thross@aep.com
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, 2006
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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of ‘accelerated filer and large accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check One)
Large accelerated filer   X     Accelerated filer  ___    Non-accelerated filer   ___    

Indicate by check mark whether AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company, are large accelerated filers, accelerated filers, or non-accelerated filers. See definition of ‘accelerated filer and large accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check One)
Large accelerated filer  ___    Accelerated filer  ___   Non-accelerated filer    X_  
 
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
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.
 

 

   
Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2006, the last trading date of the registrants’ most recently completed second fiscal quarter
 
 
 
Number of shares of common stock outstanding of the registrants at
July 31, 2006
         
AEP Generating Company
 
None
 
1,000
       
($1,000 par value)
AEP Texas Central Company
 
None
 
2,211,678
       
($25 par value)
AEP Texas North Company
 
None
 
5,488,560
       
($25 par value)
American Electric Power Company, Inc.
 
$13,492,667,933
 
393,975,064
       
($6.50 par value)
Appalachian Power Company
 
None
 
13,499,500
       
(no par value)
Columbus Southern Power Company
 
None
 
16,410,426
       
(no par value)
Indiana Michigan Power Company
 
None
 
1,400,000
       
(no par value)
Kentucky Power Company
 
None
 
1,009,000
       
($50 par value)
Ohio Power Company
 
None
 
27,952,473
       
(no par value)
Public Service Company of Oklahoma
 
None
 
9,013,000
       
($15 par value)
Southwestern Electric Power Company
 
None
 
7,536,640
       
($18 par value)




AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX TO QUARTERLY REPORTS ON FORM 10-Q
June 30, 2006

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

ADFIT
 
Accumulated Deferred Federal Income Taxes.
ADITC
 
Accumulated Deferred Investment Tax Credits.
AEGCo
 
AEP Generating Company, an AEP electric generating subsidiary.
AEP or Parent
 
American Electric Power Company, Inc.
AEP Consolidated
 
AEP and its majority owned consolidated subsidiaries and consolidated entities.
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.
CAA
 
Clean Air Act.
Cook Plant
 
Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo
 
Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW
 
Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW Operating Agreement
 
Agreement, dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing their generating capacity allocation. AEPSC acts as the agent.
CTC
 
Competition Transition Charge.
DETM
 
Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
EDFIT
 
Excess Deferred Federal Income Taxes.
EITF
 
Financial Accounting Standards Board’s Emerging Issues Task Force.
EPACT
 
Energy Policy Act of 2005.
ERCOT
 
Electric Reliability Council of Texas.
FASB
 
Financial Accounting Standards Board.
Federal EPA
 
United States Environmental Protection Agency.
FERC
 
Federal Energy Regulatory Commission.
GAAP
 
Accounting Principles Generally Accepted in the United States of America.
HPL
 
Houston Pipe Line Company LP, a former AEP subsidiary that was sold in January 2005.
IGCC
 
Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
I&M
 
Indiana Michigan Power Company, an AEP electric utility subsidiary.
IRS
 
Internal Revenue Service.
IPP
 
Independent Power Producers.
IURC
 
Indiana Utility Regulatory Commission.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
KPSC
 
Kentucky Public Service Commission.
kV
 
Kilovolt.
KWH
 
Kilowatthour.
MISO
 
Midwest Independent Transmission System Operator.
 
MTM
 
Mark-to-Market.
MW
 
Megawatt.
MWH
 
Megawatthour.
NOx
 
Nitrogen oxide.
Nonutility Money Pool
 
AEP System’s Nonutility Money Pool.
NRC
 
Nuclear Regulatory Commission.
NSR
 
New Source Review.
NYMEX
 
New York Mercantile Exchange.
OATT
 
Open Access Transmission Tariff.
OCC
 
Corporation Commission of the State of Oklahoma.
OPCo
 
Ohio Power Company, an AEP electric utility subsidiary.
OTC
 
Over the counter.
PJM
 
Pennsylvania - New Jersey - Maryland regional transmission organization.
PSO
 
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTB
 
Price-to-Beat.
PUCO
 
Public Utilities Commission of Ohio.
PUCT
 
Public Utility Commission of Texas.
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 FASB.
SFAS 133
 
Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.”
SIA
 
System Integration Agreement.
SO2
 
Sulfur Dioxide.
SPP
 
Southwest Power Pool.
STP
 
South Texas Project Nuclear Generating Plant.
Sweeny
 
Sweeny Cogeneration Limited Partnership, owner and operator of a four unit, 480 MW gas-fired generation facility, owned 50% by AEP.
SWEPCo
 
Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC
 
AEP Texas Central Company, an AEP electric utility subsidiary.
TEM
 
SUEZ Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing, Inc.).
Texas Restructuring Legislation
 
Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC
 
AEP Texas North Company, an AEP electric utility subsidiary.
True-up Proceeding
 
A filing made under the Texas Restructuring Legislation to finalize the amount of stranded costs and other true-up items and the recovery of such amounts.
Utility Money Pool
 
AEP System’s Utility Money Pool.
VaR
 
Value at Risk, a method to quantify risk exposure.
Virginia SCC
 
Virginia State Corporation Commission.
WPCo
 
Wheeling Power Company, an AEP electric distribution subsidiary.
WVPSC
 
Public Service Commission of West Virginia.


   




FORWARD-LOOKING INFORMATION

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

·
Electric load and customer growth.
·
Weather conditions, including storms.
·
Available sources and costs of, and transportation for, fuels and the creditworthiness of fuel suppliers and transporters.
·
Availability of generating capacity and the performance of our generating plants.
·
Our ability to recover regulatory assets and stranded costs in connection with deregulation.
·
Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·
Our ability to build or acquire generating capacity when needed at acceptable prices and terms and to recover those costs through applicable
rate cases or competitive rates.
·
New legislation, litigation and government regulation including requirements for reduced emissions of sulfur, nitrogen, mercury, carbon and other substances.
·
Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions (including rate or other recovery for new
investments, transmission service and environmental compliance).
·
Resolution of litigation (including pending Clean Air Act enforcement actions and disputes arising from the bankruptcy of Enron Corp. and related matters).
·
Our ability to constrain operation and maintenance costs.
·
Our ability to sell assets at acceptable prices and other acceptable terms.
·
The economic climate and growth in our service territory and changes in market demand and demographic patterns.
·
Inflationary and interest rate trends.
·
Our ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities.
·
Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
·
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 implementation of EPACT and membership in 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

Several factors contributed to our positive performance in the second quarter of 2006. We received favorable outcomes in various regulatory activities causing increased revenues. We also continued to win new power supply contracts with municipal and cooperative customers and our barging subsidiary is producing strong results. Some of these positive factors were offset in part by mild weather and increased fuel costs.

Regulatory Activity

Our significant regulatory activity progressed with the following major developments:

·
In April 2006, the PUCO approved our recovery of the pre-construction costs for the IGCC clean-coal plant in Meigs County, Ohio. We subsequently submitted tariffs and received PUCO approval to recover $24 million of our IGCC pre-construction costs beginning July 1, 2006.
·
In May 2006, we filed a base rate case in Virginia requesting a net rate increase of $198 million. Rates will be effective, subject to refund, on October 2, 2006.
·
In May 2006, the PUCO approved a two-step increase in transmission rates with an over/under recovery mechanism effective April 1, 2006. We subsequently submitted tariffs and received PUCO approval to implement the rates in June 2006. We expect this order to increase 2006 revenues by $63 million.
·
In June 2006, we received a financing order from the PUCT to issue $1.7 billion in securitization bonds. We anticipate issuing the bonds and receiving the proceeds by the end of September 2006. We intend to use the proceeds to reduce a portion of TCC’s debt and equity, which would include a dividend payment to AEP.
·
In July 2006, an ALJ rendered an initial decision to the FERC recommending that current transmission rates in PJM are unjust and unreasonable and should be redesigned to replace the PJM license plate rates effective April 1, 2006. If approved by the FERC, the new regional rates should result in parties outside of the AEP zone in PJM contributing a significant portion of AEP’s transmission revenue requirement, some of which may be treated as a credit to retail customers. The favorable impact of the initial ALJ decision is not determinable pending the decision of the FERC and subject to analysis of credits to retail customers, if any.
·
In July 2006, the FERC approved our request for use of an incentive rate treatment for our proposed 550-mile I-765 transmission line project. The approval is conditioned upon PJM including the project in its formal Regional Transmission Expansion Plan, which should be finalized in 2006 or early 2007.
·
In July 2006, the West Virginia Public Service Commission approved a settlement agreement in APCo and WPCo’s base rate case, providing for a $44 million annual increase in rates effective July 28, 2006. These rates include a surcharge for recovery of the cost of the Wyoming-Jacksons Ferry 765 kV line, which was energized and placed in service in June 2006.

