mabaird@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 March 31, 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, 2005, the last trading date of the registrants’ most recently completed second fiscal quarter
 
 
 
Number of shares of common stock outstanding of the registrants at
April 28, 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.
 
$14,172,701,867
 
393,914,882
       
($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
March 31, 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 5.
Other Information
   
 
Item 6.
Exhibits:
   
       
Exhibit 12
     
       
Exhibit 31(a)
     
       
Exhibit 31(b)
     
       
Exhibit 31(c)
     
       
Exhibit 31(d)
     
       
Exhibit 32(a)
     
       
Exhibit 32(b)
     
               
SIGNATURE
     
 
This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.





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

 
Term
 
 
Meaning

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.
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

Regulatory Activity

Our significant regulatory activity progressed with the following major developments:

·
In January 2006, we implemented our Ohio Rate Stabilization Plans, resulting in increased revenues of $49 million for the three months ended March 31, 2006. 
·
The Kentucky Public Service Commission approved our $41 million rate case settlement agreement. New rates became effective on March 30, 2006.
·
In March 2006, after the February 2006 receipt of an order in our Texas stranded costs proceeding, we filed with the Public Utility Commission of Texas (PUCT) for approval of a financing order to issue $1.8 billion in securitization bonds. We expect an order in June or July 2006.
·
In April 2006, the Public Utilities Commission of Ohio (PUCO) approved our recovery of the pre-construction costs for the Integrated Gasification Combined Cycle (IGCC) clean-coal plant in Meigs County, Ohio. The PUCO also ruled that it is reasonable to recover the pre-construction costs of the facility through a provider of last resort recovery mechanism. We subsequently submitted tariffs for PUCO approval related to recovery of our IGCC pre-construction costs.
·
In April 2006, we reached a tentative settlement in our APCo and WPCo rate case, subject to approval by the Public Service Commission of West Virginia, providing for a $44 million increase in rates effective July 28, 2006.
·
In May 2006, we filed a base rate case in Virginia requesting a net rate increase of $198 million.

Our near-term additional activity includes:

·
A TCC competition transition charge (CTC) filing with the PUCT in the second quarter to address a $491 million credit to customers from the True-up Proceeding.
·
Issuance of securitization bonds in Texas in the third quarter of 2006.

Fuel Costs

Market prices for coal, natural gas and oil continued increasing in the first quarter of 2006. These increasing fuel costs result from increasing worldwide demand, supply interruptions and uncertainty, anticipation and ultimate promulgation of clean air rules, transportation constraints and other market factors. We manage price and performance risk through a portfolio of contracts of varying durations and other fuel procurement and management activities. Fuel recovery mechanisms exist for about 55% of our fuel costs in our various jurisdictions. Additionally, about 25% of our fuel is used for off-system sales where prices for our power should allow us to recover our cost of fuel. Accordingly, we should recover approximately 80% of fuel cost increases. The remaining 20% of our fuel costs relate primarily to Ohio customers, where fuel is a fixed component of costs included in our rates, but we do not have an active fuel cost recovery adjustment mechanism. Such percentages are subject to change over time based on fuel cost impacts and changes to the recovery adjustment mechanisms at jurisdictions in our individual operating companies. 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 currently expect under recoveries during 2006 and under-recovered $4 million for the quarter ended March 31, 2006. In West Virginia, we received permission to begin deferral accounting for over- or under-recovery of fuel and related costs effective July 1, 2006. In addition, our Ohio companies increased their generation rates in 2006, as previously approved by the PUCO in our Rate Stabilization Plans. While these items should help to offset some of the negative impact on our gross margins, we expect an additional eleven to thirteen percent increase in coal costs in 2006.
 
RESULTS OF OPERATIONS

Segments

Our principal operating business segments and their major activities were:

·
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 months ended March 31, 2006 and 2005 were as follows (Earnings and Weighted Average Basic Shares Outstanding in millions):

   
2006
 
2005
 
   
Earnings
 
EPS (c)
 
Earnings
 
EPS (c)
 
Utility Operations
 
$
365
 
$
0.93
 
$
353
 
$
0.90
 
Investments - Other
   
16
   
0.04
   
5
   
0.01
 
All Other (a)
   
(2
)
 
(0.01
)
 
(14
)
 
(0.04
)
Investments - Gas Operations (b)
   
(1
)
 
-
   
10
   
0.03
 
Income Before Discontinued Operations
 
$
378
 
$
0.96
 
$
354
 
$
0.90
 
                           
Weighted Average Basic Shares Outstanding
         
394
         
393
 

(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.
 

