Unassociated Document
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 September 30, 2006
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____

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

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

Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of ‘accelerated filer and large accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check One)
Large accelerated filer   X      Accelerated filer     Non-accelerated filer       

Indicate by check mark whether AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company, are large accelerated filers, accelerated filers, or non-accelerated filers. See definition of ‘accelerated filer and large accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check One)
Large accelerated filer        Accelerated filer     Non-accelerated filer   X  
 
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
Yes       
No   

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







     
 
 
Number of shares of common stock outstanding of the registrants at
October 31, 2006
       
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.
   
      395,572,735
     
($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
September 30, 2006

Glossary of Terms
 
 
     
Forward-Looking Information
 
 
     
Part I. FINANCIAL INFORMATION
   
       
 
Items 1, 2 and 3 - Financial Statements, Management’s Financial Discussion and Analysis and Quantitative and Qualitative Disclosures About Risk Management Activities:
   
American Electric Power Company, Inc. and Subsidiary Companies:
   
 
Management’s Financial Discussion and Analysis of Results of Operations
 
 
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
 
 
Condensed Consolidated Financial Statements
 
 
 
Index to Condensed Notes to Condensed Consolidated Financial Statements
 
 
       
AEP Generating Company:
   
 
Management’s Narrative Financial Discussion and Analysis
 
 
 
Condensed Financial Statements
 
 
 
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
 
       
AEP Texas Central Company and 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
 
 
       
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 Financial Discussion and Analysis
 
 
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
 
 
Condensed Consolidated Financial Statements
 
 
 
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
 
       
Kentucky Power Company:
   
 
Management’s Narrative Financial Discussion and Analysis
 
 
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
 
 
Condensed Financial Statements
 
 
 
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
 
       
Ohio Power Company Consolidated:
   
 
Management’s Financial Discussion and Analysis
 
 
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
 
 
Condensed Consolidated Financial Statements
 
 
 
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
 
       
Public Service Company of Oklahoma:
   
 
Management’s Narrative Financial Discussion and Analysis
 
 
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
 
 
Condensed Financial Statements
 
 
 
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
 
       
Southwestern Electric Power Company Consolidated:
   
 
Management’s Financial Discussion and Analysis
 
 
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
 
 
Condensed Consolidated Financial Statements
 
 
 
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
 
       
Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
 
       
Combined Management’s Discussion and Analysis of Registrant Subsidiaries
 
 
       
 
Item 4.
Controls and Procedures
 
 
         
Part II. OTHER INFORMATION
   
     
 
Item 1.
Legal Proceedings
 
 
 
Item 1A.
Risk Factors
 
 
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
 
 
 
Item 5.
Other Information
 
 
 
Item 6.
Exhibits:
 
 
        Exhibit 12    
        Exhibit 31 (a)    
        Exhibit 31 (b)    
        Exhibit 31 (c)    
        Exhibit 31 (d)    
        Exhibit 32 (a)    
        Exhibit 32 (b)    
               
SIGNATURE
   
 

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







GLOSSARY OF TERMS
 
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
 
Term
 
 
Meaning
ADFIT
 
Accumulated Deferred Federal Income Taxes.
ADITC
 
Accumulated Deferred Investment Tax Credits.
AEGCo
 
AEP Generating Company, an AEP electric generating subsidiary.
AEP or Parent
 
American Electric Power Company, Inc.
AEP Consolidated
 
AEP and its majority owned consolidated subsidiaries and consolidated entities.
AEP East companies
 
APCo, CSPCo, I&M, KPCo and OPCo.
AEPES
 
AEP Energy Services, Inc., a subsidiary of AEP Resources, Inc.
AEP System or the System
 
American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP System Power Pool or AEP
  Power Pool
 
Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and resultant wholesale off-system sales of the member companies.
AEPSC
 
American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AEP West companies
 
PSO, SWEPCo, TCC and TNC.
AFUDC
 
Allowance for Funds Used During Construction.
ALJ
 
Administrative Law Judge.
AOCI
 
Accumulated Other Comprehensive Income.
APCo
 
Appalachian Power Company, an AEP electric utility subsidiary.
CAA
 
Clean Air Act.
Cook Plant
 
Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo
 
Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW
 
Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW Operating Agreement
 
Agreement, dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing their generating capacity allocation. AEPSC acts as the agent.
CTC
 
Competition Transition Charge.
DETM
 
Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
ECAR
 
East Central Area Reliability Council.
EDFIT
 
Excess Deferred Federal Income Taxes.
EITF
 
Financial Accounting Standards Board’s Emerging Issues Task Force.
EPACT
 
Energy Policy Act of 2005.
ERCOT
 
Electric Reliability Council of Texas.
FASB
 
Financial Accounting Standards Board.
Federal EPA
 
United States Environmental Protection Agency.
FERC
 
Federal Energy Regulatory Commission.
GAAP
 
Accounting Principles Generally Accepted in the United States of America.
HPL
 
Houston Pipe Line Company LP, a former AEP subsidiary that was sold in January 2005.
IGCC
 
Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
I&M
 
Indiana Michigan Power Company, an AEP electric utility subsidiary.
IPP
 
Independent Power Producers.
IRS
 
Internal Revenue Service.
IURC
 
Indiana Utility Regulatory Commission.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
KPSC
 
Kentucky Public Service Commission.
kV
 
Kilovolt.
KWH
 
Kilowatthour.
MISO
 
Midwest Independent Transmission System Operator.
MTM
 
Mark-to-Market.
MW
 
Megawatt.
MWH
 
Megawatthour.
NOx
 
Nitrogen oxide.
Nonutility Money Pool
 
AEP System’s Nonutility Money Pool.
NRC
 
Nuclear Regulatory Commission.
NSR
 
New Source Review.
NYMEX
 
New York Mercantile Exchange.
OATT
 
Open Access Transmission Tariff.
OCC
 
Corporation Commission of the State of Oklahoma.
OPCo
 
Ohio Power Company, an AEP electric utility subsidiary.
OTC
 
Over the counter.
PJM
 
Pennsylvania - New Jersey - Maryland regional transmission organization.
PSO
 
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTB
 
Price-to-Beat.
PUCO
 
Public Utilities Commission of Ohio.
PUCT
 
Public Utility Commission of Texas.
PURPA
 
Public Utility Regulatory Policies Act of 1978.
Registrant Subsidiaries
 
AEP subsidiaries which are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC.
REP
 
Texas Retail Electric Provider.
Risk Management Contracts
 
Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
 
A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned or leased 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 FASB.
SFAS 133
 
Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.”
SIA
 
System Integration Agreement.
SO2
 
Sulfur Dioxide.
SPP
 
Southwest Power Pool.
STP
 
South Texas Project Nuclear Generating Plant.
Sweeny
 
Sweeny Cogeneration Limited Partnership, owner and operator of a four unit, 480 MW gas-fired generation facility, owned 50% by AEP.
SWEPCo
 
Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC
 
AEP Texas Central Company, an AEP electric utility subsidiary.
TEM
 
SUEZ Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing, Inc.).
Texas Restructuring Legislation
 
Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC
 
AEP Texas North Company, an AEP electric utility subsidiary.
True-up Proceeding
 
A filing made under the Texas Restructuring Legislation to finalize the amount of stranded costs and other true-up items and the recovery of such amounts.
Utility Money Pool
 
AEP System’s Utility Money Pool.
VaR
 
Value at Risk, a method to quantify risk exposure.
Virginia SCC
 
Virginia State Corporation Commission.
WPCo
 
Wheeling Power Company, an AEP electric distribution subsidiary.
WVPSC
 
Public Service Commission of West Virginia.
 





FORWARD-LOOKING INFORMATION

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

·
Electric load and customer growth.
·
Weather conditions, including storms.
·
Available sources and costs of, and transportation for, fuels and the creditworthiness of fuel suppliers and transporters.
·
Availability of generating capacity and the performance of our generating plants.
·
Our ability to recover regulatory assets and stranded costs in connection with deregulation.
·
Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·
Our ability to build or acquire generating capacity when needed at acceptable prices and terms and to recover those costs through applicable rate cases or competitive rates.
·
New legislation, litigation and government regulation including requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, 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.
·
Changes in the financial markets, particularly those affecting the availability of capital and our ability to refinance existing debt at attractive rates.
·
Actions of rating agencies, including changes in the ratings of debt.
·
Volatility and changes in markets for electricity, natural gas and other energy-related commodities.
·
Changes in utility regulation, including implementation of EPACT and membership in and integration into regional transmission structures.
·
Accounting pronouncements periodically issued by accounting standard-setting bodies.
·
The performance of our pension and other postretirement benefit plans.
·
Prices for power that we generate and sell at wholesale.
·
Changes in technology, particularly with respect to new, developing or alternative sources of generation.
·
Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events.



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

EXECUTIVE OVERVIEW

Several factors, both positive and negative, contributed to our performance in the third quarter of 2006. We continued receiving favorable outcomes in various regulatory activities resulting in increased revenues. We also continued securing new power supply contracts with municipal and cooperative customers and our barging subsidiary produced strong results. Some of these positive factors were offset in part by mild weather and an impairment related to our Plaquemine Cogeneration Facility in connection with the pending sale to Dow Chemical Company.

Regulatory Activity

Our significant regulatory activity progressed with the following major developments:

·
In July 2006, an ALJ rendered an initial decision to the FERC recommending that current transmission rates in PJM are unjust and unreasonable and should be redesigned to replace the PJM license plate rates effective April 1, 2006. If approved by the FERC, the new regional rates would result in parties outside of the AEP zone in PJM contributing a significant portion of AEP’s transmission revenue requirement, some of which may be treated as a refund to retail customers. The favorable impact of the initial ALJ decision is not determinable pending the decision of the FERC and subject to analysis of refunds to retail customers, if any.
·
In July 2006, the FERC approved our request for use of an incentive rate treatment for our proposed 550-mile 765 kV transmission line project. The approval is conditioned upon PJM including the project in its formal Regional Transmission Expansion Plan, which should be finalized in early 2007.
·
In July 2006, the West Virginia Public Service Commission approved a settlement agreement in APCo and WPCo’s base rate case, providing for a $44 million annual increase in rates effective July 28, 2006. These rates include a surcharge for recovery of the cost of the Wyoming-Jacksons Ferry 765 kV line, which was energized and placed in service in June 2006.
·
In August 2006, an ALJ rendered an initial decision to the FERC indicating the rate design for recovery of SECA charges was flawed and that the SECA rates charged were unfair, unjust and discriminatory and that refunds should be made. We believe this decision is contrary to other FERC rulings and intend to defend against a SECA rates refund.
·
In September 2006, the Virginia SCC’s chief hearing examiner issued an opinion recommending disallowance of our $21 million environmental and reliability cost recovery case filed in June 2005. We subsequently wrote off our related assets which reduced pretax earnings by $36 million in the third quarter of 2006. We believe the hearing examiner’s recommendation is contrary to the law and have urged the Virginia SCC not to adopt that recommendation.
·
In September 2006, we announced our intention to file transmission and distribution wires rate cases in Texas in late 2006.  We anticipate requesting an $83 million increase for TCC and a $25 million increase for TNC.
·
In September 2006, we filed a notice of intent in Oklahoma to file a base rate case in November 2006.
·
In October 2006, we filed state environmental permit applications for clean-coal power plants in Ohio and West Virginia, representing another step towards the commencement of construction of our IGCC plants.
·
In October 2006, we implemented an interim increase in Virginia retail base rates, subject to refund, as ordered by the Virginia SCC related to our $198 million net base rate case filing from May 2006. Hearings are scheduled for December 2006.
·
In October 2006, TCC issued $1.74 billion senior secured transition bonds as previously approved by the PUCT. In October 2006, TCC repaid $345 million of intercompany notes to AEP and also paid a special dividend of $585 million to AEP. We will use the remaining proceeds to reduce a portion of TCC’s debt and equity.
·
In October 2006, the IURC denied our request to revise I&M’s book depreciation rates without adjusting base tariff rates.

Fuel Costs

During 2006, spot market prices for coal and natural gas have declined. In contrast, market prices for fuel oil have increased and continue to be volatile. We still expect an approximate ten percent increase in coal costs during 2006 and a six to eight percent increase in 2007 even considering softening fuel markets and favorable transportation effects during the first nine months of the year. We have price risk related to these commodity prices. We do not have an active fuel cost recovery adjustment mechanism in Ohio, which represents approximately 20% of our fuel costs.

In Indiana, our fuel recovery mechanism is temporarily capped, subject to preestablished escalators, at a fixed rate through June 2007. As a consequence of the cap, we incurred under-recoveries of $17 million for the first nine months of 2006 and expect additional under-recoveries for the remainder of 2006. Our Ohio companies increased their generation rates in 2006, as previously approved by the PUCO in our Rate Stabilization Plans, which are intended to recover increases in generation costs, including increased fuel costs. These increased rates, along with the reinstated fuel cost adjustment rate clause for over- or under-recovery of fuel, off-system sales margins, certain transmission items and related costs effective July 1, 2006 in West Virginia, will help offset future negative impacts of fuel price increases on our gross margins.

Barging Operations

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

In August 2006, we reached an agreement to sell our Plaquemine Cogeneration Facility (the Facility) to Dow Chemical Company (Dow) for $64 million. We expect the sale to close in the fourth quarter of 2006. We recorded a pretax impairment of $209 million ($136 million, net of tax) in the third quarter of 2006 based on the terms of the agreement to sell the Facility to Dow. In addition to the cash proceeds, the sale agreement allows us to participate in gross margin sharing on the Facility for five years and we retain the right to any judgment paid by TEM for breaching the original PPA, as discussed in Note 5.

Assuming the sale closes, our future earnings will be favorably impacted by eliminating ongoing operating losses. These improvements will be partially offset by interest expense associated with continuing debt service obligations.

Dividend Increase

In October 2006, our Board of Directors approved a five percent increase in our quarterly dividend to $0.39 per share from $0.37 per share.

RESULTS OF OPERATIONS

Segments

Our principal operating business segments and their major activities are:

Utility Operations
 
·
Generation of electricity for sale to U.S. retail and wholesale customers.
 
·
Electricity transmission and distribution in the U.S.
Investments - Other
 
·
Bulk commodity barging operations, wind farms, IPPs and other energy supply-related businesses.
 
Our consolidated Income Before Discontinued Operations for the three and nine months ended September 30, 2006 and 2005 were as follows (Earnings and Weighted Average Number of Basic Shares Outstanding in millions):

   
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
   
2006
 
2005
 
2006
 
2005
 
   
Earnings
 
EPS (c)
 
Earnings
 
EPS (c)
 
Earnings
 
EPS (c)
 
Earnings
 
EPS (c)
 
Utility Operations
 
$
379
 
$
0.96
 
$
352
 
$
0.91
 
$
904
 
$
2.29
 
$
952
 
$
2.45
 
Investments - Other
   
(109
) (d)
 
(0.28
) (d)
 
28
   
0.07
   
(80
) (d)
 
(0.20
) (d)
 
32
   
0.08
 
All Other (a)
   
(2
)
 
-
   
(5
)
 
(0.01
)
 
(7
)
 
(0.02
)
 
(45
)
 
(0.12
)
Investments - Gas Operations (b)
   
(3
)
 
(0.01
)
 
(10
)
 
(0.03
)
 
(2
)
 
-
   
(2
)
 
-
 
Income Before Discontinued Operations
 
$
265
 
$
0.67
 
$
365
 
$
0.94
 
$
815
 
$
2.07
 
$
937
 
$
2.41
 
                                                   
Weighted Average Number of Basic
  Shares Outstanding
         
394
         
389
         
394
         
389
 

(a)
All Other includes the parent company’s guarantee revenues, interest income and expense, as well as other nonallocated costs.
 
(b)
We sold our remaining gas pipeline and storage assets in 2005.
 
(c)
The earnings per share of any segment does not represent a direct legal interest in the assets and liabilities allocated to any one segment but rather represents a direct equity interest in AEP’s assets and liabilities as a whole.
 
  (d) Loss primarily due to an after-tax impairment of $136 million (approximately $0.34 per share) related to our Plaquemine Cogeneration Facility.  

Third Quarter of 2006 Compared to Third Quarter of 2005

Income Before Discontinued Operations in the third quarter of 2006 decreased $100 million compared to the third quarter of 2005 principally due to an impairment of the Plaquemine Cogeneration Facility as a result of the pending sale and decreases in Utility Operations earnings related to lower transmission revenues from the loss of SECA rates and the write off of Virginia environmental and reliability regulatory assets pursuant to a hearing examiner's recommendation, which we have urged the Virginia SCC not to adopt. These decreases were partially offset by an earnings increase in Utility Operations primarily related to new retail rates implemented in Ohio and Kentucky and increased off-system sales margins.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Income Before Discontinued Operations for the nine months ended September 30, 2006 decreased $122 million compared to the nine months ended September 30, 2005 due to a $48 million decrease in Utility Operations earnings from decreases in transmission revenues from the loss of SECA rates and increases in operating expenses, partially offset by new retail rates implemented in Ohio and Kentucky. In addition, our Investments - Other segment earnings decreased $112 million from an impairment of the Plaquemine Cogeneration Facility related to the pending sale. These decreases were partially offset by a decrease of $38 million in interest expense, net of interest income, at the parent company.