Fuel Costs

During 2006, spot market prices for coal and natural gas have softened. In contrast, market prices for fuel oil have continued to increase. However, even considering softening fuel markets and favorable transportation effects during the first half of the year, we still expect an approximate eleven percent increase in coal costs during 2006, and we have price risk related to these commodity prices. More specifically, we do not have active fuel cost recovery adjustment mechanisms in Indiana and Ohio, which represents approximately 20% of our fuel costs.

In Indiana, our fuel recovery mechanism is temporarily capped, subject to preestablished escalators, at a fixed rate through June 2007. As a consequence of the cap, we incurred under-recoveries of $12 million for the first six months of 2006 and expect additional under-recoveries for the remainder of 2006. Our Ohio companies increased their generation rates in 2006, as previously approved by the PUCO in our Rate Stabilization Plans, which are presently subject to an Ohio Supreme Court remand. These increased rates, along with the reinstated fuel cost adjustment rate clause for over- or under-recovery of fuel and related costs effective July 1, 2006 in West Virginia, will help offset future negative impacts of fuel prices on our gross margins.

Barging Operations

During 2006, we have achieved favorable results in our Investments - Other segment primarily due to our barging operations. AEP MEMCO LLC (MEMCO) handles the dispatching and logistics for our river operations, which consists primarily of coal deliveries to our plants, coal movement between plants for ensuring continued operations when market disruptions occur and transportation of bargeable commodities for third parties. MEMCO continues to benefit from strong market demand for barging services as well as a tight supply of barges, which allowed it to negotiate very favorable annual freight contracts for 2006 and beyond for hauling a variety of commodities for third parties. The strong freight market, enhanced operating conditions when compared with the flooding and ice encountered during the first quarter of 2005 and the continued implementation of programs to maximize equipment use all contribute to an increase in tonnage transported and a related increase in earnings.
 
Stock Option Grant Practices

Our internal audit function recently completed a review of our stock option grant practices. The review was initiated as a matter of prudence resulting from our desire to ensure we had not engaged in the kinds of past practices that have recently received adverse publicity and resulted in investigations of other companies. Our internal auditors found no indication of backdating or special option grant timing.

RESULTS OF OPERATIONS

Segments

Our principal operating business segments and their major activities are:

    Utility Operations
 
·
Generation of electricity for sale to U.S. retail and wholesale customers.
 
·
Electricity transmission and distribution in the U.S.
    Investments - Other
 
·
Bulk commodity barging operations, wind farms, IPPs and other energy supply-related businesses.

Our consolidated Income Before Discontinued Operations for the three and six months ended June 30, 2006 and 2005 were as follows (Earnings and Weighted Average Basic Shares Outstanding in millions):

   
Three Months Ended June 30,
 
Six Months Ended June 30,
 
   
2006
 
2005
 
2006
 
2005
 
   
Earnings
 
EPS (c)
 
Earnings
 
EPS (c)
 
Earnings
 
EPS (c)
 
Earnings
 
EPS (c)
 
Utility Operations
 
$
160
 
$
0.41
 
$
247
 
$
0.64
 
$
525
 
$
1.33
 
$
600
 
$
1.54
 
Investments - Other
   
13
   
0.03
   
(1
)
 
-
   
29
   
0.08
   
4
   
0.01
 
All Other (a)
   
(3
)
 
-
   
(26
)
 
(0.06
)
 
(5
)
 
(0.01
)
 
(40
)
 
(0.10
)
Investments - Gas Operations (b)
   
2
   
-
   
(2
)
 
(0.01
)
 
1
   
-
   
8
   
0.02
 
Income Before Discontinued Operations
 
$
172
 
$
0.44
 
$
218
 
$
0.57
 
$
550
 
$
1.40
 
$
572
 
$
1.47
 
                                                   
Weighted Average Number of Basic
  Shares Outstanding
         
394
         
384
         
394
         
389
 

(a)
All Other includes the parent company’s interest income and expense, as well as other nonallocated costs.
 
(b)
We sold our remaining gas pipeline and storage assets in 2005.
 
(c)
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 2006 Compared to Second Quarter of 2005

Income Before Discontinued Operations in the second quarter of 2006 decreased $46 million compared to the second quarter of 2005 due to an $87 million decrease in Utility Operations earnings primarily related to decreases in off-system sales and transmission revenues and increases in operating expenses, partially offset by new rates implemented in Ohio and Kentucky. The decrease in Utility Operations earnings was partially offset by an earnings increase of $14 million in our Investments - Other segment primarily related to favorable results in our barging operations and a decrease of $23 million in All Other related to interest expense, net of interest income, at the parent company.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Income Before Discontinued Operations for the six months ended June 30, 2006 decreased $22 million compared to the six months ended June 30, 2005 due to a $75 million decrease in Utility Operations earnings primarily related to decreases in off-system sales and transmission revenues and increases in operating expenses, partially offset by new rates implemented in Ohio and Kentucky. The decrease in Utility Operations earnings was partially offset by an earnings increase of $25 million in our Investments - Other segment primarily related to favorable results in our barging operations and a decrease of $35 million in interest expense, net of interest income, at the parent company.

Our results of operations are discussed below according to our operating segments.

Utility Operations

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

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
2006
 
2005
 
2006
 
2005
 
 
(in millions)
 
Revenues
$
2,799
 
$
2,702
 
$
5,768
 
$
5,386
 
Fuel and Purchased Energy
 
1,126
   
988
   
2,253
   
1,911
 
Gross Margin
 
1,673
   
1,714
   
3,515
   
3,475
 
Depreciation and Amortization
 
339
   
317
   
672
   
635
 
Other Operating Expenses
 
987
   
938
   
1,833
   
1,743
 
Operating Income
 
347
   
459
   
1,010
   
1,097
 
Other Income, Net
 
43
   
49
   
85
   
79
 
Interest Expense and Preferred Stock Dividend  Requirements
160
156
314
300
Income Tax Expense
 
70
   
105
   
256
   
276
 
Income Before Discontinued Operations
$
160
 
$
247
 
$
525
 
$
600
 

Summary of Selected Sales and Weather Data
For Utility Operations
For the Three and Six Months Ended June 30, 2006 and 2005

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
2006
 
2005
 
2006
 
2005
 
 
(in millions of KWH)
Energy Summary
                       
Retail:
                       
 
Residential
 
9,590
   
9,956
   
22,528
   
23,180
 
 
Commercial
 
9,440
   
9,573
   
18,349
   
18,305
 
 
Industrial
 
13,716
   
13,480
   
26,937
   
26,253
 
 
Miscellaneous
 
625
   
639
   
1,214
   
1,284
 
Subtotal
 
33,371
   
33,648
   
69,028
   
69,022
 
Texas Retail and Other
 
138
   
161
   
206
   
389
 
Total Retail
 
33,509
   
33,809
   
69,234
   
69,411
 
                         
Wholesale
 
10,822
   
11,745
   
21,667
   
24,380
 
                         
Texas Wires Delivery
 
6,915
   
6,736
   
12,461
   
12,254
 
                         
Total KWHs                   51,246     52,290     103,362     106,045  


Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on results of operations. In general, degree day changes in our eastern region have a larger effect on results of operations than changes in our western region due to the relative size of the two regions and the associated number of customers within each. Cooling degree days and heating degree days in our service territory for the quarter and year-to-date periods ended June 30, 2006 and 2005 were as follows:

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
2006
 
2005
 
2006
 
2005
 
 
(in degree days)
Weather Summary
                       
Eastern Region
                       
Actual - Heating (a)
 
107
   
165
   
1,563
   
1,939
 
Normal - Heating (b)
 
175
   
177
   
1,992
   
1,988
 
                         
Actual - Cooling (c)
 
228
   
288
   
229
   
288
 
Normal - Cooling (b)
 
279
   
278
   
282
   
281
 
                         
Western Region (d)
                       
Actual - Heating (a)
 
5
   
26
   
663
   
795
 
Normal - Heating (b)
 
33
   
33
   
1,005
   
1,005
 
                         
Actual - Cooling (c)
 
815
   
681
   
858
   
701
 
Normal - Cooling (b)
 
652
   
644
   
669
   
662
 

(a)
Eastern Region and Western Region heating degree days are calculated on a 55 degree temperature base.
 
