margins increased $155 million primarily due to the following:
 
·
A $29 million increase at APCo related to the Virginia base rate case and the West Virginia construction surcharge.
 
·
A $29 million increase related to Ormet, a new industrial customer in Ohio, effective January 1, 2007.  See “Ormet” section of Note 3.
 
·
A $23 million increase related to increased residential and commercial usage and customer growth.
 
·
A $16 million increase in usage related to weather.  As compared to the prior year, our eastern region experienced an 18% increase in cooling degree days partially offset by a 4% decrease in cooling degree days in our western region.
 
·
A $15 million increase related to new rates implemented in our Ohio jurisdictions as approved by the PUCO in our RSPs.
 
·
A $15 million increase related to new rates in Texas.
 
·
A $14 million increase related to increased sales to municipal, cooperative and other customers primarily resulting from new power supply contracts.
 
These increases were partially offset by:
 
·
A $15 million decrease in financial transmission rights revenue, net of congestion, primarily due to fewer transmission constraints within the PJM market. Financial transmission rights are financial instruments which entitle the holder to receive compensation for transmission charges that arise when the PJM market is congested.
·
Margins from Off-system Sales increased $36 million primarily due to favorable fuel reconciliations in our western territory, benefits from our eastern natural gas fleet, higher power prices, and higher sales volumes in the east.
·
Transmission Revenues, Net decreased $58 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 were essentially flat as a result of higher securitization revenue at TCC from the $1.7 billion securitization in October 2006 partially offset by lower gains on sale of emission allowances.  Securitization revenue represents amounts collected to recover securitization bond principal and interest payments related to TCC’s securitized transition assets and are fully offset by amortization and interest expenses.

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

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

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

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

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

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

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

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

·
Other Operation and Maintenance expenses increased $154 million primarily due to a $77 million expense resulting from the NSR settlement.  The remaining increases relate to generation expenses 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 million in 2006 to $18 million in 2007.  Operating expenses increased $2 million mainly due to the increased fleet size, rising fuel costs and wage increases.

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

Income Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations segment decreased from $54 million in 2006 to $40 million in 2007.  MEMCO operated approximately 11% more barges in the first nine months of 2007 than 2006; however, revenue remained flat as reduced imports, primarily 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.  In 2006, we recorded a $136 million after-tax impairment of the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006.  In 2007, we had an after-tax gain of $10 million on the sale of investment securities.

AEP System Income Taxes

Income Tax Expense increased $72 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
 
   
($ in millions)
 
Long-term Debt, Including Amounts Due
   Within One Year
  $
14,776
      58.3 %   $
13,698
      59.1 %
Short-term Debt
   
587
     
2.3
     
18
     
0.0
 
Total Debt
   
15,363
     
60.6
     
13,716
     
59.1
 
Common Equity
   
9,909
     
39.1
     
9,412
     
40.6
 
Preferred Stock
   
61
     
0.3
     
61
     
0.3
 
                                 
Total Debt and Equity Capitalization
  $
25,333
      100.0 %   $
23,189
      100.0 %

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

Liquidity

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

We manage our liquidity by maintaining adequate external financing commitments.  At September 30, 2007, our available liquidity was approximately $2.6 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
   

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

Sale of Receivables

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

Debt Covenants and Borrowing Limitations

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

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

Under a regulatory order, our utility subsidiaries, other than TCC, cannot incur additional indebtedness if the issuer’s common equity would constitute less than 30% of its capital.  In addition, this order restricts those utility subsidiaries from issuing long-term debt unless that debt will be rated investment grade by at least one nationally recognized statistical rating organization.  At 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, we had not exceeded those authorized limits.
 
Credit Ratings

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

                                   
Moody’s
   
S&P
   
Fitch
                                                 
AEP Short Term Debt
P-2
   
A-2
   
F-2
AEP Senior Unsecured Debt
Baa2
   
BBB
   
BBB

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

Cash Flow

Managing our cash flows is a major factor in maintaining our liquidity strength.
   
Nine Months Ended
 
   
September 30,
 
   
2007
   
2006
 
   
(in millions)
 
Cash and Cash Equivalents at Beginning of Period
  $
301
    $
401
 
Net Cash Flows From Operating Activities
   
1,630
     
2,196
 
Net Cash Flows Used For Investing Activities
    (2,935 )    
(2,457
Net Cash Flows From Financing Activities
   
1,200
     
119
 
Net Decrease in Cash and Cash Equivalents
    (105 )    
(142
Cash and Cash Equivalents at End of Period
  $
196
    $
259
 
 
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
 
   
September 30,
 
   
2007
   
2006
 
   
(in millions)
 
Net Income
  $
858
    $
821
 
Less:  Discontinued Operations, Net of Tax
    (2 )     (6 )
Income Before Discontinued Operations
   
856
     
815
 
Depreciation and Amortization
   
1,144
     
1,084
 
Other
    (370 )    
297
 
Net Cash Flows From Operating Activities
  $
1,630
    $
2,196
 

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

Net Cash Flows From Operating Activities were $1.6 billion in 2007. We produced Income Before Discontinued Operations of $856 million adjusted for noncash expense items, primarily depreciation and amortization.  Other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The current period activity in these asset and liability accounts relates to a number of items, the most significant of which relates to the Texas CTC refund of fuel over-recovery.

