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

Commission
 
Registrant, State of Incorporation,
 
I.R.S. Employer
File Number
 
Address of Principal Executive Offices, and Telephone Number
 
Identification No.
         
1-3525
 
AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation)
 
13-4922640
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 Central Company, AEP Texas North Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company and Public Service Company of Oklahoma meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.

 



     
 
 
Number of shares of common stock outstanding of the registrants at
April 30, 2007
       
AEP Generating Company
   
1,000
     
($1,000 par value)
AEP Texas Central Company
   
2,211,678
     
($25 par value)
AEP Texas North Company
   
5,488,560
     
($25 par value)
American Electric Power Company, Inc.
   
     398,766,908
     
($6.50 par value)
Appalachian Power Company
   
13,499,500
     
(no par value)
Columbus Southern Power Company
   
16,410,426
     
(no par value)
Indiana Michigan Power Company
   
1,400,000
     
(no par value)
Kentucky Power Company
   
1,009,000
     
($50 par value)
Ohio Power Company
   
27,952,473
     
(no par value)
Public Service Company of Oklahoma
   
9,013,000
     
($15 par value)
Southwestern Electric Power Company
   
7,536,640
     
($18 par value)



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

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

ADITC
 
Accumulated Deferred Investment Tax Credits.
AEGCo
 
AEP Generating Company, an AEP electric utility subsidiary.
AEP or Parent
 
American Electric Power Company, Inc.
AEP Consolidated
 
AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit
 
AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated domestic electric utility companies.
AEP East companies
 
APCo, CSPCo, I&M, KPCo and OPCo.
AEP System or the System
 
American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP System Power Pool or 
   AEP Power Pool
 
Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and resultant wholesale off-system sales of the member companies.
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.
AOCI
 
Accumulated Other Comprehensive Income (Loss).
APCo
 
Appalachian Power Company, an AEP electric utility subsidiary.
ARO
 
Asset Retirement Obligations.
CAA
 
Clean Air Act.
CO2
 
Carbon Dioxide.
Cook Plant
 
Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo
 
Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW
 
Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW Operating Agreement
 
Agreement, dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing 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.
ECAR
 
East Central Area Reliability Council.
EDFIT
 
Excess Deferred Federal Income Taxes.
ERCOT
 
Electric Reliability Council of Texas.
FASB
 
Financial Accounting Standards Board.
Federal EPA
 
United States Environmental Protection Agency.
FERC
 
Federal Energy Regulatory Commission.
FIN 46
 
FASB Interpretation No. 46, “Consolidation of Variable Interest Entities.”
FIN 48
 
FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1, "Definition of Settlement in FASB Interpretation No. 48."
GAAP
 
Accounting Principles Generally Accepted in the United States of America.
HPL
 
Houston Pipeline Company, a former AEP subsidiary.
IGCC
 
Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
IPP
 
Independent Power Producer.
IRS
 
Internal Revenue Service.
IURC
 
Indiana Utility Regulatory Commission.
I&M
 
Indiana Michigan Power Company, an AEP electric utility subsidiary.
JMG
 
JMG Funding LP.
KGPCo
 
Kingsport Power Company, an AEP electric distribution subsidiary.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
KPSC
 
Kentucky Public Service Commission.
kV
 
Kilovolt.
KWH
 
Kilowatthour.
LPSC
 
Louisiana Public Service Commission.
MISO
 
Midwest Independent Transmission System Operator.
MTM
 
Mark-to-Market.
MW
 
Megawatt.
MWH
 
Megawatthour.
NOx
 
Nitrogen oxide.
Nonutility Money Pool
 
AEP System’s Nonutility Money Pool.
NRC
 
Nuclear Regulatory Commission.
NSR
 
New Source Review.
NYMEX
 
New York Mercantile Exchange.
OATT
 
Open Access Transmission Tariff.
OCC
 
Corporation Commission of the State of Oklahoma.
OPCo
 
Ohio Power Company, an AEP electric utility subsidiary.
OTC
 
Over the counter.
OVEC
 
Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PJM
 
Pennsylvania - New Jersey - Maryland regional transmission organization.
PSO
 
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO
 
Public Utilities Commission of Ohio.
PUCT
 
Public Utility Commission of Texas.
Registrant Subsidiaries
 
AEP subsidiaries which are SEC registrants; 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.
RSP
 
Rate Stabilization Plan.
RTO
 
Regional Transmission Organization.
S&P
 
Standard and Poor’s.
SEC
 
United States Securities and Exchange Commission.
SECA
 
Seams Elimination Cost Allocation.
SFAS
 
Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board.
SFAS 71
 
Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation.”
SFAS 133
 
Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.”
SFAS 158
 
Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”
SFAS 159
 
Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.”
SIA
 
System Integration Agreement.
SO2
 
Sulfur Dioxide.
SPP
 
Southwest Power Pool.
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.
Transmission Equalization
  Agreement
 
Transmission Equalization Agreement by and among APCo, CSPCo, I&M, KPCo and OPCo with AEPSC as agent, promoting the allocation of the cost of ownership and operation of the transmission system in proportion to their demand ratios.
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, costs 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, soot or particulate matter and other substances.
·
Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions (including rate or other recovery for new investments, transmission service and environmental compliance).
·
Resolution of litigation (including pending Clean Air Act enforcement actions and disputes arising from the bankruptcy of Enron Corp. and related matters).
·
Our ability to constrain operation and maintenance costs.
·
The economic climate and growth in our service territory and changes in market demand and demographic patterns.
·
Inflationary and interest rate trends.
·
Our ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities.
·
Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
·
Actions of rating agencies, including changes in the ratings of debt.
·
Volatility and changes in markets for electricity, natural gas and other energy-related commodities.
·
Changes in utility regulation, including recent legislation in Virginia, the potential for new legislation in Ohio and membership in and integration into regional transmission organizations.
·
Accounting pronouncements periodically issued by accounting standard-setting bodies.
·
The performance of our pension and other postretirement benefit plans.
·
Prices for power that we generate and sell at wholesale.
·
Changes in technology, particularly with respect to new, developing or alternative sources of generation.
·
Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events.


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





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

EXECUTIVE OVERVIEW

Regulatory Activity

Our significant regulatory activities in 2007 are updated to include:

·
In March 2007, the Texas District Court judge reversed his earlier preliminary decision and concluded the sale of assets method used by TCC to value its nuclear plant stranded costs was appropriate.
·
In March 2007, various intervenors and the PUCT staff filed their recommendations in TCC’s and TNC’s energy delivery base rate filings. Though the recommendations varied, the range of recommended increase was $8 million to $30 million for TCC and $1 million to $14 million for TNC. In April 2007, TCC and TNC filed rebuttal testimony and continue to pursue $70 million and $22 million, respectively, in annual base rate increases. Hearings began in April 2007 and are scheduled to conclude in May 2007.
·
In April 2007, the Virginia legislature approved amendments recommended by the Governor to the legislature’s recently adopted, comprehensive bill providing for the re-regulation of electric utilities generation/supply rates. The effective date of the new amendments is July 1, 2007.
·
In March 2007, a Hearing Examiner (HE) in Virginia issued a report recommending a $76 million increase in APCo’s base rates and $45 million credit to the fuel factor for off-system sales margins. APCo continues to pursue an annual base rate increase of $225 million and a $27 million credit for off-system sales margins. We expect a ruling during 2007.
·
In April 2007, the FERC issued an order reversing an initial favorable ALJ decision which had found the existing PJM zonal rate design to be unjust and determined that it should be replaced. In the April 2007 order, the FERC ruled that the existing PJM rate design is just and reasonable. As a result of this order, our retail customers will be asked to bear the full cost of the existing AEP east transmission zone facilities. We presently recover approximately 85% of these costs from retail customers. The FERC further ruled that the cost of new facilities of 500 kV and above would be shared among all PJM participants.
·
In March 2007, the OCC staff and various intervenors filed testimony in PSO’s base rate case. The recommendations were base rate reductions that ranged from $18 million to $52 million. In April 2007, PSO filed rebuttal testimony and continues to pursue an increase in annual base rates of $48 million.
·
Beginning with the May 2007 billing cycle, CSPCo and OPCo implemented rates filed with the PUCO under the 4% provision of their RSPs to increase their annual generation rates for 2007 by $24 million and $8 million, respectively, to recover governmentally-mandated costs. These increases are subject to refund until the PUCO issues a final order in the matter. The hearing is scheduled to begin in late May 2007.
·
In March 2007, CSPCo filed an application under the 4% provision of the RSP to adjust the Power Acquisition Rider (PAR) which was authorized in 2005 by the PUCO in connection with CSPCo's acquisition of Monongahela Power Company's certified territory in Ohio. If approved, CSPCo's revenues would increase by $22 million and $38 million for 2007 and 2008, respectively.
·
In April 2007, CSPCo and OPCo filed a joint motion with the PUCO staff and other intervenors to withdraw the proposed enhanced reliability plan.

Investment Activity

Our significant investment activities in 2007 are updated to include:

·
We completed the 480 MW Darby Electric Generation Station acquisition in April 2007.
·
In April 2007, we signed a memorandum of understanding with Allegheny Energy Inc. to form a joint venture company to build and own certain electric transmission assets within PJM with the initial focus on a transmission line between AEP’s Amos power plant in West Virginia and Allegheny’s proposed Kemptown power plant in Maryland. We expect to execute definitive agreements for the joint venture with Allegheny Energy Inc. by mid-2007 and anticipate the joint venture will begin activities in the second half of 2007.

RESULTS OF OPERATIONS

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

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

MEMCO Operations
·
Barging operations that annually transport approximately 34 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and Lower Mississippi rivers. Approximately 35% of the barging operations relates to the transportation of coal, 28% relates to agricultural products, 21% relates to steel and 16% relates to other commodities.

Generation and Marketing
·
IPPs, wind farms and marketing and risk management activities primarily in ERCOT.

The table below presents our consolidated Income Before Discontinued Operations for the three months ended March 31, 2007 and 2006 (Earnings and Weighted Average Number of Basic Shares Outstanding in millions). We reclassified prior year amounts to conform to the current year’s segment presentation.

   
Three Months Ended March 31,
 
   
2007
 
2006
 
   
Earnings
 
EPS (b)
 
Earnings
 
EPS (b)
 
Utility Operations
 
$
253
 
$
0.63
 
$
365
 
$
0.93
 
MEMCO Operations
   
15
   
0.04
   
21
   
0.05
 
Generation and Marketing
   
(1
)
 
-
   
4
   
0.01
 
All Other (a)
   
4
   
0.01
   
(12
)
 
(0.03
)
Income Before Discontinued Operations
 
$
271
 
$
0.68
 
$
378
 
$
0.96
 
                           
Weighted Average Number of Basic Shares Outstanding
         
397
         
394
 

(a)
All Other includes:
 
·
Parent company’s guarantee revenue received from affiliates, interest income and interest expense and other nonallocated costs.
 
·
Other energy supply related businesses, including the Plaquemine Cogeneration Facility, which was sold in the fourth quarter of 2006.
(b)
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 2007 Compared to First Quarter of 2006

Income Before Discontinued Operations in 2007 decreased $107 million compared to 2006 primarily due to a decrease in Utility Operations segment earnings of $112 million. The decrease in Utility Operations segment earnings primarily relates to higher operation and maintenance expenses, higher regulatory amortization expense, lower earnings-sharing payments from Centrica, lower off-system sales margins and the elimination of SECA revenues. These decreases were partially offset by higher retail margins related to new rates in the east region and favorable weather.

Average basic shares outstanding increased to 397 million in 2007 from 394 million in 2006 primarily due to the issuance of shares under our incentive compensation and dividend reinvestment plans. Actual shares outstanding were 398 million as of March 31, 2007.
 
Utility Operations

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

   
Three Months Ended
 
   
March 31,
 
   
2007
 
2006
 
   
(in millions)
 
Revenues
 
$
3,033
 
$
2,966
 
Fuel and Purchased Power
   
1,119
   
1,126
 
Gross Margin
   
1,914
   
1,840
 
Depreciation and Amortization
   
383
   
340
 
Other Operating Expenses
   
991
   
836
 
Operating Income
   
540
   
664
 
Other Income, Net
   
18
   
41
 
Interest Charges and Preferred Stock Dividend Requirements
   
179
   
154
 
Income Tax Expense
   
126
   
186
 
Income Before Discontinued Operations
 
$
253
 
$
365
 

Summary of Selected Sales and Weather Data
For Utility Operations
For the Three Months Ended March 31, 2007 and 2006

   
 2007
 
2006
 
Energy Summary
 
 (in millions of KWH)
 
Retail:
          
Residential
   
14,139
   
12,938
 
Commercial
   
9,359
   
8,909
 
Industrial
   
13,565
   
13,222
 
Miscellaneous
   
614
   
618
 
Total Retail
   
37,677
   
35,687
 
               
Wholesale
   
8,778
   
10,844
 
               
Texas Wires Delivery
   
5,831
   
5,546
 
Total KWHs
   
52,286
   
52,077
 


Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on results of operations. In general, degree day changes in our eastern region have a larger effect on results of operations than changes in our western region due to the relative size of the two regions and the associated number of customers within each. Cooling degree days and heating degree days in our service territory for the three months ended March 31, 2007 and 2006 were as follows:

                                             
2007
 
2006
 
Weather Summary
 
(in degree days)
 
Eastern Region
         
Actual - Heating (a)
 
1,816
 
1,456
 
Normal - Heating (b)
 
1,792
 
1,817
 
           
Actual - Cooling (c)
 
14
 
1
 
Normal - Cooling (b)
 
3
 
3
 
           
Western Region (d)
         
Actual - Heating (a)
 
902
 
658
 
Normal - Heating (b)
 
959
 
972
 
           
Actual - Cooling (c)
 
56
 
43
 
Normal - Cooling (b)
 
18
 
17
 

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

First Quarter of 2007 Compared to First Quarter of 2006

Reconciliation of First Quarter of 2006 to First Quarter of 2007
Income from Utility Operations Before Discontinued Operations
(in millions)

First Quarter of 2006
       
$
365
 
               
Changes in Gross Margin:
             
Retail Margins
   
139
       
Off-system Sales
   
(41
)
     
Transmission Revenues
   
(29
)
     
Other Revenues
   
5
       
Total Change in Gross Margin
         
74
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(111
)
     
Gain on Dispositions of Assets, Net
   
(47
)
     
Depreciation and Amortization
   
(43
)
     
Carrying Costs Income
   
(22
)
     
Other Income, Net
   
2
       
Interest and Other Charges
   
(25
)
     
Total Change in Operating Expenses and Other
         
(246
)
               
Income Tax Expense
         
60
 
               
First Quarter of 2007
       
$
253
 

Income from Utility Operations Before Discontinued Operations decreased $112 million to $253 million in 2007. The key driver of the decrease was a $246 million increase in Operating Expenses and Other offset by a $74 million increase in Gross Margin and a $60 million decrease in Income Tax Expense.