(b)
Normal Heating/Cooling represents the 30-year average of degree days.
 
(c)
Eastern Region and Western Region cooling days are calculated on a 65 degree temperature base.
 
(d)
Western Region statistics represent PSO/SWEPCo customer base only.
 

Second Quarter of 2006 Compared to Second Quarter of 2005

Reconciliation of Second Quarter of 2005 to Second Quarter of 2006
Income from Utility Operations Before Discontinued Operations
(in millions)
 
Second Quarter of 2005
       
$
247
 
               
Changes in Gross Margin:
             
Retail Margins
   
56
       
Off-system Sales
   
(49
)
     
Transmission Revenues
   
(55
)
     
Other
   
7
       
Total Change in Gross Margin
         
(41
)
               
Changes in Operating Expenses and Other:
             
Maintenance and Other Operation
   
(34
)
     
Depreciation and Amortization
   
(22
)
     
Taxes Other Than Income Taxes
   
(15
)
     
Other Income, Net
   
(6
)
     
Interest and Other Charges
   
(4
)
     
Total Change in Operating Expenses and Other
         
(81
)
               
Income Tax Expense
         
35
 
               
Second Quarter of 2006
       
$
160
 

Income from Utility Operations Before Discontinued Operations decreased $87 million to $160 million in 2006. The key drivers of the decrease were a $41 million net decrease in Gross Margin and an $81 million increase in Operating Expenses and Other, partially offset by a $35 million decrease in Income Tax Expense.

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

·
Retail Margins increased $56 million primarily due to the following:
·
A $55 million increase related to new rates implemented in our Ohio jurisdictions as approved by the PUCO in our Rate Stabilization Plans (RSPs) and a $10 million increase related to new rates implemented in Kentucky as approved in our base rate case;
·
A $30 million increase in financial transmission rights revenue, net of congestion costs, due to improved management of price risk related to serving retail load within PJM under current transmission constraints;
·
An $18 million increase related to reduced off-system sales margins shared with customers due to lower off-system sales; and
·
A $14 million increase related to increased usage and customer growth in the industrial and commercial classes of which $11 million relates to the purchase of the Ohio service territory of Monongahela Power in December 2005; partially offset by
·
A $68 million increase in delivered fuel costs, which relates to the AEP East companies with inactive, capped or frozen fuel clauses; and
·
An $11 million decrease in usage related to mild weather. As compared to the prior year, our eastern region experienced a 21% decrease in cooling degree days, partially offset by a 20% increase in cooling degree days in the western region.
·
Margins from Off-system Sales for 2006 decreased $49 million due to lower volumes in part from the sale of STP in May 2005, a forced outage in 2006 at the Oklaunion plant, various eastern fleet outages in 2006 for boiler tube inspections and lower optimization activities.
·
Transmission Revenues decreased $55 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $18 million recorded in the second quarter of 2006 related to potential SECA refunds pending settlement negotiations with various intervenors. At this time, SECA revenues have not been replaced. See the “SECA Revenue Subject to Refund” section of Note 3.

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

·
Maintenance and Other Operation expenses increased $34 million primarily due to increases in generation expenses for planned and forced plant outages, increases in transmission and distribution expenses related to tree trimming and storm restoration and the establishment of a regulatory asset for PJM administrative fees in 2005 which reduced expenses in the prior period, offset by decreases related to the sale of STP in May 2005.
·
Depreciation and Amortization expense increased $22 million primarily due to increased Ohio regulatory asset amortization in conjunction with rate increases as well as higher depreciable property balances.
·
Taxes Other Than Income Taxes increased $15 million primarily due to increased real and personal property taxes.
·
Income Tax Expense decreased $35 million due to the decrease in pretax income.


Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Reconciliation of Six Months Ended June 30, 2005 to Six Months Ended June 30, 2006
Income from Utility Operations Before Discontinued Operations
(in millions)

Six Months Ended June 30, 2005
       
$
600
 
               
Changes in Gross Margin:
             
Retail Margins
   
168
       
Off-system Sales
   
(73
)
     
Transmission Revenues
   
(54
)
     
Other
   
(1
)
     
Total Change in Gross Margin
         
40
 
               
Changes in Operating Expenses and Other:
             
Maintenance and Other Operation
   
(28
)
     
Gain on Sales of Assets, Net
   
(46
)
     
Depreciation and Amortization
   
(37
)
     
Taxes Other Than Income Taxes
   
(16
)
     
Other Income, Net
   
6
       
Interest and Other Charges
   
(14
)
     
Total Change in Operating Expenses and Other
         
(135
)
               
Income Tax Expense
         
20
 
               
Six Months Ended June 30, 2006
       
$
525
 

Income from Utility Operations Before Discontinued Operations decreased $75 million to $525 million in 2006. The key driver of the decrease was a $135 million increase in Operating Expenses and Other, offset by a $40 million increase in Gross Margin and a $20 million decrease in Income Tax Expense.

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

·
Retail Margins increased $168 million primarily due to the following:
·
A $103 million increase related to new rates implemented in our Ohio jurisdictions as approved by the PUCO in our RSPs, a $10 million increase related to new rates implemented in Kentucky as approved in our base rate case and a $7 million increase related to new rates implemented in Oklahoma in June 2005;
·
A $76 million increase in financial transmission rights revenue, net of congestion costs, due to improved management of price risk related to serving retail load within PJM under current transmission constraints;
·
A $41 million increase related to increased usage and customer growth in the industrial and commercial classes of which $21 million relates to the purchase of the Ohio service territory of Monongahela Power in December 2005;
·
An $18 million increase related to reduced off-system sales margins shared with customers due to lower off-system sales; and
·
A $29 million increase related to increased sales to municipal, cooperative and other wholesale customers primarily as a result of new power supply contracts; partially offset by
·
A $109 million increase in delivered fuel cost, which relates to AEP East companies with inactive, capped or frozen fuel clauses; and
·
A $37 million decrease in usage related to mild weather. As compared to the prior year, our eastern region and western region experienced 19% and 17% declines, respectively, in heating degree days. These decreases were partially offset by an increase of 22% in cooling degree days in the western region.
·
Margins from Off-system Sales for 2006 were $73 million lower than in 2005 due to lower volumes in part from the sale of STP in May 2005, a forced outage in 2006 at the Oklaunion plant, various eastern fleet outages in 2006 for boiler tube inspections and lower optimization activities.
·
Transmission Revenues decreased $54 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $19 million recorded in 2006 related to potential SECA refunds pending settlement negotiations with various intervenors. At this time, SECA revenues have not been replaced. See the “SECA Revenue Subject to Refund” section of Note 3.

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

·
Maintenance and Other Operation expenses increased $28 million primarily due to increases in generation expenses related to base operations, maintenance and planned and forced plant outages, distribution expenses related to tree trimming and the establishment of a regulatory asset for PJM administrative fees in 2005 which reduced expenses in the prior period, offset by favorable variances related to expenses from the January 2005 ice storm in Ohio and Indiana and decreases related to the sale of STP in May 2005.
·
Gain on Sales of Assets, Net decreased $46 million resulting from 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. In 2005, we reached a settlement with Centrica and received $112 million related to two years of earnings sharing whereas in 2006 we received $70 million related to one year of earnings sharing.
·
Depreciation and Amortization expense increased $37 million primarily due to increased Ohio regulatory asset amortization in conjunction with rate increases as well as higher depreciable property balances.
·
Taxes Other Than Income Taxes increased $16 million primarily due to increased real and personal property taxes.
·
Interest and Other Charges increased $14 million from the prior period primarily due to additional debt issued in late 2005 and early 2006 and increasing interest rates.
·
Income Tax Expense decreased $20 million due to the decrease in pretax income.

Investments - Other

Second Quarter of 2006 Compared to Second Quarter of 2005

Income Before Discontinued Operations from our Investments - Other segment increased from a loss of $1 million in 2005 to income of $13 million in 2006. The increase was primarily due to favorable barging activity at MEMCO due to strong demand and a tight supply of barges, resulting in increased barge freight rates.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Income Before Discontinued Operations from our Investments - Other segment increased $25 million primarily due to favorable barging activity at MEMCO due to strong demand and a tight supply of barges which increased barge freight rates. Additionally, the first quarter of 2006 operating conditions for our barging operations improved from 2005 when severe ice and flooding caused increased operating costs.