Net Cash Flows From Operating Activities were $2.2 billion in 2006.  We produced Income Before Discontinued Operations of $815 million adjusted for 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 represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The current period activity in these asset and liability accounts relates to a number of items; the most significant is a $235 million decrease in cash related to customer deposits held for trading activities generally due to lower gas and power market prices.

Investing Activities
   
Nine Months Ended
 
   
September 30,
 
   
2007
   
2006
 
   
(in millions)
 
Construction Expenditures
  $ (2,595 )   $
(2,428
Acquisition of Darby, Dresden and Lawrenceburg Plants
    (512 )    
-
 
Proceeds from Sales of Assets
   
78
     
120
 
Other
   
94
     
(149
Net Cash Flows Used For Investing Activities
  $ (2,935 )   $
(2,457

Net Cash Flows Used For Investing Activities were $2.9 billion in 2007 primarily due to Construction Expenditures for our environmental, distribution and new generation investment plan and purchases of gas-fired generating units.

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

We forecast approximately $1 billion of construction expenditures for the remainder of 2007.  Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  These construction expenditures will be funded with cash from operations and financing activities.

Financing Activities
   
Nine Months Ended
 
   
September 30,
 
   
2007
   
2006
 
   
(in millions)
 
Issuance/Retirement of Debt, Net
  $
1,623
    $
529
 
Dividends Paid on Common Stock
    (467 )    
(437
Other
   
44
     
27
 
Net Cash Flows From Financing Activities
  $
1,200
    $
119
 

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

Net Cash Flows From Financing Activities in 2006 were $119 million.  During 2006, we issued $115 million of obligations relating to pollution control bonds, issued $1 billion of senior unsecured notes and retired $396 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.

We expect to issue debt in the capital markets of approximately $675 million to fund our capital investment plans for the remainder of 2007.

Off-balance Sheet Arrangements

Under a limited set of circumstances we enter into off-balance sheet arrangements to accelerate cash collections, reduce operational expenses and spread risk of loss to third parties.  Our internal 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
 
   
(in millions)
 
AEP Credit Accounts Receivable Purchase Commitments
  $
530
    $
536
 
Rockport Plant Unit 2 Future Minimum Lease Payments
   
2,290
     
2,364
 
Railcars Maximum Potential Loss From Lease Agreement
   
30
     
31
 

For complete information on each of these off-balance sheet arrangements see the “Off-balance Sheet Arrangements” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2006 Annual Report.

Summary Obligation Information

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

Other

Texas REPs

As part of the purchase-and-sale agreement related to the sale of our Texas REPs in 2002, we retained the right to share in earnings with Centrica from the two REPs above a threshold amount through 2006 if the Texas retail market developed increased earnings opportunities.  We received $20 million and $70 million payments in 2007 and 2006, respectively, for our share in earnings.  The payment we received in 2007 was the final payment under the earnings sharing agreement.

SIGNIFICANT FACTORS

We continue to be involved in various matters described in the “Significant Factors” section of Management’s Financial Discussion and Analysis of Results of Operations in our 2006 Annual Report.  The 2006 Annual Report should be read in conjunction with this report in order to understand significant factors without material changes in status since the issuance of our 2006 Annual Report, but may have a material impact on our future results of operations, cash flows and financial condition.
 
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.

Texas Restructuring

TCC recovered its net recoverable stranded generation costs through a securitization financing and is refunding its net other true-up items through a CTC rate rider credit under 2006 PUCT orders.  TCC appealed the PUCT stranded costs true-up and related orders seeking relief in both state and federal court on the grounds that certain aspects of the orders are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law and fail to fully compensate TCC for its net stranded cost and other true-up items.

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 on the carrying cost rate is ultimately upheld on appeal and remanded to the PUCT for reconsideration, the PUCT could either confirm the existing weighted average carrying cost (WACC) rate or 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 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 rulings to the Texas Court of Appeals.  Management cannot predict the outcome of these true-up and related proceedings.  If TCC ultimately succeeds in its appeals in both state and federal court, it could have a favorable effect on future results of operations, cash flows and financial condition.  If municipal customers and other intervenors succeed in their appeals, or if TCC has a tax normalization violation as discussed in the “TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes” section of Note 3, it could have a substantial adverse effect on future results of operations, cash flows and financial condition.