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

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

   
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
   
2006
 
2005
 
2006
 
2005
 
   
(in millions)
 
Revenues
 
$
3,441
 
$
3,237
 
$
9,209
 
$
8,623
 
Fuel and Purchased Energy
   
1,384
   
1,252
   
3,637
   
3,163
 
Gross Margin
   
2,057
   
1,985
   
5,572
   
5,460
 
Depreciation and Amortization
   
369
   
328
   
1,041
   
963
 
Other Operating Expenses
   
973
   
1,014
   
2,806
   
2,757
 
Operating Income
   
715
   
643
   
1,725
   
1,740
 
Other Income, Net
   
20
   
43
   
105
   
122
 
Interest Expense and Preferred Stock Dividend  Requirements
   
161
   
145
   
475
   
445
 
Income Tax Expense
   
195
   
189
   
451
   
465
 
Income Before Discontinued Operations
 
$
379
 
$
352
 
$
904
 
$
952
 

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

   
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
   
2006
 
2005
 
2006
 
2005
 
   
(in millions of KWH)
 
Energy Summary
                     
Retail:
                     
Residential
   
13,482
   
14,152
   
36,010
   
37,332
 
Commercial
   
10,799
   
10,900
   
29,149
   
29,204
 
Industrial
   
13,468
   
13,380
   
40,405
   
39,633
 
Miscellaneous
   
677
   
682
   
1,890
   
1,968
 
Subtotal
   
38,426
   
39,114
   
107,454
   
108,137
 
Texas Retail and Other
   
105
   
115
   
312
   
504
 
Total Retail
   
38,531
   
39,229
   
107,766
   
108,641
 
                           
Wholesale
   
13,465
   
13,135
   
35,131
   
37,515
 
                           
Texas Wires Delivery
   
7,877
   
8,093
   
20,338
   
20,348
 
                           
Total KWHs
   
59,873
   
60,457
   
163,235
   
166,504
 

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

   
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
   
2006
 
2005
 
2006
 
2005
 
   
(in degree days)
 
Weather Summary
                     
Eastern Region
                     
Actual - Heating (a)
   
10
   
1
   
1,573
   
1,940
 
Normal - Heating (b)
   
7
   
7
   
1,999
   
1,995
 
                           
Actual - Cooling (c)
   
685
   
834
   
914
   
1,122
 
Normal - Cooling (b)
   
688
   
674
   
970
   
955
 
                           
Western Region (d)
                         
Actual - Heating (a)
   
0
   
0
   
664
   
795
 
Normal - Heating (b)
   
2
   
2
   
1,007
   
1,007
 
                           
Actual - Cooling (c)
   
1,468
   
1,523
   
2,325
   
2,225
 
Normal - Cooling (b)
   
1,410
   
1,397
   
2,079
   
2,059
 

(a)
Eastern Region and Western Region heating degree days are calculated on a 55 degree temperature base.
 
(b)
Normal Heating/Cooling represents the 30-year average of degree days.
 
(c)
Eastern Region and Western Region cooling days are calculated on a 65 degree temperature base.
 
(d)
Western Region statistics represent PSO/SWEPCo customer base only.
 
 
Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006
Income from Utility Operations Before Discontinued Operations
(in millions)
Third Quarter of 2005
       
$
352
 
               
Changes in Gross Margin:
             
Retail Margins
   
29
       
Off-system Sales
   
75
       
Transmission Revenues
   
(38
)
     
Other
   
6
       
Total Change in Gross Margin
         
72
 
               
Changes in Operating Expenses and Other:
             
Maintenance and Other Operation
   
(15
)
     
Asset Impairments and Other Related Charges
   
39
       
Depreciation and Amortization
   
(41
)
     
Taxes Other Than Income Taxes
   
17
       
Other Income, Net
   
(23
)
     
Interest and Other Charges
   
(16
)
     
Total Change in Operating Expenses and Other
         
(39
)
               
Income Tax Expense
         
(6
)
               
Third Quarter of 2006
       
$
379
 

Income from Utility Operations Before Discontinued Operations increased $27 million to $379 million in 2006. The key driver of the increase was a $72 million net increase in Gross Margin, partially offset by a $39 million increase in Operating Expenses and Other.

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

·
Retail Margins increased $29 million primarily due to the following:
 
·
A $72 million increase related to new rates implemented in our Ohio jurisdictions as approved by the PUCO in our Rate Stabilization Plans (RSPs) and a $12 million increase related to new rates implemented in Kentucky as approved in our base rate case;
 
·
A $20 million increase related to increased sales to municipal, cooperative and other wholesale customers primarily as a result of new power supply contracts; and
 
·
An $18 million increase related to the purchase of the Ohio service territory of Monongahela Power in December 2005; partially offset by
 
 · 
A $22 million decrease in financial transmission rights revenue, net of congestion, primarily due to fewer transmission constraints within the PJM market;
 
 · 
A $33 million decrease related to increased refunds to retail customers of a portion of off-system sales margins due to higher off-system sales and the reinstatement of the off-system sales margins sharing mechanism in West Virginia effective July 1, 2006 in conjunction with the West Virginia rate case settlement;
 
 · 
A $14 million increase in delivered fuel costs, which relates to AEP East companies with inactive, capped or frozen fuel clauses; and
 
 · 
A $30 million decrease in usage related to mild weather. As compared to the prior year, we experienced an 18% decrease in cooling degree days in the eastern region and a 4% decrease in the western region.
·
Margins from Off-system Sales for 2006 increased $75 million primarily due to positive margins from hedges of plant output and strong physical sales in the east, where AEP’s generation availability factor was high in July and August when wholesale prices were favorable.
·
Transmission Revenues decreased $38 million primarily due to the elimination of SECA revenues as of April 1, 2006. At this time, we have a pending proposal with the FERC to replace SECA revenues. 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:

·
Maintenance and Other Operation expenses increased $15 million primarily due to increases in generation expenses for base operations, maintenance and an abandonment of digital turbine control equipment at the Cook Plant, increases in transmission and distribution expenses related to vegetation management and storm restoration and the establishment of a regulatory asset for PJM administrative fees in 2005 which reduced expenses in the prior period, offset by the establishment of a net regulatory asset for recovery of prior years’ Ohio ice storm damage costs and lower incentive pay accruals.
·
Asset Impairments and Other Related Charges were $39 million in 2005 due to our commitment to a plan in September 2005 to retire two units at our Conesville Plant. We retired the two units effective December 29, 2005.
·
Depreciation and Amortization expense increased $41 million primarily due to increased Ohio regulatory asset amortization in conjunction with rate increases, higher depreciable property balances and the write off of Virginia environmental and reliability regulatory assets.
·
Taxes Other Than Income Taxes decreased $17 million primarily due to adjustments related to real and personal property taxes and sales and use taxes.
·
Other Income, Net decreased $23 million primarily related to the write off of carrying costs on Virginia environmental and reliability regulatory assets.
·
Interest and Other Charges increased $16 million primarily due to additional debt issued in late 2005 and early 2006 and an increase in regulatory interest related to Texas regulatory liabilities partially offset by an increase in allowance for borrowed funds used during construction.
·
Income Tax Expense increased $6 million due to the increase in pretax income.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

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

Nine Months Ended September 30, 2005
       
$
952
 
               
Changes in Gross Margin:
             
Retail Margins
   
198
       
Off-system Sales
   
2
       
Transmission Revenues
   
(93
)
     
Other
   
5
       
Total Change in Gross Margin
         
112
 
               
Changes in Operating Expenses and Other:
             
Maintenance and Other Operation
   
(42
)
     
Gain on Disposition of Assets, Net
   
(47
)
     
Asset Impairments and Other Related Charges
   
39
       
Depreciation and Amortization
   
(78
)
     
Other Income, Net
   
(16
)
     
Interest and Other Charges
   
(30
)
     
Total Change in Operating Expenses and Other
         
(174
)
               
Income Tax Expense
         
14
 
               
Nine Months Ended September 30, 2006
       
$
904
 

Income from Utility Operations Before Discontinued Operations decreased $48 million to $904 million in 2006. The key driver of the decrease was a $174 million increase in Operating Expenses and Other, offset by a $112 million increase in Gross Margin and a $14 million decrease in Income Tax Expense.
 
The major components of the net increase in Gross Margin were as follows:
 

·
Retail Margins increased $198 million primarily due to the following:
 
·
A $175 million increase related to new rates implemented in our Ohio jurisdictions as approved by the PUCO in our RSPs, a $22 million increase related to new rates implemented in Kentucky as approved in our base rate case and a $12 million increase related to new rates implemented in Oklahoma in June 2005;
 
·
A $21 million increase in financial transmission rights revenue, net of congestion, due to improved management of price risk related to serving retail load within PJM under current transmission constraints;
 
·
A $58 million increase related to increased usage and customer growth in the industrial and commercial classes of which $47 million relates to the purchase of the Ohio service territory of Monongahela Power in December 2005; and
 
 · 
A $50 million increase related to increased sales to municipal, cooperative and other wholesale customers primarily as a result of new power supply contracts; partially offset by
 
 · 
An $84 million increase in delivered fuel cost, which relates to the AEP East companies with inactive, capped or frozen fuel clauses;
 
 · 
A $66 million decrease in usage related to mild weather. As compared to the prior year, our eastern region and western region experienced 19% and 17% declines, respectively, in heating degree days. Also compared to the prior year, our eastern region experienced a 19% decrease in cooling degree days. These decreases were partially offset by an increase of 5% in cooling degree days in the western region; and
 
 · 
A $15 million decrease related to increased refunds to retail customers of a portion of off-system sales margins due to higher off-system sales and the reinstatement of the off-system sales margins sharing mechanism in West Virginia effective July 1, 2006 in conjunction with the West Virginia rate case settlement.
·
Transmission Revenues decreased $93 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $19 million recorded in 2006 related to potential SECA refunds pending settlement negotiations with various intervenors. At this time, we have a pending proposal with the FERC to replace SECA revenues. 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:

·
Maintenance and Other Operation expenses increased $42 million primarily due to increases in generation expenses related to base operations, maintenance and planned and forced plant outages, distribution expenses related to vegetation management and the establishment of a regulatory asset for PJM administrative fees in 2005 which reduced expenses in the prior period. These increases were partially offset by favorable variances related to expenses from the January 2005 ice storm in Ohio and Indiana, decreases related to the sale of STP in May 2005 and lower incentive accruals.
·
Asset Impairments and Other Related Charges were $39 million in 2005 due to our commitment to a plan in September 2005 to retire two units at our Conesville Plant. We retired the two units effective December 29, 2005.
·
Gain on Disposition of Assets, Net decreased $47 million resulting from revenues related to the earnings sharing agreement with Centrica as stipulated in the purchase-and-sale agreement from the sale of our REPs in 2002. In 2005, we reached a settlement with Centrica and received $112 million related to two years of earnings sharing whereas in 2006 we received $70 million related to one year of earnings sharing.
·
Depreciation and Amortization expense increased $78 million primarily due to increased Ohio regulatory asset amortization in conjunction with rate increases, higher depreciable property balances and the write off of Virginia environmental and reliability regulatory assets.
·
Other Income, Net decreased $16 million primarily due to the write off of carrying costs on Virginia environmental and reliability regulatory assets and a decrease in Ohio carrying costs income as a result of the implementation of the Ohio rate stabilization plans in January 2006, partially offset by an increase in the allowance for equity funds used during construction.
·
Interest and Other Charges increased $30 million from the prior period primarily due to additional debt issued in late 2005 and early 2006 and increasing interest rates, partially offset by an increase in allowance for borrowed funds used during construction.
·
Income Tax Expense decreased $14 million due to the decrease in pretax income.

Investments - Other

Third Quarter of 2006 Compared to Third Quarter of 2005

Loss Before Discontinued Operations from our Investments - Other segment was $109 million in 2006 compared to income of $28 million in 2005. The change was primarily due to a $136 million after-tax impairment of the Plaquemine Cogeneration Facility related to the pending sale and a $32 million after-tax gain on the sale of Pacific Hydro Limited in the third quarter of 2005, partially offset by favorable barging activity at MEMCO due to strong demand and a tight supply of barges resulting in increased barge freight rates. Also, the third quarter 2006 operating conditions for our barging operations improved from 2005 when Hurricane Katrina increased operating costs.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Loss Before Discontinued Operations from our Investments - Other segment was $80 million in 2006 compared to income of $32 million in 2005. The change was primarily due to a $136 million after-tax impairment of the Plaquemine Cogeneration Facility related to the pending sale and a $32 million after-tax gain on the sale of Pacific Hydro Limited in the third quarter of 2005, partially offset by favorable barging activity at MEMCO due to strong demand and a tight supply of barges resulting in increased barge freight rates. Additionally, 2006 operating conditions for our barging operations improved from 2005 when hurricanes, severe ice and flooding caused increased operating costs.

Other

Parent

Third Quarter of 2006 Compared to Third Quarter of 2005

The parent company’s Loss Before Discontinued Operations decreased $3 million from 2005 primarily due to lower interest expense as a result of the maturity of senior unsecured notes of $396 million in the second quarter of 2006, partially offset by higher interest expense due to the issuance of $345 million of senior notes in June 2005.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

The parent company’s Loss Before Discontinued Operations decreased $38 million from 2005 primarily due to lower interest expense and associated buyback costs related to the redemption of $550 million of senior unsecured notes in April 2005 and increased affiliated interest income related to favorable results from the corporate borrowing program.

Investments - Gas Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

The Loss Before Discontinued Operations from our Gas Operations segment improved $7 million primarily related to results from gas contracts that were not sold with the gas pipeline and storage assets.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

The Loss Before Discontinued Operations from our Gas Operations segment was essentially flat. Prior year results included one month of HPL’s operations due to the sale of HPL in January 2005. Current year results relate primarily to gas contracts that were not sold with the gas pipeline and storage assets.

AEP System Income Taxes

The decrease in income tax expense of $63 million between the third quarter of 2006 and the third quarter of 2005 is primarily due to a decrease in pretax book income.
 
The decrease in income tax expense of $77 million between the nine months ended September 30, 2006 and the nine months ended September 30, 2005 is primarily due to a decrease in pretax book income.

FINANCIAL CONDITION

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

Debt and Equity Capitalization ($ in millions)

   
September 30, 2006
 
December 31, 2005
 
Long-term Debt, including amounts due within one year
 
$
12,763
   
57.0
%
$
12,226
   
57.2
%
Short-term Debt
   
23
   
0.1
   
10
   
0.0
 
Total Debt
   
12,786
   
57.1
   
12,236
   
57.2
 
Common Equity
   
9,525
   
42.6
   
9,088
   
42.5
 
Preferred Stock
   
61
   
0.3
   
61
   
0.3
 
                           
Total Debt and Equity Capitalization
 
$
22,372
   
100.0
%
$
21,385
   
100.0
%

The amount of our common equity increased primarily due to earnings exceeding the amount of dividends paid in 2006. As a result, our ratio of total debt to total capital improved from 57.2% to 57.1%.

In September 2006, the FASB issued SFAS 158 related to phase one of its pension and postretirement benefit accounting project. It could have a  negative impact on our debt to capital ratio when reported at December 31, 2006. The new standard requires the recognition of an additional minimum liability for fully-funded pension and postretirement benefit plans, thereby eliminating on the balance sheet the SFAS 87 and SFAS 106 deferral and amortization of net actuarial gains and losses. This could require recognition of a significant net-of-tax accumulated other comprehensive income reduction to common equity for those jurisdictions where a regulatory asset cannot be recorded. We estimate regulatory assets could offset as much as two-thirds of any net-of-tax accumulated other comprehensive income reduction.  The effective date is fiscal years ending after December 15, 2006.

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 September 30, 2006, our available liquidity was approximately $3.2 billion as illustrated in the table below:

   
Amount
 
Maturity
 
   
(in millions)
     
Commercial Paper Backup:
          
Revolving Credit Facility
 
$
1,500
   
March 2010
 
Revolving Credit Facility
   
1,500
   
April 2011
 
Total
   
3,000
       
Cash and Cash Equivalents
   
259
       
Total Liquidity Sources
   
3,259
       
Less: Letter of Credit Drawn
   
34
       
Net Available Liquidity
 
$
3,225
       

In April 2006, we amended the terms and increased the size of our credit facilities from $2.7 billion to $3 billion on terms more economically favorable than the previous agreements. The amended facilities are structured as two $1.5 billion credit facilities, each with an option to issue up to $200 million as letters of credit.
 