Other

Parent

Second Quarter of 2006 Compared to Second Quarter of 2005

The parent company’s Loss before Discontinued Operations decreased $23 million from 2005 primarily due to lower interest expense and associated buyback costs related to the redemption of $550 million of senior unsecured notes in April 2005 and increased affiliated interest income related to favorable results from the corporate borrowing program.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

The parent company’s Loss before Discontinued Operations decreased $35 million from 2005 primarily due to lower interest expense and associated buyback costs related to the redemption of $550 million of senior unsecured notes in April 2005 and increased affiliated interest income related to favorable results from the corporate borrowing program.

Investments - Gas Operations

Second Quarter of 2006 Compared to Second Quarter of 2005

Income Before Discontinued Operations from our Gas Operations segment increased from a loss of $2 million in 2005 to income of $2 million in 2006. The increase primarily relates to a true-up adjustment in the second quarter of 2006 related to the Enron litigation settled in the fourth quarter of 2005. Current year results also relate to gas contracts that were not sold with the gas pipeline and storage assets.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005

Income Before Discontinued Operations from our Gas Operations segment of $1 million in 2006 compares with $8 million of income recorded for 2005. Prior year results included one month of HPL’s operations due to the sale of HPL in January 2005. Current year results relate to gas contracts that were not sold with the gas pipeline and storage assets.

AEP System Income Taxes

The decrease in income tax expense of $31 million between the second quarter of 2006 and the second quarter of 2005 is primarily due to a decrease in pretax book income.

The decrease in income tax expense of $14 million between the six months ended June 30, 2006 and the six months ended June 30, 2005 is primarily due to a decrease in pretax book income.

FINANCIAL CONDITION

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

Debt and Equity Capitalization ($ in millions)

   
June 30, 2006
 
December 31, 2005
 
Long-term Debt, including amounts due within one year
 
$
12,645
   
56.7
%
$
12,226
   
57.2
%
Short-term Debt
   
159
   
0.7
   
10
   
0.0
 
Total Debt
   
12,804
   
57.4
   
12,236
   
57.2
 
Common Equity
   
9,426
   
42.3
   
9,088
   
42.5
 
Preferred Stock
   
61
   
0.3
   
61
   
0.3
 
                           
Total Debt and Equity Capitalization
 
$
22,291
   
100.0
%
$
21,385
   
100.0
%

The amount of our common equity increased primarily due to earnings exceeding the amount of dividends paid in 2006. However, as a consequence of increasing debt for capital investment during 2006, our ratio of total debt to total capital increased from 57.2% to 57.4%.

The FASB’s current pension and postretirement benefit accounting project could have a major negative impact on our debt to capital ratio in future years. The potential change could require the recognition of an additional minimum liability for fully-funded pension and postretirement benefit plans, thereby eliminating on the balance sheet the SFAS 87 and SFAS 106 deferral and amortization of net actuarial gains and losses. If adopted, this could require recognition of a significant net-of-tax accumulated other comprehensive income reduction to common equity for those regulatory jurisdictions where a regulatory asset cannot be recorded. The proposed effective date is fiscal years ending after December 15, 2006. We cannot predict the ultimate effects of the final amendment if adopted.

Liquidity

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

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments. At June 30, 2006, our available liquidity was approximately $3.1 billion as illustrated in the table below:
 

    Amount   
 Maturity
 
    (in millions)        
Commercial Paper Backup:
           
Revolving Credit Facility
 
$
1,500
   
March 2010
 
Revolving Credit Facility
   
1,500
   
April 2011
 
Total
   
3,000
       
Cash and Cash Equivalents
   
249
       
Total Liquidity Sources
   
3,249
       
Less: AEP Commercial Paper Outstanding
   
144
       
Letter of Credit Drawn
   
31
       
Net Available Liquidity
 
$
3,074
       
 
In April 2006, we amended the terms and increased the size of our credit facilities from $2.7 billion to $3 billion on terms more economically favorable than the previous agreements. The amended facilities are structured as two $1.5 billion credit facilities, each with an option to issue up to $200 million as letters of credit.

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, 2006, this contractually-defined percentage was 54.4%. Nonperformance of these covenants could result in an event of default under these credit agreements. At June 30, 2006, we complied with all of the covenants contained in these credit agreements. In addition, the acceleration of our payment obligations, or the obligations of certain of our subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million would cause an event of default under these credit agreements and permit the lenders to declare the outstanding amounts payable.

The two amended revolving credit facilities do not contain a material adverse change clause.

Under a regulatory order, 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 the 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, 2006, all utility subsidiaries were comfortably in compliance with this order.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders. At June 30, 2006, our utility subsidiaries had not exceeded those authorized limits.

Credit Ratings

AEP’s ratings have not been adjusted by any rating agency during 2006 and AEP is currently on a stable outlook by the rating agencies. Our current credit ratings are as follows:

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

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

Cash Flow

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

   
Six Months Ended
June 30,
 
   
2006
 
2005
 
   
(in millions)
 
Cash and Cash Equivalents at Beginning of Period
 
$
401
 
$
320
 
Net Cash Flows From Operating Activities
   
1,137
   
982
 
Net Cash Flows From (Used For) Investing Activities
   
(1,586
)
 
458
 
Net Cash Flows From (Used For) Financing Activities
   
297
   
(1,153
)
Net Increase (Decrease) in Cash and Cash Equivalents
   
(152
)
 
287
 
Cash and Cash Equivalents at End of Period
 
$
249
 
$
607
 

Cash from operations, combined with a bank-sponsored receivables purchase agreement and short-term borrowings, provides working capital and allows us to meet other short-term cash needs. We use our corporate borrowing program to meet the short-term borrowing needs of our subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries. In addition, we also fund, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of June 30, 2006, we had credit facilities totaling $3.0 billion to support our commercial paper program with $144 million outstanding. The maximum amount of commercial paper outstanding during the six months ended June 30, 2006 was $325 million. The weighted-average interest rate for our commercial paper during the first six months of 2006 was 4.86%. We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding mechanisms are arranged. Sources of long-term funding include issuance of common stock or long-term debt and sale-leaseback or leasing agreements. Utility Money Pool borrowings and external borrowings may not exceed authorized limits under regulatory orders. See the discussion below for further detail related to the components of our cash flows.

Operating Activities

   
Six Months Ended
June 30,
 
   
2006
 
2005
 
   
(in millions)
 
Net Income
 
$
556
 
$
576
 
Less: Income From Discontinued Operations
   
(6
)
 
(4
)
Income From Continuing Operations
   
550
   
572
 
Noncash Items Included in Earnings
   
634
   
611
 
Changes in Assets and Liabilities
   
(47
)
 
(201
)
Net Cash Flows From Operating Activities
 
$
1,137
 
$
982
 

The key driver of the increase in cash from operations for the first six months of 2006 was due to no Pension Contributions to Qualified Plan Trusts in 2006 compared with a $204 million contribution in 2005.

Net Cash Flows From Operating Activities were $1.1 billion in 2006 consisting primarily of Income from Continuing Operations of $550 million adjusted for noncash charges of $634 million, which principally includes $689 million for Depreciation and Amortization. In 2005, we initiated fuel proceedings in Oklahoma, Texas, Virginia and Arkansas seeking recovery of our increased fuel costs. Under-recovered fuel costs decreased in 2006 due to the recovery of higher cost of fuel, especially natural gas. Other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in these asset and liability accounts relates to a number of items; the most significant are a $185 million cash increase from net Accounts Receivable/Accounts Payable due to a lower balance of Customer Accounts Receivable at June 30, 2006 and a $189 million decrease in cash related to customer deposits held for trading activities.

Net Cash Flows From Operating Activities were $982 million in 2005 consisting primarily of Income from Continuing Operations of $572 million adjusted for noncash charges of $611 million, which principally includes $652 million for Depreciation and Amortization. We realized gains of $115 million on sales of assets and made contributions of $204 million to our pension trust fund. Changes in Assets and Liabilities represent those 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, Net and an increase in the balance of Accrued Taxes of $172 million. Cash increased related to Accounts Receivable, Net due to a higher factored balance at June 30, 2005. Accrued Taxes increased due to no estimated federal income tax payment during the first quarter of 2005 and paying $43 million, net of refunds received, during the first half of 2005.

