AEP Second Quarter 2005 10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended June 30, 2005
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____

Commission
 
Registrant, State of Incorporation,
 
I.R.S. Employer
File Number
 
Address of Principal Executive Offices, and Telephone Number
 
Identification No.
         
1-3525
 
AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation)
 
13-4922640
0-18135
 
AEP GENERATING COMPANY (An Ohio Corporation)
 
31-1033833
0-346
 
AEP TEXAS CENTRAL COMPANY (A Texas Corporation)
 
74-0550600
0-340
 
AEP TEXAS NORTH COMPANY (A Texas Corporation)
 
75-0646790
1-3457
 
APPALACHIAN POWER COMPANY (A Virginia Corporation)
 
54-0124790
1-2680
 
COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation)
 
31-4154203
1-3570
 
INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)
 
35-0410455
1-6858
 
KENTUCKY POWER COMPANY (A Kentucky Corporation)
 
61-0247775
1-6543
 
OHIO POWER COMPANY (An Ohio Corporation)
 
31-4271000
0-343
 
PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)
 
73-0410895
1-3146
 
SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation)
 
72-0323455
         
All Registrants
 
1 Riverside Plaza, Columbus, Ohio 43215-2373
   
   
Telephone (614) 716-1000
   

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

Indicate by check mark whether American Electric Power Company, Inc. is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Yes   X  
NO ___

Indicate by check mark whether AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company, are accelerated filers (as defined in Rule 12b-2 of the Exchange Act).
Yes ___
NO   X  

AEP Generating Company, AEP Texas North Company, Columbus Southern Power Company, Kentucky Power Company and Public Service Company of Oklahoma meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.





   
Number of Shares of Common Stock Outstanding at July 29, 2005
 
       
American Electric Power Company, Inc.
 
384,772,013
 
AEP Generating Company
 
1,000
 
AEP Texas Central Company
 
2,211,678
 
AEP Texas North Company
 
5,488,560
 
Appalachian Power Company
 
13,499,500
 
Columbus Southern Power Company
 
16,410,426
 
Indiana Michigan Power Company
 
1,400,000
 
Kentucky Power Company
 
1,009,000
 
Ohio Power Company
 
27,952,473
 
Public Service Company of Oklahoma
 
9,013,000
 
Southwestern Electric Power Company
 
7,536,640
 
       



 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX TO QUARTERLY REPORT ON FORM 10-Q
June 30, 2005

 
 
 
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
 
     
Condensed Notes to Consolidated Financial Statements
 
       
   
AEP Generating Company:
     
Management’s Narrative Financial Discussion and Analysis
 
     
Condensed Financial Statements
 
       
   
AEP Texas Central Company and Subsidiary:
     
Management’s Financial Discussion and Analysis
 
     
Quantitative and Qualitative Disclosures About Risk Management Activities
 
     
Condensed Consolidated Financial Statements
 
       
   
AEP Texas North Company:
     
Management’s Narrative Financial Discussion and Analysis
 
     
Quantitative and Qualitative Disclosures About Risk Management Activities
 
     
Condensed 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
 
       
   
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
 
       
   
Indiana Michigan Power Company and Subsidiaries:
     
Management’s Financial Discussion and Analysis
 
     
Quantitative and Qualitative Disclosures About Risk Management Activities
 
     
Condensed Consolidated Financial Statements
 
       
   
Kentucky Power Company:
     
Management’s Narrative Financial Discussion and Analysis
 
     
Quantitative and Qualitative Disclosures About Risk Management Activities
 
     
Condensed Financial Statements
 
       
   
Ohio Power Company Consolidated:
     
Management’s Financial Discussion and Analysis
 
     
Quantitative and Qualitative Disclosures About Risk Management Activities
 
     
Condensed Consolidated Financial Statements
 
         
   
Public Service Company of Oklahoma:
     
Management’s Narrative Financial Discussion and Analysis
 
     
Quantitative and Qualitative Disclosures About Risk Management Activities
 
     
Condensed Financial Statements
 
       
   
Southwestern Electric Power Company Consolidated:
     
Management’s Financial Discussion and Analysis
 
     
Quantitative and Qualitative Disclosures About Risk Management Activities
 
     
Condensed Consolidated Financial Statements
 
       
   
Condensed Notes to Financial Statements of Registrant Subsidiaries
 
       
   
Combined Management’s Discussion and Analysis of Registrant Subsidiaries
 
       
Item 4.
 
Controls and Procedures
 
       
Part II. OTHER INFORMATION
 
Item 1.
 
Legal Proceedings
 
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
 
           
Exhibits:
 
           
Exhibit 10 (a)
 
           
Exhibit 10 (b)
 
           
Exhibit 12
 
           
Exhibit 31(a)
 
           
Exhibit 31(b)
 
           
Exhibit 31(c)
 
           
Exhibit 31(d)
 
           
Exhibit 32(a)
 
           
Exhibit 32(b)
 
       
 
SIGNATURE
 

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







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

 
Term
 
 
Meaning

AEGCo
 
            AEP Generating Company, an electric utility subsidiary of AEP.
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.
AEPES
 
AEP Energy Services, Inc., a subsidiary of AEP Resources, Inc.
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.
AEPSC
 
American Electric Power Service Corporation, a service subsidiary providing management and professional
  services to AEP and its subsidiaries.
AEP West companies
 
PSO, SWEPCo, TCC and TNC.
AFUDC
 
Allowance for Funds Used During Construction.
ALJ
 
Administrative Law Judge.
APCo
 
Appalachian Power Company, an AEP electric utility subsidiary.
ARO
 
Asset Retirement Obligations.
CAA
 
Clean Air Act.
COLI
 
Corporate owned, life insurance program.
Cook Plant
 
The 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.).
DETM
 
            Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
DOE
 
            United States Department of Energy.
ECAR
 
East Central Area Reliability Council.
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 46
 
FASB Interpretation No. 46, “Consolidation of Variable Interest Entities.”
GAAP
 
Generally Accepted Accounting Principles.
HPL
 
Houston Pipeline Company.
I&M
 
Indiana Michigan Power Company, an AEP electric utility subsidiary.
IPP
 
Independent Power Producers.
IURC
 
Indiana Utility Regulatory Commission.
JMG
 
JMG Funding LP.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
KPSC
 
Kentucky Public Service Commission.
KWH
 
Kilowatthour.
LIG
 
Louisiana Intrastate Gas, a former AEP subsidiary.
ME SWEPCo
 
Mutual Energy SWEPCo L.P., a Texas retail electric provider.
MLR
 
Member load ratio, the method used to allocate AEP Power Pool transactions to its members.
MTM
 
Mark-to-Market.
MW
 
Megawatt.
MWH
 
Megawatthour.
NOx
 
Nitrogen oxide.
Nonutility Money Pool
 
AEP System’s Nonutility Money Pool.
NYMEX
 
New York Mercantile Exchange.
OATT
 
Open Access Transmission Tariff.
OCC
 
Oklahoma Corporation Commission.
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
 
The Public Utility Commission of Texas.
PUHCA
 
Public Utility Holding Company Act.
PURPA
 
Public Utility Regulatory Policies Act of 1978.
Registrant Subsidiaries
 
AEP subsidiaries which are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
  TCC and TNC.
REP
 
            Texas Retail Electric Provider.
Risk Management Contracts
 
Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
 
A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned by
  AEGCo and I&M.
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 109
 
Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes.
SFAS 133
 
Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging
  Activities.
SNF
 
Spent Nuclear Fuel.
SO2
 
Sulfur Dioxide.
SPP
 
Southwest Power Pool.
STP
 
South Texas Project Nuclear Generating Plant.
SWEPCo
 
Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC
 
AEP Texas Central Company, an AEP electric utility subsidiary.
Tenor
 
Maturity of a contract.
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.
TVA
 
Tennessee Valley Authority.
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.
Zimmer Plant
 
William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by CSPCo.





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 of fuel suppliers and transporters.
·
Availability of generating capacity and the performance of our generating plants.
·
The ability to recover regulatory assets and stranded costs in connection with deregulation.
·
The ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·
New legislation, litigation and government regulation including requirements for reduced emissions of sulfur, nitrogen, mercury, carbon 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.).
·
Our ability to constrain operation and maintenance costs.
·
Our ability to sell assets at acceptable prices and other acceptable terms, including rights to share in earnings derived from the assets subsequent to their sale.
·
The economic climate and growth in our service territory and changes in market demand and demographic patterns.
·
Inflationary 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 and number of participants in the energy trading market.
·
Changes in the financial markets, particularly those affecting the availability of capital and our ability to refinance existing debt at attractive rates.
·
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 membership and integration into regional transmission structures.
·
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.

 



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

EXECUTIVE OVERVIEW

Utility Operations Segment Results
Net income from our Utility Operations was $247 million for the second quarter of 2005, representing an increase of $63 million when compared with net income from our Utility Operations for the second quarter of 2004. The increase was due to higher retail and wholesale sales, lower maintenance and other operation expenses, the recognition of carrying costs for our Ohio companies’ environmental investments and regional transmission organization expenses and the accrual of carrying costs on our stranded costs in Texas.

The increase in retail sales is due to the continuing effect of customer growth and higher usage across all classes, partially due to warmer weather in the latter part of the second quarter of 2005. The increase in wholesale sales is from higher margins on off-system sales. Partially offsetting these favorable items are higher fuel costs, as further discussed below in the “Fuel Costs” section, and reduced transmission revenues.

Acquisitions
In May 2005, we announced an agreement to purchase the Waterford Energy Center for $220 million. The Waterford Energy Center is a natural-gas-fired plant with capacity of 821 megawatts located in Waterford, Ohio. This purchase is part of our broad strategy to meet the growing capacity needs of our customer base and reduce reliance on the marketplace. We expect this acquisition to close in the third quarter of 2005.

In June 2005, the PUCO ordered CSPCo to explore the purchase of the Ohio service territory of Monongahela Power, which includes approximately 29,000 customers. On August 2, 2005, we agreed to terms of a transaction, which includes the transfer of Monongahela Power’s Ohio customer base and the assets that serve those customers to CSPCo for an estimated sales price of approximately $55 million. The sale price will be adjusted based on book values of the acquired assets and liabilities at the closing date. We anticipate the purchase, subject to regulatory approval, to close late in the fourth quarter of 2005.

Environmental
In June 2005, we revised our environmental investment program that extends from 2004 through 2010 to a projected investment level of $4.1 billion, from our previous estimate of $3.7 billion. The increase is attributable to continued refinement of our forecast and the ongoing development of estimates for our remaining scrubber program. There could be additional changes in our investment program estimates as we further evaluate and monitor the impact of the Clean Air Interstate Rule and Clean Air Mercury Rule.
 
In June 2005, we announced five additional locations where we will invest in equipment to continue to improve the environmental performance of our coal-fired power plants including sites in West Virginia, Ohio, Kentucky and Texas. These projects will be completed between 2007 and 2010 and are included in both our previous and revised projected investment level discussed above.

