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)


           
2007
 
2006
 
CURRENT LIABILITIES
 
(in millions)
 
Accounts Payable
$
1,263
 
$
1,360
 
Short-term Debt
 
175
   
18
 
Long-term Debt Due Within One Year
 
1,377
   
1,269
 
Risk Management Liabilities
 
403
   
541
 
Customer Deposits
 
315
   
339
 
Accrued Taxes
 
758
   
781
 
Accrued Interest
 
247
   
186
 
Other
 
770
   
962
 
TOTAL
 
5,308
   
5,456
 
             
NONCURRENT LIABILITIES
           
Long-term Debt
 
12,525
   
12,429
 
Long-term Risk Management Liabilities
 
219
   
260
 
Deferred Income Taxes
 
4,581
   
4,690
 
Regulatory Liabilities and Deferred Investment Tax Credits
 
2,759
   
2,910
 
Asset Retirement Obligations
 
1,035
   
1,023
 
Employee Benefits and Pension Obligations
 
829
   
823
 
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2
 
146
   
148
 
Deferred Credits and Other
 
933
   
775
 
TOTAL
 
23,027
   
23,058
 
             
TOTAL LIABILITIES
 
28,335
   
28,514
 
             
Cumulative Preferred Stock Not Subject to Mandatory Redemption
 
61
   
61
 
             
Commitments and Contingencies (Note 4)
           
             
COMMON SHAREHOLDERS’ EQUITY
           
Common Stock Par Value $6.50:
           
     
2007
   
2006
             
Shares Authorized
   
600,000,000
   
600,000,000
             
Shares Issued
   
419,667,962
   
418,174,728
             
(21,499,992 shares were held in treasury at March 31, 2007 and December 31, 2006)
 
2,728
   
2,718
 
Paid-in Capital
 
4,270
   
4,221
 
Retained Earnings
 
2,795
   
2,696
 
Accumulated Other Comprehensive Income (Loss)
 
(253
)
 
(223
)
TOTAL
 
9,540
   
9,412
 
             
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
$
37,936
 
$
37,987
 

See Condensed Notes to Condensed Consolidated Financial Statements.
 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007 and 2006
(in millions)
(Unaudited)


   
2007
 
2006
 
OPERATING ACTIVITIES
           
Net Income
 
$
271
 
$
381
 
Less: Discontinued Operations, Net of Tax
   
-
   
(3
)
Income before Discontinued Operations
   
271
   
378
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
391
   
348
 
Deferred Income Taxes
   
5
   
7
 
Deferred Investment Tax Credits
   
(6
)
 
(7
)
Carrying Costs Income
   
(8
)
 
(30
)
Mark-to-Market of Risk Management Contracts
   
22
   
(9
)
Amortization of Nuclear Fuel
   
16
   
14
 
Deferred Property Taxes
   
(67
)
 
(82
)
Fuel Over/Under-Recovery, Net
   
(62
)
 
103
 
Gain on Sales of Assets and Equity Investments, Net
   
(23
)
 
(71
)
Change in Other Noncurrent Assets
   
44
   
45
 
Change in Other Noncurrent Liabilities
   
16
   
10
 
Changes in Certain Components of Working Capital:
             
Accounts Receivable, Net
   
(29
)
 
214
 
Fuel, Materials and Supplies
   
(3
)
 
(50
)
Margin Deposits
   
33
   
50
 
Accounts Payable
   
(31
)
 
(115
)
Accrued Taxes
   
32
   
176
 
Customer Deposits
   
(23
)
 
(157
)
Other Current Assets
   
(40
)
 
19
 
Other Current Liabilities
   
(187
)
 
(260
)
Net Cash Flows From Operating Activities
   
351
   
583
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(907
)
 
(765
)
Change in Other Temporary Cash Investments, Net
   
(20
)
 
27
 
Purchases of Investment Securities
   
(3,693
)
 
(2,469
)
Sales of Investment Securities
   
3,929
   
2,380
 
Proceeds from Sales of Assets
   
68
   
111
 
Other
   
(5
)
 
(34
)
Net Cash Flows Used For Investing Activities
   
(628
)
 
(750
)
               
FINANCING ACTIVITIES
             
Issuance of Common Stock
   
54
   
5
 
Change in Short-term Debt, Net
   
157
   
216
 
Issuance of Long-term Debt
   
247
   
55
 
Retirement of Long-term Debt
   
(49
)
 
(142
)
Dividends Paid on Common Stock
   
(155
)
 
(146
)
Other
   
(19
)
 
54
 
Net Cash Flows From Financing Activities
   
235
   
42
 
               
Net Decrease in Cash and Cash Equivalents
   
(42
)
 
(125
)
Cash and Cash Equivalents at Beginning of Period
   
301
   
401
 
Cash and Cash Equivalents at End of Period
 
$
259
 
$
276
 
               
SUPPLEMENTARY INFORMATION
             
Cash Paid for Interest, Net of Capitalized Amounts
 
$
152
 
$
159
 
Net Cash Paid for Income Taxes
   
66
   
13
 
Noncash Acquisitions Under Capital Leases
   
11
   
20
 
Construction Expenditures Included in Accounts Payable at March 31,
   
323
   
246
 
               
See Condensed Notes to Condensed Consolidated Financial Statements.
             

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS’ EQUITY AND
COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2007 and 2006
(in millions)
(Unaudited)

   
Common Stock
         
Accumulated Other Comprehensive Income (Loss)
     
   
Shares
 
Amount
 
Paid-in Capital
 
Retained Earnings
   
Total
 
DECEMBER 31, 2005
   
415
 
$
2,699
 
$
4,131
 
$
2,285
 
$
(27
)
$
9,088
 
Issuance of Common Stock
         
1
   
4
               
5
 
Common Stock Dividends
                     
(146
)
       
(146
)
Other
               
2
               
2
 
TOTAL
                                 
8,949
 
                                       
COMPREHENSIVE INCOME
                                     
Other Comprehensive Income, Net of Tax:
                                     
 
Cash Flow Hedges, Net of Tax of $19
                           
35
   
35
 
 
Securities Available for Sale, Net of Tax of $10
                           
19
   
19
 
NET INCOME
                     
381
         
381
 
TOTAL COMPREHENSIVE INCOME
                                 
435
 
MARCH 31, 2006
   
415
 
$
2,700
 
$
4,137
 
$
2,520
 
$
27
 
$
9,384
 
                                       
DECEMBER 31, 2006
   
418
 
$
2,718
 
$
4,221
 
$
2,696
 
$
(223
)
$
9,412
 
                                       
FIN 48 Adoption, Net of Tax
                     
(17
)
       
(17
)
Issuance of Common Stock
   
2
   
10
   
44
               
54
 
Common Stock Dividends
                     
(155
)
       
(155
)
Other
               
5
               
5
 
TOTAL
                                 
9,299
 
                                       
COMPREHENSIVE INCOME
                                     
Other Comprehensive Loss, Net of Tax:
                                     
 
Cash Flow Hedges, Net of Tax of $12
                           
(22
)
 
(22
)
 
Securities Available for Sale, Net of Tax of $4
                           
(8
)
 
(8
)
NET INCOME
                     
271
         
271
 
TOTAL COMPREHENSIVE INCOME
                                 
241
 
MARCH 31, 2007
   
420
 
$
2,728
 
$
4,270
 
$
2,795
 
$
(253
)
$
9,540
 

   See Condensed Notes to Condensed Consolidated Financial Statements.

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX TO CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

   
 1.
Significant Accounting Matters
 2.
New Accounting Pronouncements
3.
Rate Matters
 4.
Commitments, Guarantees and Contingencies
5.
Acquisitions, Dispositions, Discontinued Operations and Assets Held for Sale
6.
Benefit Plans
7.
Business Segments
8.
Income Taxes
9.
Financing Activities

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

         1. SIGNIFICANT ACCOUNTING MATTERS

General

The accompanying unaudited condensed consolidated financial statements and footnotes were prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all the information and footnotes required by GAAP for complete financial statements.

In the opinion of management, the unaudited interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods. The results of operations for the three months ended March 31, 2007 are not necessarily indicative of results that may be expected for the year ending December 31, 2007. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2006 consolidated financial statements and notes thereto, which are included in our Annual Report on Form 10-K for the year ended December 31, 2006 as filed with the SEC on February 28, 2007.

Components of Accumulated Other Comprehensive Income (Loss) (AOCI)

AOCI is included on the Condensed Consolidated Balance Sheets in the common shareholders’ equity section. The following table provides the components that constitute the balance sheet amount in AOCI:

   
March 31,
 
December 31,
 
   
2007
 
2006
 
Components
 
(in millions)
 
Securities Available for Sale, Net of Tax
 
$
10
 
$
18
 
Cash Flow Hedges, Net of Tax
   
(28
)
 
(6
)
SFAS 158 Adoption, Net of Tax
   
(235
)
 
(235
)
Total
 
$
(253
)
$
(223
)

At March 31, 2007, we expect to reclassify approximately $11 million of net losses from cash flow hedges in AOCI to Net Income during the next twelve months at the time the hedged transactions affect Net Income. The actual amounts that are reclassified from AOCI to Net Income can differ as a result of market fluctuations.

At March 31, 2007, thirty-nine months is the maximum length of time that our exposure to variability in future cash flows is hedged with contracts designated as cash flow hedges.

Earnings Per Share (EPS)

The following table presents our basic and diluted EPS calculations included on our Condensed Consolidated Statements of Income:

   
Three Months Ended March 31,
 
   
2007
 
2006
 
   
(in millions, except per share data)
 
        
$/share
      
$/share
 
Earnings Applicable to Common Stock
 
$
271
       
$
381
       
                           
Average Number of Basic Shares Outstanding
   
397.3
 
$
0.68
   
393.7
 
$
0.97
 
Average Dilutive Effect of:
                         
Performance Share Units
   
0.6
   
-
   
1.4
   
(0.01
)
Stock Options
   
0.5
   
-
   
0.3
   
-
 
Restricted Stock Units
   
0.1
   
-
   
0.1
   
-
 
Restricted Shares
   
0.1
   
-
   
0.1
   
-
 
Average Number of Diluted Shares Outstanding
   
398.6
 
$
0.68
   
395.6
 
$
0.96
 

The assumed conversion of our share-based compensation does not affect net earnings for purposes of calculating diluted earnings per share as of March 31, 2007.

Options to purchase 0.1 million and 0.4 million shares of common stock were outstanding at March 31, 2007 and 2006, respectively, but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the quarter-end market price of the common shares and, therefore, the effect would be antidilutive.

Supplementary Information
   
Three Months Ended
March 31,
 
   
2007
 
2006
 
Related Party Transactions
 
(in millions)
 
AEP Consolidated Purchased Energy:
           
Ohio Valley Electric Corporation (43.47% Owned)
 
$
49
 
$
55
 
Sweeny Cogeneration Limited Partnership (50% Owned)
   
30
   
34
 
AEP Consolidated Other Revenues - Barging and Other 
  Transportation Services - Ohio Valley Electric Corporation (43.47% Owned)
   
9
   
7
 

Reclassifications

Certain prior period financial statement items have been reclassified to conform to current period presentation.

On our 2006 Condensed Consolidated Statement of Income, we reclassified regulatory credits related to regulatory asset cost deferral on ARO from Depreciation and Amortization to Other Operation and Maintenance to offset the ARO accretion expense. These reclassifications totaled $7 million for the three months ended March 31, 2006.

In our segment information, we reclassified two subsidiary companies, AEP Texas Commercial & Industrial Retail GP, LLC and AEP Texas Commercial & Industrial Retail LP, from the Utility Operations segment to the Generation and Marketing segment. Combined revenues for these companies totaled $5 million for the three months ended March 31, 2006. As a result, on our 2006 Condensed Consolidated Statement of Income, we reclassified these revenues from Utility Operations to Other.

These revisions had no impact on our previously reported results of operations, cash flows or changes in shareholders’ equity.


         2. NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of exposure drafts or final pronouncements, we thoroughly review the new accounting literature to determine the relevance, if any, to our business. The following represents a summary of new pronouncements issued or implemented in 2007 and standards issued but not implemented that we have determined relate to our operations.

SFAS 157 “Fair Value Measurements” (SFAS 157)

In September 2006, the FASB issued SFAS 157, enhancing existing guidance for fair value measurement of assets and liabilities and instruments measured at fair value that are classified in shareholders’ equity. The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures. It emphasizes that fair value is market-based with the highest measurement hierarchy being market prices in active markets. The standard requires fair value measurements be disclosed by hierarchy level and an entity include its own credit standing in the measurement of its liabilities and modifies the transaction price presumption.

SFAS 157 is effective for interim and annual periods in fiscal years beginning after November 15, 2007. We expect that the adoption of this standard will impact MTM valuations of certain contracts, but we are unable to quantify the effect. Although the statement is applied prospectively upon adoption, the effect of certain transactions is applied retrospectively as of the beginning of the fiscal year of application, with a cumulative effect adjustment to the appropriate balance sheet items. We will adopt SFAS 157 effective January 1, 2008.

SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159)

In February 2007, the FASB issued SFAS 159, permitting entities to choose to measure many financial instruments and certain other items at fair value. The standard also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities.

SFAS 159 is effective for annual periods in fiscal years beginning after November 15, 2007. If the fair value option is elected, the effect of the first remeasurement to fair value is reported as a cumulative effect adjustment to the opening balance of retained earnings. If we elect the fair value option promulgated by this standard, the valuations of certain assets and liabilities may be impacted. The statement is applied prospectively upon adoption. We will adopt SFAS 159 effective January 1, 2008.

FIN 48 “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1 "Definition of Settlement in FASB Interpretation No. 48"
 
In July 2006, the FASB issued FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” and in May 2007, the FASB issued FASB Staff Position FIN 48-1 “Definition of Settlement in FASB Interpretation No. 48.” 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, with an unfavorable adjustment to retained earnings of $17 million.

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued by FASB, we cannot determine the impact on the reporting of our operations and financial position that may result from any such future changes. The FASB is currently working on several projects including business combinations, revenue recognition, liabilities and equity, derivatives disclosures, emission allowances, earnings per share calculations, leases, insurance, subsequent events and related tax impacts. We also expect to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP. The ultimate pronouncements resulting from these and future projects could have an impact on our future results of operations and financial position.

         3. RATE MATTERS 

As discussed in our 2006 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 2006 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact results of operations, cash flows and possibly financial condition. The following discusses ratemaking developments in 2007 and updates the 2006 Annual Report.

Ohio Rate Matters

Ohio Restructuring and Rate Stabilization Plans

In January 2007, CSPCo and OPCo 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. Pursuant to the RSPs, CSPCo and OPCo implemented these proposed increases effective with the beginning of the May 2007 billing cycle. 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. The PAR is intended to recover the difference between CSPCo's tariffed generation service rates and the cost of power acquired to serve the former Monongahela Power load. The PAR was set for an initial 17-month period of January 2006 through May 2007. The filing would adjust the PAR for the nineteen month period of June 2007 through December 2008. The filing reflects a true up for estimated under-recoveries during the initial period, $8 million as of March 31, 2007, as well as the power acquisition costs for the upcoming nineteen-month period. If approved, CSPCo's revenues would increase by $22 million and $38 million for 2007 and 2008, respectively.
 
In March 2007, CSPCo and OPCo filed a settlement agreement at the PUCO resolving the Ohio Supreme Court's remand of the PUCO’s RSP order. The Supreme Court indicated concern with the absence of a competitive bid process as an alternative to the generation rates set by the RSP. In response, the settling parties agreed to have CSPCo and OPCo take bids for Renewable Energy Certificates (RECs). CSPCo and OPCo will give customers the option to pay a generation rate premium that would encourage the development of renewable energy sources by reimbursing CSPCo and OPCo for the cost of the RECs and the administrative costs of the program. This settlement agreement was supported by the Office of Consumers' Counsel, the Ohio Partners for Affordable Energy, the Ohio Energy Group and the PUCO staff. In May 2007, the PUCO adopted the settlement agreement in its entirety.

CSPCo and OPCo are involved in discussions with various stakeholders in Ohio about potential legislation to address the period following the expiration of the RSPs on December 31, 2008. At this time, management is unable to predict whether CSPCo and OPCo will transition to market pricing, as permitted by the current Ohio restructuring legislation, extend their RSP rates, with or without modification, or become subject to a legislative reinstatement of some form of cost-based regulation for their generation supply business on January 1, 2009 when the RSP period ends.

Customer Choice Deferrals

As provided in the restructuring settlement agreement approved by the PUCO in 2000, CSPCo and OPCo established regulatory assets for customer choice implementation costs and related carrying costs in excess of $20 million each for recovery in the next general base rate filing which changes distribution rates after December 31, 2007 for OPCo and December 31, 2008 for CSPCo. Pursuant to the RSPs, recovery of these amounts for OPCo was further deferred until the next base rate filing to change distribution rates after the end of the RSP period of December 31, 2008. Through March 31, 2007, CSPCo and OPCo incurred $50 million and $51 million, respectively, of such costs and established regulatory assets of $25 million each for such costs. CSPCo and OPCo have not recognized $5 million and $6 million, respectively, of equity carrying costs, which are recognizable when collected. Management believes that the deferred customer choice implementation costs were prudently incurred to implement customer choice in Ohio and are probable of recovery in future distribution rates.

IGCC Plant

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

Distribution Reliability Plan

In January 2006, CSPCo and OPCo initiated a proceeding at the PUCO seeking a new distribution rate rider to fund enhanced distribution reliability programs. In the fourth quarter of 2006, as directed by the PUCO, CSPCo and OPCo filed a proposed enhanced reliability plan. The plan contemplated CSPCo and OPCo recovering approximately $28 million and $43 million, respectively, in additional distribution revenue during an eighteen month period beginning July 2007. In January 2007, the OCC filed testimony, which argued that CSPCo and OPCo should be required to improve distribution service reliability with funds from their existing rates.

In April 2007, CSPCo and OPCo filed a joint motion with the PUCO staff, the Ohio Consumers’ Counsel, the Appalachian People’s Action Coalition, the Ohio Partners for Affordable Energy and the Ohio Manufacturers Association to withdraw the proposed enhanced reliability plan.

Ormet

Effective January 1, 2007, CSPCo and OPCo began to serve Ormet, a major industrial customer with a 520 MW load, under a PUCO encouraged settlement agreement. The settlement agreement between CSPCo and OPCo, Ormet, its employees’ union and certain other interested parties was approved by the PUCO in November 2006. The settlement agreement provides for the recovery in 2007 and 2008 by CSPCo and OPCo of the difference between $43 per MWH to be paid by Ormet for power and a PUCO approved market price, if higher. The recovery will be accomplished by the amortization of a $57 million ($15 million for CSPCo and $42 million for OPCo) Ohio franchise tax phase-out regulatory liability recorded in 2005 and, if that is not sufficient, an increase in RSP generation rates under the additional 4% provision of the RSPs. The $43 per MWH price to be paid by Ormet for generation services is above the industrial RSP generation tariff but below current market prices. In December 2006, CSPCo and OPCo submitted a market price of $47.69 per MWH for 2007, which is pending PUCO approval. If the PUCO approves a lower market price, it could have an adverse effect on results of operations and cash flows. If CSPCo and OPCo serve the Ormet load after 2008 without any special provisions, they could experience incremental costs to acquire additional capacity to meet their reserve requirements and/or forgo off-system sales margins, which could have an adverse effect on future results of operations and cash flows.

Texas Rate Matters

TCC TEXAS RESTRUCTURING

Texas District Court Appeal Proceedings

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. See “TCC and TNC Deferred Fuel” andTCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes” sections below.

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. The judge directed that these matters should be remanded to the PUCT to determine the 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.

OTHER TEXAS RESTRUCTURING MATTERS

TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes

In TCC’s 2006 true-up and securitization orders, the PUCT reduced net regulatory assets and the amount to be securitized by $51 million related to the present value of ADITC and by $10 million related to EDFIT associated with TCC’s generation assets for a total reduction of $61 million.

TCC filed a request for a private letter ruling with the IRS in June 2005 regarding the permissibility under the IRS rules and regulations of the ADITC and EDFIT reduction proposed by the PUCT. The IRS issued its private letter ruling in May 2006, which stated that the PUCT’s flow-through to customers of the present value of the ADITC and EDFIT benefits would result in a normalization violation. To address the matter and avoid a normalization violation, the PUCT agreed to allow TCC to defer an amount of the CTC refund totaling $103 million ($61 million in present value of ADITC and EDFIT associated with TCC’s generation assets plus $42 million of related carrying costs) pending resolution of the normalization issue.  If it is ultimately determined that a refund to customers through the true-up process of the ADITC and EDFIT, discussed above, is not a normalization violation, then TCC will be required to refund the $103 million, plus additional carrying costs. However, if such refund of ADITC and EDFIT is ultimately determined to cause a normalization violation, TCC anticipates it will be permitted to retain the $61 million present value of ADITC and EDFIT plus carrying costs, favorably impacting future results of operations.

If a normalization violation occurs, it could result in TCC’s repayment to the IRS of ADITC on all property, including transmission and distribution property, which approximates $104 million as of March 31, 2007, and a loss of TCC’s right to claim accelerated tax depreciation in future tax returns. Tax counsel advised management that a normalization violation should not occur until all remedies under law have been exhausted and the tax benefits are returned to ratepayers under a nonappealable order. Management intends to continue its efforts to avoid a normalization violation that would adversely affect future results of operations and cash flows.

TCC and TNC Deferred Fuel

The TCC deferred fuel over-recovery regulatory liability is a component of the other true-up items net regulatory liability refunded through the CTC rate rider credit. In 2002, TCC and TNC filed with the PUCT seeking to reconcile fuel costs and establish their final deferred fuel balances. In its final fuel reconciliation orders, the PUCT ordered a reduction in TCC’s and TNC’s recoverable fuel costs for, among other things, the reallocation of additional AEP System off-system sales margins under a FERC-approved SIA. Both TCC and TNC appealed the PUCT’s rulings regarding a number of issues in the fuel orders in state court and challenged the jurisdiction of the PUCT over the allocation of off-system sales margin allocations in the federal court. Intervenors also appealed the PUCT’s rulings in state court.

In 2006, the Federal District Court issued orders precluding the PUCT from enforcing the off-system sales reallocation portion of its ruling in the final TNC and TCC fuel reconciliation proceedings. The Federal court ruled, in both cases, that the FERC, not the PUCT, has jurisdiction over the allocation. The PUCT appealed both Federal District Court decisions to the United States Court of Appeals. In TNC’s case, the Court of Appeals affirmed the District Court’s decision. The PUCT has indicated they will appeal this ruling to the United States Supreme Court. TCC has filed a Motion for Summary Affirmance based on the outcome of the TNC appeal. For TCC, the PUCT has conceded the issue concerning the allocation of off-system sales margins to AEP West companies under the SIA as governed by the TNC case. However, the PUCT continues to challenge the allocation of those margins among AEP West companies under the CSW Operating Agreement. If the PUCT’s appeals are ultimately unsuccessful, TCC and TNC could record income of $16 million and $8 million, respectively, related to the reversal of the previously recorded fuel over-recovery regulatory liabilities.

If the PUCT is unsuccessful in the federal court system, it or another interested party may file a complaint at the FERC to address the allocation issue. If a complaint at the FERC results in the PUCT’s decisions being adopted by the FERC, there could be an adverse effect on results of operations and cash flows. An unfavorable FERC ruling may result in a retroactive reallocation of off-system sales margins from AEP East companies to AEP West companies under the then existing SIA allocation method. If the adjustments were applied retroactively, the AEP East companies may be unable to recover the amounts reallocated to the West companies from their customers due to past frozen rates, past inactive fuel clauses and fuel clauses that do not include off-system sales credits. Although management cannot predict the ultimate outcome of this federal litigation, management believes that its allocations were in accordance with the then existing FERC-approved SIA and that it should not have to allocate additional off-system sales margins to the West companies including TCC and TNC.

In January 2007, TCC began refunding as part of the CTC rate rider credit described above, $149 million of its $165 million over-recovered deferred fuel regulatory liability. The remaining $16 million refund related to the favorable Federal District Court order has been deferred pending the outcome of the federal court appeal and would be subject to refund only upon a successful appeal by the PUCT.

Excess Earnings

In 2005, the Texas Court of Appeals issued a decision finding the PUCT’s prior order from the unbundled cost of service case requiring TCC to refund excess earnings prior to and outside of the true-up process was unlawful under the Texas Restructuring Legislation. TCC refunded $55 million of excess earnings, including interest, of which $30 million went to the affiliated REP. In November 2005, the PUCT filed a petition for review with the Supreme Court of Texas seeking reversal of the Texas Court of Appeals’ decision. The Supreme Court of Texas requested briefing, which has been provided, but it has not decided whether it will hear the case. If the Court of Appeals decision is upheld and the refund mechanism is found to be unlawful, the impact on TCC would then depend on: (a) how and if TCC is ordered by the PUCT to refund the excess earnings through the true-up process to ultimate customers and (b) whether TCC will be able to recover the amounts previously refunded to the REPs including the REP TCC sold to Centrica. Management is unable to predict the ultimate outcome of this litigation and its effect on future results of operations and cash flows.
 
OTHER TEXAS RATE MATTERS

TCC and TNC Energy Delivery Base Rate Filings

TCC and TNC each filed a base rate case seeking to increase transmission and distribution energy delivery services (wires) base rates in Texas. TCC and TNC requested $81 million and $25 million in annual increases, respectively. Both requests include a return on common equity of 11.25% and the impact of the expiration of the CSW merger savings rate credits. In March 2007, various intervenors and the PUCT staff filed their recommendations. 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. The recommended return on common equity ranged from 9.00% to 9.75%. In April 2007, TCC and TNC filed rebuttal testimony reducing the requested annual increases to $70 million for TCC and $22 million for TNC including a reduced requested return on common equity of 10.75%. Hearings began in April 2007 and are scheduled to conclude in May 2007. Management expects the new base wires rates to become effective, subject to refund, in the second quarter of 2007 with a decision from the PUCT expected in the third quarter of 2007. Management is unable to predict the ultimate effect of this filing on future results of operations, cash flows and financial condition.

SWEPCo Fuel Reconciliation - Texas

In June 2006, SWEPCo filed a fuel reconciliation proceeding with the PUCT for its Texas retail operations. SWEPCo sought, in the proceedings, to include under-recoveries related to the reconciliation period of $50 million. In January 2007, intervenors filed testimony recommending that SWEPCo’s reconcilable fuel costs be reduced. The intervenor recommendations ranged from a $10 million to $28 million reduction. In February 2007, the PUCT staff filed testimony recommending that SWEPCo’s reconcilable fuel costs be reduced by $10 million. SWEPCo does not agree with the intervenor’s or staff’s recommendations and filed rebuttal testimony in February 2007. Hearings have been held and briefs have been filed. Results of operations could be adversely affected by $28 million plus carrying costs if the PUCT adopts all of the intervenor and staff recommendations. Management is unable to predict the outcome of this proceeding or its effect on future results of operations and cash flows.
 
Virginia Rate Matters 

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 transmission and distribution 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, subject to Virginia SCC approval, certain environmental retrofits, and a floor on the allowed return on equity based on the average earned return on equities’ of regional vertically integrated electric utilities. Effective July 1, 2007, the amendments allow utilities to retain a minimum of 25% of the margins from off-system sales with the remaining margins from such sales credited against fuel factor expenses. 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.

APCo Virginia Base Rate Case

In May 2006, APCo filed a request with the Virginia SCC seeking an increase in base rates of $225 million to recover increasing costs including the cost of its investment in environmental equipment and a return on equity of 11.5%. In addition, APCo requested to move off-system sales margins, currently credited to customers through base rates, to the fuel factor where they can be trued-up to actual. APCo also proposed to share the off-system sales margins with customers with 40% going to reduce rates and 60% being retained by APCo. This proposed off-system sales fuel rate credit, which is estimated to be $27 million, partially offsets the $225 million requested increase in base rates for a net increase in base rate revenues of $198 million. The major components of the $225 million base rate request include $73 million for the impact of removing off-system sales margins from the rate year ending September 30, 2007, $60 million mainly due to projected net environmental plant additions through September 30, 2007 and $48 million for return on equity.

In May 2006, the Virginia SCC issued an order, consistent with Virginia law, placing the net requested base rate increase of $198 million into effect on October 2, 2006, subject to refund. The $198 million base rate increase being collected, subject to refund, includes recovery of incremental environmental compliance and transmission and distribution system reliability (E&R) costs projected to be incurred during the rate year beginning October 2006. These incremental E&R costs can be deferred and recovered through the E&R surcharge mechanism if not recovered through this base rate request. In October 2006, the Virginia SCC staff filed its direct testimony recommending a base rate increase of $13 million with a return on equity of 9.9% and no off-system sales margin sharing. Other intervenors have recommended base rate increases ranging from $42 million to $112 million. APCo filed rebuttal testimony in November 2006. Hearings were held in December 2006.

In March 2007, the Hearing Examiner (HE) 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. The HE’s recommendations include a return on equity of 10.1% which would reduce APCo’s revenue requirement by approximately $23 million. The HE also recommended limiting forward looking ratemaking adjustments to June 30, 2006 as opposed to September 30, 2007, which would reduce APCo’s revenue requirement by approximately $72 million, of which approximately $60 million relates to incremental E&R costs that can be deferred for future recovery through the E&R surcharge mechanism. The HE further proposed to share the off-system sales margins using the twelve months ended June 30, 2006 of $101 million with 50% reducing base rates, 45% reducing fuel rates and 5% retained by APCo to determine the revenue requirement. APCo’s proposal did not reduce base rates for off-system sales margins, but reduced fuel rates approximately $27 million for off-system sales margins. APCo expects a final order to be issued during 2007.

APCo is providing for a possible refund of revenues collected subject to refund consistent with the HE recommendations. Management is unable to predict the ultimate effect of this filing on future results of operations, cash flows and financial condition.

West Virginia Rate Matters

APCo and WPCo ENEC Filing

In April 2007, the WVPSC issued an order establishing an investigation and hearing of APCo’s and WPCo’s 2007 Expanded Net Energy Cost (ENEC) compliance filing. The ENEC is an expanded form of fuel clause mechanism, which includes all energy-related costs including fuel, purchased power expenses, off-system sales credits and other energy/transmission items. In the March 2007 ENEC joint filing, APCo and WPCo filed for an increase of approximately $101 million including a $72 million increase in ENEC and a $29 million increase in construction surcharges to become effective July 1, 2007. A hearing on the compliance filing is scheduled for May 2007.

APCo IGCC

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.
 
Indiana Rate Matters

I&M Depreciation Study Filing

In February 2007, I&M filed a request with the IURC for approval of revised book depreciation rates effective January 1, 2007. The filing included a settlement agreement entered into with the Indiana Office of the Utility Consumer Counsel that would provide direct benefits to I&M's customers if new depreciation rates are approved by the IURC. The direct benefits would include a $5 million credit to fuel costs and an approximate $8 million smart metering pilot program. In addition, if the agreement is approved, I&M would initiate a general rate proceeding on or before July 1, 2007 and initiate two studies, one to investigate a general smart metering program and the other to study the market viability of demand side management programs. Based on the depreciation study included in the filing, I&M recommended a decrease in pretax annual depreciation expense on an Indiana jurisdictional basis of approximately $69 million reflecting an NRC-approved 20-year extension of the Cook Plant licenses for Units 1 and 2 and an extension of the service life of the Tanners Creek coal-fired generating units. This petition was not a request for a change in customers’ electric service rates. As proposed, the book depreciation reduction would increase earnings but would not impact cash flows until rates are revised. The IURC held a public hearing in April 2007. I&M requested expeditious review and approval of its filing, but management cannot predict the outcome of the request or the timing of any approved depreciation reduction. If approved as filed, pretax earnings would increase by $64 million in 2007.

Kentucky Rate Matters

KPCo Environmental Surcharge Filing

In July 2006, KPCo filed for approval of an amended environmental compliance plan and revised tariff to implement an adjusted environmental surcharge. KPCo estimates the amended environmental compliance plan and revised tariff would increase revenues over 2006 levels by approximately $2 million in 2007 and $6 million in 2008 for a total of $8 million of additional revenue at current cost projections. In January 2007, the KPSC issued an order approving KPCo’s proposed plan and surcharge. Future recovery is based upon actual environmental costs and is subject to periodic review and approval of those actual costs by the KPSC.

In November 2006, the Kentucky Attorney General and the Kentucky Industrial Utility Consumers (KIUC) filed an appeal with the Kentucky Court of Appeals of the Franklin Circuit Court’s 2006 order upholding the KPSC’s 2005 Environmental Surcharge order. In its order, the KPSC approved KPCo’s recovery of its environmental costs at its Big Sandy Plant and its share of environmental costs incurred as a result of the AEP Power Pool capacity settlement. The KPSC has allowed KPCo to recover these FERC-approved allocated costs, via the environmental surcharge, since the KPSC’s first environmental surcharge order in 1997. KPCo presently recovers $7 million a year in environmental surcharge revenues.

In March 2007, the KPSC issued an order, at the request of the Kentucky Attorney General, stating the environmental surcharge collections authorized in the January 2007 order that are associated with out-of-state generating facilities should be collected over the six months beginning March 2007, subject to refund, pending the outcome of the court of appeals process. At this time, management is unable to predict the outcome of this proceeding and its effect on KPCo’s current environmental surcharge revenues or on the January 2007 KPSC order increasing KPCo’s environmental rates.

Oklahoma Rate Matters

PSO Fuel and Purchased Power and its Possible Impact on AEP East companies and AEP West companies

In 2002, PSO under-recovered $44 million of fuel costs resulting from a reallocation among AEP West companies of purchased power costs for periods prior to January 1, 2002. In July 2003, PSO proposed collection of those reallocated costs over eighteen months. In August 2003, the OCC staff filed testimony recommending PSO recover $42 million of the reallocated purchased power costs over three years and PSO reduced its regulatory asset deferral by $2 million. The OCC subsequently expanded the case to include a full prudence review of PSO’s 2001 fuel and purchased power practices. In January 2006, the OCC staff and intervenors issued supplemental testimony alleging that AEP deviated from the FERC-approved method of allocating off-system sales margins between AEP East companies and AEP West companies and among AEP West companies. The OCC staff proposed that the OCC offset the $42 million of under-recovered fuel with the proposed reallocation of off-system sales margins of $27 million to $37 million and with $9 million attributed to wholesale customers, which they claimed had not been refunded. In February 2006, the OCC staff filed a report concluding that the $9 million of reallocated purchased power costs assigned to wholesale customers had been refunded, thus removing that issue from its recommendation.

In 2004, an Oklahoma ALJ found that the OCC lacks authority to examine whether PSO deviated from the FERC-approved allocation methodology and held that any such complaints should be addressed at the FERC. The OCC has not ruled on appeals by intervenors of the ALJ’s finding. The United States District Court for the Western District of Texas issued orders in September 2005 regarding a TNC fuel proceeding and in August 2006 regarding a TCC fuel proceeding, preempting the PUCT from reallocating off-system sales margins between the AEP East companies and AEP West companies. The federal court agreed that the FERC has sole jurisdiction over that allocation. The PUCT appealed the ruling. The United States Court of Appeals for the Fifth Circuit, issued a decision in December 2006 regarding the TNC fuel proceeding that affirmed the United States District Court ruling.

PSO does not agree with the intervenors’ and the OCC staff’s recommendations and proposals other than the staff’s original recommendation that PSO be allowed to recover the $42 million over three years and will defend its right to recover its under-recovered fuel balance. Management believes that if the position taken by the federal courts in the Texas proceeding is applied to PSO’s case, then the OCC should be preempted from disallowing fuel recoveries for alleged improper allocations of off-system sales margins between AEP East companies and AEP West companies. The OCC or another party could file a complaint at the FERC alleging the allocation of off-system sales margins to PSO is improper, which could result in an adverse effect on future results of operations and cash flows for AEP and the AEP East companies. However, to date, there has been no claim asserted at the FERC that AEP deviated from the approved allocation methodologies, but even if one were asserted, management believes that it would not prevail. 

In June 2005, the OCC issued an order directing its staff to conduct a prudence review of PSO’s fuel and purchased power practices for the year 2003. The OCC staff filed testimony finding no disallowances in the test year data. The Attorney General of Oklahoma filed testimony stating that they could not determine if PSO’s gas procurement activities were prudent, but did not include a recommended disallowance. However, an intervenor filed testimony in June 2006 proposing the disallowance of $22 million in fuel costs based on a historical review of potential hedging opportunities that he alleges existed during the year. A hearing was held in August 2006 and management expects a recommendation from the ALJ in 2007. 

In February 2006, a law was enacted requiring the OCC to conduct prudence reviews on all generation and fuel procurement processes, practices and costs on either a two or three-year cycle depending on the number of customers served. PSO is subject to the required biennial reviews. In compliance with an OCC order, PSO is required to file its testimony by June 15, 2007. This proceeding will cover the year 2005.

Management cannot predict the outcome of the pending fuel and purchased power reviews or planned future reviews, but believes that PSO’s fuel and purchased power procurement practices and costs are prudent and properly incurred. If the OCC disagrees and disallows fuel or purchased power costs including the unrecovered 2002 reallocation of such costs incurred by PSO, it would have an adverse effect on future results of operations and cash flows.

PSO Rate Filing

In November 2006, PSO filed a request to increase base rates $50 million for Oklahoma jurisdictional customers with a proposed effective date in the second quarter of 2007. PSO sought a return on equity of 11.75%. PSO also proposed a formula rate plan that, if approved as filed, will permit PSO to defer any unrecovered costs as a result of a revenue deficiency that exceeds 50 basis points of the allowed return on equity for recovery within twelve months beginning six months after the test year. The formula would enable PSO to recover on a timely basis the cost of its new generation, transmission and distribution construction (including carrying costs during construction), provide the opportunity to achieve the approved return on equity and avoid recording a significant AFUDC that would have been recorded during the construction time period.

In March 2007, the OCC staff and various intervenors filed testimony. The recommendations were base rate reductions that ranged from $18 million to $52 million. The recommended returns on equity ranged from 9.25% to 10.09%. These recommendations included reductions in depreciation expense of approximately $25 million, which has no earnings impact. The OCC staff filed testimony supporting a formula rate plan, generally similar to the one proposed by PSO. In April 2007, PSO filed rebuttal testimony regarding various issues raised by the OCC Staff and the intervenors. As a result of rebuttal testimony, PSO reduced its base rate request by $2 million. Hearings commenced on May 1, 2007.