First Quarter of 2006 Compared to First Quarter of 2005

Income Before Discontinued Operations in 2006 increased $24 million compared to 2005 due to increased utility operations revenue primarily related to rate increases in our Ohio jurisdiction as approved by the PUCO in CSPCo’s and OPCo’s Rate Stabilization Plans (RSP).

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
March 31,
 
   
2006
 
2005
 
   
(in millions)
 
Revenues
 
$
2,969
 
$
2,684
 
Fuel and Purchased Energy
   
1,127
   
923
 
Gross Margin
   
1,842
   
1,761
 
Depreciation and Amortization
   
333
   
318
 
Other Operating Expenses
   
846
   
805
 
Operating Income
   
663
   
638
 
Other Income (Expense), Net
   
42
   
30
 
Interest Expense and Preferred Stock Dividend Requirements
   
154
   
144
 
Income Tax Expense
   
186
   
171
 
Income Before Discontinued Operations
 
$
365
 
$
353
 

Summary of Selected Sales and Weather Data
For Utility Operations
For the Three Months Ended March 31, 2006 and 2005

   
2006
 
2005
 
Energy Summary
 
(in millions of KWH)
 
Retail:
         
Residential
   
12,938
   
13,224
 
Commercial
   
8,909
   
8,732
 
Industrial
   
13,221
   
12,774
 
Miscellaneous
   
589
   
645
 
Subtotal
   
35,657
   
35,375
 
Texas Retail and Other
   
68
   
228
 
Total     35,725     35,603  
               
Wholesale
   
10,844
   
12,635
 
               
Texas Wires Delivery
   
5,546
   
5,519
 
 
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. Cooling degree days and heating degree days in our service territory for the quarters ended March 31, 2006 and 2005 were as follows:

   
2006
 
2005
   
Weather Summary
 
(in degree days)
 
Eastern Region
           
Actual - Heating (a)
 
1,456
 
1,774
   
Normal - Heating (b)
 
1,817
 
1,811
   
             
Actual - Cooling (c)
 
1
 
-
   
Normal - Cooling (b)
 
3
 
3
   
             
Western Region (d)
           
Actual - Heating (a)
 
658
 
769
   
Normal - Heating (b)
 
972
 
973
   
             
Actual - Cooling (c)
 
43
 
20
   
Normal - Cooling (b)
 
17
 
18
   
     
(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.
   

First Quarter of 2006 Compared to First Quarter of 2005

Reconciliation of First Quarter of 2005 to First Quarter of 2006
Income from Utility Operations Before Discontinued Operations
(in millions)

First Quarter of 2005
       
$
353
 
               
Changes in Gross Margin:
             
Retail Margins
   
111
       
Off-system Sales
   
(24
)
     
Other
   
(6
)
     
Total Change in Gross Margin
         
81
 
               
Changes in Operating Expenses and Other:
             
Maintenance and Other Operation
   
6
       
Gain on Sales of Assets, Net
   
(46
)
     
Depreciation and Amortization
   
(15
)
     
Taxes Other Than Income Taxes
   
(1
)
     
Other Income (Expense), Net
   
12
       
Interest and Other Charges
   
(10
)
     
Total Change in Operating Expenses and Other
         
(54
)
               
Income Tax Expense
         
(15
)
               
First Quarter of 2006
       
$
365
 

Income from Utility Operations Before Discontinued Operations increased $12 million to $365 million in 2006. The key driver of the increase was an $81 million net increase in Gross Margin, offset in part by a $54 million increase in Operating Expenses and Other and a $15 million increase in Income Tax Expense.
 
The major components of the net increase in Gross Margin were as follows:

·
Retail Margins increased $111 million primarily due to the following:
·     
A $49 million increase related to new rates implemented in our Ohio jurisdiction as approved by the PUCO in our RSPs;
·     
A $28 million increase related to increased usage and customer growth in the industrial and commercial classes;
·     
An $11 million increase related to increased usage and customer growth in the residential class; and
·     
A $26 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 $25 million decrease in usage related to mild weather. As compared to the prior year, heating degree days were 18% lower in the east and 14% lower in the west.
·
Margins from Off-system Sales for 2006 were $24 million lower than in 2005 due to lower volumes in part from the sale of STP in May 2005 and lower optimization activities.
·
Other revenues decreased $6 million primarily due to a decrease in construction activities performed for third parties.

Utility Operating Expenses and Other changed between years as follows:

·
Maintenance and Other Operation expenses decreased $6 million primarily due to a decrease in construction activities performed for third parties.
·
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 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 $15 million primarily due to increased Ohio and Texas regulatory asset amortization.
·
Other Income (Expense), Net increased $12 million primarily due to capitalized carrying costs on environmental and system reliability capital expenditures for APCo. APCo began capitalizing carrying costs in conjunction with its environmental and reliability costs filing in Virginia in the third quarter of 2005.
·
Interest and Other Charges increased $10 million from the prior period primarily due to new debt issued during 2005 and increasing interest rates.
·
Income Tax Expense increased $15 million due to the increase in pretax income. See “AEP System Income Taxes” section below for further discussion of fluctuations related to income taxes.