Texas Regulatory Activity

Stranded Cost Recovery

During May 2005, TCC:

·
Sold its ownership interest in the South Texas Project (STP) nuclear plant for approximately $314 million and the assumption of liabilities of approximately $22 million;
·
Received a good cause exception to the true-up rule to allow TCC to make its true-up filing prior to the closing of the sale of TCC’s ownership interest in Oklaunion, which is still in litigation; and
·
Submitted its true-up filing to the PUCT for a final determination of stranded costs and other true-up amounts.

Texas Restructuring Legislation provides for a PUCT decision within 150 days after filing. A final order is expected in the fourth quarter of 2005.
 
TCC Rate Case
In June 2005, the PUCT orally approved a settlement in TCC’s rate case, which resulted in a net decrease of $9 million in base rates charged to retail electric providers and wholesale transmission customers. When coupled with reduced depreciation expense due to revised depreciation rates, the removal of a merger-related rate rider credit and other items that were approved in the settlement, TCC estimates that pretax income may improve by approximately $11 million per year.

Fuel Costs
Market prices for coal, natural gas and oil increased dramatically during 2004 and have continued to increase in 2005. These increasing fuel costs are the result of increasing worldwide demand, supply uncertainty, and transportation constraints, as well as other market factors. We manage price and performance risk, particularly for coal, through a portfolio of contracts of varying durations and other fuel procurement and management activities. We have fuel recovery mechanisms for about 45% of our fuel costs in our various jurisdictions. Additionally, about 25% of our fuel is used for off-system sales where prices for our power should allow us to recover our cost of fuel. Accordingly, we should recover approximately 70% of fuel cost increases. The remaining 30% of our fuel costs relate primarily to Ohio and West Virginia customers, where we do not have fuel cost recovery mechanisms. Such percentages are subject to change over time based on fuel cost impacts, fuel caps and freezes and changes to the recovery mechanisms at jurisdictions in our individual operating companies.

During the second quarter of 2005 as compared to the same period in 2004, higher coal costs reduced gross margins by approximately $44 million and our year-to-date reduction in gross margins related to fuel costs is approximately $100 million. Several major events have impacted fuel costs in 2005. In January, deliveries of coal were restricted due to flooding events and restricted shipping on the Ohio River at Belleville. Central Appalachian coal deliveries were also affected by rail transportation limitations resulting in performance issues among coal suppliers, the railroad, and AEP. The Union Pacific Railroad claimed, in mid-May, a force majeure event due to severe track damage impacting the delivery of Powder River Basin (PRB) coal. That claimed event has reduced, and will continue to reduce, PRB coal deliveries by roughly 15% through at least November 2005. Since PRB supplies tend to be lower priced than our average, delivered coal costs are being impacted. The fuel cost escalation that began in the second quarter of 2004 resulted in a larger year-over-year variance for the first half of 2005 than is expected in the second half of 2005.

Energy Policy Act of 2005
The United States House of Representatives and the United States Senate recently agreed to and passed legislation referred to as the Energy Policy Act of 2005. The President has not yet signed the Energy Policy Act of 2005 into law, but public statements from representatives of the White House indicate that he is likely to do so. The Energy Policy Act of 2005 repeals PUHCA, effective six months after the date of enactment. We believe adoption of the Energy Policy Act of 2005 may end litigation challenging our merger with CSW.  The Energy Policy Act of 2005 provides for tax credits for the development of certain clean coal and emissions technologies and would provide federal tax relief in support of our commitment to build IGCC generating units.
 
Additional Information
For additional information on our strategic outlook, see “Management’s Financial Discussion and Analysis of Results of Operations,” including “Business Strategy,” in our 2004 Annual Report. Also see the remainder of our “Management’s Financial Discussion and Analysis of Results of Operations” in this Form 10-Q, along with the Notes to Consolidated Financial Statements.

RESULTS OF OPERATIONS
 
Segments

As outlined in our 2004 Annual Report, our business strategy and the core of our business are to focus on domestic electric utility operations. Our previous decision that we no longer sought business interests outside of the footprint of our domestic core utility assets led us to embark on a divestiture of such noncore assets. Major asset divestitures included the sale in 2004 of two generating plants in the U.K., LIG and Jefferson Island Storage & Hub, and the sale in January 2005 of a 98% interest in the HPL assets. Consequently, the significance of our three Investments segments is declining.

Our principal operating business segments and their major activities are:

·
Utility Operations:
    ·
Domestic generation of electricity for sale to retail and wholesale customers.
    ·
Domestic electricity transmission and distribution.
 
·
Investments-Gas Operations:
    ·
Gas pipeline and storage services.
    ·
Gas marketing and risk management activities.
   
  LIG Pipeline Company and its subsidiaries, including Jefferson Island Storage & Hub LLC, were classified as discontinued operations during 2003
  and were sold during 2004. We sold a 98% controlling interest in HPL during the first quarter of 2005.
 
·
Investments-UK Operations:
    ·
Generation of electricity in the U.K. for sale to wholesale customers.
    ·
Coal procurement and transportation to our plants.
   
  UK Operations were classified as discontinued operations during 2003 and were sold during the third quarter of 2004.
 
·
Investments-Other:
    ·
Bulk commodity barging operations, wind farms, independent power producers and other energy
supply related businesses.
 
 
  Four independent power producers were sold during the third and fourth quarters of 2004.
                     
AEP Consolidated Results

Our consolidated Net Income for the three and six months periods ended June 30, 2005 and 2004 was as follows (Earnings and Weighted Average Shares Outstanding in millions):

   
Three Months Ended June 30,
 
Six Months Ended June 30,
 
   
2005
 
2004
 
2005
 
2004
 
                                      
   
Earnings
 
EPS
 
Earnings
 
EPS
 
Earnings
 
EPS
 
Earnings
 
EPS
 
Utility Operations
 
$
247
 
$
0.64
 
$
184
 
$
0.46
 
$
600
 
$
1.54
 
$
488
 
$
1.23
 
Investments - Gas Operations
   
(2
)
 
(0.01
)
 
(4
)
 
(0.01
)
 
8
   
0.02
   
(14
)
 
(0.03
)
Investments - Other
   
(1
)
 
-
   
(4
)
 
(0.01
)
 
4
   
0.01
   
-
   
-
 
All Other (a)
   
(26
)
 
(0.06
)
 
(25
)
 
(0.06
)
 
(40
)
 
(0.10
)
 
(34
)
 
(0.09
)
Income Before Discontinued Operations
   
218
   
0.57
   
151
   
0.38
   
572
   
1.47
   
440
   
1.11
 
                                                   
Investments - Gas Operations
   
-
   
-
   
2
   
-
   
-
   
-
   
1
   
-
 
Investments - UK Operations
   
-
   
-
   
(52
)
 
(0.13
)
 
(5
)
 
(0.01
)
 
(64
)
 
(0.16
)
Investments - Other
   
3
   
0.01
   
(1
)
 
-
   
9
   
0.02
   
5
   
0.01
 
Discontinued Operations, Net of Tax
   
3
   
0.01
   
(51
)
 
(0.13
)
 
4
   
0.01
   
(58
)
 
(0.15
)
                                                   
Net Income
 
$
221
 
$
0.58
 
$
100
 
$
0.25
 
$
576
 
$
1.48
 
$
382
 
$
0.96
 
                                                   
Weighted Average Shares Outstanding
         
384
         
396
         
389
         
396
 

(a) All Other includes the parent company’s interest income and expense, as well as other nonallocated costs.

The earnings per share of any segment does not represent a direct legal interest in the assets and liabilities allocated to any one segment but rather represents a direct equity interest in AEP’s assets and liabilities as a whole.

Second Quarter of 2005 Compared to Second Quarter of 2004

Income Before Discontinued Operations increased $67 million to $218 million in the second quarter of 2005 compared to the second quarter of 2004.

For the second quarter of 2005, our Utility Operations earnings increased $63 million from second quarter of the previous year primarily due to load and customer growth in all sectors, an increase in off-system sales margins and Ohio and Texas carrying cost accruals. These favorable changes are partially offset by higher fuel costs.

Average shares outstanding decreased to 384 million in 2005 from 396 million in 2004 primarily due to the common stock share repurchase program approved by our Board of Directors in February 2005.

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004

Income Before Discontinued Operations increased $132 million to $572 million for the six months ended June 30, 2005.

For the six months ended June 30, 2005, our Utility Operations earnings increased $112 million from the same six month period of the previous year driven primarily by the Centrica earnings sharing payments received in March 2005, Ohio and Texas carrying cost accruals and lower maintenance and other operation expenses. These favorable changes are partially offset by higher fuel costs.

Earnings from our Gas Operations increased $22 million from the same six month period of the previous year reflecting favorable results for one month of HPL’s operations in 2005 compared with a loss for the six months of HPL’s operations in the prior year. We sold a 98% controlling interest in HPL in January 2005, resulting in decreased operations, maintenance and depreciation expenses as well as decreased interest charges.

The loss from our All Other grouping, primarily representing parent company income and expenses, increased $6 million in 2005. This increase is primarily due to lower interest income and lower guarantee fees received in the current period.

Average shares outstanding decreased to 389 million in 2005 from 396 million in 2004 primarily due to the common stock share repurchase program approved by our Board of Directors in February 2005.

Our results of operations by operating segment are discussed below.

Utility Operations

Our Utility Operations include regulated revenues with direct and variable offsetting expenses and net reported commodity trading operations. We believe that a discussion of our Utility Operations segment results on a gross margin basis is most appropriate. Gross margins represent utility operating revenues less the related direct costs of fuel and purchased power.