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

·
Retail Margins increased $139 million primarily due to the following:
 
·
A $35 million increase related to new rates implemented in our Ohio jurisdictions as approved by the PUCO in our RSPs and a $58 million increase related to new rates implemented in other east jurisdictions of Kentucky, West Virginia and Virginia. See “APCo Virginia Base Rate Case” in Note 3 for discussion of the Virginia increase implemented subject to refund.
 
·
A $34 million increase related to increased residential and commercial usage and customer growth.
 
·
A $40 million increase in usage related to weather. As compared to the prior year, our eastern region and western region experienced 25% and 37% increases, respectively, in heating degree days.
     These increases were partially offset by:
 
·
A $27 million decrease in financial transmission rights revenue, net of congestion, primarily due to fewer transmission constraints within the PJM market.
·
Margins from Off-system Sales decreased $41 million primarily due to lower generation availability in the east due to planned outages for completion of environmental retrofits and higher retail load offset by higher margins from trading activities.
·
Transmission Revenues decreased $29 million primarily due to the elimination of SECA revenues as of April 1, 2006. See the “Transmission Rate Proceedings at the FERC” section of Note 3.
 
Utility Operating Expenses and Other and Income Taxes changed between years as follows:

·
Other Operation and Maintenance expenses increased $111 million primarily due to increases in generation expenses related to plant outages and removal costs, distribution expenses associated with service reliability and storm restoration primarily in Oklahoma and expenses associated with employee benefits.
·
Gain on Disposition of Assets, Net decreased $47 million primarily related to the earnings sharing agreement with Centrica from the sale of our REPs in 2002. In 2006, we received $70 million from Centrica for earnings sharing and in 2007 we received $20 million as the earnings sharing agreement ended.
·
Depreciation and Amortization expense increased $43 million primarily due to increased Ohio regulatory asset amortization related to recovery of IGCC preconstruction costs, increased Texas amortization of the securitized transition assets, increased Virginia regulatory amortization related to environmental and reliability recovery and higher depreciable property balances.
·
Carrying Costs Income decreased $22 million because TCC started recovering Texas stranded costs in October 2006, resulting in lower Texas carrying costs income in 2007.
·
Interest and Other Charges increased $25 million primarily due to additional debt issued in the fourth quarter of 2006 partially offset by an increase in allowance for borrowed funds used for construction.
·
Income Tax Expense decreased $60 million due to a decrease in pretax income.

MEMCO Operations

First Quarter of 2007 Compared to First Quarter of 2006

Income Before Discontinued Operations from our MEMCO Operations segment decreased from $21 million in 2006 to $15 million in 2007. The decrease was primarily related to a return to normal winter river operating conditions in 2007 compared to milder and more favorable weather in 2006 and lower spot market rates due to decreased barging demand caused by lower backhaul imports.

Generation and Marketing

First Quarter of 2007 Compared to First Quarter of 2006

Loss Before Discontinued Operations from our Generation and Marketing segment was $1 million in 2007 compared to income of $4 million in 2006. The decrease primarily relates to planned and forced outages at our Oklaunion plant in 2007 that limited the availability of power under lease.

All Other

First Quarter of 2007 Compared to First Quarter of 2006

Income Before Discontinued Operations from All Other increased from a $12 million loss in 2006 to income of $4 million in 2007. In 2006, we had after-tax losses of $8 million in 2006 from operation of the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006. In 2007, we had an after-tax gain of $10 million on the sale of investment securities.

AEP System Income Taxes

Income Tax Expense decreased $59 million 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 
   
March 31, 2007
 
December 31, 2006
 
   
($ in millions)
 
Long-term Debt, including amounts due within one year
 
$
13,902
   
58.7
%  
$
13,698
   
59.1
Short-term Debt
   
175
   
0.7
   
18
   
0.0
 
Total Debt
   
14,077
   
59.4
   
13,716
   
59.1
 
Common Equity
   
9,540
   
40.3
   
9,412
   
40.6
 
Preferred Stock
   
61
   
0.3
   
61
   
0.3
 
                           
Total Debt and Equity Capitalization
 
$
23,678
   
100.0
%
$
23,189
   
100.0
%

Our ratio of debt to total capital increased from 59.1% to 59.4% in 2007 due to our increased borrowings.

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, 2007, 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 2011
 
Revolving Credit Facility
   
1,500
   
April 2012
 
Total
   
3,000
       
Cash and Cash Equivalents
   
259
       
Total Liquidity Sources
   
3,259
       
Less: AEP Commercial Paper Outstanding
   
150
       
      Letters of Credit Drawn
   
27
       
               
Net Available Liquidity
 
$
3,082
       

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

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, 2007, this contractually-defined percentage was 54.5%. Nonperformance of these covenants could result in an event of default under these credit agreements. At March 31, 2007, we complied with all of the covenants contained in these credit agreements. In addition, the acceleration of our payment obligations, or the obligations of certain of our major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements and permit the lenders to declare the outstanding amounts payable.

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

Under a regulatory order, our utility subsidiaries, other than TCC, cannot incur additional indebtedness if the issuer’s common equity would constitute less than 30% of its capital. In addition, this order restricts those utility subsidiaries from issuing long-term debt unless that debt will be rated investment grade by at least one nationally recognized statistical rating organization. At March 31, 2007, all applicable utility subsidiaries complied with this order.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders. At March 31, 2007, we had not exceeded those authorized limits.

Credit Ratings

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

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

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

Cash Flow

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

   
Three Months Ended
 
   
March 31,
 
   
2007
 
2006
 
   
(in millions)
 
Cash and Cash Equivalents at Beginning of Period
 
$
301
 
$
401
 
Net Cash Flows From Operating Activities
   
351
   
583
 
Net Cash Flows Used For Investing Activities
   
(628
)
 
(750
)
Net Cash Flows From Financing Activities
   
235
   
42
 
Net Decrease in Cash and Cash Equivalents
   
(42
)
 
(125
)
Cash and Cash Equivalents at End of Period
 
$
259
 
$
276
 

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, 2007, we had credit facilities totaling $3 billion to support our commercial paper program. The maximum amount of commercial paper outstanding during 2007 was $150 million. The weighted-average interest rate of our commercial paper during 2007 was 5.43%. We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged. Sources of long-term funding include issuance of common stock or long-term debt and sale-leaseback or leasing agreements. Utility Money Pool borrowings and external borrowings may not exceed authorized limits under regulatory orders. See the discussion below for further detail related to the components of our cash flows.