Investments - Other

First Quarter of 2006 Compared to First Quarter of 2005

Income Before Discontinued Operations from our Investments - Other segment increased from $5 million in 2005 to $16 million in 2006. The increase was primarily due to favorable barging activity at AEP MEMCO LLC due to strong demand and a tight supply of barges which increased the barge fees. 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

First Quarter of 2006 Compared to First Quarter of 2005

The parent company’s loss decreased $12 million from 2005 primarily due to lower interest expense related to the redemption of $550 million senior unsecured notes in April 2005 and increased affiliated interest income related to favorable results from the corporate borrowing program.
 
Investments - Gas Operations

First Quarter of 2006 Compared to First Quarter of 2005

The $1 million Loss Before Discontinued Operations compares with $10 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 primarily relate to gas contracts that were not sold with the gas pipeline and storage assets.

AEP System Income Taxes

The increase in income tax expense of $17 million between the first quarter of 2006 and first quarter of 2005 is primarily due to an increase in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis.

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)

   
March 31, 2006
 
December 31, 2005
 
Common Equity
 
$
9,384
   
43.0
%
$
9,088
   
42.5
%
Preferred Stock
   
61
   
0.3
   
61
   
0.3
 
Long-term Debt, including amounts due within one year
   
12,142
   
55.7
   
12,226
   
57.2
 
Short-term Debt
   
226
   
1.0
   
10
   
0.0
 
                           
Total Debt and Equity Capitalization
 
$
21,813
   
100.0
%
$
21,385
   
100.0
%

Our common equity increased primarily due to earnings exceeding the amount of dividends paid in 2006. As a consequence of the capital changes during 2006, we improved our ratio of total debt to total capital from 57.2% to 56.7%.

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. We cannot predict the ultimate effects of the final rule or its effective date.
 
Liquidity

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

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments. At March 31, 2006, our available liquidity was approximately $2.7 billion as illustrated in the table below:
 
Amount
 
Maturity
 
(in millions)
   
Commercial Paper Backup:
       
 
Revolving Credit Facility
$
1,000
 
May 2007
 
Revolving Credit Facility
 
1,500
 
March 2010
Letter of Credit Facility
 
200
 
September 2006
Total
 
2,700
   
Cash and Cash Equivalents
 
276
   
Total Liquidity Sources
 
2,976
   
Less: AEP Commercial Paper Outstanding
 
215
   
 
Letter of Credit Drawn on Credit Facility
 
31
   
Net Available Liquidity
$
2,730
   
 
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, with an option in each to issue up to $200 million as letters of credit, expiring separately in March 2010 and April 2011. We also terminated an existing $200 million letter of credit facility. If the amendments had occurred prior to March 31, 2006 our Net Available Liquidity would have been $3,030 million.

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 March 31, 2006, this contractually-defined percentage was 53.6%. Nonperformance of these covenants could result in an event of default under these credit agreements. At March 31, 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.

We do not believe that our rights under the amended facilities would be affected by a material adverse change.

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 March 31, 2006, all utility subsidiaries were in compliance with this order.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders. At March 31, 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

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

   
Three Month Ended
March 31,
 
   
2006
 
2005
 
   
(in millions)
 
Cash and Cash Equivalents at Beginning of Period
 
$
401
 
$
320
 
Net Cash Flows From Operating Activities
   
590
   
667
 
Net Cash Flows From (Used For) Investing Activities
   
(757
)
 
842
 
Net Cash Flows From (Used For) Financing Activities
   
42
   
(568
)
Net Increase (Decrease) in Cash and Cash Equivalents
   
(125
)
 
941
 
Cash and Cash Equivalents at End of Period
 
$
276
 
$
1,261
 

Cash from operations, combined with a bank-sponsored receivables purchase agreement and short-term borrowings, provides working capital and allows us to meet other short-term cash needs. We use our corporate borrowing program to meet the short-term borrowing needs of our subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries. In addition, we also fund, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of March 31, 2006, we had credit facilities totaling $2.5 billion to support our commercial paper program. In April 2006, we increased our credit facilities to $3 billion. 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.