Debt Covenants and Borrowing Limitations

Our revolving credit agreements contain covenants that 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 September 30, 2006, this contractually-defined percentage was 54.2%. Nonperformance of these covenants could result in an event of default under these credit agreements. At September 30, 2006, we complied with all of the covenants contained in these credit agreements. In addition, the acceleration of our payment obligations, or the obligations of certain of our subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million would cause an event of default under these credit agreements and permit the lenders to declare the outstanding amounts payable.

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

Under a regulatory order, our utility subsidiaries, 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 the utility subsidiaries from issuing long-term debt unless that debt will be rated investment grade by at least one nationally recognized statistical rating organization. At September 30, 2006, all utility subsidiaries were comfortably in compliance with this order.

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

Credit Ratings

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

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

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

Cash Flow

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

   
Nine Months Ended
September 30,
 
   
2006
 
2005
 
   
(in millions)
 
Cash and Cash Equivalents at Beginning of Period
 
$
401
 
$
320
 
Net Cash Flows From Operating Activities
   
2,213
   
1,699
 
Net Cash Flows Used For Investing Activities
   
(2,474
)
 
(60
)
Net Cash Flows From (Used For) Financing Activities
   
119
   
(1,110
)
Net Increase (Decrease) in Cash and Cash Equivalents
   
(142
)
 
529
 
Cash and Cash Equivalents at End of Period
 
$
259
 
$
849
 
 
Cash from operations, bank-sponsored receivables purchase agreement and short-term borrowings provide 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 September 30, 2006, we had credit facilities totaling $3 billion to support our commercial paper program without an outstanding balance. The maximum amount of commercial paper outstanding during the nine months ended September 30, 2006 was $325 million. The weighted-average interest rate for our commercial paper during the first nine months of 2006 was 4.96%. We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding mechanisms are arranged. Sources of long-term funding include issuance of common stock or long-term debt and sale-leaseback or leasing agreements. Utility Money Pool borrowings and external borrowings may not exceed authorized limits under regulatory orders. See the discussion below for further detail related to the components of our cash flows.

Operating Activities

   
Nine Months Ended
September 30,
 
   
2006
 
2005
 
   
(in millions)
 
Net Income
 
$
821
 
$
963
 
Less: Discontinued Operations, Net of Tax
   
(6
)
 
(26
)
Income Before Discontinued Operations
   
815
   
937
 
Noncash Items Included in Earnings
   
1,164
   
987
 
Changes in Assets and Liabilities
   
234
   
(225
)
Net Cash Flows From Operating Activities
 
$
2,213
 
$
1,699
 

The key drivers of the increase in cash from operations for the first nine months of 2006 were no Pension Contributions to Qualified Plan Trusts in 2006 compared with a $306 million contribution in 2005 and increased recovery of deferred fuel. In 2005, we initiated fuel proceedings in Oklahoma, Texas, Virginia and Arkansas seeking recovery of our increased fuel costs.

Net Cash Flows From Operating Activities were $2.2 billion in 2006 consisting primarily of Income Before Discontinued Operations of $815 million adjusted for noncash charges of $1.2 billion, which principally includes $1.1 billion for Depreciation and Amortization. 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 is a $235 million decrease in cash related to customer deposits held for trading activities generally due to lower gas and power market prices.

Net Cash Flows From Operating Activities were $1.7 billion in 2005 consisting primarily of Income Before Discontinued Operations of $937 million adjusted for noncash charges of $987 million, which principally includes $988 million for Depreciation and Amortization. Changes in Assets and Liabilities represent those items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in these asset and liability accounts relates to a number of items; the most significant are a $311 million cash increase from Customer Deposits held for trading activities and increases from Accounts Payable and Accrued Taxes. Cash increased $173 million related to Accounts Payable due to higher fuel and allowance acquisition costs not paid at September 30, 2005. Accrued Taxes increased due to the difference between the recording of the current federal income tax liability, the timing of required estimated payments and the receipt of a prior year federal income tax refund. Our consolidated tax group paid a total of $217 million in federal income taxes, net of refunds, during the first nine months of 2005. We also realized gains on sales of assets of $172 million and made contributions of $306 million to our pension trust fund.

Investing Activities
   
Nine Months Ended
September 30,
 
   
2006
 
2005
 
   
(in millions)
 
Investment Securities:
           
Purchases of Investment Securities
 
$
(8,153
)
$
(4,319
)
Sales of Investment Securities
   
8,056
   
4,378
 
Change in Investment Securities, Net
   
(97
)
 
59
 
Construction Expenditures
   
(2,445
)
 
(1,610
)
Acquisition of Waterford Plant
   
-
   
(218
)
Change in Other Temporary Cash Investments, Net
   
20
   
99
 
Proceeds from Sales of Assets
   
120
   
1,599
 
Other
   
(72
)
 
11
 
Net Cash Flows Used for Investing Activities
 
$
(2,474
)
$
(60
)

Net Cash Flows Used For Investing Activities were $2.5 billion in 2006 primarily due to Construction Expenditures supporting our environmental investment plan. These cash flows were consistent with our budgeted cash flows for investing activities for the nine months ended September 30, 2006.  We forecast $1.3 billion of Construction Expenditures for the remainder of 2006, which will be funded through results of operations and financing activities.

During 2006, we purchased $8.2 billion of investments and received $8.1 billion of proceeds from the sales of securities. During 2005, we purchased $4.3 billion of investments and received $4.4 billion of proceeds from the sales of securities. In our normal course of business, we purchase taxable and tax exempt securities with cash available for short-term investments. The increased purchases and sales in 2006 reflect our investing in expanded investment security types. These amounts also include purchases and sales within our nuclear trusts.

Net Cash Flows Used For Investing Activities were $60 million in 2005 primarily due to the proceeds from the sale of HPL and STP, a portion of which we used to repurchase common stock and retire senior unsecured notes. Our Construction Expenditures of $1.6 billion included generation, environmental, transmission and distribution investment.

We forecast $3.5 billion of construction expenditures for 2007, which will be funded through results of operations and financing activities. These expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, legal reviews and the ability to access capital.

Financing Activities
   
Nine Months Ended
September 30,
 
   
2006
 
2005
 
   
(in millions)
 
Issuance of Common Stock
 
$
24
 
$
393
 
Repurchase of Common Stock
   
-
   
(427
)
Issuance/Retirement of Debt, Net
   
529
   
(562
)
Dividends Paid on Common Stock
   
(437
)
 
(408
)
Other
   
3
   
(106
)
Net Cash Flows From (Used for) Financing Activities
 
$
119
 
$
(1,110
)

Net Cash Flows From Financing Activities in 2006 were $119 million. During 2006, we issued $115 million of new obligations relating to pollution control bonds, issued $1 billion of senior unsecured notes and retired $396 million of senior unsecured notes for a net increase in senior unsecured notes outstanding of $604 million and retired $100 million of first mortgage bonds and $52 million of securitization bonds. See Note 13 for a complete discussion of long-term debt issuances and retirements.
 
Net Cash Flows Used For Financing Activities in 2005 were $1.1 billion. During 2005, we repurchased common stock and reduced outstanding long-term debt using the proceeds from the sale of HPL and the conversion of the equity units to common stock. In addition, our subsidiaries retired $66 million of cumulative preferred stock, which is reflected in the Other amount in the above table.  In addition to the equity unit conversion, we had limited stock issuances related to stock options exercised.

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 changed from year-end as follows:

   
September 30,
2006
 
December 31,
2005
 
   
(in millions)
 
AEP Credit
 
$
548
 
$
516
 
Rockport Plant Unit 2
   
2,437
   
2,511
 
Railcars
   
31
   
31
 

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

Summary Obligation Information

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

Other

Cook Plant Outage

In September 2006, Cook Plant Unit 1 began a regular scheduled refueling outage. This outage includes the replacement of major components, including the reactor vessel head. Installation of capital projects exceeding $100 million will be completed during this outage and were included in our capital forecast. The improvements and replacement of major components should increase unit capacity and efficiency. We expect to restart Cook Plant Unit 1 in early November 2006 as planned.  We refueled Cook Plant Unit 2 during March and April 2006 and plan to replace its vessel head during its next refueling outage in the fall of 2007.

Texas REPs

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

New Generation

In September 2005, PSO sought proposals for new peaking generation to be online in 2008 and in December 2005 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 neutral third parties. 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 PSO 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 July 2006, PSO announced plans to enter a joint venture with Oklahoma Gas and Electric Company (OG&E) where OG&E will construct and operate a new 950 MW coal-fueled electricity generating unit near Red Rock, Oklahoma. PSO will own 50% of the new unit. Preliminary cost estimates for 100% of the new facility are approximately $1.8 billion.

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 the existing Arsenal Hill Power Plant in Shreveport, Louisiana. SWEPCo also plans to build a new base load coal plant by 2011 in Hempstead County, Arkansas to meet the longer-term generation needs of its customers. Preliminary cost estimates for the new facilities are approximately $1.4 billion (this total excludes the related transmission investment).

The 2006 through 2008 estimated construction expenditures as disclosed in our 2005 Annual Report on Form 10-K included cost estimates for these new facilities. All new generation construction projects discussed above are subject to regulatory approvals from the various states in which the subsidiaries operate. Construction is expected to begin in 2007.

SIGNIFICANT FACTORS

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

ERCOT Transmission Project

In October 2006, we announced our intent to form a joint venture company to fund, own and operate new electric transmission assets in ERCOT and we signed a memorandum of understanding with MidAmerican Energy Holdings Co. (MidAmerican) as our joint venture partner. We will contribute Texas transmission assets currently under construction valued at approximately $100 million to the joint venture company. A MidAmerican subsidiary would make a cash contribution to the joint venture company. The equity ownership of the new company would be split 50-50 between AEP and MidAmerican with an anticipated utility capitalization structure targeted at 40 percent equity and 60 percent debt. The joint venture is anticipated to be active in 2007 and is subject to regulatory approval from the PUCT and the FERC.

We believe there is a high degree of regulatory certainty for transmission investment due to the predetermination of ERCOT’s need based on significant Texas economic growth as well as “green generation” initiatives. In addition, a streamlined annual interim transmission cost of service review process is available, which will help reduce regulatory lag. The use of a joint venture structure will allow us to reduce its up-front capital requirements for this type of significant investment while allowing us to participate in more 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 peak transfer capability by approximately 5,000 MW and reducing transmission line losses by up to 280 MW. It will also enhance reliability of the Eastern transmission grid. A new subsidiary, AEP Transmission Co., LLC, will own the line and undertake construction of the project. The projected cost for the project is approximately $3 billion, of which ownership may be shared with other third party participants. The project is subject to PJM, state and federal regulatory approvals and appropriate incentive cost recovery mechanisms. The projected in-service date is 2014, assuming three years to site and acquire rights-of-way and five years to construct the line. We were the first to file with the Department of Energy (DOE) seeking to have the proposed route designated a National Interest Electric Transmission Corridor (NIETC). The Energy Policy Act of 2005 provides for NIETC designation for areas experiencing electric energy transmission capacity constraints or congestion that adversely affects consumers. In August 2006, the DOE issued the “National Electric Transmission Congestion Study”. In this study, DOE indicated that the mid-Atlantic Coastal area, where the AEP Interstate Project is designed to reinforce, is one of the two most critical congestion areas in the nation. This finding should help AEP to obtain early National Interest Transmission Corridor Designation as promulgated by the National Energy Policy Act of 2005. In October 2006, both AEP and PJM filed comments with the DOE encouraging corridor designation that is consistent with the proposed line.
 
In July 2006, the FERC granted conditional approval for incentive rate treatment for the proposed line. The approval is conditioned upon the new line being included in PJM’s formal Regional Transmission Expansion Plan to be finalized later this year or in early 2007. The approved incentives include, (a) a return on equity set at the high end of the “zone of reasonableness”; (b) the option to timely recover the cost of capital associated with construction work in progress; and (c) the ability to defer expense and recover costs incurred during the pre-construction and pre-operating period. Since the FERC approved these rate making principles, we expect to implement the incentives in future FERC rate filings.

Texas Regulatory Activity

Texas Restructuring

In June 2006, TCC filed to implement a CTC refund of $357 million for its other true-up items over eight years. The differences between the components of TCC’s Recorded Net Regulatory Liabilities - Other True-up Items as of September 30, 2006 (including interest) and its Net CTC Refund Proposed request are detailed below:

   
(in millions)
 
Wholesale Capacity Auction True-up
 
$
61
 
Carrying Costs on Wholesale Capacity Auction True-up
   
31
 
Retail Clawback including Carrying Costs
   
(65
)
Deferred Over-recovered Fuel Balance
   
(184
)
Retrospective ADFIT Benefit
   
(77
)
Other
   
(4
)
Recorded Net Regulatory Liabilities - Other True-up Items
   
(238
)
Unrecorded Prospective ADFIT Benefit
   
(240
)
Gross CTC Refund Proposed
   
(478
)
FERC Jurisdictional Fuel Refund Deferral
   
16
 
ADITC and EDFIT Benefit Refund Deferral
   
98
 
Net CTC Refund Proposed, After Deferrals
   
(364
)
True-up Proceeding Expense Surcharge
   
7
 
Net CTC Refund Proposed, After Deferrals and Expenses
 
$
(357
)

In September 2006, the PUCT approved an interim CTC that was implemented on October 12, 2006, the same day that TCC began billing customers for the securitization bonds. The interim CTC will refund the entire retail clawback of $65 million (including carrying costs) by the end of 2006 to residential customers. The CTC refund to the other customer classes during the interim period will be as proposed by TCC, with the exception of the large industrials, who will not receive any fuel refunds during the interim period.

At an October 2006 open meeting, the PUCT announced oral decisions regarding the CTC refund. A final written order is expected in late November or early December of this year. In its decision, the PUCT confirmed that TCC can use securitization bond proceeds to make the CTC refund. The PUCT’s decision was to continue the interim CTC through December 2006 to complete the refund of the retail clawback over three months. Beginning in January 2007, the Deferred Over-recovered Fuel Balance will be refunded over six months with the large industrial customers receiving their entire refund in January 2007. Starting in July 2007, the remaining CTC items will be refunded over one year, except that the PUCT agreed with TCC’s request to defer the refund of the ADITC and EDFIT Benefit Refund Deferral and the FERC Jurisdictional Fuel Refund Deferral (see table above). The PUCT will decide those issues and related amounts in another proceeding.

Municipal customers and other intervenors appealed the PUCT orders seeking to further reduce TCC’s true-up recoveries. If we determine, as a result of future PUCT orders or appeal court rulings, that it is probable TCC cannot recover a portion of its recorded net true-up regulatory asset and we are able to estimate the amount of a resultant impairment, we would record a provision for such amount which would have an adverse effect on future results of operations, cash flows and possibly financial condition. TCC appealed the PUCT orders seeking relief in both state and federal court where it believes the PUCT’s rulings are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law.  The significant items appealed by TCC are:

·
the PUCT ruled that TCC did not comply with the statute and PUCT rules regarding the auction of 15% of its Texas jurisdictional installed capacity,
·
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 gas units with the sale of its coal unit,
·
and two federal matters regarding the allocation of off-system sales related to fuel recoveries and the potential tax normalization violation.
 
These appeals could take years to resolve and could result in material effects on future results of operations. If the PUCT rejects TCC’s deferral proposal and a normalization violation occurs, future results of operations and cash flows could be adversely affected by the recapture of $104 million of TCC’s ADITC and the loss by TCC of future accelerated tax depreciation election. The estimated future impact on earnings of the Texas Restructuring as of September 30, 2006, exclusive of a possible normalization violation and any effects of appeal litigation, over the 14-year securitization net recovery period assuming the PUCT approves TCC’s CTC filing, including the interim refund, is detailed below:

   
(in millions)
 
ADITC and EDFIT Benefits Reducing Securitization
 
$
98
 
ADFIT Benefit Applied to Reduce 2002 Securitization of Regulatory Assets
   
(60
)
Securitization Settlement
   
(77
)
Unrecorded Prospective ADFIT Benefit Increasing the CTC Refund
   
(240
)
Unrecorded Equity Carrying Costs Recognized as Collected
   
224
 
Future Interest Payable on Proposed CTC Refund
   
(19
)
Deferred Fuel - Federal Jurisdictional Issue
   
16
 
Net Adverse Earnings Impact Over 14 Years
 
$
(58
)

If the PUCT changes its oral decision regarding the proposed CTC deferral and the two contingent federal matters are refunded to customers, the future adverse impact on results of operations over the next 14 years will increase to $181 million. This potential adverse impact on results of operations over the next 14 years would be more than offset by the annual cost of money benefit from the $2.2 billion in net proceeds that resulted from the sale of bonds in connection with the initial regulatory asset securitization in 2002 of $797 million and from the $1.74 billion sale of securitization bonds in October 2006 less the proposed $357 million CTC refund over the next eight years.
 