   
Three Months Ended June 30,
 
Six Months Ended June 30,
 
   
2005
 
2004
 
2005
 
2004
 
   
(in millions)
 
Revenues
 
$
2,668
 
$
2,545
 
$
5,282
 
$
5,147
 
Fuel and Purchased Power
   
956
   
820
   
1,861
   
1,599
 
Gross Margin
   
1,712
   
1,725
   
3,421
   
3,548
 
Depreciation and Amortization
   
317
   
308
   
635
   
618
 
Other Operating Expenses
   
943
   
994
   
1,814
   
1,882
 
Operating Income
   
452
   
423
   
972
   
1,048
 
Other Income (Expense), Net
   
56
   
16
   
204
   
26
 
Interest Expense and Preferred Stock Dividend Requirements
   
156
   
161
   
300
   
327
 
Income Taxes
   
105
   
94
   
276
   
259
 
Income Before Discontinued Operations
 
$
247
 
$
184
 
$
600
 
$
488
 
 

Summary of Selected Sales Data
For Utility Operations
For the Three and Six Months Ended June 30, 2005 and 2004

   
Three Months Ended
 
Six Months Ended
 
   
2005
 
2004
 
2005
 
2004
 
Energy Summary
 
(in millions of KWH)
 
Retail:
                 
Residential
   
9,956
   
9,740
   
23,180
   
23,167
 
Commercial
   
9,573
   
9,390
   
18,305
   
18,169
 
Industrial
   
13,480
   
12,902
   
26,253
   
25,175
 
Miscellaneous
   
639
   
806
   
1,284
   
1,549
 
Total Retail
   
33,648
   
32,838
   
69,022
   
68,060
 
Texas Retail and Other
   
161
   
298
   
389
   
522
 
Total
   
33,809
   
33,136
   
69,411
   
68,582
 
                           
Wholesale
   
12,138
   
13,644
   
24,773
   
27,495
 
                           
Texas Wires Delivery
   
6,736
   
6,250
   
12,254
   
11,740
 

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact weather has on results of operations. Cooling degree days and heating degree days in our service territory for the quarter and year-to-date periods ended June 30, 2005, and 2004 were as follows:

   
Three Months Ended
 
Six Months Ended
 
   
2005
 
2004
 
2005
 
2004
 
Weather Summary
 
(in degree days)
 
Eastern Region
                 
Actual - Heating
   
165
   
168
   
1,939
   
2,032
 
Normal - Heating (a)
   
176
   
180
   
1,988
   
1,986
 
                           
Actual - Cooling
   
287
   
313
   
287
   
316
 
Normal - Cooling (a)
   
278
   
278
   
281
   
281
 
                           
Western Region (b)
                         
Actual - Heating
   
26
   
30
   
795
   
913
 
Normal - Heating (a)
   
33
   
33
   
1,006
   
1,012
 
                           
Actual - Cooling
   
681
   
659
   
701
   
689
 
Normal - Cooling (a) 
   
645
   
642
   
662
   
660
 

(a) Normal Heating/Cooling represents the 30-year average of degree days.
 
(b) Western Region statistics represent PSO/SWEPCo customer base only.
 
Second Quarter of 2005 Compared to Second Quarter of 2004

Reconciliation of Second Quarter of 2004 to Second Quarter of 2005
Income Before Discontinued Operations
(in millions)

Second Quarter of 2004
       
$
184
 
               
Changes in Gross Margin:
             
Retail Margins
   
5
       
Texas Supply
   
(36
)
     
Transmission Revenues
   
(21
)
     
Off-system Sales
   
38
       
Other Revenues
   
1
       
           
(13
)
               
Changes in Operating Expenses And Other:
             
Maintenance and Other Operation
   
46
       
Depreciation and Amortization
   
(9
)
     
Taxes Other Than Income Taxes
   
5
       
Other Income (Expense), Net
   
40
       
Interest Expenses
   
5
       
           
87
 
               
Income Taxes
         
(11
)
               
Second Quarter of 2005
       
$
247
 

Income from Utility Operations increased $63 million to $247 million in 2005. The key drivers of the increase were a $46 million decrease in Maintenance and Other Operation expenses and a $40 million increase in Other Income (Expense), Net, partially offset by a $13 million decrease in gross margin.

The major components of our change in gross margin were as follows:

·
Retail margins in our utility business were $5 million higher than last year. The primary driver of this increase was a 3% increase in volume attributable to load growth in residential and commercial classes as well as favorable weather in 2005. The margin increase related to load growth was partially offset by higher fuel costs of approximately $44 million, which primarily relates to our utilities in the East with inactive fuel clauses.
·
Our Texas Supply business had a $36 million decrease in gross margin as a result of the sale of a majority of our Texas generation assets in the third quarter of 2004 and STP in May 2005.
·
Transmission Revenues decreased $21 million primarily due to the loss of through and out rates as mandated by the FERC. Higher transmission revenues in the ECAR region because of the addition of SECA rates partially offset the change in FERC tariffs.
·
Margins from Off-system Sales for 2005 were $38 million higher than 2004 primarily due to higher volumes and favorable price margins.
 
Utility Operating Expenses and Other changed between years as follows:

·
Maintenance and Other Operation expenses decreased $46 million. Approximately $11 million of the decrease is due to timing of maintenance projects and different spending patterns experienced in the second quarter of 2005 as compared to the same period in 2004. Additionally, in 2004 we incurred $20 million related to major storms. Also, an $18 million reduction relates to the sale of the Texas generation and STP assets and a $19 million reduction relates to lower labor, incentives, fringes and outside service costs. These favorable variances were partially offset by a $22 million severance accrual in 2005 as a result of our company-wide staffing and budget review, which will ultimately reduce our staffing levels by 466 positions.
   ·     Other Income (Expense), Net increased $40 million primarily due to the following:
   ·     $20 million related to the recognition of carrying costs by TCC on its net stranded generation costs and its capacity auction true-up asset.
   ·     $11 million related to the recognition of carrying costs on environmental and RTO expenses by our Ohio companies related to the
          Rate Stabilization Plans.
   ·     $9 million related to increased AFUDC due to extensive construction activities occurring in 2005.

See “Income Taxes” section below for discussion of fluctuations related to income taxes.

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004

Reconciliation of Six Months Ended June 30, 2004 to Six Months Ended June 30, 2005
Income Before Discontinued Operations
(in millions)

Six Months Ended June 30, 2004
       
$
488
 
               
Changes in Gross Margin:
             
Retail Margins
   
(61
)
     
Texas Supply
   
(56
)
     
Transmission Revenues
   
(51
)
     
Off-system Sales
   
34
       
Other Revenues
   
7
       
           
(127
)
               
Changes in Operating Expenses And Other:
             
Maintenance and Other Operation
   
67
       
Depreciation and Amortization
   
(17
)
     
Taxes Other Than Income Taxes
   
1
       
Other Income (Expense), Net
   
178
       
Interest Expenses
   
27
       
           
256
 
               
Income Taxes
         
(17
)
               
Six Months Ended June 30, 2005
       
$
600
 

Income from Utility Operations increased $112 million to $600 million in 2005. The key drivers of the increase were a $178 million increase in Other Income (Expense), Net and a $67 million decrease in Maintenance and Other Operation, partially offset by a $127 million decrease in gross margin.
 
The major components of our change in gross margin were as follows:

·
Overall Retail Margins in our utility business were $61 million lower than last year. The primary driver of this decrease was higher delivered fuel costs of approximately $100 million, of which the majority relates to our East companies with inactive fuel clauses. The higher fuel costs were partially offset by continued customer growth and usage in our residential and commercial classes.
·
Our Texas Supply business had a $56 million decrease in gross margin due to the sale of a majority of our Texas generation assets in the third quarter of 2004 and STP in May 2005.
·
Transmission Revenues decreased $51 million primarily due to the loss of through and out rates as mandated by the FERC. Higher transmission revenues in the ECAR region because of the addition of SECA rates partially offset the change in FERC tariffs.
·
Margins from Off-system Sales for 2005 were $34 million higher than 2004 primarily due to a 3% growth in volume and favorable price margins partially offset by a $41 million decrease in optimization activity.

Utility Operating Expenses and Other changed between years as follows:

·
Maintenance and Other Operation expenses decreased $67 million. Approximately $10 million of the decrease is due to timing of maintenance projects and different spending patterns experienced in the first six months of 2005 as compared to the same period in 2004. Expenses were lower by $60 million primarily due to the cancellation of our COLI policies in 2005 and lower labor, incentives and outside service costs in 2005. Also, a $19 million reduction relates to the sale in 2004 of our Texas generation assets. These favorable variances were partially offset by a $22 million severance accrual in 2005 as a result of our company-wide staffing and budget review, which will ultimately reduce our staffing levels by 466 positions.
·
Other Income (Expense), Net increased $178 million primarily due to the following:
 
·
$112 million resulting from the receipt of revenues related to the earnings sharing agreement with Centrica as stipulated in the purchase and sale agreement from the sale of our REPs in 2002. Agreement was reached with Centrica in March 2005 resolving disputes on how such amounts are to be calculated.
 
·
$37 million related to the recognition of carrying costs on environmental and RTO expenses by our Ohio companies related to the Rate Stabilization Plans.
 
·
$15 million related to increased AFUDC due to extensive construction activities occurring in 2005.
 
·
$15 million related to the recognition of carrying costs by TCC on its net stranded generation costs and its capacity auction true-up asset.
·
Interest Expenses decreased $27 million due to the refinancing of higher coupon debt and the retirement of debt in 2004 and in the first six months of 2005.

See “Income Taxes” section below for discussion of fluctuations related to income taxes.

Investments-Gas Operations

Second Quarter of 2005 Compared to Second Quarter of 2004

Our $2 million net loss from Gas Operations before discontinued operations compares with a $4 million loss recorded in the second quarter of 2004. Due to the sale of a 98% controlling interest in HPL in January 2005, current year results include results from gas trading operations that will wind down over the next several years compared to three months of HPL’s operations in the prior year.

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004

Our $8 million net income from Gas Operations before discontinued operations compares with a $14 million loss recorded in the six months ended June 30, 2004. Due to the sale of a 98% controlling interest in HPL in January 2005, current year results include only one month of HPL’s operations compared to six months of HPL’s operations in the prior year. The variance consists of a $51 million decrease in operation, maintenance and depreciation expenses and a $21 million decrease in interest charges offset by a $42 million decrease in gross margins and an $8 million increase in income taxes.

Investments - UK Operations

Second Quarter of 2005 Compared to Second Quarter of 2004

Losses included in discontinued operations from our Investments - UK Operations segment were zero in 2005 as compared to $52 million in 2004 due to the sale of substantially all operations and assets within our Investments - UK Operations segment in July 2004.

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004

Losses included in discontinued operations from our Investments - UK Operations segment were $5 million in 2005 as compared to $64 million in 2004 due to the sale of substantially all operations and assets within our Investments - UK Operations segment in July 2004. The current period amount represents purchase price true-up adjustments made during the first quarter of 2005 related to the 2004 sale.

Investments - Other

Second Quarter of 2005 Compared to Second Quarter of 2004

Losses before discontinued operations from our Investments - Other segment decreased by $3 million in 2005 primarily due to the following:

·
A $5 million decreased loss due to reductions in outstanding debt at AEP Communications that occurred in October 2004.
·
A $3 million increased profit at MEMCO due to favorable operating conditions and strong freight rates in 2005.
·
A $3 million increased loss at AEP Resources related to $1 million of increased losses from the Dow plant in 2005 and increased legal and tax expenses of $2 million in 2005.
·
The remaining $2 million increased loss relates to several items at various subsidiaries, none of which is individually significant.