Virginia Restructuring

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

SECA Revenue Subject to Refund

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

(a)
Amount excludes AFUDC.
(b)
Includes Units 3 and 4, 150 MW, declared in commercial operation on July 12, 2007 with construction costs totaling $55 million.
(c)
In April 2007, the OCC approved that PSO will recover through a rider, subject to a $135 million cost cap, all of the traditional costs associated with plant in service at the time these units are placed in service.
(d)
In September 2007, AEGCo purchased the under-construction Dresden plant from Dresden Energy LLC, a subsidiary of Dominion Resources, Inc., for $85 million, which is included in the “Total Projected Cost” section above.
(e)
SWEPCo plans to own approximately 73%, or 438 MW, totaling about $950 million in capital investment.  See “Turk Plant” section below.
(f)
Front-end engineering and design study is complete.  Cost estimates are not yet filed with the PUCO due to the pending appeals to the Supreme Court of Ohio resulting from the PUCO’s April 2006 opinion and order.  See “Ohio IGCC Plant” section below.

AEP acquired the following generation facilities:

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

(a)
CSPCo purchased Darby Electric Generating Station (Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light Company.
(b)
AEGCo purchased Lawrenceburg Generating Station (Lawrenceburg), adjacent to I&M’s Tanners Creek Plant, from an affiliate of Public Service Enterprise Group (PSEG).  AEGCo sells the power to CSPCo under a FERC-approved unit power agreement.
 
Ohio IGCC Plant

In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs related to building and operating a 629 MW IGCC power plant using clean-coal technology.  The application proposed three phases of cost recovery associated with the IGCC plant:  Phase 1, recovery of $24 million in pre-construction costs during 2006; Phase 2, concurrent recovery of construction-financing costs; and Phase 3, recovery or refund in distribution rates of any difference between the market-based standard service offer price for generation and the cost of operating and maintaining the plant, including a return on and return of the ultimate cost to construct the plant, originally projected to be $1.2 billion, along with fuel, consumables and replacement power costs.  The proposed recoveries in Phases 1 and 2 would be applied against the average 4% limit on additional generation rate increases CSPCo and OPCo could request under their RSPs.

In April 2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase 1 of the cost recovery proposal.  In June 2006, the PUCO issued another order approving a tariff to recover Phase 1 pre-construction costs over a period of no more than 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 a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas named Turk Plant.  SWEPCo submitted filings with the Arkansas Public Service Commission (APSC) in December 2006 and the PUCT and LPSC in February 2007 to seek approvals to proceed with the plant.  In September 2007, OMPA signed a joint ownership agreement and agreed to own approximately 7% of the Turk Plant.  SWEPCo continues discussions with Arkansas Electric Cooperative Corporation and North Texas Electric Cooperative to become potential partners in the Turk Plant.  SWEPCo anticipates owning approximately 73% of the Turk Plant and will operate the facility.  The Turk Plant is estimated to cost $1.3 billion in total with SWEPCo’s portion estimated to cost $950 million, excluding AFUDC.  If approved on a timely basis, the plant is expected to be in-service in mid-2011.  As of September 2007, SWEPCo incurred and capitalized approximately $206 million and has contractual commitments for an additional $875 million.  If the Turk Plant is not approved, cancellation fees may be required to terminate SWEPCo’s commitment.

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

Electric Transmission Texas LLC Joint Venture (Utility Operations segment)

In January 2007, we signed 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 filed with the PUCT in January 2007 requesting regulatory approval to operate as an electric transmission utility in Texas, to transfer from TCC to ETT approximately $76 million of transmission assets under construction and to establish a wholesale transmission tariff for ETT.  ETT also requested PUCT approval of initial rates based on an 11.25% return on equity.  A hearing was held in July 2007.  On October 31, 2007, the PUCT issued an order approving the transaction and initial rates based on  9.96% return on equity.  ETT and MidAmerican are reviewing the order.

In February 2007, TCC also made a regulatory filing at the FERC regarding the transfer of 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 PUCT issued an interim order in August 2007.  In that order, the PUCT directed ERCOT to perform studies by April 2008 that determine the necessary transmission upgrades to accommodate between 10,000 and 22,800 MW of wind development from CREZs across the Texas panhandle and central West Texas.  The PUCT also indicated in its interim order that it plans to select transmission construction designees in the first quarter of 2008.

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

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

On June 22, 2007, PJM’s Board authorized the construction of a major new transmission line to address the reliability and efficiency needs of the PJM system.  PJM has identified a need for a new line as early as 2012.  The line would be 765kV for most of its length and would run approximately 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 cost of the Amos-to-Kemptown Line is estimated to be approximately $1.8 billion and AEP’s estimated share will be approximately $600 million.  The PATH companies will not be consolidated with AEP for financial or tax reporting purposes.
 