Investing Activities

   
Six Months Ended
June 30,
 
   
2006
 
2005
 
   
(in millions)
 
Investment Securities:
           
Purchases of Investment Securities
 
$
(5,647
)
$
(2,141
)
Sales of Investment Securities
   
5,596
   
2,213
 
Change in Investment Securities, Net
   
(51
)
 
72
 
Construction Expenditures
   
(1,625
)
 
(1,020
)
Change in Other Temporary Cash Investments, Net
   
3
   
(103
)
Proceeds from Sales of Assets
   
123
   
1,500
 
Other
   
(36
)
 
9
 
Net Cash Flows From (Used for) Investing Activities
 
$
(1,586
)
$
458
 

Net Cash Flows Used For Investing Activities were $1.6 billion in 2006 primarily due to Construction Expenditures, which increased mostly due to our environmental investment plan.

During 2006, we purchased $5.6 billion of investments and received $5.6 billion of proceeds from the sales of securities. During 2005, we purchased $2.1 billion of investments and received $2.2 billion of proceeds from the sales of securities. In our normal course of business, we purchase auction rate securities and variable rate demand notes with cash available for short-term investments. These amounts also include purchases and sales within our nuclear trusts.

Net Cash Flows From Investing Activities were $458 million in 2005 primarily due to the proceeds from the sale of HPL, a portion of which we used to repurchase common stock and retire senior unsecured notes. Our Construction Expenditures of $1 billion included generation, environmental, transmission and distribution investment.

We forecast $2.1 billion of Construction Expenditures for the remainder of 2006, which will be funded through results of operations and financing activities. These expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, and the ability to access capital.

Financing Activities

   
Six Months Ended
June 30,
 
   
2006
 
2005
 
   
(in millions)
 
Issuance of Common Stock
 
$
6
 
$
28
 
Repurchase of Common Stock
   
-
   
(427
)
Issuance/Retirement of Debt, Net
   
552
   
(389
)
Dividends Paid on Common Stock
   
(291
)
 
(273
)
Other
   
30
   
(92
)
Net Cash Flows From (Used for) Financing Activities
 
$
297
 
$
(1,153
)

Net Cash Flows From Financing Activities in 2006 were $297 million. During the six months of 2006, we issued $115 million of new obligations relating to pollution control bonds, issued $850 million of notes and retired $396 million of notes for a net increase in notes outstanding of $454 million and increased our short-term commercial paper outstanding by $144 million. See Note 13 for a complete discussion of long-term debt issuances and retirements. The Other amount of $30 million in the above table includes a $68 million payment received from a coal supplier, net of an $8 million repayment, related to a long-term coal purchase contract amended in March 2006.

Net Cash Flows Used For Financing Activities in 2005 were $1.2 billion. During the six months of 2005, we repurchased common stock using a portion of the proceeds from the sale of HPL. In addition, our subsidiaries retired $66 million of cumulative preferred stock, which is reflected in the Other amount in the above table.

Off-balance Sheet Arrangements

Under a limited set of circumstances we enter into off-balance sheet arrangements to accelerate cash collections, reduce operational expenses and spread risk of loss to third parties. Our current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements and sales of customer accounts receivable that we enter in the normal course of business. Our significant off-balance sheet arrangements have changed from year-end as follows:
 
 
June 30,
2006
 
December 31,
2005
 
   
(in millions)
 
AEP Credit
 
$
560
 
$
516
 
Rockport Plant Unit 2
   
2,437
   
2,511
 
Railcars
   
31
   
31
 

For complete information on each of these off-balance sheet arrangements see the “Off-balance Sheet Arrangements” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2005 Annual Report.

Summary Obligation Information

A summary of our contractual obligations is included in our 2005 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” - “Financing Activities” above.

Other
 
Cook Plant Outage

On July 30, 2006, Unit 1 of our Cook Plant was taken off line due to elevated ambient temperatures in the containment building caused by a combination of high Lake Michigan water temperatures and partial blockage of cooling ventilation units. The Unit’s operating license limits the containment building temperature to 120 degrees. Supplemental cooling units were installed on both units and will remain in place for the near future. Unit 1 returned to service on August 3, 2006.
 
Texas REPs

As part of the purchase and sale agreement related to the sale of our Texas REPs in 2002, we retained the right to share in earnings with Centrica from the two REPs above a threshold amount through 2006 if the Texas retail market developed increased earnings opportunities. In March of 2006, we received a $70 million payment for our share in earnings for 2005. The payment for 2006 is contingent on Centrica’s future operating results, capped at $20 million and, to the extent earned, is expected to be received in the first quarter of 2007. See “Texas REPs” section of Note 8.

New Generation

In December 2005, PSO sought proposals for new base load generation to be online in 2011. PSO received six proposals and evaluated those proposals meeting the Request for Proposal criteria with oversight from a neutral third party. In July 2006, PSO announced plans to enter a joint venture with Oklahoma Gas and Electric Company (OG&E) where OG&E will construct and operate a new 950 MW coal-fueled electricity generating unit near Red Rock, Oklahoma. PSO will own 50% of the new unit. Preliminary cost estimates for 100% of the new facility are approximately $1.8 billion. The 2006 through 2008 estimated construction expenditures as disclosed in our 2005 Form 10-K included cost estimates for a base load facility.

In December 2005, SWEPCo sought proposals for new peaking, intermediate and base load generation to be online between 2008 and 2011. In May 2006, SWEPCo announced plans to construct short-term, mid-term and long-term generation to meet the demands of its customers. SWEPCo will build up to 480 MW of simple-cycle natural gas combustion turbine peaking generation in Tontitown, Arkansas and will build a 480 MW combined-cycle natural gas fired plant at the existing Arsenal Hill Power Plant in Shreveport, Louisiana. SWEPCo also plans to build a new base load coal or lignite-fueled plant by 2011 to meet the longer-term generation needs of its customers. Preliminary cost estimates for the new facilities are approximately $1.4 billion. The 2006 through 2008 estimated construction expenditures as disclosed in our 2005 Form 10-K included cost estimates for these types of facilities.

All new generation construction projects discussed above are subject to regulatory approvals from the various states in which the companies operate. Construction is expected to begin in 2007.

SIGNIFICANT FACTORS

We continue to be involved in various matters described in the “Significant Factors” section of Management’s Financial Discussion and Analysis of Results of Operations in our 2005 Annual Report. The 2005 Annual Report should be read in conjunction with this report in order to understand significant factors without material changes in status since the issuance of our 2005 Annual Report, but may have a material impact on our future results of operations, cash flows and financial condition.

AEP Interstate Project

In January 2006, we filed a proposal with the FERC and PJM to build a new 765 kV 550-mile transmission line stretching from West Virginia to New Jersey. The 765 kV line is designed to create a major thoroughfare and reduce PJM congestion costs by substantially improving west-east peak transfer capability by approximately 5,000 MW and reducing transmission line losses by up to 280 MW. It will also enhance reliability of the Eastern transmission grid. A new subsidiary, AEP Transmission Co., LLC, will own the line and undertake construction of the project. The projected cost for the project is approximately $3 billion, which may be shared with other participants, and the project is subject to PJM, state and federal regulatory approvals and appropriate incentive cost recovery mechanisms. The projected in-service date is 2014, subject to PJM and FERC approvals, assuming three years to site and acquire rights-of-way and five years to construct the line. We also were the first to file with the DOE seeking to have the proposed route designated a National Interest Electric Transmission Corridor (NIETC). The Energy Policy Act of 2005 provides for NIETC designation for areas experiencing electric energy transmission capacity constraints or congestion that adversely affects consumers.

In July 2006, the FERC granted conditional approval for incentive rate treatment for the proposed line as we requested. The approval is conditioned upon the new line being included in PJM’s formal Regional Transmission Expansion Plan to be finalized later this year or in early 2007. The approved incentives include, (a) a return on equity set at the high end of the “zone of reasonableness”; (b) the option to timely recover the cost of capital associated with construction work in progress; and (c) the ability to defer expense and recover costs incurred during the pre-construction and pre-operating period. The approval does not constitute final FERC action, as we will need to implement the incentives in future rate filings.

Texas Regulatory Activity

Texas Restructuring

The PUCT issued an order in TCC’s True-up Proceeding in February 2006, which determined that TCC’s true-up regulatory asset was $1.475 billion including carrying costs through September 2005. In December 2005, TCC adjusted its recorded net true-up regulatory asset to comply with the order. We appealed, seeking additional recovery consistent with the Texas Restructuring Legislation and related rules. Other parties have appealed the PUCT’s order claiming it permits TCC to over-recover stranded costs.