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004

Income before discontinued operations from our Investments - Other segment increased by $4 million in 2005 primarily due to the following:

·
A $5 million increase at CSW Energy Services related to a current year gain due to a working capital true-up for our November 2004 Numanco sale and a release of product liability and litigation reserves related to our Total Electric Vehicle investment due to the resolution of all open litigation as of March 31, 2005.
·
An $8 million increase due to reductions in outstanding debt at AEP Communications that occurred in October 2004.
·
A $5 million increase at AEP Coal mostly related to Black Lung Trust settlements.
·
A $3 million increase at AEP Investments due to the investment write-down of PHPK Technologies, Inc. in 2004 of $1 million, favorable earnings from Pac Hydro of $1 million in 2005 and $1 million in reduced operations and maintenance at AEP EmTech.
·
A $1 million increase at CSW International related to tax reserve adjustments in June 2005.
·
A $2 million increase related to several items at various subsidiaries, none of which is individually significant.
·
A $17 million decrease at AEP Resources primarily related to a $2 million favorable judgment on an Australian tax issue received in 2004, a $4 million favorable entry in 2004 related to capitalized fuel during construction of the Dow Plant, $5 million of increased losses related to the Dow plant in 2005 and an unfavorable tax adjustment of $4 million booked in 2005.
·
A $3 million decrease at our IPPs resulting from an unfavorable tax adjustment in June 2005.
 
All Other

Second Quarter of 2005 Compared to Second Quarter of 2004

Our parent company’s loss for the second quarter of 2005 increased $1 million in comparison to the second quarter of 2004 due to lower interest income in 2005.

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004

Our parent company’s loss for the six months ended June 30, 2005 increased $6 million in comparison to the six months ended June 30, 2004 due to lower interest income of $7 million and lower guarantee fees received from affiliates of $2 million, partially offset by lower interest expense of $2 million due to lower short term debt borrowings in 2005 and savings from the redemption of $550 million senior unsecured notes in the second quarter of 2005.

Income Taxes

The effective tax rates for the second quarter of 2005 and 2004 were 31.8% and 33.9%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, energy production credits, amortization of investment tax credits and state income taxes. The decrease in the effective tax rate is primarily due to changes in permanent differences.

The effective tax rates for the six months ended 2005 and 2004 were 32.3% and 35.1%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, energy production credits, amortization of investment tax credits and state income taxes. The decrease in the effective tax rate is primarily due to changes in permanent differences and state income taxes.

FINANCIAL CONDITION

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

Capitalization ($ in millions)

   
June 30, 2005
 
December 31, 2004
 
Common Shareholders’ Equity
 
$
8,382
   
41.1
%
$
8,515
   
40.6
%
Cumulative Preferred Stock
   
61
   
0.3
   
61
   
0.3
 
Cumulative Preferred Stock (Subject to Mandatory Redemption)
   
-
   
-
   
66
   
0.3
 
Long-term Debt, including amounts due within one year
   
11,916
   
58.5
   
12,287
   
58.7
 
Short-term Debt
   
14
   
0.1
   
23
   
0.1
 
                           
Total Capitalization
 
$
20,373
   
100.0
%
$
20,952
   
100.0
%

In March 2005, we repurchased 12.5 million shares of our outstanding common stock through an accelerated share repurchase agreement at an initial price of $34.63 per share. The 12.5 million shares repurchased under the program were subject to a contingent purchase price adjustment based on the actual purchase prices paid for the common stock during the program period. Based on this adjustment, our actual stock purchase price averaged $34.18 per share.

In April 2005, we redeemed $550 million of parent company senior notes.

As a consequence of the capital changes during the first six months of 2005, our ratio of debt to total capital decreased from 59.1% to 58.6% (preferred stock subject to mandatory redemption is included in the debt component of the ratio).

Liquidity

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

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments. We had an available liquidity position, at June 30, 2005, of approximately $3.3 billion as illustrated in the table below.

   
Amount
 
 Maturity
 
   
(in millions)
      
Commercial Paper Backup:
          
   Revolving Credit Facility  
$
1,000
   
May 2007
 
   Revolving Credit Facility    
1,500
   
March 2010
 
Letter of Credit Facility
   
200
   
September 2006
 
Total
   
2,700
       
Cash and Cash Equivalents
   
607
       
Total Liquidity Sources
   
3,307
       
Less: AEP Commercial Paper Outstanding
   
-
(a)      
   Letters of Credit Outstanding    
50
       
               
Net Available Liquidity at June 30, 2005
 
$
3,257
       

(a)
Amount does not include JMG commercial paper outstanding in the amount of $14 million. This commercial paper is specifically associated with the Gavin scrubber and does not reduce AEP’s available liquidity. The JMG commercial paper is supported by a separate letter of credit facility not included above.

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. At June 30, 2005, this percentage was 53.5%. Nonperformance of these covenants could result in an event of default under these credit agreements. At June 30, 2005, we complied with the covenants contained in these credit agreements. In addition, the acceleration of our payment obligations, or the obligations of certain of our 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 amounts outstanding thereunder payable.

Our revolving credit facilities generally prohibit new borrowings if we experience a material adverse change in our business or operations. We may, however, make new borrowings under these facilities if we experience a material adverse change so long as the proceeds of such borrowings are used to repay outstanding commercial paper. Under the $1.5 billion revolving credit facility, which matures in March 2010, we may borrow despite a material adverse change if our ratings are BBB (or better) from S&P, and Baa2 (or better) from Moody’s at any time during the facility’s term.

Under an SEC order, we and our utility subsidiaries cannot incur additional indebtedness if the issuer’s common equity would constitute less than 30% (25% for TCC) of its capital. In addition, this order restricts us and our 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 June 30, 2005, we were in compliance with this order.

Nonutility Money Pool borrowings, Utility Money Pool borrowings and external borrowings may not exceed SEC or state commission authorized limits. At June 30, 2005, we had not exceeded the SEC or state commission authorized limits.
 
Credit Ratings

AEP’s ratings have not been adjusted by any rating agency during 2005 and AEP, Inc. is currently on a “positive” outlook by Moody’s.

Our current ratings by the major agencies are as follows:

   
Moody’s
 
S&P
 
Fitch
 
               
Short-term Debt
   
P-3
   
A-2
   
F-2
 
Senior Unsecured Debt
   
Baa3
   
BBB
   
BBB
 

If AEP or any of its 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 nationally recognized rating agencies listed above, our borrowing costs could increase and access to borrowed funds could be negatively affected.

Cash Flow  

Our cash flows are a major factor in managing and maintaining our liquidity strength.

   
Six Months Ended June 30,
 
   
2005
 
2004
 
   
(in millions)
 
Cash and Cash Equivalents at Beginning of Period
 
$
320
 
$
778
 
Cash Flows From (Used For):
             
Operating Activities
   
894
   
1,275
 
Investing Activities
   
484
   
(565
)
Financing Activities
   
(1,091
)
 
(825
)
Net Increase (Decrease) in Cash and Cash Equivalents
   
287
   
(115
)
Cash and Cash Equivalents at End of Period
 
$
607
 
$
663
 
Other Temporary Cash Investments
 
$
275
 
$
403
 

Cash from operations, combined with a bank-sponsored receivables purchase agreement and short-term borrowings, provide necessary working capital and help us 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 our other subsidiaries that are not participants in the Nonutility Money Pool. As of June 30, 2005, we had credit facilities totaling $2.5 billion to support our commercial paper program. At June 30, 2005, we had no outstanding short-term borrowings supported by the revolving credit facilities. JMG had commercial paper outstanding in the amount of $14 million. This commercial paper is specifically associated with the Gavin scrubber and is not supported by our credit facilities. The maximum amount of commercial paper outstanding during the six months ended June 30, 2005 was $25 million. The weighted-average interest rate for our commercial paper during the first six months of 2005 was 2.5%.

We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding alternatives are arranged. Sources of long-term funding include issuance of common stock, preferred stock or long-term debt and sale-leaseback or leasing agreements.

In addition to our Cash and Cash Equivalents, we have Other Temporary Cash Investments on hand that factor in managing and maintaining our liquidity.
 
Operating Activities

   
Six Months Ended June 30,
 
   
2005
 
2004
 
   
(in millions)
 
Net Income
 
$
576
 
$
382
 
Plus: (Income) Loss From Discontinued Operations
   
(4
)
 
58
 
Income from Continuing Operations
   
572
   
440
 
Noncash Items Included in Earnings
   
594
   
797
 
Changes in Assets and Liabilities
   
(272
)
 
38
 
Net Cash Flows From Operating Activities
 
$
894
 
$
1,275
 

The key drivers of the decrease in cash from operations for the first six months of 2005 are the Pension Contributions of $204 million and the Gain on Sales of Assets of $115 million, $112 million of which relates to the sale of our Texas REPs to Centrica.

2005 Operating Cash Flow

Our Net Cash Flows From Operating Activities were $894 million for the first six months of 2005. We produced Income from Continuing Operations of $572 million during the period. Income from Continuing Operations for the period included noncash expense items primarily for depreciation, amortization, accretion, deferred taxes and deferred investment tax credits. In addition, there is a current period favorable impact for a net $43 million balance sheet change for risk management contracts that are marked-to-market. These contracts have an unrealized earnings impact as market prices move, and a cash impact upon settlement or upon disbursement or receipt of premiums. We made contributions of $204 million to our pension trust fund. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in these asset and liability accounts relates to a number of items; the most significant are a $155 million cash increase from accounts receivable and an increase in the balance of Taxes Accrued of $172 million. Cash increased related to net accounts receivable due to a higher factored balance at June 30, 2005. Taxes Accrued increased because our consolidated tax group was not required to make an estimated federal income tax payment during the first quarter of 2005 and paid $43 million, net of refunds received, during the first half of 2005.

2004 Operating Cash Flow

Our Net Cash Flows From Operating Activities were $1.3 billion for the first six months of 2004. We produced Income from Continuing Operations of $440 million during the period. Income from Continuing Operations for the period included noncash items of $749 million for depreciation, amortization, accretion, deferred taxes and deferred investment tax credits. There was a current period favorable impact for a net $50 million balance sheet change for risk management contracts that were marked-to-market. These contracts have an unrealized earnings impact as market prices move, and a cash impact upon settlement or upon disbursement or receipt of premiums. The most significant changes in other activity in the asset and liability accounts are an increase in Taxes Accrued of $140 million and $144 million increase in Fuel, Material and Supplies.
 
Investing Activities

   
Six Months Ended June 30,
 
   
2005
 
2004
 
   
(in millions)
 
Construction Expenditures
 
$
(1,018
)
$
(690
)
Change in Other Temporary Cash Investments, Net
   
(103
)
 
(1
)
Purchases of Auction Rate Securities
   
(1,338
)
 
(201
)
Proceeds from the Sale of Auction Rate Securities
   
1,441
   
203
 
Proceeds from Sale of Assets
   
1,500
   
131
 
Other
   
2
   
(7
)
Net Cash Flows From (Used For) Investing Activities
 
$
484
 
$
(565
)

Our Net Cash Flows From Investing Activities were $484 million in 2005 primarily due to proceeds from the sale of HPL and STP in 2005. We used the cash from asset sales to repurchase common stock. Our Construction Expenditures include environmental, transmission and distribution investments as we had planned. Our remaining Construction Expenditures for 2005 are estimated to be approximately $1.7 billion.

We purchase auction rate securities with cash available for short-term investment. During the first half of 2005, we purchased $1.3 billion of securities and received $1.4 billion of proceeds from sale, which included the sale of our auction rate securities held at December 31, 2004, as reflected above in the Change In Other Temporary Cash Investments, Net line.