Operating Activities

   
Three Months Ended
March 31,
 
   
2006
 
2005
 
   
(in millions)
 
Net Income
 
$
381
 
$
355
 
Less: Income From Discontinued Operations
   
(3
)
 
(1
)
Income From Continuing Operations
   
378
   
354
 
Noncash Items Included in Earnings
   
317
   
325
 
Changes in Assets and Liabilities
   
(105
)
 
(12
)
Net Cash Flows From Operating Activities
 
$
590
 
$
667
 
 
2006 Operating Cash Flow

Net Cash Flows From Operating Activities were $590 million in 2006. We produced Income from Continuing Operations of $378 million. Income from Continuing Operations included noncash expense items primarily for depreciation, amortization, accretion, deferred taxes and deferred investment tax credits. In 2005, we initiated fuel proceedings in Oklahoma, Texas, Virginia and Arkansas seeking recovery of our increased fuel costs. Under-recovered fuel costs decreased due to recovery of higher cost of fuel, especially natural gas. Other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in these asset and liability accounts relates to a number of items; the most significant are a $99 million cash increase from net Accounts Receivable/Accounts Payable due to a lower balance of Customer Accounts Receivable at March 31, 2006 and an increase in Accrued Taxes of $176 million. We did not make a federal income tax payment during the first quarter of 2006.

2005 Operating Cash Flow

Net Cash Flows From Operating Activities were $667 million in 2005 consisting of our Income from Continuing Operations of $354 million and noncash charges of $327 million for Depreciation and Amortization. We realized gains of $115 million on sales of assets. 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 is a $245 million increase in Accrued Taxes. We did not make a federal income tax payment during the first quarter of 2005.

Investing Activities

   
Three Months Ended
March 31,
 
   
2006
 
2005
 
   
(in millions)
 
Construction Expenditures
 
$
(772
)
$
(434
)
Change in Other Temporary Cash Investments, Net
   
27
   
(9
)
Investment Securities:
             
Purchases of Investment Securities
   
(2,469
)
 
(1,311
)
Sales of Investment Securities
   
2,380
   
1,396
 
Change in Investment Securities, Net
   
(89
)
 
85
 
Proceeds from Sales of Assets
   
111
   
1,184
 
Other
   
(34
)
 
16
 
Net Cash Flows From (Used for) Investing Activities
 
$
(757
)
$
842
 

Net Cash Flows Used For Investing Activities were $757 million in 2006 primarily due to Construction Expenditures. Construction Expenditures increased due to our environmental investment plan.

During 2006, we purchased $2.5 billion of investments and received $2.4 billion of proceeds from the sales of securities. During 2005, we purchased $1.3 billion of investments and received $1.4 billion of proceeds from the sales of securities. 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 $842 million in 2005 primarily due to the proceeds from the sale of HPL. During 2005, we sold HPL and used a portion of the proceeds from the sale to repurchase common stock. Our Construction Expenditures of $434 million included environmental, transmission and distribution investment.

We forecast $2.9 billion of Construction Expenditures for the remainder of 2006. Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, and the ability to access capital. These construction expenditures will be funded through results of operations and financing activities.

Financing Activities

   
Three Months Ended
March 31,
 
   
2006
 
2005
 
   
(in millions)
 
Issuance of Common Stock
 
$
5
 
$
17
 
Repurchase of Common Stock
   
-
   
(434
)
Issuance/Retirement of Debt, Net
   
129
   
65
 
Dividends Paid on Common Stock
   
(146
)
 
(138
)
Other
   
54
   
(78
)
Net Cash Flows From (Used for) Financing Activities
 
$
42
 
$
(568
)

Net Cash Flows From Financing Activities in 2006 were $42 million. During the first quarter of 2006, we issued $50 million of obligations relating to pollution control bonds and increased our short-term commercial paper outstanding. See Note 12 for a complete discussion of long-term debt issuances and retirements. The Other amount of $54 million in the above table primarily consists of $68 million received from a coal supplier related to a long-term coal purchase contract amended in March 2006.

Net Cash Flows Used For Financing Activities in 2005 were $568 million. During the first quarter 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.

In April 2006, APCo issued $500 million of debt consisting of $250 million of 5.55% notes due 2011 and $250 million of 6.375% notes due 2036. Also in April, OPCo issued obligations relating to auction rate pollution control bonds in the amount of $65 million. The new bonds bear variable interest at a 28-day auction rate. The proceeds from this issuance will contribute to our investment in environmental equipment.

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 off-balance sheet arrangements have not changed significantly from year-end. 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

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 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, is capped at $20 million and, to the extent payable, will be paid in the first quarter of 2007. See “Texas REPs” section of Note 8.
 
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.