Litigation

In the ordinary course of business, we and our subsidiaries are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases that have a probable likelihood of loss and the loss amount can be estimated. For details on our pending litigation and regulatory proceedings see Note 4 - Rate Matters, Note 6 - Customer Choice and Industry Restructuring, Note 7 - Commitments and Contingencies and the “Litigation” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2005 Annual Report. Additionally, see Note 3 - Rate Matters, Note 4 - Customer Choice and Industry Restructuring and Note 5 - Commitments and Contingencies included herein. 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 have committed to substantial capital investments and additional operational costs to comply with new environmental control requirements. The sources of these requirements include:

·
Requirements under the CAA to reduce emissions of SO2, NOx, particulate matter and mercury from fossil fuel-fired power plants;
·
Requirements under the Clean Water Act to reduce the impacts of water intake structures on aquatic species at certain of our power plants; and
·
Possible future requirements to reduce carbon dioxide emissions to address concerns about global climate change.

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

Environmental Litigation

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

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

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

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

Critical Accounting Estimates

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

Adoption of New Accounting Pronouncements

Beginning in 2006, we adopted SFAS No. 123 (revised 2004) Share-Based Payment, on a modified prospective basis, resulting in an insignificant favorable cumulative effect of a change in accounting principle. Including stock-based compensation expense related to employee stock options and other share based awards, did not materially affect our quarter-over-quarter and year-to-date net income and earnings per share. We have not granted options as part of our regular stock-based compensation program since 2003.  However, we have used options in limited circumstances totaling 149,000 options in 2004, 10,000 options in 2005 and none during 2006.  As of September 30, 2006, we have $49.1 million of total unrecognized compensation cost related to unvested share-based compensation arrangements. Our unrecognized compensation cost will be recognized over a weighted-average period of 1.57 years. See Note 2 - New Accounting Pronouncements in our Condensed Notes to Condensed Consolidated Financial Statements for further discussion.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

As a major power producer and marketer of wholesale electricity, coal and emission allowances, our Utility Operations segment is exposed to certain market risks. These risks include commodity price risk, interest rate risk and credit risk. In addition, we may be exposed to foreign currency exchange risk because occasionally we procure various services and materials 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.

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

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

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

We actively participate in the Committee of Chief Risk Officers (CCRO) to develop standard disclosures for risk management activities around risk management contracts. The CCRO is composed predominantly of chief risk officers of major electricity and gas companies in the United States. The CCRO adopted disclosure standards for risk management contracts to improve clarity, understanding and consistency of information reported. Implementation of the disclosures is voluntary. We support the work of the CCRO and have embraced the disclosure standards applicable to our business activities. The following tables provide information on our risk management activities.

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

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

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

   
Utility Operations
 
Investments - Gas Operations
 
Sub-Total MTM Risk Management Contracts
 
PLUS: MTM of Cash Flow and Fair Value Hedges
 
Total
 
Current Assets
 
$
444
 
$
99
 
$
543
 
$
26
 
$
569
 
Noncurrent Assets
   
337
   
130
   
467
   
4
   
471
 
Total Assets
   
781
   
229
   
1,010
   
30
   
1,040
 
                                 
Current Liabilities
   
(373
)
 
(99
)
 
(472
)
 
(24
)
 
(496
 )
Noncurrent Liabilities
   
(184
)
 
(137
)
 
(321
)
 
(3
)
 
(324
 )
Total Liabilities
   
(557
)
 
(236
)
 
(793
)
 
(27
)
 
(820
 )
                                 
Total MTM Derivative Contract Net Assets
  (Liabilities)
 
$
224
 
$
(7
)
$
217
 
$
3
 
$
220
 

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

   
Utility
Operations
 
Investments-Gas
Operations
 
Total
 
Total MTM Risk Management Contract Net Assets (Liabilities) at
  December 31, 2005
 
$
215
 
$
(19
)
$
196
 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
   
(8
)
 
10
   
2
 
Fair Value of New Contracts at Inception When Entered During the Period (a)
   
1
   
-
   
1
 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option
  Contracts Entered During The Period
   
(1
)
 
-
   
(1
)
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts
   
1
   
-
   
1
 
Changes in Fair Value due to Market Fluctuations During the Period (b)
   
19
   
2
   
21
 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
   
(3
)
 
-
   
(3
)
Total MTM Risk Management Contract Net Assets (Liabilities) at
  September 30, 2006
 
$
224
 
$
(7
)
 
217
 
Net Cash Flow and Fair Value Hedge Contracts
               
3
 
Ending Net Risk Management Assets at September 30, 2006
             
$
220
 

(a)
Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)
Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)
“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 Operations. These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions. Approximately $7 million of the regulatory deferral change is due to the change in the SIA. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
 
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets (Liabilities)

The following table presents:

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

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets (Liabilities)
Fair Value of Contracts as of September 30, 2006
(in millions)

   
Remainder
2006
 
2007
 
2008
 
2009
 
2010
 
After
2010
 
Total
 
Utility Operations:
                                    
Prices Actively Quoted -   Exchange Traded Contracts
 
$
-
 
$
(9
)
$
22
 
$
(1
)
$
-
 
$
-
 
$
12
 
Prices Provided by Other External
  Sources - OTC Broker Quotes (a)
   
(4
)
 
119
   
29
   
23
   
-
   
-
   
167
 
Prices Based on Models and Other Valuation Methods (b)
   
(1
)
 
(15
)
 
5
   
19
   
28
   
9
   
45
 
Total
 
$
(5
)
$
95
 
$
56
 
$
41
 
$
28
 
$
9
 
$
224
 
                                             
Investments - Gas Operations:
                                           
Prices Actively Quoted - Exchange Traded Contracts
 
$
-
 
$
7
 
$
-
 
$
-
 
$
-
 
$
-
 
$
7
 
Prices Provided by Other External
  Sources - OTC Broker Quotes (a)
   
(2
)
 
(4
)
 
-
   
-
   
-
   
-
   
(6
)
Prices Based on Models and Other Valuation Methods (b)
   
-
   
-
   
(2
)
 
(4
)
 
(3
)
 
1
   
(8
)
Total
 
$
(2
)
$
3
 
$
(2
)
$
(4
)
$
(3
)
$
1
 
$
(7
)
                                             
Total:
                                           
Prices Actively Quoted - Exchange Traded Contracts
 
$
-
 
$
(2
)
$
22
 
$
(1
)
$
-
 
$
-
 
$
19
 
Prices Provided by Other External
  Sources - OTC Broker Quotes (a)
   
(6
)
 
115
   
29
   
23
   
-
   
-
   
161
 
Prices Based on Models and Other Valuation Methods (b)
   
(1
)
 
(15
)
 
3
   
15
   
25
   
10
   
37
 
Total
 
$
(7
)
$
98
 
$
54
 
$
37
 
$
25
 
$
10
 
$
217
 

(a)
Prices Provided by Other External Sources - OTC Broker Quotes reflects information obtained from over-the-counter (OTC) brokers, industry services, or multiple-party on-line platforms.
(b)
Prices Based on Models and Other Valuation Methods is in the absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity is limited, such valuations are classified as modeled.
   
 
Contract values that are measured using models or valuation methods other than active quotes or OTC broker quotes (because of the lack of such data for all delivery quantities, locations and periods) incorporate in the model or other valuation methods, to the extent possible, OTC broker quotes and active quotes for deliveries in years and at locations for which such quotes are available.
 
The determination of the point at which a market is no longer liquid for placing it in the modeled category in the preceding table varies by market. The following table reports an estimate of the maximum tenors (contract maturities) of the liquid portion of each energy market.

Maximum Tenor of the Liquid Portion of Risk Management Contracts
As of September 30, 2006

Commodity
 
Transaction Class
 
Market/Region
 
Tenor
           
(in Months)
Natural Gas
 
Futures
 
NYMEX / Henry Hub
 
60
             
   
Physical Forwards
 
Gulf Coast, Texas
 
18
             
   
Swaps
 
Northeast, Mid-Continent, Gulf  Coast, Texas
 
18
             
   
Exchange Option Volatility
 
NYMEX / Henry Hub
 
12
             
Power
 
Futures
 
AEP East - PJM
 
36
             
   
Physical Forwards
 
AEP East
 
39
             
   
Physical Forwards
 
AEP West
 
39
             
   
Physical Forwards
 
West Coast
 
39
             
   
Peak Power Volatility (Options)
AEP East - Cinergy, PJM
 
12
             
Emissions
 
Credits
 
SO2, NOx
 
27
             
Coal
 
Physical Forwards
 
PRB, NYMEX, CSX
 
27

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

We are exposed to market fluctuations in energy commodity prices impacting our power and remaining gas operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

We employ the use of interest rate derivative transactions to manage interest rate risk related to existing variable rate debt and to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate exposure.
 
The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for changes in cash flow hedges from December 31, 2005 to September 30, 2006. The following table also indicates what portion of designated, effective hedges are expected to be reclassified into net income in the next 12 months. Only contracts designated as effective cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and are included in the previous risk management tables.

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

   
 Power and
Gas
 
 Interest
Rate
 
 Total
 
Beginning Balance in AOCI, December 31, 2005
 
$
(6
)
$
(21
)
$
(27
)
Changes in Fair Value
   
13
   
(3
)
 
10
 
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled
   
7
   
1
   
8
 
Ending Balance in AOCI, September 30, 2006
 
$
14
 
$
(23
)
$
(9
)
                     
After-Tax Portion Expected to be Reclassified to Earnings During Next 12 Months
 
$
15
 
$
(2
)
$
13
 

Credit Risk

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

We have risk management contracts with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily. As of September 30, 2006, our credit exposure net of credit collateral to sub investment grade counterparties was approximately 2.56%, expressed in terms of net MTM assets and net receivables. As of September 30, 2006, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable (in millions, except number of counterparties):

Counterparty Credit Quality
 
Exposure
Before
Credit
Collateral
 
Credit
Collateral
 
Net
Exposure
 
Number
of
Counterparties
>10%
 
Net Exposure
of
Counterparties
>10%
 
Investment Grade
 
$
802
 
$
140
 
$
662
   
1
 
$
70
 
Split Rating
   
4
   
4
   
-
   
1
   
-
 
Noninvestment Grade
   
15
   
15
   
-
   
2
   
-
 
No External Ratings:
                               
Internal Investment Grade
   
33
   
-
   
33
   
3
   
21
 
Internal Noninvestment Grade
   
40
   
22
   
18
   
3
   
17
 
Total as of September 30, 2006
 
$
894
 
$
181
 
$
713
   
10
 
$
108
 
                                 
As of December 31, 2005
 
$
1,366
 
$
484
 
$
882
   
10
 
$
322
 

Generation Plant Hedging Information

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

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

 
Remainder
2006
 
2007
 
2008
Estimated Plant Output Hedged
91%
 
88%
 
87%


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 September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

VaR Model

Nine Months Ended
September 30, 2006
       
Twelve Months Ended
December 31, 2005
(in millions)
       
(in millions)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
$2
 
$10
 
$3
 
$1
       
$3
 
$5
 
$3
 
$1

The High VaR for the nine months ended September 30, 2006 occurred in mid-August during a period of high gas and power price 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 $550 million at September 30, 2006 and $615 million at December 31, 2005. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not materially affect our results of operations, cash flows or financial position.




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

   
Three Months Ended
 
Nine Months Ended
 
   
2006
 
2005
 
2006
 
2005
 
REVENUES
                   
Utility Operations
 
$
3,485
 
$
3,152
 
$
9,282
 
$
8,437
 
Gas Operations
   
(47
)
 
73
   
(80
)
 
449
 
Other
   
156
   
103
   
436
   
326
 
TOTAL
   
3,594
   
3,328
   
9,638
   
9,212
 
                           
EXPENSES
                         
Fuel and Other Consumables Used for Electric Generation
   
1,113
   
1,066
   
2,962
   
2,659
 
Purchased Energy for Resale
   
267
   
181
   
670
   
494
 
Purchased Gas for Resale
   
4
   
5
   
4
   
255
 
Maintenance and Other Operation
   
904
   
873
   
2,634
   
2,588
 
Gain/Loss on Disposition of Assets, Net
   
-
   
(1
)
 
(68
)
 
(116
)
Asset Impairments and Other Related Charges
   
209
   
39
   
209
   
39
 
Depreciation and Amortization
   
376
   
336
   
1,065
   
988
 
Taxes Other Than Income Taxes
   
186
   
205
   
567
   
566
 
TOTAL
   
3,059
   
2,704
   
8,043
   
7,473
 
                           
OPERATING INCOME
   
535
   
624
   
1,595
   
1,739
 
                           
Interest and Investment Income
   
22
   
18
   
41
   
43
 
Carrying Costs Income
   
3
   
27
   
66
   
83
 
Allowance For Equity Funds Used During Construction
   
12
   
5
   
25
   
17
 
Gain on Disposition of Equity Investments, Net
   
-
   
56
   
3
   
56
 
Investment Value Losses
   
-
   
(7
)
 
-
   
(7
)
                           
INTEREST AND OTHER CHARGES
                         
Interest Expense
   
174
   
163
   
518
   
524
 
Preferred Stock Dividend Requirements of Subsidiaries
   
1
   
1
   
2
   
6
 
TOTAL
   
175
   
164
   
520
   
530
 
                           
INCOME BEFORE INCOME TAX EXPENSE, MINORITY   INTEREST EXPENSE AND EQUITY EARNINGS
   
397
   
559
   
1,210
   
1,401
 
                           
Income Tax Expense
   
133
   
196
   
394
   
471
 
Minority Interest Expense
   
1
   
1
   
2
   
3
 
Equity Earnings of Unconsolidated Subsidiaries
   
2
   
3
   
1
   
10
 
                           
INCOME BEFORE DISCONTINUED OPERATIONS
   
265
   
365
   
815
   
937
 
                           
DISCONTINUED OPERATIONS, Net of Tax
   
-
   
22
   
6
   
26
 
                           
NET INCOME
 
$
265
 
$
387
 
$
821
 
$
963
 
                           
WEIGHTED AVERAGE NUMBER OF BASIC SHARES   OUTSTANDING
   
394
   
389
   
394
   
389
 
                           
BASIC EARNINGS PER SHARE
                         
Income Before Discontinued Operations
 
$
0.67
 
$
0.94
 
$
2.07
 
$
2.41
 
Discontinued Operations, Net of Tax
   
-
   
0.05
   
0.01
   
0.07
 
TOTAL BASIC EARNINGS PER SHARE
 
$
0.67
 
$
0.99
 
$
2.08
 
$
2.48
 
                           
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES   OUTSTANDING
   
396
   
390
   
396
   
390
 
                           
DILUTED EARNINGS PER SHARE
                         
Income Before Discontinued Operations
 
$
0.67
 
$
0.94
 
$
2.06
 
$
2.40
 
Discontinued Operations, Net of Tax
   
-
   
0.05
   
0.01
   
0.07
 
TOTAL DILUTED EARNINGS PER SHARE
 
$
0.67
 
$
0.99
 
$
2.07
 
$
2.47
 
                           
CASH DIVIDENDS PAID PER SHARE
 
$
0.37
 
$
0.35
 
$
1.11
 
$
1.05
 
                           
See Condensed Notes to Condensed Consolidated Financial Statements.