TCC filed an application in March 2006 requesting to securitize its net stranded generation plant costs and related carrying costs through August 31, 2006. In June 2006, the PUCT approved TCC’s settlement with intervenors authorizing the securitization of $1.697 billion of net stranded generation costs including carrying costs through August 31, 2006, the assumed securitization date, plus estimated issuance costs of $23 million, for a total of $1.72 billion. We anticipate issuing the securitization bonds by the end of the third quarter of 2006.

The differences between the securitization amount ordered by the PUCT of $1.7 billion and the recorded securitizable true-up regulatory asset of $1.5 billion at June 30, 2006 are detailed in the table below:

   
(in millions)
 
Stranded Generation Plant Costs
 
$
974
 
Net Generation-related Regulatory Asset
   
249
 
Excess Earnings
   
(49
)
Recorded Net Stranded Generation Plant Costs
   
1,174
 
Recorded Debt Carrying Costs on Net Stranded Generation Plant Costs
   
375
 
Recorded Securitizable True-up Regulatory Asset
   
1,549
 
Unrecorded But Recoverable Equity Carrying Costs
   
217
 
Unrecorded Estimated July 2006 - August 2006 Debt Carrying Costs
   
17
 
Unrecorded Excess Earnings, Related Carrying Costs and Other
   
52
 
Settlement Reduction
   
(77
)
Reduction for ADITC and EDFIT Benefits
   
(61
)
Approved Securitizable Amount
   
1,697
 
Unrecorded Securitization Issuance Costs
   
23
 
Amount to be Securitized
 
$
1,720
 

In June 2006, TCC filed to implement a CTC refund of $355 million for its net other true-up items over eight years. The differences between the components of TCC’s Recorded Net Regulatory Liabilities for Other True-up Items as of June 30, 2006 and its CTC proceeding request are detailed below:

   
(in millions)
 
Wholesale Capacity Auction True-up
 
$
61
 
Carrying Costs on Wholesale Capacity Auction True-up
   
28
 
Retail Clawback including Carrying Costs
   
(63
)
Deferred Over-recovered Fuel Balance
   
(181
)
Retrospective ADFIT Benefit
   
(70
)
Other
   
(4
)
Recorded Net Regulatory Liabilities - Other True-up Items
   
(229
)
Unrecorded Prospective ADFIT Benefit
   
(240
)
Unrecorded Estimated July 2006 - August 2006 Carrying Costs
   
(6
)
Gross CTC Refund
   
(475
)
FERC Jurisdictional Fuel Refund Deferral
   
16
 
ADITC and EDFIT Benefit Refund Deferral
   
97
 
Net CTC Refund Proposed, After Deferrals
   
(362
)
Rate Case Expense Surcharge
   
7
 
Net Refund Proposed, After Deferrals and Expenses
 
$
(355
)

TCC requested that a portion of the refund be deferred, pending the outcome of two contingent federal matters related to the refund of $16 million of FERC jurisdictional fuel over-recoveries and $97 million for potential tax normalization violation matters related to the refund of ADITC and EDFIT benefits. Although TCC proposed to refund the $355 million over eight years, certain intervenors have supported accelerated refunds. Management cannot predict the outcome of this filing. If the two contingent federal matters are resolved unfavorably, TCC will refund the $16 million and the $97 million plus carrying costs.

Municipal customers and other intervenors are appealing the PUCT orders seeking to further reduce TCC’s true-up recoveries. If we determine as a result of future PUCT orders or appeal court rulings that it is probable TCC cannot recover a portion of its recorded net true-up regulatory asset and we are able to estimate the amount of a resultant impairment, we would record a provision for such amount which would have an adverse effect on future results of operations, cash flows and possibly financial condition. TCC is appealing the PUCT orders seeking relief in both state and federal court where it believes the PUCT’s rulings are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law.
 
These appeals could take years to resolve and could result in material effects on future results of operations. If the PUCT rejects TCC’s deferral proposal and a normalization violation occurs, future results of operations and cash flows could be adversely affected by the recapture of $105 million of TCC’s ADITC and the loss by TCC of future accelerated tax depreciation election. The estimated future impact on earnings of the Texas restructuring as of June 30, 2006, exclusive of a possible normalization violation and any effects of appeal litigation, over the 14-year securitization net recovery period assuming the PUCT approves TCC’s CTC filing is detailed below:

   
(in millions)
 
ADITC and EDFIT Benefits Reducing Securitization
 
$
97
 
ADFIT Benefit Applied to Reduce 2002 Securitization of Regulatory Assets
   
(64
)
Securitization Settlement
   
(77
)
Unrecorded Prospective ADFIT Benefit Increasing the CTC Refund
   
(240
)
Unrecorded Equity Carrying Costs Recognized as Collected
   
217
 
Future Carrying Cost Payable on Proposed CTC Refund
   
(113
)
Deferred Fuel - Federal Jurisdictional Issue
   
16
 
Net Adverse Earnings Impact Over 14 Years
 
$
(164
)

If the proposed CTC deferral is rejected by the PUCT or the two contingencies are refunded to customers, the future adverse impact on results of operations over the next 14 years will increase to $317 million. This potential adverse impact on results of operations over the next 14 years would be more than offset by the annual cost of money benefit from the $2.2 billion in net proceeds that resulted from the sale of bonds in connection with the initial regulatory asset securitization in 2002 of $797 million and from the upcoming $1.720 billion sale of securitization bonds later this year less the proposed $355 million CTC refund over the next eight years.
 
Litigation

In the ordinary course of business, we and our subsidiaries are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases that have a probable likelihood of loss and the loss amount can be estimated. For details on our pending litigation and regulatory proceedings see Note 4 - Rate Matters, Note 6 - Customer Choice and Industry Restructuring, Note 7 - Commitments and Contingencies and the “Litigation” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2005 Annual Report. Additionally, see Note 3 - Rate Matters, Note 4 - Customer Choice and Industry Restructuring and Note 5 - Commitments and Contingencies included herein. An adverse result in these proceedings has the potential to materially affect the results of operations, cash flows and financial condition of AEP and its subsidiaries.

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

Environmental Matters

We have committed to substantial capital investments and additional operational costs to comply with new environmental control requirements. The sources of these requirements include:

·
Requirements under the CAA to reduce emissions of SO2, NOx, particulate matter (PM), and mercury from fossil fuel-fired power plants;
·
Requirements under the Clean Water Act (CWA) 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 (CO2) emissions to address concerns about global climate change.

In addition, we are engaged in litigation with respect to certain environmental matters, have been notified of potential responsibility for the clean-up of contaminated sites, and incur costs for disposal of spent nuclear fuel and future decommissioning of our nuclear units. All of these matters are discussed in the “Environmental Matters” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2005 Annual Report.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control mobile and stationary sources of air emissions. The major CAA programs affecting our power plants are briefly described below. Many of these programs are implemented and administered by the states, which can impose additional or more stringent requirements.

National Ambient Air Quality Standards: The CAA requires the Federal EPA to periodically review the available scientific data for six criteria pollutants and establish a concentration level in the ambient air for those substances that is adequate to protect the public health and welfare with an extra margin for safety. These concentration levels are known as national ambient air quality standards (NAAQS).

Each state identifies those areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (nonattainment areas). Each state must then develop a state implementation plan (SIP) to bring nonattainment areas into compliance with the NAAQS and maintain good air quality in attainment areas. All SIPs are then submitted to the Federal EPA for approval. If a state fails to develop adequate plans, the Federal EPA must develop and implement a plan. In addition, as the Federal EPA reviews the NAAQS, the attainment status of areas can change, and states may be required to develop new SIPs. The Federal EPA recently proposed a new PM NAAQS and is conducting periodic reviews for additional criteria pollutants.

In 1997, the Federal EPA established new NAAQS that required further reductions in SO2 and NOx emissions. In 2005, the Federal EPA issued a final model federal rule, the Clean Air Interstate Rule (CAIR), that assists states developing new SIPs to meet the new NAAQS. CAIR reduces regional emissions of SO2 and NOx from power plants in the Eastern U.S. (29 states and the District of Columbia). CAIR requires power plants within these states to reduce emissions of SO2 by 50 percent by 2010, and by 65 percent by 2015. NOx emissions will be subject to additional limits beginning in 2009, and will be reduced by a total of 70 percent from current levels by 2015. Reduction of both SO2 and NOx would be achieved through a cap-and-trade program. The Federal EPA affirmed certain aspects of the final CAIR after considering petitions for reconsideration. The rule has been challenged in the courts. States must develop and submit SIPs to implement CAIR by November 2006. Nearly all of the states in which our power plants are located will be covered by CAIR. Oklahoma is not affected, while Texas and Arkansas will be covered only by certain parts of CAIR. A SIP that complies with CAIR will also establish compliance with other CAA requirements, including certain visibility goals.