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, which included carrying costs through September 2005. TCC filed an application in March 2006 requesting to securitize $1.8 billion of net stranded generation plant costs and related carrying costs to September 1, 2006. The $1.8 billion does not include TCC’s other true-up items, which are partially offsetting in nature. These obligations total $491 million and would be payable through a CTC over a period determined by the PUCT. Intervenors and the PUCT staff filed testimony in April 2006. Hearings are scheduled for May. It is possible that the PUCT could reduce the securitization amount by all or some portion of the negative other true-up items. If that occurs, a negative impact on the timing of cash flows could result. Cash flows from securitization would be adversely impacted if the PUCT reduces TCC’s computation of the amount to be securitized in the securitization proceeding.

The PUCT has not addressed the allocation of stranded costs to TCC’s wholesale jurisdiction. TCC estimates the amount allocated to wholesale to be less than $1 million, while intervenors and PUCT staff filed testimony recommending that $77 million of stranded costs be allocated to TCC’s wholesale jurisdiction. TCC cannot predict the ultimate amount the PUCT will allocate to the wholesale jurisdiction that TCC will not be able to securitize or recover.

Consistent with certain prior securitization determinations, the PUCT may deduct the cost-of-money benefit of accumulated deferred federal income taxes (ADFIT) from the securitization request. Then, the future cost-of-money benefit would be transferred to a separate regulatory asset recoverable in normal delivery rates outside of the securitization process, which would affect the timing of cash recovery. We estimate the total cost-of-money benefit to be $328 million, which TCC plans to include in its estimated CTC request. Intervenors filed testimony recommending an increase in this amount, along with the retrospective ADFIT amounts, by as much as $175 million.

In addition, the intervenors raised three issues totaling $138 million that were addressed by the PUCT in prior proceedings - the appropriate interest rate for both stranded cost and deferred fuel and the treatment of excess earnings refunds. Other issues raised by the intervenors dealt with the amounts to be securitized versus refunded to customers through the CTC, customer class allocation issues and debt defeasance strategies.

The difference between the recorded securitizable true-up regulatory asset of $1.5 billion at March 31, 2006 and our securitization request of $1.8 billion is detailed in the table below:

   
(in millions)
 
Stranded Generation Plant Costs
 
$
969
 
Net Generation-related Regulatory Asset
   
249
 
Excess Earnings
   
(49
)
Recorded Net Stranded Generation Plant Costs
   
1,169
 
Recorded Debt Carrying Costs on Recorded Net Stranded Generation Plant Costs
   
284
 
Recorded Securitizable True-up Regulatory Asset
   
1,453
 
Unrecorded But Recoverable Equity Carrying Costs
   
212
 
Unrecorded Estimated April 2006 - August 2006 Debt Carrying Costs
   
40
 
Unrecorded Securitization Issuance Costs
   
24
 
Unrecorded Excess Earnings, Related Return and Other
   
75
 
Securitization Request
 
$
1,804
 

The principal components of the CTC rate reduction are an over-recovered fuel balance, the retail clawback and the ADFIT benefit related to TCC’s stranded generation cost, offset by a positive wholesale capacity auction true-up regulatory asset balance. TCC will incur carrying costs on the net negative other true-up regulatory liability balances until fully refunded. TCC anticipates filing to implement a negative CTC (as a rate reduction) for its net other true-up items in the second quarter of 2006.

The difference between the components of TCC’s recorded net regulatory liabilities - other true-up items as of March 31, 2006 and the amount expected to be requested in the CTC proceeding are detailed below:

   
(in millions)
 
Wholesale Capacity Auction True-up
 
$
61
 
Carrying Costs on Wholesale Capacity Auction True-up
   
17
 
Retail Clawback
   
(61
)
Deferred Over-recovered Fuel Balance
   
(177
)
Recorded Net Regulatory Liabilities - Other True-up Items
   
(160
)
ADFIT Benefit
   
(328
)
Unrecorded Carrying Costs and Other
   
(3
)
Estimated CTC Request
 
$
(491
)

If we determine in future securitization and CTC proceedings 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 such nonrecovery, we would record a provision for such amount which could have an adverse effect on future results of operations, cash flows and possibly financial condition. TCC intends to pursue rehearing and appeals to vigorously seek relief as necessary in both federal and state court where it believes the PUCT’s rulings are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law. It is expected that the cities and other intervenors will also pursue vigorously court appeals to further reduce TCC’s true-up recoveries. Although TCC believes it has meritorious arguments, management cannot predict the ultimate outcome of any future proceedings, requested rehearings or court appeals. If the municipal customers and other intervenors succeed in their expected appeals, it could have a material adverse effect on future results of operations, cash flows and financial condition.