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2006 and December 31, 2005
(in millions)
(Unaudited)

   
2006
 
2005
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
259
 
$
401
 
Other Temporary Cash Investments
   
198
   
127
 
Accounts Receivable:
             
Customers
   
751
   
826
 
Accrued Unbilled Revenues
   
314
   
374
 
Miscellaneous
   
52
   
51
 
Allowance for Uncollectible Accounts
   
(34
)
 
(31
)
  Total Receivables
   
1,083
   
1,220
 
Fuel, Materials and Supplies
   
810
   
726
 
Risk Management Assets
   
569
   
926
 
Margin Deposits
   
90
   
221
 
Regulatory Asset for Under-Recovered Fuel Costs
   
66
   
197
 
Other
   
100
   
127
 
TOTAL
   
3,175
   
3,945
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
16,712
   
16,653
 
Transmission
   
6,952
   
6,433
 
Distribution
   
11,179
   
10,702
 
Other (including coal mining and nuclear fuel)
   
3,277
   
3,116
 
Construction Work in Progress
   
2,848
   
2,217
 
Total
   
40,968
   
39,121
 
Accumulated Depreciation and Amortization
   
15,146
   
14,837
 
TOTAL - NET
   
25,822
   
24,284
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
3,196
   
3,262
 
Securitized Transition Assets and Other
   
558
   
593
 
Spent Nuclear Fuel and Decommissioning Trusts
   
1,191
   
1,134
 
Investments in Power and Distribution Projects
   
45
   
97
 
Goodwill
   
76
   
76
 
Long-term Risk Management Assets
   
471
   
886
 
Employee Benefits and Pension Assets
   
1,059
   
1,105
 
Other
   
682
   
746
 
TOTAL
   
7,278
   
7,899
 
               
Assets Held for Sale
   
110
   
44
 
               
TOTAL ASSETS
 
$
36,385
 
$
36,172
 

See Condensed Notes to Condensed Consolidated Financial Statements.



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2006 and December 31, 2005
(Unaudited)


   
2006
 
2005
 
CURRENT LIABILITIES
 
(in millions)
 
Accounts Payable
$
1,180
 
$
1,144
 
Short-term Debt
 
23
   
10
 
Long-term Debt Due Within One Year
 
1,789
   
1,153
 
Risk Management Liabilities
 
496
   
906
 
Accrued Taxes
 
828
   
651
 
Accrued Interest
 
192
   
183
 
Customer Deposits
 
336
   
571
 
Other
 
752
   
842
 
TOTAL
 
5,596
   
5,460
 
             
NONCURRENT LIABILITIES
           
Long-term Debt
 
10,974
   
11,073
 
Long-term Risk Management Liabilities
 
324
   
723
 
Deferred Income Taxes
 
4,673
   
4,810
 
Regulatory Liabilities and Deferred Investment Tax Credits
 
2,955
   
2,747
 
Asset Retirement Obligations
 
975
   
936
 
Employee Benefits and Pension Obligations
 
349
   
355
 
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2
 
150
   
157
 
Deferred Credits and Other
 
803
   
762
 
TOTAL
 
21,203
   
21,563
 
             
TOTAL LIABILITIES
 
26,799
   
27,023
 
             
Cumulative Preferred Stock Not Subject to Mandatory Redemption
 
61
   
61
 
             
Commitments and Contingencies (Note 5)
           
             
COMMON SHAREHOLDERS’ EQUITY
           
Common Stock Par Value $6.50:
           
     
2006
   
2005
             
Shares Authorized
   
600,000,000
   
600,000,000
             
Shares Issued
   
415,979,691
   
415,218,830
             
(21,499,992 shares were held in treasury at September 30, 2006 and December 31, 2005)
 
2,704
   
2,699
 
Paid-in Capital
 
4,153
   
4,131
 
Retained Earnings
 
2,669
   
2,285
 
Accumulated Other Comprehensive Income (Loss)
 
(1
)
 
(27
)
TOTAL
 
9,525
   
9,088
 
             
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
$
36,385
 
$
36,172
 

   See Condensed Notes to Condensed Consolidated Financial Statements.



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2006 and 2005
(in millions)
(Unaudited)
   
2006
 
2005
 
OPERATING ACTIVITIES
           
Net Income
 
$
821
 
$
963
 
Less: Discontinued Operations, Net of Tax
   
(6
)
 
(26
)
Income Before Discontinued Operations
   
815
   
937
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
1,065
   
988
 
Accretion of Asset Retirement Obligations
   
47
   
50
 
Deferred Income Taxes
   
(88
)
 
(33
)
Deferred Investment Tax Credits
   
(20
)
 
(23
)
Asset Impairments, Investment Value Losses and Other Related Charges
   
209
   
46
 
Carrying Costs Income
   
(66
)
 
(83
)
Mark-to-Market of Risk Management Contracts
   
(21
)
 
-
 
Amortization of Nuclear Fuel
   
38
   
42
 
Deferred Property Taxes
   
105
   
94
 
Pension Contributions to Qualified Plan Trusts         (306 )
Fuel Over/Under-Recovery, Net
   
158
   
(183
)
Gain on Sales of Assets and Equity Investments, Net
   
(71
)
 
(172
)
Change in Other Noncurrent Assets
   
72
   
(84
)
Change in Other Noncurrent Liabilities
   
(21
)
 
34
 
Changes in Certain Components of Working Capital:
             
Accounts Receivable, Net
   
139
   
5
 
Fuel, Materials and Supplies
   
(84
)
 
54
 
Accounts Payable
   
(49
)
 
173
 
Accrued Taxes
   
176
   
118
 
Customer Deposits
   
(235
)
 
311
 
Other Current Assets
   
142
   
(246
)
Other Current Liabilities
   
(98
)
 
(23
)
Net Cash Flows From Operating Activities
   
2,213
   
1,699
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(2,445
)
 
(1,610
)
Acquisition of Waterford Plant
   
-
   
(218
)
Change in Other Temporary Cash Investments, Net
   
20
   
99
 
Purchases of Investment Securities
   
(8,153
)
 
(4,319
)
Sales of Investment Securities
   
8,056
   
4,378
 
Proceeds from Sales of Assets
   
120
   
1,599
 
Other
   
(72
)
 
11
 
Net Cash Flows Used For Investing Activities
   
(2,474
)
 
(60
)
               
FINANCING ACTIVITIES
             
Issuance of Common Stock
   
24
   
393
 
Repurchase of Common Stock
   
-
   
(427
)
Change in Short-term Debt, Net
   
11
   
(8
)
Issuance of Long-term Debt
   
1,229
   
2,045
 
Retirement of Long-term Debt
   
(711
)
 
(2,599
)
Dividends Paid on Common Stock
   
(437
)
 
(408
)
Other
   
3
   
(106
)
Net Cash Flows From (Used For) Financing Activities
   
119
   
(1,110
)
               
Net Increase (Decrease) in Cash and Cash Equivalents
   
(142
)
 
529
 
Cash and Cash Equivalents at Beginning of Period
   
401
   
320
 
Cash and Cash Equivalents at End of Period
 
$
259
 
$
849
 
               
SUPPLEMENTARY INFORMATION
             
Cash Paid for Interest, Net of Capitalized Amounts
 
$
462
 
$
492
 
Net Cash Paid for Income Taxes
   
206
   
277
 
Noncash Acquisitions Under Capital Leases
   
66
   
42
 
Construction Expenditures Included in Accounts Payable at September 30,
   
334
   
182
 
Disposition of Liabilities Related to Acquisitions/Divestitures, Net
   
-
   
20
 
 
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 Nine Months Ended September 30, 2006 and 2005
(in millions)
(Unaudited)
 
   
Common Stock
         
Accumulated
     
   
Shares
 
Amount
 
Paid-in Capital
 
Retained
Earnings
 
Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2004
   
405
 
$
2,632
 
$
4,203
 
$
2,024
 
$
(344
)
$
8,515
 
Issuance of Common Stock
   
10
   
65
   
328
               
393
 
Common Stock Dividends
                     
(408
)
       
(408
)
Repurchase of Common Stock
               
(427
)
             
(427
)
Other
               
17
               
17
 
TOTAL
                                 
8,090
 
                                       
COMPREHENSIVE INCOME
                                     
Other Comprehensive Income (Loss),   Net of Tax:
                                     
Foreign Currency Translation Adjustments,
    Net of Tax of $0
                           
(6
)
 
(6
)
Cash Flow Hedges, Net of Tax of $36
                           
(67
)
 
(67
)
Minimum Pension Liability, Net of Tax of $0
                           
4
   
4
 
Securities Available for Sale, Net of Tax of $0
                           
1
   
1
 
NET INCOME
                     
963
         
963
 
TOTAL COMPREHENSIVE INCOME
                                 
895
 
SEPTEMBER 30, 2005
   
415
 
$
2,697
 
$
4,121
 
$
2,579
 
$
(412
)
$
8,985
 
                                       
DECEMBER 31, 2005
   
415
 
$
2,699
 
$
4,131
 
$
2,285
 
$
(27
)
$
9,088
 
Issuance of Common Stock
   
1
   
5
   
19
               
24
 
Common Stock Dividends
                     
(437
)
       
(437
)
Other
               
3
               
3
 
TOTAL
                                 
8,678
 
                                       
COMPREHENSIVE INCOME
                                     
Other Comprehensive Income, Net of Tax:
                                     
Cash Flow Hedges, Net of Tax of $10
                           
18
   
18
 
Securities Available for Sale, Net of Tax of $4
                           
8
   
8
 
NET INCOME
                     
821
         
821
 
TOTAL COMPREHENSIVE INCOME
                                 
847
 
SEPTEMBER 30, 2006
   
416
 
$
2,704
 
$
4,153
 
$
2,669
 
$
(1
)
$
9,525
 

   See Condensed Notes to Condensed Consolidated Financial Statements.



AMERICAN ELECTRIC POWER, 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.
 
Customer Choice and Industry Restructuring
 5.
 
Commitments and Contingencies
 6.
 
Guarantees
 7.
 
Company-wide Staffing and Budget Review
8.
 
Acquisitions, Dispositions, Discontinued Operations, Assets Held for Sale and Asset Impairments
9.
 
Benefit Plans
10.
 
Stock-Based Compensation
11.
 
Income Taxes
12.
 
Business Segments
13.
 
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 Securities and Exchange Commission (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 and nine months ended September 30, 2006 are not necessarily indicative of results that may be expected for the year ending December 31, 2006. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2005 consolidated financial statements and notes thereto, which are included in our Annual Report on Form 10-K for the year ended December 31, 2005 as filed with the SEC on March 1, 2006.

Components of Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss) is included on our Condensed Consolidated Balance Sheets in the common shareholders’ equity section. The following table provides the components that constitute the balance sheet amount in Accumulated Other Comprehensive Income (Loss):

   
September 30,
 
December 31,
 
   
2006
 
2005
 
Components
 
(in millions)
 
Securities Available for Sale, Net of Tax
 
$
27
 
$
19
 
Cash Flow Hedges, Net of Tax
   
(9
)
 
(27
)
Minimum Pension Liability, Net of Tax
   
(19
)
 
(19
)
Total
 
$
(1
)
$
(27
)

At September 30, 2006, we expect to reclassify approximately $13 million of net gains from cash flow hedges in Accumulated Other Comprehensive Income (Loss) to Net Income during the next twelve months at the time the hedged transactions affect Net Income. The actual amounts that are reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ as a result of market fluctuations.

At September 30, 2006, 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.

Stock-Based Compensation Plans 

At September 30, 2006, we have options outstanding under two stock-based employee compensation plans: The Amended and Restated American Electric Power System Long-Term Incentive Plan and the Central and South West Corporation Long-Term Incentive Plan. We also grant performance share units, phantom stock units, restricted shares and restricted stock units to employees, in accordance with plans previously approved by shareholder votes.

On January 1, 2006, we adopted SFAS No. 123 (revised 2004), “Share-Based Payment,” (SFAS 123R) which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors including stock options and employee stock purchases based on estimated fair values. See the SFAS 123 (revised 2004) “Share-Based Payment” section of Note 2 for additional discussion.

In conjunction with the adoption of SFAS 123R, we changed our method of attributing the value of stock-based compensation to expense from the accelerated multiple-option approach to the straight-line single-option method. Compensation expense for all share-based payment awards granted prior to January 1, 2006 will continue to be recognized using the accelerated multiple-option approach while compensation expense for all share-based payment awards granted on or after January 1, 2006 is recognized using the straight-line single-option method. As stock-based compensation expense recognized in our Condensed Consolidated Statements of Operations for the three and nine months periods ended September 30, 2006 is based on awards ultimately expected to vest, it has been reduced for estimated forfeitures. SFAS 123R requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. In our pro forma information presented below as required under SFAS 123 for the periods prior to 2006, we accounted for forfeitures as they occurred.

For the three and nine months ended September 30, 2005, no stock option expense was reflected in Net Income as we accounted for stock options using the intrinsic value method under Accounting Principles Board (APB) Opinion No. 25, “Accounting For Stock Issued to Employees.” Under the intrinsic value method, no stock option expense is recognized when the exercise price of the stock options granted equals the fair value of the underlying stock at the date of grant. During the first nine months of 2005 the Board of Directors granted 10,000 options. For the three and nine months ended September 30, 2006 and 2005, compensation cost is included in Net Income for the performance share units, phantom stock units, restricted shares, restricted stock units and the Director’s stock units. See Note 10 for additional discussion.

Pro Forma Information Under SFAS 123, “Accounting for Stock-Based Compensation,” for Periods Presented Prior to January 1, 2006

The following table shows the effect on our Net Income and Earnings Per Share as if we had applied fair value measurement and recognition provisions of SFAS 123 to stock-based employee and director compensation awards for the three and nine months ended September 30, 2005:

   
Three Months
Ended
 
Nine Months
Ended
 
   
(in millions, except per share data)
 
             
Net Income, As Reported
 
$
387
 
$
963
 
Add: Stock-based Compensation Expense Included in Reported Net Income, Net of Related Tax Effects
   
4
   
10
 
Deduct: Stock-based Compensation Expense Determined Under Fair Value Based Method for All Awards,
  Net of Related Tax Effects
   
(5
)
 
(11
)
Pro Forma Net Income
 
$
386
 
$
962
 
               
Earnings Per Share:
             
Basic - As Reported
 
$
0.99
 
$
2.48
 
Basic - Pro Forma (a)
 
$
0.99
 
$
2.48
 
               
Diluted - As Reported
 
$
0.99
 
$
2.47
 
Diluted - Pro Forma (a)
 
$
0.99
 
$
2.47
 

(a)
The pro forma amounts are not representative of the effects on reported net income for future years.
 
Earnings Per Share (EPS)

The following table presents our basic and diluted Earnings Per Share (EPS) calculations included in our Condensed Consolidated Statements of Operations:

   
Three Months Ended September 30,
 
   
2006
 
2005
 
   
(in millions, except per share data)
 
        
$/share
      
$/share
 
Earnings applicable to common stock
 
$
265
       
$
387
       
                           
Average number of basic shares outstanding
   
393.9
 
$
0.67
   
388.9
 
$
0.99
 
Average dilutive effect of:
                         
Performance Share Units
   
2.0
   
-
   
1.0
   
-
 
Stock Options
   
0.2
   
-
   
0.5
   
-
 
Restricted Stock Units
   
0.1
   
-
   
0.1
   
-
 
Restricted Shares
   
0.1
   
-
   
-
   
-
 
Average number of diluted shares outstanding
   
396.3
 
$
0.67
   
390.5
 
$
0.99
 

   
Nine Months Ended September 30,
 
   
2006
 
2005
 
   
(in millions, except per share data)
 
        
$/share
      
$/share
 
Earnings applicable to common stock
 
$
821
       
$
963
       
                           
Average number of basic shares outstanding
   
393.8
 
$
2.08
   
388.7
 
$
2.48
 
Average dilutive effect of:
                         
Performance Share Units
   
1.6
   
(0.01
)
 
0.9
   
(0.01
)
Stock Options
   
0.2
   
-
   
0.3
   
-
 
Restricted Stock Units
   
0.1
   
-
   
0.1
   
-
 
Restricted Shares
   
0.1
   
-
   
-
   
-
 
Average number of diluted shares outstanding
   
395.8
 
$
2.07
   
390.0
 
$
2.47
 

Our stock option and other equity compensation plans are discussed in Note 10.

Related Party Transactions

   
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
   
2006
 
2005
 
2006
 
2005
 
   
(in millions)
 
AEP Consolidated Purchased Energy:
     
  Ohio Valley Electric Corporation (43.47% Owned)
 
$
54
 
$
49
 
$
167
 
$
140
 
  Sweeny Cogeneration Limited Partnership (50% Owned)
   
30
   
38
   
92
   
98
 
AEP Consolidated Other Revenues - Barging and Other   Transportation Services - Ohio Valley Electric Corporation   (43.47% Owned)
   
8
   
6
   
23
   
14
 

Reclassifications

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

On our Condensed Consolidated Statements of Cash Flows, we included purchases and sales of investments within our Spent Nuclear Fuel and Decommissioning Trusts as a component of Investing Activities rather than Operating Activities.
 
         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 2006 that we determined relate to our operations.

SFAS 123 (revised 2004) “Share-Based Payment” (SFAS 123R)

In December 2004, the FASB issued SFAS 123R. SFAS 123R requires entities to recognize compensation expense in an amount equal to the fair value of share-based payments granted to employees. The statement eliminates the alternative to use the intrinsic value method of accounting previously available under Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.” We recorded an insignificant cumulative effect of a change in accounting principle in the first quarter of 2006 for the effect of initially applying the statement primarily reflected in Maintenance and Other Operation on our Condensed Consolidated Statements of Operations.