Hazardous Air Pollutants: As a result of the 1990 Amendments to the CAA, the Federal EPA investigated hazardous air pollutant (HAP) emissions from the electric utility sector and submitted a report to Congress, identifying mercury emissions from coal-fired power plants as warranting further study. In March 2005, the Federal EPA issued a final Clean Air Mercury Rule (CAMR) setting mercury standards for new coal-fired power plants and requiring all states to issue new SIPs including mercury requirements for existing coal-fired power plants. The Federal EPA issued a model federal rule based on a cap-and-trade program for mercury emissions from existing coal-fired power plants that would reduce mercury emissions to 38 tons per year from all existing plants in 2010, and to 15 tons per year in 2018. The national cap of 38 tons per year in 2010 is intended to reflect the level of reduction in mercury emissions that will be achieved as a result of installing controls to reduce SO2 and NOx emissions in order to comply with CAIR. The Federal EPA reaffirmed the final CAMR after reconsidering certain aspects of the rule, and the rule has been challenged in the courts. States must develop and submit their SIPs to implement CAMR by November 2006.

The Acid Rain Program: The 1990 Amendments to the CAA included a cap-and-trade emission reduction program for SO2 emissions from power plants, implemented in two phases. By 2000, the program established a nationwide cap on power plant SO2 emissions of 8.9 million tons per year. The 1990 Amendments also contained requirements for power plants to reduce NOx emissions through the use of available combustion controls.

The success of the SO2 cap-and-trade program encouraged the Federal EPA and the states to use it as a model for other emission reduction programs, including CAIR and CAMR. We meet our obligations under the Acid Rain Program through the installation of controls, use of alternate fuels, and participation in the emissions allowance markets. CAIR uses the SO2 allowances originally allocated through the Acid Rain Program as the basis for its SO2 cap-and trade system.

Regional Haze: The CAA also establishes visibility goals for certain federally-designated areas, including national parks, and requires states to submit SIPs that will demonstrate reasonable progress toward preventing impairment and remedying any existing impairment of visibility in these areas. This is commonly called the “Regional Haze” program. In June 2005, the Federal EPA issued its final Clean Air Visibility Rule (CAVR), detailing how the CAA’s best available retrofit technology (BART) requirements will be applied to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants. The final rule contains a demonstration that for power plants subject to CAIR, CAIR will result in more visibility improvements than BART would provide. Thus, states are allowed to substitute CAIR requirements in their Regional Haze SIPs for controls that would otherwise be required by BART. For BART-eligible facilities located in states not subject to CAIR requirements for SO2 and NOx, some additional controls will be required. The final rule has been challenged in the courts.

Estimated Air Quality Environmental Investments

As discussed in the 2005 Annual Report, the CAIR and CAMR programs described above will require us to make significant additional investments, some of which are estimable. However, many of the rules described above have been challenged in the courts and have not yet been incorporated into SIPs. As a result, these rules may be further modified. Our 2006 through 2010 investment estimates of $191 million for NOx controls and $2.8 billion for SO2 controls disclosed in the 2005 Annual Report are subject to significant uncertainties, and will be affected by any changes in the outcome of several interrelated variables and assumptions, including: the timing of implementation, required levels of reductions, methods for allocation of allowances and our selected compliance alternatives. In short, we cannot estimate our compliance costs with certainty.

We will seek recovery of expenditures for pollution control technologies, replacement or additional generation and associated operating costs from customers through our regulated rates (in regulated jurisdictions). We should be able to recover these expenditures through market prices in deregulated jurisdictions. If not, those costs could adversely affect future results of operations, cash flows and possibly financial condition.

Potential Regulation of CO2 Emissions

At the Third Conference of the Parties to the United Nations Framework Convention on Climate Change held in Kyoto, Japan in December 1997, more than 160 countries, including the U.S., negotiated a treaty requiring legally-binding reductions in emissions of greenhouse gases, chiefly CO2, which many scientists believe are contributing to global climate change. The U.S. signed the Kyoto Protocol in November 1998, but the treaty was not submitted to the Senate for its advice and consent. In March 2001, President Bush announced his opposition to the treaty. During 2004, enough countries ratified the treaty for it to become enforceable against the ratifying countries in February 2005. Several bills have been introduced in Congress seeking regulation of greenhouse gas emissions, including CO2 emissions from power plants, but none have passed either house of Congress.
 
The Federal EPA stated that it does not have authority under the CAA to regulate greenhouse gas emissions that may affect global climate trends. This decision was challenged in the courts and upheld by an appellate court. The U.S. Supreme Court will review the appellate decision. While mandatory requirements to reduce CO2 emissions at our power plants do not appear imminent, we participate in a number of voluntary programs to monitor, mitigate, and reduce greenhouse gas emissions.

Environmental Litigation

New Source Review (NSR) Litigation: In 1999, the Federal EPA and a number of states filed complaints alleging that APCo, CSPCo, I&M, and OPCo modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA. A separate lawsuit, initiated by certain environmental intervenor groups, has been consolidated with the Federal EPA case. Several similar complaints were filed in 1999 and 2000 against other nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these cases were resolved through consent decrees. The alleged modifications at our power plants occurred over a 20-year period. A bench trial on the liability issues was held during July 2005. Briefing has concluded. In June 2006, the judge stayed the liability decision pending the issuance of a decision by the U.S. Supreme Court in the Duke Energy case. A bench trial on remedy issues, if necessary, is scheduled to begin four months after the U.S. Supreme Court decision is issued.

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

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

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.

Other Environmental Concerns

We perform environmental reviews and audits on a regular basis for the purpose of identifying, evaluating and addressing environmental concerns and issues. In addition to the matters discussed above, we manage other environmental concerns that we do not believe are material or potentially material at this time. If they become significant or if any new matters arise that we believe could be material, they could have a material adverse effect on future results of operations, cash flows and possibly financial condition.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2005 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

Beginning in 2006, we adopted SFAS No. 123 (revised 2004) Share-Based Payment, on a modified prospective basis, resulting in an insignificant favorable cumulative effect of a change in accounting principle. Including stock-based compensation expense related to employee stock options and other share based awards, did not materially affect our quarter-over-quarter and year-to-date net income and earnings per share. As of June 30, 2006, we have $43 million of total unrecognized compensation cost related to unvested share-based compensation arrangements. Our unrecognized compensation cost will be recognized over a weighted-average period of 1.63 years. See Note 2 - New Accounting Pronouncements in our Condensed Notes to Condensed Consolidated Financial Statements for further discussion.

 


QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

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

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

We employ risk management contracts including physical forward purchase and sale contracts, exchange futures and options, over-the-counter options, swaps and other derivative contracts to offset price risk where appropriate. We engage in risk management of electricity, gas, coal, and emissions and to a lesser degree other commodities associated with our energy business. As a result, we are subject to price risk. The amount of risk taken is controlled by risk management operations, our Chief Risk Officer and risk management staff. When risk management activities exceed certain predetermined limits, the positions are modified to reduce the risk to be within the limits unless specifically approved by the Risk Executive Committee.

We have 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 various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. Our committee meets monthly and consists of the Chief Risk Officer, senior executives, and other 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 applicable to our business activities. The following tables provide information on our risk management activities.