Our Net Cash Flows Used For Investing Activities were $565 million in 2004 primarily due to Construction Expenditures partially offset by the proceeds from the sales of the Pushan Power Plant in China and LIG Pipeline Company. The sales were part of our announced plan to divest noncore investments and assets.

Financing Activities

   
Six Months Ended June 30,
 
   
2005
 
2004
 
   
(in millions)
 
Issuance of Common Stock
 
$
28
 
$
11
 
Repurchase of Common Stock
   
(427
)
 
-
 
Issuance/Retirement of Debt, net
   
(353
)
 
(555
)
Retirement of Preferred Stock
   
(66
)
 
(4
)
Dividends Paid on Common Stock
   
(273
)
 
(277
)
Net Cash Flows Used For Financing Activities
 
$
(1,091
)
$
(825
)

Our Net Cash Flows Used For Financing Activities in 2005 were $1.1 billion. During the first six months of 2005, we repurchased common stock and reduced outstanding long-term debt using the proceeds from the sale of HPL. Our subsidiaries retired $66 million of cumulative preferred stock.

Our Net Cash Flows Used For Financing Activities were $825 million in 2004. During 2004, we retired debt using cash from operating activities. We retired approximately $986 million of long-term debt, excluding $25 million related to an asset sale. We increased our short-term debt by $188 million and issued approximately $243 million of long-term debt.

Off-balance Sheet Arrangements

Under a limited set of circumstances we enter into off-balance sheet arrangements to accelerate cash collections, reduce operational expenses and spread risk of loss to third parties. Our current policy restricts 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 off-balance sheet arrangements have not changed significantly from year-end. For complete information on each of these off-balance sheet arrangements see the “Minority Interest and Off-balance Sheet Arrangements” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2004 Annual Report.

Summary Obligation Information

A summary of our contractual obligations is included in our 2004 Annual Report and has not changed significantly from year-end other than the issuances and retirements discussed in “Cash Flow”“Financing Activities” above.

SIGNIFICANT MATTERS

Texas Regulatory Activity

Texas Restructuring

The principal remaining component of the stranded cost recovery process in Texas is the PUCT’s determination and approval of TCC’s net stranded generation costs and other recoverable true-up items including carrying costs in TCC’s true-up filing. The PUCT approved TCC’s request to file its True-up Proceeding after the sales of its interest in STP, with only the ownership interest in Oklaunion remaining to be settled. On May 19, 2005, the sales of TCC’s interest in STP closed. On May 27, 2005, TCC filed its true-up request seeking recovery of $2.4 billion of net stranded costs and other true-up items which it believes the Texas Restructuring Legislation allows. TCC’s request includes unrecorded equity carrying costs through May 27, 2005, all future carrying costs through September 2005 and amounts for stranded costs that we have previously written off (principally, a $238 million provision for a probable depreciation adjustment recorded in December 2004 based on a methodology approved by the PUCT in a nonaffiliated utility’s true-up order). The PUCT hearing is scheduled to begin on September 26, 2005. It is anticipated that the PUCT will issue a final order in the fourth quarter of 2005.

TCC continues to accrue carrying costs on its net true-up regulatory asset at the embedded 8.12% debt component rate and will continue to do so until it recovers its approved net true-up regulatory asset. In a nonaffiliated utility’s securitization proceeding, the PUCT issued an order in March 2005 that resulted in a reduction in its carrying costs based on an assumed cost-of-money benefit for accumulated deferred federal income taxes retroactively applied to January 1, 2004. In the first half of 2005, TCC began to accrue carrying costs based on this order. Through June 30, 2005, TCC has computed carrying costs of $483 million, of which TCC has recognized $317 million to-date. The equity component of the carrying costs, which totals $166 million through June 30, 2005, will be recognized in income as collected.

In an April 2005 PUCT open meeting regarding another nonaffiliated utility’s True-up Proceeding, the other utility was required to use a lower rate to compute its carrying costs than its filed unbundled cost of service rate. TCC’s facts differ from the other utility’s; however, if the PUCT ultimately determines that a similar lower rate be used by TCC to calculate carrying costs on its stranded cost balance, a portion of carrying costs previously recorded would have to be reversed and would have an adverse impact on future results of operations and cash flows. Through June 30, 2005, such reversal would approximate $60 million, of which $9 million would apply to amounts accrued in 2005.

When the True-up Proceeding is completed, TCC intends to file to recover the PUCT-approved net stranded generation costs and other true-up amounts, plus appropriate carrying costs, through a nonbypassable competition transition charge in the regulated Transmission and Distribution (T&D) rates and through an additional transition charge for amounts that can be recovered through the sale of securitization bonds.

We believe that our filed $2.4 billion request for recovery of net stranded costs and other true-up items, inclusive of carrying costs, is recoverable under the Texas Restructuring Legislation and that our $1.7 billion recorded net true-up regulatory asset, inclusive of carrying costs at June 30, 2005, is probable of recovery at this time. However, we anticipate that other parties will contend in our proceeding that material amounts of our net stranded costs and/or wholesale capacity auction true-up amounts should not be recovered. To the extent decisions of the PUCT in TCC’s True-up Proceeding differ from our interpretation and application of the Texas Restructuring Legislation and our evaluation of other true-up orders of nonaffiliated utilities, additional provisions for material disallowances and reductions of the net true-up regulatory asset, including recorded carrying costs, are possible. Such disallowances would have an adverse effect on future results of operations, cash flows and possibly financial condition.

TCC Rate Case

TCC has an on-going T&D rate review before the PUCT. In that rate review, the PUCT has decided all issues except the amount of affiliate expenses to include in revenue requirements. Through an oral ruling, the PUCT approved the nonunanimous settlement filed in June 2005 that provides for an $11 million disallowance of affiliate expenses which, when combined with the previous decisions, results in a total reduction in TCC’s annual base rates of $9 million. A draft final order has been issued reflecting the $9 million reduction in TCC’s annual base rates. This reduction in TCC’s annual base rates will be offset by the elimination of a merger-related rate rider credit of $7 million, an increase in other miscellaneous revenues of $4 million and a decrease in depreciation expense of $9 million, resulting in a prospective increase in estimated annual pretax earnings of $11 million. It is anticipated that the PUCT will approve the final written order at its August 2005 open meeting. If the final written order differs from the draft order, it could impact projected annual pretax earnings effect.

Ohio Regulatory Activity

Ohio Restructuring

On January 26, 2005, the PUCO approved Rate Stabilization Plans (RSP) for CSPCo and OPCo (the Ohio companies). The plans provided, among other things, for CSPCo and OPCo to raise their generation rates by 3% and 7%, respectively, in 2006, 2007 and 2008 and provided for additional annual generation rate increases of up to an average of 4% per year based on supporting the need for additional revenues. The plans also provided that the Ohio companies could recover in 2006, 2007 and 2008 environmental carrying costs and PJM RTO costs from 2004 and 2005 related to their obligation as the Provider of Last Resort in Ohio’s customer choice program. Pretax earnings were increased by $14 million for CSPCo and $40 million for OPCo in the first half of 2005 as a result of implementing this provision of the RSP. Of these amounts, approximately $8 million for CSPCo and $21 million for OPCo relate to 2004 environmental carrying costs and RTO costs.

In February 2005, various intervenors filed applications for rehearing with the PUCO regarding its approval of the RSP. On March 23, 2005, the PUCO denied all applications for rehearing. In the second quarter of 2005, two intervenors filed separate appeals to the Ohio Supreme Court. If the RSP order was determined to be illegal under the Restructuring Legislation, as contended by the two intervenors, it would have an adverse effect on results of operations, cash flow and possibly financial condition. Although we believe that the RSP plan is legal and we intend to defend vigorously the PUCO’s order, we cannot predict the ultimate outcome of the pending litigation.


Integrated Gasification Combined Cycle (IGCC) Power Plant
 
On March 18, 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs related to building and operating a new approximately 600 MW IGCC power plant using clean-coal technology. The application proposes cost recovery associated with the IGCC plant in three phases. In Phase 1, the Ohio companies would recover approximately $18 million in pre-construction costs during 2006. In Phase 2, the Ohio companies would recover approximately $237 million in construction financing costs from 2007 through mid-2010 when the plant is projected to be placed in commercial operation. The proposed recoveries in Phases 1 and 2 will be applied against the 4% limit on additional generation rate increases the Ohio companies could request in 2006, 2007 and 2008, under their Rate Stabilization Plans. In Phase 3, which begins when the plant enters commercial operation, the Ohio companies would recover the projected $1.2 billion cost of the plant and a return on the unrecovered cost over its operating life along with fuel, replacement power and operation and maintenance costs.

Oklahoma Regulatory Activity

PSO Rate Review

PSO has been involved in a commission staff-initiated base rate review before the OCC which began in 2003. In March 2005, a settlement was negotiated and approved by the ALJ. The settlement provides for a $7 million annual base revenue reduction offset by a $6 million reduction in annual depreciation expense and recovery through fuel revenues of certain transmission expenses previously recovered in base rates. In addition, the settlement eliminates a $9 million annual merger savings rate reduction rider at the end of December 2005. The settlement also provides for recovery over 24 months of $9 million of deferred fuel costs associated with a renegotiated coal transportation contract and the continuation of a $12 million vegetation management rider, both of which are earnings neutral. Finally, the settlement stipulates that PSO may not file for a base rate increase before April 1, 2006. The OCC issued an order approving the stipulation on May 2, 2005, allowing for the implementation of new base rates in June 2005.

PSO Fuel and Purchased Power

In 2002, PSO experienced a $44 million under-recovery of fuel costs resulting from a reallocation among AEP West companies of purchased power costs for periods prior to January 1, 2002. In July 2003, PSO offered to the OCC to collect those reallocated costs over 18 months. In August 2003, the OCC Staff filed testimony recommending PSO recover $42 million of the reallocation over three years. Subsequently, the OCC expanded the case to include a full prudence review of PSO’s 2001 fuel and purchased power practices and off-system sales margin sharing between AEP East and AEP West companies for the year 2002. On July 25, 2005, the OCC Staff and two intervenors filed testimony in which they quantified the alleged improperly allocated off-system sales margins between AEP East and AEP West companies. Their overall recommendations related to the allocation would result in an increase in off-system sales margins and thus, a reduction in PSO’s recoverable fuel costs through June 2005 of an amount between $38 million and $47 million.

On June 10, 2005, the OCC decided to have its staff conduct a prudence review of PSO’s fuel and purchased power practices for 2003.

Management is unable to predict the ultimate effect of these proceedings on revenues, results of operations, cash flows and financial condition.