Management is unable to predict the outcome of these proceedings, however, if rates are not increased in an amount sufficient to recover expected unavoidable cost increases future results of operations, cash flows and possibly financial condition could be adversely affected.

PSO Lawton and Peaking Generation Settlement Agreement

On November 26, 2003, pursuant to an application by Lawton Cogeneration, L.L.C. (Lawton) seeking approval of a Power Supply Agreement (the Agreement) with PSO and associated avoided cost payments, the OCC issued an order approving the Agreement and setting the avoided costs.
 
In December 2003, PSO filed an appeal of the OCC’s order with the Oklahoma Supreme Court (the Court). In the appeal, PSO maintained that the OCC exceeded its authority under state and federal laws to require PSO to enter into the Agreement. The Court issued a decision on June 21, 2005, affirming portions of the OCC’s order and remanding certain provisions. The Court affirmed the OCC’s finding that Lawton established a legally enforceable obligation and ruled that it was within the OCC’s discretion to award a 20-year contract and to base the capacity payment on a peaking unit. The Court directed the OCC to revisit its determination of PSO’s avoided energy cost. Hearings were held on the remanded issues in April and May 2006.

In April 2007, all parties in the case filed a settlement agreement with the OCC resolving all issues. The OCC approved the settlement agreement in April 2007. The settlement agreement provides for a purchase fee of $35 million to be paid by PSO to Lawton and for Lawton to provide, at PSO’s direction, all rights to the Lawton 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 through a rider, subject to a $135 million cost cap, all of the traditional costs associated with plant in service of its new peaking units to be located at the Southwestern Station and Riverside Station at the time these units are placed in service.  PSO may request approval from the OCC for recovery of costs exceeding the cost cap if special circumstances occurred necessitating a higher level of costs. Such costs will continue to 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. Once the cost recovery for the new peaking units begins in mid-2008, PSO expects annual revenues of an estimated $36 million related to cost recovery of the peaking units and the purchase fee. This settlement agreement was supported by the OCC Staff, the Attorney General, the Oklahoma Industrial Energy Consumers and Lawton Cogeneration, L.L.C.

Louisiana Rate Matters

SWEPCo Louisiana Compliance Filing

In October 2002, SWEPCo filed with the LPSC detailed financial information typically utilized in a revenue requirement filing, including a jurisdictional cost of service. This filing was required by the LPSC as a result of its order approving the merger between AEP and CSW. Due to multiple delays, in April 2006, the LPSC and SWEPCo agreed to update the financial information based on a 2005 test year. SWEPCo filed updated financial review schedules in May 2006 showing a return on equity of 9.44% compared to the previously authorized return on equity of 11.1%.

In July 2006, the LPSC staff’s consultants filed direct testimony recommending a base rate reduction in the range of $12 million to $20 million for SWEPCo’s Louisiana jurisdiction customers, based on a proposed 10% return on equity. The recommended reduction range is subject to SWEPCo validating certain ongoing operations and maintenance expense levels. SWEPCo filed rebuttal testimony in October 2006 strongly refuting the consultants’ recommendations. In December 2006, the LPSC staff’s consultants filed reply testimony asserting that SWEPCo’s Louisiana base rates are excessive by $17 million which includes a proposed return on equity of 9.8%. SWEPCo filed rebuttal testimony in January 2007. A decision is not expected until mid or late 2007. At this time, management is unable to predict the outcome of this proceeding. If a rate reduction is ultimately ordered, it would adversely impact future results of operations, cash flows and possibly financial condition.

FERC Rate Matters

Transmission Rate Proceedings at the FERC

The FERC PJM Regional Transmission Rate Proceeding

At AEP’s urging, the FERC instituted an investigation of PJM’s zonal rate regime, indicating that the present rate regime may need to be replaced through establishment of regional rates that would compensate AEP and other transmission owners for the regional transmission facilities they provide to PJM, which provides service for the benefit of customers throughout PJM. In September 2005, AEP and a nonaffiliated utility (Allegheny Power or AP) jointly filed a regional transmission rate design proposal with the FERC. This filing proposes and supports a new PJM rate regime generally referred to as Highway/Byway.

Parties to the regional rate proceeding proposed the following rate regimes:

·
AEP/AP proposed a Highway/Byway rate design in which:
 
·
The cost of all transmission facilities in the PJM region operated at 345 kV or higher would be included in a “Highway” rate that all load serving entities (LSEs) would pay based on peak demand. The AEP/AP proposal would produce about $125 million in additional revenues per year for AEP from users in other zones of PJM.
 
·
The cost of transmission facilities operating at lower voltages would be collected in the zones where those costs are presently charged under PJM’s existing rate design.
·
Two other utilities, Baltimore Gas & Electric Company (BG&E) and Old Dominion Electric Cooperative (ODEC), proposed a Highway/Byway rate that includes transmission facilities above 200 kV, which would produce lower revenues for AEP than the AEP/AP proposal.
·
In another competing Highway/Byway proposal, a group of LSEs proposed rates that would include existing 500 kV and higher voltage facilities and new facilities above 200 kV in the Highway rate, which would produce considerably lower revenues for AEP than the AEP/AP proposal.
·
In January 2006, the FERC staff issued testimony and exhibits supporting a PJM-wide flat rate or “Postage Stamp” type of rate design that would include all transmission facilities, which would produce higher transmission revenues for AEP than the AEP/AP proposal.

All of these proposals were challenged by a majority of other transmission owners in the PJM region, who favor continuation of the existing PJM rate design which provides AEP with no compensation for through and out traffic on its east zone transmission system. Hearings were held in April 2006 and the ALJ issued an initial decision in July 2006. The ALJ found the existing PJM zonal rate design to be unjust and determined that it should be replaced. The ALJ found that the Highway/Byway rates proposed by AEP/AP and BG&E/ODEC and the Postage Stamp rate proposed by the FERC staff to be just and reasonable alternatives. The ALJ also found FERC staff’s proposed Postage Stamp rate to be just and reasonable and recommended that it be adopted. The ALJ also found that the effective date of the rate change should be April 1, 2006 to coincide with SECA rate elimination. Because the Postage Stamp rate was found to produce greater cost shifts than other proposals, the judge also recommended that the design be phased-in. Without a phase-in, the Postage Stamp method would produce more revenue for AEP than the AEP/AP proposal. The phase-in of Postage Stamp rates would delay the full impact of that result until about 2012.

AEP filed briefs noting exceptions to the initial decision and replies to the exceptions of other parties. AEP argued that a phase-in should not be required. Nevertheless, AEP argued that if the FERC adopts the Postage Stamp rate and a phase-in plan, the revenue collections curtailed by the phase-in should be deferred and paid later with interest.

During 2006, the AEP East companies sought to increase retail rates in most of their states to recover lost T&O and SECA revenues. The status of such state retail rate proceedings is as follows:

·
In Kentucky, KPCo settled a rate case, which provided for the recovery of its share of the transmission revenue reduction in new rates effective March 30, 2006.
·
In Ohio, CSPCo and OPCo recover their FERC-approved OATT that reflects their share of the full transmission revenue requirement retroactive to April 1, 2006 under a May 2006 PUCO order.
·
In West Virginia, APCo settled a rate case, which provided for the recovery of its share of the T&O/SECA transmission revenue reduction beginning July 28, 2006.
·
In Virginia, APCo filed a request for revised rates, which includes recovery of its share of the T&O/SECA transmission revenue reduction starting October 2, 2006, subject to refund.
·
In Indiana, I&M is precluded by a rate cap from raising its rates until July 1, 2007.
·
In Michigan, I&M has not filed to seek recovery of the lost transmission revenues.

In April 2007, the FERC issued an order reversing the ALJ decision. The FERC ruled that the current PJM rate design is just and reasonable. The FERC further ruled that the cost of new facilities of 500 kV and above would be shared among all PJM participants. As a result of this order, the AEP East companies retail customers will be asked to bear the full cost of the existing AEP east transmission zone facilities. However, the AEP East companies customers will also be charged a share of the cost of new 500 kV and higher voltage transmission facilities built in PJM, of which the vast majority for the foreseeable future will not be needed by their customers, but will bolster service and reduce costs in other zones of PJM. The AEP East companies will need to obtain regulatory approvals for recovery of any costs of new facilities that are assigned to them as a result of this order, if upheld. AEP will request rehearing of this order. Management cannot estimate at this time what effect, if any, this order will have on their future construction of new east transmission facilities, results of operations, cash flows and financial condition.

The AEP East companies presently recover from retail customers approximately 85% of the reduction in transmission revenues of $128 million a year. Future results of operations, cash flows and financial condition will continue to be adversely affected in Indiana and Michigan until these lost transmission revenues are recovered in retail rates.

SECA Revenue Subject to Refund

The AEP East companies ceased collecting through-and-out transmission service (T&O) revenues in accordance with FERC orders, and collected 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. As a result, the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund or surcharge. The AEP East companies paid SECA rates to other utilities at considerably lesser amounts than collected. If a refund is ordered, the AEP East companies would also receive refunds related to the SECA rates they paid to third parties. The AEP East companies recognized gross SECA revenues as follows:

   
Gross SECA Revenues Recognized
 
   
(in millions)
 
Year Ended December 31, 2006 (a)
 
$
43
 
Year Ended December 31, 2005
   
163
 
Year Ended December 31, 2004
   
14
 

(a)
Represents revenues through March 31, 2006, when SECA rates expired, and excludes all provisions for refund.

Approximately $19 million of these recorded SECA revenues billed by PJM were never collected. The AEP East companies filed a motion with the FERC to force payment of these uncollected SECA billings.

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. The ALJ also found that the unpaid SECA rates must be paid in the recommended reduced amount.

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 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 reserves of $37 million in net refunds.

In September 2006, AEP, together with Exelon and DP&L, 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.
 
         4. COMMITMENTS, GUARANTEES AND CONTINGENCIES

We are subject to certain claims and legal actions arising in our ordinary course of business. In addition, our business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against us cannot be predicted. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on our financial statements. The Commitments, Guarantees and Contingencies note within our 2006 Annual Report should be read in conjunction with this report.

GUARANTEES

There are certain immaterial liabilities recorded for guarantees in accordance with FASB Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” There is no collateral held in relation to any guarantees in excess of our ownership percentages. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letters Of Credit

We enter into standby letters of credit (LOCs) with third parties. These LOCs cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits, debt service reserves and credit enhancements for issued bonds. As the parent company, we issued all of these LOCs in our ordinary course of business on behalf of our subsidiaries. At March 31, 2007, the maximum future payments for all the LOCs are approximately $27 million with maturities ranging from June 2007 to March 2008.

Guarantees Of Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation in the amount of approximately $85 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), an entity consolidated under FIN 46. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study, we estimate the reserves will be depleted in 2029 with final reclamation completed by 2036, at an estimated cost of approximately $39 million. As of March 31, 2007, SWEPCo has collected approximately $30 million through a rider for final mine closure costs, of which approximately $13 million is recorded in Deferred Credits and Other and approximately $17 million is recorded in Asset Retirement Obligations on our Condensed Consolidated Balance Sheets.

Sabine charges SWEPCo, its only customer, all its costs. SWEPCo passes these costs through its fuel clause.

Indemnifications And Other Guarantees

Contracts

We enter into several types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, our exposure generally does not exceed the sale price. The status of certain sales agreements is discussed in the 2006 Annual Report, “Dispositions” section of Note 8. These sale agreements include indemnifications with a maximum exposure related to the collective purchase price, which is approximately $2.2 billion (approximately $1 billion relates to the BOA litigation, see “Enron Bankruptcy” section of this note). There are no material liabilities recorded for any indemnifications.
 
Master Operating Lease

We lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed receipt of up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, we are committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. At March 31, 2007, the maximum potential loss for these lease agreements was approximately $56 million ($36 million, net of tax) assuming the fair market value of the equipment is zero at the end of the lease term.

Railcar Lease

In June 2003, we entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease has an initial term of five years. At the end of each lease term, we may (a) renew for another five-year term, not to exceed a total of twenty years; (b) purchase the railcars for the purchase price amount specified in the lease, projected at the lease inception to be the then fair market value; or (c) return the railcars and arrange a third party sale (return-and-sale option). The lease is accounted for as an operating lease. We intend to renew the lease for the full twenty years. This operating lease agreement allows us to avoid a large initial capital expenditure and to spread our railcar costs evenly over the expected twenty-year usage.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under the return-and-sale option discussed above will equal at least a lessee obligation amount specified in the lease, which declines over the current lease term from approximately 86% to 77% of the projected fair market value of the equipment. At March 31, 2007, the maximum potential loss was approximately $31 million ($20 million, net of tax) assuming the fair market value of the equipment is zero at the end of the current lease term. We have other railcar lease arrangements that do not utilize this type of financing structure.

CONTINGENCIES

Federal EPA Complaint and Notice of Violation

The Federal EPA, certain special interest groups and a number of states allege 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. The Federal EPA filed its complaints against our subsidiaries in U.S. District Court for the Southern District of Ohio. The alleged modifications occurred at our generating units over a twenty-year period. A bench trial on the liability issues was held during July 2005. 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 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 routine maintenance, replacement of degraded equipment or failed component or other repairs needed for the reliable, safe and efficient operation of the plant. The CAA authorizes civil penalties of up to $27,500 ($32,500 after March 15, 2004) per day per violation at each generating unit. In 2001, the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief.

Cases are pending that could affect CSPCo’s share of jointly-owned units at Beckjord, Zimmer, and Stuart Stations. Similar cases have been filed against other nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these cases were resolved through consent decrees.

Courts have reached different conclusions regarding whether the activities at issue in these cases are routine maintenance, repair or replacement, and therefore are excluded from NSR. Similarly, courts have reached different results regarding whether the activities at issue increased emissions from the power plants. 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 most of the challenged activities would be excluded 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 yet to be determined by the Court. If we do not prevail, we believe we can recover any capital and operating costs of additional pollution control equipment that may be required through regulated rates and market prices of electricity. If we are unable to recover such costs or if material penalties are imposed, it would adversely affect our future results of operations, cash flows and possibly financial condition.

SWEPCo Notice of Enforcement and Notice of Citizen Suit

In March 2005, two special interest groups, Sierra Club and Public Citizen, filed a complaint in Federal District Court for the Eastern District of Texas alleging violations of the CAA at SWEPCo’s Welsh Plant. SWEPCo filed a response to the complaint in May 2005. A trial in this matter is scheduled for the second quarter of 2007.

In 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary of findings resulting from a compliance investigation at the plant. In April 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of approximately $228 thousand against SWEPCo based on alleged violations of certain representations regarding heat input in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements. SWEPCo responded to the preliminary report and petition in May 2005. The enforcement order contains a recommendation limiting the heat input on each Welsh unit to the referenced heat input contained within the permit application within 10 days of the issuance of a final TCEQ order and until a permit amendment is issued. SWEPCo had previously requested a permit alteration to remove the reference to a specific heat input value for each Welsh unit and to clarify the sulfur content requirement for fuels consumed at the plant. A permit alteration was issued in March 2007 removing the heat input references from the Welsh permit and clarifying the sulfur content of fuels burned at the plant is limited to 0.5% on an as-received basis. The Sierra Club and Public Citizen filed a motion to overturn the permit alteration.

We are unable to predict the timing of any future action by TCEQ or the special interest groups or the effect of such actions on our results of operations, cash flows or financial condition.
 
Carbon Dioxide (CO2) Public Nuisance Claims

In 2004, eight states and the City of New York filed an action in federal district court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority. The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants. The actions allege that CO2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming, and sought injunctive relief in the form of specific emission reduction commitments from the defendants. The defendants’ motion to dismiss the lawsuits was granted in September 2005. The dismissal was appealed to the Second Circuit Court of Appeals. Briefing and oral argument have concluded. On April 2, 2007, the U.S. Supreme Court issued a decision holding that the Federal EPA has authority to regulate emissions of CO2 and other greenhouse gases under the CAA, which may impact the Second Circuit’s analysis of these issues. We believe the actions are without merit and intend to defend against the claims.

TEM Litigation

OPCo agreed to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) (now known as SUEZ Energy Marketing NA, Inc.) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA). Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming.

In September 2003, TEM and AEP separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. We alleged that TEM breached the PPA, and we sought a determination of our rights under the PPA. TEM alleged that the PPA never became enforceable, or alternatively, that the PPA was terminated as the result of AEP’s breaches. The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) provided a limited guaranty.

In August 2005, a federal judge ruled that TEM had breached the contract and awarded us damages of $123 million plus prejudgment interest. Any eventual proceeds will be recorded as a gain when received.

In September 2005, TEM posted a $142 million letter of credit as security pending appeal of the judgment. Both parties filed Notices of Appeal with the United States Court of Appeals for the Second Circuit, which heard oral argument on the appeals in December 2006. We cannot predict the ultimate outcome of this proceeding.

Enron Bankruptcy

In connection with the 2001 acquisition of HPL, we entered into an agreement with BAM Lease Company, which granted HPL the exclusive right to use approximately 65 billion cubic feet (BCF) of cushion gas required for the normal operation of the Bammel gas storage facility. At the time of our acquisition of HPL, Bank of America (BOA) and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of 65 BCF of cushion gas. Also at the time of our acquisition, Enron and the BOA Syndicate released HPL from all prior and future liabilities and obligations in connection with the financing arrangement.

After the Enron bankruptcy, the BOA Syndicate informed HPL of a purported default by Enron under the terms of the financing arrangement. In 2002, the BOA Syndicate filed a lawsuit against HPL in Texas state court seeking a declaratory judgment that the BOA Syndicate has a valid and enforceable security interest in gas purportedly in the Bammel storage facility. In 2003, the Texas state court granted partial summary judgment in favor of the BOA Syndicate. HPL appealed this decision. In August 2006, the Court of Appeals for the First District of Texas vacated the trial court’s judgment and dismissed the BOA Syndicate’s case. The BOA Syndicate did not seek review of this decision. In June 2004, BOA filed an amended petition in a separate lawsuit in Texas state court seeking to obtain possession of up to 55 BCF of storage gas in the Bammel storage facility or its fair value. Following an adverse decision on its motion to obtain possession of this gas, BOA voluntarily dismissed this action. In October 2004, BOA refiled this action. HPL’s motion to have the case assigned to the judge who heard the case originally was granted. HPL intends to defend against any renewed claims by BOA.

In 2003, AEP filed a lawsuit against BOA in the United States District Court for the Southern District of Texas. BOA led a lending syndicate involving the 1997 gas monetization that Enron and its subsidiaries undertook and the leasing of the Bammel underground gas storage facility to HPL. The lawsuit asserts that BOA made misrepresentations and engaged in fraud to induce and promote the stock sale of HPL, that BOA directly benefited from the sale of HPL and that AEP undertook the stock purchase and entered into the Bammel storage facility lease arrangement with Enron and the cushion gas arrangement with Enron and BOA based on misrepresentations that BOA made about Enron’s financial condition that BOA knew or should have known were false including that the 1997 gas monetization did not contravene or constitute a default of any federal, state, or local statute, rule, regulation, code or any law. In February 2004, BOA filed a motion to dismiss this Texas federal lawsuit. In September 2004, the Magistrate Judge issued a Recommended Decision and Order recommending that BOA’s Motion to Dismiss be denied, that the five counts in the lawsuit seeking declaratory judgments involving the Bammel facility and the right to use and cushion gas consent agreements be transferred to the Southern District of New York and that the four counts alleging breach of contract, fraud and negligent misrepresentation proceed in the Southern District of Texas. BOA objected to the Magistrate Judge’s decision. In April 2005, the Judge entered an order overruling BOA’s objections, denying BOA’s Motion to Dismiss and severing and transferring the declaratory judgment claims to the Southern District of New York. HPL and BOA filed motions for summary judgment in the case pending in the Southern District of New York. The case in federal court in Texas was set for trial beginning April 2007 but the Court continued the trial pending a decision on the motions for summary judgment in the New York case.

In February 2007, the Judge in the New York action, after hearing oral argument on the motions for summary judgment, made a series of oral “informal findings” and submitted a written memorandum to the parties’ counsel. In the memorandum to counsel, the Judge stated that he was denying several of AEP’s motions for partial summary judgment and granting several of BOA motions for summary judgment. The substantive matters left open for further proceedings include the issue of the nature of the gas subject to BOA security interest and the value of that interest. The Judge stated that the memorandum to counsel is not an opinion or an order, and that no opinion or order will be issued until all motions pending before the Court have been decided. The Judge heard additional arguments on the summary judgment motions in March 2007. At this time we are unable to predict how the Judge will rule on the pending motions due to the complexity of those issues and the parties’ disagreement over each issue. If the Judge issues a judgment directing AEP to pay an amount in excess of the gain on the sale of HPL described below and if AEP is unsuccessful in having the judgment reversed or modified, the judgment could have a material adverse effect on the results of operations, cash flow, and possibly financial condition.

In February 2004, in connection with BOA’s dispute, Enron filed Notices of Rejection regarding the cushion gas exclusive right-to-use agreement and other incidental agreements. We objected to Enron’s attempted rejection of these agreements and filed an adversary proceeding contesting Enron’s right to reject these agreements.

In 2005, we sold our interest in HPL. We indemnified the buyer of HPL against any damages resulting from the BOA litigation up to the purchase price. The determination of the gain on sale, estimated to be $380 million at March 31, 2007 and December 31, 2006, and the recognition of the gain are dependent on the ultimate resolution of the BOA dispute and the costs, if any, associated with the resolution of this matter. The deferred gain is included in Deferred Credits and Other on our Condensed Consolidated Balance Sheets.

Although management is unable to predict the outcome of the remaining lawsuits, it is possible that their resolution could have an adverse impact on our results of operations, cash flows and financial condition.

Shareholder Lawsuits

In 2002 and 2003, three putative class action lawsuits were filed against AEP, certain executives and AEP’s Employee Retirement Income Security Act (ERISA) Plan Administrator alleging violations of ERISA in the selection of AEP stock as an investment alternative and in the allocation of assets to AEP stock. The ERISA actions were pending in Federal District Court, Columbus, Ohio. In these actions, the plaintiffs sought recovery of an unstated amount of compensatory damages, attorney fees and costs. In July 2006, the Court entered judgment denying plaintiff’s motion for class certification and dismissing all claims without prejudice. In August 2006, the plaintiffs filed a notice of appeal to the United States Court of Appeals for the Sixth Circuit. Briefing of this appeal was completed in December 2006 and the parties await the scheduling of oral argument. We intend to continue to defend against these claims.
 
Natural Gas Markets Lawsuits

In 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against forty energy companies, including AEP, and two publishing companies alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were filed in California. In addition, a number of other cases were filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. In some of these cases, AEP (or a subsidiary) is among the companies named as defendants. These cases are at various pre-trial stages. Several of these cases were transferred to the United States District Court for the District of Nevada but subsequently were remanded to California state court. In 2005, the judge in Nevada dismissed three of the remaining cases (AEP was a defendant in one of these cases), on the basis of the filed rate doctrine. Plaintiffs in these cases appealed the decisions. We will continue to defend each case where an AEP company is a defendant.

FERC Long-term Contracts

In 2002, the FERC held a hearing related to a complaint filed by Nevada Power Company and Sierra Pacific Power Company (the Nevada utilities). The complaint sought to break long-term contracts entered during the 2000 and 2001 California energy price spike which the customers alleged were “high-priced.” The complaint alleged that we sold power at unjust and unreasonable prices. In December 2002, a FERC ALJ ruled in our favor and dismissed the complaint filed by the Nevada utilities. In 2001, the Nevada utilities filed complaints asserting that the prices for power supplied under those contracts should be lowered as the market for power was allegedly dysfunctional at the time such contracts were executed. The ALJ rejected the complaint, held that the markets for future delivery were not dysfunctional, and that the Nevada utilities failed to demonstrate that the public interest required that changes be made to the contracts. In June 2003, the FERC issued an order affirming the ALJ’s decision. In December 2006, the U.S. Court of Appeals for the Ninth Circuit reversed the FERC order and remanded the case to the FERC for further proceedings. Management is unable to predict the outcome of these proceedings or their impact on future results of operations and cash flows. We have asserted claims against certain companies that sold power to us, which we resold to the Nevada utilities, seeking to recover a portion of any amounts we may owe to the Nevada utilities.

         5. ACQUISITIONS, DISPOSITIONS, DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

ACQUISITIONS

2007

Darby Electric Generating Station (Utility Operations segment)

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 and the assumption of liabilities of approximately $2 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.

Lawrenceburg Generating Station (Utility Operations segment)

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. AEGCo will complete the purchase 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.

2006

None
 
DISPOSITIONS

2007

Texas Plants - Oklaunion Power Station (Utility Operations segment)

In February 2007, TCC sold its 7.81% share of Oklaunion Power Station to the Public Utilities Board of the City of Brownsville for $42.8 million plus working capital adjustments. The sale did not have an impact on our results of operations nor do we expect any remaining litigation to have a significant effect on our results of operations.

Intercontinental Exchange, Inc. (ICE) (All Other)

During March 2007, we sold 130,000 shares of ICE and recognized a $16 million pretax gain ($10 million, net of tax). We recorded the gains in Interest and Investment Income on our 2007 Condensed Consolidated Statement of Income. We recorded our remaining investment of approximately 138,000 shares in Other Temporary Cash Investments on our Condensed Consolidated Balance Sheets.
 
Texas REPs (Utility Operations Segment)

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. These payments are reflected in Gain/Loss on Disposition of Assets, Net on our Condensed Consolidated Statements of Income. The payment we received in 2007 was the final payment under the earnings sharing agreement.
 
2006

Compresion Bajio S de R.L. de C.V. (All Other)

In January 2002, we acquired a 50% interest in Compresion Bajio S de R.L. de C.V. (Bajio), a 600 MW power plant in Mexico. We completed the sale in February 2006 for approximately $29 million with no effect on our 2006 results of operations.

DISCONTINUED OPERATIONS

We determined that certain of our operations were discontinued operations and classified them as such for all periods presented. We recorded no income or charges related to our discontinued operations during the first quarter of 2007. During the first quarter of 2006, we had discontinued operations from U.K. Generation related to a release of accrued liabilities for the London office lease and tax adjustments from the sale. We recorded pretax income related to U.K. Generation of $5 million ($3 million, net of tax) during the first quarter of 2006.

ASSETS HELD FOR SALE

Texas Plants - Oklaunion Power Station (Utility Operations segment)

In February 2007, TCC sold its 7.81% share of Oklaunion Power Station to the Public Utilities Board of the City of Brownsville. The sale did not have a significant effect on our results of operations nor do we expect any remaining litigation to have a significant effect on our results of operations.

We classified TCC’s assets related to the Oklaunion Power Station in Assets Held for Sale on our Condensed Consolidated Balance Sheet at December 31, 2006. The plant does not meet the “component-of-an-entity” criteria because it does not have cash flows that can be clearly distinguished operationally. The plant also does not meet the “component-of-an-entity” criteria for financial reporting purposes because it does not operate individually, but rather as a part of the AEP System, which includes all of the generation facilities owned by our Registrant Subsidiaries except TNC.

Our Assets Held for Sale were as follows:

   
March 31,
 
December 31,
 
   
2007
 
2006
 
Texas Plants
 
(in millions)
 
Other Current Assets
 
$
-
 
$
1
 
Property, Plant and Equipment, Net
   
-
   
43
 
Total Assets Held for Sale
 
$
-
 
$
44
 
 
         6. BENEFIT PLANS 

We adopted SFAS 158 as of December 31, 2006. We recorded a SFAS 71 regulatory asset for qualifying SFAS 158 costs of our regulated operations that for ratemaking purposes will be deferred for future recovery.

Components of Net Periodic Benefit Cost

The following table provides the components of our net periodic benefit cost for the plans for the three months ended March 31, 2007 and 2006:
       
Other
 
       
Postretirement
 
   
Pension Plans
 
Benefit Plans
 
   
2007
 
2006
 
2007
 
2006
 
   
(in millions)
 
Service Cost
 
$
24
 
$
24
 
$
10
 
$
10
 
Interest Cost
   
59
   
57
   
26
   
25
 
Expected Return on Plan Assets
   
(85
)
 
(83
)
 
(26
)
 
(23
)
Amortization of Transition Obligation
   
-
   
-
   
7
   
7
 
Amortization of Net Actuarial Loss
   
15
   
20
   
3
   
5
 
Net Periodic Benefit Cost
 
$
13
 
$
18
 
$
20
 
$
24
 

         7.  BUSINESS SEGMENTS

As outlined in our 2006 Annual Report, our primary business strategy and the core of our business are to focus on our electric utility operations. Within our Utility Operations segment, we centrally dispatch all generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Generation/supply in Ohio and Virginia continue to have commission-determined transition rates. In April 2007, the Virginia legislature approved amendments recommended by the Governor providing for the re-regulation of electric utility generation/supply rates. See “Virginia Restructuring” section of Note 3.

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 remainder of our company’s activities is presented as All Other. While not considered a business segment, 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.

The tables below present our reportable segment information for the three months ended March 31, 2007 and 2006 and balance sheet information as of March 31, 2007 and December 31, 2006. These amounts include certain estimates and allocations where necessary. We reclassified prior year amounts to conform to the current year’s segment presentation.

       
Nonutility Operations
             
   
Utility Operations
 
MEMCO
Operations
 
Generation
and
Marketing
 
All Other (a)
 
Reconciling Adjustments
 
Consolidated
 
   
(in millions)
Three Months Ended March 31, 2007
                                     
Revenues from:
                                     
 
External Customers
 
$
2,886
 
$
117
 
$
115
 
$
51
 
$
-
 
$
3,169
 
 
Other Operating Segments
   
147
   
3
   
(73
)
 
(45
)
 
(32
)
 
-
 
Total Revenues
 
$
3,033
 
$
120
 
$
42
 
$
6
 
$
(32
)
$
3,169
 
                                       
Net Income (Loss)
 
$
253
 
$
15
 
$
(1
)
$
4
 
$
-
 
$
271
 

       
Nonutility Operations
             
   
Utility Operations
 
MEMCO
Operations
 
Generation
and
Marketing
 
All Other (a)
 
Reconciling Adjustments
 
Consolidated
 
   
(in millions)
 
Three Months Ended March 31, 2006
                               
Revenues from:
                               
External Customers
 
$
2,982
 
$
116
 
$
13
 
$
(3
)
$
-
 
$
3,108
 
Other Operating Segments
   
(16
)
 
3
   
-
   
22
   
(9
)
 
-
 
Total Revenues
 
$
2,966
 
$
119
 
$
13
 
$
19
 
$
(9
)
$
3,108
 
                                       
Income (Loss) Before Discontinued
  Operations
 
$
365
 
$
21
 
$
4
 
$
(12
)
$
-
 
$
378
 
Discontinued Operations, Net of Tax
   
-
   
-
   
-
   
3
   
-
   
3
 
Net Income (Loss)
 
$
365
 
$
21
 
$
4
 
$
(9
)
$
-
 
$
381
 

       
Nonutility Operations
             
   
Utility Operations
 
MEMCO
Operations
 
Generation
and
Marketing
 
All Other (a)
 
Reconciling Adjustments
 
Consolidated
 
March 31, 2007
 
(in millions)
 
Total Property, Plant and Equipment
 
$
42,092
 
$
239
 
$
565
 
$
35
 
$
(237
)(c)
$
42,694
 
Accumulated Depreciation and Amortization
   
15,244
   
53
   
90
   
7
   
(3
)(c)
 
15,391
 
Total Property, Plant and Equipment - Net
 
$
26,848
 
$
186
 
$
475
 
$
28
 
$
(234
)(c)
$
27,303
 
                                       
Total Assets
 
$
36,789
 
$
305
 
$
705
 
$
11,732
 
$
(11,595
)(b)
$
37,936
 


         
Nonutility Operations
                   
   
Utility Operations
 
MEMCO
Operations
 
Generation
and
Marketing
 
All Other (a)
 
Reconciling Adjustments
 
Consolidated
 
December 31, 2006
 
(in millions)
 
Total Property, Plant and Equipment
 
$
41,420
 
$
239
 
$
327
 
$
35
 
$
-
 
$
42,021
 
Accumulated Depreciation and Amortization
   
15,101
   
51
   
83
   
5
   
-
   
15,240
 
Total Property, Plant and Equipment - Net
 
$
26,319
 
$
188
 
$
244
 
$
30
 
$
-
 
$
26,781
 
                                       
Total Assets
 
$
36,632
 
$
315
 
$
342
 
$
11,460
 
$
(10,762
)(b)
$
37,987
 
Assets Held for Sale
   
44
   
-
   
-
   
-
   
-
   
44
 

(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)
Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies.
(c)
Reconciling Adjustments for Total Property, Plant and Equipment and Accumulated Depreciation and Amortization as of March 31, 2007 represent the elimination of an intercompany capital lease that began during the first quarter of 2007.

          8.   INCOME TAXES

We join in the filing of a consolidated federal income tax return with our subsidiaries in the American Electric Power (AEP) System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current expense. The tax benefit of the parent is allocated to our subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidated group.

Audit Status

AEP System companies also file income tax returns in various state, local, and foreign jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2000. The IRS and other taxing authorities routinely examine our tax returns. We believe that we have filed tax returns with positions that may be challenged by these tax authorities. We are currently under exam in several state and local jurisdictions. However, management does not believe that the ultimate resolution of these audits will materially impact results of operations.

We have settled with the IRS all issues from the audits of our consolidated federal income tax returns for years prior to 1997. We have effectively settled all outstanding proposed IRS adjustments for years 1997 through 1999 and through June 2000 for the CSW pre-merger tax period and anticipate payment for the agreed adjustments to occur during 2007. Returns for the years 2000 through 2003 are presently being audited by the IRS and we anticipate that the audit will be completed by the end of 2007.

The IRS has proposed certain significant adjustments to AEP’s foreign tax credit and interest allocation positions. Management is currently evaluating those proposed adjustments to determine if it agrees, but if accepted, we do not anticipate that the adjustments would result in a material change to our financial position.
 
FIN 48 Adoption

We adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, we recognized approximately a $17 million increase in the liabilities for unrecognized tax benefits, as well as related interest expense and penalties, which was accounted for as a reduction to the January 1, 2007 balance of retained earnings.

At January 1, 2007, the total amount of unrecognized tax benefits under FIN 48 was $175 million. We believe it is reasonably possible that there will be a $46 million net decrease in unrecognized tax benefits due to the settlement of audits and the expiration of statute of limitations within 12 months of the reporting date. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $73 million. There are $66 million of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

Prior to the adoption of FIN 48, we recorded interest and penalty accruals related to income tax positions in tax accrual accounts. With the adoption of FIN 48, we began recognizing interest accruals related to income tax positions in interest income or expense as applicable, and penalties in operating expenses. As of January 1, 2007, we accrued approximately $25 million for the payment of uncertain interest and penalties.

         9.   FINANCING ACTIVITIES

Long-term Debt
   
March 31,
 
December 31,
 
Type of Debt
 
2007
 
2006
 
   
(in millions)
 
Senior Unsecured Notes
 
$
8,903
 
$
8,653
 
Pollution Control Bonds
   
1,950
   
1,950
 
First Mortgage Bonds
   
90
   
90
 
Defeased First Mortgage Bonds (a)
   
27
   
27
 
Notes Payable
   
320
   
337
 
Securitization Bonds
   
2,303
   
2,335
 
Notes Payable To Trust
   
113
   
113
 
Spent Nuclear Fuel Obligation (b)
   
251
   
247
 
Other Long-term Debt
   
2
   
2
 
Unamortized Discount (net)
   
(57
)
 
(56
)
Total Long-term Debt Outstanding
   
13,902
   
13,698
 
Less Portion Due Within One Year
   
1,377
   
1,269
 
Long-term Portion
 
$
12,525
 
$
12,429
 

(a)
In May 2004, we deposited cash and treasury securities with a trustee to defease all of TCC’s outstanding First Mortgage Bonds. The defeased TCC First Mortgage Bonds had a balance of $19 million at both March 31, 2007 and December 31, 2006. Trust Fund Assets related to this obligation of $23 million and $2 million at March 31, 2007 and December 31, 2006, respectively, are included in Other Temporary Cash Investments and $0 and $21 million at March 31, 2007 and December 31, 2006, respectively, are included in Other Noncurrent Assets on our Condensed Consolidated Balance Sheets. In December 2005, we deposited cash and treasury securities with a trustee to defease the remaining TNC outstanding First Mortgage Bond. The defeased TNC First Mortgage Bond had a balance of $8 million at both March 31, 2007 and December 31, 2006. Trust fund assets related to this obligation of $9 million at both March 31, 2007 and December 31, 2006 are included in Other Temporary Cash Investments on our Condensed Consolidated Balance Sheet. Trust fund assets are restricted for exclusive use in funding the interest and principal due on the First Mortgage Bonds.
(b)
Pursuant to the Nuclear Waste Policy Act of 1982, I&M (a nuclear licensee) has an obligation with the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust Fund assets related to this obligation of $276 million and $274 million at March 31, 2007 and December 31, 2006, respectively, are included in Spent Nuclear Fuel and Decommissioning Trusts on our Condensed Consolidated Balance Sheets.
 
 
Long-term debt and other securities issued, retired and principal payments made during the first three months of 2007 are shown in the tables below.
Company
 
Type of Debt
 
Principal Amount
 
Interest Rate
 
Due Date
 
       
(in millions)
 
(%)
     
Issuances:
                 
SWEPCo
 
Senior Unsecured Notes
 
$
250
 
5.55
 
2017
 
Total Issuances
     
$
250
(a)
       
      
The above borrowing arrangement does not contain guarantees, collateral or dividend restrictions.
   
(a)
Amount indicated on statement of cash flows of $247 million is net of issuance costs and unamortized premium or discount.

 
Company
 
Type of Debt
 
Principal Amount Paid
 
Interest Rate
 
Due Date
 
       
(in millions)
 
(%)
     
Retirements and  Principal Payments:
                 
OPCo
 
Notes Payable
 
$
1
 
6.81
 
2008
 
OPCo
 
Notes Payable
   
6
 
6.27
 
2009
 
SWEPCo
 
Notes Payable
   
2
 
4.47
 
2011
 
SWEPCo
 
Notes Payable
   
4
 
6.36
 
2007
 
SWEPCo
 
Notes Payable
   
1
 
Variable
 
2008
 
TCC
 
Securitization Bonds
   
32
 
5.01
 
2008
 
                     
Non-Registrant:
                   
AEP Subsidiaries
 
Notes Payable
   
3
 
Variable
 
2017
 
Total Retirements
     
$
49
         

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.