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 Clean Air Act (CAA) to reduce emissions of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter (PM), and mercury from fossil fuel-fired power plants;
·
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” or 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 reconsidered and affirmed certain aspects of the final CAIR, and 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 is currently reconsidering certain aspects of the final CAMR, 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 are the subject of reconsideration by the Federal EPA, have been challenged in the courts and have not yet been incorporated into SIPs. As a result, these rules may be further modified. Our estimates 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 has 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. A petition to appeal to the U.S. Supreme Court has been filed. While mandatory requirements to reduce CO2 emissions at our power plants do not appear to be 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 special interest 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. 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 been completed, but no decision has been issued. A bench trial on remedy issues is scheduled for January 2007.

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 have been filed in certain appellate courts, including a petition to appeal to the U.S. Supreme Court 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 and the Federal EPA filed a petition for rehearing in that case. The Federal EPA also recently proposed a rule that would define “emissions increases” in a way that most of the challenged activities would be excluded 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 are managing 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, the trend in our quarter-over-quarter net income and earnings per share is not materially different. As of March 31, 2006, we have $46 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 1.67 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, because we procure some services and materials in our energy business from foreign suppliers we have foreign currency risk.  They represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

Our Investment - Gas Operations segment holds forward gas contracts that were not sold with the gas pipeline and storage assets. These contracts are primarily financial derivatives, along with some physical contracts, which will gradually liquidate and completely expire in 2011. Our risk objective and outcomes to-date keep these positions 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 and our Chief Risk Officer and risk management staff. When risk management activities exceed certain predetermined limits, the positions are modified or hedged 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 are 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 March 31, 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
March 31, 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
$
437
 
$
134
 
$
571
 
$
54
 
$
625
 
Noncurrent Assets
 
449
 
 
199
 
 
648
 
 
7
 
 
655
 
Total Assets
 
886
 
 
333
 
 
1,219
 
 
61
 
 
1,280
 
                               
Current Liabilities
 
(379
)
 
(139
)
 
(518
)
(21
)
 
(539
)
Noncurrent Liabilities
 
(293
)
 
(204
)
 
(497
)
 
(3
)
 
(500
)
Total Liabilities
 
(672
)
 
(343
)
 
(1,015
)
 
(24
)
 
(1,039
)
                               
Total MTM Derivative Contract Net
  Assets (Liabilities)
$
214
 
$
(10
)
$
204
 
$
37
 
$
241
 
 
 
MTM Risk Management Contract Net Assets (Liabilities)
Three Months Ended March 31, 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
   
(5
)
 
7
   
2
 
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
   
(4
)
 
-
   
(4
)
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)
   
8
   
2
   
10
 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
   
(2
)
 
-
   
(2
)
Total MTM Risk Management Contract Net Assets (Liabilities) at March 31, 2006
 
$
214
 
$
(10
)
 
204
 
Net Cash Flow and Fair Value Hedge Contracts
               
37
 
Ending Net Risk Management Assets at March 31, 2006
             
$
241
 

(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.
 
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 March 31, 2006
(in millions)

   
 Remainder 2006
 
2007
 
2008
 
2009
 
2010
 
After 2010
 
Total
 
Utility Operations:
                                    
Prices Actively Quoted -  Exchange Traded Contracts
 
$
38
 
$
(1
)
$
3
 
$
-
 
$
-
 
$
-
 
$
40
 
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)
   
13
   
39
   
28
   
23
   
-
   
-
   
103
 
Prices Based on Models and Other Valuation Methods (b)
   
(7
)
 
17
   
14
   
14
   
29
   
4
   
71
 
Total
 
$
44
 
$
55
 
$
45
 
$
37
 
$
29
 
$
4
 
$
214
 
                                             
Investments - Gas Operations:
                                           
Prices Actively Quoted -  Exchange Traded Contracts
 
$
(3
)
$
12
 
$
-
 
$
-
 
$
-
 
$
-
 
$
9
 
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)
   
(1
)
 
(9
)
 
-
   
-
   
-
   
-
   
(10
)
Prices Based on Models and Other Valuation Methods (b)
   
(2
)
 
-
   
(1
)
 
(4
)
 
(3
)
 
1
   
(9
)
Total
 
$
(6
)
$
3
 
$
(1
)
$
(4
)
$
(3
)
$
1
 
$
(10
)
                                             
Total:
                                           
Prices Actively Quoted -  Exchange Traded Contracts
 
$
35
 
$
11
 
$
3
 
$
-
 
$
-
 
$
-
 
$
49
 
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)
   
12
   
30
   
28
   
23
   
-
   
-
   
93
 
Prices Based on Models and Other Valuation Methods (b)
   
(9
)
 
17
   
13
   
10
   
26
   
5
   
62
 
Total
 
$
38
 
$
58
 
$
44
 
$
33
 
$
26
 
$
5
 
$
204
 

(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.
 