Operating Activities
   
Three Months Ended
 
   
March 31,
 
   
2007
 
2006
 
   
(in millions)
 
Net Income
 
$
271
 
$
381
 
Less: Discontinued Operations, Net of Tax
   
-
   
(3
)
Income Before Discontinued Operations
   
271
   
378
 
Noncash Items Included in Earnings
   
420
   
323
 
Changes in Assets and Liabilities
   
(340
)
 
(118
)
Net Cash Flows From Operating Activities
 
$
351
 
$
583
 

Net Cash Flows From Operating Activities decreased in 2007 primarily due to lower fuel costs recovery.

Net Cash Flows From Operating Activities were $351 million in 2007 consisting primarily of Income Before Discontinued Operations of $271 million. Income Before Discontinued Operations included noncash expense items primarily for depreciation, amortization, deferred taxes and deferred investment tax credits. 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, none of which were significant.

Net Cash Flows From Operating Activities were $583 million in 2006. We produced Income Before Discontinued Operations of $378 million. Income Before Discontinued Operations included noncash expense items primarily for depreciation, amortization, 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.

Investing Activities
   
Three Months Ended
 
   
March 31,
 
   
2007
 
2006
 
   
(in millions)
 
Construction Expenditures
 
$
(907
)
$
(765
)
Change in Other Temporary Cash Investments, Net
   
(20
)
 
27
 
(Purchases)/Sales of Investment Securities, Net
   
236
   
(89
)
Proceeds from Sales of Assets
   
68
   
111
 
Other
   
(5
)
 
(34
)
Net Cash Flows Used for Investing Activities
 
$
(628
)
$
(750
)

Net Cash Flows Used For Investing Activities were $628 million in 2007 primarily due to Construction Expenditures for our environmental, distribution and new generation investment plan. In our normal course of business, we purchase investment securities including auction rate securities and variable rate demand notes with cash available for short-term investments. Also included in Purchases/Sales of Investment Securities, Net are purchases and sales of securities within our nuclear trusts.

Net Cash Flows Used For Investing Activities were $750 million in 2006 primarily due to Construction Expenditures. Construction Expenditures increased due to our environmental investment plan.

We forecast approximately $2.6 billion of construction expenditures for the remainder of 2007 plus $427 million for announced purchases of gas-fired generating units. Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital. These construction expenditures will be funded through results of operations and financing activities.

Financing Activities
   
Three Months Ended
 
   
March 31,
 
   
2007
 
2006
 
   
(in millions)
 
Issuance of Common Stock
 
$
54
 
$
5
 
Issuance/Retirement of Debt, Net
   
355
   
129
 
Dividends Paid on Common Stock
   
(155
)
 
(146
)
Other
   
(19
)
 
54
 
Net Cash Flows From Financing Activities
 
$
235
 
$
42
 

Net Cash Flows From Financing Activities in 2007 were $235 million primarily due to $150 million of short-term commercial paper borrowings under our credit facilities and issuing $250 million of debt securities. We paid common stock dividends of $155 million. See Note 9 for a complete discussion of long-term debt issuances and retirements.

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. 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.

In April 2007, OPCo issued $400 million of three-year floating rate notes at an initial rate of 5.53% due in 2010. The proceeds from this issuance will contribute to our investment in environmental equipment.

Our capital investment plans for 2007 will require additional funding from the capital markets.

Off-balance Sheet Arrangements

Under a limited set of circumstances we enter into off-balance sheet arrangements to accelerate cash collections, reduce operational expenses and spread risk of loss to third parties. Our 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 are as follows:
               
   
March 31,
2007 
 
December 31,
2007 
 
   
(in millions)
 
AEP Credit Accounts Receivable Purchase Commitments
 
$
549
 
$
536
 
Rockport Plant Unit 2 Future Minimum Lease Payments
   
2,364
   
2,364
 
Railcars Maximum Potential Loss From Lease Agreement
   
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 2006 Annual Report.

Summary Obligation Information

A summary of our contractual obligations is included in our 2006 Annual Report and has not changed significantly from year-end other than the debt issuances discussed in “Cash Flow” and “Financing Activities” above.

Other

Texas REPs

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

SIGNIFICANT FACTORS

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

Electric Transmission Texas LLC Joint Venture

In January 2007, we signed a participation agreement with MidAmerican Energy Holdings Company (MidAmerican) to form a joint venture company, Electric Transmission Texas LLC (ETT), to fund, own and operate electric transmission assets in ERCOT. ETT filed with the PUCT in January 2007 requesting regulatory approval to operate as an electric transmission utility in Texas, to transfer from TCC to ETT approximately $76 million of transmission assets currently under construction and to establish a wholesale transmission tariff for ETT. ETT also requested approval from the PUCT of initial rates based on an 11.25% return on equity. A procedural schedule has been established in the case, with a hearing scheduled for June. We expect a final order from the PUCT in the third quarter.

TCC also made a regulatory filing at the FERC in February 2007 regarding the transfer of certain transmission assets from TCC to ETT. In April, the FERC authorized the transfer.

Upon receipt of all required regulatory approvals, AEP Utilities, Inc., a subsidiary of AEP, and MEHC Texas Transco LLC, a subsidiary of MidAmerican, each will acquire a 50 percent equity ownership in ETT. AEP and MidAmerican plan for ETT to invest in additional transmission projects in ERCOT. The joint venture partners anticipate investments in excess of $1 billion of joint investment in Texas ERCOT Transmission projects could be constructed by ETT during the next several years. The joint venture is anticipated to be formed and begin operations in the second half of 2007, subject to regulatory approval from the PUCT and the FERC.

In February 2007, ETT filed an informational proposal with the PUCT that addresses the Competitive Renewable Energy Zone initiative of the Texas Legislature and in April ETT filed detailed testimony and exhibits supporting this proposal. The proposal outlines opportunities for additional significant investment in transmission assets in Texas.

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

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 from West Virginia to New Jersey. The 765 kV line is designed to reduce PJM congestion costs by substantially improving west-east transfer capability by approximately 5,000 MW during peak loading conditions and reducing transmission line losses by up to 280 MW. The project would also enhance reliability of the Eastern transmission grid. The projected cost for the project, as oringally proposed to PJM, is approximately $3 billion. The project is subject to PJM and state approvals, and FERC approvals of incentive cost recovery mechanisms. The projected in-service date assumes eight years for siting and construction. Due to PJM's need to review and evaluate the project in conjunction with other proposed projects, the projected in-service date is now 2015. This assumes approval by the PJM Board in mid-2007, followed by approval by the FERC on initial rates by the end of 2007.

We were the first entity to file with the Department of Energy (DOE) seeking to have the route of a proposed transmission project designated as 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 August 2006, the DOE issued the “National Interest Electric Transmission Congestion Study.” In this study, DOE indicated that the mid-Atlantic Coastal area, which the AEP Interstate Project is designed to reinforce, is one of the two most critical congestion areas in the nation. In April 2007, the DOE approved the mid-Atlantic Coastal area as a NIETC which includes the entire proposed 765 kV transmission line.

In July 2006, pursuant to our request, the FERC provided that the new line is included in PJM’s formal Regional Transmission Expansion Plan to be finalized in 2007. The conditionally approved incentives include (a) a return on equity set at the high end of the “zone of reasonableness”; (b) the timely recovery of the cost of capital during the construction period; and (c) the ability to defer and recover costs incurred during the pre-construction and pre-operating period. Since the FERC has clarified that the project qualifies for these rate incentives, we expect to propose rates that will capture the incentives in a future FERC rate filing.