Short-term Debt

Short-term debt is used to fund our corporate borrowing program and fund other short-term cash needs. Our outstanding short-term debt is as follows:
   
March 31, 2007
   
December 31, 2006
 
   
Outstanding
Amount
 
Interest
Rate
   
Outstanding
Amount
 
Interest
Rate
 
Type of Debt
 
(in millions)
         
(in millions)
       
Commercial Paper - AEP
 
$
150
   
5.43
%
(a)
$
-
   
-
 
Commercial Paper - JMG (b)
   
5
   
5.56
%
   
1
   
5.56
%
Line of Credit - Sabine (c)
   
20
   
6.52
%
   
17
   
6.38
%
Total
 
$
175
         
$
18
       

(a)
Weighted average rate.
(b)
This commercial paper is specifically associated with the Gavin Scrubber and is backed by a separate credit facility. This commercial paper does not reduce available liquidity under AEP’s credit facilities.
(c)
Sabine is consolidated under FIN 46. This line of credit does not reduce available liquidity under AEP’s credit facilities.

Credit Facilities

In March 2007, we amended the terms of our credit facilities. The amended facilities are structured as two $1.5 billion credit facilities, with an option in each to issue up to $300 million as letters of credit, expiring separately in March 2011 and April 2012.
 
 
 

 
 









AEP GENERATING COMPANY





 


















AEP GENERATING COMPANY
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

We engage in the generation and wholesale sale of electric power to two affiliates, I&M and KPCo, under long-term agreements. We derive operating revenues from the sale of Rockport Plant energy and capacity to I&M and KPCo pursuant to FERC-approved long-term unit power agreements through December 2022. Under the terms of its unit power agreement, I&M agreed to purchase all of our Rockport energy and capacity unless it is sold to other utilities or affiliates. I&M assigned 30% of its rights to energy and capacity to KPCo.

The unit power agreements provide for a FERC-approved rate of return on common equity, a return on other capital (net of temporary cash investments) and recovery of costs including operation and maintenance, fuel and taxes. Under the terms of the unit power agreements, we accumulate all expenses monthly and prepare bills for our affiliates. In the month the expenses are incurred, we recognize the billing revenues and establish a receivable from the affiliated companies. The co-owners divide the costs of operating the plant.

Results of Operations

First Quarter of 2007 Compared to First Quarter of 2006

Reconciliation of First Quarter of 2006 to First Quarter of 2007
Net Income
(in millions)

First Quarter of 2006
       
$
2.9
 
               
Change in Gross Margin:
             
Wholesale Sales
         
(0.7
)
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(1.3
)
     
Interest Expense
   
(0.5
)
     
Total Change in Operating Expenses and Other
         
(1.8
)
               
Income Tax Expense (Credit)
         
1.2
 
               
First Quarter of 2007
       
$
1.6
 

Net Income decreased $1.3 million for 2007 compared with 2006. The fluctuation in Net Income is a result of terms in the unit power agreements which allow for a return on total capital of the Rockport Plant calculated and adjusted monthly for over/under billings.

Gross Margin, defined as Operating Revenues less Fuel for Electric Generation, decreased $0.7 million primarily due to year-end tax adjustments reflected in January’s bill.

Other Operation and Maintenance expenses increased $1.3 million primarily due to increased maintenance cost reflecting more planned and forced outages at the Rockport Plant in 2007 than 2006.

Interest Expense increased $0.5 million primarily due to increased rates on short-term borrowings and increased money pool borrowings.

Income Taxes

Income Tax Expense (Credit) decreased $1.2 million primarily due to a decrease in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis.

Significant Factors

Lawrenceburg Generating Station

In January 2007, we 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. This new generation acquisition will be financed by a capital contribution from AEP and issuance of debt related to this acquisition. We plan to sell the power to CSPCo through a FERC-approved purchase power contract.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in our 2006 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.



AEP GENERATING COMPANY
CONDENSED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
           
OPERATING REVENUES
 
$
77,151
 
$
78,151
 
               
EXPENSES
             
Fuel Used for Electric Generation
   
43,649
   
43,961
 
Rent - Rockport Plant Unit 2
   
17,071
   
17,071
 
Other Operation
   
3,326
   
3,068
 
Maintenance
   
3,811
   
2,786
 
Depreciation and Amortization
   
5,990
   
5,975
 
Taxes Other Than Income Taxes
   
1,081
   
1,070
 
TOTAL
   
74,928
   
73,931
 
               
OPERATING INCOME
   
2,223
   
4,220
 
               
Interest Expense
   
(1,252
)
 
(722
)
               
INCOME BEFORE INCOME TAXES
   
971
   
3,498
 
               
Income Tax Expense (Credit)
   
(620
)
 
570
 
               
NET INCOME
 
$
1,591
 
$
2,928
 

CONDENSED STATEMENTS OF RETAINED EARNINGS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
           
BALANCE AT BEGINNING OF PERIOD
 
$
30,942
 
$
26,038
 
               
FIN 48 Adoption, Net of Tax
   
27
   
-
 
               
Net Income
   
1,591
   
2,928
 
               
Cash Dividends Declared
   
-
   
1,998
 
               
BALANCE AT END OF PERIOD
 
$
32,560
 
$
26,968
 

The common stock of AEGCo is wholly-owned by AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


AEP GENERATING COMPANY
CONDENSED BALANCE SHEETS
ASSETS
March 31, 2007 and December 31, 2006
(in thousands)
(Unaudited)


   
2007
 
2006
 
CURRENT ASSETS
           
Accounts Receivable - Affiliated Companies
 
$
29,380
 
$
31,060
 
Fuel
   
28,414
   
37,701
 
Materials and Supplies
   
8,024
   
7,873
 
Accrued Tax Benefits
   
1,820
   
3,808
 
Prepayments and Other
   
38
   
57
 
TOTAL
   
67,676
   
80,499
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric - Production
   
688,599
   
686,776
 
Other
   
2,567
   
2,460
 
Construction Work in Progress
   
15,931
   
15,198
 
Total
   
707,097
   
704,434
 
Accumulated Depreciation and Amortization
   
405,676
   
398,422
 
TOTAL - NET
   
301,421
   
306,012
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
5,403
   
5,438
 
Deferred Charges and Other
   
3,667
   
1,382
 
TOTAL
   
9,070
   
6,820
 
               
TOTAL ASSETS
 
$
378,167
 
$
393,331
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



AEP GENERATING COMPANY
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY
March 31, 2007 and December 31, 2006
(Unaudited)

   
2007
 
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
 
$
29,997
 
$
53,646
 
Accounts Payable:
             
General
   
6
   
549
 
Affiliated Companies
   
18,918
   
27,935
 
Accrued Taxes
   
7,092
   
3,685
 
Accrued Rent - Rockport Plant Unit 2
   
23,427
   
4,963
 
Other
   
521
   
1,200
 
TOTAL
   
79,961
   
91,978
 
               
NONCURRENT LIABILITIES
             
Long-term Debt - Nonaffiliated
   
44,839
   
44,837
 
Deferred Income Taxes
   
19,792
   
19,749
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
76,069
   
79,650
 
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2
   
87,370
   
88,762
 
Deferred Credits and Other
   
13,142
   
12,979
 
TOTAL
   
241,212
   
245,977
 
               
TOTAL LIABILITIES
   
321,173
   
337,955
 
               
Commitments and Contingencies (Note 4)
             
               
COMMON SHAREHOLDER’S EQUITY
             
Common Stock - Par Value - $1,000 Per Share:
  Authorized - 1,000 Shares
  Outstanding - 1,000 Shares
   
1,000
   
1,000
 
Paid-in Capital
   
23,434
   
23,434
 
Retained Earnings
   
32,560
   
30,942
 
TOTAL
   
56,994
   
55,376
 
               
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY
 
$
378,167
 
$
393,331
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



AEP GENERATING COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)
 
   
2007
 
2006
 
OPERATING ACTIVITIES
           
Net Income
 
$
1,591
 
$
2,928
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
5,990
   
5,975
 
Deferred Income Taxes
   
(1,205
)
 
(1,126
)
Deferred Investment Tax Credits
   
(820
)
 
(827
)
Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2
   
(1,392
)
 
(1,392
)
Deferred Property Taxes
   
(2,516
)
 
(2,734
)
Changes in Other Noncurrent Assets
   
47
   
(403
)
Changes in Other Noncurrent Liabilities
   
200
   
374
 
Changes in Certain Components of Working Capital:
             
Accounts Receivable
   
1,680
   
1,607
 
Fuel, Materials and Supplies
   
9,136
   
(1,044
)
Accounts Payable
   
(9,560
)
 
(2,068
)
Accrued Taxes, Net
   
5,252
   
6,179
 
Accrued Rent - Rockport Plant Unit 2
   
18,464
   
18,464
 
Other Current Assets
   
(28
)
 
(35
)
Other Current Liabilities
   
(332
)
 
(379
)
Net Cash Flows From Operating Activities
   
26,507
   
25,519
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(2,841
)
 
(1,693
)
               
FINANCING ACTIVITIES
             
Change in Advances from Affiliates, Net
   
(23,649
)
 
(21,814
)
Principal Payments for Capital Lease Obligations
   
(17
)
 
(14
)
Dividends Paid on Common Stock
   
-
   
(1,998
)
Net Cash Flows Used For Financing Activities
   
(23,666
)
 
(23,826
)
               
Net Change in Cash and Cash Equivalents
   
-
   
-
 
Cash and Cash Equivalents at Beginning of Period
   
-
   
-
 
Cash and Cash Equivalents at End of Period
 
$
-
 
$
-
 

SUPPLEMENTARY INFORMATION
           
Cash Paid for Interest, Net of Capitalized Amounts
 
$
1,398
 
$
1,109
 
Net Cash Received for Income Taxes
   
(439
)
 
-
 
Noncash Acquisitions Under Capital Leases
   
1
   
27
 

   See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


AEP GENERATING COMPANY
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to AEGCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to AEGCo.

 
Footnote Reference
Significant Accounting Matters
Note 1
New Accounting Pronouncements
Note 2
Commitments, Guarantees and Contingencies
Note 4
Acquisitions, Dispositions and Assets Held for Sale
Note 5
Business Segments
Note 7
Income Taxes
Note 8
Financing Activities
Note 9

 









 
 
 
 

 

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES

 
 
 
 
 
 
 
 
 
 

 

 



AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS



Results of Operations

First Quarter of 2007 Compared to First Quarter of 2006

Reconciliation of First Quarter of 2006 to First Quarter of 2007
Net Income
(in millions)

First Quarter of 2006
       
$
4
 
               
Changes in Gross Margin:
             
Off-system Sales
   
7
       
Texas Wires
   
6
       
Transmission Revenues
   
1
       
Other
   
28
       
Total Change in Gross Margin
         
42
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
2
       
Depreciation and Amortization
   
(13
)
     
Taxes Other Than Income Taxes
   
2
       
Carrying Costs Income
   
(19
)
     
Other Income
   
5
       
Interest Expense
   
(19
)
     
Total Change in Operating Expenses and Other
         
(42
)
               
First Quarter of 2007
       
$
4
 

Net Income remained relatively flat in the first quarter of 2007 compared to the first quarter of 2006.

The major components of our change in Gross Margin, defined as revenues less the related direct costs of fuel, including the consumption of emissions allowances, and purchased power were as follows:

·
Margins from Off-system Sales increased $7 million primarily due to lower margins from optimization activities of $5 million in 2006. An additional $2 million increase was primarily due to a $4 million provision for refund recorded in 2006 related to the pending and subsequent sale of our portion of the Oklaunion Plant offset in part by reduced sales margins upon completion of the sale.
·
Texas Wires revenues increased $6 million primarily due to increased usage and favorable weather conditions. As compared to the prior year, heating degree days more than doubled.
·
Other revenues increased $28 million. This increase was due in part to $36 million of revenue from securitization transition charges primarily resulting from new financing in October 2006. Securitization transition charges represent amounts collected to recover securitization bond principal and interest payments related to our securitized transition assets and are fully offset by amortization and interest expenses. This increase was partially offset by a $7 million decrease in third party construction project revenues mainly related to work performed for the Lower Colorado River Authority.

Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expenses decreased $2 million primarily due to a $5 million decrease from lower expenses related to construction projects performed for third parties, primarily Lower Colorado River Authority. This decrease is partially offset by an increase of $2 million in payments made for transmission services and approximately $1 million increase related to the replacement of meters.
·
Depreciation and Amortization expense increased $13 million primarily due to the recovery and amortization of the securitization assets of $15 million offset in part by $2 million related to the amortization of the CTC liability (see “TCC’s 2006 Securitization Proceeding” and “TCC’s 2006 CTC Proceeding” sections of Note 4 of the 2006 Annual Report).
·
Taxes Other Than Income Taxes decreased $2 million primarily due to lower property-related taxes related to Texas tax legislation and the sale of our portion of Oklaunion in February 2007.
·
Carrying Costs Income decreased $19 million primarily due to the absence of carrying cost on stranded cost recovery.
·
Other Income increased $5 million primarily due to larger invested balances in the Utility Money Pool.
·
Interest Expense increased $19 million primarily due to a $22 million increase in long-term debt interest primarily related to the Securitization Bonds issued in October 2006, offset in part by the retirement of other long-term debt.

Income Taxes

Income Tax Expense remained relatively flat for the first quarter 2007.

Financial Condition

Credit Ratings

In April 2007, Fitch Ratings downgraded our unsecured debt from A- to BBB+ and placed us on negative outlook. The negative rating outlook reflects Fitch’s expectation that credit metrics will continue to be weak for the BBB rating category absent a favorable outcome in our pending rate case in Texas. See “TCC and TNC Energy Delivery Base Rate Filings” in Note 3.

Critical Accounting Estimates

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

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

VaR Associated with Debt Outstanding

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 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 $228 million and $232 million at March 31, 2007 and December 31, 2006, respectively. 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 negatively affect our results of operations or consolidated financial position.




AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
REVENUES
         
Electric Generation, Transmission and Distribution
 
$
171,987
 
$
123,211
 
Sales to AEP Affiliates
   
1,130
   
1,598
 
Other
   
3,814
   
10,479
 
TOTAL
   
176,931
   
135,288
 
               
EXPENSES
             
Fuel and Other Consumables Used for Electric Generation
   
825
   
1,726
 
Purchased Electricity for Resale
   
1,509
   
1,680
 
Other Operation
   
57,396
   
58,902
 
Maintenance
   
7,785
   
7,789
 
Depreciation and Amortization
   
46,020
   
33,360
 
Taxes Other Than Income Taxes
   
18,524
   
20,363
 
TOTAL
   
132,059
   
123,820
 
               
OPERATING INCOME
   
44,872
   
11,468
 
               
Other Income (Expense):
             
Interest Income
   
4,959
   
505
 
Carrying Costs Income
   
-
   
19,423
 
Allowance for Equity Funds Used During Construction
   
1,159
   
373
 
Interest Expense
   
(46,021
)
 
(26,773
)
               
INCOME BEFORE INCOME TAXES
   
4,969
   
4,996
 
               
Income Tax Expense
   
1,431
   
1,223
 
               
NET INCOME
   
3,538
   
3,773
 
               
Preferred Stock Dividend Requirements
   
60
   
60
 
               
EARNINGS APPLICABLE TO COMMON STOCK
 
$
3,478
 
$
3,713
 

The common stock of TCC is owned by a wholly-owned subsidiary of AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
                            
DECEMBER 31, 2005
 
$
55,292
 
$
132,606
 
$
760,884
 
$
(1,152
)
$
947,630
 
                                 
Preferred Stock Dividends
               
(60
)
       
(60
)
TOTAL
                           
947,570
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Income, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $141
                     
262
   
262
 
NET INCOME
               
3,773
         
3,773
 
TOTAL COMPREHENSIVE INCOME
                           
4,035
 
                                 
MARCH 31, 2006
 
$
55,292
 
$
132,606
 
$
764,597
 
$
(890
)
$
951,605
 
                                 
DECEMBER 31, 2006
 
$
55,292
 
$
132,606
 
$
217,218
 
$
-
 
$
405,116
 
                                 
FIN 48 Adoption, Net of Tax
               
(2,187
)
       
(2,187
)
Preferred Stock Dividends
               
(60
)
       
(60
)
TOTAL
                           
402,869
 
                                 
COMPREHENSIVE INCOME
                               
NET INCOME
               
3,538
         
3,538
 
TOTAL COMPREHENSIVE INCOME
                           
3,538
 
                                 
MARCH 31, 2007
 
$
55,292
 
$
132,606
 
$
218,509
 
$
-
 
$
406,407
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2007 and December 31, 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
52
 
$
779
 
Other Cash Deposits
   
131,824
   
104,203
 
Advances to Affiliates
   
216,953
   
394,004
 
Accounts Receivable:
             
Customers
   
44,519
   
31,215
 
Affiliated Companies
   
6,513
   
8,613
 
Accrued Unbilled Revenues
   
17,969
   
10,093
 
Allowance for Uncollectible Accounts
   
(45
)
 
(49
)
   Total Accounts Receivable
   
68,956
   
49,872
 
Materials and Supplies
   
30,526
   
28,347
 
Prepayments and Other
   
11,107
   
5,672
 
TOTAL
   
459,418
   
582,877
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Transmission
   
917,708
   
904,527
 
Distribution
   
1,602,745
   
1,579,498
 
Other
   
224,856
   
220,028
 
Construction Work in Progress
   
166,300
   
165,979
 
Total
   
2,911,609
   
2,870,032
 
Accumulated Depreciation and Amortization
   
636,740
   
630,239
 
TOTAL - NET
   
2,274,869
   
2,239,793
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
187,765
   
193,111
 
Securitized Transition Assets
   
2,133,966
   
2,158,408
 
Employee Benefits and Pension Assets
   
35,534
   
35,574
 
Deferred Charges and Other
   
68,393
   
69,493
 
TOTAL
   
2,425,658
   
2,456,586
 
               
Assets Held for Sale - Texas Generation Plant
   
-
   
44,475
 
               
TOTAL ASSETS
 
$
5,159,945
 
$
5,323,731
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2007 and December 31, 2006
(Unaudited)

   
2007
 
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Accounts Payable:
           
General
 
$
17,857
 
$
26,934
 
Affiliated Companies
   
17,329
   
21,234
 
Long-term Debt Due Within One Year - Nonaffiliated
   
138,507
   
78,227
 
Customer Deposits
   
17,851
   
18,742
 
Accrued Taxes
   
33,474
   
74,499
 
Accrued Interest
   
57,625
   
44,712
 
Other
   
21,138
   
34,762
 
TOTAL
   
303,781
   
299,110
 
               
NONCURRENT LIABILITIES
             
Long-term Debt - Nonaffiliated
   
2,845,020
   
2,937,387
 
Deferred Income Taxes
   
1,037,080
   
1,034,123
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
503,627
   
598,027
 
Deferred Credits and Other
   
58,109
   
44,047
 
TOTAL
   
4,443,836
   
4,613,584
 
               
TOTAL LIABILITIES
   
4,747,617
   
4,912,694
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
5,921
   
5,921
 
               
Commitments and Contingencies (Note 4)
             
               
COMMON SHAREHOLDER’S EQUITY
             
Common Stock - Par Value - $25 Per Share:
             
Authorized - 12,000,000 Shares
             
Outstanding - 2,211,678 Shares
   
55,292
   
55,292
 
Paid-in Capital
   
132,606
   
132,606
 
Retained Earnings
   
218,509
   
217,218
 
TOTAL
   
406,407
   
405,116
 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 
$
5,159,945
 
$
5,323,731
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
OPERATING ACTIVITIES
           
Net Income
 
$
3,538
 
$
3,773
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
46,020
   
33,360
 
Deferred Income Taxes
   
11,102
   
2,928
 
Carrying Costs on Stranded Cost Recovery
   
-
   
(19,423
)
Mark-to-Market of Risk Management Contracts
   
-
   
5,125
 
Fuel Over/Under Recovery, Net
   
(98,665
)
 
-
 
Deferred Property Taxes
   
(20,064
)
 
(25,755
)
Change in Other Noncurrent Assets
   
(753
)
 
(1,330
)
Change in Other Noncurrent Liabilities
   
3,187
   
1,398
 
Changes in Certain Components of Working Capital:
             
Accounts Receivable, Net
   
(19,084
)
 
121,367
 
Fuel, Materials and Supplies
   
(2,543
)
 
(2,569
)
Accounts Payable
   
(3,957
)
 
(53,124
)
Customer Deposits
   
(891
)
 
(6,514
)
Accrued Taxes, Net
   
(40,642
)
 
6,854
 
Accrued Interest
   
11,019
   
(16,152
)
Other Current Assets
   
681
   
2,629
 
Other Current Liabilities
   
(13,867
)
 
(7,461
)
Net Cash Flows From (Used for) Operating Activities
   
(124,919
)
 
45,106
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(59,872
)
 
(58,645
)
Change in Other Cash Deposits, Net
   
(6,071
)
 
29,736
 
Change in Advances to Affiliates, Net
   
177,051
   
(32,101
)
Proceeds from Sale of Assets
   
45,619
   
3,837
 
Net Cash Flows From (Used For) Investing Activities
   
156,727
   
(57,173
)
               
FINANCING ACTIVITIES
             
Issuance of Long-term Debt - Affiliated
   
-
   
125,000
 
Change in Advances from Affiliates, Net
   
-
   
(82,080
)
Retirement of Long-term Debt - Nonaffiliated
   
(32,125
)
 
(30,641
)
Principal Payments for Capital Lease Obligations
   
(350
)
 
(152
)
Dividends Paid on Cumulative Preferred Stock
   
(60
)
 
(60
)
Net Cash From (Used For) Financing Activities
   
(32,535
)
 
12,067
 
               
Net Decrease in Cash and Cash Equivalents
   
(727
)
 
-
 
Cash and Cash Equivalents at Beginning of Period
   
779
   
-
 
Cash and Cash Equivalents at End of Period
 
$
52
 
$
-
 

SUPPLEMENTARY INFORMATION
           
Cash Paid for Interest, Net of Capitalized Amounts
 
$
27,961
 
$
40,646
 
Net Cash Paid for Income Taxes
   
32,601
   
485
 
Noncash Acquisitions Under Capital Leases
   
363
   
680
 
Construction Expenditures Included in Accounts Payable at March 31,
   
7,477
   
9,970
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to TCC’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to TCC.

 
Footnote Reference
Significant Accounting Matters
Note 1
New Accounting Pronouncements
Note 2
Rate Matters
Note 3
Commitments, Guarantees and Contingencies
Note 4
Acquisitions, Dispositions and Assets Held for Sale
Note 5
Benefit Plans
Note 6
Business Segments
Note 7
Income Taxes
Note 8
Financing Activities
Note 9









 
 
 
 

 



AEP TEXAS NORTH COMPANY AND SUBSIDIARY

 
 
 
 
 
 
 
 
 
 

 





AEP TEXAS NORTH COMPANY AND SUBSIDIARY
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations

First Quarter of 2007 Compared to First Quarter of 2006

Reconciliation of First Quarter of 2006 to First Quarter of 2007
Net Income
(in millions)

First Quarter of 2006
       
$
4
 
               
Changes in Gross Margin:
             
Off-system Sales
   
3
       
Texas Wires
   
2
       
Transmission Revenues
   
1
       
Total Change in Gross Margin
         
6
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(4
)
     
Total Change in Operating Expenses and Other
         
(4
)
               
Income Tax Expense
         
(1
)
               
First Quarter of 2007
       
$
5
 

Net Income increased $1 million primarily due to an increase in Gross Margin of $6 million partially offset by an increase in Other Operation and Maintenance expenses of $4 million.

The major components of our change in Gross Margin, defined as revenues less the related direct cost of fuel, consumption of emissions allowances and purchased power were as follows:

·
Margins from Off-system Sales increased $3 million primarily due to lower margins from optimization activities of $2 million in 2006. An additional $1 million increase was primarily due to the implementation of the Power Purchase Agreement with AEP Energy Partners in January 2007. Under this agreement, we recover our costs and capacity charges regardless of plant availability. See “Oklaunion PPA between TNC and AEP Energy Partners” section of Note 1.
·
Texas Wires revenues increased $2 million primarily due to increased usage and favorable weather conditions. As compared to the prior year, heating degree days increased 77%.

Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expenses increased $4 million primarily resulting from planned and forced outages at our Oklaunion Plant during the first quarter of 2007.

Income Taxes

Income Tax Expense increased $1 million primarily due to an increase in pretax book income.
 
Critical Accounting Estimates

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

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.




QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management assets and liabilities are zero at March 31, 2007 as a result of our exit from the generation business. See “Oklaunion PPA between TNC and AEP Energy Partners” section of Note 1.

VaR Associated with Debt Outstanding

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 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 $11 million and $12 million at March 31, 2007 and December 31, 2006, respectively. 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 negatively affect our results of operations or financial position.





AEP TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
REVENUES
         
Electric Generation, Transmission and Distribution
 
$
38,079
 
$
68,825
 
Sales to AEP Affiliates
   
24,654
   
6,025
 
Other
   
230
   
(184
)
TOTAL
   
62,963
   
74,666
 
               
EXPENSES
             
Fuel and Other Consumables Used for Electric Generation
   
6,276
   
12,115
 
Purchased Electricity for Resale
   
2,802
   
14,396
 
Other Operation
   
19,563
   
18,478
 
Maintenance
   
7,467
   
5,201
 
Depreciation and Amortization
   
10,346
   
10,301
 
Taxes Other Than Income Taxes
   
4,841
   
5,540
 
TOTAL
   
51,295
   
66,031
 
               
OPERATING INCOME
   
11,668
   
8,635
 
               
Other Income (Expense):
             
Interest Income
   
133
   
219
 
Allowance for Equity Funds Used During Construction
   
52
   
382
 
Interest Expense
   
(4,346
)
 
(4,362
)
               
INCOME BEFORE INCOME TAXES
   
7,507
   
4,874
 
               
Income Tax Expense
   
2,230
   
1,040
 
               
NET INCOME
   
5,277
   
3,834
 
               
Preferred Stock Dividend Requirements
   
26
   
26
 
Gain on Reacquired Preferred Stock
   
-
   
2
 
               
EARNINGS APPLICABLE TO COMMON STOCK
 
$
5,251
 
$
3,810
 

The common stock of TNC is owned by a wholly-owned subsidiary of AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



AEP TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2005
 
$
137,214
 
$
2,351
 
$
174,858
 
$
(504
)
$
313,919
 
                                 
Common Stock Dividends
               
(8,000
)
       
(8,000
)
Preferred Stock Dividends
               
(26
)
       
(26
)
Gain on Reacquired Preferred Stock
               
2
         
2
 
TOTAL
                           
305,895
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Income, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $102
                     
189
   
189
 
NET INCOME
               
3,834
         
3,834
 
TOTAL COMPREHENSIVE INCOME
                           
4,023
 
                                 
MARCH 31, 2006
 
$
137,214
 
$
2,351
 
$
170,668
 
$
(315
)
$
309,918
 
                                 
DECEMBER 31, 2006
 
$
137,214
 
$
2,351
 
$
176,950
 
$
(10,159
)
$
306,356
 
                                 
FIN 48 Adoption, Net of Tax
               
(557
)
       
(557
)
Preferred Stock Dividends
               
(26
)
       
(26
)
TOTAL
                           
305,773
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Income, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $378
                     
702
   
702
 
NET INCOME
               
5,277
         
5,277
 
TOTAL COMPREHENSIVE INCOME
                           
5,979
 
                                 
MARCH 31, 2007
 
$
137,214
 
$
2,351
 
$
181,644
 
$
(9,457
)
$
311,752
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



AEP TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2007 and December 31, 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
3
 
$
84
 
Other Cash Deposits
   
8,958
   
8,863
 
Advances to Affiliates
   
-
   
13,543
 
Accounts Receivable:
             
Customers
   
11,080
   
21,742
 
Affiliated Companies
   
13,177
   
5,634
 
Accrued Unbilled Revenues
   
2,917
   
2,292
 
Allowance for Uncollectible Accounts
   
(18
)
 
(9
)
   Total Accounts Receivable
   
27,156
   
29,659
 
Fuel
   
11,401
   
8,559
 
Materials and Supplies
   
9,544
   
9,319
 
Prepayments and Other
   
1,879
   
1,681
 
TOTAL
   
58,941
   
71,708
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
290,654
   
290,485
 
Transmission
   
330,272
   
327,845
 
Distribution
   
506,752
   
512,265
 
Other
   
160,141
   
159,451
 
Construction Work in Progress
   
36,145
   
38,847
 
Total
   
1,323,964
   
1,328,893
 
Accumulated Depreciation and Amortization
   
483,960
   
486,961
 
TOTAL - NET
   
840,004
   
841,932
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
38,356
   
38,402
 
Employee Benefits and Pension Assets
   
12,824
   
12,867
 
Deferred Charges and Other
   
12,807
   
2,605
 
TOTAL
   
63,987
   
53,874
 
               
TOTAL ASSETS
 
$
962,932
 
$
967,514
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




AEP TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2007 and December 31, 2006
(Unaudited)

   
2007
 
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
 
$
11,185
 
$
-
 
Accounts Payable:
             
General
   
6,328
   
4,448
 
Affiliated Companies
   
34,129
   
43,993
 
Long-term Debt Due Within One Year - Nonaffiliated
   
8,151
   
8,151
 
Accrued Taxes
   
19,477
   
21,782
 
Other
   
8,687
   
14,934
 
TOTAL
   
87,957
   
93,308
 
               
NONCURRENT LIABILITIES
             
Long-term Debt - Nonaffiliated
   
268,807
   
268,785
 
Long-term Risk Management Liabilities
   
-
   
1,081
 
Deferred Income Taxes
   
120,261
   
124,048
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
132,646
   
139,429
 
Deferred Credits and Other
   
39,160
   
32,158
 
TOTAL
   
560,874
   
565,501
 
               
TOTAL LIABILITIES
   
648,831
   
658,809
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
2,349
   
2,349
 
               
Commitments and Contingencies (Note 4)
             
               
COMMON SHAREHOLDER’S EQUITY
             
Common Stock - Par Value - $25 Per Share:
             
Authorized - 7,800,000 Shares
             
Outstanding - 5,488,560 Shares
   
137,214
   
137,214
 
Paid-in Capital
   
2,351
   
2,351
 
Retained Earnings
   
181,644
   
176,950
 
Accumulated Other Comprehensive Income (Loss)
   
(9,457
)
 
(10,159
)
TOTAL
   
311,752
   
306,356
 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 
$
962,932
 
$
967,514
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



AEP TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)


   
2007
 
2006
 
OPERATING ACTIVITIES
           
Net Income
 
$
5,277
 
$
3,834
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
10,346
   
10,301
 
Deferred Income Taxes
   
(1,016
)
 
(1,323
)
Mark-to-Market of Risk Management Contracts
   
-
   
1,989
 
Deferred Property Taxes
   
(10,862
)
 
(12,360
)
Change in Other Noncurrent Assets
   
1,508
   
(2,081
)
Change in Other Noncurrent Liabilities
   
(5,713
)
 
652
 
Changes in Certain Components of Working Capital:
             
Accounts Receivable, Net
   
2,503
   
36,836
 
Fuel, Materials and Supplies
   
(3,067
)
 
(2,156
)
Accounts Payable
   
(9,176
)
 
(36,932
)
Accrued Taxes, Net
   
(302
)
 
4,059
 
Other Current Assets
   
(255
)
 
1,676
 
Other Current Liabilities
   
(5,975
)
 
(9,775
)
Net Cash Flows Used For Operating Activities
   
(16,732
)
 
(5,280
)
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(19,793
)
 
(18,662
)
Change in Other Cash Deposits, Net
   
(95
)
 
792
 
Change In Advances to Affiliates, Net
   
13,543
   
31,240
 
Proceeds from Sale of Assets
   
11,965
   
-
 
Net Cash Flows From Investing Activities
   
5,620
   
13,370
 
               
FINANCING ACTIVITIES
             
Change in Advances from Affiliates, Net
   
11,185
   
-
 
Principal Payments for Capital Lease Obligations
   
(128
)
 
(64
)
Dividends Paid on Common Stock
   
-
   
(8,000
)
Dividends Paid on Cumulative Preferred Stock
   
(26
)
 
(26
)
Net Cash Flows From (Used For) Financing Activities
   
11,031
   
(8,090
)
               
Net Decrease in Cash and Cash Equivalents
   
(81
)
 
-
 
Cash and Cash Equivalents at Beginning of Period
   
84
   
-
 
Cash and Cash Equivalents at End of Period
 
$
3
 
$
-
 

SUPPLEMENTARY INFORMATION
           
Cash Paid for Interest, Net of Capitalized Amounts
 
$
6,150
 
$
6,113
 
Net Cash Paid for Income Taxes
   
2,288
   
-
 
Noncash Acquisitions Under Capital Leases
   
98
   
224
 
Construction Expenditures Included in Accounts Payable at March 31,
   
2,509
   
2,372
 

 See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


AEP TEXAS NORTH COMPANY AND SUBSIDIARY
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to TNC’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to TNC.

 
Footnote Reference
Significant Accounting Matters
Note 1
New Accounting Pronouncements
Note 2
Rate Matters
Note 3
Commitments, Guarantees and Contingencies
Note 4
Benefit Plans
Note 6
Business Segments
Note 7
Income Taxes
Note 8
Financing Activities
Note 9

 








 
 
 
 

APPALACHIAN POWER COMPANY
AND SUBSIDIARIES

 
 
 
 
 
 
 

 





APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations

First Quarter of 2007 Compared to First Quarter of 2006

Reconciliation of First Quarter of 2006 to First Quarter of 2007
Net Income
(in millions)

First Quarter of 2006
       
$
74
 
               
Changes in Gross Margin:
             
Retail Margins
   
29
       
Off-system Sales
   
(6
)
     
Transmission Revenues
   
(11
)
     
Other
   
1
       
Total Change in Gross Margin
         
13
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(5
)
     
Depreciation and Amortization
   
(11
)
     
Taxes Other Than Income Taxes
   
2
       
Carrying Costs Income
   
(3
)
     
Interest Expense
   
(2
)
     
Total Change in Operating Expenses and Other
         
(19
)
               
Income Tax Expense
         
2
 
               
   First Quarter of 2007
       
$
70
 

Net Income decreased $4 million to $70 million in 2007 primarily due to an increase in Operating Expenses and Other of $19 million, partially offset by an increase in Gross Margin of $13 million.

The major components of our change in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·
Retail Margins increased $29 million in comparison to 2006 primarily due to:
 
·
A $42 million increase in retail revenues primarily related to new rates implemented in relation to our Virginia general rate case, which are being collected subject to refund, and recovery of Virginia Environmental and Reliability (E&R) costs. See the “APCo Virginia Base Rate Case” section of Note 3.
 
·
A $9 million increase in retail sales primarily due to increased demand in the residential class associated with favorable weather conditions. Heating degree days increased approximately 19%.
 
These increases were partially offset by:
 
·
A $14 million decrease in revenues related to financial transmission rights, net of congestion, primarily due to fewer transmission constraints in the PJM market.
 
·
A $9 million decrease in revenues related to the Expanded Net Energy Cost (ENEC) mechanism with West Virginia retail customers primarily due to pass-through of off-system sales margins. The mechanism was reinstated in West Virginia effective July 1, 2006 in conjunction with our West Virginia rate case.
·
Margins from Off-system Sales decreased $6 million primarily due to an $18 million decrease in physical sales margins partially offset by a $10 million increase in margins from optimization activities and a $2 million increase in our allocation of off-system sales margins under the SIA. The change in allocation methodology of the SIA occurred on April 1, 2006.
·
Transmission Revenues decreased $11 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.
 
Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expenses increased $5 million mainly due to a $6 million increase in expenses for overhead line right-of-way clearing, overhead line repairs and increases in various other operation and maintenance expenses totaling $8 million. These increases were partially offset by a $9 million decrease in expenses related to the AEP Transmission Equalization Agreement due to the addition of our Wyoming-Jacksons Ferry 765 kV line which was energized and placed into service in June 2006.
·
Depreciation and Amortization expenses increased $11 million primarily due to the amortization of carrying charges and depreciation expense that are being collected through the E&R surcharges and increased plant in service related to the Wyoming-Jacksons Ferry 765 kV line, which was energized and placed in service in June 2006.
·
Carrying Costs Income decreased $3 million related to carrying costs associated with our E&R case.

Income Taxes

Income Tax Expense decreased $2 million primarily due to a decrease in pretax book income.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

 
Moody’s
 
S&P
 
Fitch
           
Senior Unsecured Debt
Baa2
 
BBB
 
BBB+

Cash Flow

Cash flows for the three months ended March 31, 2007 and 2006 were as follows:
   
2007
 
2006
 
   
(in thousands)
 
Cash and Cash Equivalents at Beginning of Period
 
$
2,318
 
$
1,741
 
Cash Flows From (Used For):
             
Operating Activities
   
176,029
   
210,980
 
Investing Activities
   
(200,894
)
 
(194,897
)
Financing Activities
   
24,534
   
(16,372
)
Net Decrease in Cash and Cash Equivalents
   
(331
)
 
(289
)
Cash and Cash Equivalents at End of Period
 
$
1,987
 
$
1,452
 

Operating Activities

Net Cash Flows From Operating Activities were $176 million in 2007. We produced income of $70 million during the period and a noncash expense item of $59 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital had no significant items in 2007.

Net Cash Flows From Operating Activities were $211 million in 2006. We produced income of $74 million during the period and a noncash expense item of $48 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital had two significant items, an increase in Accounts Receivable, Net and Accrued Taxes, Net. During the first quarter of 2006, we did not make any federal income tax payments and collected receivables from our affiliates related to power sales, settled litigation and emission allowances.

Investing Activities

Net Cash Flows Used For Investing Activities during 2007 and 2006 primarily reflect our construction expenditures of $202 million and $197 million, respectively. Construction expenditures are primarily for projects to improve service reliability for transmission and distribution, as well as environmental upgrades for both periods. In 2006, capital projects for transmission expenditures were primarily related to the Wyoming-Jacksons Ferry 765 KV line placed into service in June 2006. Environmental upgrades include the installation of selective catalytic reduction equipment on our plants and the flue gas desulfurization project at the Amos and Mountaineer plants. In February 2007, environmental upgrades were completed for the Mountaineer plant. For the remainder of 2007, we expect construction expenditures to be approximately $460 million.