In March 2005, the SEC issued Staff Accounting Bulletin (SAB) No. 107, “Share-Based Payment” (SAB 107), which conveys the SEC staff’s views on the interaction between SFAS 123R and certain SEC rules and regulations. SAB 107 also provides the SEC staff’s views regarding the valuation of share-based payment arrangements for public companies. Also, the FASB issued three FASB Staff Positions (FSP) during 2005 and one in February 2006 that provided additional implementation guidance. We applied the principles of SAB 107 and the applicable FSPs in conjunction with our adoption of SFAS 123R.

We adopted SFAS 123R in the first quarter of 2006 using the modified prospective method. This method requires us to record compensation expense for all awards granted after the time of adoption and recognize the unvested portion of previously granted awards that remain outstanding at the time of adoption as the requisite service is rendered. The compensation cost is based on the grant-date fair value of the equity award. Stock-based compensation expense recognized during the period is based on the value of the portion of share-based payment awards that is ultimately expected to vest during the period. Stock-based compensation expense recognized in our Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2006 includes compensation expense for share-based payment awards granted prior to, but not yet vested as of, January 1, 2006 based on the grant date fair value estimated in accordance with the pro forma provisions of SFAS 123 and compensation expense for the share-based payment awards granted subsequent to January 1, 2006 based on the grant date fair value estimated in accordance with the provisions of SFAS 123R. Our implementation of SFAS 123R did not materially affect our results of operations, cash flows or financial condition.

SFAS 157 “Fair Value Measurements”

In September 2006, the FASB issued SFAS 157. SFAS 157 enhances existing guidance for fair value measurement of assets and liabilities as well as instruments measured at fair value that are classified in shareholders’ equity. SFAS 157 defines fair value, establishes a fair value measurement framework and expands fair value disclosures. SFAS 157 emphasizes that fair value is market-based with the highest measurement hierarchy being market prices in active markets. The standard will change current practice and requires fair value measurements be disclosed by hierarchy level. SFAS 157 requires 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 are currently in the process of determining the effect this standard will have on our financial statements. Although SFAS 157 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. SFAS 157 will be effective for us starting January 1, 2008.
 
SFAS 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”

In September 2006, the FASB issued SFAS 158. SFAS 158 amends previous standards. It requires employers to fully recognize the obligations associated with defined benefit pension, retiree healthcare and other postretirement (OPEB) plans in their balance sheets. Previous standards required an employer to disclose the complete funded status of its plan only in the notes to the financial statements and provided that an employer delay recognition of certain changes in plan assets and obligations that affected the costs of providing benefits resulting in an asset or liability that often differed from the plan’s funded status. SFAS 158 requires a defined benefit pension or postretirement plan sponsor (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for the plan’s underfunded status, (b) measure the plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year (with limited exceptions), and (c) recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year but are not recognized as a component of net periodic benefit cost pursuant to SFAS 87, “Employers’ Accounting for Pensions,” or SFAS 106, “Employer’s Accounting for Postretirement Benefits Other Than Pensions.” It also requires an employer to disclose additional information on how delayed recognition of certain changes in the funded status of a defined benefit postretirement plan affects net periodic benefit costs for the next fiscal year.

The effect of SFAS 158 is to adjust AOCI at the end of each year, for both underfunded and overfunded pension and OPEB plans, to an amount equal to the remaining unrecognized SFAS 87 and SFAS 106 deferrals for unamortized actuarial losses or gains, prior service costs, or transition obligations, such that remaining deferred costs result in an AOCI equity reduction and deferred gains result in an AOCI equity addition.

The year-end AOCI measure is volatile based on fluctuating investment returns and discount rates. Favorable changes include higher returns that increase plan assets and higher discount rates that reduce the discounted benefit obligation.

SFAS 158 is effective for initial recognition of a defined benefit postretirement plan and related disclosure for fiscal years ending after December 15, 2006. We have not completed the process of determining the effect of this standard on our financial statements, including whether a portion of the adjustment required by SFAS 158 can be deferred as a regulatory asset under SFAS 71.

EITF Issue 06-3 “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)” (EITF 06-3)

In June 2006, the EITF reached a consensus on the income statement presentation of various types of taxes. The scope of this issue includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value added, and some excise taxes. The presentation of taxes within the scope of this issue on either a gross (included in revenues and costs) or a net (excluded from revenues) basis is an accounting policy decision that should be disclosed pursuant to APB Opinion No. 22, “Disclosure of Accounting Policies.” The EITF’s decision on gross/net presentation requires that any such taxes reported on a gross basis be disclosed on an aggregate basis in interim and annual financial statements, for each period for which an income statement is presented, if those amounts are significant.

EITF 06-3 is effective for fiscal years beginning after December 15, 2006. As disclosed in Note 1 of the 2005 Annual Report, we act as an agent for some state and local governments and collect from customers certain excise taxes levied by those state or local governments on our customers. Our policy is to present these taxes on a net basis and we do not recognize these taxes as revenues or expenses. Therefore, this issue will not have a material impact on our financial statements.
 
FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (FIN 48)

In July 2006, the FASB issued FIN 48 which clarifies the application of SFAS 109, “Accounting for Income Taxes.” 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. FIN 48 is effective for fiscal years beginning after December 15, 2006. We have not completed the process of determining the effect of this interpretation on our financial statements.

SAB No. 108 “Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in the Current Year Financial Statements” (SAB 108)

In September 2006, the SEC staff issued SAB 108. SAB 108 addresses the diversity in practice when quantifying the effect of an error on financial statements. SAB 108 provides guidance on the consideration of the effects of prior year misstatements in quantifying misstatements in current year financial statements. We will be required to adopt the provisions of SAB 108 effective December 31, 2006. We believe that the adoption of SAB 108 will not have a material impact on our financial statements.

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, 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 2005 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and state commissions. The Rate Matters note within our 2005 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 and cash flows. Rate matters that are not believed to be reasonably likely to affect future results of operations and cash flows are not included in this report or the 2005 Annual Report. The following sections discuss ratemaking developments in 2006 and update the 2005 Annual Report.

APCo Virginia Environmental and Reliability Costs

The Virginia Electric Restructuring Act (the statute) includes a provision that permits recovery, during the extended capped rate period ending December 31, 2010, of incremental environmental compliance and transmission and distribution (T&D) system reliability (E&R) costs prudently incurred on and after July 1, 2004. In 2005, APCo filed a request with the Virginia SCC and updated it through supplemental testimony seeking recovery of $21 million of incremental E&R costs incurred from July 2004 through September 2005. Through August 31, 2006, APCo deferred as a regulatory asset $47 million of incremental E&R costs incurred since July 1, 2004 based on a legal opinion that such costs were probable of recovery under the law.
 
In January 2006, the Virginia SCC staff proposed that APCo be allowed to increase its electric rates at an ongoing level of $20 million to recover current, rather than past, incremental E&R costs. The staff proposal would effectively disallow the recovery of costs incurred prior to the authorization and implementation of new rates, including all incremental E&R costs that were deferred as a regulatory asset. At the E&R hearings, which concluded in March 2006, the staff amended its testimony to recommend a $24 million increase in APCo’s ongoing rates. In September 2006, the Hearing Examiner issued a report recommending adoption of the staff proposal with minor modifications, which would result in (a) an on-going level of E&R cost recovery of $29 million only if the Virginia SCC decides that any rate increase from the base rate case (described below) does not include the $29 million ongoing level of E&R costs, and (b) the disallowance of all previously deferred incremental E&R costs. In the third quarter of 2006, we concluded that the Virginia SCC might not grant recovery of actual incremental E&R costs incurred during the period from July 2004 through September 2006. Accordingly, we wrote off all of the E&R regulatory asset, adversely affecting pretax earnings by $36 million, net of the reinstatement of related AFUDC and capitalized interest. We believe that the staff’s proposal and the Hearing Examiner’s recommendation are contrary to the statute. The Virginia SCC’s final order in this proceeding is pending.

If the Virginia SCC properly implements the statute as interpreted in its October 2005 order and as supported by the Virginia Attorney General’s office in October 2006, we should be able to recover all of our incremental E&R costs prudently incurred since July 1, 2004. If the Virginia SCC adopts the Hearing Examiner's findings, based on advice of counsel, we will appeal the decision.

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 adjusted annually. APCo also proposed to share the off-system sales margins with the customers with 40% going to reduce rates and 60% being retained by APCo. This resultant 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 revenues of $198 million. The major components of the $225 million 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 October 2, 2006, subject to refund. In October 2006, the Virginia SCC staff filed their direct testimony recommending a base rate increase of $13 million. Other intervenors have recommended base rate increases ranging from $42 million to $112 million. APCo plans to file rebuttal testimony in November 2006. Hearings are scheduled to begin in December 2006. We are unable to predict the ultimate effect of this filing on future revenues, cash flows and financial condition.

APCo and WPCo West Virginia Rate Case

In July 2006, the WVPSC approved the settlement agreement APCo and WPCo reached with the WVPSC staff and intervenors in the West Virginia rate case filed in 2005. The settlement agreement provided for an initial overall increase in rates of $44 million effective July 28, 2006 comprised of:

·
A $56 million increase in Expanded Net Energy Cost (ENEC) for fuel, purchased power expenses, off system sales credits and other energy related costs;
·
A $23 million special construction surcharge providing recovery of the costs of scrubbers and the new Wyoming-Jacksons Ferry 765 kV line to date;
·
An $18 million general base rate reduction resulting predominantly from a reduction in the return on equity to 10.5% and a $9 million reduction in depreciation expense which affects cash flows but not earnings; and
·
A $17 million credit to refund a portion of deferred prior over-recoveries of ENEC of $51 million, recorded in regulatory liabilities on the Condensed Consolidated Balance Sheets, which will impact cash flows but not earnings.
 
In addition, the agreement provides a surcharge mechanism that allows APCo and WPCo to adjust their rates annually for the timely recovery in each of the next three years of the incremental cost of ongoing environmental investments in scrubbers at APCo’s Mountaineer and John Amos power plants and the costs of the new Wyoming-Jacksons Ferry 765 kV line. Although the amount of these annual surcharge increases cannot be determined until the incremental costs are known and reviewed by the WVPSC, APCo estimates that they will result in an annual increase in revenues of $36 million effective July 1, 2007, $14 million effective July 1, 2008 and $18 million effective July 1, 2009.

The settlement further provides for the reinstatement of the ENEC mechanism effective July 1, 2006 with over/under recovery deferral accounting and annual ENEC proceedings to affect annual rate adjustments for changes in fuel and purchased power costs beginning in 2007. The settlement provides for the return to customers of the remaining $34 million of the prior ENEC regulatory liability plus interest at a LIBOR rate on the unrefunded balance in future ENEC proceedings.
 
I&M Depreciation Study Filing

In December 2005, I&M filed a petition with the IURC seeking authorization to revise its book depreciation rates applicable to its electric utility plant in service effective January 1, 2006. Based on a depreciation study included in the filing, I&M recommended a decrease in pretax annual depreciation expense of approximately $69 million on an Indiana jurisdictional basis 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. A public hearing was held in May 2006 and the final brief was filed in June 2006. As proposed by I&M, the book depreciation expense reduction would increase earnings, but would not impact cash flows until electric service rates are revised.

An order issued by the IURC on October 19, 2006 does not dispute our revised depreciation accounting rates but, nevertheless, the IURC denied I&M's request to revise its book depreciation rates between base rate cases. The IURC believes that depreciation rates for an electric utility should not be changed between general rate cases unless it was “absolutely essential” and a direct benefit to customers was shown. I&M has twenty days in which to file for a rehearing or reconsideration. We have not yet decided whether we will file for a rehearing or reconsideration or if and when we will file to adjust base rates to reflect the depreciation study.

KPCo Rate Filing

In March 2006, the KPSC approved the settlement agreement in KPCo’s 2005 base rate case. The approved agreement provides for a $41 million annual increase in revenues effective on March 30, 2006 and the retention of the existing environmental surcharge tariff. No return on equity is specified by the settlement terms except to note that KPCo will use a 10.5% return on equity to calculate the environmental surcharge tariff and AFUDC.

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 18 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 through 2003 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 their 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 their 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.

PSO does not agree with the intervenors’ and the OCC staff’s recommendations and proposals and will defend its position. If the OCC denies recovery of any portion of the $42 million under-recovery of reallocated costs or offsets under-recovered fuel deferrals with additional reallocated off-system sales margins, our future results of operations and cash flows could be adversely affected. However, if the position taken by the federal court in Texas applies to PSO’s case, the OCC could 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 may file a complaint at the FERC alleging the allocation of off-system sales margins adopted by 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. To date, there has been no claim asserted at the FERC that AEP deviated from the approved allocation methodologies. Management is unable to predict the ultimate effect, if any, of these Oklahoma fuel clause proceedings and any future FERC proceedings on future results of operations, cash flows and financial condition.

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 existed during the year. A hearing was held in August 2006 and we expect a recommendation from the ALJ in the fourth quarter of 2006.

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. The OCC staff indicated that it expects the review process to begin in late 2006 or early 2007.

Management cannot predict the outcome of the pending fuel and purchase 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 September 2006, PSO filed a notice of its intent to file in November 2006 a plan to modify the base rates of PSO’s Oklahoma jurisdictional customers with a proposed effective date in the second quarter of 2007.

SWEPCo Louisiana Fuel Inquiry

In March 2006, the Louisiana Public Service Commission (LPSC) closed its inquiry into SWEPCo’s fuel and purchased power procurement activities during the period January 1, 2005 through October 31, 2005. The LPSC approved the LPSC staff’s report, which concluded that SWEPCo’s activities were appropriate and did not identify any disallowances or areas for improvement.
 
SWEPCo PUCT Staff Review of Earnings

In October 2005, the staff of the PUCT reported the results of its review of SWEPCo’s year-end 2004 earnings. Based on the staff’s adjustments to the information submitted by SWEPCo, the report indicates that SWEPCo is receiving excess revenues of approximately $15 million. The staff engaged SWEPCo in discussions to reconcile the earnings calculation and to consider possible ways to address the results. After those discussions, the PUCT staff informed SWEPCo in April 2006 that they would not pursue the matter further.

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. In April 2004, at the request of the LPSC, SWEPCo filed updated financial information with a test year ending December 31, 2003. Both filings indicated that SWEPCo’s rates should not be reduced. 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 and the recommended base rate reduction does not include the impact of a proposed consolidated federal income tax adjustment, which, if approved, would increase the proposed rate reduction. SWEPCo filed rebuttal testimony in October 2006 strongly refuting the consultants’ recommendations. Hearings are expected to occur late in the fourth quarter of 2006. A decision is not expected until 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 and cash flows.

TCC and TNC Rate Filings

In September 2006, we announced that TCC and TNC will each file transmission and distribution wires rate cases in Texas in late 2006.  We anticipate requesting an $83 million annual increase for TCC and a $25 million annual increase for TNC.  Both requests include the impact of the expiration of the CSW merger savings credits.

ERCOT Price-to-Beat (PTB) Fuel Factor Appeal

Several parties including the Office of Public Utility Counsel and cities served by both TCC and TNC appealed the PUCT’s December 2001 orders establishing initial PTB fuel factors for Mutual Energy CPL and Mutual Energy WTU (TCC’s and TNC’s former affiliated REPs, respectively). In June 2003, the District Court ruled the PUCT record lacked substantial evidence regarding the effect of loss of load due to retail competition on the generation requirements of both Mutual Energy WTU and Mutual Energy CPL and on the PTB rates. In an opinion issued in July 2005, the Texas Court of Appeals reversed the District Court. The cities appealed the appeals court decision to the Supreme Court of Texas, which has ordered full briefing, but has not granted review. Management cannot predict the outcome of further appeals, but a reversal of the favorable court of appeals decision regarding the loss of load issue could result in the issue being returned to the PUCT for further consideration. If that were to happen and if the PUCT orders refunds of PTB revenues, it could adversely impact results of operations and cash flows for the portion of the refund applicable to the period of time that TCC and TNC owned the REPs.

RTO Formation/Integration Costs

In 2005, the FERC approved the amortization of approximately $18 million of deferred RTO formation/integration costs not billed by PJM over 15 years and $17 million of deferred PJM-billed integration costs over 10 years. Total amortization related to such costs was $1 million in both the third quarter of 2006 and 2005. In the first nine months of 2006 and 2005, total amortization related to such costs was $4 million and $3 million, respectively. As of September 30, 2006 and December 31, 2005, the AEP East companies had $30 million and $31 million, respectively, of deferred unamortized RTO and PJM formation/integration costs.
 