Virginia and West Virginia Regulatory Activity

APCo Virginia Environmental and Reliability Costs

In April 2004, the Virginia Electric Restructuring Act was amended to include a provision which permits recovery, during the extended capped rate period ending December 31, 2010, of incremental environmental compliance and T&D system reliability (E&R) costs prudently incurred after July 1, 2004. On July 1, 2005, APCo filed a request with the Virginia SCC seeking approval for the recovery of $62 million in incremental E&R costs through June 30, 2006. Approximately $14 million of the amount requested represents incremental E&R costs for the twelve months ended June 30, 2005 and $48 million represents projected incremental E&R costs to be incurred for the twelve months ending June 30, 2006. The $62 million request relates to environmental controls on coal-fired generators to meet the first phase of the Clean Air Interstate Rule and Clean Air Mercury Rule finalized earlier this year, recovery of the incremental cost of the Jacksons Ferry-Wyoming 765 kilovolt transmission line construction and other incremental T&D system reliability costs.

APCo requested that a twelve-month E&R recovery factor be applied to electric service bills on an interim basis beginning August 1, 2005. If approved, the recovery factor will be applied as a 9.18% surcharge to customer bills. APCo proposed the difference between the actual incremental costs incurred and the cost recovered be subject to future rate adjustment.

On July 14, 2005, the Virginia SCC issued an order that established a procedural schedule in APCo’s proceeding including a public hearing on February 7, 2006. The order provided that no portion of APCo’s application should become effective pending further decision of the Virginia SCC. Each party to the proceeding may file legal arguments on or before September 6, 2005, on whether and, under what circumstances, the Virginia SCC has the authority to make effective, on an interim basis subject to refund, any portion of APCo’s requested rate change. We are unable to predict the final outcome of this proceeding. If the Virginia SCC denies recovery of net incremental amounts deferred, it would adversely affect future results of operations and cash flows.

APCo and WPCo West Virginia Rate Case

On July 1, 2005, APCo and WPCo formally notified the Public Service Commission of West Virginia of their intent to file a joint general rate case seeking increases in retail rates in the third quarter of 2005. The filing will include, among other things, a request to reinstate the suspended expanded fuel, net energy and purchased power clause and to provide for scheduled rate recovery of significant environmental and transmission expenditures. As of June 30, 2005 and December 31, 2004, we had $52 million of previously over-recovered fuel, net energy and purchased power costs related to APCo recorded in regulatory liabilities. Management is unable to predict the ultimate effect of this filing on revenues, results of operations, cash flows and financial condition.

FERC Order on Regional Through and Out Rates

A load-based transitional transmission rate mechanism, SECA, became effective December 1, 2004 to mitigate the loss of revenues due to the FERC’s elimination of through and out (T&O) transmission rates. SECA transition rates are in effect through March 31, 2006. The FERC has set the SECA rate issue for hearing and indicated that the SECA rates are being recovered subject to refund. We recognized SECA revenues of $32 million and $57 million for the second quarter and first half of 2005, respectively.  In addition, we recognized $11 million of SECA revenues in December 2004. Intervenors in that proceeding are objecting to the SECA rates and our method of determining those rates. Management is unable to determine the probable outcome of the FERC’s SECA rate proceeding.

In a March 31, 2005 FERC filing, we proposed an increase in the revenue requirements and rates for transmission service, and certain ancillary services in the AEP zone of PJM. The customers receiving these services are the AEP East companies and municipal, cooperative wholesale entities and retail customers that exercise retail choice that have load delivery points in the AEP zone of PJM. As proposed, the transmission service rates will increase in two steps, first to reflect an increase in the revenue requirements, and then to reflect the loss of revenues from the SECA transition rates on April 1, 2006. On May 31, 2005, the FERC accepted the filing, set the issues for hearing, and suspended the effective date of the proposed rates until November 1, 2005, subject to refund with interest if lower rates are eventually approved. The FERC accepted the two-step increase concept, such that the transmission rates will automatically increase on April 1, 2006, if the SECA revenues cease to be collected, and to the extent that replacement rates are not established. In a separate proceeding, at AEP’s urging, the FERC instituted an investigation of PJM’s zonal rate regime, indicating that the present regime may need to be replaced through establishment of regional rates that would compensate AEP, among others, for the regional service provided by high voltage facilities they own that benefit customers throughout PJM. This investigation provides AEP an opportunity to propose and support a new PJM rate regime that could mitigate losses from the elimination of T&O transmission rates and the discontinuance of the SECA rate collections.

The AEP East companies received approximately $196 million of T&O rate revenues for the twelve months ended September 30, 2004, the twelve months prior to AEP joining PJM. The portion of those revenues associated with transactions for which the T&O rate was eliminated and replaced by SECA transition rates was $171 million. At this time, management is unable to predict whether the SECA transition rates will fully compensate the AEP East companies for their lost T&O revenues for the period December 1, 2004 through March 31, 2006 and whether, effective with the expiration of the SECA transition rates on March 31, 2006, the resultant increase in the AEP East zonal transmission rates applicable to AEP’s internal load and wholesale transmission customers in AEP’s zone will be sufficient to replace the SECA transition rate revenues. In addition, we are unable to predict whether the effect of the loss of transmission revenues will be recoverable on a timely basis in the AEP East state retail jurisdictions and from wholesale customers within the AEP zone. If, (i) the SECA transition rates do not fully compensate AEP for its lost T&O revenues through March 31, 2006, (ii) AEP zonal transmission rates are not sufficiently increased by the FERC after March 31, 2006 to replace the lost T&O/SECA revenues, (iii) the FERC’s review of our current SECA rate results in a rate reduction which is subject to refund, or (iv) any increase in the AEP East companies’ transmission costs from the loss of transmission revenues are not fully recovered in retail and wholesale rates on a timely basis, and (v) if the FERC does not approve a new rate within PJM or within the PJM and MidWest ISO Regions that compensates for AEP’s T&O revenue losses, future results of operations, cash flows and financial condition would be adversely affected.

Litigation

We continue to be involved in various litigation described in the “Significant Factors - Litigation” section of Management’s Financial Discussion and Analysis of Results of Operations in our 2004 Annual Report. The 2004 Annual Report should be read in conjunction with this report in order to understand other litigation that did not have significant changes in status since the issuance of our 2004 Annual Report, but may have a material impact on our future results of operations, cash flows and financial condition. Other matters described in the 2004 Annual Report that did not have significant changes during the first six months of 2005, that should be read in order to gain a full understanding of our current litigation include: (1) Coal Transportation Dispute, (2) Shareholders’ Litigation, (3) Potential Uninsured Losses, (4) Enron Bankruptcy, (5) Bank of Montreal Claim, (6) Natural Gas Markets Lawsuits, (7) Conserstone Lawsuit and (8) TEM Litigation. Additionally, refer to the Commitments and Contingencies footnote in our Condensed Notes to Condensed Consolidated Financial Statements for further discussion of these matters.

Federal EPA Complaint and Notice of Violation

See discussion of New Source Review Litigation within “Significant Factors - Environmental Matters.”

Merger Litigation

In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC did not adequately explain that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit the basis for its conclusion that the merger met PUHCA requirements that utilities be “physically interconnected” and confined to a “single area or region.” In January 2005, a hearing was held before an ALJ.

On May 3, 2005, the ALJ issued an Initial Decision concluding that the AEP System is “physically interconnected” but is not confined to a “single area or region.” Therefore, the ALJ concluded that the combined AEP/CSW system does not constitute a single integrated public utility system under PUHCA. Management believes that the merger meets the requirements of PUHCA and has filed a petition for review of this Initial Decision, which the SEC has granted. The SEC is reviewing the Initial Decision. We believe adoption of the Energy Policy Act of 2005 may end litigation challenging our merger with CSW.

Texas Commercial Energy, LLP Lawsuit

Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit in federal District Court in Corpus Christi, Texas, in July 2003, against us and four of our subsidiaries, certain nonaffiliated energy companies and ERCOT. The action alleges violations of the Sherman Antitrust Act, fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, civil conspiracy and negligence. The allegations, not all of which are made against the AEP companies, range from anticompetitive bidding to withholding power. TCE alleges that these activities resulted in price spikes requiring TCE to post additional collateral and ultimately forced it into bankruptcy when it was unable to raise prices to its customers due to their fixed price contracts. The suit alleges over $500 million in damages for all defendants and seeks recovery of damages, exemplary damages and court costs. Two additional parties, Utility Choice, LLC and Cirro Energy Corporation, sought leave to intervene as plaintiffs asserting similar claims. In June 2004, the Court dismissed all claims against the AEP companies. TCE has appealed the trial court’s decision to the United States Court of Appeals for the Fifth Circuit. The Fifth Circuit issued its decision in June 2005 and affirmed the lower Court’s decision. In March 2005, Utility Choice, LLC and Cirro Energy Corporation filed in U.S. District Court alleging similar violations as those alleged in the TCE lawsuit. In April 2005, the defendants filed a Motion to Stay this case, pending the outcome of the appeal in the TCE case.

SWEPCo Notice of Enforcement and Notice of Citizen Suit 

On July 13, 2004, two special interest groups issued a notice of intent to commence a citizen suit under the CAA for alleged violations of various permit conditions in permits issued to SWEPCo's Welsh, Knox Lee, and Pirkey plants. The allegations at the Welsh Plant concern compliance with emission limitations on particulate matter and carbon monoxide, compliance with a referenced design heat input value, and compliance with certain reporting requirements. The allegations at the Knox Lee Plant relate to the receipt of an off-specification fuel oil, and the allegations at Pirkey Plant relate to testing and reporting of volatile organic compound emissions. On March 10, 2005, a complaint was filed in Federal District Court for the Eastern District of Texas by the two special interest groups, alleging violations of the CAA at Welsh Plant. SWEPCo filed a response to the complaint in May 2005.

On July 19, 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary of findings resulting from a compliance investigation at the plant. The summary includes allegations concerning compliance with certain recordkeeping and reporting requirements, compliance with a referenced design heat input value in the Welsh permit, compliance with a fuel sulfur content limit, and compliance with emission limits for sulfur dioxide. On April 11, 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of $228,312 against SWEPCo based on alleged violations of certain representations regarding heat input and fuel characteristics in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements. SWEPCo responded to the preliminary report and petition on May 2, 2005. The enforcement order contains a recommendation that would limit the heat input on each Welsh unit to the referenced heat input contained within the permit application within 10 days of the issuance of a final TCEQ order and until a permit amendment is issued. SWEPCo had previously requested a permit alteration to remove the references to a specific heat input value for each Welsh unit.

On August 13, 2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to the off-specification fuel oil deliveries at the Knox Lee Plant. On April 11, 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order and assessing an administrative penalty of $5,550 against SWEPCo based on alleged violations of certain permit requirements at Knox Lee. SWEPCo responded to the preliminary report and petition on May 2, 2005.

Management is unable to predict the timing of any future action by TCEQ or the special interest groups or the effect of such actions on results of operations, cash flows or financial condition.

Environmental Matters

As discussed in our 2004 Annual Report, there are emerging environmental control requirements that we expect will result in substantial capital investments and operational costs. The sources of these future requirements include:

·
Legislative and regulatory proposals to adopt stringent controls on SO2, NOx and mercury emissions from coal-fired power plants,
·
Clean Water Act rules to reduce the impacts of water intake structures on aquatic species at certain of our power plants, and
·
Possible future requirements to reduce carbon dioxide emissions to address concerns about global climate change.