In April 2007, we signed a memorandum of understanding (MOU) with Allegheny Energy Inc. to form a joint venture company to build and own certain electric transmission assets within PJM including the first half of the West Virginia - New Jersey line proposed by AEP in January 2006.  Under the terms of the MOU, the joint venture company will build and own approximately 250 miles of 765kV transmission lines from AEP's Amos station to the Maryland border.  The MOU does not include any provisions for the remainder of the AEP Interstate Project proposal from Allegheny's Kemptown station to New Jersey. We expect to execute definitive agreements for the joint venture with Allegheny Energy Inc. by mid-2007 and anticipate the joint venture will begin activities in the second half of 2007.

Texas Restructuring

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

·
The PUCT ruling that TCC did not comply with the statute and PUCT rules regarding the required auction of 15% of its Texas jurisdictional installed capacity, which led to a significant disallowance of capacity auction true-up revenues,
·
The PUCT ruling that TCC acted in a manner that was commercially unreasonable, because it failed to determine a minimum price at which it would reject bids for the sale of its nuclear generating plant and it bundled out of the money gas units with the sale of its coal unit, which led to the disallowance of a significant portion of TCC’s net stranded generation plant cost, and
·
The two federal matters regarding the allocation of off-system sales related to fuel recoveries and the potential tax normalization violation.

Municipal customers and other intervenors also appealed the PUCT true-up orders seeking to further reduce TCC’s true-up recoveries. On February 1, 2007, the Texas District Court judge hearing the various appeals issued a letter containing his preliminary determinations. He generally affirmed the PUCT’s April 4, 2006 final true-up order for TCC with two significant exceptions. The judge determined that the PUCT erred when it determined TCC’s stranded cost using the sale of assets method instead of the Excess Cost Over Market (ECOM) method to value TCC’s nuclear plant. The judge also determined that the PUCT erred when it concluded it was required to use the carrying cost rate specified in the true-up order. However, the District Court did not rule that the carrying cost rate was inappropriate. He directed that these matters should be remanded to the PUCT to determine their specific impact on TCC’s future true-up revenues.

In March 2007, the District Court judge reversed his earlier preliminary decision and concluded the sale of assets method to value TCC’s nuclear plant was appropriate. The District Court judge did not reconsider his preliminary ruling that the PUCT erred when it concluded it was required to use the carrying cost rate specified in the true-up order. The District Court judge also determined the PUCT improperly reduced TCC’s net stranded plant costs from the sale of its generating units through the commercial unreasonableness disallowance, which could have a materially favorable effect on TCC. Management cannot predict the ultimate outcome of any future court appeals or any future remanded PUCT proceeding. If the District Court’s carrying cost rate remand ruling is ultimately upheld on appeal and remanded to the PUCT for reconsideration, the PUCT could either confirm the existing weighted average carrying cost (WACC) rate or redetermine a new rate. If the PUCT changes the rate, it could result in a material adverse change to TCC’s recoverable carrying costs, results of operations, cash flows and financial condition. TCC, the PUCT and intervenors appealed the District Court ruling to the Court of Appeals. Management cannot predict what actions, if any, the PUCT will take regarding the carrying costs.
 
If TCC ultimately succeeds in its appeals, it could have a favorable effect on future results of operations, cash flows and financial condition. If municipal customers and other intervenors succeed in their appeals, it could have a substantial adverse effect on future results of operations, cash flows and financial condition.

SECA Revenue Subject to Refund

We ceased collecting through-and-out transmission service (T&O) revenues in accordance with FERC orders and implemented SECA rates to mitigate the loss of T&O revenues from December 1, 2004 through March 31, 2006, when SECA rates expired. Intervenors objected to the SECA rates, raising various issues. In August 2006, the ALJ issued an initial decision, finding that the rate design for the recovery of SECA charges was flawed and that a large portion of the “lost revenues” reflected in the SECA rates was not recoverable. The ALJ found that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made.

Since the implementation of SECA rates in December 2004, the AEP East companies recorded approximately $220 million of gross SECA revenues, subject to refund. The AEP East companies have reached settlements with certain customers related to approximately $70 million of such revenues. The unsettled gross SECA revenues total approximately $150 million. If the ALJ’s initial decision is upheld in its entirety, it would disallow $126 million of the AEP East companies’ unsettled gross SECA revenues. In the second half of 2006, the AEP East companies provided a reserve of $37 million in net refunds.

In September 2006, AEP, together with Exelon and the Dayton Power and Light Company, filed an extensive post hearing brief and reply brief noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part. Management believes that the FERC should reject the initial decision because it is contrary to prior related FERC decisions, which are presently subject to rehearing. Furthermore, management believes the ALJ’s findings on key issues are largely without merit. Although management believes they have meritorious arguments, management cannot predict the ultimate outcome of any future FERC proceedings or court appeals. If the FERC adopts the ALJ’s decision, it will have an adverse effect on future results of operations and cash flows.
 
Virginia Restructuring

In April 2004, Virginia enacted legislation that extended the transition period for electricity restructuring, including capped rates, through December 31, 2010. The legislation provides APCo with specified cost recovery opportunities during the capped rate period, including two optional bundled general base rate changes and an opportunity for timely recovery, through a separate rate mechanism, of certain incremental environmental and reliability costs incurred on and after July 1, 2004. Under the restructuring law, APCo continues to have an active fuel clause recovery mechanism in Virginia and continues to practice deferred fuel accounting. Also, under the restructuring law, APCo defers incremental environmental generation costs and incremental T&D reliability costs for future recovery, to the extent such costs are not being recovered when incurred, and amortizes a portion of such deferrals commensurate with recovery.

In April 2007, the Virginia legislature adopted a comprehensive law providing for the re-regulation of electric utilities’ generation/supply rates. The amendments shorten the transition period by two years (from 2010 to 2008) after which rates for retail generation/supply will return to a form of cost-based regulation. The legislation provides for, among other things, biennial rate reviews beginning in 2009, rate adjustment clauses for the recovery of the costs of (a) transmission services and new transmission investment, (b) Demand Side Management, load management, and energy efficiency programs, (c) renewable energy programs, and (d) environmental retrofit and new generation investments, significant return on equity enhancements for large investments in new generation and a floor on the allowed return on equity based on the average earned return on equities’ of regional vertically integrated electric utilities. Effective July 1, 2007, utilities will retain a minimum of 25% of the margins from off-system sales with the remaining margins from such sales credited against the fuel factor. The legislation also allows APCo to continue to defer and recover incremental environmental and reliability costs incurred through December 31, 2008. APCo expects this new form of cost-based ratemaking should improve its annual return on equity and cash flow from operations when new ratemaking begins in 2009. However, with the return of cost-based regulation, APCo’s generation business will again meet the criteria for application of regulatory accounting principles under SFAS 71. Results of operations and financial condition could be adversely affected when APCo is required to re-establish certain net regulatory liabilities applicable to its generation/supply business. The timing and earnings effect from such reapplication of SFAS 71 regulatory accounting for APCo’s Virginia generation/supply business are uncertain at this time.