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 March 31, 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
 
45
   
Physical Forwards
 
AEP West
 
45
   
Physical Forwards
 
West Coast
 
45
   
Peak Power Volatility (Options)
AEP East - Cinergy, PJM
 
12
Emissions
 
Credits
 
SO2, NOx
 
33
Coal
 
Physical Forwards
 
PRB, NYMEX, CSX
 
33

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 March 31, 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
Three Months Ended March 31, 2006
(in millions)

   
 Power and Gas
 
 Interest Rate
 
 Total
 
Beginning Balance in AOCI, December 31, 2005
 
$
(6
)
$
(21
)
$
(27
)
Changes in Fair Value
   
22
   
9
   
31
 
Reclassifications from AOCI to Net Income for Cash Flow Hedges
  Settled
   
3
   
1
   
4
 
Ending Balance in AOCI, March 31, 2006
 
$
19
 
$
(11
)
$
8
 
                     
After Tax Portion Expected to be Reclassified to Earnings
  During Next 12 Months
 
$
18
 
$
(1
)
$
17
 

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 March 31, 2006, our credit exposure net of credit collateral to sub investment grade counterparties was approximately 3.13%, expressed in terms of net MTM assets and net receivables. As of March 31, 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
 
$
807
 
$
145
 
$
662
   
1
 
$
87
 
Split Rating
   
4
   
2
   
2
   
2
   
2
 
Noninvestment Grade
   
134
   
125
   
9
   
1
   
8
 
No External Ratings:
                               
Internal Investment Grade
   
85
   
-
   
85
   
1
   
64
 
Internal Noninvestment Grade
   
32
   
17
   
15
   
2
   
14
 
Total
 
$
1,062
 
$
289
 
$
773
   
7
 
$
175
 
 
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. Please note that this table is a point-in-time estimate, subject to changes in market conditions and our decisions on how to manage operations and risk. “Estimated Plant Output Hedged” represents the portion of MWHs of future generation/production, taking into consideration scheduled plant outages, for which we have sales commitments or estimated requirement obligations to customers.

Generation Plant Hedging Information
Estimated Next Three Years
As of March 31, 2006

 
Remainder
2006
2007
2008
Estimated Plant Output Hedged
90%
91%
92%

VaR Associated with Risk Management Contracts

Commodity Price Risk

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at March 31, 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

Three Months Ended
March 31, 2006
       
Twelve Months Ended
December 31, 2005
(in millions)
       
(in millions)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
$2
 
$6
 
$3
 
$2
       
$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 $531 million at March 31, 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 Months Ended March 31, 2006 and 2005
(in millions, except per-share amounts)
(Unaudited)

   
2006
 
2005
 
REVENUES
         
Utility Operations
 
$
2,987
 
$
2,605
 
Gas Operations
   
(18
)
 
357
 
Other
   
139
   
103
 
TOTAL
   
3,108
   
3,065
 
               
EXPENSES
             
Fuel and Other Consumables Used for Electric Generation
   
961
   
789
 
Purchased Energy for Resale
   
166
   
130
 
Purchased Gas for Resale
   
-
   
249
 
Maintenance and Other Operation
   
828
   
837
 
Gain/Loss on Disposition of Assets, Net
   
(68
)
 