In a December 2005 order, the FERC approved the inclusion of a separate rate in the PJM AEP zone OATT to recover the amortization of deferred RTO formation/integration costs and related carrying costs not billed by PJM of $2 million per year. The AEP East companies will be responsible for paying the majority of the amortized costs assigned by the FERC to the AEP East zone since their internal load is the bulk (about 85%) of the transmission load in the AEP zone. As a result, the AEP East companies will need to recover the 85% through their retail rates.

In May 2006, the FERC approved a settlement that provides for recovery over a ten-year period of the PJM-billed integration costs, including related carrying charges, of AEP, Commonwealth Edison Company (ComEd) and The Dayton Power & Light Company (DP&L) from all present zones of the PJM region, except the Virginia Electric & Power Company (VEPCo) zone. The net result of the settlement is that the AEP East companies will recover approximately 50% of the deferred PJM-billed integration costs from third parties, and will need to recover the remaining 50% through retail rates.

As a result of recently approved rate increases, CSPCo, OPCo and KPCo recover the amortization of RTO formation/integration costs billed to the AEP East companies in Ohio and Kentucky. APCo received approval to include the amortization of RTO formation/integration costs in retail rates in West Virginia effective July 28, 2006. In Virginia, APCo filed a base rate case, which includes recovery of these costs when rates became effective October 2, 2006, subject to refund. In Indiana, I&M is subject to a rate cap until June 30, 2007 and is precluded from recovering its share of the deferred RTO costs until that date or until it can file for a rate increase in Indiana. I&M has not yet filed for recovery in Michigan.

Until I&M can adjust its retail rates in Indiana and Michigan to recover the amortization of its deferred RTO formation/integration costs, results of operations and cash flows will be adversely affected by approximately 15% of the amortizations. If the Virginia, Indiana or Michigan commissions disallow recovery of any portion of the billed amortization of deferred RTO formation/integration costs, it could result in a write off of up to 25% of the total remaining deferred balance, adversely impacting future results of operations and cash flows.  In the event of a disallowance, we would appeal that decision to the appropriate state or federal courts.

Transmission Rate Proceedings at the FERC

SECA Revenue Subject to Refund

In accordance with FERC orders, we collected SECA rates to mitigate lost through-and-out transmission service (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 also paid SECA rates to other utilities at considerably lesser amounts than collected. If a refund is ordered, we would also receive refunds related to the SECA rates we paid. The AEP East companies recognized gross SECA revenues as follows:

   
(in millions)
 
Three Months Ended September 30, 2006
 
$
-
 
Three Months Ended September 30, 2005
   
43
 
Nine Months Ended September 30, 2006 (a)
   
43
 
Nine Months Ended September 30, 2005
   
120
 

(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 SECA billings.

A hearing in the SECA case 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 were 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.

Since the implementation of SECA rates in December 2004, the AEP East companies recorded approximately $220 million of gross SECA revenues, subject to refund, and 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. It would also provide refunds of SECA rates paid by the AEP East companies in considerably less significant amounts. Based on the completed settlements, and before the issuance of the ALJ’s initial decision, the AEP East companies provided for $22 million in net refunds, of which $18 million was recorded in the second quarter of 2006 in Utility Operations Revenues on the Condensed Consolidated Statements of Operations.

We, together with Exelon and DP&L, filed an extensive brief noting exceptions to the initial ALJ decision and asking the FERC to reverse the decision in large part. Reply briefs were filed in October 2006. We believe that the FERC should reject the initial ALJ decision because it is contrary to prior related FERC decisions, which are presently subject to rehearing. Furthermore, we believe the ALJ’s findings on key issues are largely without merit. As a result, we have not provided for a possible refund of SECA rates in excess of our current provisions. If the FERC does adopt the ALJ’s recommendations, we will appeal the decision to the courts. Although we believe we 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.

AEP East Transmission Revenue Requirement and Rates

In December 2005, the FERC approved an uncontested settlement which allowed increases in our wholesale transmission OATT rates in three steps: first, beginning retroactively on November 1, 2005, second, beginning on April 1, 2006 when the SECA revenues were eliminated and third, beginning on August 1, 2006 when the new Wyoming-Jacksons Ferry 765 kV line went into service. We estimate that this rate increase will increase wholesale transmission revenues by $22 million in 2006 and $28 million in 2007.

The Elimination of T&O and SECA Rates and the FERC PJM Regional Transmission Rate Proceeding

In a separate proceeding, at our 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 than the AEP/AP proposal.
·
In a 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 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 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 PJM rate design. 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 would be just and reasonable alternatives; however, the judge also found the Postage Stamp rate proposed by the FERC staff to be just and reasonable, and recommended 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 somewhat more revenue for AEP than the AEP/AP proposal, but the phase-in would delay the full impact of that result until about 2012.

We filed briefs noting exceptions to the initial decision and replies to the exceptions of other parties. We 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. A FERC decision is likely in early to mid-2007.

From the elimination of T&O rates in December 2004 through the expiration of SECA rates on March 31, 2006, SECA transition rates failed to fully compensate the AEP East companies for their lost T&O revenues. Effective with the expiration of the SECA transition rates on March 31, 2006, the increase in the AEP East zonal transmission rates applicable to AEP’s internal load and wholesale transmission customers in AEP’s zone was not sufficient to replace the prior T&O revenues or the lower temporary SECA transition rate revenues; however, a favorable outcome in the PJM regional transmission rate proceeding, made retroactive to April 1, 2006 could mitigate a large portion of the shortfall. Full mitigation of the effects of eliminated T&O revenues and the less favorable terminated SECA revenues will require cost recovery through state retail rate proceedings pending any resolution that may result from the above FERC regional transmission rate proceeding. 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 the FERC-approved OATT which 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 yet filed to seek recovery of the lost transmission revenues.

We presently recover from retail customers approximately 65% of the reduction in transmission revenues of $128 million a year. On October 2, 2006, when new base rates went into effect subject to refund in Virginia, that percentage increased to 80%.

Once approved by the FERC, the favorable impacts of the new regional PJM rate design will flow directly to wholesale customers and to retail customers in West Virginia through the ENEC and to retail customers in Ohio upon PUCO approval of a filing we would make to reflect the new rates. In Kentucky, Indiana, Virginia and Michigan, the additional transmission revenues can be expected to reduce retail rates in future base rate proceedings.
 
We believe that the AEP/AP proposal or the Postage Stamp proposal combined with the retail recovery discussed above would be an effective replacement for the eliminated T&O and SECA rates.
Management is unable to predict whether the FERC will approve either the ALJ’s decision or another regional rate design. Future results of operations, cash flows and financial condition would be adversely affected if the approved FERC transmission rates are not sufficient to replace the lost T&O/SECA revenues and the resultant increase in the AEP East companies’ unrecovered transmission costs are not fully recovered in retail rates in Indiana and Michigan.
 
Calpine Oneta Power, L.P.’s Request at the FERC for Reactive Power Compensation From SPP

In April 2003, Calpine Oneta Power (Calpine), an IPP, filed at the FERC a proposed rate schedule to charge SPP for reactive power from Calpine’s generating facility. The FERC rate schedule included a fixed annual fee of $2 million. PSO, SWEPCO and a small portion of TNC operate in SPP. An ALJ initially ruled against Calpine and we concluded that the likelihood of the FERC awarding Calpine a reactive power capacity rate was remote. In September 2006, the FERC issued its decision reversing the ALJ decision, granting Calpine’s request and requiring Calpine to make a compliance filing within 30 days. Our share of this SPP expense could be approximately 90% of the total amount billed by Calpine. Based on this information, we recorded an expense provision, including interest, of $8 million in September 2006 for the retroactive reactive power liability. We will seek rehearing at the FERC and may appeal the decision if the FERC either denies rehearing or rules in favor of Calpine on rehearing.

Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement

The SIA provides, among other things, for the methodology of sharing trading and marketing margins between the AEP East companies and AEP West companies. In March 2006, the FERC approved our proposed methodology effective April 1, 2006 and beyond. The approved allocation methodology for the AEP East companies and AEP West companies is based upon the location of the specific trading and marketing activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT generally accruing to the benefit of PSO and SWEPCo. Previously, the SIA allocation provided for a different method of sharing all such margins between both AEP East companies and AEP West companies, which effectively allowed the AEP West companies to share in PJM and MISO regional margins. In February 2006, we filed with the FERC to remove TCC and TNC from the SIA and CSW Operating Agreement because they are in the final stages of exiting the generation business and have already ceased serving retail load. The FERC approved the removal of TCC and TNC from the SIA and CSW Operating Agreement effective May 1, 2006.

The impact on future results of operations and cash flows will depend upon the level of future margins by region and the status of expanded net energy fuel clause recovery mechanisms and related off-system sales sharing mechanisms by state. Our total trading and marketing margins are unaffected by the allocation methodology.

         4. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING

We are affected by customer choice initiatives and industry restructuring. The Customer Choice and Industry Restructuring note in our 2005 Annual Report should be read in conjunction with this report to gain a complete understanding of material customer choice and industry restructuring matters without significant changes since year-end. The following paragraphs discuss significant events occurring in 2006 related to customer choice and industry restructuring and update the 2005 Annual Report.

TEXAS RESTRUCTURING

In February 2006, the PUCT issued an order in TCC’s $2.4 billion True-up Proceeding, which determined that TCC’s true-up regulatory asset was $1.475 billion including carrying costs through September 2005. In December 2005, TCC adjusted its recorded net true-up regulatory asset to comply with the order. The PUCT issued an order on rehearing in April 2006, which made minor changes to, but otherwise affirmed, the February 2006 order. We appealed, seeking additional recovery consistent with the Texas Restructuring Legislation and related rules. Other parties appealed the PUCT’s true-up order claiming it permits TCC to over-recover stranded generation costs and other true-up items.
 
TCC Securitization Proceeding

TCC filed an application in March 2006 requesting recovery through securitization of $1.8 billion of net stranded generation plant costs and related carrying costs through August 31, 2006. The $1.8 billion request did not include TCC’s negative other true-up items, which total $478 million. See “CTC Proceeding for Other True-up Items” section of this note. Intervenors and the PUCT staff filed testimony regarding TCC’s securitization request in April 2006. In May 2006, TCC filed a letter with the PUCT reducing its request by $6 million of current carrying costs and reduced the recorded net recoverable regulatory asset by the recorded debt-related component. In May 2006, TCC and the other parties filed a settlement with the PUCT, which further reduced the securitizable amount by $77 million and settled several issues that would have delayed the sale of the securitization bonds. The PUCT approved the settlement in June 2006 authorizing $1.697 billion including carrying costs through August 31, 2006, the assumed securitization date, plus estimated issuance costs of $23 million, for a total of $1.72 billion. We issued TCC securitization bonds on October 11, 2006 for $1.74 billion, including additional issuance costs and carrying costs to October 11, 2006.

TCC performed a probability of recovery impairment test on its net true-up regulatory asset taking into account the treatment ordered by the PUCT. We determined that the projected cash flows from the securitization less the proposed CTC refund would be more than sufficient to recover TCC’s recorded net true-up regulatory asset due to the existence of $224 million of unrecorded equity-related carrying costs which are not recorded until collected in regulated rates. As a result, no additional impairment was recorded for the approved reduction in the amount to be securitized. However, the $77 million agreed upon reduction in the securitizable amount will have a negative impact on future earnings.

Consistent with certain prior securitization determinations, the PUCT issued a specific order in the securitization proceeding that calculated a $315 million cost-of-money benefit from true-up related ADFIT through August 2006, of which $75 million ($77 million through September 30, 2006) relates to the recorded benefit prior to the date of securitization and $240 million relates to the unrecorded benefit subsequent to the date of securitization. The PUCT included the $315 million ADFIT-related stranded cost benefit in the CTC refund of $478 million. In June 2006, we transferred the effects of the ADFIT on recorded carrying costs from the securitizable asset to the CTC refund, thereby increasing the carrying costs identified to the securitizable assets in the table below.

The differences between the securitization amount ordered by the PUCT of $1.74 billion and the Recorded Securitizable True-up Regulatory Asset of $1.57 billion by component at September 30, 2006 are detailed in the table below:

   
(in millions)
 
Stranded Generation Plant Costs
 
$
974
 
Net Generation-related Regulatory Asset
   
249
 
Excess Earnings
   
(49
)
Recorded Net Stranded Generation Plant Costs
   
1,174
 
Recorded Debt Carrying Costs on Net Stranded Generation Plant Costs
   
400
 
Recorded Securitizable True-up Regulatory Asset
   
1,574
 
Unrecorded But Recoverable Equity Carrying Costs
   
224
 
Unrecorded Estimated October 2006 Debt Carrying Costs
   
3
 
Unrecorded Excess Earnings, Related Carrying Costs and Other
   
53
 
Unrecorded Settlement Reduction
   
(77
)
Reduction for the Present Value of ADITC and EDFIT Benefits
   
(61
)
Approved Securitizable Amount as of October 11, 2006
   
1,716
 
Unrecorded Securitization Bond Issuance Costs
   
24
 
Amount Securitized on October 11, 2006
 
$
1,740
 

Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes

In TCC’s true-up and securitization orders, the PUCT reduced net stranded generation plant costs 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 generating assets. (See Reduction for the Present Value of ADITC and EDFIT Benefits of $61 million in the table above.) TCC testified that the sharing of these tax benefits with customers might be a violation of the Internal Revenue Code’s normalization provisions.
 
TCC filed a request for a private letter ruling from the IRS in June 2005 to determine whether the PUCT’s action would result in a normalization violation. The IRS issued its private letter ruling on May 9, 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. TCC informed the PUCT on May 10, 2006 of the adverse ruling, however, the PUCT did not change its order on rehearing. TCC filed an appeal with the PUCT. As discussed below in the “CTC Proceeding for Other True-up Items” section of this note, TCC proposed, and the PUCT agreed, to defer refunding the amount of the present value of its ADITC and EDFIT benefits through its CTC until this normalization issue is resolved upon the IRS issuance of final normalization regulations.
 
If a normalization violation occurs, it could result in the repayment of TCC’s ADITC on all property, including transmission and distribution property, which approximates $104 million as of September 30, 2006 and also a loss of the 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 through the appeal of the PUCT’s true-up order and through a CTC deferral.

CTC Proceeding for Other True-up Items

In June 2006, TCC filed to implement a negative CTC to refund its other true-up items over eight years. TCC will incur interest expense on the other true-up regulatory liability balances until it is fully refunded. The principal components of the CTC refund liability are an over-recovered fuel balance, the retail clawback and the ADFIT benefit related to TCC’s stranded generation cost, offset by a positive wholesale capacity auction true-up regulatory asset balance.

The differences between the components of TCC’s Recorded Net Regulatory Liabilities - Other True-up Items of $238 million as of September 30, 2006 (including interest expense) and its Net CTC Refund Proposed of $357 million are detailed below:

   
(in millions)
 
Wholesale Capacity Auction True-up
 
$
61
 
Carrying Costs on Wholesale Capacity Auction True-up
   
31
 
Retail Clawback including Carrying Costs
   
(65
)
Deferred Over-recovered Fuel Balance
   
(184
)
Retrospective ADFIT Benefit
   
(77
)
Other
   
(4
)
Recorded Net Regulatory Liabilities - Other True-up Items
   
(238
)
Unrecorded Prospective ADFIT Benefit
   
(240
)
Gross CTC Refund Proposed
   
(478
)
FERC Jurisdictional Fuel Refund Deferral
   
16
 
ADITC and EDFIT Benefit Refund Deferral
   
98
 
Net CTC Refund Proposed, After Deferrals
   
(364
)
True-up Proceeding Expense Surcharge
   
7
 
Net CTC Refund Proposed, After Deferrals and Expenses
 
$
(357
)

TCC requested that a portion of the refund be deferred, pending the outcome of two contingent federal matters related to the refund of $16 million of FERC jurisdictional fuel over-recoveries (discussed below) and $98 million (including carrying costs) related to potential tax normalization violation matters related to the refund of ADITC and EDFIT benefits (discussed above). Under TCC’s proposal, (a) if the two contingent federal matters are resolved consistent with the PUCT’s treatment, TCC will then refund the $16 million and the $98 million plus carrying costs or (b) if these two issues are not resolved consistent with the PUCT’s treatment, the deferred refunds will not be made in order to avoid a normalization violation and the violation of a Federal court order. Management cannot predict the final outcome of this filing.

Although TCC proposed to refund the $357 million over eight years, certain intervenors supported accelerated refunds. In September 2006, the PUCT approved an interim CTC that was implemented on October 12, 2006, the same day that TCC began billing customers for the securitization bonds. The interim CTC will refund the entire retail clawback of $65 million (including carrying costs) to residential customers by the end of 2006. The CTC refund to the other customer classes during the interim period will be as proposed by TCC, with the exception of the large industrials, who will not receive any fuel refunds during the interim period.