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

The following two tables summarize the various mark-to-market (MTM) positions included in our condensed balance sheet as of June 30, 2006 and the reasons for changes in our total MTM value included in our condensed balance sheet as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
June 30, 2006
(in millions)

 
Utility Operations
 
Investments - Gas Operations
 
Sub-Total MTM Risk Management Contracts
 
PLUS: MTM of Cash Flow and Fair Value Hedges
 
Total
 
Current Assets
$
431
 
$
123
 
$
554
 
$
65
 
$
619
 
Noncurrent Assets
 
390
 
 
175
 
 
565
 
 
12
 
 
577
 
Total Assets
 
821
 
 
298
 
 
1,119
 
 
77
 
 
1,196
 
                               
Current Liabilities
 
(338
)
 
(126
)
 
(464
)
(16
)
 
(480
)
Noncurrent Liabilities
 
(235
)
 
(181
)
 
(416
)
 
(2
)
 
(418
)
Total Liabilities
 
(573
)
 
(307
)
 
(880
)
 
(18
)
 
(898
)
                               
Total MTM Derivative Contract Net
  Assets (Liabilities)
$
248
 
$
(9
)
$
239
 
$
59
 
$
298
 


MTM Risk Management Contract Net Assets (Liabilities)
Six Months Ended June 30, 2006
(in millions)

   
Utility Operations
 
Investments-Gas Operations
 
Total
 
Total MTM Risk Management Contract Net Assets (Liabilities) at
   December 31, 2005
 
$
215
 
$
(19
)
$
196
 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior
   Period
   
(8
)
 
8
   
-
 
Fair Value of New Contracts at Inception When Entered During the Period (a)
   
1
   
-
   
1
 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts
   Entered During The Period
   
13
   
-
   
13
 
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts
   
1
   
-
   
1
 
Changes in Fair Value due to Market Fluctuations During the Period (b)
   
13
   
2
   
15
 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
   
13
   
-
   
13
 
Total MTM Risk Management Contract Net Assets (Liabilities) at
   June 30, 2006
 
$
248
 
$
(9
)
 
239
 
Net Cash Flow and Fair Value Hedge Contracts
               
59
 
Ending Net Risk Management Assets at June 30, 2006
             
$
298
 

(a)
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.
(b)
Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)
“Change in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Operations. These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions. Approximately $7 million of the regulatory deferral change is due to the change in the SIA. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

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

The following table presents:

·
The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
·
The maturity, by year, of our net assets/liabilities, 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, 2006
(in millions)

   
 Remainder
2006
 
2007
 
2008
 
2009
 
2010
 
After 2010
 
Total
 
Utility Operations:
                                    
Prices Actively Quoted -  Exchange Traded Contracts
 
$
(11
)
$
1
 
$
14
 
$
-
 
$
-
 
$
-
 
$
4
 
Prices Provided by Other External Sources - OTC Broker Quotes (a)
   
43
   
68
   
33
   
25
   
-
   
-
   
169
 
Prices Based on Models and Other Valuation Methods (b)
   
20
   
(1
)
 
6
   
13
   
28
   
9
   
75
 
Total
 
$
52
 
$
68
 
$
53
 
$
38
 
$
28
 
$
9
 
$
248
 
                                             
Investments - Gas Operations:
                                           
Prices Actively Quoted -  Exchange Traded Contracts
 
$
(1
)
$
11
 
$
-
 
$
-
 
$
-
 
$
-
 
$
10
 
Prices Provided by Other External Sources - OTC Broker Quotes (a)
   
(3
)
 
(8
)
 
-
   
-
   
-
   
-
   
(11
)
Prices Based on Models and Other Valuation Methods (b)
   
(1
)
 
-
   
(1
)
 
(4
)
 
(3
)
 
1
   
(8
)
Total
 
$
(5
)
$
3
 
$
(1
)
$
(4
)
$
(3
)
$
1
 
$
(9
)
                                             
Total:
                                           
Prices Actively Quoted -  Exchange Traded Contracts
 
$
(12
)
$
12
 
$
14
 
$
-
 
$
-
 
$
-
 
$
14
 
Prices Provided by Other External Sources - OTC Broker Quotes (a)
   
40
   
60
   
33
   
25
   
-
   
-
   
158
 
Prices Based on Models and Other Valuation Methods (b)
   
19
   
(1
)
 
5
   
9
   
25
   
10
   
67
 
Total
 
$
47
 
$
71
 
$
52
 
$
34
 
$
25
 
$
10
 
$
239
 

(a)
Prices Provided by Other External Sources - OTC Broker Quotes reflects information obtained from over-the-counter (OTC) brokers, 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.
   
 
Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available.
 
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, 2006

Commodity
 
Transaction Class
 
Market/Region
 
Tenor
           
(in Months)
Natural Gas
 
Futures
 
NYMEX / Henry Hub
 
60
             
   
Physical Forwards
 
Gulf Coast, Texas
 
21
             
   
Swaps
 
Northeast, Mid-Continent, Gulf  Coast, Texas
 
21
             
   
Exchange Option Volatility
 
NYMEX / Henry Hub
 
12
             
Power
 
Futures
 
AEP East - PJM
 
36
             
   
Physical Forwards
 
AEP East
 
42
             
   
Physical Forwards
 
AEP West
 
42
             
   
Physical Forwards
 
West Coast
 
42
             
   
Peak Power Volatility (Options)
AEP East - Cinergy, PJM
 
12
             
Emissions
 
Credits
 
SO2, NOx
 
30
             
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 remaining 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 derivative transactions to manage interest rate risk related to existing variable rate debt and to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate exposure.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for changes in cash flow hedges from December 31, 2005 to June 30, 2006. The following table also indicates what portion of designated, effective hedges are expected to be reclassified into net income in the next 12 months. Only contracts designated as effective cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and are included in the previous risk management tables.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
Six Months Ended June 30, 2006
(in millions)

   
 Power and Gas
 
 Interest Rate
 
 Total
 
Beginning Balance in AOCI, December 31, 2005
 
$
(6
)
$
(21
)
$
(27
)
Changes in Fair Value
   
37
   
12
   
49
 
Reclassifications from AOCI to Net Income for Cash Flow
   Hedges Settled
   
3
   
2
   
5
 
Ending Balance in AOCI, June 30, 2006
 
$
34
 
$
(7
)
$
27
 
                     
After-Tax Portion Expected to be Reclassified to
   Earnings During Next 12 Months
 
$
30
 
$
(1
)
$
29
 

Credit Risk

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

We have risk management contracts with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily. As of June 30, 2006, our credit exposure net of credit collateral to sub investment grade counterparties was approximately 5.90%, expressed in terms of net MTM assets and net receivables. As of June 30, 2006, 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
 
$
883
 
$
156
 
$
727
   
1
 
$
107
 
Split Rating
   
2
   
-
   
2
   
2
   
2
 
Noninvestment Grade
   
109
   
106
   
3
   
1
   
3
 
No External Ratings:
                               
Internal Investment Grade
   
28
   
-
   
28
   
1
   
10
 
Internal Noninvestment Grade
   
58
   
13
   
45
   
3
   
43
 
Total as of June 30, 2006
 
$
1,080
 
$
275
 
$
805
   
8
 
$
165
 
                                 
As of December 31, 2005   $ 1,366   $ 484   $ 882     10     322  

Generation Plant Hedging Information

This table provides information on operating measures regarding the proportion of output of our generation facilities (based on economic availability projections) economically hedged, including both contracts designated as cash flow hedges under SFAS 133 and contracts not designated as cash flow hedges. This information is forward-looking and provided on a prospective basis through December 31, 2008. This table is a point-in-time estimate, subject to changes in market conditions and our decisions on how to manage operations and risk. “Estimated Plant Output Hedged” represents the portion of MWHs of future generation/production, taking into consideration scheduled plant outages, for which we have sales commitments or estimated requirement obligations to customers.

Generation Plant Hedging Information
Estimated Next Three Years
As of June 30, 2006

   
Remainder
2006
 
2007
 
2008
Estimated Plant Output Hedged
 
91%
 
90%
 
88%

VaR Associated with Risk Management Contracts

Commodity Price Risk

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at June 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

The following table shows the end, high, average, and low market risk as measured by VaR for the periods indicated:

VaR Model

Six Months Ended
June 30, 2006
       
Twelve Months Ended
December 31, 2005
(in millions)
       
(in millions)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
$2
 
$7
 
$3
 
$1
       
$3
 
$5
 
$3
 
$1

Interest Rate Risk

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The volatilities and correlations were based on three years of daily prices. The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $690 million at June 30, 2006 and $615 million at December 31, 2005. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not materially affect our results of operations, cash flows or financial position.


 


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three and Six Months Ended June 30, 2006 and 2005
(in millions, except per-share amounts)
(Unaudited)

   
Three Months Ended
 
Six Months Ended
 
   
2006
 
2005
 
2006
 
2005
 
REVENUES
                   
Utility Operations
 
$
2,810
 
$
2,680
 
$
5,797
 
$
5,285
 
Gas Operations
   
(15
)
 
19
   
(33
)
 
376
 
Other
   
141
   
120
   
280
   
223
 
TOTAL
   
2,936
   
2,819
   
6,044
   
5,884