Financing Activities

Net Cash Flows From Financing Activities were $25 million in 2007. We had a net increase of $48 million in borrowings from the Utility Money Pool and paid $15 million in dividends on common stock.

Net Cash Flows Used For Financing Activities were $16 million in 2006. In 2006, we retired a First Mortgage Bond of $100 million and incurred obligations of $50 million relating to pollution control bonds. We repaid short-term borrowings from the Utility Money Pool of $30 million. In addition, we received funds of $68 million related to a long-term coal purchase contract amended in March 2006.

Financing Activity

There were no material long-term debt issuances and retirements during the first three months of 2007.

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt or refinance long-term debt maturities. In addition, we participate in the Utility Money Pool, which provides access to AEP’s liquidity.

Summary Obligation Information

A summary of our contractual obligations is included in our 2006 Annual Report and has not changed significantly from year-end.

Significant Factors

New Generation

In January 2006, we filed a petition with the WVPSC requesting our approval of a Certificate of Public Convenience and Necessity to construct a 629 MW IGCC plant adjacent to our existing Mountaineer Generating Station in Mason County, WV. In January 2007, at our 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, we 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.

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 us 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, we continue to have an active fuel clause recovery mechanism in Virginia and continue to practice deferred fuel accounting. Also, under the restructuring law, we defer incremental environmental generation costs and incremental transmission and distribution reliability costs for future recovery, to the extent such costs are not being recovered when incurred, and amortize 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, subject to Virginia SCC approval, certain environmental retrofits, and a floor on the allowed return on equity based on the average earned return on equities’ of regional vertically integrated electric utilities. Effective July 1, 2007, the amendments allow utilities to retain a minimum of 25% of the margins from off-system sales with the remaining margins from such sales credited against fuel factor expenses. The legislation also allows us to continue to defer and recover incremental environmental and reliability costs incurred through December 31, 2008. We expect this new form of cost-based ratemaking should improve our annual return on equity and cash flow from operations when new ratemaking begins in 2009. However, with the return of cost-based regulation, our 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 we are required to re-establish certain net regulatory liabilities applicable to our generation/supply business. The timing and earnings effect from such reapplication of SFAS 71 regulatory accounting for our Virginia generation/supply business are uncertain at this time.

Litigation and Regulatory Activity

In the ordinary course of business, we 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 which have a probable likelihood of loss and the loss amount can be estimated. For details on our pending litigation and regulatory proceedings, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies in our 2006 Annual Report. Also, see Note 3 - Rate Matters and Note 4 - Commitments, Guarantees and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” 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, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management assets and liabilities are managed by AEPSC as agent for us. The related risk management policies and procedures are instituted and administered by AEPSC. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

The following two tables summarize the various mark-to-market (MTM) positions included on our condensed consolidated balance sheet as of March 31, 2007 and the reasons for changes in our total MTM value as compared to December 31, 2006.
 
Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of March 31, 2007
(in thousands)

   
MTM Risk Management Contracts
 
Cash Flow &
Fair Value
Hedges
 
DETM
Assignment (a)
 
Total
 
Current Assets
 
$
66,058
 
$
1,405
 
$
-
 
$
67,463
 
Noncurrent Assets
   
84,718
   
1,269
   
-
   
85,987
 
Total MTM Derivative Contract Assets
   
150,776
   
2,674
   
-
   
153,450
 
                           
Current Liabilities
   
(47,767
)
 
(6,899
)
 
(3,152
)
 
(57,818
)
Noncurrent Liabilities
   
(49,833
)
 
(804
)
 
(8,358
)
 
(58,995
)
Total MTM Derivative Contract Liabilities
   
(97,600
)
 
(7,703
)
 
(11,510
)
 
(116,813
)
                           
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
53,176
 
$
(5,029
)
$
(11,510
)
$
36,637
 

(a)
See “Natural Gas Contracts with DETM” section of Note 16 of the 2006 Annual Report.
 
MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2007
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2006
 
$
52,489
 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
   
(5,389
)
Fair Value of New Contracts at Inception When Entered During the Period (a)
   
255
 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period
   
(35
)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts
   
-
 
Changes in Fair Value Due to Market Fluctuations During the Period (b)
   
4,918
 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
   
938
 
Total MTM Risk Management Contract Net Assets
   
53,176
 
Net Cash Flow & Fair Value Hedge Contracts
   
(5,029
)
DETM Assignment (d)
   
(11,510
)
Total MTM Risk Management Contract Net Assets at March 31, 2007
 
$
36,637
 

(a)
Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)
Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)
“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(d)
See “Natural Gas Contracts with DETM” section of Note 16 of the 2006 Annual Report.

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

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
Fair Value of Contracts as of March 31, 2007
(in thousands)

   
Remainder
2007
 
2008
 
2009
 
2010
 
2011
 
After
2011
 
Total
 
Prices Actively Quoted - Exchange Traded Contracts
 
$
15,650
 
$
(644
)
$
706
 
$
-
 
$
-
 
$
-
 
$
15,712
 
Prices Provided by Other External Sources -
   OTC Broker Quotes (a)
   
3,482
   
13,908
   
11,448
   
4,542
   
-
   
-
   
33,380
 
Prices Based on Models and Other Valuation Methods (b)
   
(3,723
)
 
(2,358
)
 
1,822
   
5,482
   
1,235
   
1,626
   
4,084
 
Total
 
$
15,409
 
$
10,906
 
$
13,976
 
$
10,024
 
$
1,235
 
$
1,626
 
$
53,176
 

(a)
“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)
“Prices Based on Models and Other Valuation Methods” is used in 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 are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.
   
 
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.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed Consolidated Balance Sheet

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 anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

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 the changes from December 31, 2006 to March 31, 2007. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2007
(in thousands)

   
Power
 
Foreign
Currency
 
Interest
Rate
 
Total
 
Beginning Balance in AOCI December 31, 2006
 
$
5,332
 
$
(164
)
$
(7,715
)
$
(2,547
)
Changes in Fair Value
   
(5,612
)
 
-
   
-
   
(5,612
)
Reclassifications from AOCI to Net Income for 
   Cash Flow Hedges Settled
   
(2,221
)
 
2
   
347
   
(1,872
)
Ending Balance in AOCI March 31, 2007
 
$
(2,501
)
$
(162
)
$
(7,368
)
$
(10,031
)

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $4,214 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

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:

Three Months Ended
March 31, 2007
       
Twelve Months Ended
December 31, 2006
(in thousands)
       
(in thousands)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
$712
 
$2,328
 
$1,037
 
$282
       
$756
 
$1,915
 
$658
 
$358

The High VaR for the twelve months ended December 31, 2006 occurred in the third quarter due to volatility in the ECAR/PJM region.

VaR Associated with Debt Outstanding

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 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 $176 million and $153 million at March 31, 2007 and December 31, 2006, respectively. 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 negatively affect our results of operations or consolidated financial position.



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
REVENUES
         
Electric Generation, Transmission and Distribution
 
$
601,546
 
$
559,993
 
Sales to AEP Affiliates
   
61,545
   
71,772
 
Other
   
2,637
   
2,676
 
TOTAL
   
665,728
   
634,441
 
               
EXPENSES
             
Fuel and Other Consumables Used for Electric Generation
   
171,186
   
166,853
 
Purchased Electricity for Resale
   
35,950
   
27,616
 
Purchased Electricity from AEP Affiliates
   
127,601
   
122,399
 
Other Operation
   
67,629
   
69,901
 
Maintenance
   
45,753
   
37,839
 
Depreciation and Amortization
   
59,160
   
48,268
 
Taxes Other Than Income Taxes
   
21,275
   
23,092
 
TOTAL
   
528,554
   
495,968
 
               
OPERATING INCOME
   
137,174
   
138,473
 
               
Other Income (Expense):
             
Interest Income
   
639
   
951
 
Carrying Costs Income
   
3,166
   
6,011
 
Allowance for Equity Funds Used During Construction
   
2,777
   
2,476
 
Interest Expense
   
(31,823
)
 
(30,268
)
               
INCOME BEFORE INCOME TAXES
   
111,933
   
117,643
 
               
Income Tax Expense
   
41,706
   
44,049
 
               
NET INCOME
   
70,227
   
73,594
 
               
Preferred Stock Dividend Requirements including Capital Stock Expense
   
238
   
238
 
               
EARNINGS APPLICABLE TO COMMON STOCK
 
$
69,989
 
$
73,356
 

The common stock of APCo is wholly-owned by AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
                            
DECEMBER 31, 2005
 
$
260,458
 
$
924,837
 
$
635,016
 
$
(16,610
)
$
1,803,701
 
                                 
Common Stock Dividends
               
(2,500
)
       
(2,500
)
Preferred Stock Dividends
               
(200
)
       
(200
)
Capital Stock Expense
         
38
   
(38
)
       
-
 
TOTAL
                           
1,801,001
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Income, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $7,144
                     
13,268
   
13,268
 
NET INCOME
               
73,594
         
73,594
 
TOTAL COMPREHENSIVE INCOME
                           
86,862
 
                                 
MARCH 31, 2006
 
$
260,458
 
$
924,875
 
$
705,872
 
$
(3,342
)
$
1,887,863
 
                                 
DECEMBER 31, 2006
 
$
260,458
 
$
1,024,994
 
$
805,513
 
$
(54,791
)
$
2,036,174
 
                                 
FIN 48 Adoption, Net of Tax
               
(2,685
)
       
(2,685
)
Common Stock Dividends
               
(15,000
)
       
(15,000
)
Preferred Stock Dividends
               
(200
)
       
(200
)
Capital Stock Expense
         
38
   
(38
)
       
-
 
TOTAL
                           
2,018,289
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $4,030
                     
(7,484
)
 
(7,484
)
NET INCOME
               
70,227
         
70,227
 
TOTAL COMPREHENSIVE INCOME
                           
62,743
 
                                 
MARCH 31, 2007
 
$
260,458
 
$
1,025,032
 
$
857,817
 
$
(62,275
)
$
2,081,032
 

  See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2007 and December 31, 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
1,987
 
$
2,318
 
Accounts Receivable:
             
Customers
   
199,112
   
180,190
 
Affiliated Companies
   
85,919
   
98,237
 
Accrued Unbilled Revenues
   
29,618
   
46,281
 
Miscellaneous
   
4,849
   
3,400
 
Allowance for Uncollectible Accounts
   
(4,573
)
 
(4,334
)
   Total Accounts Receivable
   
314,925
   
323,774
 
Fuel
   
72,075
   
77,077
 
Materials and Supplies
   
69,428
   
56,235
 
Risk Management Assets
   
67,463
   
105,376
 
Accrued Tax Benefits
   
9,189
   
3,748
 
Regulatory Asset for Under-Recovered Fuel Costs
   
17,789
   
29,526
 
Prepayments and Other
   
15,682
   
20,126
 
TOTAL
   
568,538
   
618,180
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
3,363,911
   
2,844,803
 
Transmission
   
1,640,046
   
1,620,512
 
Distribution
   
2,276,327
   
2,237,887
 
Other
   
342,014
   
339,450
 
Construction Work in Progress
   
512,388
   
957,626
 
Total
   
8,134,686
   
8,000,278
 
Accumulated Depreciation and Amortization
   
2,470,106
   
2,476,290
 
TOTAL - NET
   
5,664,580
   
5,523,988
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
612,352
   
622,153
 
Long-term Risk Management Assets
   
85,987
   
88,906
 
Deferred Charges and Other
   
167,913
   
163,089
 
TOTAL
   
866,252
   
874,148
 
               
TOTAL ASSETS
 
$
7,099,370
 
$
7,016,316
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2007 and December 31, 2006
(Unaudited)

   
2007
 
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
 
$
82,860
 
$
34,975
 
Accounts Payable:
             
General
   
286,892
   
296,437
 
Affiliated Companies
   
77,642
   
105,525
 
Long-term Debt Due Within One Year - Nonaffiliated
   
324,169
   
324,191
 
Risk Management Liabilities
   
57,818
   
81,114
 
Customer Deposits
   
54,193
   
56,364
 
Accrued Taxes
   
87,864
   
60,056
 
Accrued Interest
   
55,787
   
30,617
 
Other
   
119,509
   
142,326
 
TOTAL
   
1,146,734
   
1,131,605
 
               
NONCURRENT LIABILITIES
             
Long-term Debt - Nonaffiliated
   
2,174,951
   
2,174,473
 
Long-term Debt - Affiliated
   
100,000
   
100,000
 
Long-term Risk Management Liabilities
   
58,995
   
64,909
 
Deferred Income Taxes
   
933,703
   
957,229
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
307,018
   
309,724
 
Deferred Credits and Other
   
279,174
   
224,439
 
TOTAL
   
3,853,841
   
3,830,774
 
               
TOTAL LIABILITIES
   
5,000,575
   
4,962,379
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
17,763
   
17,763
 
               
Commitments and Contingencies (Note 4)
             
               
COMMON SHAREHOLDER’S EQUITY
             
Common Stock - No Par Value:
             
Authorized - 30,000,000 Shares
             
Outstanding - 13,499,500 Shares
   
260,458
   
260,458
 
Paid-in Capital
   
1,025,032
   
1,024,994
 
Retained Earnings
   
857,817
   
805,513
 
Accumulated Other Comprehensive Income (Loss)
   
(62,275
)
 
(54,791
)
TOTAL
   
2,081,032
   
2,036,174
 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 
$
7,099,370
 
$
7,016,316
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
OPERATING ACTIVITIES
           
Net Income
 
$
70,227
 
$
73,594
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
59,160
   
48,268
 
Deferred Income Taxes
   
(3,901
)
 
(11,423
)
Carrying Costs Income
   
(3,166
)
 
(6,011
)
Mark-to-Market of Risk Management Contracts
   
(401
)
 
(5,696
)
Change in Other Noncurrent Assets
   
(12,747
)
 
4,020
 
Change in Other Noncurrent Liabilities
   
30,172
   
5,848
 
Changes in Certain Components of Working Capital:
             
Accounts Receivable, Net
   
8,849
   
75,278
 
Fuel, Materials and Supplies
   
(1,034
)
 
13,028
 
Accounts Payable
   
(19,891
)
 
(30,148
)
Customer Deposits
   
(2,171
)
 
(13,530
)
Accrued Taxes, Net
   
29,539
   
56,180
 
Accrued Interest
   
21,608
   
15,511
 
Fuel Over/Under Recovery, Net
   
12,987
   
7,832
 
Other Current Assets
   
3,899
   
(1,718
)
Other Current Liabilities
   
(17,101
)
 
(20,053
)
Net Cash Flows From Operating Activities
   
176,029
   
210,980
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(202,007
)
 
(196,561
)
Change in Other Cash Deposits, Net
   
(29
)
 
-
 
Proceeds from Sales of Assets
   
1,142
   
1,664
 
Net Cash Flows Used For Investing Activities
   
(200,894
)
 
(194,897
)
               
FINANCING ACTIVITIES
             
Issuance of Long-term Debt - Nonaffiliated
   
-
   
49,677
 
Change in Advances from Affiliates, Net
   
47,885
   
(29,941
)
Retirement of Long-term Debt - Nonaffiliated
   
(3
)
 
(100,003
)
Principal Payments for Capital Lease Obligations
   
(1,112
)
 
(1,483
)
Funds From Amended Coal Contract
   
-
   
68,078
 
Amortization of Funds From Amended Coal Contract
   
(7,036
)
 
-
 
Dividends Paid on Common Stock
   
(15,000
)
 
(2,500
)
Dividends Paid on Cumulative Preferred Stock
   
(200
)
 
(200
)
Net Cash Flows From (Used For) Financing Activities
   
24,534
   
(16,372
)
               
Net Decrease in Cash and Cash Equivalents
   
(331
)
 
(289
)
Cash and Cash Equivalents at Beginning of Period
   
2,318
   
1,741
 
Cash and Cash Equivalents at End of Period
 
$
1,987
 
$
1,452
 

 
SUPPLEMENTARY INFORMATION
           
Cash Paid for Interest, Net of Capitalized Amounts
 
$
7,084
 
$
14,686
 
Net Cash Paid for Income Taxes
   
7,775
   
1,771
 
Noncash Acquisitions Under Capital Leases
   
444
   
1,184
 
Construction Expenditures Included in Accounts Payable at March 31,
   
113,021
   
83,682
 

 See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to APCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to APCo.

 
Footnote Reference
Significant Accounting Matters
Note 1
New Accounting Pronouncements
Note 2
Rate Matters
Note 3
Commitments, Guarantees and Contingencies
Note 4
Benefit Plans
Note 6
Business Segments
Note 7
Income Taxes
Note 8
Financing Activities
Note 9










 
 
 
 


COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES


 
 
 
 
 
 

 




COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations

First Quarter of 2007 Compared to First Quarter of 2006

Reconciliation of First Quarter of 2006 to First Quarter of 2007
Net Income
(in millions)

First Quarter of 2006
       
$
51
 
               
Changes in Gross Margin:
             
Retail Margins
   
27
       
Off-system Sales
   
(11
)
     
Transmission Revenues
   
(7
)
     
Other
   
(4
)
     
Total Change in Gross Margin
         
5
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(10
)
     
Depreciation and Amortization
   
(4
)
     
Taxes Other Than Income Taxes
   
(1
)
     
Interest Expense
   
2
       
Other
   
1
       
Total Change in Operating Expenses and Other
         
(12
)
               
Income Tax Expense
         
3
 
               
First Quarter of 2007
       
$
47
 

Net Income decreased $4 million to $47 million in 2007. The key driver of the decrease was a $12 million increase in Operating Expenses and Other offset by a $5 million increase in Gross Margin and a $3 million decrease in Income Tax Expense.

The major components of our increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·
Retail Margins increased $27 million primarily due to:
 
·
An $11 million increase in residential and commercial revenue primarily due to a 27% increase in heating degree days.
 
·
A $10 million increase in rate revenues related to a $4 million increase in our RSP, a $3 million increase related to rate recovery of storm costs and a $3 million increase related to rate recovery of IGCC preconstruction costs (see “Ohio Rate Matters” section of Note 3). The increase in rate recovery of storm costs was offset by the amortization of deferred expenses in Other Operation and Maintenance. The increase in rate recovery of IGCC preconstruction costs was offset by the amortization of deferred expenses in Depreciation and Amortization.
 
·
A $7 million increase in industrial revenue due to the addition of Ormet, a major industrial customer (see “Ormet” section of Note 3).
·
Margins from Off-system Sales decreased $11 million primarily due to an $8 million decrease in physical sales margins and a $4 million decrease in margins from optimization activities.
·
Transmission Revenues decreased $7 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.
·
Other revenues decreased $4 million primarily due to lower gains on sales of emission allowances.

Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expenses increased $10 million primarily due to:
·   
A $5 million increase in overhead line expenses due in part to the amortization of deferred storm expenses recovered through a cost-recovery rider. The increase in amortization of deferred storm expenses was offset by a corresponding increase in Retail Margins.
·   
A $3 million increase in our net allocated transmission costs related to the Transmission Equalization Agreement as a result of the addition of APCo’s Wyoming-Jacksons Ferry 765 kV line, which was energized and placed in service in June 2006.
·
Depreciation and Amortization increased $4 million primarily due to the amortization of IGCC preconstruction costs of $3 million in the first quarter of 2007. The increase in amortization of IGCC preconstruction costs was offset by a corresponding increase in Retail Margins.
·
Interest Expense decreased $2 million primarily due to an increase in allowance for borrowed funds used during construction.

Income Taxes

Income Tax Expense decreased $3 million primarily due to a decrease in pretax book income and state income taxes offset in part by the recording of tax adjustments.

Critical Accounting Estimates

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

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management assets and liabilities are managed by AEPSC as agent for us. The related risk management policies and procedures are instituted and administered by AEPSC. See the complete discussion and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

VaR Associated with Debt Outstanding

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 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 $80 million and $70 million at March 31, 2007 and December 31, 2006, respectively. 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 negatively affect our results of operations or consolidated financial position.



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
REVENUES
         
Electric Generation, Transmission and Distribution
 
$
423,466
 
$
413,669
 
Sales to AEP Affiliates
   
23,013
   
13,769
 
Other
   
1,433
   
1,330
 
TOTAL
   
447,912
   
428,768
 
               
EXPENSES
             
Fuel and Other Consumables Used for Electric Generation
   
75,862
   
69,820
 
Purchased Electricity for Resale
   
31,311
   
24,765
 
Purchased Electricity from AEP Affiliates
   
83,541
   
82,477
 
Other Operation
   
61,159
   
55,945
 
Maintenance
   
22,564
   
17,934
 
Depreciation and Amortization
   
50,297
   
45,828
 
Taxes Other Than Income Taxes
   
40,582
   
39,502
 
TOTAL
   
365,316
   
336,271
 
               
OPERATING INCOME
   
82,596
   
92,497
 
               
Other Income (Expense):
             
Interest Income
   
422
   
455
 
Carrying Costs Income
   
1,092
   
716
 
Allowance for Equity Funds Used During Construction
   
772
   
464
 
Interest Expense
   
(15,281
)
 
(17,520
)
               
INCOME BEFORE INCOME TAXES
   
69,601
   
76,612
 
               
Income Tax Expense
   
22,620
   
25,275
 
               
NET INCOME       46,981      51,337  
               
Capital Stock Expense
   
39
   
39
 
             
EARNINGS APPLICABLE TO COMMON STOCK   $  46,942   $  51,298  

The common stock of CSPCo is wholly-owned by AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
                            
DECEMBER 31, 2005
 
$
41,026
 
$
580,035
 
$
361,365
 
$
(880
)
$
981,546
 
                                 
Common Stock Dividends
               
(22,500
)
       
(22,500
)
Capital Stock Expense
         
39
   
(39
)
       
-
 
TOTAL
                           
959,046
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Income, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $2,176
                     
4,041
   
4,041
 
NET INCOME
               
51,337
         
51,337
 
TOTAL COMPREHENSIVE INCOME
                           
55,378
 
                                 
MARCH 31, 2006
 
$
41,026
 
$
580,074
 
$
390,163
 
$
3,161
 
$
1,014,424
 
                                 
DECEMBER 31, 2006
 
$
41,026
 
$
580,192
 
$
456,787
 
$
(21,988
)
$
1,056,017
 
                                 
FIN 48 Adoption, Net of Tax
               
(3,022
)
       
(3,022
)
Common Stock Dividends
               
(20,000
)
       
(20,000
)
Capital Stock Expense
         
39
   
(39
)
       
-
 
TOTAL
                           
1,032,995
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $2,841
                     
(5,276
)
 
(5,276
)
NET INCOME
               
46,981
         
46,981
 
TOTAL COMPREHENSIVE INCOME
                           
41,705
 
                                 
MARCH 31, 2007
 
$
41,026
 
$
580,231
 
$
480,707
 
$
(27,264
)
$
1,074,700
 

   See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2007 and December 31, 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
237
 
$
1,319
 
Advances to Affiliates
   
922
   
-
 
Accounts Receivable:
             
Customers
   
59,380
   
49,362
 
Affiliated Companies
   
35,351
   
62,866
 
Accrued Unbilled Revenues
   
8,011
   
11,042
 
Miscellaneous
   
5,626
   
4,895
 
Allowance for Uncollectible Accounts
   
(588
)
 
(546
)
   Total Accounts Receivable
   
107,780
   
127,619
 
Fuel
   
31,320
   
37,348
 
Materials and Supplies
   
34,575
   
31,765
 
Emission Allowances
   
8,971
   
3,493
 
Risk Management Assets
   
36,969
   
66,238
 
Accrued Tax Benefits
   
-
   
4,763
 
Prepayments and Other
   
11,734
   
16,107
 
TOTAL
   
232,508
   
288,652
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
1,954,377
   
1,896,073
 
Transmission
   
481,875
   
479,119
 
Distribution
   
1,496,080
   
1,475,758
 
Other
   
190,645
   
191,103
 
Construction Work in Progress
   
269,771
   
294,138
 
Total
   
4,392,748
   
4,336,191
 
Accumulated Depreciation and Amortization
   
1,629,386
   
1,611,043
 
TOTAL - NET
   
2,763,362
   
2,725,148
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
277,251
   
298,304
 
Long-term Risk Management Assets
   
46,978
   
56,206
 
Deferred Charges and Other
   
131,818
   
152,379
 
TOTAL
   
456,047
   
506,889
 
               
TOTAL ASSETS
 
$
3,451,917
 
$
3,520,689
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY
March 31, 2007 and December 31, 2006
(Unaudited)

   
2007
 
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
 
$
-
 
$
696
 
Accounts Payable:
             
General
   
97,767
   
112,431
 
Affiliated Companies
   
51,552
   
59,538
 
Long-term Debt Due Within One Year - Nonaffiliated
   
52,000
   
-
 
Risk Management Liabilities
   
31,365
   
49,285
 
Customer Deposits
   
37,563
   
34,991
 
Accrued Taxes
   
144,223
   
166,551
 
Accrued Interest
   
17,698
   
20,868
 
Other
   
34,767
   
37,143
 
TOTAL
   
466,935
   
481,503
 
               
NONCURRENT LIABILITIES
             
Long-term Debt - Nonaffiliated
   
1,045,422
   
1,097,322
 
Long-term Debt - Affiliated
   
100,000
   
100,000
 
Long-term Risk Management Liabilities
   
32,396
   
40,477
 
Deferred Income Taxes
   
462,516
   
475,888
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
168,597
   
179,048
 
Deferred Credits and Other
   
101,351
   
90,434
 
TOTAL
   
1,910,282
   
1,983,169
 
               
TOTAL LIABILITIES
   
2,377,217
   
2,464,672
 
               
Commitments and Contingencies (Note 4)
             
               
COMMON SHAREHOLDER’S EQUITY
             
Common Stock - No Par Value:
             
Authorized - 24,000,000 Shares
             
Outstanding - 16,410,426 Shares
   
41,026
   
41,026
 
Paid-in Capital
   
580,231
   
580,192
 
Retained Earnings
   
480,707
   
456,787
 
Accumulated Other Comprehensive Income (Loss)
   
(27,264
)
 
(21,988
)
TOTAL
   
1,074,700
   
1,056,017
 
               
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY
 
$
3,451,917
 
$
3,520,689
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
OPERATING ACTIVITIES
           
Net Income
 
$
46,981
 
$
51,337
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
50,297
   
45,828
 
Deferred Income Taxes
   
(716
)
 
3,816
 
Carrying Costs Income
   
(1,092
)
 
(716
)
Mark-to-Market of Risk Management Contracts
   
4,400
   
(3,624
)
Deferred Property Taxes
   
18,954
   
10,884
 
Change in Other Noncurrent Assets
   
(912
)
 
(11,325
)
Change in Other Noncurrent Liabilities
   
(15,510
)
 
5,800
 
Changes in Certain Components of Working Capital:
             
Accounts Receivable, Net
   
19,839
   
33,295
 
Fuel, Materials and Supplies
   
3,218
   
(7,431
)
Accounts Payable
   
(7,659
)
 
12,540
 
Customer Deposits
   
2,572
   
(7,901
)
Accrued Taxes, Net
   
(8,651
)
 
(7,873
)
Accrued Interest
   
(5,658
)
 
(4,127
)
Other Current Assets
   
5,694
   
(728
)
Other Current Liabilities
   
(5,056
)
 
(6,571
)
Net Cash Flows From Operating Activities
   
106,701
   
113,204
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(85,641
)
 
(65,032
)
Change in Other Cash Deposits, Net
   
(20
)
 
(1,151
)
Change in Advances to Affiliates, Net
   
(922
)
 
(6,867
)
Proceeds from Sale of Assets
   
189
   
531
 
Net Cash Flows Used For Investing Activities
   
(86,394
)
 
(72,519
)
               
FINANCING ACTIVITIES
             
Change in Advances from Affiliates, Net
   
(696
)
 
(17,609
)
Principal Payments for Capital Lease Obligations
   
(693
)
 
(759
)
Dividends Paid on Common Stock
   
(20,000
)
 
(22,500
)
Net Cash Flows Used For Financing Activities
   
(21,389
)
 
(40,868
)
               
Net Decrease in Cash and Cash Equivalents
   
(1,082
)
 
(183
)
Cash and Cash Equivalents at Beginning of Period
   
1,319
   
940
 
Cash and Cash Equivalents at End of Period
 
$
237
 
$
757
 

SUPPLEMENTARY INFORMATION
           
Cash Paid for Interest, Net of Capitalized Amounts
 
$
20,132
 
$
22,320
 
Net Cash Paid (Received) for Income Taxes
   
(2,907
)
 
2,533
 
Noncash Acquisitions Under Capital Leases
   
275
   
1,102
 
Construction Expenditures Included in Accounts Payable at March 31,
   
20,636
   
12,054
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to CSPCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to CSPCo.

 
Footnote
Reference
Significant Accounting Matters
Note 1
New Accounting Pronouncements
Note 2
Rate Matters
Note 3
Commitments, Guarantees and Contingencies
Note 4
Acquisitions, Dispositions and Assets Held for Sale
Note 5
Benefit Plans
Note 6
Business Segments
Note 7
Income Taxes
Note 8
Financing Activities
Note 9
 



 





 
 
 
 
 

 
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
 
 
 
 
 

 
 
 
 
 
 

 






INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations

First Quarter of 2007 Compared to First Quarter of 2006

Reconciliation of First Quarter of 2006 to First Quarter of 2007
Net Income
(in millions)

First Quarter of 2006
       
$
58
 
               
Changes in Gross Margin:
             
Retail Margins
   
(24
)
     
FERC Municipals and Cooperatives
   
9
       
Off-system Sales
   
(4
)
     
Transmission Revenues
   
(2
)
     
Other
   
(7
)
     
Total Change in Gross Margin
         
(28
)
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(6
)
     
Depreciation and Amortization
   
(7
)
     
Other Income
   
(1
)
     
Interest Expense
   
(2
)
     
Total Change in Operating Expenses and Other
         
(16
)
               
Income Tax Expense
         
15
 
               
First Quarter of 2007
       
$
29
 

Net Income decreased $29 million to $29 million in 2007. The key driver of the decrease was a $28 million decrease in Gross Margin.

The major components of our decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·
Retail Margins decreased $24 million primarily due to a reduction in capacity settlement revenues of $23 million under the Interconnection Agreement reflecting our new peak demand in July 2006.
·
FERC Municipals and Cooperatives margins increased $9 million due to the addition of new municipal contracts including new rates and increased demand effective July 2006 and January 2007.
·
Margins from Off-system Sales decreased $4 million primarily due to an $11 million decrease in physical sales margins partially offset by a $6 million increase in margins from optimization activities.
·
Transmission Revenues decreased $2 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.
·
Other revenues decreased $7 million primarily due to decreased River Transportation Division (RTD) revenues for barging coal and decreased gains on sales of emission allowances. RTD related expenses which offset the RTD revenue decrease are included in Other Operation on the Condensed Consolidated Statements of Income resulting in our earning only a return approved under regulatory order.
 
Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expenses increased $6 million primarily due to a $5 million increase in transmission expense due to our reduced credits under the Transmission Equalization Agreement. Our credits decreased due to our July 2006 peak and due to APCo’s addition of the Wyoming-Jacksons Ferry 765 kV line, which was energized and placed in service in June 2006 thus decreasing our share of the transmission investment pool.
·
Depreciation and Amortization expense increased $7 million primarily due to a $5 million increase in depreciation related to capital additions and a $2 million increase in amortization related to capitalized software development costs.
·
Interest Expense increased $2 million primarily due to an increase in outstanding long-term debt and higher interest rates.

Income Taxes

Income Tax Expense decreased $15 million primarily due to a decrease in pretax book income.

Critical Accounting Estimates

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

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management assets and liabilities are managed by AEPSC as agent for us. The related risk management policies and procedures are instituted and administered by AEPSC. See the complete discussion and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

VaR Associated with Debt Outstanding

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 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 $108 million and $93 million at March 31, 2007 and December 31, 2006, respectively. 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 negatively affect our results of operations or consolidated financial position.



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
REVENUES
         
Electric Generation, Transmission and Distribution
 
$
405,164
 
$
403,769
 
Sales to AEP Affiliates
   
67,429
   
88,534
 
Other - Affiliated
   
12,667
   
15,094
 
Other - Nonaffiliated
   
7,609
   
8,382
 
TOTAL
   
492,869
   
515,779
 
               
EXPENSES
             
Fuel and Other Consumables Used for Electric Generation
   
96,117
   
89,452
 
Purchased Electricity for Resale
   
17,940
   
11,010
 
Purchased Electricity from AEP Affiliates
   
77,513
   
86,422
 
Other Operation
   
120,733
   
111,617
 
Maintenance
   
42,430
   
45,219
 
Depreciation and Amortization
   
56,307
   
49,715
 
Taxes Other Than Income Taxes
   
17,994
   
18,906
 
TOTAL
   
429,034
   
412,341
 
               
OPERATING INCOME
   
63,835
   
103,438
 
               
Other Income (Expense):
             
Interest Income
   
588
   
694
 
Allowance for Equity Funds Used During Construction
   
265
   
1,924
 
Interest Expense
   
(19,821
)
 
(17,533
)
               
INCOME BEFORE INCOME TAXES
   
44,867
   
88,523
 
               
Income Tax Expense
   
15,404
   
30,645
 
               
NET INCOME
   
29,463
   
57,878
 
               
Preferred Stock Dividend Requirements
   
85
   
85
 
               
EARNINGS APPLICABLE TO COMMON STOCK
 
$
29,378
 
$
57,793
 

The common stock of I&M is wholly-owned by AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2005
 
$
56,584
 
$
861,290
 
$
305,787
 
$
(3,569
)
$
1,220,092
 
                                 
Common Stock Dividends
               
(10,000
)
       
(10,000
)
Preferred Stock Dividends
               
(85
)
       
(85
)
TOTAL
                           
1,210,007
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Income, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $2,265
                     
4,207
   
4,207
 
NET INCOME
               
57,878
         
57,878
 
TOTAL COMPREHENSIVE INCOME
                           
62,085
 
                                 
MARCH 31, 2006
 
$
56,584
 
$
861,290
 
$
353,580
 
$
638
 
$
1,272,092
 
                                 
DECEMBER 31, 2006
 
$
56,584
 
$
861,290
 
$
386,616
 
$
(15,051
)
$
1,289,439
 
                                 
FIN 48 Adoption, Net of Tax
               
327
         
327
 
Common Stock Dividends
               
(10,000
)
       
(10,000
)
Preferred Stock Dividends
               
(85
)
       
(85
)
TOTAL
                           
1,279,681
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $2,850
                     
(5,293
)
 
(5,293
)
NET INCOME
               
29,463
         
29,463
 
TOTAL COMPREHENSIVE INCOME
                           
24,170
 
                                 
MARCH 31, 2007
 
$
56,584
 
$
861,290
 
$
406,321
 
$
(20,344
)
$
1,303,851
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2007 and December 31, 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
753
 
$
1,369
 
Accounts Receivable:
             
Customers
   
86,128
   
82,102
 
Affiliated Companies
   
66,155
   
108,288
 
Accrued Unbilled Revenues
   
806
   
2,206
 
Miscellaneous
   
2,571
   
1,838
 
Allowance for Uncollectible Accounts
   
(616
)
 
(601
)
   Total Accounts Receivable
   
155,044
   
193,833
 
Fuel
   
47,818
   
64,669
 
Materials and Supplies
   
136,373
   
129,953
 
Risk Management Assets
   
39,175
   
69,752
 
Accrued Tax Benefits
   
8,680
   
27,378
 
Prepayments and Other
   
13,500
   
15,170
 
TOTAL
   
401,343
   
502,124
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
3,383,343
   
3,363,813
 
Transmission
   
1,052,730
   
1,047,264
 
Distribution
   
1,143,815
   
1,102,033
 
Other (including nuclear fuel and coal mining)
   
516,972
   
529,727
 
Construction Work in Progress
   
144,856
   
183,893
 
Total
   
6,241,716
   
6,226,730
 
Accumulated Depreciation, Depletion and Amortization
   
2,949,796
   
2,914,131
 
TOTAL - NET
   
3,291,920
   
3,312,599
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
292,704
   
314,805
 
Spent Nuclear Fuel and Decommissioning Trusts
   
1,262,960
   
1,248,319
 
Long-term Risk Management Assets
   
49,470
   
59,137
 
Deferred Charges and Other
   
117,384
   
109,453
 
TOTAL
   
1,722,518
   
1,731,714
 
               
TOTAL ASSETS
 
$
5,415,781
 
$
5,546,437
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2007 and December 31, 2006
(Unaudited)

   
2007
 
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
 
$
45,759
 
$
91,173
 
Accounts Payable:
             
General
   
99,223
   
146,733
 
Affiliated Companies
   
57,940
   
65,497
 
Long-term Debt Due Within One Year - Nonaffiliated
   
50,000
   
50,000
 
Risk Management Liabilities
   
33,643
   
52,083
 
Customer Deposits
   
31,436
   
34,946
 
Accrued Taxes
   
76,087
   
59,652
 
Other
   
115,714
   
128,461
 
TOTAL
   
509,802
   
628,545
 
               
NONCURRENT LIABILITIES
             
Long-term Debt - Nonaffiliated
   
1,508,695
   
1,505,135
 
Long-term Risk Management Liabilities
   
34,243
   
42,641
 
Deferred Income Taxes
   
311,584
   
335,000
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
739,972
   
753,402
 
Asset Retirement Obligations
   
820,371
   
809,853
 
Deferred Credits and Other
   
179,181
   
174,340
 
TOTAL
   
3,594,046
   
3,620,371
 
               
TOTAL LIABILITIES
   
4,103,848
   
4,248,916
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
8,082
   
8,082
 
               
Commitments and Contingencies (Note 4)
             
               
COMMON SHAREHOLDER’S EQUITY
             
Common Stock - No Par Value:
             
Authorized - 2,500,000 Shares
             
Outstanding - 1,400,000 Shares
   
56,584
   
56,584
 
Paid-in Capital
   
861,290
   
861,290
 
Retained Earnings
   
406,321
   
386,616
 
Accumulated Other Comprehensive Income (Loss)
   
(20,344
)
 
(15,051
)
TOTAL
   
1,303,851
   
1,289,439
 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 
$
5,415,781
 
$
5,546,437
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
OPERATING ACTIVITIES
           
Net Income
 
$
29,463
 
$
57,878
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
56,307
   
49,715
 
Deferred Income Taxes
   
(3,638
)
 
3,493
 
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net
   
12,191
   
(1,639
)
Amortization of Nuclear Fuel
   
16,372
   
13,596
 
Mark-to-Market of Risk Management Contracts
   
4,897
   
(4,060
)
Deferred Property Taxes
   
(10,836
)
 
(9,839
)
Change in Other Noncurrent Assets
   
5,729
   
4,381
 
Change in Other Noncurrent Liabilities
   
(1,971
)
 
18,839
 
Changes in Certain Components of Working Capital:
             
Accounts Receivable, Net
   
38,789
   
43,019
 
Fuel, Materials and Supplies
   
14,985
   
(7,194
)
Accounts Payable
   
(38,233
)
 
(7,010
)
Customer Deposits
   
(3,510
)
 
(8,031
)
Accrued Taxes, Net
   
39,525
   
42,871
 
Accrued Rent - Rockport Plant Unit 2
   
18,464
   
18,464
 
Other Current Assets
   
1,959
   
428
 
Other Current Liabilities
   
(35,720
)
 
(20,797
)
Net Cash Flows From Operating Activities
   
144,773
   
194,114
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(62,252
)
 
(89,411
)
Purchases of Investment Securities
   
(204,874
)
 
(150,239
)
Sales of Investment Securities
   
183,927
   
134,258
 
Acquisitions of Nuclear Fuel
   
(5,366
)
 
(34,427
)
Proceeds from Sales of Assets and Other
   
248
   
1,384
 
Net Cash Flows Used For Investing Activities
   
(88,317
)
 
(138,435
)
               
FINANCING ACTIVITIES
             
Change in Advances from Affiliates, Net
   
(45,414
)
 
(44,565
)
Principal Payments for Capital Lease Obligations
   
(1,573
)
 
(1,274
)
Dividends Paid on Common Stock
   
(10,000
)
 
(10,000
)
Dividends Paid on Cumulative Preferred Stock
   
(85
)
 
(85
)
Net Cash Flows Used For Financing Activities
   
(57,072
)
 
(55,924
)
               
Net Decrease in Cash and Cash Equivalents
   
(616
)
 
(245
)
Cash and Cash Equivalents at Beginning of Period
   
1,369
   
854
 
Cash and Cash Equivalents at End of Period
 
$
753
 
$
609
 

SUPPLEMENTARY INFORMATION
           
Cash Paid for Interest, Net of Capitalized Amounts
 
$
15,048
 
$
4,776
 
Net Cash Paid (Received) for Income Taxes
   
(2,768
)
 
1,324
 
Noncash Acquisitions Under Capital Leases
   
369
   
2,218
 
Construction Expenditures Included in Accounts Payable at March 31,
   
20,243
   
27,624
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to I&M’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to I&M.
 