This discussion updates certain events occurring in 2005. You should also read the “Significant Factors - Environmental Matters” section within Management’s Financial Discussion and Analysis of Results of Operations in our 2004 Annual Report for a description of all environmental matters affecting us, including, but not limited to, (1) the current air quality regulatory framework, (2) estimated air quality environmental investments, (3) the Comprehensive Environmental Response Compensation and Liability Act (Superfund) and state remediation, (4) global climate change, (5) carbon dioxide public nuisance claims, (6) costs for spent nuclear fuel disposal and decommissioning, and (7) Clean Water Act regulation.

Future Reduction Requirements for SO2 , NOx and Mercury

Regulatory Emissions Reductions

In January 2004, the Federal EPA published two proposed rules that would collectively require reductions of approximately 70% each in emissions of SO2, NOx and mercury from coal-fired electric generating units by 2015 (2018 for mercury). This initiative has two major components:

·
The Federal EPA proposed a Clean Air Interstate Rule (CAIR) to reduce SO2 and NOx emissions across the Eastern United States (29 states and the District of Columbia) and make progress toward attainment of the new fine particulate matter and ground-level ozone national ambient air quality standards. These reductions could also satisfy these states’ obligations to make reasonable progress towards the national visibility goal under the regional haze program.
·
The Federal EPA proposed to regulate mercury emissions from coal-fired electric generating units.
 
On March 14, 2005, the Administrator of the Federal EPA signed the final CAIR. The rule is slightly revised from the proposed version released in January 2004, and includes both a seasonal and annual NOx control program as well as an annual SO2 control program. All of the states in which our generating facilities are located will be subject to the seasonal and annual NOx control programs and the annual SO2 control program, except for Texas, Oklahoma and Arkansas. Texas will be subject to the annual programs only. Arkansas will be subject to the seasonal NOx control program only. Oklahoma is not affected by CAIR. In addition, the compliance deadline for Phase I for the NOx control program has been accelerated to 2009, and will replace any obligations imposed by the NOx State Implementation Plan (SIP) Call in 2009.

On March 15, 2005, the Administrator of the Federal EPA signed a final Clean Air Mercury Rule (CAMR) that will permit mercury emission reductions to be achieved from existing sources through a national cap-and-trade approach. The cap-and-trade approach would include a two-phase mercury reduction program for coal-fired utilities. The final CAMR imposes a national cap on mercury emissions from coal-fired power plants of 38 tons by 2010 and 15 tons by 2018.

In April 2004, the Federal EPA Administrator signed a proposed rule detailing how states should analyze and include "Best Available Retrofit Technology" (BART) requirements for individual facilities in their SIPs to address regional haze. The requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain regulated pollutants in specific industrial categories, including utility boilers. On June 15, 2005, the Federal EPA issued its final "Clean Air Visibility Rule" (CAVR). The record for the final rule contains an analysis that demonstrates that for electric generating units subject to CAIR, CAIR will result in more visibility improvements than BART would provide. Therefore, states that adopt the CAIR are allowed to substitute CAIR for controls otherwise required by BART. On July 20, 2005, the Federal EPA also issued a proposed rule detailing the requirements for an emissions trading program that can satisfy the BART requirements for the regional haze program.

The changes in the Federal EPA’s final CAIR, CAMR and CAVR have not caused us to revise our estimates of the capital investments necessary to achieve compliance with these requirements. However, the final rules give states substantial discretion in developing their rules to implement these programs, and states will have 18 months after publication of the notice of final rulemaking to submit their revised SIPs. In addition, both the CAIR and CAMR have been challenged in the United States Court of Appeals for the District of Columbia. As a result, the ultimate requirements may not be known for several years and may depart significantly from the rules described here. If the final rules are remanded by the court, if states elect not to participate in the federal cap-and-trade programs, or if states elect to impose additional requirements on individual units that are already subject to CAIR and/or the CAMR, our costs could increase significantly. The cost of compliance could have an adverse effect on future results of operations, cash flows and financial condition unless recovered from customers.

New Source Review Litigation

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

The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities modified certain units at coal-fired generating plants in violation of the new source review requirements of the CAA. The Federal EPA filed its complaints against our subsidiaries in U.S. District Court for the Southern District of Ohio. The Court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications occurred at our generating units over a 20-year period. A bench trial on the liability issues was held during July 2005. Briefing is underway and closing arguments will be heard on September 22, 2005.

In June 2004, the Federal EPA issued a Notice of Violation (NOV) in order to “perfect” its complaint in the pending litigation. The NOV expands the number of alleged “modifications” undertaken at the Amos, Cardinal, Conesville, Kammer, Muskingum River, Sporn and Tanners Creek plants during scheduled outages on these units from 1979 through the present. Approximately one-third of the allegations in the NOV are already contained in allegations made by the states or the special interest groups in the pending litigation. The Federal EPA filed a motion to amend its complaints and to expand the scope of the pending litigation. The AEP subsidiaries opposed that motion. In September 2004, the judge disallowed the addition of claims to the pending case. The judge also granted motions to dismiss a number of allegations in the original filing. Subsequently, the Federal EPA and eight Northeastern states each filed an additional complaint containing the same allegations against the Amos and Conesville plants that the judge disallowed in the pending case. The Northeastern states’ complaint has been assigned to the same judge in the U.S. District Court for the Southern District of Ohio. AEP filed an answer to the Northeastern states’ complaint in January 2005 and to the Federal EPA’s complaint in July 2005, denying the allegations and stating its defense.

On June 24, 2005, the United States Court of Appeals for the District of Columbia Circuit issued a decision affirming in part the new source review reform regulations adopted by the Federal EPA in December 2002. The court upheld the Federal EPA’s decision to apply an actual-to-future actual emissions test, utilizing a five-year look back period to establish actual baseline emissions for utilities and a ten-year period for other sources, and excluding increased emissions unrelated to a physical change from the projected emissions, including emissions associated with demand growth. The court vacated the Federal EPA’s adoption of a broad pollution control project exclusion that includes projects that result in a significant collateral emissions increase, and the “clean unit” applicability test, and remanded certain recordkeeping requirements to the Federal EPA.

We are unable to estimate the loss or range of loss related to any contingent liability we might have for civil penalties under the CAA proceedings. We are also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. If we do not prevail, we believe we can recover any capital and operating costs of additional pollution control equipment that may be required through regulated rates and market prices for electricity. If we are unable to recover such costs or if material penalties are imposed, it would adversely affect future results of operations, cash flows and possibly financial condition.

Emergency Release Reporting

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) requires immediate reporting to the Federal EPA for releases of hazardous substances to the environment above the identified reportable quantity (RQ). The Environmental Planning and Community Right-to-Know Act (EPCRA) requires immediate reporting of releases of hazardous substances that cross property boundaries of the releasing facility.

On July 27, 2004, the Federal EPA Region 5 issued an Administrative Complaint related to the alleged failure of I&M to immediately report under Superfund and EPCRA a November 2002 release of sodium hypochlorite from the Cook Plant. I&M and the Federal EPA signed a Final Consent Agreement and Final Order related to the Administrative Complaint effective June 30, 2005. I&M will pay an immaterial civil penalty and invest in a supplemental environmental project at the Cook Plant.

On December 21, 2004, the Federal EPA notified OPCo of its intent to file a Civil Administrative Complaint, alleging one violation of Superfund reporting obligations and two violations of EPCRA for failure to timely report a June 2004 release of an RQ amount of ammonia from OPCo’s Gavin Plant selective catalytic reduction system. The Federal EPA indicated its intent to seek civil penalties. In February 2005, OPCo provided relevant information that the Federal EPA should consider in advance of any filing.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2004 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.

 


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 has certain market risks inherent in our business activities. These risks include commodity price risk, interest rate risk, foreign exchange risk and credit risk. They represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

Our Investment-Gas Operations segment continues to hold forward gas contracts that were not sold with the gas pipeline and storage assets. These contracts are primarily financial derivatives with some physical contracts which will gradually wind down and completely expire in 2011. Our risk objective is to keep these positions risk neutral through maturity.

We have established policies and procedures that allow us to identify, assess, and manage market risk exposures in our day-to-day operations. Our risk policies have been reviewed with our Board of Directors and approved by our Risk Executive Committee. Our Chief Risk Officer administers our risk policies and procedures. The Risk Executive Committee establishes risk limits, approves risk policies, and assigns responsibilities regarding the oversight and management of risk and monitors risk levels. Members of this committee receive daily, weekly, and monthly reports regarding compliance with policies, limits and procedures. Our committee meets monthly and consists of the Chief Risk Officer, Credit Risk Management, Market Risk Oversight, and senior financial and operating managers.

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 is composed of the chief risk officers of major electricity and gas companies in the United States. The CCRO adopted disclosure standards for risk management contracts to improve clarity, understanding and consistency of information reported. Implementation of the disclosures is voluntary. We support the work of the CCRO and have embraced the disclosure standards. The following tables provide information on our risk management activities:
 
Mark-to-Market Risk Management Contract Net Assets (Liabilities)

This table provides detail on changes in our MTM asset or liability balance sheet position from one period to the next.
 
MTM Risk Management Contract Net Assets
Six Months Ended June 30, 2005
(in millions)

   
Utility Operations
 
Investments-Gas Operations
 
Investments-UK Operations
 
Total
 
Total MTM Risk Management Contract Net Assets   
  (Liabilities) at December 31, 2004
 
$
277
 
$
-
 
$
(12
)
$
265
 
(Gain) Loss from Contracts Realized/Settled During the Period (a)
   
(52
)
 
(4
)
 
12
   
(44
)
Fair Value of New Contracts When Entered During the Period (b)
   
2
   
-
   
-
   
2
 
Net Option Premiums Paid/(Received) (c)
   
(1
)
 
-
   
-
   
(1
)
Change in Fair Value Due to Valuation Methodology Changes
   
-
   
-
   
-
   
-
 
Changes in Fair Value of Risk Management Contracts (d)
   
30
   
(3
)
 
-
   
27
 
Changes in Fair Value of Risk Management Contracts Allocated to
  Regulated Jurisdictions (e)
   
(13
)
 
-
   
-
   
(13
)
Total MTM Risk Management Contract Net Assets
  (Liabilities) at June 30, 2005
 
$
243
 
$
(7
)
$
-
   
236
 
Net Cash Flow and Fair Value Hedge Contracts (f)
                     
(37
)
Ending Net Risk Management Assets at June 30, 2005
                   
$
199
 

(a)
“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized gains from risk management contracts and related derivatives that settled during 2005 where we entered into the contract prior to 2005.
(b)
“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2005. Most of the fair value comes from longer term fixed price contracts with customers that seek 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.
(c)
“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts entered in 2005.
(d)
“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(e)
“Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.
(f)
“Net Cash Flow and Fair Value Hedge Contracts” (pretax) are discussed in detail within the following pages.
 