New Generation

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

In April 2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase 1 of the cost recovery proposal. In June 2006, the PUCO issued another order approving a tariff to recover Phase 1 pre-construction costs over no more than a twelve-month period effective July 1, 2006. Through March 31, 2007, CSPCo and OPCo each recorded pre-construction IGCC regulatory assets of $10 million and each recovered $9 million of those costs. CSPCo and OPCo will recover the remaining amounts through June 30, 2007. The PUCO indicated that if CSPCo and OPCo have not commenced a continuous course of construction of the IGCC plant within five years of the June 2006 PUCO order, all charges collected for pre-construction costs, associated with items that may be utilized in IGCC projects at other sites, must be refunded to Ohio ratepayers with interest. The PUCO deferred ruling on Phases 2 and 3 cost recovery until further hearings are held. A date for further rehearings has not been set.

In August 2006, the Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order in the IGCC proceeding. CSPCo and OPCo believe that the PUCO’s authorization to begin collection of Phase 1 rates is lawful. Management, however, cannot predict the outcome of these appeals. If the PUCO’s order is found to be unlawful, CSPCo and OPCo could be required to refund Phase I cost-related recoveries.

In January 2006, APCo filed a petition with the WVPSC requesting its approval of a Certificate of Public Convenience and Necessity to construct a 629 MW IGCC plant adjacent to APCo’s existing Mountaineer Generating Station in Mason County, WV. In January 2007, at APCo’s request, the WVPSC issued an order delaying the Commission’s deadline for issuing an order on the certificate to December 2007. Through March 31, 2007, APCo deferred pre-construction IGCC costs totaling $10 million. If the plant is not built and these costs are not recoverable, future results of operations and cash flows would be adversely affected.

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 new generation to satisfy 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 its existing Arsenal Hill Power Plant in Shreveport, Louisiana. SWEPCo also plans to build a new 600 MW base load coal plant, of which SWEPCo’s investment will be 73%, in Hempstead County, Arkansas by 2011 to meet the long-term generation needs of its customers. Preliminary cost estimates for SWEPCo’s share of the new facilities are approximately $1.4 billion (this total excludes the related transmission investment and AFUDC). These new facilities are subject to regulatory approvals from SWEPCo’s three state commissions. The peaking generation facility in Tontitown, Arkansas has been approved by all three state commissions and Units 3 and 4 are projected to be online in July 2007 and the remaining two units by 2008. Construction is expected to begin in 2007 on the intermediate and base load facilities upon approval from the state regulatory commissions. Expenditures related to construction of these facilities are expected to total $349 million in 2007.

In September 2005, PSO sought proposals for new peaking generation to be online in 2008, and in December 2005 PSO sought proposals for base load generation to be online in 2011. PSO received proposals and evaluated those proposals meeting the Request for Proposal criteria with oversight from a neutral third party. In March 2006, PSO announced plans to add 170 MW of peaking generation to its Riverside Station plant in Jenks, Oklahoma where PSO will construct and operate two 85 MW simple-cycle natural gas combustion turbines. Also in March 2006, PSO announced plans to add 170 MW of peaking generation to its Southwestern Station plant in Anadarko, Oklahoma where they will construct and operate two 85 MW simple-cycle natural gas combustion turbines. Combined preliminary cost estimates for these additions are approximately $120 million. In April 2007, the OCC approved a settlement agreement regarding these new peaking units. The settlement agreement provides for recovery of a purchase fee of $35 million to be paid by PSO to Lawton Cogeneration, LLC (Lawton) and for all rights to Lawton’s cogeneration facility for permits, options and engineering studies. PSO will record the purchase fee as a regulatory asset and recover it through a rider over a three-year period with a carrying charge of 8.25% beginning in September 2007. In addition, PSO will recover the traditional costs associated with plant in service of these new peaking units. Such costs will be recovered through the rider until cost recovery occurs through base rates or formula rates in a subsequent proceeding. PSO must file a rate case within eighteen months of the beginning of recovery through the rider unless the OCC approves a formula-based rate mechanism that provides for recovery of the peaking units.
 
In July 2006, PSO announced plans to enter a joint venture with Oklahoma Gas and Electric Company (OG&E) and Oklahoma Municipal Power Authority (OMPA) 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. PSO, OG&E and OMPA signed an agreement in February 2007 with Red Rock Power Partners to begin the first phase of the project. Preliminary cost estimates for 100% of the new facility are approximately $1.8 billion, and the unit is expected to be online no later than the first half of 2012. These new facilities are subject to regulatory approval from the OCC. Construction of all of these additions is expected to begin in 2007. Expenditures related to construction of these facilities are expected to total $125 million in 2007.

In November 2006, CSPCo agreed to purchase Darby Electric Generating Station (Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light Company, for $102 million. CSPCo completed the purchase in April 2007. The Darby plant is located near Mount Sterling, Ohio and is a natural gas, simple cycle power plant with a generating capacity of 480 MW.  The purchase of Darby is an economically efficient way to provide peaking generation to our customers at a cost below that of building a new, comparable plant. 

In January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station (Lawrenceburg) from an affiliate of Public Service Enterprise Group (PSEG) for approximately $325 million and the assumption of liabilities of approximately $2 million. The transaction is expected to close in May 2007. The Lawrenceburg plant is located in Lawrenceburg, Indiana, adjacent to I&M’s Tanners Creek Plant, and is a natural gas, combined cycle power plant with a generating capacity of 1,096 MW. AEGCo plans to sell the power to CSPCo through a FERC-approved purchase power contract.

Litigation

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

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

Environmental Matters

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

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

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

Environmental Litigation

New Source Review (NSR) Litigation: In 1999, the Federal EPA and a number of states filed complaints alleging that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities including the Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric Company, Ohio Edison Company, Southern Indiana Gas & Electric Company, Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company and Duke Energy, modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA. 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 thereafter against 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 twenty-year period. A bench trial on the liability issues was held during 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.

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 the Duke Energy 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 Court denied the Federal EPA’s request for rehearing, and the Federal EPA and other parties filed a petition for review by the U.S. Supreme Court. In April 2007, the Supreme Court denied the petition for review. The Federal EPA also proposed a rule that would define “emissions increases” in a way that would exclude most of the challenged activities from NSR.

On April 2, 2007, the U.S. Supreme Court reversed the Fourth Circuit Court of Appeals’ decision that had supported the statutory construction argument of Duke Energy in its NSR proceeding. In a unanimous decision, the Court ruled that the Federal EPA was not obligated to define “major modification” in two different CAA provisions in the same way. The Court also found that the Fourth Circuit’s interpretation of “major modification” as applying only to projects that increased hourly emission rates amounted to an invalidation of the relevant Federal EPA regulations, which under the CAA can only be challenged in the Court of Appeals within 60 days of the Federal EPA rulemaking. The U.S. Supreme Court did acknowledge, however, that Duke Energy may argue on remand that the Federal EPA has been inconsistent in its interpretations of the CAA and the regulations and may not retroactively change 20 years of accepted practice.

In addition to providing guidance on certain of the merits of the NSR proceedings brought against APCo, CSPCo, I&M and OPCo in U.S. District Court for the Southern District of Ohio, the U.S. Supreme Court’s issuance of a ruling in the Duke Energy cases has an impact on the timing of our NSR proceedings. First, the court in the case for which a trial on liability issues has been conducted has indicated an intent to issue a decision on liability. Second, the bench trial on remedy issues, if necessary, is likely to be scheduled to begin in the third quarter of 2007.