Footnote
Reference
   
Significant Accounting Matters
Note 1
New Accounting Pronouncements
Note 2
Rate Matters
Note 3
Commitments, Guarantees and Contingencies
Note 4
Benefit Plans
Note 6
Business Segments
Note 7
Income Taxes
Note 8
Financing Activities
Note 9











 
 

 



KENTUCKY POWER COMPANY

 
 
 
 
 
 
 
 

 






KENTUCKY POWER COMPANY
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations

First Quarter of 2007 Compared to First Quarter of 2006

Reconciliation of First Quarter of 2006 to First Quarter of 2007
Net Income
(in millions)

First Quarter of 2006
       
$
10
 
               
Changes in Gross Margin:
             
Retail Margins
   
17
       
Off-system Sales
   
(2
)
     
Transmission Revenues
   
(3
)
     
Other
   
(1
)
     
Total Change in Gross Margin
         
11
 
               
Other Operation and Maintenance
         
(3
)
               
Income Tax Expense
         
(3
)
               
First Quarter of 2007
       
$
15
 

Net Income increased $5 million to $15 million in 2007. The key driver of the increase was an $11 million increase in Gross Margin, offset by an increase in Other Operation and Maintenance expenses of $3 million and an increase in Income Tax Expense of $3 million.

The major components of our change in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·
Retail Margins increased $17 million primarily due to rate relief of $14 million from the March 2006 approval of the settlement agreement in our base rate case.
·
Transmission Revenues decreased $3 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.

Other Operation and Maintenance

Other Operation and Maintenance expenses increased $3 million primarily due to an increase in our net allocated transmission costs related to the Transmission Equalization Agreement as a result of the addition of APCo’s Wyoming-Jacksons Ferry 765 kV line which was energized and placed into service in June 2006. Other Operation and Maintenance expenses also increased as a result of increased forced outages at the Big Sandy Plant.

Income Taxes

Income Tax Expense increased $3 million primarily due to an increase in pretax book income.
 
Critical Accounting Estimates

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

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.




QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management assets and liabilities are managed by AEPSC as agent for us. The related risk management policies and procedures are instituted and administered by AEPSC. See the complete discussion and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

VaR Associated with Debt Outstanding

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 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 $19 million and $13 million at March 31, 2007 and December 31, 2006, respectively. 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 negatively affect our results of operations or financial position.




KENTUCKY POWER COMPANY
CONDENSED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
REVENUES
         
Electric Generation, Transmission and Distribution
 
$
140,486
 
$
137,620
 
Sales to AEP Affiliates
   
13,461
   
13,968
 
Other
   
149
   
259
 
TOTAL
   
154,096
   
151,847
 
               
EXPENSES
             
Fuel and Other Consumables Used for Electric Generation
   
38,304
   
43,966
 
Purchased Electricity for Resale
   
3,305
   
973
 
Purchased Electricity from AEP Affiliates
   
43,257
   
49,526
 
Other Operation
   
15,886
   
13,726
 
Maintenance
   
8,210
   
7,141
 
Depreciation and Amortization
   
11,796
   
11,479
 
Taxes Other Than Income Taxes
   
2,803
   
2,512
 
TOTAL
   
123,561
   
129,323
 
               
OPERATING INCOME
   
30,535
   
22,524
 
               
Other Income (Expense):
             
Interest Income
   
112
   
166
 
Allowance for Equity Funds Used During Construction
   
14
   
101
 
Interest Expense
   
(7,011
)
 
(7,296
)
               
INCOME BEFORE INCOME TAXES
   
23,650
   
15,495
 
               
Income Tax Expense
   
8,439
   
5,665
 
               
NET INCOME
 
$
15,211
 
$
9,830
 

The common stock of KPCo is wholly-owned by AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



KENTUCKY POWER COMPANY
CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
Common
Stock
 
Paid-in
Capital 
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2005
 
$
50,450
 
$
208,750
 
$
88,864
 
$
(223
)
$
347,841
 
                                 
Common Stock Dividends
               
(2,500
)
       
(2,500
)
TOTAL
                           
345,341
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Income, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $873
                     
1,621
   
1,621
 
NET INCOME
               
9,830
         
9,830
 
TOTAL COMPREHENSIVE INCOME
                           
11,451
 
                                 
MARCH 31, 2006
 
$
50,450
 
$
208,750
 
$
96,194
 
$
1,398
 
$
356,792
 
                                 
DECEMBER 31, 2006
 
$
50,450
 
$
208,750
 
$
108,899
 
$
1,552
 
$
369,651
 
                                 
FIN 48 Adoption, Net of Tax
               
(786
)
       
(786
)
Common Stock Dividends
               
(5,000
)
       
(5,000
)
TOTAL
                           
363,865
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $1,100
                     
(2,042
)
 
(2,042
)
NET INCOME
               
15,211
         
15,211
 
TOTAL COMPREHENSIVE INCOME
                           
13,169
 
                                 
MARCH 31, 2007
 
$
50,450
 
$
208,750
 
$
118,324
 
$
(490
)
$
377,034
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



KENTUCKY POWER COMPANY
CONDENSED BALANCE SHEETS
ASSETS
March 31, 2007 and December 31, 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
775
 
$
702
 
Accounts Receivable:
             
Customers
   
30,027
   
30,112
 
Affiliated Companies
   
9,142
   
10,540
 
Accrued Unbilled Revenues
   
6,093
   
3,602
 
Miscellaneous
   
684
   
327
 
Allowance for Uncollectible Accounts
   
(242
)
 
(227
)
   Total Accounts Receivable
   
45,704
   
44,354
 
Fuel
   
12,852
   
16,070
 
Materials and Supplies
   
10,277
   
8,726
 
Risk Management Assets
   
16,110
   
25,624
 
Accrued Tax Benefits
   
-
   
1,021
 
Margin Deposits
   
1,458
   
2,923
 
Prepayments and Other
   
2,637
   
2,425
 
TOTAL
   
89,813
   
101,845
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
480,501
   
478,955
 
Transmission
   
395,646
   
394,419
 
Distribution
   
480,690
   
481,083
 
Other
   
60,047
   
61,089
 
Construction Work in Progress
   
27,705
   
29,587
 
Total
   
1,444,589
   
1,445,133
 
Accumulated Depreciation and Amortization
   
441,565
   
442,778
 
TOTAL - NET
   
1,003,024
   
1,002,355
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
135,241
   
136,139
 
Long-term Risk Management Assets
   
19,313
   
21,282
 
Deferred Charges and Other
   
46,953
   
48,944
 
TOTAL
   
201,507
   
206,365
 
               
TOTAL ASSETS
 
$
1,294,344
 
$
1,310,565
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



KENTUCKY POWER COMPANY
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY
March 31, 2007 and December 31, 2006
(Unaudited)

   
2007
 
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
 
$
20,769
 
$
30,636
 
Accounts Payable:
             
General
   
33,876
   
31,490
 
Affiliated Companies
   
17,615
   
23,658
 
Long-term Debt Due Within One Year - Nonaffiliated
   
322,554
   
322,048
 
Risk Management Liabilities
   
14,167
   
20,001
 
Customer Deposits
   
15,273
   
16,095
 
Accrued Taxes
   
18,933
   
18,775
 
Other
   
22,759
   
26,303
 
TOTAL
   
465,946
   
489,006
 
               
NONCURRENT LIABILITIES
             
Long-term Debt - Nonaffiliated
   
104,944
   
104,920
 
Long-term Debt - Affiliated
   
20,000
   
20,000
 
Long-term Risk Management Liabilities
   
13,464
   
15,426
 
Deferred Income Taxes
   
239,776
   
242,133
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
47,426
   
49,109
 
Deferred Credits and Other
   
25,754
   
20,320
 
TOTAL
   
451,364
   
451,908
 
               
TOTAL LIABILITIES
   
917,310
   
940,914
 
               
Commitments and Contingencies (Note 4)
             
               
COMMON SHAREHOLDER’S EQUITY
             
Common Stock - $50 Par Value Per Share:
             
Authorized - 2,000,000 Shares
             
Outstanding - 1,009,000 Shares
   
50,450
   
50,450
 
Paid-in Capital
   
208,750
   
208,750
 
Retained Earnings
   
118,324
   
108,899
 
Accumulated Other Comprehensive Income (Loss)
   
(490
)
 
1,552
 
TOTAL
   
377,034
   
369,651
 
               
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY
 
$
1,294,344
 
$
1,310,565
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



KENTUCKY POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
OPERATING ACTIVITIES
           
Net Income
 
$
15,211
 
$
9,830
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
11,796
   
11,479
 
Deferred Income Taxes
   
956
   
2,217
 
Mark-to-Market of Risk Management Contracts
   
1,092
   
(1,378
)
Change in Other Noncurrent Assets
   
980
   
2,518
 
Change in Other Noncurrent Liabilities
   
(78
)
 
1,845
 
Changes in Certain Components of Working Capital:
             
Accounts Receivable, Net
   
(1,350
)
 
16,149
 
Fuel, Materials and Supplies
   
3,609
   
(2,808
)
Accounts Payable
   
(2,557
)
 
(6,212
)
Customer Deposits
   
(822
)
 
(3,127
)
Accrued Taxes, Net
   
1,447
   
2,676
 
Other Current Assets
   
1,012
   
2,069
 
Other Current Liabilities
   
(3,348
)
 
(1,480
)
Net Cash Flows From Operating Activities
   
27,948
   
33,778
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(13,001
)
 
(19,376
)
Change in Advances to Affiliates, Net
   
-
   
(5,923
)
Proceeds from Sale of Assets
   
231
   
301
 
Net Cash Flows Used For Investing Activities
   
(12,770
)
 
(24,998
)
               
FINANCING ACTIVITIES
             
Change in Advances from Affiliates, Net
   
(9,867
)
 
(6,040
)
Principal Payments for Capital Lease Obligations
   
(238
)
 
(343
)
Dividends Paid on Common Stock
   
(5,000
)
 
(2,500
)
Net Cash Flows Used For Financing Activities
   
(15,105
)
 
(8,883
)
               
Net Increase (Decrease) in Cash and Cash Equivalents
   
73
   
(103
)
Cash and Cash Equivalents at Beginning of Period
   
702
   
526
 
Cash and Cash Equivalents at End of Period
 
$
775
 
$
423
 

SUPPLEMENTARY INFORMATION
           
Cash Paid for Interest, Net of Capitalized Amounts
 
$
5,371
 
$
4,156
 
Net Cash Paid for Income Taxes
   
738
   
214
 
Noncash Acquisitions Under Capital Leases
   
139
   
224
 
Construction Expenditures Included in Accounts Payable at March 31,
   
2,257
   
3,079
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


KENTUCKY POWER COMPANY
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to KPCo’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to KPCo.

 
Footnote Reference
   
Significant Accounting Matters
Note 1
New Accounting Pronouncements
Note 2
Rate Matters
Note 3
Commitments, Guarantees and Contingencies
Note 4
Benefit Plans
Note 6
Business Segments
Note 7
Income Taxes
Note 8
Financing Activities
Note 9









 
 

 


OHIO POWER COMPANY CONSOLIDATED
 

 
 
 
 

 






OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

First Quarter of 2007 Compared to First Quarter of 2006

Reconciliation of First Quarter of 2006 to First Quarter of 2007
Net Income
(in millions)

First Quarter of 2006
       
$
95
 
               
Changes in Gross Margin:
             
Retail Margins
   
59
       
Off-system Sales
   
(22
)
     
Transmission Revenues
   
(9
)
     
Other
   
(10
)
     
Total Change in Gross Margin
         
18
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(28
)
     
Depreciation and Amortization
   
(5
)
     
Taxes Other Than Income Taxes
   
(1
)
     
Interest Expense
   
(3
)
     
Total Change in Operating Expenses and Other
         
(37
)
               
Income Tax Expense
         
3
 
               
First Quarter of 2007
       
$
79
 

Net Income decreased $16 million to $79 million in 2007. The key driver of the decrease was a $37 million increase in Operating Expenses and Other offset by an $18 million increase in Gross Margin.

The major components of our increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:

·
Retail Margins increased $59 million primarily due to the following:
 
·
A $25 million increase in capacity settlements under the Interconnection Agreement related to certain of our affiliates’ peaks and the expiration of our supplemental capacity and energy obligation to Buckeye Power, Inc. under the Cardinal Station Agreement.
 
·
A $14 million increase in rate revenues related to an $8 million increase in our RSP, a $3 million increase related to rate recovery of storm costs and a $3 million increase related to rate recovery of IGCC preconstruction costs (see “Ohio Rate Matters” section of Note 3). The increase in rate recovery of storm costs was offset by the amortization of deferred expenses in Other Operation and Maintenance. The increase in rate recovery of IGCC preconstruction costs was offset by the amortization of deferred expenses in Depreciation and Amortization.
 
·
A $9 million increase in fuel margins.
 
·
A $7 million increase in industrial revenue due to the addition of Ormet, a major industrial customer (see “Ormet” section of Note 3).
 
·
A $6 million increase in residential revenue primarily due to a 25% increase in heating degree days.
 
These increases were partially offset by:
 
·
A $9 million decrease in revenues associated with SO2 allowances received in 2006 from Buckeye Power, Inc. under the Cardinal Station Allowances Agreement.
·
Margins from Off-system Sales decreased $22 million due to a $19 million decrease in physical sales margins and a $4 million decrease in margins from optimization activities.
·
Transmission Revenues decreased $9 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).
·
Other revenues decreased $10 million primarily due to a $4 million decrease related to the expiration of an obligation to sell supplemental capacity and energy to Buckeye Power, Inc. under the Cardinal Station Agreement, a $3 million decrease in gains on sales of emission allowances and a $2 million decrease in revenue associated with Cook Coal Terminal.

Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expenses increased $28 million primarily due to a $19 million increase in maintenance and removal costs related to planned and forced outages at the Gavin, Muskingum, Mitchell and Cardinal plants and a $5 million increase due to the prior period adjustment of liabilities related to sold coal companies.
·
Depreciation and Amortization increased $5 million primarily due to the amortization of IGCC preconstruction costs of $3 million in the first quarter of 2007 and a $1 million increase in depreciation related to environmental improvements placed in service at the Mitchell plant. The increase in amortization of IGCC preconstruction costs was offset by a corresponding increase in Retail Margins.
·
Interest Expense increased $3 million primarily due to a $5 million increase related to long-term debt issuances since June 2006 and a $3 million increase related to higher borrowings from the Utility Money Pool partially offset by a $6 million increase in allowance for borrowed funds used during construction.

Income Taxes

Income Tax Expense decreased $3 million primarily due to a decrease in pretax book income offset in part by state income taxes.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

 
Moody’s
 
S&P
 
Fitch
           
Senior Unsecured Debt
A3
 
BBB
 
BBB+

Cash Flow

Cash flows for the three months ended March 31, 2007 and 2006 were as follows:

   
2007
 
2006
 
   
(in thousands)
 
Cash and Cash Equivalents at Beginning of Period
 
$
1,625
 
$
1,240
 
Cash Flows From (Used For):
             
Operating Activities
   
96,864
   
182,002
 
Investing Activities
   
(306,826
)
 
(221,862
)
Financing Activities
   
209,598
   
39,577
 
Net Decrease in Cash and Cash Equivalents
   
(364
)
 
(283
)
Cash and Cash Equivalents at End of Period
 
$
1,261
 
$
957
 

Operating Activities

Net Cash Flows From Operating Activities were $97 million in 2007. We produced Net Income of $79 million during the period and a noncash expense item of $84 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items. Accounts Receivable, Net had a $38 million outflow due to temporary timing differences of rent receivables and an increase in billed revenue for electric customers. Accounts Payable had a $26 million outflow primarily due to emission allowance payments in January 2007. Fuel, Materials and Supplies had a $24 million outflow primarily due to an increase in coal inventories.
 
Our Net Cash Flows From Operating Activities were $182 million in 2006. We produced income of $95 million during the period and a noncash expense item of $79 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital primarily relates to two items. Accounts Receivable, Net had a $102 million inflow due to receivables collected from our affiliates related to power sales, settled litigation and emission allowances. Accounts Payable had a $60 million outflow due to emission allowance payments in January 2006 and temporary timing differences for payments to affiliates.

Investing Activities

Our Net Cash Used For Investing Activities were $307 million and $222 million in 2007 and 2006, respectively. Construction Expenditures were $302 million and $223 million in 2007 and 2006, respectively, primarily related to environmental upgrades, as well as projects to improve service reliability for transmission and distribution. Environmental upgrades include the installation of selective catalytic reduction equipment and the flue gas desulfurization projects at the Cardinal, Amos and Mitchell plants. In January 2007, environmental upgrades were completed for Unit 2 at the Mitchell plant. For the remainder of 2007, we expect construction expenditures to be approximately $530 million.

Financing Activities

Net Cash Flows From Financing Activities were $210 million in 2007 primarily due to a net increase of $216 million in borrowings from the Utility Money Pool.

Net Cash Flows From Financing Activities were $40 million in 2006 primarily due to a $35 million capital contribution from AEP.

Financing Activity

Long-term debt issuances and retirements during the first three months of 2007 were:

Issuances

None

Retirements
   
Principal
Amount Paid
 
Interest
 
Due
Type of Debt
   
Rate
 
Date
     
(in thousands)
 
(%)
   
Notes Payable - Nonaffiliated
 
$
1,463
 
6.81
 
2008
Notes Payable - Nonaffiliated
   
6,000
 
6.27
 
2009

In April 2007, we 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.

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt, refinance short-term debt or refinance long-term debt maturities. In addition, we participate in the Utility Money Pool, which provides access to AEP’s liquidity.

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 issuance discussed in “Financing Activity” above.
 
Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, we 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 which have a probable likelihood of loss and the loss amount can be estimated. For details on our pending litigation and regulatory proceedings, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies in our 2006 Annual Report. Also, see Note 3 - Rate Matters and Note 4 - Commitments, Guarantees and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries”. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” 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, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management assets and liabilities are managed by AEPSC as agent for us. The related risk management policies and procedures are instituted and administered by AEPSC. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

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

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of March 31, 2007
(in thousands)

   
MTM Risk Management Contracts
 
Cash Flow Hedges
 
DETM Assignment (a)
 
Total
 
Current Assets
 
$
49,092
 
$
756
 
$
-
 
$
49,848
 
Noncurrent Assets
   
57,316
   
96
   
-
   
57,412
 
Total MTM Derivative Contract Assets
   
106,408
   
852
   
-
   
107,260
 
                           
Current Liabilities
   
(42,532
)
 
(3,980
)
 
(2,071
)
 
(48,583
)
Noncurrent Liabilities
   
(35,731
)
 
(312
)
 
(5,493
)
 
(41,536
)
Total MTM Derivative Contract Liabilities
   
(78,263
)
 
(4,292
)
 
(7,564
)
 
(90,119
)
                           
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
28,145
 
$
(3,440
)
$
(7,564
)
$
17,141
 

(a)
See “Natural Gas Contracts with DETM” section of Note 16 in the 2006 Annual Report.
 
MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2007
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2006
 
$
33,042
 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
   
(4,433
)
Fair Value of New Contracts at Inception When Entered During the Period (a)
   
311
 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period
   
(23
)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts
   
-
 
Changes in Fair Value Due to Market Fluctuations During the Period (b)
   
(317
)
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
   
(435
)
Total MTM Risk Management Contract Net Assets
   
28,145
 
Net Cash Flow Hedge Contracts
   
(3,440
)
DETM Assignment (d)
   
(7,564
)
Total MTM Risk Management Contract Net Assets at March 31, 2007
 
$
17,141
 

(a)
Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)
Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)
“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(d)
See “Natural Gas Contracts with DETM” section of Note 16 in our 2006 Annual Report.
 
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets

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
Fair Value of Contracts as of March 31, 2007
(in thousands)


   
Remainder
2007
 
2008
 
2009
 
2010
 
2011
 
After
2011
 
Total
 
Prices Actively Quoted - Exchange Traded Contracts
 
$
11,122
 
$
(399
)
$
464
 
$
-
 
$
-
 
$
-
 
$
11,187
 
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)
   
(621
)
 
9,668
   
7,524
   
2,985
   
-
   
-
   
19,556
 
Prices Based on Models and Other Valuation Methods (b)
   
(5,725
)
 
(3,527
)
 
1,165
   
3,608
   
812
   
1,069
   
(2,598
)
Total
 
$
4,776
 
$
5,742
 
$
9,153
 
$
6,593
 
$
812
 
$
1,069
 
$
28,145
 

(a)
“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)
“Prices Based on Models and Other Valuation Methods” is used in 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 are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.
   
 
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.


Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed Consolidated Balance Sheet

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 anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

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 the changes from December 31, 2006 to March 31, 2007. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2007
(in thousands)

   
Power
 
Foreign
Currency
 
Interest Rate
 
Total
 
Beginning Balance in AOCI December 31, 2006
 
$
4,040
 
$
(331
)
$
3,553
 
$
7,262
 
Changes in Fair Value
   
(4,677
)
 
-
   
-
   
(4,677
)
Reclassifications from AOCI to Net Income for 
   Cash Flow Hedges Settled
   
(1,595
)
 
3
   
(202
)
 
(1,794
)
Ending Balance in AOCI March 31, 2007
 
$
(2,232
)
$
(328
)
$
3,351
 
$
791
 

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $1,292 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

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:

Three Months Ended March 31, 2007
       
Twelve Months Ended December 31, 2006
(in thousands)
       
(in thousands)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
$678
 
$2,054
 
$924
 
$255
       
$573
 
$1,451
 
$500
 
$271

The High VaR for the twelve months ended December 31, 2006 occurred in the third quarter due to volatility in the ECAR/PJM region.

VaR Associated with Debt Outstanding

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 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 $131 million and $110 million at March 31, 2007 and December 31, 2006, respectively. 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 negatively affect our results of operations or consolidated financial position.




OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
REVENUES
         
Electric Generation, Transmission and Distribution
 
$
492,534
 
$
544,639
 
Sales to AEP Affiliates
   
178,894
   
149,259
 
Other - Affiliated
   
4,038
   
3,709
 
Other - Nonaffiliated
   
3,975
   
4,999
 
TOTAL
   
679,441
   
702,606
 
               
EXPENSES
             
Fuel and Other Consumables Used for Electric Generation
   
198,293
   
235,130
 
Purchased Electricity for Resale
   
24,854
   
21,714
 
Purchased Electricity from AEP Affiliates
   
20,966
   
28,572
 
Other Operation
   
102,987
   
86,629
 
Maintenance
   
59,148
   
47,524
 
Depreciation and Amortization
   
84,276
   
78,821
 
Taxes Other Than Income Taxes
   
48,385
   
47,153
 
TOTAL
   
538,909
   
545,543
 
               
OPERATING INCOME
   
140,532
   
157,063
 
               
Other Income (Expense):
             
Interest Income
   
412
   
637
 
Carrying Costs Income
   
3,541
   
3,383
 
Allowance for Equity Funds Used During Construction
   
571
   
738
 
Interest Expense
   
(25,931
)
 
(23,414
)
               
INCOME BEFORE INCOME TAXES
   
119,125
   
138,407
 
               
Income Tax Expense
   
39,864
   
43,375
 
               
NET INCOME
   
79,261
   
95,032
 
               
Preferred Stock Dividend Requirements
   
183
   
183
 
               
EARNINGS APPLICABLE TO COMMON STOCK
 
$
79,078
 
$
94,849
 

The common stock of OPCo is wholly-owned by AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2005
 
$
321,201
 
$
466,637
 
$
979,354
 
$
755
 
$
1,767,947
 
                                 
Capital Contribution From Parent
         
35,000
               
35,000
 
Preferred Stock Dividends
               
(183
)
       
(183
)
TOTAL
                           
1,802,764
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Income, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $3,326
                     
6,176
   
6,176
 
NET INCOME
               
95,032
         
95,032
 
TOTAL COMPREHENSIVE INCOME
                           
101,208
 
                                 
MARCH 31, 2006
 
$
321,201
 
$
501,637
 
$
1,074,203
 
$
6,931
 
$
1,903,972
 
                                 
DECEMBER 31, 2006
 
$
321,201
 
$
536,639
 
$
1,207,265
 
$
(56,763
)
$
2,008,342
 
                                 
FIN 48 Adoption, Net of Tax
               
(5,380
)
       
(5,380
)
Preferred Stock Dividends
               
(183
)
       
(183
)
TOTAL
                           
2,002,779
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $3,485
                     
(6,471
)
 
(6,471
)
NET INCOME
               
79,261
         
79,261
 
TOTAL COMPREHENSIVE INCOME
                           
72,790
 
                                 
MARCH 31, 2007
 
$
321,201
 
$
536,639
 
$
1,280,963
 
$
(63,234
)
$
2,075,569
 

   See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2007 and December 31, 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
1,261
 
$
1,625
 
Accounts Receivable:
             
Customers
   
114,608
   
86,116
 
Affiliated Companies
   
109,029
   
108,214
 
Accrued Unbilled Revenues
   
17,082
   
10,106
 
Miscellaneous
   
3,620
   
1,819
 
Allowance for Uncollectible Accounts
   
(838
)
 
(824
)
   Total Accounts Receivable
   
243,501
   
205,431
 
Fuel
   
139,950
   
120,441
 
Materials and Supplies
   
78,866
   
74,840
 
Emission Allowances
   
12,302
   
10,388
 
Risk Management Assets
   
49,848
   
86,947
 
Accrued Tax Benefits
   
3,181
   
22,909
 
Prepayments and Other
   
28,395
   
18,416
 
TOTAL
   
557,304
   
540,997
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
4,747,459
   
4,413,340
 
Transmission
   
1,038,642
   
1,030,934
 
Distribution
   
1,336,874
   
1,322,103
 
Other
   
300,054
   
299,637
 
Construction Work in Progress
   
1,226,985
   
1,339,631
 
Total
   
8,650,014
   
8,405,645
 
Accumulated Depreciation and Amortization
   
2,867,416
   
2,836,584
 
TOTAL - NET
   
5,782,598
   
5,569,061
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
387,201
   
414,180
 
Long-term Risk Management Assets
   
57,412
   
70,092
 
Deferred Charges and Other
   
209,873
   
224,403
 
TOTAL
   
654,486
   
708,675
 
               
TOTAL ASSETS
 
$
6,994,388
 
$
6,818,733
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2007 and December 31, 2006
(Unaudited)

   
2007
 
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
 
$
397,127
 
$
181,281
 
Accounts Payable:
             
General
   
225,809
   
250,025
 
Affiliated Companies
   
116,297
   
145,197
 
Short-term Debt - Nonaffiliated
   
4,503
   
1,203
 
Long-term Debt Due Within One Year - Nonaffiliated
   
17,854
   
17,854
 
Risk Management Liabilities
   
48,583
   
73,386
 
Customer Deposits
   
31,547
   
31,465
 
Accrued Taxes
   
148,057
   
165,338
 
Accrued Interest
   
34,561
   
35,497
 
Other
   
126,845
   
123,631
 
TOTAL
   
1,151,183
   
1,024,877
 
               
NONCURRENT LIABILITIES
             
Long-term Debt - Nonaffiliated
   
2,176,601
   
2,183,887
 
Long-term Debt - Affiliated
   
200,000
   
200,000
 
Long-term Risk Management Liabilities
   
41,536
   
52,929
 
Deferred Income Taxes
   
891,761
   
911,221
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
173,946
   
185,895
 
Deferred Credits and Other
   
249,254
   
219,127
 
TOTAL
   
3,733,098
   
3,753,059
 
               
TOTAL LIABILITIES
   
4,884,281
   
4,777,936
 
               
Minority Interest
   
17,910
   
15,825
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
16,628
   
16,630
 
               
Commitments and Contingencies (Note 4)
             
               
COMMON SHAREHOLDER’S EQUITY
             
Common Stock - No Par Value:
             
Authorized - 40,000,000 Shares
             
Outstanding - 27,952,473 Shares
   
321,201
   
321,201
 
Paid-in Capital
   
536,639
   
536,639
 
Retained Earnings
   
1,280,963
   
1,207,265
 
Accumulated Other Comprehensive Income (Loss)
   
(63,234
)
 
(56,763
)
TOTAL
   
2,075,569
   
2,008,342
 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 
$
6,994,388
 
$
6,818,733
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
OPERATING ACTIVITIES
           
Net Income
 
$
79,261
 
$
95,032
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
84,276
   
78,821
 
Deferred Income Taxes
   
2,851
   
3,604
 
Carrying Costs Income
   
(3,541
)
 
(3,383
)
Mark-to-Market of Risk Management Contracts
   
3,958
   
(3,616
)
Deferred Property Taxes
   
17,920
   
17,331
 
Change in Other Noncurrent Assets
   
(4,406
)
 
2,455
 
Change in Other Noncurrent Liabilities
   
(4,434
)
 
13,855
 
Changes in Certain Components of Working Capital:
             
Accounts Receivable, Net
   
(38,070
)
 
101,866
 
Fuel, Materials and Supplies
   
(23,535
)
 
(18,238
)
Accounts Payable
   
(25,807
)
 
(60,411
)
Customer Deposits
   
82
   
(12,497
)
Accrued Taxes, Net
   
6,360
   
3,116
 
Accrued Interest
   
(2,986
)
 
(10,998
)
Other Current Assets
   
1,706
   
(739
)
Other Current Liabilities
   
3,229
   
(24,196
)
Net Cash Flows From Operating Activities
   
96,864
   
182,002
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(301,635
)
 
(222,600
)
Change in Other Cash Deposits, Net
   
(7,988
)
 
(1,651
)
Proceeds from Sale of Assets
   
2,797
   
2,389
 
Net Cash Flows Used For Investing Activities
   
(306,826
)
 
(221,862
)
               
FINANCING ACTIVITIES
             
Capital Contributions from Parent Company
   
-
   
35,000
 
Change in Short-term Debt, Net - Nonaffiliated
   
3,300
   
636
 
Change in Advances from Affiliates, Net
   
215,846
   
10,972
 
Retirement of Long-term Debt - Nonaffiliated
   
(7,463
)
 
(4,713
)
Principal Payments for Capital Lease Obligations
   
(1,902
)
 
(2,135
)
Dividends Paid on Cumulative Preferred Stock
   
(183
)
 
(183
)
Net Cash Flows From Financing Activities
   
209,598
   
39,577
 
               
Net Decrease in Cash and Cash Equivalents
   
(364
)
 
(283
)
Cash and Cash Equivalents at Beginning of Period
   
1,625
   
1,240
 
Cash and Cash Equivalents at End of Period
 
$
1,261
 
$
957
 

SUPPLEMENTARY INFORMATION
           
Cash Paid for Interest, Net of Capitalized Amounts
 
$
29,646
 
$
29,152
 
Net Cash Paid (Received) for Income Taxes
   
(8,899
)
 
922
 
Noncash Acquisitions Under Capital Leases
   
608
   
927
 
Construction Expenditures Included in Accounts Payable at March 31,
   
98,653
   
82,024
 
 
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


OHIO POWER COMPANY CONSOLIDATED
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to OPCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to OPCo.
 
Footnote
Reference
   
Significant Accounting Matters
Note 1
New Accounting Pronouncements
Note 2
Rate Matters
Note 3
Commitments, Guarantees and Contingencies
Note 4
Benefit Plans
Note 6
Business Segments
Note 7
Income Taxes
Note 8
Financing Activities
Note 9











 

 



PUBLIC SERVICE COMPANY OF OKLAHOMA

 
 
 
 
 

 






PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations

First Quarter of 2007 Compared to First Quarter of 2006

Reconciliation of First Quarter of 2006 to First Quarter of 2007
Net Loss
(in millions)

First Quarter of 2006
       
$
(5
)
               
Changes in Gross Margin:
             
Retail and Off-system Sales Margins
   
5
       
Transmission Revenues
   
1
       
Other
   
(1
)
     
Total Change in Gross Margin
         
5
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(27
)
     
Depreciation and Amortization
   
(2
)
     
Interest Expense
   
(2
)
     
Total Change in Operating Expenses and Other
         
(31
)
               
Income Tax Credit
         
11
 
               
First Quarter of 2007
       
$
(20
)

Net Loss increased $15 million to $20 million in 2007. The key driver of the increased loss was a $31 million increase in Operating Expenses and Other, partially offset by an $11 million increase in Income Tax Credit and a $5 million increase in Gross Margin.

The major component of our increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power was a $5 million increase in Retail and Off-system Sales Margins primarily due to a $4 million increase in retail margins resulting from an increase in heating degree days.

Operating Expenses and Other increased between years as follows:

·
Other Operation and Maintenance expenses increased $27 million due to:
 
·
A $21 million increase in distribution maintenance expense primarily due to a January 2007 ice storm.
 
·
A $2 million increase in administrative and general expenses, mostly due to increased employee-related expenses.
·
Interest Expense increased $2 million primarily due to increased borrowings.

Income Taxes

Income Tax Credit increased $11 million primarily due to an increase in pretax book loss and a decrease in state income taxes.

Critical Accounting Estimates

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

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.




QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management assets and liabilities are managed by AEPSC as agent for us. The related risk management policies and procedures are instituted and administered by AEPSC. See the complete discussion and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.

VaR Associated with Debt Outstanding

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 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 $42 million and $39 million at March 31, 2007 and December 31, 2006, respectively. 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 negatively affect our results of operations or financial position.







PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
REVENUES
         
Electric Generation, Transmission and Distribution
 
$
290,080
 
$
339,601
 
Sales to AEP Affiliates
   
24,593
   
14,068
 
Other
   
640
   
1,060
 
TOTAL
   
315,313
   
354,729
 
               
EXPENSES
             
Fuel and Other Consumables Used for Electric Generation
   
142,515
   
213,173
 
Purchased Electricity for Resale
   
67,409
   
33,217
 
Purchased Electricity from AEP Affiliates
   
13,484
   
21,231
 
Other Operation
   
41,007
   
36,756
 
Maintenance
   
43,085
   
20,307
 
Depreciation and Amortization
   
22,706
   
21,132
 
Taxes Other Than Income Taxes
   
10,294
   
10,076
 
TOTAL
   
340,500
   
355,892
 
               
OPERATING LOSS
   
(25,187
)
 
(1,163
)
               
Other Income (Expense):
             
Interest Income
   
646
   
569
 
Interest Expense
   
(11,383
)
 
(9,135
)
               
LOSS BEFORE INCOME TAXES
   
(35,924
)
 
(9,729
)
               
Income Tax Credit
   
(15,498
)
 
(4,372
)
               
NET LOSS
   
(20,426
)
 
(5,357
)
               
Preferred Stock Dividend Requirements
   
53
   
53
 
               
LOSS APPLICABLE TO COMMON STOCK
 
$
(20,479
)
$
(5,410
)

The common stock of PSO is owned by a wholly-owned subsidiary of AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2005
 
$
157,230
 
$
230,016
 
$
162,615
 
$
(1,264
)
$
548,597
 
                                 
Preferred Stock Dividends
               
(53
)
       
(53
)
TOTAL
                           
548,544
 
                                 
COMPREHENSIVE LOSS
                               
Other Comprehensive Income, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $749
                     
1,391
   
1,391
 
NET LOSS
               
(5,357
)
       
(5,357
)
TOTAL COMPREHENSIVE LOSS
                           
(3,966
)
                                 
MARCH 31, 2006
 
$
157,230
 
$
230,016
 
$
157,205
 
$
127
 
$
544,578
 
                                 
DECEMBER 31, 2006
 
$
157,230
 
$
230,016
 
$
199,262
 
$
(1,070
)
$
585,438
 
                                 
FIN 48 Adoption, Net of Tax
               
(386
)
       
(386
)
Capital Contribution from Parent Company
         
20,000
               
20,000
 
Preferred Stock Dividends
               
(53
)
       
(53
)
TOTAL
                           
604,999
 
                                 
COMPREHENSIVE LOSS
                               
Other Comprehensive Income, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $24
                     
45
   
45
 
NET LOSS
               
(20,426
)
       
(20,426
)
TOTAL COMPREHENSIVE LOSS
                           
(20,381
)
                                 
MARCH 31, 2007
 
$
157,230
 
$
250,016
 
$
178,397
 
$
(1,025
)
$
584,618
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
March 31, 2007 and December 31, 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
CURRENT ASSETS
      
Cash and Cash Equivalents
 
$
1,584
 
$
1,651
 
Accounts Receivable:
             
Customers
   
51,680
   
70,319
 
Affiliated Companies
   
73,191
   
73,318
 
Miscellaneous
   
13,004
   
10,270
 
Allowance for Uncollectible Accounts
   
(89
)
 
(5
)
   Total Accounts Receivable
   
137,786
   
153,902
 
Fuel
   
19,028
   
20,082
 
Materials and Supplies
   
52,951
   
48,375
 
Risk Management Assets
   
56,139
   
100,802
 
Accrued Tax Benefits
   
25,206
   
4,679
 
Regulatory Asset for Under-Recovered Fuel Costs
   
-
   
7,557
 
Margin Deposits
   
22,705
   
35,270
 
Prepayments and Other
   
5,718
   
5,732
 
TOTAL
   
321,117
   
378,050
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
1,095,466
   
1,091,910
 
Transmission
   
505,326
   
503,638
 
Distribution
   
1,248,077
   
1,215,236
 
Other
   
237,383
   
234,227
 
Construction Work in Progress
   
158,637
   
141,283
 
Total
   
3,244,889
   
3,186,294
 
Accumulated Depreciation and Amortization
   
1,200,212
   
1,187,107
 
TOTAL - NET
   
2,044,677
   
1,999,187
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
138,815
   
142,905
 
Long-term Risk Management Assets
   
13,748
   
17,066
 
Employee Benefits and Pension Assets
   
29,761
   
30,161
 
Deferred Charges and Other
   
34,237
   
11,677
 
TOTAL
   
216,561
   
201,809
 
               
TOTAL ASSETS
 
$
2,582,355
 
$
2,579,046
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2007 and December 31, 2006
(Unaudited)

   
2007
 
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
 
$
135,694
 
$
76,323
 
Accounts Payable:
             
General
   
173,021
   
165,618
 
Affiliated Companies
   
68,782
   
65,134
 
Risk Management Liabilities
   
46,530
   
88,469
 
Customer Deposits
   
41,404
   
51,335
 
Accrued Taxes
   
35,144
   
19,984
 
Regulatory Liability for Over-Recovered Fuel Costs
   
9,015
   
-
 
Other
   
29,898
   
58,651
 
TOTAL
   
539,488
   
525,514
 
               
NONCURRENT LIABILITIES
             
Long-term Debt - Nonaffiliated
   
670,042
   
669,998
 
Long-term Risk Management Liabilities
   
8,514
   
11,448
 
Deferred Income Taxes
   
407,365
   
414,197
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
306,194
   
315,584
 
Deferred Credits and Other
   
60,872
   
51,605
 
TOTAL
   
1,452,987
   
1,462,832
 
               
TOTAL LIABILITIES
   
1,992,475
   
1,988,346
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
5,262
   
5,262
 
               
Commitments and Contingencies (Note 4)
             
               
COMMON SHAREHOLDER’S EQUITY
             
Common Stock - $15 Par Value Per Share:
             
Authorized - 11,000,000 Shares
             
Issued - 10,482,000 Shares
             
Outstanding - 9,013,000 Shares
   
157,230
   
157,230
 
Paid-in Capital
   
250,016
   
230,016
 
Retained Earnings
   
178,397
   
199,262
 
Accumulated Other Comprehensive Income (Loss)
   
(1,025
)
 
(1,070
)
TOTAL
   
584,618
   
585,438
 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 
$
2,582,355
 
$
2,579,046
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
OPERATING ACTIVITIES
           
Net Loss
 
$
(20,426
)
$
(5,357
)
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
22,706
   
21,132
 
Deferred Income Taxes
   
1,039
   
(23,436
)
Mark-to-Market of Risk Management Contracts
   
3,108
   
9,106
 
Deferred Property Taxes
   
(24,809
)
 
(24,295
)
Change in Other Noncurrent Assets
   
4,393
   
11,118
 
Change in Other Noncurrent Liabilities
   
(11,269
)
 
(20,806
)
Changes in Certain Components of Working Capital:
             
Accounts Receivable, Net
   
16,116
   
33,852
 
Fuel, Materials and Supplies
   
(3,513
)
 
(26
)
Margin Deposits
   
12,565
   
5,065
 
Accounts Payable
   
6,941
   
(77,217
)
Customer Deposits
   
(9,931
)
 
(13,056
)
Accrued Taxes, Net
   
(4,378
)
 
34,196
 
Fuel Over/Under Recovery, Net
   
16,572
   
74,281
 
Other Current Assets
   
(139
)
 
1,021
 
Other Current Liabilities
   
(26,677
)
 
(23,048
)
Net Cash Flows From (Used for) Operating Activities
   
(17,702
)
 
2,530
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(61,301
)
 
(45,539
)
Change in Other Cash Deposits, Net
   
(29
)
 
6
 
Proceeds from Sales of Assets
   
17
   
-
 
Net Cash Flows Used For Investing Activities
   
(61,313
)
 
(45,533
)
               
FINANCING ACTIVITIES
             
Capital Contributions from Parent Company
   
20,000
   
-
 
Change in Advances from Affiliates, Net
   
59,371
   
42,932
 
Principal Payments for Capital Lease Obligations
   
(370
)
 
(206
)
Dividends Paid on Cumulative Preferred Stock
   
(53
)
 
(53
)
Net Cash Flows From Financing Activities
   
78,948
   
42,673
 
               
Net Decrease in Cash and Cash Equivalents
   
(67
)
 
(330
)
Cash and Cash Equivalents at Beginning of Period
   
1,651
   
1,520
 
Cash and Cash Equivalents at End of Period
 
$
1,584
 
$
1,190
 

SUPPLEMENTARY INFORMATION
           
Cash Paid for Interest, Net of Capitalized Amounts
 
$
12,921
 
$
8,681
 
Net Cash Paid for Income Taxes
   
2,623
   
575
 
Noncash Acquisitions Under Capital Leases
   
283
   
564
 
Construction Expenditures Included in Accounts Payable at March 31,
   
19,038
   
6,052
 

 See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


PUBLIC SERVICE COMPANY OF OKLAHOMA
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The condensed notes to PSO’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to PSO.
 
Footnote Reference
   
Significant Accounting Matters
Note 1
New Accounting Pronouncements
Note 2
Rate Matters
Note 3
Commitments, Guarantees and Contingencies
Note 4
Benefit Plans
Note 6
Business Segments
Note 7
Income Taxes
Note 8
Financing Activities
Note 9












 
 

 
 

 

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

 
 
 
 
 
 
 
 
 

 






SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

First Quarter of 2007 Compared to First Quarter of 2006

Reconciliation of First Quarter of 2006 to First Quarter of 2007
Net Income
(in millions)

First Quarter of 2006
       
$
18
 
               
Changes in Gross Margin:
             
Retail and Off-system Sales Margins (a)
   
(1
)
     
Other
   
(4
)
     
Total Change in Gross Margin
         
(5
)
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(6
)
     
Depreciation and Amortization
   
(1
)
     
Other Income
   
1
       
Interest Expense
   
(3
)
     
Total Change in Operating Expenses and Other
         
(9
)
               
Income Tax Expense
         
6
 
               
First Quarter of 2007
       
$
10
 

(a)
Includes firm wholesale sales to municipals and cooperatives.

Net Income decreased $8 million to $10 million in 2007. The key drivers of the decrease were a $9 million increase in Operating Expenses and Other and a $5 million decrease in Gross Margin, offset by a $6 million decrease in Income Tax Expense.

The major component of our decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power was a $4 million decrease in Other changes in gross margin, primarily due to lower gains on sales of emission allowances.

Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expenses increased $6 million primarily due to a $2 million increase in generation operation and maintenance, a $1 million increase in transmission expenses due to higher SPP administration fees and a $1 million increase in administrative and general expenses, primarily associated with outside services and employee-related expenses.
·
Interest Expense increased $3 million primarily due to increased long-term debt.

Income Taxes

Income Tax Expense decreased $6 million primarily due to a decrease in pretax book income and state income taxes.
 
Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

 
Moody’s
 
S&P
 
Fitch
           
First Mortgage Bonds
A3
 
A-
 
A
Senior Unsecured Debt
Baa1
 
BBB
 
A-

Cash Flow

Cash flows for the three months ended March 31, 2007 and 2006 were as follows:

   
2007
 
2006
 
   
(in thousands)
 
Cash and Cash Equivalents at Beginning of Period
 
$
2,618
 
$
3,049
 
Cash Flows From (Used For):
             
Operating Activities
   
65,590
   
41,293
 
Investing Activities
   
(120,639
)
 
(54,294
)
Financing Activities
   
54,331
   
12,501
 
Net Decrease in Cash and Cash Equivalents
   
(718
)
 
(500
)
Cash and Cash Equivalents at End of Period
 
$
1,900
 
$
2,549
 

Operating Activities

Net Cash Flows From Operating Activities were $66 million in 2007. We produced Net Income of $10 million during the period and a noncash expense item of $34 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. The $36 million inflow from Accrued Taxes, Net was the result of increased accruals related to property and income taxes. The $22 million inflow from Margin Deposits was due to decreased trading-related deposits resulting from normal trading activities. The $20 million inflow from Accounts Receivable, Net was primarily due to the assignment of certain ERCOT contracts to an affiliate company.

Our Net Cash Flows From Operating Activities were $41 million in 2006. We produced Net Income of $18 million during the period and noncash expense items of $33 million for Depreciation and Amortization. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items. The $27 million inflow from Accounts Receivable, Net was due to lower affiliated energy transactions. The $18 million outflow from Fuel, Materials and Supplies was the result of reduced fuel consumption during scheduled power plant outages. The $45 million inflow from Accrued Taxes, Net was due to increased income taxes. We did not make a federal income tax payment in 2006. The $16 million outflow from Customer Deposits was due to lower trading-related deposits. In addition, our cash flow related to Over/Under Fuel Recovery was favorably impacted by the new fuel surcharges effective December 2005 in our Arkansas service territory and in January 2006 in our Texas service territory. The $15 million outflow from Accounts Payable was the result of lower expenditures related to tree trimming and right-of-way clearing, energy purchases and general operations.

Investing Activities

Cash Flows Used For Investing Activities during 2007 and 2006 were $121 million and $54 million, respectively. The $108 million of cash flows for Construction Expenditures during 2007 were primarily related to new generation facilities. In addition, we had a net increase of $9 million in loans to the Utility Money Pool. The cash flows during 2006 were comprised primarily of Construction Expenditures related to projects for improved transmission and distribution service reliability.

Financing Activities

Cash Flows From Financing Activities were $54 million during 2007. We issued $250 million of Senior Unsecured Notes. We had a net decrease of $189 million in borrowings from the Utility Money Pool.

Cash Flows From Financing Activities were $13 million during 2006. We had a net increase of $21 million in borrowings from the Utility Money Pool. We paid $10 million in common stock dividends.

Financing Activity

Long-term debt issuances and retirements during the first three months of 2007 were:

Issuances
   
Principal
Amount Paid
 
Interest
 
Due
Type of Debt
   
Rate
 
Date
     
(in thousands)
 
(%)
   
Senior Unsecured Notes
 
$
250,000
 
5.55
 
2017

Retirements
   
Principal
Amount Paid
 
Interest
 
Due
Type of Debt
   
Rate
 
Date
     
(in thousands)
 
(%)
   
Notes Payable - Nonaffiliated
 
$
1,645
 
4.47
 
2011
Notes Payable - Nonaffiliated
   
4,000
 
6.36
 
2007
Notes Payable - Nonaffiliated
   
750
 
Variable
 
2008

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt or refinance long-term debt maturities. In addition, we participate in the Utility Money Pool, which provides access to AEP’s liquidity.

Summary Obligation Information

A summary of our contractual obligations is included in our 2006 Annual Report and has not changed significantly since year-end other than the debt issuance discussed in “Financing Activity” above and Energy and Capacity Purchase Contracts. Effective January 1, 2007, we transferred a significant amount of ERCOT energy marketing contracts to AEPEP; thereby decreasing our future obligations in Energy and Capacity Purchase Contracts. See “ERCOT Contracts Transferred to AEPEP” section of Note 1.

Significant Factors

Litigation and Regulatory Activity

In the ordinary course of business, we 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 which have a probable likelihood of loss and the loss amount can be estimated. For details on our pending litigation and regulatory proceedings, see Note 4 - Rate Matters and Note 6 - Commitments, Guarantees and Contingencies in our 2006 Annual Report. Also, see Note 3 - Rate Matters and Note 4 - Commitments, Guarantees and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries” section. Adverse results in these proceedings have the potential to materially affect our results of operations, financial condition and cash flows.
 
New Generation

In December 2005, we sought proposals for new peaking, intermediate and base load generation to be online between 2008 and 2011. In May 2006, we announced plans to construct new generation to satisfy the demands of its customers. We 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. We also plan to build a new 600 MW base load coal plant, of which our investment will be 73%, in Hempstead County, Arkansas by 2011 to meet the long-term generation needs of its customers. Preliminary cost estimates our 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 our 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.

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” 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, pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management assets and liabilities are managed by AEPSC as agent for us. The related risk management policies and procedures are instituted and administered by AEPSC. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

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

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of March 31, 2007
(in thousands)

   
MTM Risk Management Contracts
 
Cash Flow Hedges
 
Total
 
Current Assets
 
$
66,352
 
$
582
 
$
66,934
 
Noncurrent Assets
   
16,264
   
37
   
16,301
 
Total MTM Derivative Contract Assets
   
82,616
   
619
   
83,235
 
                     
Current Liabilities
   
(55,257
)
 
(6
)
 
(55,263
)
Noncurrent Liabilities
   
(10,158
)
 
(16
)
 
(10,174
)
Total MTM Derivative Contract Liabilities
   
(65,415
)
 
(22
)
 
(65,437
)
                     
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
17,201
 
$
597
 
$
17,798
 

MTM Risk Management Contract Net Assets
Three Months Ended March 31, 2007
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2006
 
$
20,166
 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
   
(1,013
)
Fair Value of New Contracts at Inception When Entered During the Period (a)
   
-
 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period
   
-
 
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts
   
-
 
Changes in Fair Value Due to Market Fluctuations During the Period (b)
   
21
 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
   
(1,973
)
Total MTM Risk Management Contract Net Assets
   
17,201
 
Net Cash Flow Hedge Contracts
   
597
 
Total MTM Risk Management Contract Net Assets at March 31, 2007
 
$
17,798
 

(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, etc.
(c)
“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.

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

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
Fair Value of Contracts as of March 31, 2007
(in thousands)

   
Remainder
2007
 
2008
 
2009
 
2010
 
2011
 
After
2011
 
Total
 
Prices Actively Quoted - Exchange Traded Contracts
 
$
(16,029
)
$
1,742
 
$
(283
)
$
-
 
$
-
 
$
-
 
$
(14,570
)
Prices Provided by Other External
   Sources - OTC Broker Quotes (a)
   
29,194
   
4,143
   
(813
)
 
-
   
-
   
-
   
32,524
 
Prices Based on Models and Other
   Valuation Methods (b)
   
(2,551
)
 
335
   
1,461
   
2
   
-
   
-
   
(753
)
Total
 
$
10,614
 
$
6,220
 
$
365
 
$
2
 
$
-
 
$
-
 
$
17,201
 

(a)
“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)
“Prices Based on Models and Other Valuation Methods” is used in 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 are limited, such valuations are classified as modeled. The determination of the point at which a market is no longer liquid for placing it in the modeled category varies by market.
   
 
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.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed Consolidated Balance Sheet

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 anticipated borrowings of fixed-rate debt. We do not hedge all interest rate risk.

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 the changes from December 31, 2006 to March 31, 2007. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity
Three Months Ended March 31, 2007
(in thousands)

   
Interest Rate
 
Foreign
Currency
 
Total
 
Beginning Balance in AOCI December 31, 2006
 
$
(6,435
)
$
25
 
$
(6,410
)
Changes in Fair Value
   
(1,019
)
 
509
   
(510
)
Reclassifications from AOCI to Net Income for 
   Cash Flow Hedges Settled
   
183
   
-
   
183
 
Ending Balance in AOCI March 31, 2007
 
$
(7,271
)
$
534
 
$
(6,737
)

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $249 thousand loss.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

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:

Three Months Ended March 31, 2007
       
Twelve Months Ended December 31, 2006
(in thousands)
       
(in thousands)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
$83
 
$245
 
$100
 
$25
       
$447
 
$2,171
 
$794
 
$68

The High VaR for the twelve months ended December 31, 2006 occurred in the fourth quarter due to volatility in the ERCOT region.

VaR Associated with Debt Outstanding

We also 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 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 $43 million and $25 million at March 31, 2007 and December 31, 2006, respectively. 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 negatively affect our results of operations or consolidated financial position.



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
REVENUES
         
Electric Generation, Transmission and Distribution
 
$
327,284
 
$
293,993
 
Sales to AEP Affiliates
   
16,415
   
10,765
 
Other
   
400
   
374
 
TOTAL
   
344,099
   
305,132
 
               
EXPENSES
             
Fuel and Other Consumables Used for Electric Generation
   
111,987
   
90,661
 
Purchased Electricity for Resale
   
52,498
   
29,218
 
Purchased Electricity from AEP Affiliates
   
22,917
   
23,337
 
Other Operation
   
53,783
   
49,700
 
Maintenance
   
26,339
   
24,657
 
Depreciation and Amortization
   
34,122
   
32,617
 
Taxes Other Than Income Taxes
   
15,991
   
15,982
 
TOTAL
   
317,637
   
266,172
 
               
OPERATING INCOME
   
26,462
   
38,960
 
               
Other Income (Expense):
             
Interest Income
   
705
   
543
 
Allowance for Equity Funds Used During Construction
   
1,391
   
185
 
Interest Expense
   
(15,490
)
 
(12,771
)
               
INCOME BEFORE INCOME TAXES AND MINORITY
  INTEREST EXPENSE
   
13,068
   
26,917
 
               
Income Tax Expense
   
2,621
   
8,823
 
Minority Interest Expense
   
842
   
222
 
               
NET INCOME
   
9,605
   
17,872
 
               
Preferred Stock Dividend Requirements
   
57
   
57
 
               
EARNINGS APPLICABLE TO COMMON STOCK
 
$
9,548
 
$
17,815
 

The common stock of SWEPCo is owned by a wholly-owned subsidiary of AEP.

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
 

 
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2005
 
$
135,660
 
$
245,003
 
$
407,844
 
$
(6,129
)
$
782,378
 
                                 
Common Stock Dividends
               
(10,000
)
       
(10,000
)
Preferred Stock Dividends
               
(57
)
       
(57
)
TOTAL
                           
772,321
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Income, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $930
                     
1,728
   
1,728
 
NET INCOME
               
17,872
         
17,872
 
TOTAL COMPREHENSIVE INCOME
                           
19,600
 
                                 
MARCH 31, 2006
 
$
135,660
 
$
245,003
 
$
415,659
 
$
(4,401
)
$
791,921
 
                                 
DECEMBER 31, 2006
 
$
135,660
 
$
245,003
 
$
459,338
 
$
(18,799
)
$
821,202
 
                                 
FIN 48 Adoption, Net of Tax
               
(1,642
)
       
(1,642
)
Preferred Stock Dividends
               
(57
)
       
(57
)
TOTAL
                           
819,503
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $39
                     
(327
)
 
(327
)
NET INCOME
               
9,605
         
9,605
 
TOTAL COMPREHENSIVE INCOME
                           
9,278
 
                                 
MARCH 31, 2007
 
$
135,660
 
$
245,003
 
$
467,244
 
$
(19,126
)
$
828,781
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2007 and December 31, 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
1,900
 
$
2,618
 
Advances to Affiliates
   
8,959
   
-
 
Accounts Receivable:
             
Customers
   
74,382
   
88,245
 
Affiliated Companies
   
48,598
   
59,679
 
Miscellaneous
   
13,077
   
8,595
 
Allowance for Uncollectible Accounts
   
(137
)
 
(130
)
   Total Accounts Receivable
   
135,920
   
156,389
 
Fuel
   
73,479
   
69,426
 
Materials and Supplies
   
46,101
   
46,001
 
Risk Management Assets
   
66,934
   
120,036
 
Margin Deposits
   
19,353
   
41,579
 
Prepayments and Other
   
28,581
   
18,256
 
TOTAL
   
381,227
   
454,305
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
1,586,238
   
1,576,200
 
Transmission
   
690,384
   
668,008
 
Distribution
   
1,262,203
   
1,228,948
 
Other
   
611,255
   
595,429
 
Construction Work in Progress
   
301,251
   
259,662
 
Total
   
4,451,331
   
4,328,247
 
Accumulated Depreciation and Amortization
   
1,868,974
   
1,834,145
 
TOTAL - NET
   
2,582,357
   
2,494,102
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
153,080
   
156,420
 
Long-term Risk Management Assets
   
16,301
   
20,531
 
Employee Benefits and Pension Assets
   
25,302
   
26,029
 
Deferred Charges and Other
   
68,855
   
39,581
 
TOTAL
   
263,538
   
242,561
 
               
TOTAL ASSETS
 
$
3,227,122
 
$
3,190,968
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
March 31, 2007 and December 31, 2006
(Unaudited)

   
2007
 
2006
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
 
$
-
 
$
188,965
 
Accounts Payable:
             
General
   
155,206
   
140,424
 
Affiliated Companies
   
72,448
   
68,680
 
Short-term Debt - Nonaffiliated
   
20,433
   
17,143
 
Long-term Debt Due Within One Year - Nonaffiliated
   
97,768
   
102,312
 
Risk Management Liabilities
   
55,263
   
109,578
 
Customer Deposits
   
36,798
   
48,277
 
Accrued Taxes
   
64,418
   
31,591
 
Regulatory Liability for Over-Recovered Fuel Costs
   
33,791
   
26,012
 
Other
   
66,871
   
85,086
 
TOTAL
   
602,996
   
818,068
 
               
NONCURRENT LIABILITIES
             
Long-term Debt - Nonaffiliated
   
822,519
   
576,694
 
Long-term Debt - Affiliated
   
50,000
   
50,000
 
Long-term Risk Management Liabilities
   
10,174
   
14,083
 
Deferred Income Taxes
   
362,321
   
374,548
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
347,951
   
346,774
 
Deferred Credits and Other
   
196,064
   
183,087
 
TOTAL
   
1,789,029
   
1,545,186
 
               
TOTAL LIABILITIES
   
2,392,025
   
2,363,254
 
               
Minority Interest
   
1,619
   
1,815
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
4,697
   
4,697
 
               
Commitments and Contingencies (Note 4)
             
               
COMMON SHAREHOLDER’S EQUITY
             
Common Stock - Par Value - $18 Per Share:
             
Authorized - 7,600,000 Shares
             
Outstanding - 7,536,640 Shares
   
135,660
   
135,660
 
Paid-in Capital
   
245,003
   
245,003
 
Retained Earnings
   
467,244
   
459,338
 
Accumulated Other Comprehensive Income (Loss)
   
(19,126
)
 
(18,799
)
TOTAL
   
828,781
   
821,202
 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 
$
3,227,122
 
$
3,190,968
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007 and 2006
(in thousands)
(Unaudited)

   
2007
 
2006
 
OPERATING ACTIVITIES
           
Net Income
 
$
9,605
 
$
17,872
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
34,122
   
32,617
 
Deferred Income Taxes
   
(6,677
)
 
(9,101
)
Mark-to-Market of Risk Management Contracts
   
2,965
   
10,468
 
Deferred Property Taxes
   
(28,815
)
 
(28,997
)
Change in Other Noncurrent Assets
   
(3,198
)
 
9,458
 
Change in Other Noncurrent Liabilities
   
(178
)
 
(19,121
)
Changes in Certain Components of Working Capital:
             
Accounts Receivable, Net
   
20,469
   
26,848
 
Fuel, Materials and Supplies
   
(4,141
)
 
(17,521
)
Margin Deposits
   
22,226
   
7,915
 
Accounts Payable
   
13,806
   
(15,304
)
Customer Deposits
   
(11,479
)
 
(15,861
)
Accrued Taxes, Net
   
36,113
   
45,238
 
Fuel Over/Under Recovery, Net
   
4,212
   
15,216
 
Other Current Assets
   
(2,868
)
 
2,821
 
Other Current Liabilities
   
(20,572
)
 
(21,255
)
Net Cash Flows From Operating Activities
   
65,590
   
41,293
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(107,613
)
 
(54,238
)
Change in Advances to Affiliates, Net
   
(8,959
)
 
-
 
Other
   
(4,067
)
 
(56
)
Net Cash Flows Used For Investing Activities
   
(120,639
)
 
(54,294
)
               
FINANCING ACTIVITIES
             
Issuance of Long-term Debt - Nonaffiliated
   
247,548
   
-
 
Change in Short-term Debt, Net - Nonaffiliated
   
3,290
   
4,394
 
Change in Advances from Affiliates, Net
   
(188,965
)
 
20,988
 
Retirement of Long-term Debt - Nonaffiliated
   
(6,395
)
 
(2,457
)
Principal Payments for Capital Lease Obligations
   
(1,090
)
 
(367
)
Dividends Paid on Common Stock
   
-
   
(10,000
)
Dividends Paid on Cumulative Preferred Stock
   
(57
)
 
(57
)
Net Cash Flows From Financing Activities
   
54,331
   
12,501
 
               
Net Decrease in Cash and Cash Equivalents
   
(718
)
 
(500
)
Cash and Cash Equivalents at Beginning of Period
   
2,618
   
3,049
 
Cash and Cash Equivalents at End of Period
 
$
1,900
 
$
2,549
 

SUPPLEMENTARY INFORMATION
           
Cash Paid for Interest, Net of Capitalized Amounts
 
$
16,747
 
$
11,892
 
Net Cash Paid for Income Taxes
   
580
   
1,282
 
Noncash Acquisitions Under Capital Leases
   
3,192
   
3,412
 
Construction Expenditures Included in Accounts Payable at March 31,
   
32,460
   
12,800
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to SWEPCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to SWEPCo.
 
 
Footnote Reference
   
Significant Accounting Matters
Note 1
New Accounting Pronouncements
Note 2
Rate Matters
Note 3
Commitments, Guarantees and Contingencies
Note 4
Benefit Plans
Note 6
Business Segments
Note 7
Income Taxes
Note 8
Financing Activities
Note 9


 

CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES

The condensed notes to condensed financial statements that follow are a combined presentation for the Registrant Subsidiaries. The following list indicates the registrants to which the footnotes apply:
     
1.
Significant Accounting Matters
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
2.
New Accounting Pronouncements
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
3.
Rate Matters
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
4.
Commitments, Guarantees and Contingencies
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
5.
Acquisitions, Dispositions and Assets Held for Sale
AEGCo, CSPCo, TCC
6.
Benefit Plans
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
7.
Business Segments
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
8.
Income Taxes
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
9.
Financing Activities
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC



         1. SIGNIFICANT ACCOUNTING MATTERS

General

The accompanying unaudited condensed financial statements and footnotes were prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all the information and footnotes required by GAAP for complete financial statements.

In the opinion of management, the unaudited interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations, financial position and cash flows for the interim periods for each Registrant Subsidiary. The results of operations for the three months March 31, 2007 are not necessarily indicative of results that may be expected for the year ending December 31, 2007. The accompanying condensed financial statements are unaudited and should be read in conjunction with the audited 2006 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2006 as filed with the SEC on February 28, 2007.

Components of Accumulated Other Comprehensive Income (Loss) (AOCI)

AOCI is included on the balance sheets in the common shareholder’s equity section. AOCI for Registrant Subsidiaries as of March 31, 2007 and December 31, 2006 is shown in the following table.
   
March 31,
 
December 31,
 
   
2007
 
2006
 
Components
 
(in thousands)
 
Cash Flow Hedges:
           
APCo
 
$
(10,031
)
$
(2,547
)
CSPCo
   
(1,878
)
 
3,398
 
I&M
   
(14,255
)
 
(8,962
)
KPCo
   
(490
)
 
1,552
 
OPCo
   
791
   
7,262
 
PSO
   
(1,025
)
 
(1,070
)
SWEPCo
   
(6,737
)
 
(6,410
)
TNC
   
-
   
(702
)
               
SFAS 158 Adoption:
             
APCo
 
$
(52,244
)
$
(52,244
)
CSPCo
   
(25,386
)
 
(25,386
)
I&M
   
(6,089
)
 
(6,089
)
OPCo
   
(64,025
)
 
(64,025
)
SWEPCo
   
(12,389
)
 
(12,389
)
TNC
   
(9,457
)
 
(9,457
)

Related Party Transactions

Oklaunion PPA between TNC and AEP Energy Partners

On January 1, 2007, TNC began a 20-year Power Purchase & Sale Agreement (PPA) with an affiliate, AEP Energy Partners (AEPEP), whereby TNC agrees to sell AEPEP 100% of TNC’s capacity and associated energy from its undivided interest (54.69%) in the Oklaunion plant. AEPEP is to pay TNC for the capacity and associated energy delivered to the delivery point, the sum of fuel, operation and maintenance, depreciation, capacity and all taxes other than federal income taxes applicable. A portion of the payment is fixed and is payable regardless of the level of output. There are no penalties if TNC fails to maintain a minimum availability level or exceeds a maximum heat rate level. The PPA was approved by the FERC on July 12, 2006.

TNC recorded revenue of $23.4 million from AEPEP in the first quarter of 2007, which is included in Sales to AEP Affiliates on its 2007 Condensed Consolidated Statement of Income.

ERCOT Contracts Transferred to AEPEP

Effective January 1, 2007, PSO and SWEPCo transferred certain existing ERCOT energy marketing contracts to AEPEP and entered into intercompany financial and physical purchase and sale agreements with AEPEP. This was done to lock in PSO and SWEPCo’s margins on ERCOT trading and marketing contracts and to transfer the future associated commodity price and credit risk to AEPEP. The contracts will mature over the next three years.

PSO and SWEPCo have historically presented third party ERCOT trading and marketing activity on a net basis in Revenues - Electric Generation, Transmission and Distribution. The applicable ERCOT third party trading and marketing contracts that were not transferred to AEPEP will remain until maturity on PSO and SWEPCo and will be presented on a net basis in Sales to AEP Affiliates on PSO’s and SWEPCo’s Statements of Income.

The following table indicates the sales to AEPEP and the amounts reclassified from third party to affiliate:

   
For the Three Months Ended March 31, 2007
 
Company
 
Net Settlement
With AEPEP
 
Third Party Amounts
Reclassified to Affiliate
 
Net Amount
included in Sales
to AEP Affiliates
 
   
(in thousands)
 
PSO
 
$
43,150
 
$
(35,837
)
$
7,313
 
SWEPCo
   
46,876
   
(38,259
)
 
8,617
 

The following table indicates the affiliated portion of risk management assets and liabilities reflected on PSO’s and SWEPCo’s balance sheets associated with these contracts:
 
   
As of March 31, 2007
 
   
PSO
 
SWEPCo
 
Current
 
(in thousands)
 
Risk Management Assets
 
$
-
 
$
-
 
Risk Management Liabilities
   
(8,282
)
 
(9,758
)
               
Noncurrent
             
Long-term Risk Management Assets
 
$
584
 
$
688
 
Long-term Risk Management Liabilities
   
(2,097
)
 
(2,471
)

Texas Restructuring - SPP - Affecting TNC and SWEPCo

In August 2006, the PUCT adopted a rule extending the delay in implementation of customer choice in the SPP area of Texas until no sooner than January 1, 2011. SWEPCo’s and approximately 3% of TNC’s businesses were in SPP. A petition was filed in May 2006 requesting approval to transfer Mutual Energy SWEPCO L.P.’s (a subsidiary of AEP C&I Company, LLC) customers and TNC’s facilities and certificated service territory located in the SPP area to SWEPCo. In January 2007, the final regulatory approval was received for the transfers. The transfers were effective February 2007 and were recorded at net book value of $11.6 million. The Arkansas Public Service Commission’s approval requires SWEPCo to amend its fuel recovery tariff so that Arkansas customers do not pay the incremental cost of serving the additional load.

Reclassifications

Certain prior period financial statement items have been reclassified to conform to current period presentation. These revisions had no impact on the Registrant Subsidiaries’ previously reported results of operations or changes in shareholders’ equity.

On their statements of income, the Registrant Subsidiaries reclassified regulatory credits related to regulatory asset cost deferral on ARO from Depreciation and Amortization to Other Operation and Maintenance to offset the ARO accretion expense. The following table shows the credits reclassified by the Registrant Subsidiaries in 2006:

   
Three Months Ended
 
   
March 31, 2006
 
Company
 
(in thousands)
 
AEGCo
 
$
27
 
APCo
   
296
 
I&M
   
5,589
 

         2. NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of exposure drafts or final pronouncements, we thoroughly review the new accounting literature to determine the relevance, if any, to our business. The following represents a summary of new pronouncements issued or implemented in 2007 and standards issued but not implemented that we have determined relate to our operations.

SFAS 157 “Fair Value Measurements” (SFAS 157)

In September 2006, the FASB issued SFAS 157, enhancing existing guidance for fair value measurement of assets and liabilities and instruments measured at fair value that are classified in shareholders’ equity. The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures. It emphasizes that fair value is market-based with the highest measurement hierarchy being market prices in active markets. The standard requires fair value measurements be disclosed by hierarchy level and an entity include its own credit standing in the measurement of its liabilities and modifies the transaction price presumption.

SFAS 157 is effective for interim and annual periods in fiscal years beginning after November 15, 2007. Management expects that the adoption of this standard will impact MTM valuations of certain contracts, but is unable to quantify the effect. Although the statement is applied prospectively upon adoption, the effect of certain transactions is applied retrospectively as of the beginning of the fiscal year of application, with a cumulative effect adjustment to the appropriate balance sheet items. The Registrant Subsidiaries will adopt SFAS 157 effective January 1, 2008.

SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159)

In February 2007, the FASB issued SFAS 159, permitting entities to choose to measure many financial instruments and certain other items at fair value. The standard also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities.

SFAS 159 is effective for annual periods in fiscal years beginning after November 15, 2007. If the fair value option is elected, the effect of the first remeasurement to fair value is reported as a cumulative effect adjustment to the opening balance of retained earnings. In the event we elect the fair value option promulgated by this standard, the valuations of certain assets and liabilities may be impacted. The statement is applied prospectively upon adoption. The Registrant Subsidiaries will adopt SFAS 159 effective January 1, 2008.

FIN 48 “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1 "Definition of Settlement in FASB Interpretation No. 48"

In July 2006, the FASB issued FASB Interpretation No. 48 "Accounting for Uncertainty in Income Taxes" and in May 2007, the FASB issued FASB Staff Position FIN 48-1 "Definition of Settlement in FASB Interpretation No. 48."  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. The Registrant Subsidiaries adopted FIN 48 effective January 1, 2007. The impact of this interpretation was an unfavorable (favorable) adjustment to retained earnings as follows:

Company
 
(in thousands)
 
AEGCo
 
$
(27
)
APCo
   
2,685
 
CSPCo
   
3,022
 
I&M
   
(327
)
KPCo
   
786
 
OPCo
   
5,380
 
PSO
   
386
 
SWEPCo
   
1,642
 
TCC
   
2,187
 
TNC
   
557
 

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued by FASB, we cannot determine the impact on the reporting of our operations and financial position that may result from any such future changes. The FASB is currently working on several projects including business combinations, revenue recognition, liabilities and equity, derivatives disclosures, emission allowances, leases, insurance, subsequent events and related tax impacts. We also expect to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP. The ultimate pronouncements resulting from these and future projects could have an impact on future results of operations and financial position.

         3. RATE MATTERS

The Registrant subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2006 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact results of operations, cash flows and possibly financial condition. The following discusses ratemaking developments in 2007 and updates the 2006 Annual Report.

Ohio Rate Matters

Ohio Restructuring and Rate Stabilization Plans - Affecting CSPCo and OPCo

In January 2007, CSPCo and OPCo 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. Pursuant to the RSPs, CSPCo and OPCo implemented these proposed increases effective with the beginning of the May 2007 billing cycle. 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. The PAR is intended to recover the difference between CSPCo's tariffed generation service rates and the cost of power acquired to serve the former Monongahela Power load. The PAR was set for an initial 17-month period of January 2006 through May 2007. The filing would adjust the PAR for the nineteen month period of June 2007 through December 2008. The filing reflects a true up for estimated under-recoveries during the initial period, $8 million as of March 31, 2007, as well as the power acquisition costs for the upcoming nineteen-month period. If approved, CSPCo's revenues would increase by $22 million and $38 million for 2007 and 2008, respectively.
 
In March 2007, CSPCo and OPCo filed a settlement agreement at the PUCO resolving the Ohio Supreme Court's remand of the PUCO’s RSP order. The Supreme Court indicated concern with the absence of a competitive bid process as an alternative to the generation rates set by the RSP. In response, the settling parties agreed to have CSPCo and OPCo take bids for Renewable Energy Certificates (RECs). CSPCo and OPCo will give customers the option to pay a generation rate premium that would encourage the development of renewable energy sources by reimbursing CSPCo and OPCo for the cost of the RECs and the administrative costs of the program. This settlement agreement was supported by the Office of Consumers' Counsel, the Ohio Partners for Affordable Energy, the Ohio Energy Group and the PUCO staff. In May 2007, the PUCO adopted the settlement agreement in its entirety.
 
CSPCo and OPCo are involved in discussions with various stakeholders in Ohio about potential legislation to address the period following the expiration of the RSPs on December 31, 2008. At this time, management is unable to predict whether CSPCo and OPCo will transition to market pricing, as permitted by the current Ohio restructuring legislation, extend their RSP rates, with or without modification, or become subject to a legislative reinstatement of some form of cost-based regulation for their generation supply business on January 1, 2009 when the RSP period ends.