Detail on MTM Risk Management Contract Net Assets (Liabilities)
As of June 30, 2005
(in millions)

   
Utility Operations
 
Investments-Gas Operations
 
Total
 
Current Assets
 
$
376
 
$
222
 
$
598
 
Noncurrent Assets
   
529
   
164
   
693
 
Total Assets
   
905
   
386
   
1,291
 
                     
Current Liabilities
   
(325
)
 
(217
)
 
(542
)
Noncurrent Liabilities
   
(337
)
 
(176
)
 
(513
)
Total Liabilities
   
(662
)
 
(393
)
 
(1,055
)
                     
Total Net Assets (Liabilities), 
  excluding Hedges
 
$
243
 
$
(7
)
$
236
 
 
 
Reconciliation of MTM Risk Management Contracts to
Total MTM Risk Management Contract Net Assets (Liabilities)
As of June 30, 2005
(in millions)

   
MTM Risk Management Contracts (a)
 
PLUS:
Hedges
 
Total (b)
 
Current Assets
 
$
598
 
$
1
 
$
599
 
Noncurrent Assets
   
693
   
1
   
694
 
Total MTM Derivative Contract Assets
   
1,291
   
2
   
1,293
 
                     
Current Liabilities
   
(542
)
 
(36
)
 
(578
)
Noncurrent Liabilities
   
(513
)
 
(3
)
 
(516
)
Total MTM Derivative Contract Liabilities
   
(1,055
)
 
(39
)
 
(1,094
)
                     
Total MTM Derivative Contract Net Assets
 
$
236
 
$
(37
)
$
199
 

(a)
Does not include Cash Flow and Fair Value Hedges.
(b)
Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Condensed Consolidated Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets (liabilities) provides two fundamental pieces of information.

·
The source of 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, giving 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 June 30, 2005
(in millions)

   
Remainder 2005
 
2006
 
2007
 
2008
 
2009
 
After 2009 (c)
 
Total (d)
 
Utility Operations:
                                    
Prices Actively Quoted - Exchange Traded Contracts
 
$
(32
)
$
6
 
$
23
 
$
-
 
$
-
 
$
-
 
$
(3
)
Prices Provided by Other External Sources - OTC Broker Quotes (a)
   
99
   
107
   
52
   
39
   
-
   
-
   
297
 
Prices Based on Models and Other Valuation Methods (b)
   
(40
)
 
(60
)
 
(18
)
 
7
   
33
   
27
   
(51
)
Total
 
$
27
 
$
53
 
$
57
 
$
46
 
$
33
 
$
27
 
$
243
 
                                             
Investments - Gas Operations:
                                           
Prices Actively Quoted - Exchange Traded Contracts
 
$
(5
)
$
(7
)
$
5
 
$
-
 
$
-
 
$
-
 
$
(7
)
Prices Provided by Other External Sources - OTC Broker Quotes (a)
   
20
   
(3
)
 
(3
)
 
-
   
-
   
-
   
14
 
Prices Based on Models and Other Valuation Methods (b)
   
(3
)
 
(3
)
 
-
   
(2
)
 
(4
)
 
(2
)
 
(14
)
Total
 
$
12
 
$
(13
)
$
2
 
$
(2
)
$
(4
)
$
(2
)
$
(7
)
                                             
Total:
                                           
Prices Actively Quoted - Exchange Traded Contracts
 
$
(37
)
$
(1
)
$
28
 
$
-
 
$
-
 
$
-
 
$
(10
)
Prices Provided by Other External Sources - OTC Broker Quotes (a)
   
119
   
104
   
49
   
39
   
-
   
-
   
311
 
Prices Based on Models and Other Valuation Methods (b)
   
(43
)
 
(63
)
 
(18
)
 
5
   
29
   
25
   
(65
)
Total
 
$
39
 
$
40
 
$
59
 
$
44
 
$
29
 
$
25
 
$
236
 

(a)
Prices Provided by Other External Sources- OTC Broker Quotes reflects information obtained from over-the-counter brokers (OTC), industry services, or multiple-party on-line platforms.
(b)
Prices Based on Models and Other Valuation Methods is in the absence of pricing 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.
(c)
There is mark-to-market value in excess of 10 percent of our total mark-to-market value in individual periods beyond 2009. $24 million of this mark-to-market value is in 2010.
(d)
Amounts exclude Cash Flow and Fair Value Hedges.

The determination of the point at which a market is no longer liquid for placing it in the Modeled category in the preceding table varies by market. The following table 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 June 30, 2005

Commodity
 
Transaction Class
 
Market/Region
 
Tenor
           
(in months)
Natural Gas
 
Futures
 
NYMEX/Henry Hub
 
60
   
Physical Forwards
 
Gulf Coast, Texas
 
36
   
Swaps
 
Gas East - Northeast, Mid-continent,
   
       
Gulf Coast, Texas
 
36
   
Swaps
 
Gas West - Rocky Mountains, West Coast
 
42
   
Exchange Option Volatility
 
NYMEX/Henry Hub
 
12
             
Power
 
Futures
 
Power East - PJM
 
36
   
Physical Forwards
 
Power East - MISO Cin Hub
 
42
   
Physical Forwards
 
Power East - PJM West
 
42
   
Physical Forwards
 
Power East - AEP Dayton (PJM)
 
18
   
Physical Forwards
 
Power East - NEPOOL
 
42
   
Physical Forwards
 
Power East - NYPP
 
42
   
Physical Forwards
 
Power East - ERCOT
 
42
   
Physical Forwards
 
Power East - Com Ed
 
18
   
Physical Forwards
 
Power East - Entergy
 
6
   
Physical Forwards
 
Power West - Palo Verde, Mead
 
54
   
Physical Forwards
 
Power West - North Path 15, South Path 15
 
54
   
Physical Forwards
 
Power West - Mid Columbia
 
54
   
Peak Power Volatility (Options)
 
Cinergy, PJM
 
12
             
Crude Oil
 
Swaps
 
West Texas Intermediate
 
36
             
Emissions
 
Credits
 
SO2, NOx
 
42
             
Coal
 
Physical Forwards
 
PRB, NYMEX, CSX
 
30

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 and gas operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

We employ the use of interest rate forward and swap transactions in order to manage interest rate risk to existing floating rate debt and to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate exposure.

The tables below provide detail on designated, effective cash flow hedges included in our Condensed Consolidated Balance Sheets. The data in the first table indicates the magnitude of cash flow hedges that we have in place. 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. This table further indicates what portions of designated, effective hedges are expected to be reclassified into net income in the next 12 months. The second table provides the nature of changes from December 31, 2004 to June 30, 2005.

Information on energy commodity risk management activities is presented separately from interest rate risk management activities.

 
Cash FlowHedges included in Accumulated Other Comprehensive Income (Loss)
On the Condensed Consolidated Balance Sheet as of June 30, 2005
(in millions)

   
Accumulated Other Comprehensive Income
(Loss) After Tax (a)
 
After Tax
Portion Expected to be Reclassified to Earnings During the Next 12 Months (b)
 
Power and Gas
 
$
(19
)
$
(18
)
Interest Rate
   
(32
)
 
(5
)
               
Total
 
$
(51
)
$
(23
)

Total Accumulated Other Comprehensive Income (Loss) Activity
Six Months Ended June 30, 2005
(in millions)

   
Power and Gas
 
Interest
Rate
 
Total
 
Beginning Balance, December 31, 2004
 
$
23
 
$
(23
)
$
-
 
Changes in Fair Value (c)
   
(15
)
 
(12
)
 
(27
)
Reclassifications from AOCI to Net Income (d)
   
(27
)
 
3
   
(24
)
Ending Balance, June 30, 2005
 
$
(19
)
$
(32
)
$
(51
)

(a)
“Accumulated Other Comprehensive Income (Loss) After Tax” - Gains/losses are net of related income taxes that have not yet been included in the determination of net income; reported as a separate component of shareholders’ equity on the balance sheet.
(b)
“After Tax Portion Expected to be Reclassified to Earnings During the Next 12 Months” - Amount of gains or losses (realized or unrealized) from derivatives used as hedging instruments that have been deferred and are expected to be reclassified into net income during the next 12 months at the time the hedged transaction affects net income.
(c)
“Changes in Fair Value” - Changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at June 30, 2005. Amounts are reported net of related income taxes.
(d)
“Reclassifications from AOCI to Net Income” - Gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into Net Income during the reporting period. Amounts are reported net of related income taxes.

Credit Risk

We limit credit risk by assessing creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness after transactions have been initiated. Only after an entity has met our internal credit rating criteria will we extend unsecured credit. We use Moody’s, S&P and qualitative and quantitative data to assess the financial health of counterparties on an ongoing basis. Our analysis, in conjunction with the rating agencies’ information, is used to determine appropriate risk parameters. We also require cash deposits, letters of credit and parental/affiliate guarantees as security from counterparties depending upon credit quality in our normal course of business.

We have risk management contracts with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily. At June 30, 2005, our credit exposure net of collateral to sub investment grade counterparties was approximately 12.4%,expressed in terms of net MTM assets and net receivables. As of June 30, 2005, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable (in millions, except number of counterparties):

Counterparty Credit Quality
 
Exposure Before Credit Collateral
 
Credit Collateral
 
Net Exposure
 
Number of Counterparties >10%
 
Net Exposure of Counterparties >10%
 
Investment Grade
 
$
767
 
$
140
 
$
627
   
2
 
$
178
 
Split Rating
   
13
   
3
   
10
   
1
   
9
 
Noninvestment Grade
   
193
   
116
   
77
   
3
   
66
 
No External Ratings:
                               
Internal Investment Grade
   
50
   
-
   
50
   
1
   
34
 
Internal Noninvestment Grade
   
25
   
6
   
19
   
2
   
17
 
Total
 
$
1,048
 
$
265
 
$
783
   
9
 
$
304
 

Generation Plant Hedging Information

This table provides information on operating measures regarding the proportion of output of our generation facilities (based on economic availability projections) economically hedged, including both contracts designated as cash flow hedges and contracts not designated as cash flow hedges. This information is forward-looking and provided on a prospective basis through December 31, 2007. This table presents a point-in-time estimate, subject to changes in market conditions and our decisions on how to manage operations and risk. “Estimated Plant Output Hedged” represents the portion of MWHs of future generation/production for which we have sales commitments or estimated requirement obligations to customers.

Generation Plant Hedging Information
Estimated Next Three Years
As of June 30, 2005

   
Remainder 2005
 
2006
 
2007
 
Estimated Plant Output Hedged
   
91
%
 
85
%
 
85
%

VaR Associated with Risk Management Contracts

We use a risk measurement model, which calculates VaR to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at June 30, 2005, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

The following table shows the end, high, average, and low market risk as measured by VaR year-to-date:

VaR Model

Six Months Ended
June 30, 2005
       
Twelve Months Ended
December 31, 2004
       
(in millions)
       
(in millions)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low