We are unable to estimate the loss or range of loss related to any contingent liability, if any, we might have for civil penalties under the 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 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.

Critical Accounting Estimates

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

Adoption of New Accounting Pronouncements

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

 


QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

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

All Other includes gas operations which 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.

Our Generation and Marketing segment holds power sale contracts to commercial and industrial customers and wholesale power trading and marketing contracts within ERCOT.

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

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

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

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

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
March 31, 2007
(in millions)
 
Utility Operations
 
Generation and
Marketing
 
All Other
 
Sub-Total MTM Risk Management Contracts
 
PLUS: MTM of Cash Flow and Fair Value Hedges
 
Total
 
Current Assets
$
319
 
$
30
 
$
121
 
$
470
 
$
6
 
$
476
 
Noncurrent Assets
 
210
   
21
   
110
 
 
341
   
10
   
351
 
Total Assets
 
529
   
51
   
231
 
 
811
   
16
   
827
 
                                     
Current Liabilities
 
(228
)
 
(35
)
 
(120
)
 
(383
)
 
(20
)
 
(403
)
Noncurrent Liabilities
 
(92
)
 
(8
)
 
(117
)
 
(217
)
 
(2
)
 
(219
)
Total Liabilities
 
(320
)
 
(43
)
 
(237
)
 
(600
)
 
(22
)
 
(622
)
                                     
Total MTM Derivative
  Contract Net Assets
  (Liabilities)
$
209
 
$
8
 
$
(6
)
$
211
 
$
(6
)
$
205
 

MTM Risk Management Contract Net Assets (Liabilities)
Three Months Ended March 31, 2007
(in millions)
   
Utility Operations
 
Generation
and
Marketing
 
All Other
 
Total
 
Total MTM Risk Management Contract Net Assets   (Liabilities)  at December 31, 2006
 
$
236
 
$
2
 
$
(5
)
$
233
 
(Gain) Loss from Contracts Realized/Settled During 
   the Period and Entered in a Prior Period
   
(23
)
 
-
   
-
   
(23
)
Fair Value of New Contracts at Inception When Entered
  During the Period (a)
   
1
   
3
   
-
   
4
 
Net Option Premiums Paid/(Received) for Unexercised or   Unexpired Option Contracts Entered During The Period
   
-
   
-
   
-
   
-
 
Changes in Fair Value Due to Valuation Methodology
  Changes on Forward Contracts
   
-
   
-
   
-
   
-
 
Changes in Fair Value Due to Market Fluctuations During 
  the Period (b)
   
5
   
3
   
(1
)
 
7
 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
   
(10
)
 
-
   
-
   
(10
)
Total MTM Risk Management Contract Net Assets   (Liabilities) at March 31, 2007
 
$
209
 
$
8
 
$
(6
)
 
211
 
Net Cash Flow and Fair Value Hedge Contracts
                     
(6
)
Total MTM Risk Management Contract Net Assets at   March  31, 2007
                   
$
205
 

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

The following table presents:

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

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets (Liabilities)
Fair Value of Contracts as of March 31, 2007
(in millions)
   
Remainder
2007
 
2008
 
2009
 
2010
 
2011
 
After
2011
 
Total
 
Utility Operations:
                                    
Prices Actively Quoted - Exchange Traded Contracts
 
$
14
 
$
1
 
$
2
 
$
-
 
$
-
 
$
-
 
$
17
 
Prices Provided by Other External Sources -
  OTC Broker Quotes (a)
   
85
   
50
   
33
   
14
   
-
   
-
   
182
 
Prices Based on Models and Other Valuation Methods (b)
   
(18
)
 
(7
)
 
9
   
17
   
4
   
5
   
10
 
Total
 
$
81
 
$
44
 
$
44
 
$
31
 
$
4
 
$
5
 
$
209
 
                                             
Generation and Marketing:
                                           
Prices Actively Quoted - Exchange Traded Contracts
 
$
(5
)
$
(4
)
$
1
 
$
-
 
$
-
 
$
-
 
$
(8
)
Prices Provided by Other External Sources -
  OTC Broker Quotes (a)
   
(3
)
 
8
   
1
   
-
   
-
   
-
   
6
 
Prices Based on Models and Other Valuation Methods (b)
   
3
   
6
   
(1
)
 
-
   
-
   
2
   
10
 
Total
 
$
(5
)
$
10
 
$
1
 
$
-
 
$
-
 
$
2
 
$
8
 
                                             
All Other:
                                           
Prices Actively Quoted - Exchange Traded Contracts
 
$
4
 
$
-
 
$
-
 
$
-
 
$
-
 
$
-
 
$
4
 
Prices Provided by Other External Sources -
  OTC Broker Quotes (a)
   
(3
)
 
-
   
-
   
-
   
-
   
-
   
(3
)
Prices Based on Models and Other Valuation Methods (b)
   
-
   
(1
)
 
(4
)
 
(4
)
 
2
   
-
   
(7
)
Total
 
$
1
 
$
(1
)
$
(4
)
$
(4
)
$
2
 
$
-
 
$
(6
)
                                             
Total:
                                           
Prices Actively Quoted - Exchange Traded Contracts
 
$
13
 
$
(3
)
$
3
 
$
-
 
$
-
 
$
-
 
$
13
 
Prices Provided by Other External Sources -
  OTC Broker Quotes (a)
   
79
   
58
   
34
   
14
   
-
   
-
   
185
 
Prices Based on Models and Other Valuation Methods (b)
   
(15
)
 
(2
)
 
4
   
13
   
6
   
7
   
13
 
Total
 
$
77
 
$
53
 
$
41
 
$
27
 
$
6
 
$
7
 
$
211
 

(a)
Prices Provided by Other External Sources - OTC Broker Quotes reflects information obtained from over-the-counter brokers (OTC), industry services, or multiple-party online platforms.
(b)
Prices Based on Models and Other Valuation Methods is used in the absence of 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 March 31, 2007

Commodity
 
Transaction Class
 
Market/Region
 
Tenor
           
(in Months)
Natural Gas
 
Futures
 
NYMEX / Henry Hub
 
60
             
   
Physical Forwards
 
Gulf Coast, Texas
 
19
             
   
Swaps
 
Northeast, Mid-Continent, Gulf Coast, Texas
 
19
             
   
Exchange Option Volatility
 
NYMEX / Henry Hub
 
12
             
Power
 
Futures
 
AEP East - PJM
 
33
             
   
Physical Forwards
 
AEP East
 
45
             
   
Physical Forwards
 
AEP West
 
33
             
   
Physical Forwards
 
West Coast
 
33
             
   
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 operations. We monitor these risks on our future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows. We do not hedge all commodity price risk.

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

We use forward contracts and collars as cash flow hedges to lock in prices on certain transactions denominated in foreign currencies where deemed necessary. We do not hedge all foreign currency exposure.
 