Customer Choice Deferrals - Affecting CSPCo and OPCo

As provided in the restructuring settlement agreement approved by the PUCO in 2000, CSPCo and OPCo established regulatory assets for customer choice implementation costs and related carrying costs in excess of $20 million each for recovery in the next general base rate filing which changes distribution rates after December 31, 2007 for OPCo and December 31, 2008 for CSPCo. Pursuant to the RSPs, recovery of these amounts for OPCo was further deferred until the next base rate filing to change distribution rates after the end of the RSP period of December 31, 2008. Through March 31, 2007, CSPCo and OPCo incurred $50 million and $51 million, respectively, of such costs and established regulatory assets of $25 million each for such costs. CSPCo and OPCo have not recognized $5 million and $6 million, respectively, of equity carrying costs, which are recognizable when collected. Management believes that the deferred customer choice implementation costs were prudently incurred to implement customer choice in Ohio and are probable of recovery in future distribution rates.

IGCC Plant - Affecting CSPCo and OPCo

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. Management believes 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.

Distribution Reliability Plan - Affecting CSPCo and OPCo

In January 2006, CSPCo and OPCo initiated a proceeding at the PUCO seeking a new distribution rate rider to fund enhanced distribution reliability programs. In the fourth quarter of 2006, as directed by the PUCO, CSPCo and OPCo filed a proposed enhanced reliability plan. The plan contemplated CSPCo and OPCo recovering approximately $28 million and $43 million, respectively, in additional distribution revenue during an eighteen month period beginning July 2007. In January 2007, the OCC filed testimony, which argued that CSPCo and OPCo should be required to improve distribution service reliability with funds from their existing rates.

In April 2007, CSPCo and OPCo filed a joint motion with the PUCO staff, the Ohio Consumers’ Counsel, the Appalachian People’s Action Coalition, the Ohio Partners for Affordable Energy and the Ohio Manufacturers Association to withdraw the proposed enhanced reliability plan.

Ormet - Affecting CSPCo and OPCo

Effective January 1, 2007, CSPCo and OPCo began to serve Ormet, a major industrial customer with a 520 MW load, under a PUCO encouraged settlement agreement. The settlement agreement between CSPCo and OPCo, Ormet, its employees’ union and certain other interested parties was approved by the PUCO in November 2006. The settlement agreement provides for the recovery in 2007 and 2008 by CSPCo and OPCo of the difference between $43 per MWH to be paid by Ormet for power and a PUCO approved market price, if higher. The recovery will be accomplished by the amortization of a $57 million ($15 million for CSPCo and $42 million for OPCo) Ohio franchise tax phase-out regulatory liability recorded in 2005 and, if that is not sufficient, an increase in RSP generation rates under the additional 4% provision of the RSPs. The $43 per MWH price to be paid by Ormet for generation services is above the industrial RSP generation tariff but below current market prices. In December 2006, CSPCo and OPCo submitted a market price of $47.69 per MWH for 2007, which is pending PUCO approval. If the PUCO approves a lower market price, it could have an adverse effect on results of operations and cash flows. If CSPCo and OPCo serve the Ormet load after 2008 without any special provisions, they could experience incremental costs to acquire additional capacity to meet their reserve requirements and/or forgo off-system sales margins, which could have an adverse effect on future results of operations and cash flows.

Texas Rate Matters

TCC TEXAS RESTRUCTURING - Affecting TCC

Texas District Court Appeal Proceedings

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. See “TCC and TNC Deferred Fuel” andTCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes” sections below.

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. The judge directed that these matters should be remanded to the PUCT to determine the 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.

OTHER TEXAS RESTRUCTURING MATTERS

TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes - Affecting TCC

In TCC’s 2006 true-up and securitization orders, the PUCT reduced net regulatory assets and the amount to be securitized by $51 million related to the present value of ADITC and by $10 million related to EDFIT associated with TCC’s generation assets for a total reduction of $61 million.

TCC filed a request for a private letter ruling with the IRS in June 2005 regarding the permissibility under the IRS rules and regulations of the ADITC and EDFIT reduction proposed by the PUCT. The IRS issued its private letter ruling in May 2006, which stated that the PUCT’s flow-through to customers of the present value of the ADITC and EDFIT benefits would result in a normalization violation. To address the matter and avoid a normalization violation, the PUCT agreed to allow TCC to defer an amount of the CTC refund totaling $103 million ($61 million in present value of ADITC and EDFIT associated with TCC’s generation assets plus $42 million of related carrying costs) pending resolution of the normalization issue. If it is ultimately determined that a refund to customers through the true-up process of the ADITC and EDFIT, discussed above, is not a normalization violation, then TCC will be required to refund the $103 million, plus additional carrying costs. However, if such refund of ADITC and EDFIT is ultimately determined to cause a normalization violation, TCC anticipates it will be permitted to retain the $61 million present value of ADITC and EDFIT plus carrying costs, favorably impacting future results of operations.

If a normalization violation occurs, it could result in TCC’s repayment to the IRS of ADITC on all property, including transmission and distribution property, which approximates $104 million as of March 31, 2007, and a loss of TCC’s right to claim accelerated tax depreciation in future tax returns. Tax counsel advised management that a normalization violation should not occur until all remedies under law have been exhausted and the tax benefits are returned to ratepayers under a nonappealable order. Management intends to continue its efforts to avoid a normalization violation that would adversely affect future results of operations and cash flows.

TCC and TNC Deferred Fuel - Affecting TCC and TNC

The TCC deferred fuel over-recovery regulatory liability is a component of the other true-up items net regulatory liability refunded through the CTC rate rider credit. In 2002, TCC and TNC filed with the PUCT seeking to reconcile fuel costs and establish their final deferred fuel balances. In its final fuel reconciliation orders, the PUCT ordered a reduction in TCC’s and TNC’s recoverable fuel costs for, among other things, the reallocation of additional AEP System off-system sales margins under a FERC-approved SIA. Both TCC and TNC appealed the PUCT’s rulings regarding a number of issues in the fuel orders in state court and challenged the jurisdiction of the PUCT over the allocation of off-system sales margin allocations in the federal court. Intervenors also appealed the PUCT’s rulings in state court.

In 2006, the Federal District Court issued orders precluding the PUCT from enforcing the off-system sales reallocation portion of its ruling in the final TNC and TCC fuel reconciliation proceedings. The Federal court ruled, in both cases, that the FERC, not the PUCT, has jurisdiction over the allocation. The PUCT appealed both Federal District Court decisions to the United States Court of Appeals. In TNC’s case, the Court of Appeals affirmed the District Court’s decision. The PUCT has indicated they will appeal this ruling to the United States Supreme Court. TCC has filed a Motion for Summary Affirmance based on the outcome of the TNC appeal. For TCC, the PUCT has conceded the issue concerning the allocation of off-system sales margins to AEP West companies under the SIA as governed by the TNC case. However, the PUCT continues to challenge the allocation of those margins among AEP West companies under the CSW Operating Agreement. If the PUCT’s appeals are ultimately unsuccessful, TCC and TNC could record income of $16 million and $8 million, respectively, related to the reversal of the previously recorded fuel over-recovery regulatory liabilities.

If the PUCT is unsuccessful in the federal court system, it or another interested party may file a complaint at the FERC to address the allocation issue. If a complaint at the FERC results in the PUCT’s decisions being adopted by the FERC, there could be an adverse effect on results of operations and cash flows. An unfavorable FERC ruling may result in a retroactive reallocation of off-system sales margins from AEP East companies to AEP West companies under the then existing SIA allocation method. If the adjustments were applied retroactively, the AEP East companies may be unable to recover the amounts reallocated to the West companies from their customers due to past frozen rates, past inactive fuel clauses and fuel clauses that do not include off-system sales credits. Although management cannot predict the ultimate outcome of this federal litigation, management believes that its allocations were in accordance with the then existing FERC-approved SIA and that it should not have to allocate additional off-system sales margins to the West companies including TCC and TNC.

In January 2007, TCC began refunding as part of the CTC rate rider credit described above, $149 million of its $165 million over-recovered deferred fuel regulatory liability. The remaining $16 million refund related to the favorable Federal District Court order has been deferred pending the outcome of the federal court appeal and would be subject to refund only upon a successful appeal by the PUCT.

Excess Earnings - Affecting TCC

In 2005, the Texas Court of Appeals issued a decision finding the PUCT’s prior order from the unbundled cost of service case requiring TCC to refund excess earnings prior to and outside of the true-up process was unlawful under the Texas Restructuring Legislation. TCC refunded $55 million of excess earnings, including interest, of which $30 million went to the affiliated REP. In November 2005, the PUCT filed a petition for review with the Supreme Court of Texas seeking reversal of the Texas Court of Appeals’ decision. The Supreme Court of Texas requested briefing, which has been provided, but it has not decided whether it will hear the case. If the Court of Appeals decision is upheld and the refund mechanism is found to be unlawful, the impact on TCC would then depend on: (a) how and if TCC is ordered by the PUCT to refund the excess earnings through the true-up process to ultimate customers and (b) whether TCC will be able to recover the amounts previously refunded to the REPs including the REP TCC sold to Centrica. Management is unable to predict the ultimate outcome of this litigation and its effect on future results of operations and cash flows.

OTHER TEXAS RATE MATTERS

TCC and TNC Energy Delivery Base Rate Filings - Affecting TCC and TNC

TCC and TNC each filed a base rate case seeking to increase transmission and distribution energy delivery services (wires) base rates in Texas. TCC and TNC requested $81 million and $25 million in annual increases, respectively. Both requests include a return on common equity of 11.25% and the impact of the expiration of the CSW merger savings rate credits. In March 2007, various intervenors and the PUCT staff filed their recommendations. 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. The recommended return on common equity ranged from 9.00% to 9.75%. In April 2007, TCC and TNC filed rebuttal testimony reducing the requested annual increases to $70 million for TCC and $22 million for TNC including a reduced requested return on common equity of 10.75%. Hearings began in April 2007 and are scheduled to be concluded in May 2007. Management expects the new base wires rates to become effective, subject to refund, in the second quarter of 2007 with a decision from the PUCT expected in the third quarter of 2007. Management is unable to predict the ultimate effect of this filing on future results of operations, cash flows and financial condition.

SWEPCo Fuel Reconciliation - Texas - Affecting SWEPCo

In June 2006, SWEPCo filed a fuel reconciliation proceeding with the PUCT for its Texas retail operations. SWEPCo sought, in the proceedings, to include under-recoveries related to the reconciliation period of $50 million. In January 2007, intervenors filed testimony recommending that SWEPCo’s reconcilable fuel costs be reduced. The intervenor recommendations ranged from a $10 million to $28 million reduction. In February 2007, the PUCT staff filed testimony recommending that SWEPCo’s reconcilable fuel costs be reduced by $10 million. SWEPCo does not agree with the intervenor’s or staff’s recommendations and filed rebuttal testimony in February 2007. Hearings have been held and briefs have been filed. Results of operations could be adversely affected by $28 million plus carrying costs if the PUCT adopts all of the intervenor and staff recommendations. Management is unable to predict the outcome of this proceeding or its effect on future results of operations and cash flows.

Virginia Rate Matters 

Virginia Restructuring - Affecting APCo

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 transmission and distribution 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, subject to Virginia SCC approval, certain environmental retrofits, and a floor on the allowed return on equity based on the average earned return on equities’ of regional vertically integrated electric utilities. Effective July 1, 2007, the amendments allow utilities to retain a minimum of 25% of the margins from off-system sales with the remaining margins from such sales credited against fuel factor expenses. 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.

APCo Virginia Base Rate Case - Affecting APCo

In May 2006, APCo filed a request with the Virginia SCC seeking an increase in base rates of $225 million to recover increasing costs including the cost of its investment in environmental equipment and a return on equity of 11.5%. In addition, APCo requested to move off-system sales margins, currently credited to customers through base rates, to the fuel factor where they can be trued-up to actual. APCo also proposed to share the off-system sales margins with customers with 40% going to reduce rates and 60% being retained by APCo. This proposed off-system sales fuel rate credit, which is estimated to be $27 million, partially offsets the $225 million requested increase in base rates for a net increase in base rate revenues of $198 million. The major components of the $225 million base rate request include $73 million for the impact of removing off-system sales margins from the rate year ending September 30, 2007, $60 million mainly due to projected net environmental plant additions through September 30, 2007 and $48 million for return on equity.

In May 2006, the Virginia SCC issued an order, consistent with Virginia law, placing the net requested base rate increase of $198 million into effect on October 2, 2006, subject to refund. The $198 million base rate increase being collected, subject to refund, includes recovery of incremental environmental compliance and transmission and distribution system reliability (E&R) costs projected to be incurred during the rate year beginning October 2006. These incremental E&R costs can be deferred and recovered through the E&R surcharge mechanism if not recovered through this base rate request. In October 2006, the Virginia SCC staff filed its direct testimony recommending a base rate increase of $13 million with a return on equity of 9.9% and no off-system sales margin sharing. Other intervenors have recommended base rate increases ranging from $42 million to $112 million. APCo filed rebuttal testimony in November 2006. Hearings were held in December 2006.

In March 2007, the Hearing Examiner (HE) 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. The HE’s recommendations include a return on equity of 10.1% which would reduce APCo’s revenue requirement by approximately $23 million. The HE also recommended limiting forward looking ratemaking adjustments to June 30, 2006 as opposed to September 30, 2007, which would reduce APCo’s revenue requirement by approximately $72 million, of which approximately $60 million relates to incremental E&R costs that can be deferred for future recovery through the E&R surcharge mechanism. The HE further proposed to share the off-system sales margins using the twelve months ended June 30, 2006 of $101 million with 50% reducing base rates, 45% reducing fuel rates and 5% retained by APCo to determine the revenue requirement. APCo’s proposal did not reduce base rates for off-system sales margins, but reduced fuel rates approximately $27 million for off-system sales margins. APCo expects a final order to be issued during 2007.

APCo is providing for a possible refund of revenues collected subject to refund consistent with the HE recommendations. Management is unable to predict the ultimate effect of this filing on future results of operations, cash flows and financial condition.

West Virginia Rate Matters

APCo Expanded Net Energy Cost (ENEC) Filing - Affecting APCo

In April 2007, the WVPSC issued an order establishing an investigation and hearing of APCo’s and WPCo’s 2007 ENEC joint compliance filing. The ENEC is an expanded form of fuel clause mechanism, which includes all energy-related costs including fuel, purchased power expenses, off-system sales credits and other energy/transmission items. In the March 2007 ENEC joint compliance filing, APCo filed for an increase of approximately $91 million including a $65 million increase in ENEC and a $26 million increase in construction surcharges to become effective July 1, 2007. A hearing on the joint compliance filing is scheduled for May 2007.

APCo IGCC - Affecting APCo

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.

Indiana Rate Matters

I&M Depreciation Study Filing - Affecting I&M

In February 2007, I&M filed a request with the IURC for approval of revised book depreciation rates effective January 1, 2007. The filing included a settlement agreement entered into with the Indiana Office of the Utility Consumer Counsel that would provide direct benefits to I&M's customers if new depreciation rates are approved by the IURC. The direct benefits would include a $5 million credit to fuel costs and an approximate $8 million smart metering pilot program. In addition, if the agreement is approved, I&M would initiate a general rate proceeding on or before July 1, 2007 and initiate two studies, one to investigate a general smart metering program and the other to study the market viability of demand side management programs. Based on the depreciation study included in the filing, I&M recommended a decrease in pretax annual depreciation expense on an Indiana jurisdictional basis of approximately $69 million reflecting an NRC-approved 20-year extension of the Cook Plant licenses for Units 1 and 2 and an extension of the service life of the Tanners Creek coal-fired generating units. This petition was not a request for a change in customers’ electric service rates. As proposed, the book depreciation reduction would increase earnings but would not impact cash flows until rates are revised. The IURC held a public hearing in April 2007. I&M requested expeditious review and approval of its filing, but management cannot predict the outcome of the request or the timing of any approved depreciation reduction. If approved as filed, pretax earnings would increase by $64 million in 2007.

Kentucky Rate Matters

KPCo Environmental Surcharge Filing - Affecting KPCo

In July 2006, KPCo filed for approval of an amended environmental compliance plan and revised tariff to implement an adjusted environmental surcharge. KPCo estimates the amended environmental compliance plan and revised tariff would increase revenues over 2006 levels by approximately $2 million in 2007 and $6 million in 2008 for a total of $8 million of additional revenue at current cost projections. In January 2007, the KPSC issued an order approving KPCo’s proposed plan and surcharge. Future recovery is based upon actual environmental costs and is subject to periodic review and approval of those actual costs by the KPSC.

In November 2006, the Kentucky Attorney General and the Kentucky Industrial Utility Consumers (KIUC) filed an appeal with the Kentucky Court of Appeals of the Franklin Circuit Court’s 2006 order upholding the KPSC’s 2005 Environmental Surcharge order. In its order, the KPSC approved KPCo’s recovery of its environmental costs at its Big Sandy Plant and its share of environmental costs incurred as a result of the AEP Power Pool capacity settlement. The KPSC has allowed KPCo to recover these FERC-approved allocated costs, via the environmental surcharge, since the KPSC’s first environmental surcharge order in 1997. KPCo presently recovers $7 million a year in environmental surcharge revenues.

In March 2007, the KPSC issued an order, at the request of the Kentucky Attorney General, stating the environmental surcharge collections authorized in the January 2007 order that are associated with out-of-state generating facilities should be collected over the six months beginning March 2007, subject to refund, pending the outcome of the court of appeals process. At this time, management is unable to predict the outcome of this proceeding and its effect on KPCo’s current environmental surcharge revenues or on the January 2007 KPSC order increasing KPCo’s environmental rates.

Oklahoma Rate Matters

PSO Fuel and Purchased Power and its Possible Impact on AEP East companies and AEP West companies

In 2002, PSO under-recovered $44 million of fuel costs resulting from a reallocation among AEP West companies of purchased power costs for periods prior to January 1, 2002. In July 2003, PSO proposed collection of those reallocated costs over eighteen months. In August 2003, the OCC staff filed testimony recommending PSO recover $42 million of the reallocated purchased power costs over three years and PSO reduced its regulatory asset deferral by $2 million. The OCC subsequently expanded the case to include a full prudence review of PSO’s 2001 fuel and purchased power practices. In January 2006, the OCC staff and intervenors issued supplemental testimony alleging that AEP deviated from the FERC-approved method of allocating off-system sales margins between AEP East companies and AEP West companies and among AEP West companies. The OCC staff proposed that the OCC offset the $42 million of under-recovered fuel with the proposed reallocation of off-system sales margins of $27 million to $37 million and with $9 million attributed to wholesale customers, which they claimed had not been refunded. In February 2006, the OCC staff filed a report concluding that the $9 million of reallocated purchased power costs assigned to wholesale customers had been refunded, thus removing that issue from its recommendation.

In 2004, an Oklahoma ALJ found that the OCC lacks authority to examine whether PSO deviated from the FERC-approved allocation methodology and held that any such complaints should be addressed at the FERC. The OCC has not ruled on appeals by intervenors of the ALJ’s finding. The United States District Court for the Western District of Texas issued orders in September 2005 regarding a TNC fuel proceeding and in August 2006 regarding a TCC fuel proceeding, preempting the PUCT from reallocating off-system sales margins between the AEP East companies and AEP West companies. The federal court agreed that the FERC has sole jurisdiction over that allocation. The PUCT appealed the ruling. The United States Court of Appeals for the Fifth Circuit, issued a decision in December 2006 regarding the TNC fuel proceeding that affirmed the United States District Court ruling.

PSO does not agree with the intervenors’ and the OCC staff’s recommendations and proposals other than the staff’s original recommendation that PSO be allowed to recover the $42 million over three years and will defend its right to recover its under-recovered fuel balance. Management believes that if the position taken by the federal courts in the Texas proceeding is applied to PSO’s case, then the OCC should be preempted from disallowing fuel recoveries for alleged improper allocations of off-system sales margins between AEP East companies and AEP West companies. The OCC or another party could file a complaint at the FERC alleging the allocation of off-system sales margins to PSO is improper, which could result in an adverse effect on future results of operations and cash flows for AEP and the AEP East companies. However, to date, there has been no claim asserted at the FERC that AEP deviated from the approved allocation methodologies, but even if one were asserted, management believes that it would not prevail. 

In June 2005, the OCC issued an order directing its staff to conduct a prudence review of PSO’s fuel and purchased power practices for the year 2003. The OCC staff filed testimony finding no disallowances in the test year data. The Attorney General of Oklahoma filed testimony stating that they could not determine if PSO’s gas procurement activities were prudent, but did not include a recommended disallowance. However, an intervenor filed testimony in June 2006 proposing the disallowance of $22 million in fuel costs based on a historical review of potential hedging opportunities that he alleges existed during the year. A hearing was held in August 2006 and management expects a recommendation from the ALJ in 2007. 

In February 2006, a law was enacted requiring the OCC to conduct prudence reviews on all generation and fuel procurement processes, practices and costs on either a two or three-year cycle depending on the number of customers served. PSO is subject to the required biennial reviews. In compliance with an OCC order, PSO is required to file its testimony by June 15, 2007. This proceeding will cover the year 2005.

Management cannot predict the outcome of the pending fuel and purchased power reviews or planned future reviews, but believes that PSO’s fuel and purchased power procurement practices and costs are prudent and properly incurred. If the OCC disagrees and disallows fuel or purchased power costs including the unrecovered 2002 reallocation of such costs incurred by PSO, it would have an adverse effect on future results of operations and cash flows.

PSO Rate Filing - Affecting PSO

In November 2006, PSO filed a request to increase base rates $50 million for Oklahoma jurisdictional customers with a proposed effective date in the second quarter of 2007. PSO sought a return on equity of 11.75%. PSO also proposed a formula rate plan that, if approved as filed, will permit PSO to defer any unrecovered costs as a result of a revenue deficiency that exceeds 50 basis points of the allowed return on equity for recovery within twelve months beginning six months after the test year. The formula would enable PSO to recover on a timely basis the cost of its new generation, transmission and distribution construction (including carrying costs during construction), provide the opportunity to achieve the approved return on equity and avoid recording a significant AFUDC that would have been recorded during the construction time period.

In March 2007, the OCC staff and various intervenors filed testimony. The recommendations were base rate reductions that ranged from $18 million to $52 million. The recommended returns on equity ranged from 9.25% to 10.09%. These recommendations included reductions in depreciation expense of approximately $25 million, which has no earnings impact. The OCC staff filed testimony supporting a formula rate plan, generally similar to the one proposed by PSO. In April 2007, PSO filed rebuttal testimony regarding various issues raised by the OCC Staff and the intervenors. As a result of rebuttal testimony, PSO reduced its base rate request by $2 million. Hearings commenced on May 1, 2007.

Management is unable to predict the outcome of these proceedings, however, if rates are not increased in an amount sufficient to recover expected unavoidable cost increases future results of operations, cash flows and possibly financial condition could be adversely affected.

PSO Lawton and Peaking Generation Settlement Agreement - Affecting PSO

On November 26, 2003, pursuant to an application by Lawton Cogeneration, L.L.C. (Lawton) seeking approval of a Power Supply Agreement (the Agreement) with PSO and associated avoided cost payments, the OCC issued an order approving the Agreement and setting the avoided costs. The order did not address recovery by PSO of the resultant purchased power costs.

In December 2003, PSO filed an appeal of the OCC’s order with the Oklahoma Supreme Court (the Court). In the appeal, PSO maintained that the OCC exceeded its authority under state and federal laws to require PSO to enter into the Agreement. The Court issued a decision on June 21, 2005, affirming portions of the OCC’s order and remanding certain provisions. The Court affirmed the OCC’s finding that Lawton established a legally enforceable obligation and ruled that it was within the OCC’s discretion to award a 20-year contract and to base the capacity payment on a peaking unit. The Court directed the OCC to revisit its determination of PSO’s avoided energy cost. Hearings were held on the remanded issues in April and May 2006.

In April 2007, all parties in the case filed a settlement agreement with the OCC resolving all issues. The OCC approved the settlement agreement in April 2007. The settlement agreement provides for a purchase fee of $35 million to be paid by PSO to Lawton and for Lawton to provide, at PSO’s direction, all rights to the Lawton 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 through a rider, subject to a $135 million cost cap, all of the traditional costs associated with plant in service of its new peaking units to be located at the Southwestern Station and Riverside Station at the time these units are placed in service. PSO may request approval from the OCC for recovery of costs exceeding the cost cap if special circumstances occurred necessitating a higher level of costs. Such costs will continue to 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. Once the cost recovery for the new peaking units begins in mid-2008, PSO expects annual revenues of an estimated $36 million related to cost recovery of the peaking units and the purchase fee. This settlement agreement was supported by the OCC Staff, the Attorney General, the Oklahoma Industrial Energy Consumers and Lawton Cogeneration, L.L.C.

Louisiana Rate Matters

SWEPCo Louisiana Compliance Filing - Affecting SWEPCo

In October 2002, SWEPCo filed with the LPSC detailed financial information typically utilized in a revenue requirement filing, including a jurisdictional cost of service. This filing was required by the LPSC as a result of its order approving the merger between AEP and CSW. Due to multiple delays, in April 2006, the LPSC and SWEPCo agreed to update the financial information based on a 2005 test year. SWEPCo filed updated financial review schedules in May 2006 showing a return on equity of 9.44% compared to the previously authorized return on equity of 11.1%.

In July 2006, the LPSC staff’s consultants filed direct testimony recommending a base rate reduction in the range of $12 million to $20 million for SWEPCo’s Louisiana jurisdiction customers, based on a proposed 10% return on equity. The recommended reduction range is subject to SWEPCo validating certain ongoing operations and maintenance expense levels. SWEPCo filed rebuttal testimony in October 2006 strongly refuting the consultants’ recommendations. In December 2006, the LPSC staff’s consultants filed reply testimony asserting that SWEPCo’s Louisiana base rates are excessive by $17 million which includes a proposed return on equity of 9.8%. SWEPCo filed rebuttal testimony in January 2007. A decision is not expected until mid or late 2007. At this time, management is unable to predict the outcome of this proceeding. If a rate reduction is ultimately ordered, it would adversely impact future results of operations, cash flows and possibly financial condition.

FERC Rate Matters

Transmission Rate Proceedings at the FERC - Affecting APCo, CSPCo, I&M, KPCo and OPCo

The FERC PJM Regional Transmission Rate Proceeding

At AEP’s urging, the FERC instituted an investigation of PJM’s zonal rate regime, indicating that the present rate regime may need to be replaced through establishment of regional rates that would compensate AEP and other transmission owners for the regional transmission facilities they provide to PJM, which provides service for the benefit of customers throughout PJM. In September 2005, AEP and a nonaffiliated utility (Allegheny Power or AP) jointly filed a regional transmission rate design proposal with the FERC. This filing proposes and supports a new PJM rate regime generally referred to as Highway/Byway.

Parties to the regional rate proceeding proposed the following rate regimes:

·
AEP/AP proposed a Highway/Byway rate design in which:
 
·
The cost of all transmission facilities in the PJM region operated at 345 kV or higher would be included in a “Highway” rate that all load serving entities (LSEs) would pay based on peak demand. The AEP/AP proposal would produce about $125 million in additional revenues per year for AEP from users in other zones of PJM.
 
·
The cost of transmission facilities operating at lower voltages would be collected in the zones where those costs are presently charged under PJM’s existing rate design.
·
Two other utilities, Baltimore Gas & Electric Company (BG&E) and Old Dominion Electric Cooperative (ODEC), proposed a Highway/Byway rate that includes transmission facilities above 200 kV, which would produce lower revenues for AEP than the AEP/AP proposal.
·
In another competing Highway/Byway proposal, a group of LSEs proposed rates that would include existing 500 kV and higher voltage facilities and new facilities above 200 kV in the Highway rate, which would produce considerably lower revenues for AEP than the AEP/AP proposal.
·
In January 2006, the FERC staff issued testimony and exhibits supporting a PJM-wide flat rate or “Postage Stamp” type of rate design that would include all transmission facilities, which would produce higher transmission revenues for AEP than the AEP/AP proposal.

All of these proposals were challenged by a majority of other transmission owners in the PJM region, who favor continuation of the existing PJM rate design which provides AEP with no compensation for through and out traffic on its east zone transmission system. Hearings were held in April 2006 and the ALJ issued an initial decision in July 2006. The ALJ found the existing PJM zonal rate design to be unjust and determined that it should be replaced. The ALJ found that the Highway/Byway rates proposed by AEP/AP and BG&E/ODEC and the Postage Stamp rate proposed by the FERC staff to be just and reasonable alternatives. The ALJ also found FERC staff’s proposed Postage Stamp rate to be just and reasonable and recommended that it be adopted. The ALJ also found that the effective date of the rate change should be April 1, 2006 to coincide with SECA rate elimination. Because the Postage Stamp rate was found to produce greater cost shifts than other proposals, the judge also recommended that the design be phased-in. Without a phase-in, the Postage Stamp method would produce more revenue for AEP than the AEP/AP proposal. The phase-in of Postage Stamp rates would delay the full impact of that result until about 2012.

AEP filed briefs noting exceptions to the initial decision and replies to the exceptions of other parties. AEP argued that a phase-in should not be required. Nevertheless, AEP argued that if the FERC adopts the Postage Stamp rate and a phase-in plan, the revenue collections curtailed by the phase-in should be deferred and paid later with interest.

During 2006, the AEP East companies sought to increase retail rates in most of their states to recover lost T&O and SECA revenues. The status of such state retail rate proceedings is as follows:

·
In Kentucky, KPCo settled a rate case, which provided for the recovery of its share of the transmission revenue reduction in new rates effective March 30, 2006.
·
In Ohio, CSPCo and OPCo recover their FERC-approved OATT that reflects their share of the full transmission revenue requirement retroactive to April 1, 2006 under a May 2006 PUCO order.
·
In West Virginia, APCo settled a rate case, which provided for the recovery of its share of the T&O/SECA transmission revenue reduction beginning July 28, 2006.
·
In Virginia, APCo filed a request for revised rates, which includes recovery of its share of the T&O/SECA transmission revenue reduction starting October 2, 2006, subject to refund.
·
In Indiana, I&M is precluded by a rate cap from raising its rates until July 1, 2007.
·
In Michigan, I&M has not filed to seek recovery of the lost transmission revenues.

In April 2007, the FERC issued an order reversing the ALJ decision. The FERC ruled that the current PJM rate design is just and reasonable. The FERC further ruled that the cost of new facilities of 500 kV and above would be shared among all PJM participants. As a result of this order, the AEP East companies retail customers will be asked to bear the full cost of the existing AEP east transmission zone facilities. However, the AEP East companies customers will also be charged a share of the cost of new 500 kV and higher voltage transmission facilities built in PJM, of which the vast majority for the foreseeable future will not be needed by their customers, but will bolster service and reduce costs in other zones of PJM. The AEP East companies will need to obtain regulatory approvals for recovery of any costs of new facilities that are assigned to them as a result of this order, if upheld. AEP will request rehearing of this order. Management cannot estimate at this time what effect, if any, this order will have on their future construction of new east transmission facilities, results of operations, cash flows and financial condition.

The AEP East companies presently recover from retail customers approximately 85% of the reduction in transmission revenues of $128 million a year. Future results of operations, cash flows and financial condition will continue to be adversely affected in Indiana and Michigan until these lost transmission revenues are recovered in retail rates.

SECA Revenue Subject to Refund

The AEP East companies ceased collecting through-and-out transmission service (T&O) revenues in accordance with FERC orders, and collected 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. As a result, the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund or surcharge. The AEP East companies paid SECA rates to other utilities at considerably lesser amounts than collected. If a refund is ordered, the AEP East companies would also receive refunds related to the SECA rates they paid to third parties. The AEP East companies recognized gross SECA revenues as follows:

   
Year Ended December 31,
 
   
2006 (a)
 
2005
 
2004
 
Company
 
(in millions)
 
APCo
 
$
13.4
 
$
52.4
 
$
4.4
 
CSPCo
   
7.9
   
28.4
   
2.5
 
I&M
   
8.1
   
30.4
   
2.8
 
KPCo
   
3.2
   
12.4
   
1.0
 
OPCo
   
10.4
   
39.4
   
3.5
 

(a)
Represents revenues through March 31, 2006, when SECA rates expired, and excludes all provisions for refund.

Approximately $19 million of these recorded SECA revenues billed by PJM were never collected. The AEP East companies filed a motion with the FERC to force payment of these uncollected SECA billings.

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. The ALJ also found that the unpaid SECA rates must be paid in the recommended reduced amount.

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 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.

The AEP East companies provided for net refunds as shown in the following table:

   
Year Ended December 31,
 
   
2006
 
2005
 
Company
 
(in millions)
 
APCo
 
$
11.0
 
$
1.0
 
CSPCo
   
6.1
   
0.6
 
I&M
   
6.4
   
0.6
 
KPCo
   
2.6
   
0.2
 
OPCo
   
8.3
   
0.8
 

In September 2006, AEP, together with Exelon and DP&L, 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.

         4. COMMITMENTS, GUARANTEES AND CONTINGENCIES

The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation cannot be predicted. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2006 Annual Report should be read in conjunction with this report.

GUARANTEES

There are certain immaterial liabilities recorded for guarantees in accordance with FASB Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letters of Credit

Certain Registrant Subsidiaries enter into standby letters of credit (LOCs) with third parties. These LOCs cover items such as insurance programs, security deposits, debt service reserves and credit enhancements for issued bonds. All of these LOCs were issued in the subsidiaries’ ordinary course of business. At March 31, 2007, the maximum future payments of the LOCs include $1 million and $4 million for I&M and SWEPCo, respectively, with maturities ranging from June 2007 to March 2008.

Guarantees of Third-Party Obligations

SWEPCo

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation in the amount of approximately $85 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), an entity consolidated under FIN 46. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study, it is estimated the reserves will be depleted in 2029 with final reclamation completed by 2036, at an estimated cost of approximately $39 million. As of March 31, 2007, SWEPCo collected approximately $30 million through a rider for final mine closure costs, which is recorded in Deferred Credits and Other on SWEPCo’s Condensed Consolidated Balance Sheets.

Sabine charges SWEPCo, its only customer, all its costs. SWEPCo passes these costs through its fuel clause.

Indemnifications and Other Guarantees

Contracts

All of the Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. Prior to March 31, 2007, Registrant Subsidiaries entered into sale agreements including indemnifications with a maximum exposure that was not significant for any individual Registrant Subsidiary except TCC. TCC sale agreements include indemnifications with a maximum exposure of $456 million related to the sale price of its generation assets. See “Texas Plants - South Texas Project”, “Texas Plants - TCC Generation Assets” and “Texas Plants - Oklaunion Power Station” sections of Note 8 of the 2006 Annual Report. There are no material liabilities recorded for any indemnifications.

AEP East companies, PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP East companies, PSO and SWEPCo related to power purchase and sale activity conducted pursuant to the SIA.

Master Operating Lease

Certain Registrant Subsidiaries lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed to receive up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, the subsidiary has committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. At March 31, 2007, the maximum potential loss by subsidiary for these lease agreements assuming the fair market value of the equipment is zero at the end of the lease term is as follows:
 
   
Maximum Potential Loss
 
Company
 
(in millions)
 
APCo
 
$
7
 
CSPCo
   
4
 
I&M
   
5
 
KPCo
   
2
 
OPCo
   
7
 
PSO
   
5
 
SWEPCo
   
6
 
TCC
   
6
 
TNC
   
3
 

CONTINGENCIES

Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo, I&M, and OPCo

The Federal EPA, certain special interest groups and a number of states allege 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. The Federal EPA filed its complaints against AEP subsidiaries in U.S. District Court for the Southern District of Ohio. The alleged modifications occurred at our generating units over a twenty-year period. A bench trial on the liability issues was held during July 2005. 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 results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components or other repairs needed for the reliable, safe and efficient operation of the plant. The CAA authorizes civil penalties of up to $27,500 ($32,500 after March 15, 2004) per day per violation at each generating unit. In 2001, the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief.

The Federal EPA and eight northeastern states each filed an additional complaint containing additional allegations against the Amos and Conesville plants. APCo and CSPCo filed an answer to the northeastern states’ complaint and the Federal EPA’s complaint, denying the allegations and stating their defenses. Cases are also pending that could affect CSPCo’s share of jointly-owned units at Beckjord (12.5% owned), Zimmer (25.4% owned), and Stuart (26% owned) Stations. Similar cases have been filed against other nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk. Several of these cases were resolved through consent decrees.

Courts have reached different conclusions regarding whether the activities at issue in these cases are routine maintenance, repair, or replacement, and therefore are excluded from NSR. Similarly, courts have reached different results regarding whether the activities at issue increased emissions from the power plants. 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 most of the challenged activities would be excluded 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.

Management is unable to estimate the loss or range of loss related to any contingent liability, if any, AEP subsidiaries might have for civil penalties under the CAA proceedings. Management is also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. If AEP subsidiaries do not prevail, management believes AEP subsidiaries 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 any of the AEP subsidiaries 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.

Notice of Enforcement and Notice of Citizen Suit - Affecting SWEPCo

In March 2005, two special interest groups, Sierra Club and Public Citizen, filed a complaint in Federal District Court for the Eastern District of Texas alleging violations of the CAA at SWEPCo’s Welsh Plant. SWEPCo filed a response to the complaint in May 2005. A trial in this matter is scheduled for the second quarter of 2007.

In 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary of findings resulting from a compliance investigation at the plant. In April 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of approximately $228 thousand against SWEPCo based on alleged violations of certain representations regarding heat input in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements. SWEPCo responded to the preliminary report and petition in May 2005. The enforcement order contains a recommendation that would limit the heat input on each Welsh unit to the referenced heat input contained within the permit application within 10 days of the issuance of a final TCEQ order and until a permit amendment is issued. SWEPCo had previously requested a permit alteration to remove the reference to a specific heat input value for each Welsh unit and to clarify the sulfur content requirement for fuels consumed at the plant. A permit alteration was issued in March 2007 removing the heat input references from the Welsh permit and clarifying the sulfur content of fuels burned at the plant is limited to 0.5% on an as-received basis. The Sierra Club and Public Citizen filed a motion to overturn the permit alteration.

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

Carbon Dioxide (CO2) Public Nuisance Claims - Affecting AEP East Companies and AEP West Companies

In 2004, eight states and the City of New York filed an action in federal district court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority. The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants. The actions allege that CO2 emissions from the defendant’s power plants constitute a public nuisance under federal common law due to impacts of global warming, and sought injunctive relief in the form of specific emission reduction commitments from the defendants. The defendants’ motion to dismiss the lawsuits was granted in September 2005. The dismissal was appealed to the Second Circuit Court of Appeals. Briefing and oral argument have concluded. On April 2, 2007, the U.S. Supreme Court issued a decision holding that the Federal EPA has authority to regulate emissions of CO2 and other greenhouse gases under the CAA, which may impact the Second Circuit’s analysis of these issues. Management believes the actions are without merit and intends to defend against the claims.