Litigation

In the ordinary course of business, we and our subsidiaries are involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be.  Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases that have a probable likelihood of loss and the loss amount can be estimated.  For details on regulatory proceedings and our pending litigation see Note 4 – Rate Matters, Note 6 – Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2006 Annual Report.  Additionally, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies included herein. Adverse results in these proceedings have the potential to materially affect the results of operations, cash flows and financial condition of AEP and its subsidiaries.

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

Environmental Matters

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

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

In addition, we are engaged in litigation with respect to certain environmental matters, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of spent nuclear fuel and future decommissioning of our nuclear units.  We are also monitoring possible future requirements to reduce carbon dioxide (CO2) emissions to address concerns about global climate change.  All of these matters are discussed in the “Environmental Matters” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2006 Annual Report.

Environmental Litigation

New Source Review (NSR) Litigation:  In 1999, the Federal EPA, 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 seek further review or relief from the schedules included in our permits.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2006 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

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


 
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

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

All Other includes natural gas operations which holds forward natural gas contracts that were not sold with the natural gas pipeline and storage assets.  These contracts are primarily financial derivatives, along with physical contracts, which will gradually liquidate and completely expire in 2011.  Our risk objective is to keep these positions generally risk neutral through maturity.

Our Generation and Marketing segment holds power sale contracts 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, swaps and other derivative contracts to offset price risk where appropriate.  We engage in risk management of electricity, natural gas, coal, and emissions and to a lesser degree other commodities associated with our energy business.  As a result, we are subject to price risk.  The amount of risk taken is determined by the commercial operations group in accordance with the market risk policy approved by the Finance Committee of our Board of Directors.  Our market risk management staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures.  The CORC consists of our President – AEP Utilities, Chief Financial Officer, Senior Vice President of Commercial Operations and Treasurer.  When commercial activities exceed predetermined limits, we modify the positions to reduce the risk to be within the limits unless specifically approved by the CORC.

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

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

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

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
September 30, 2007
(in millions)
   
Utility Operations
   
Generation and
Marketing
   
All Other
   
Sub-Total MTM Risk Management Contracts
   
PLUS: MTM of Cash Flow and Fair Value Hedges
   
Total
 
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
 

MTM Risk Management Contract Net Assets (Liabilities)
Nine Months Ended September 30, 2007
(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
 

(a)
Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term.  The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)
Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)
“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected on the Condensed Consolidated Statements of Income.  These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.

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

The following table presents:

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

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

(a)
Prices Provided by Other External Sources – OTC Broker Quotes reflects information obtained from over-the-counter brokers (OTC), industry services, or multiple-party online platforms.
(b)
Prices Based on Models and Other Valuation Methods is used in the absence of 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 is limited, such valuations are classified as modeled.  Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available including values determinable by other third party transactions.
(c)
There is mark-to-market value of $35 million in individual periods beyond 2011.  $14 million of this mark-to-market value is in 2012, $8 million is in 2013, $7 million is in 2014, $2 million is in 2015, $2 million is in 2016 and $2 million is in 2017.
 
 
The determination of the point at which a market is no longer 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, 2007

Commodity
 
Transaction Class
 
Market/Region
 
Tenor
           
(in Months)
Natural Gas
 
Futures
 
NYMEX / Henry Hub
 
60
   
Physical Forwards
 
Gulf Coast, Texas
 
18
   
Swaps
 
Northeast, Mid-Continent, Gulf Coast, Texas
 
18
   
Exchange Option Volatility
 
NYMEX / Henry Hub
 
12
Power
 
Futures
 
AEP East - PJM
 
27
   
Physical Forwards
 
AEP East - Cinergy
 
39
   
Physical Forwards
 
AEP - PJM West
 
39
   
Physical Forwards
 
AEP - Dayton (PJM)
 
39
   
Physical Forwards
 
AEP - ERCOT
 
27
   
Physical Forwards
 
AEP - Entergy
 
15
   
Physical Forwards
 
West Coast
 
39
   
Peak Power Volatility (Options)
AEP East - Cinergy, PJM
 
12
Emissions
 
Credits
 
SO2, NOx
 
39
Coal
 
Physical Forwards
 
PRB, NYMEX, CSX
 
39


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, 2006 to September 30, 2007.  The following table also indicates what portion of designated, effective hedges are expected to be reclassified into net income in the next 12 months.  Only contracts designated as cash flow hedges are recorded in AOCI.  Therefore, economic hedge contracts which are not designated as effective cash flow hedges are marked-to-market and are included in the previous risk management tables.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
Nine Months Ended September 30, 2007
(in millions)
         
Interest
       
         
Rate and
       
         
Foreign
       
   
Power
   
Currency
   
Total
 
Beginning Balance in AOCI, December 31, 2006
  $
17
    $ (23 )   $ (6 )
Changes in Fair Value
   
4