The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for changes in cash flow hedges from December 31, 2006 to March 31, 2007. The following table also indicates what portion of designated, effective hedges are expected to be reclassified into net income in the next 12 months. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts which are not designated as effective cash flow hedges are marked-to-market and are included in the previous risk management tables.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
Three Months Ended March 31, 2007
(in millions)
   
 Power
 
 Interest Rate and
Foreign
Currency
 
 Total
 
Beginning Balance in AOCI, December 31, 2006
 
$
17
 
$
(23
)
$
(6
)
Changes in Fair Value
   
(15
)
 
-
   
(15
)
Reclassifications from AOCI to Net Income for
  Cash Flow Hedges Settled
   
(7
)
 
-
   
(7
)
Ending Balance in AOCI, March 31, 2007
 
$
(5
)
$
(23
)
$
(28
)
                     
After Tax Portion Expected to be Reclassified 
   to Earnings During Next 12 Months
 
$
(10
)
$
(1
)
$
(11
)

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 meets our internal credit rating criteria will we extend unsecured credit. We use Moody’s Investors Service, Standard & Poor’s and qualitative and quantitative data to assess the financial health of counterparties on an ongoing basis. We use our analysis, in conjunction with the rating agencies’ information, to determine appropriate risk parameters. We also require cash deposits, letters of credit and parent/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, 2007, our credit exposure net of credit collateral to sub investment grade counterparties was approximately 3.10%, expressed in terms of net MTM assets and net receivables. As of March 31, 2007, 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% of
Net Exposure
 
Net Exposure of Counterparties >10%
 
Investment Grade
 
$
665
 
$
102
 
$
563
   
1
 
$
72
 
Split Rating
   
7
   
2
   
5
   
2
   
4
 
Noninvestment Grade
   
7
   
-
   
7
   
2
   
7
 
No External Ratings:
                               
Internal Investment Grade
   
15
   
-
   
15
   
3
   
11
 
Internal Noninvestment Grade
   
45
   
33
   
12
   
2
   
8
 
Total as of March 31, 2007
 
$
739
 
$
137
 
$
602
   
10
 
$
102
 
                                 
Total as of December 31, 2006
 
$
998
 
$
161
 
$
837
   
9
 
$
169
 
 
Generation Plant Hedging Information

This table provides information on operating measures regarding the proportion of output of our generation facilities (based on economic availability projections) economically hedged, including both contracts designated as cash flow hedges under SFAS 133 and contracts not designated as cash flow hedges. This information is forward-looking and provided on a prospective basis through December 31, 2009. 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, 2007

 
Remainder
       
 
2007
 
2008
 
2009
Estimated Plant Output Hedged
93%
 
89%
 
90%

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, 2007, 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, 2007
       
Twelve Months Ended
December 31, 2006
(in millions)
       
(in millions)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
$2
 
$6
 
$2
 
$1
       
$3
 
$10
 
$3
 
$1

The High VaR for 2006 occurred in mid-August during a period of high gas and power volatility. The following day, positions were flattened and the VaR was significantly reduced.

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 $873 million at March 31, 2007 and $870 million at December 31, 2006. 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 INCOME
For the Three Months Ended March 31, 2007 and 2006
(in millions, except per-share amounts and shares outstanding)
(Unaudited)

   
2007
 
2006
 
REVENUES
         
Utility Operations
 
$
2,886
 
$
2,982
 
Other
   
283
   
126
 
TOTAL
   
3,169
   
3,108
 
               
EXPENSES
             
Fuel and Other Consumables Used for Electric Generation
   
886
   
961
 
Purchased Energy for Resale
   
246
   
166
 
Other Operation and Maintenance
   
938
   
821
 
Gain/Loss on Disposition of Assets, Net
   
(23
)
 
(68
)
Depreciation and Amortization
   
391
   
348
 
Taxes Other Than Income Taxes
   
186
   
191
 
TOTAL
   
2,624
   
2,419
 
               
OPERATING INCOME
   
545
   
689
 
               
Interest and Investment Income
   
23
   
8
 
Carrying Costs Income
   
8
   
30
 
Allowance For Equity Funds Used During Construction
   
8
   
6
 
Gain on Disposition of Equity Investments, Net
   
-
   
3
 
               
INTEREST AND OTHER CHARGES
             
Interest Expense
   
186
   
168
 
Preferred Stock Dividend Requirements of Subsidiaries
   
1
   
1
 
TOTAL
   
187
   
169
 
               
INCOME BEFORE INCOME TAX EXPENSE, MINORITY
  INTEREST EXPENSE AND EQUITY EARNINGS
   
397
   
567
 
               
Income Tax Expense
   
130
   
189
 
Minority Interest Expense
   
1
   
-
 
Equity Earnings of Unconsolidated Subsidiaries
   
5
   
-
 
               
INCOME BEFORE DISCONTINUED OPERATIONS
   
271
   
378
 
               
DISCONTINUED OPERATIONS, Net of Tax
   
-
   
3
 
               
NET INCOME
 
$
271
 
$
381
 
               
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING
   
397,314,642
   
393,653,162
 
               
BASIC EARNINGS PER SHARE
             
Income Before Discontinued Operations
 
$
0.68
 
$
0.96
 
Discontinued Operations, Net of Tax
   
-
   
0.01
 
TOTAL BASIC EARNINGS PER SHARE
 
$
0.68
 
$
0.97
 
               
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING
   
398,552,113
   
395,580,106
 
               
DILUTED EARNINGS PER SHARE
             
Income Before Discontinued Operations
 
$
0.68
 
$
0.95
 
Discontinued Operations, Net of Tax
   
-
   
0.01
 
TOTAL DILUTED EARNINGS PER SHARE
 
$
0.68
 
$
0.96
 
               
CASH DIVIDENDS PAID PER SHARE
 
$
0.39
 
$
0.37
 
               
See Condensed Notes to Condensed Consolidated Financial Statements.
 
 

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


   
2007
 
2006
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
259
 
$
301
 
Other Temporary Cash Investments
   
197
   
425
 
Accounts Receivable:
             
Customers
   
757
   
676
 
Accrued Unbilled Revenues
   
304
   
350
 
Miscellaneous
   
59
   
44
 
Allowance for Uncollectible Accounts
   
(31
)
 
(30
)
   Total Accounts Receivable
   
1,089
   
1,040
 
Fuel, Materials and Supplies
   
942
   
913
 
Risk Management Assets
   
476
   
680
 
Regulatory Asset for Under-Recovered Fuel Costs
   
22
   
38
 
Margin Deposits
   
88
   
120
 
Prepayments and Other
   
90
   
71
 
TOTAL
   
3,163
   
3,588
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
17,736
   
16,787
 
Transmission
   
7,094
   
7,018
 
Distribution
   
11,539
   
11,338
 
Other (including coal mining and nuclear fuel)
   
3,423
   
3,405
 
Construction Work in Progress
   
2,902
   
3,473
 
Total
   
42,694
   
42,021
 
Accumulated Depreciation and Amortization
   
(15,391
)
 
(15,240
)
TOTAL - NET
   
27,303
   
26,781
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
2,385
   
2,477
 
Securitized Transition Assets
   
2,134
   
2,158
 
Spent Nuclear Fuel and Decommissioning Trusts
   
1,263
   
1,248
 
Goodwill
   
76
   
76
 
Long-term Risk Management Assets
   
351
   
378
 
Employee Benefits and Pension Assets
   
316
   
327
 
Deferred Charges and Other
   
945
   
910
 
TOTAL
   
7,470
   
7,574
 
               
Assets Held for Sale
   
-
   
44
 
               
TOTAL ASSETS
 
$
37,936
 
$
37,987
 

See Condensed Notes to Condensed Consolidated Financial Statements.
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2007 and December 31, 2006
(Unaudited)