(115
)
Depreciation and Amortization
   
341
   
327
 
Taxes Other Than Income Taxes
   
191
   
188
 
TOTAL
   
2,419
   
2,405
 
               
OPERATING INCOME
   
689
   
660
 
               
Interest and Investment Income
   
8
   
11
 
Carrying Costs Income
   
30
   
20
 
Allowance For Equity Funds Used During Construction
   
6
   
6
 
Gain on Disposition of Equity Investments, Net
   
3
   
-
 
               
INTEREST AND OTHER CHARGES
             
Interest Expense
   
168
   
173
 
Preferred Stock Dividend Requirements of Subsidiaries
   
1
   
2
 
TOTAL
   
169
   
175
 
               
INCOME BEFORE INCOME TAX EXPENSE, MINORITY
  INTEREST EXPENSE AND EQUITY EARNINGS
   
567
   
522
 
               
Income Tax Expense
   
189
   
172
 
Minority Interest Expense
   
-
   
1
 
Equity Earnings of Unconsolidated Subsidiaries
   
-
   
5
 
               
INCOME BEFORE DISCONTINUED OPERATIONS
   
378
   
354
 
               
DISCONTINUED OPERATIONS, Net of Tax
   
3
   
1
 
               
NET INCOME
 
$
381
 
$
355
 
               
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
   
394
   
393
 
               
BASIC EARNINGS PER SHARE
             
Income Before Discontinued Operations
 
$
0.96
 
$
0.90
 
Discontinued Operations, Net of Tax
   
0.01
   
-
 
TOTAL BASIC EARNINGS PER SHARE
 
$
0.97
 
$
0.90
 
               
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
   
396
   
394
 
               
DILUTED EARNINGS PER SHARE
             
Income Before Discontinued Operations
 
$
0.95
 
$
0.90
 
Discontinued Operations, Net of Tax
   
0.01
   
-
 
TOTAL DILUTED EARNINGS PER SHARE
 
$
0.96
 
$
0.90
 
               
CASH DIVIDENDS PAID PER SHARE
 
$
0.37
 
$
0.35
 
               
See Condensed Notes to Condensed Consolidated Financial Statements.              
 



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2006 and December 31, 2005
(in millions)
(Unaudited)


   
2006
 
2005
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
276
 
$
401
 
Other Temporary Cash Investments
   
202
   
127
 
Accounts Receivable:
             
Customers
   
673
   
826
 
Accrued Unbilled Revenues
   
315
   
374
 
Miscellaneous
   
45
   
51
 
Allowance for Uncollectible Accounts
   
(33
)
 
(31
)
  Total Receivables
   
1,000
   
1,220
 
Fuel, Materials and Supplies
   
776
   
726
 
Risk Management Assets
   
625
   
926
 
Margin Deposits
   
171
   
221
 
Regulatory Asset for Under-Recovered Fuel Costs
   
92
   
197
 
Other
   
107
   
127
 
TOTAL
   
3,249
   
3,945
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
16,726
   
16,653
 
Transmission
   
6,477
   
6,433
 
Distribution
   
10,895
   
10,702
 
Other (including gas, coal mining and nuclear fuel)
   
3,146
   
3,116
 
Construction Work in Progress
   
2,538
   
2,217
 
Total
   
39,782
   
39,121
 
Accumulated Depreciation and Amortization
   
14,974
   
14,837
 
TOTAL - NET
   
24,808
   
24,284
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
3,213
   
3,262
 
Securitized Transition Assets and Other
   
583
   
593
 
Spent Nuclear Fuel and Decommissioning Trusts
   
1,160
   
1,134
 
Investments in Power and Distribution Projects
   
47
   
97
 
Goodwill
   
76
   
76
 
Long-term Risk Management Assets
   
655
   
886
 
Employee Benefits and Pension Assets
   
1,090
   
1,105
 
Other
   
840
   
746
 
TOTAL
   
7,664
   
7,899
 
               
Assets Held for Sale
   
44
   
44
 
               
TOTAL ASSETS
 
$
35,765
 
$
36,172
 

See Condensed Notes to Condensed Consolidated Financial Statements.



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2006 and December 31, 2005
(Unaudited)


   
2006
 
2005
 
CURRENT LIABILITIES
 
(in millions)
 
Accounts Payable
$
1,033
 
$
1,144
 
Short-term Debt
 
226
   
10
 
Long-term Debt Due Within One Year
 
1,061
   
1,153
 
Risk Management Liabilities
 
539
   
906
 
Accrued Taxes
 
829
   
651
 
Accrued Interest
 
180
   
183
 
Customer Deposits
 
415
   
571
 
Other
 
581
   
842
 
TOTAL
 
4,864
   
5,460
 
             
NONCURRENT LIABILITIES
           
Long-term Debt
 
11,081
   
11,073
 
Long-term Risk Management Liabilities
 
500
   
723
 
Deferred Income Taxes
 
4,847
   
4,810
 
Regulatory Liabilities and Deferred Investment Tax Credits
 
2,760
   
2,747
 
Asset Retirement Obligations
 
950
   
936
 
Employee Benefits and Pension Obligations
 
342
   
355
 
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2
 
155
   
157
 
Deferred Credits and Other
 
821
   
762
 
TOTAL
 
21,456
   
21,563
 
             
TOTAL LIABILITIES
 
26,320
   
27,023
 
             
Cumulative Preferred Stock Not Subject to Mandatory Redemption
 
61
   
61
 
             
Commitments and Contingencies (Note 5)
           
             
COMMON SHAREHOLDERS’ EQUITY
           
Common Stock Par Value $6.50:
           
     
2006
   
2005
             
Shares Authorized
   
600,000,000
   
600,000,000
             
Shares Issued
   
415,412,203
   
415,218,830
             
(21,499,992 shares were held in treasury at March 31, 2006 and
  December 31, 2005)
 
2,700
   
2,699
 
Paid-in Capital
 
4,137
   
4,131
 
Retained Earnings
 
2,520
   
2,285
 
Accumulated Other Comprehensive Income (Loss)