TEM Litigation - Affecting OPCo

OPCo agreed to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) (now known as SUEZ Energy Marketing NA, Inc.) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA). Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming.

In September 2003, TEM and OPCo separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. OPCo alleged that TEM breached the PPA, and sought a determination of its rights under the PPA. TEM alleged that the PPA never became enforceable, or alternatively, that the PPA was terminated as the result of OPCo’s breaches. The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) provided a limited guaranty.

In August 2005, a federal judge ruled that TEM had breached the contract and awarded damages to OPCo of $123 million plus prejudgment interest. Any eventual proceeds will be recorded as a gain when received.

In September 2005, TEM posted a $142 million letter of credit as security pending appeal of the judgment. Both parties filed Notices of Appeal with the United States Court of Appeals for the Second Circuit, which heard oral argument on the appeals in December 2006. Management cannot predict the ultimate outcome of this proceeding.

Coal Transportation Dispute - Affecting PSO, TCC and TNC

PSO, TCC, TNC, the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsville, Texas, as joint owners of a generating station, disputed transportation costs for coal received between July 2000 and the present time. The joint plant remitted less than the amount billed and the dispute is pending before the Surface Transportation Board. Based upon a weighted average probability analysis of possible outcomes, PSO, as operator of the plant, recorded provisions for possible loss in 2004, 2005, 2006 and the first quarter of 2007. The provision was deferred as a regulatory asset under PSO’s fuel mechanism and immaterially affected income for TCC and TNC for their respective ownership shares. Management continues to work toward mitigating the disputed amounts to the extent possible.

Coal Transportation Rate Dispute - Affecting PSO

In 1985, the Burlington Northern Railroad Co. (now BNSF) entered into a coal transportation agreement with PSO. The agreement contained a base rate subject to adjustment, a rate floor, a reopener provision and an arbitration provision. In 1992, PSO reopened the pricing provision. The parties failed to reach an agreement and the matter was arbitrated, with the arbitration panel establishing a lowered rate as of July 1, 1992 (the 1992 Rate), and modifying the rate adjustment formula. The decision did not mention the rate floor. From April 1996 through the contract termination in December 2001, the 1992 Rate exceeded the adjusted rate, determined according to the decision. PSO paid the adjusted rate and contended that the panel eliminated the rate floor. BNSF invoiced at the 1992 Rate and contended that the 1992 Rate was the new rate floor. At the end of 1991, PSO terminated the contract by paying a termination fee, as required by the agreement. BNSF contends that the termination fee should have been calculated on the 1992 Rate, not the adjusted rate, resulting in an underpayment of approximately $9.5 million, including interest.

This matter was submitted to an arbitration board. In April 2006, the arbitration board filed its decision, denying BNSF’s underpayments claim. PSO filed a request for an order confirming the arbitration award and a request for entry of judgment on the award with the U.S. District Court for the Northern District of Oklahoma. On July 14, 2006, the U.S. District Court issued an order confirming the arbitration award. On July 24, 2006, BNSF filed a Motion to Reconsider the July 14, 2006 Arbitration Confirmation Order and Final Judgment and its Motion to Vacate and Correct the Arbitration Award with the U.S. District Court. In February 2007, the U.S. District Court granted BNSF’s Motion to Reconsider. PSO filed a substantive response to BNSF’s motion and BNSF filed a reply. Management continues to work toward mitigating the disputed amounts to the extent possible.
 
Claims by the City of Brownsville, Texas Against TCC - Affecting TCC

On April 27, 2007, the City of Brownsville, Texas served its Fifth Amended Answer and Cross-Claims in litigation pending in the District Court of Dallas County, Texas. The cross-claims seek recovery against TCC based on allegations of breach of contract, breach of fiduciary duty, unjust enrichment, constructive trust, conversion, breach of the Texas theft liability act and fraud allegedly occurring in connection with a transaction in which Brownsville purchased TCC’s interest in the Oklaunion electric generating station. Management believes that the claims are without merit and intends to defend against them vigorously.

FERC Long-term Contracts - Affecting AEP East Companies and AEP West Companies

In 2002, the FERC held a hearing related to a complaint filed by Nevada Power Company and Sierra Pacific Power Company (the Nevada utilities). The complaint sought to break long-term contracts entered during the 2000 and 2001 California energy price spike which the customers alleged were “high-priced.” The complaint alleged that AEP subsidiaries sold power at unjust and unreasonable prices. In December 2002, a FERC ALJ ruled in AEP’s favor and dismissed the complaint filed by the Nevada utilities. In 2001, the Nevada utilities filed complaints asserting that the prices for power supplied under those contracts should be lowered because the market for power was allegedly dysfunctional at the time such contracts were executed. The ALJ rejected the complaint, held that the markets for future delivery were not dysfunctional, and that the Nevada utilities failed to demonstrate that the public interest required that changes be made to the contracts. In June 2003, the FERC issued an order affirming the ALJ’s decision. In December 2006, the U.S. Court of Appeals for the Ninth Circuit reversed the FERC order and remanded the case to the FERC for further proceedings. Management is unable to predict the outcome of these proceedings or their impact on future results of operations and cash flows. We have asserted claims against certain companies that sold power to us, which we resold to the Nevada utilities, seeking to recover a portion of any amounts we may owe to the Nevada utilities.

         5. ACQUISITIONS, DISPOSITIONS AND ASSETS HELD FOR SALE

ACQUISITIONS

2007

Darby Electric Generating Station - Affecting CSPCo

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 and the assumption of liabilities of approximately $2 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.

Lawrenceburg Generating Station - Affecting AEGCo

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. AEGCo will complete the purchase 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.

2006

None

DISPOSITIONS

2007

Texas Plants - Oklaunion Power Station - Affecting TCC

In February 2007, TCC sold its 7.81% share of Oklaunion Power Station to the Public Utilities Board of the City of Brownsville for $42.8 million plus adjustments. The sale did not have a significant effect on TCC’s results of operations. See "Claims by the City of Brownsville, Texas Against TCC" section of Note 4.
 
2006

None

ASSETS HELD FOR SALE

Texas Plants - Oklaunion Power Station - Affecting TCC

In February 2007, TCC sold its 7.81% share of Oklaunion Power Station to the Public Utilities Board of the City of Brownsville. The sale did not have a significant effect on TCC’s results of operations nor does TCC expect any remaining litigation to have a significant effect on its results of operations.

TCC’s assets related to the Oklaunion Power Station were classified in Assets Held for Sale - Texas Generation Plant on TCC’s Condensed Consolidated Balance Sheet at December 31, 2006. The plant does not meet the “component-of-an-entity” criteria because it does not have cash flows that can be clearly distinguished operationally. The plant also does not meet the “component-of-an-entity” criteria for financial reporting purposes because it does not operate individually, but rather as a part of the AEP System, which includes all of the generation facilities owned by the Registrant Subsidiaries except TNC.

The Assets Held for Sale were as follows:

   
March 31,
 
December 31,
 
   
2007
 
2006
 
Texas Plants (TCC)
 
(in millions)
 
Assets:
           
Other Current Assets
 
$
-
 
$
1
 
Property, Plant and Equipment, Net
   
-
   
43
 
Total Assets Held for Sale - Texas Generation Plant
 
$
-
 
$
44
 

         6. BENEFIT PLANS

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in AEP sponsored qualified pension plans and nonqualified pension plans. A substantial majority of employees are covered by either one qualified plan or both a qualified and a nonqualified pension plan. In addition, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in other postretirement benefit plans sponsored by AEP to provide medical and death benefits for retired employees.

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC adopted SFAS 158 as of December 31, 2006. They recorded a SFAS 71 regulatory asset for their qualifying SFAS 158 costs of regulated operations that for ratemaking purposes will be deferred for future recovery.

Components of Net Periodic Benefit Cost

The following table provides the components of AEP’s net periodic benefit cost for the plans for the three months ended March 31, 2007 and 2006:
 
       
Other
 
       
Postretirement
 
   
Pension Plans
 
Benefit Plans
 
   
2007
 
2006
 
2007
 
2006
 
   
(in millions)
 
Service Cost
 
$
24
 
$
24
 
$
10
 
$
10
 
Interest Cost
   
59
   
57
   
26
   
25
 
Expected Return on Plan Assets
   
(85
)
 
(83
)
 
(26
)
 
(23
)
Amortization of Transition Obligation
   
-
   
-
   
7
   
7
 
Amortization of Net Actuarial Loss
   
15
   
20
   
3
   
5
 
Net Periodic Benefit Cost
 
$
13
 
$
18
 
$
20
 
$
24
 

The following table provides the net periodic benefit cost (credit) for the plans by Registrant Subsidiary for the three months ended March 31, 2007 and 2006:
 
   
Pension Plans
 
Other Postretirement
Benefit Plans
 
   
2007
 
2006
 
2007
 
2006
 
Company
 
(in thousands)
 
APCo
 
$
842
 
$
1,468
 
$
3,560
 
$
4,489
 
CSPCo
   
(257
)
 
205
   
1,491
   
1,805
 
I&M
   
1,900
   
2,331
   
2,530
   
2,953
 
KPCo
   
255
   
358
   
426
   
513
 
OPCo
   
245
   
826
   
2,802
   
3,396
 
PSO
   
424
   
977
   
1,431
   
1,588
 
SWEPCo
   
746
   
1,225
   
1,419
   
1,578
 
TCC
   
101
   
773
   
1,575
   
1,696
 
TNC
   
70
   
325
   
631
   
715
 

         7. BUSINESS SEGMENTS

All of AEP’s Registrant Subsidiaries have one reportable segment. The one reportable segment is an integrated electricity generation, transmission and distribution business except AEGCo, which is an electricity generation business, and TCC and TNC, which are transmission and distribution businesses. All of the Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.

         8. INCOME TAXES

We join in the filing of a consolidated federal income tax return with our subsidiaries in the American Electric Power (AEP) System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current expense. The tax benefit of the parent is allocated to our subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidated group.

Audit Status

AEP System companies also file income tax returns in various state, local, and foreign jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2000. The IRS and other taxing authorities routinely examine our tax returns. We believe that we have filed tax returns with positions that may be challenged by these tax authorities. We are currently under exam in several state and local jurisdictions. However, management does not believe that the ultimate resolution of these audits will materially impact results of operations.

We have settled with the IRS all issues from the audits of our consolidated federal income tax returns for years prior to 1997. We have effectively settled all outstanding proposed IRS adjustments for years 1997 through 1999 and through June 2000 for the CSW pre-merger tax period and anticipate payment for the agreed adjustments to occur during 2007. Returns for the years 2000 through 2003 are presently being audited by the IRS and we anticipate that the audit will be completed by the end of 2007.

The IRS has proposed certain significant adjustments to AEP’s foreign tax credit and interest allocation positions. Management is currently evaluating those proposed adjustments to determine if it agrees, but if accepted, we do not anticipate the adjustments would result in a material change to our financial position.

FIN 48 Adoption

We adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, the approximate increase (decrease) in the liabilities for unrecognized tax benefits, as well as related interest expense and penalties, which was accounted for as a reduction to the January 1, 2007 balance of retained earnings was recognized by each Registrant Subsidiary as follows:

Company
 
(in thousands)
 
AEGCo
 
$
(27
)
APCo
   
2,685
 
CSPCo
   
3,022
 
I&M
   
(327
)
KPCo
   
786
 
OPCo
   
5,380
 
PSO
   
386
 
SWEPCo
   
1,642
 
TCC
   
2,187
 
TNC
   
557
 

At January 1, 2007, the total amount of unrecognized tax benefits under FIN 48 for each Registrant Subsidiary was as follows:
 
Company
 
(in millions)
 
AEGCo
 
$
0.1
 
APCo
   
21.7
 
CSPCo
   
25.0
 
I&M
   
18.2
 
KPCo
   
3.4
 
OPCo
   
49.8
 
PSO
   
8.9
 
SWEPCo
   
7.1
 
TCC
   
20.7
 
TNC
   
6.9
 

We believe it is reasonably possible that there will be a net decrease in unrecognized tax benefits due to the settlement of audits and the expiration of statute of limitations within 12 months of the reporting date for each Registrant Subsidiary as follows:
 
Company
 
(in millions)
 
AEGCo
 
$
0.5
 
APCo
   
5.5
 
CSPCo
   
9.3
 
I&M
   
6.0
 
KPCo
   
1.4
 
OPCo
   
9.0
 
PSO
   
4.4
 
SWEPCo
   
2.8
 
TCC
   
3.4
 
TNC
   
1.6
 

At January 1, 2007, the total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for each Registrant Subsidiary was as follows:

Company
 
(in millions)
 
APCo
 
$
5.4
 
CSPCo
   
13.8
 
I&M
   
5.4
 
KPCo
   
0.6
 
OPCo
   
23.4
 
PSO
   
1.2
 
SWEPCo
   
1.2
 
TCC
   
9.3
 
TNC
   
2.6
 

At January 1, 2007, tax positions for each Registrant Subsidiary, for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility was as follows:

Company
 
(in millions)
 
AEGCo
 
$
0.1
 
APCo
   
13.7
 
CSPCo
   
3.9
 
I&M
   
10.3
 
KPCo
   
2.5
 
OPCo
   
14.2
 
PSO
   
7.1
 
SWEPCo
   
5.1
 
TCC
   
6.4
 
TNC
   
2.9
 

Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

Prior to the adoption of FIN 48, we recorded interest and penalty accruals related to income tax positions in tax accrual accounts. With the adoption of FIN 48, we began recognizing interest accruals related to income tax positions in interest income or expense as applicable, and penalties in operating expenses. As of January 1, 2007, each Registrant Subsidiary accrued for the payment of uncertain interest and penalties as follows:

Company
 
(in millions)
 
AEGCo
 
$
0.1
 
APCo
   
4.6
 
CSPCo
   
1.7
 
I&M
   
2.8
 
KPCo
   
1.2
 
OPCo
   
4.3
 
PSO
   
2.7
 
SWEPCo
   
2.0
 
TCC
   
2.5
 
TNC
   
1.0
 

9. FINANCING ACTIVITIES

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first three months of 2007 were:

Company
 
Type of Debt
 
Principal Amount
 
Interest Rate
 
Due Date
       
(in thousands)
 
(%)
   
Issuances:
                 
SWEPCo
 
Senior Unsecured Notes
 
$
250,000
 
5.55
 
2017


Company
 
Type of Debt
 
Principal Amount
 
Interest Rate
 
Due Date
       
(in thousands)
 
(%)
   
Retirements and 
   Principal Payments:
                 
OPCo
 
Notes Payable
 
$
1,463
 
6.81
 
2008
OPCo
 
Notes Payable
   
6,000
 
6.27
 
2009
SWEPCo
 
Notes Payable
   
1,645
 
4.47
 
2011
SWEPCo
 
Notes Payable
   
4,000
 
6.36
 
2007
SWEPCo
 
Notes Payable
   
750
 
Variable
 
2008
TCC
 
Securitization Bonds
   
32,125
 
5.01
 
2008

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.

Lines of Credit and Short-term Debt - AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of its 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. The AEP System corporate borrowing program operates in accordance with the terms and conditions approved in a regulatory order. The amount of outstanding loans (borrowings) to/from the Utility Money Pool as of March 31, 2007 and December 31, 2006 are included in Advances to/from Affiliates on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the three months ended March 31, 2007 are described in the following table:

   
Maximum Borrowings
from Utility
Money Pool
 
Maximum
Loans to Utility Money Pool
 
Average
Borrowings from Utility Money Pool
 
Average Loans to Utility Money Pool
 
Loans (Borrowings) to/from Utility Money Pool as of March 31, 2007
 
Authorized
Short-Term Borrowing Limit
 
Company
 
(in thousands)
 
AEGCo
 
$
75,425
 
$
-
 
$
44,340
 
$
-
 
$
(29,997
)
$
125,000
(a)
APCo
   
109,259
   
-
   
71,378
   
-
   
(82,860
)
 
600,000
 
CSPCo
   
15,693
   
35,270
   
6,204
   
14,543
   
922
   
350,000
 
I&M
   
100,374
   
-
   
66,570
   
-
   
(45,759
)
 
500,000
 
KPCo
   
46,317
   
-
   
30,845
   
-
   
(20,769
)
 
200,000
 
OPCo
   
444,153
   
-
   
333,467
   
-
   
(397,127
)
 
600,000
 
PSO
   
135,694
   
-
   
76,776
   
-
   
(135,694
)
 
300,000
 
SWEPCo
   
240,786
   
48,979
   
215,207
   
30,267
   
8,959
   
350,000
 
TCC
   
-
   
394,180
   
-
   
295,542
   
216,953
   
600,000
 
TNC (b)
   
35,191
   
3,200
   
22,179
   
2,365
   
(24,487
)
 
250,000
 

(a)
In April 2007, limit increased by $285 million under regulatory orders.
(b)
Does not include short-term lending activity of TNC’s wholly-owned subsidiary, AEP Texas North Generation Company LLC (TNGC), who is a participant in the Nonutility Money Pool. As of March 31, 2007, TNGC had $13.3 million in outstanding loans to the Nonutility Money Pool.

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:
 
   
Three Months Ended March 31,
 
   
2007
 
2006
 
Maximum Interest Rate
   
5.43
%
 
4.85
%
Minimum Interest Rate
   
5.30
%
 
4.37
%

The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the three months ended March 31, 2007 and 2006 are summarized for all Registrant Subsidiaries in the following table:

   
Average Interest Rate for Funds
Borrowed from the Utility Money
Pool for
Three Months Ended March 31,
 
 Average Interest Rate for Funds
Loaned to the Utility Money
Pool for
Three Months Ended March 31,
 
   
2007
 
2006
 
 2007
 
2006
 
Company
 
(in percentage)
 
AEGCo
   
5.34
   
4.57
   
-
   
-
 
APCo
   
5.34
   
4.60
   
-
   
-
 
CSPCo
   
5.35
   
4.58
   
5.33
   
4.66
 
I&M
   
5.34
   
4.59
   
-
   
-
 
KPCo
   
5.34
   
4.54
   
-
   
4.75
 
OPCo
   
5.34
   
4.60
   
-
   
-
 
PSO
   
5.34
   
4.63
   
-
   
-
 
SWEPCo
   
5.35
   
4.60
   
5.34
   
-
 
TCC
   
-
   
4.47
   
5.34
   
4.68
 
TNC (a)
   
5.34
   
4.57
   
5.34
   
4.54
 

(a)
Does not include short-term lending activity for TNGC, who is a participant in the Nonutility Money Pool. For the three months ended March 31, 2007, the average interest rate for funds loaned to the Nonutility Money Pool by TNGC was 5.31%.


The Registrant Subsidiaries’ outstanding short-term debt was as follows:

       
March 31, 2007
   
December 31, 2006
 
   
Type of Debt
 
Outstanding
Amount
 
Interest
Rate
   
Outstanding
Amount
 
Interest
Rate
 
Company
     
(in millions)
         
(in millions)
       
OPCo
 
Commercial Paper - JMG
 
$
5
   
5.56
%
 
$
1
   
5.56
%
SWEPCo
 
Line of Credit - Sabine
   
20
   
6.52
%
   
17
   
6.38
%









COMBINED MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the registrants’ management’s discussion and analysis. The information in this section completes the information necessary for management’s discussion and analysis of financial condition and results of operations and is meant to be read with (i) Management’s Financial Discussion and Analysis, (ii) financial statements and (iii) footnotes of each individual registrant. The combined Management’s Discussion and Analysis of Registrant Subsidiaries section of the 2006 Annual Report should also be read in conjunction with this report.

Significant Factors

Ohio 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.

SECA Revenue Subject to Refund

The AEP East Companies 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.

Environmental Matters

The Registrant Subsidiaries 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 power plants.

In addition, the Registrant Subsidiaries 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 I&M’s nuclear units. Management also monitors possible future requirements to reduce carbon dioxide (CO2) emissions to address concerns about global climate change.

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 the Registrant Subsidiaries’ 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 have 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.

Management is unable to estimate the loss or range of loss related to any contingent liability, if any, the Registrant Subsidiaries might have for civil penalties under the CAA proceedings. Management is 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 the Registrant Subsidiaries do not prevail, management believes the Registrant Subsidiaries 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 the Registrant Subsidiaries 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.

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. The Registrant Subsidiaries adopted FIN 48 effective January 1, 2007. See “FIN 48 “Accounting for Uncertainty in Income Taxes”” section of Note 2 and see Note 8 - Income Taxes. The impact of this interpretation was an unfavorable (favorable) adjustment to retained earnings as follows:

Company
 
(in thousands)
 
AEGCo
 
$
(27
)
APCo
   
2,685
 
CSPCo
   
3,022
 
I&M
   
(327
)
KPCo
   
786
 
OPCo
   
5,380
 
PSO
   
386
 
SWEPCo
   
1,642
 
TCC
   
2,187
 
TNC
   
557
 









CONTROLS AND PROCEDURES

During the first quarter of 2007, management, including the principal executive officer and principal financial officer of each of AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC (collectively, the Registrants), evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

As of March 31, 2007 these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.

The only change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the first quarter 2007 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal controls over financial reporting, relates to the Southwest Power Pool’s (SPP) implementation of an Energy Imbalance Service Market. In connection with this market implementation, two of AEP’s subsidiaries (Public Service Company of Oklahoma and Southwestern Electric Power Company) implemented or modified a number of business processes and controls to facilitate participation in, and resultant settlement within, the SPP Energy Imbalance Service Market.






PART II. OTHER INFORMATION

Item 1.    Legal Proceedings

For a discussion of material legal proceedings, see Note 4, Commitments, Guarantees and Contingencies, incorporated herein by reference.

Item 1A. Risk Factors

Our Annual Report on Form 10-K for the year ended December 31, 2006 includes a detailed discussion of our risk factors. The information presented below amends and restates in their entirety certain of those risk factors that have been updated and should be read in conjunction with the risk factors and information disclosed in our 2006 Annual Report on Form 10-K.

General Risks of Our Regulated Operations

Our request for rate recovery of additional costs may not be approved in Virginia. (Applies to AEP and APCo.)

APCo filed a request with the Virginia SCC in May 2006 seeking a net increase in base rates of $198 million to recover increasing costs, including a return on equity of 11.5%. APCo also requested to apply its off-system sales margins (currently credited to customers through base rates) to the fuel factor where they can be adjusted annually. APCo also requested to retain a portion of the off-system sales margins. In May 2006, the Virginia SCC issued an order placing the net requested base rate increase into effect as of October 2, 2006, subject to refund. In October 2006, the Virginia SCC staff filed direct testimony recommending a base rate increase of $13 million with a return on equity of 9.9% and no off-system sales margin sharing. Other intervenors have recommended base rate increases ranging from $42 million to $112 million. APCo has filed rebuttal testimony and hearings were held in December 2006. In March 2007, the Hearing Examiner released a report recommending a base rate increase of $31 million with a return on equity of 10.1% and a 5% retention of off-system sales margin sharing. If the Virginia SCC denies the requested rate recovery, it could adversely impact future results of operations, cash flows and financial condition.

Our request for rate recovery of additional costs may not be approved in Texas. (Applies to AEP, TCC and TNC.)

TCC and TNC have filed requests with the PUCT to increase their transmission and distribution rates. The rate requests include the amounts charged for the delivery of electricity over TCC´s and TNC´s transmission and distribution lines. TCC is seeking approval of an $81 million increase, which includes the expiration of $20 million in billing credits that the PUCT required in approving the merger of CSW into AEP. The credits have been in place since 2000. TNC is seeking approval of a $25 million increase, which includes the expiration of $6 million in billing credits. TCC and TNC are requesting a return on equity of 11.25% with a capital structure of approximately 60% debt/40% equity. As part of rebuttal testimony filed in April 2007, TCC and TNC reduced their base rate request by $11 million and $3 million, respectively, and reduced their return on equity by 0.5%. If the PUCT denies the requested rate recovery, it could adversely impact future results of operations, cash flows and financial condition.

Our request for rate recovery of additional costs may not be approved in Oklahoma. (Applies to AEP and PSO.)

PSO filed a request with the OCC in November 2006 seeking approval of a $50 million overall increase in base rates, an annually adjusted rate mechanism to recover the expected significant investment PSO will be making in new facilities, several new and restructured tariffs to allow PSO to begin to reduce the relationship between its revenues and its sales volumes, and to implement some demand side management tariffs. PSO´s planned investments over the next five years include new generation facilities ($1.12 billion), new and refurbished transmission substations and lines ($302 million) and new distribution lines and equipment ($582 million). In April 2007, PSO filed rebuttal testimony regarding various issues raised by the OCC Staff and the intervenors. As part of rebuttal testimony, PSO reduced its base rate request by $2 million. If the OCC denies the requested rate recovery, it could adversely impact future results of operations, cash flows and financial condition.

The amount we charged third parties for using our transmission facilities has been reduced, is subject to refund and may not be completely restored in the future. (Applies to AEP and the AEP East companies.)

In July 2003, the FERC issued an order directing PJM and MISO to make compliance filings for their respective tariffs to eliminate the transaction-based charges for through and out (T&O) transmission service on transactions where the energy is delivered within those RTOs. The elimination of the T&O rates reduces the transmission service revenues collected by the RTOs and thereby reduces the revenues received by transmission owners under the RTOs’ revenue distribution protocols. To mitigate the impact of lost T&O revenues, the FERC approved temporary replacement seams elimination cost allocation (SECA) transition rates beginning in December 2004 and extending through March 2006. Intervenors objected to this decision; therefore the SECA fees we collected ($220 million) are subject to refund. Approximately $19 million of the SECA revenues that we billed were never collected. AEP filed a motion with the FERC to force payment of these SECA billings.

A hearing was held in May 2006 to determine whether any of the SECA revenues should be refunded. 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. The ALJ also found that unpaid SECA rates must be paid in the recommended reduced amount. The FERC has not ruled on the matter. If the FERC upholds the decision of the ALJ, up to $126 million of collected SECA rates could be refunded by the AEP East companies. We have recorded provisions in the aggregate amount of $37 million related to the potential refund of SECA rates pending settlement negotiations with various intervenors.

SECA transition rates expired on March 31, 2006 and did not fully compensate AEP East companies for ongoing lost T&O revenues. As a result of rate relief in certain jurisdictions, however, approximately 85% of the ongoing lost T&O revenues are now being recovered from native load customers of AEP East companies in those jurisdictions. The portion attributable to Virginia is being collected subject to refund. 

In addition to seeking retail rate recovery from native load customers in the applicable states, AEP and another member of PJM have filed an application with the FERC seeking compensation from other unaffiliated members of PJM for the costs associated with those members’ use of the filers’ the AEP East companies respective transmission assets. A majority of PJM members have filed in opposition to the proposal. Hearings were held in April 2006. An ALJ recommended a rate design that would result in greater recovery for AEP than the proposal AEP had submitted. The ALJ also recommended, however, that the design be phased-in, which could limit the amount of recovery for AEP. In April 2007, the FERC issued an order reversing the ALJ decision. The FERC ruled that the current PJM rate design is just and reasonable. The FERC further ruled that the cost of new facilities of 500 kV and above would be shared among all PJM participants. Management cannot estimate at this time what affect, if any, this order will have on our future construction of new east transmission facilities, results of operations, cash flows and financial condition.

We are exposed to losses resulting from the bankruptcy of Enron Corp. (Applies to AEP.)

On June 1, 2001, we purchased HPL from Enron Corp. (Enron). Later that year, Enron and its subsidiaries filed bankruptcy proceedings in the U.S. Bankruptcy Court for the Southern District of New York. Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy. In connection with the 2001 acquisition of HPL, we entered into an agreement with BAM Lease Company, which granted HPL the exclusive right to use approximately 65 BCF of cushion gas required for the normal operation of the Bammel gas storage facility. At the time of our acquisition of HPL, Bank of America (BOA) and certain other banks (together with BOA, BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of 65 BCF of cushion gas. Additionally, Enron and the BOA Syndicate released HPL from all prior and future liabilities and obligations in connection with the financing arrangement. After the Enron bankruptcy, HPL was informed by the BOA Syndicate of a purported default by Enron under the terms of the financing arrangement. We purchased 10 BCF of gas from Enron and are currently litigating the rights to the remaining 55 BCF of cushion gas.

In February 2004, in connection with BOA’s dispute, Enron filed Notices of Rejection regarding the cushion gas use agreement and other incidental agreements. We have objected to Enron’s attempted rejection of these agreements. In 2005, we sold HPL, including the Bammel gas storage facility. We indemnified the purchaser for damages, if any, arising from the litigation with BOA. Management is unable to predict the final resolution of these disputes, however the impact on results of operations, cash flows and financial condition could be material.

Risks Relating To State Restructuring

In Ohio, our costs may not be recovered and rates may be reduced. (Applies to AEP, OPCo and CSPCo.)

In January 2005, the PUCO approved RSPs for CSPCo and OPCo. The RSPs provide, among other things, for CSPCo and OPCo to raise their generation rates on an annual basis through 2008 by 3% and 7%, respectively. The RSPs also provide for possible additional annual generation rate increases of up to an average of 4% per year for specified costs. The RSPs also provide that CSPCo and OPCo can recover certain environmental carrying costs, PJM-related administrative costs and certain congestion costs. In 2006, CSPCo and OPCo collected an additional estimated $244 million in gross margin as a result of the RSPs. This amount is expected to increase in 2007 and 2008.

In 2005, the Ohio Consumers’ Counsel filed an appeal to the Ohio Supreme Court that challenged the validity of the RSPs under Ohio’s electricity restructuring law. In July 2006, the Ohio Supreme Court vacated the PUCO’s RSP orders for CSPCo and OPCo and remanded the case to the PUCO for further proceedings.

In August 2006, the PUCO directed CSPCo and OPCo to file a plan providing an option for customer participation in the electric market through competitive bids or other reasonable means. The PUCO also held that the RSPs shall remain effective. Accordingly, CSPCo and OPCo continued collecting RSP revenues. In September 2006, CSPCo and OPCo submitted their proposals to provide additional options for customer participation in the electric market.

In March 2007, CSPCo and OPCo filed a settlement agreement at the PUCO resolving the Ohio Supreme Court's remand of the PUCO’s RSP order. Management expects the PUCO will approve this settlement agreement.

Some laws and regulations governing restructuring in Virginia have not yet been interpreted or adopted and could harm our business, operating results and financial condition. (Applies to AEP and APCo.)

Virginia restructuring legislation was enacted in 1999 providing for retail choice of generation suppliers to be phased in over two years beginning January 1, 2002. It required jurisdictional utilities to unbundle their power supply and energy delivery rates and to file functional separation plans by January 1, 2002. APCo filed its plan with the Virginia SCC and, following Virginia SCC approval of a settlement agreement, now operates in Virginia as a functionally separated electric utility charging unbundled rates for its retail sales of electricity. The settlement agreement addressed functional separation, leaving decisions related to legal separation for later Virginia SCC consideration. While the electric restructuring law in Virginia established the general framework governing the retail electric market, it required the Virginia SCC to issue rules and determinations implementing the law.

In April 2007, Virginia enacted a law providing for cost-based regulation of electric utilities’ generation/supply rates. 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 if and when APCo is required to re-establish certain net regulatory liabilities applicable to its generation/supply business. The timing and one-time earnings effect from such reapplication of SFAS 71 regulatory accounting for APCo’s Virginia generation/supply business are uncertain at this time.

There is uncertainty as to our recovery of stranded costs resulting from industry restructuring in Texas. (Applies to AEP and TCC.)

Restructuring legislation in Texas required utilities with stranded costs to use market-based methods to value certain generating assets for determining stranded costs. We elected to use the sale of assets method to determine the market value of TCC’s generation assets for stranded cost purposes. In general terms, the amount of stranded costs under this market valuation methodology is the amount by which the book value of generating assets, including regulatory assets and liabilities that were not securitized, exceeds the market value of the generation assets, as measured by the net proceeds from the sale of the assets. In May 2005, TCC filed its stranded cost quantification application with the PUCT seeking recovery of $2.4 billion of net stranded generation costs and other recoverable true-up items. A final order was issued in April 2006. In the final order, the PUCT determined TCC’s net stranded generation costs and other recoverable true-up items to be approximately $1.475 billion. We have appealed the PUCT’s final order seeking additional recovery consistent with the Texas Restructuring Legislation and related rules, other parties have appealed the PUCT’s final order as unwarranted or too large. In a preliminary ruling filed in February 2007, the Texas state district court (District Court) adjudicating the appeal of the final order in the true-up proceeding found that the PUCT erred in several respects, including the method used to determine stranded costs and the awarding of certain carrying costs. Following the preliminary ruling, the court granted a rehearing of the issue regarding the method to determine stranded costs.

In March 2007, the District Court judge reversed the earlier preliminary decision concluding the sale of assets method to value TCC’s nuclear plant was appropriate. It is expected that the parties and intervenors will appeal various portions of the District Court ruling along with other items to the Texas Court of Appeals. Management cannot predict the ultimate outcome of any future court appeals or any future remanded PUCT proceeding.

Risks Related to Owning and Operating Generation Assets and Selling Power

Our costs of compliance with environmental laws are significant and the cost of compliance with future environmental laws could harm our cash flow and profitability. (Applies to AEP and each Registrant Subsidiary other than TCC and TNC.)

Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety. Compliance with these legal requirements requires us to commit significant capital toward environmental monitoring, installation of pollution control equipment, emission fees and permits at all of our facilities. These expenditures have been significant in the past, and we expect that they will increase in the future. On April 2, 2007, the U.S. Supreme Court issued a decision holding that the Federal EPA has authority to regulate emissions of CO2 and other greenhouse gases under the CAA. Costs of compliance with environmental regulations could adversely affect our results of operations and financial position, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increase. All of our estimates are subject to significant uncertainties about the outcome of several interrelated assumptions and variables, including timing of implementation, required levels of reductions, allocation requirements of the new rules and our selected compliance alternatives. As a result, we cannot estimate our compliance costs with certainty. The actual costs to comply could differ significantly from our estimates. All of the costs are incremental to our current investment base and operating cost structure.

If Federal and/or State requirements are imposed on electric utility companies mandating further emission reductions, including limitations on CO2 emissions, such requirements could make some of our electric generating units uneconomical to maintain or operate. (Applies to AEP and each Registrant Subsidiary other than TCC and TNC.)

Emissions of nitrogen and sulfur oxides, mercury and particulates from fossil fueled generating plants are potentially subject to increased regulations, controls and mitigation expenses. Environmental advocacy groups, other organizations and some agencies in the United States are focusing considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. Although several bills have been introduced in Congress that would compel CO2 emission reductions, none have advanced through the legislature. On April 2, 2007, the U.S. Supreme Court issued a decision holding that the Federal EPA has authority to regulate emissions of CO2 and other greenhouse gases under the CAA. Future changes in environmental regulations governing these pollutants could make some of our electric generating units uneconomical to maintain or operate. In addition, any legal obligation that would require us to substantially reduce our emissions beyond present levels could require extensive mitigation efforts and, in the case of CO2 legislation, would raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities. While mandatory requirements for further emission reductions from our fossil fleet do not appear to be imminent, we continue to monitor regulatory and legislative developments in this area.
 
Governmental authorities may assess penalties on us if it is determined that we have not complied with environmental laws and regulations. (Applies to AEP and each Registrant Subsidiary other than TCC and TNC.)

If we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, that failure may result in the assessment of civil or criminal penalties and fines against us. Recent lawsuits by the Federal EPA and various states filed against us highlight the environmental risks faced by generating facilities, in general, and coal-fired generating facilities, in particular.

Since 1999, we have been involved in litigation regarding generating plant emissions under the CAA. The Federal EPA and a number of states alleged that we and other unaffiliated utilities modified certain units at coal-fired generating plants in violation of the CAA. The Federal EPA filed complaints against certain AEP subsidiaries in U.S. District Court for the Southern District of Ohio. A separate lawsuit initiated by certain special interest groups was consolidated with the Federal EPA case. The alleged modification of the generating units occurred over a 20-year period. A bench trial on the liability issues was held during July 2005. Briefing has concluded and the court has indicated an intent to issue a decision on liability. Additionally, in July 2004 attorneys general of eight states and others sued AEP and other utilities alleging that CO2 emissions from power generating facilities constitute a public nuisance under federal common law. The trial court dismissed the suits and plaintiffs have appealed the dismissal. While we believe the claims are without merit, the costs associated with reducing CO2 emissions could harm our business and our results of operations and financial position.

If these or other future actions are resolved against us, substantial modifications of our existing coal-fired power plants could be required. In addition, we could be required to invest significantly in additional emission control equipment, accelerate the timing of capital expenditures, pay penalties and/or halt operations. Moreover, our results of operations and financial position could be reduced due to the timing of recovery of these investments and the expense of ongoing litigation.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information about purchases by AEP (or its publicly-traded subsidiaries) during the quarter ended March 31, 2007 of equity securities that are registered by AEP (or its publicly-traded subsidiaries) pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASES OF EQUITY SECURITIES
Period
 
Total Number
of Shares
Purchased
 
Average Price
Paid per Share
   
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 
Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
 
01/01/07 - 01/31/07
   
30
(a)
$
79
     
-
 
$
-
 
02/01/07 - 02/28/07
   
-
   
-
     
-
   
-
 
03/01/07 - 03/31/07
   
-
   
-
     
-
   
-
 

(a)
OPCo repurchased 30 shares of its 4.40% cumulative preferred stock, in a privately-negotiated transaction outside of an announced program.

Item 5. Other Information

NONE

Item 6. Exhibits

AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

12 - Computation of Consolidated Ratio of Earnings to Fixed Charges.

AEP

31(a) - Certification of AEP Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(c) - Certification of AEP Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

31(b) - Certification of Registrant Subsidiaries’ Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(d) - Certification of Registrant Subsidiaries’ Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

32(a) - Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
32(b) - Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.






SIGNATURE




Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

AMERICAN ELECTRIC POWER COMPANY, INC.



                By: /s/Joseph M. Buonaiuto
                Joseph M. Buonaiuto
                Controller and Chief Accounting Officer



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
SOUTHWESTERN ELECTRIC POWER COMPANY




                By: /s/Joseph M. Buonaiuto
                Joseph M. Buonaiuto
                Controller and Chief Accounting Officer



Date: May 4, 2007