At an October 2006 open meeting, the PUCT announced oral decisions regarding the CTC refund. A final written order is expected in late November or early December of this year. In its decision, the PUCT confirmed that TCC can use securitization bond proceeds to make the CTC refund. The PUCT’s decision was to continue the interim CTC through December 2006 to complete the refund of the retail clawback over three months. Beginning in January 2007, the Deferred Over-recovered Fuel Balance will be refunded over six months with the large industrial customers receiving their entire refund in January 2007. Starting in July 2007, the remaining CTC items will be refunded over one year, except that the PUCT agreed with TCC’s request to defer the refund of the ADITC and EDFIT Benefit Refund Deferral and the FERC Jurisdictional Fuel Refund Deferral (see table above). The PUCT will decide those issues and related amounts in another proceeding.

Fuel Balance Recoveries

In September 2005, the Federal District Court, Western District of Texas, issued an order precluding the PUCT from enforcing its ruling in the TNC fuel proceeding regarding the PUCT’s reallocation of off-system sales margins. In August 2006, TCC also received an order from the Federal District Court, Western District of Texas precluding the PUCT from enforcing its ruling regarding the PUCT’s reallocation of off-system sales margins in connection with TCC’s final fuel reconciliation. The favorable Federal District Court order, if upheld on appeal, could result in reductions to the over-recovered fuel principal balances of $8 million for TNC and $14 million ($16 million with carrying costs) for TCC. The PUCT appealed the TCC and TNC Federal Court decision to the United States Court of Appeals for the Fifth Circuit. If the PUCT is unsuccessful in the federal court system, the PUCT may file a complaint at the FERC to address the allocation issue. We are unable to predict if the Federal District Court’s decision will be upheld or whether the PUCT will file a complaint at the FERC. Pending further clarification, TCC and TNC have not reversed their related provisions for fuel over-recovery. If the PUCT or another party were to file a complaint at the FERC that results in the PUCT’s decisions being reinstated, it could result in an adverse effect on results of operations and cash flows for the AEP East companies because an unfavorable FERC ruling may result in a 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 from their customers due to past frozen rates, past inactive fuel clauses and fuel clauses that do not include off-system sales credits.

Carrying Costs on Net True-up Regulatory Assets Impacting Securitization and CTC Proceedings

In TCC’s True-up Proceeding, the PUCT allowed TCC to recover carrying costs at an 11.79% overall pretax weighted average cost of capital rate approved in its unbundled cost of service rate proceeding. The recorded embedded debt component of this carrying cost rate is 8.12%. Through September 30, 2006, TCC recorded $400 million of debt-related carrying costs on stranded generation plant costs included in the securitization proceeding. Equity carrying costs of $224 million related to amounts securitized will be recognized in income as collected. TCC will accrue interest expense until its net CTC refund is fully refunded. The interest expense on the net CTC refund totals $9 million and $11 million for the three and nine months ended September 30, 2006, respectively, and is included in Interest Expense on the Condensed Consolidated Statements of Operations.

In June 2006, the PUCT adopted a proposed rule that prospectively changes the interest rate applied to TCC’s CTC refund balance. TCC anticipates that the rule change will reduce the rate TCC will pay on its CTC balance from 11.79% to 7.47%. TCC anticipates that the change will reduce its annual refund by approximately $8 million. The rule also provides for adjustments to the rate during subsequent rate case proceedings.
 
TNC True-up Proceeding

TNC filed a CTC proceeding in August 2005 to establish a rate to refund its net true-up regulatory liability. In December 2005, that proceeding was abated, pending a final ruling from TNC’s appeal to the federal court regarding the fuel proceeding (described above). In August 2006, the parties to TNC’s CTC proceeding filed a settlement that recommended implementing an interim refund of the true-up regulatory liability totaling $13 million, net of the amounts at issue in the federal court proceeding, over six months beginning in September 2006. In late August 2006, the PUCT approved the settlement and the net refund began in September 2006. TNC accrues interest expense on the unrefunded balance and will continue to do so until the balance is fully refunded.

Excess Earnings

As noted in our 2005 Annual Report, 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 was unlawful under the Texas Restructuring Legislation. 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. Management is unable to predict the ultimate outcome of these proceedings.

Summary

Our recorded securitizable true-up regulatory asset at September 30, 2006 of $1.57 billion, net of the recorded net regulatory liabilities for other true-up items of $238 million, reflects the PUCT’s orders in TCC’s True-up Proceeding and its securitization proceeding. Barring any future disallowances to TCC’s net recoverable true-up regulatory asset in any subsequent proceedings or court rulings, TCC will amortize its total securitizable true-up regulatory asset commensurate with recovery over the 14-year term of the securitized bonds issued in October 2006. If we determine, as a result of future PUCT orders or appeal court rulings, that it is probable TCC cannot recover a portion of its recorded net true-up regulatory asset and we are able to estimate the amount of a resultant impairment, we would record a provision for such amount which would have an adverse effect on future results of operations, cash flows and possibly financial condition. Based on advice of Texas rate counsel, TCC appealed the PUCT orders seeking relief in both state and federal court where TCC believes the PUCT’s rulings are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law. Municipal customers and other intervenors also appealed the same PUCT orders seeking to further reduce TCC’s true-up recoveries.
 
Although TCC believes it has meritorious arguments, management cannot predict the ultimate outcome of any future proceedings or court appeals. If TCC succeeds in future appeals, it could have a material favorable effect on future results of operations, cash flows and financial condition. If municipal customers and other intervenors succeed in their appeals, or if the PUCT does not approve TCC’s CTC filing as filed and, as a result, causes a normalization violation, it could have a material adverse effect on future results of operations, cash flows and financial condition.

Texas Restructuring - SPP

In August 2006, the PUCT adopted a rule delaying customer choice in the SPP area of Texas until no sooner than January 1, 2011. SWEPCo and a small portion of TNC’s business operate in SPP. Approximately 3% of TNC’s operations are located in the SPP territory, with $13 million in net assets in SPP. We filed a petition in May 2006, requesting approval to transfer Mutual Energy SWEPCO L.P.’s (a subsidiary of AEP C&I Company, LLC) and TNC’s customers, facilities and certificated service located in the SPP area to SWEPCo. If this petition is successful, SWEPCo will be our only subsidiary affected by the delay in the SPP area.
 
OHIO RESTRUCTURING

Rate Stabilization Plans

In January 2005, the PUCO approved Rate Stabilization Plans (RSPs) for CSPCo and OPCo (the Ohio companies). The approved plans in each of 2006, 2007 and 2008 provide, among other things, for CSPCo and OPCo to raise their generation rates by 3% and 7%, respectively, and provide for possible additional annual generation rate increases of up to an average of 4% per year based on supporting the request for additional revenues for specified costs. CSPCo’s potential for the additional annual 4% generation rate increases is diminished by approximately three-quarters in 2006 and to a lesser extent in 2007 and 2008 due to the power acquisition rider approved by the PUCO in the Monongahela Power service territory acquisition proceeding and the recovery of pre-construction costs for its share of the jointly-owned IGCC plant (see “IGCC Plant” section of this note below). OPCo’s potential for additional annual 4% generation rate increases is diminished in 2006 by approximately one-quarter and to a lesser extent in 2007 due to the recovery of pre-construction costs for its share of the jointly-owned IGCC plant. The RSPs also provide that the Ohio companies can recover in 2006, 2007 and 2008 estimated 2004 and 2005 deferred environmental carrying costs and PJM-related administrative costs and congestion costs net of financial transmission rights (FTR) revenue related to their obligation as the Provider of Last Resort (POLR) in Ohio’s customer choice program. Pretax earnings increased by $10 million and $26 million for CSPCo and $20 million and $58 million for OPCo in the third quarter and first nine months of 2006, respectively, from the RSP rate increases net of the amortization of RSP regulatory assets. These increases also include the recognition of equity carrying costs. As of September 30, 2006, unrecognized equity carrying costs from 2004 and 2005, which are recognized over the three-year RSP recovery period totaled $32 million. As of September 30, 2006, the unamortized RSP regulatory assets to be recovered through December 31, 2008 were $43 million.

In the second quarter of 2005, the Ohio Consumers’ Counsel filed an appeal to the Ohio Supreme Court that challenged the RSPs and also argued that there was no POLR obligation in Ohio and, therefore, CSPCo and OPCo are not entitled to recover any POLR charges. In DP&L’s proceeding, the Ohio Supreme Court concluded that there is a POLR obligation in Ohio, supporting the Ohio companies’ position that they can recover a POLR charge. In an appeal concerning First Energy companies’ RSP, the Ohio Supreme Court held that the PUCO’s decision to eliminate the offer to customers of a price determined through competitive bids was unlawful. In July 2006, the Ohio Supreme Court vacated the PUCO’s RSP order for the Ohio companies, which also did not include a competitive bid process, and remanded the case to the PUCO for further proceedings, not inconsistent with the decision in the appeal of the First Energy companies’ RSP. In August 2006, the PUCO acted on the Ohio companies’ remand case ordering them to file a plan to provide an option for customer participation in the electric market through competitive bids or other reasonable means and also held that the RSP shall remain effective. Accordingly, the Ohio companies continued to collect RSP revenues. In accordance with the PUCO directive, in September 2006, CSPCo and OPCo submitted their proposal to provide additional options for customer participation in the electric market.

In the Ohio companies’ case, the Ohio Supreme Court did not address any other issues that had been raised on appeal, stating that its decision does not preclude the Ohio Consumers’ Counsel from raising those issues in a future appeal. Management believes that the RSP regulatory assets remain probable of recovery and that the Ohio companies will continue to collect RSP revenues.

IGCC Plant

In March 2005, the Ohio companies filed a joint application with the PUCO seeking authority to recover costs related to building and operating a new 600 MW IGCC power plant using clean-coal technology. The application proposed cost recovery associated with the IGCC plant in three phases: 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 projected $1.2 billion cost of the plant 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 the Ohio companies could request in 2006, 2007 and 2008 under their RSPs. Through September 30, 2006, the Ohio companies deferred pre-construction IGCC costs totaling $16 million and recovered $6 million of those costs.  We are currently recovering the remaining deferred amounts through June 30, 2007.

In April 2006, the PUCO issued an order authorizing the Ohio companies 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. In its June order, the PUCO indicated if the Ohio companies have not commenced continuous construction of the IGCC plant within five years of the order, all charges collected for pre-construction costs, which are assignable to other jurisdictions, must be refunded to Ohio ratepayers with interest. The PUCO deferred ruling on Phases 2 and 3 cost recovery until further hearings are held. No date for a further hearing has been set.

In June 2006, the Industrial Energy Users - Ohio (IEU), an intervenor in the PUCO proceeding, filed a Complaint for Writ of Prohibition at the Ohio Supreme Court to prohibit the use of the PUCO’s authorization by the Ohio companies to enforce the collection of the Phase 1 rates and to prohibit the PUCO from further entertaining any increase in rates for the IGCC project. The Court subsequently granted a PUCO motion to dismiss the Complaint for Writ of Prohibition.

In August 2006, IEU, Ohio Consumers’ Counsel, FirstEnergy Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order in the IGCC proceeding. The Ohio companies believe that the PUCO’s authorization to begin collection of Phase 1 rates is lawful. The Ohio companies, however, cannot predict the outcome of these appeals. If the PUCO’s order is found to be unlawful, future results of operations and cash flows will be adversely affected.

Transmission Rate Filing

In accordance with the RSPs, in December 2005, the PUCO approved the recovery of certain RTO transmission costs through separate transmission cost recovery riders for the Ohio companies. The transmission cost recovery riders are subject to an annual true-up process with over/under recovery mechanisms. In February 2006, the Ohio companies filed a request with the PUCO to incorporate all transmission costs and rates in their transmission cost recovery riders and institute a two-step increase to reflect the increases in the FERC-approved rates. In the filing, the first increase would be effective April 1, 2006 to reflect the Ohio companies’ share of the loss of SECA revenues and the second increase would be effective August 1, 2006 to recover their share of the cost of the new Wyoming-Jacksons Ferry 765 kV line. In May 2006, the PUCO issued an order approving a two-step increase in the transmission cost recovery riders with over/under recovery mechanisms, effective April 1, 2006. The new tariffs were filed with the PUCO and implemented in June 2006.

In October 2006, the Ohio companies filed for initial true-ups under the transmission cost recovery riders’ over/under recovery mechanisms. The filings reflect the refund of regulatory liabilities as of September 30, 2006 of $12 million and $16 million for CSPCo and OPCo, respectively, including carrying charges. These over-recoveries were reflected as part of the new transmission cost recovery rider filed to be effective January 2007. We anticipate the net effect of the new transmission cost recovery riders will result in increased cost recoveries over 2005 levels for CSPCo and OPCo of $27 million and $36 million, respectively, in 2006 and $15 million and $16 million, respectively, in 2007.

Distribution Service Reliability and Restoration Costs

In December 2003, the Ohio companies entered into a stipulation agreement regarding distribution service reliability. The stipulation agreement covered the years 2004 and 2005 and, among other features, established certain distribution service reliability measures that the Ohio companies were to meet. In July 2006, based on the staff report on service reliability and responses filed by the Ohio companies, the PUCO directed the Ohio companies to earmark $10 million for future measures to improve service reliability without recovery. The PUCO further indicated that it will determine where and how the $10 million will best be applied.

In March 2006, the Ohio companies filed an application with the PUCO to implement tariff riders to recover a portion of previously expensed incremental costs of restoring service disrupted by severe winter storms in December 2004 and January 2005. CSPCo and OPCo each requested recovery of approximately $12 million of such costs, which was approved by the PUCO in August 2006. Effective September 1, 2006, the Ohio companies implemented the storm cost recovery riders, which will continue until they have collected the authorized amounts or one year, whichever is shorter. In September 2006, the Ohio Consumers’ Counsel filed a request for rehearing with the PUCO, which was denied in October 2006.

As a result of the above, in September 2006 the Ohio companies recorded regulatory assets of $14 million, favorably affecting earnings.

Ormet

Ormet Primary Aluminum Corporation and Ormet Primary Mill Products Corporation (together, Ormet) was a customer of OPCo until 2000. Beginning in 2000, at Ormet’s request, the PUCO authorized a modification of the certified service territories of OPCo and South Central Power Company (SCP), a nonaffiliate, so that Ormet became a customer of SCP. SCP agreed to let Ormet access the electric generation market for the vast majority of its 520 MW load. Ormet filed a request with the PUCO to return to being served by OPCo at the industrial tariff rate. OPCo opposed the request because it would likely require the purchase of capacity and energy from the market at prices above the industrial RSP tariff rate in order to serve Ormet, as well as substantially reduce our ability to sell energy into the wholesale market at the higher market prices.

In June 2006, the PUCO found that SCP was not providing or proposing to provide physically adequate service to Ormet. In October 2006, the PUCO convened a hearing to determine if an electric supplier, other than SCP, should be authorized to serve Ormet’s significant load.

Subsequent to the hearing, the Ohio companies together with Ormet, its employees’ union and certain other interested parties filed a settlement agreement with the PUCO for approval. The settlement agreement provides for the reallocation of the service territories of CSPCo, OPCo and SCP so that Ormet’s Hannibal, Ohio facilities are located in a joint CSPCo/OPCo certified territory effective January 1, 2007. The settlement also provides for the recovery in 2007 and 2008 by CSPCo and OPCo of the difference between $43 per MWH paid by Ormet and a to-be-determined market price submitted by management and reviewed by the PUCO.  The recovery is accomplished by the amortization to income 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 RSP. The $43 per MWH price for generation services is above the industrial RSP generation tariff but below current market prices.

Customer Choice Deferrals

As provided in stipulation agreements approved by the PUCO in 2000, the Ohio companies defer customer choice implementation costs and related carrying costs in excess of $20 million each. The agreements provide for the deferral of these costs as regulatory assets until the next distribution base rate cases. Through September 30, 2006, we incurred $97 million of such costs and deferred $48 million of such costs for probable future recovery in distribution rates. We have not recorded $9 million of equity carrying costs, which are not recognized until collected. Pursuant to the RSPs, recovery of these amounts is subject to PUCO review and is deferred until the next distribution rate filing to change rates after the December 31, 2008 end of the RSP period. We believe that the deferred customer choice implementation costs were prudently incurred to implement customer choice in Ohio and should be recoverable in future distribution rates. If the PUCO determines that any of the deferred costs are unrecoverable, it would have an adverse impact on future results of operations and cash flows.

         5. COMMITMENTS AND CONTINGENCIES

As discussed in the Commitments and Contingencies note within our 2005 Annual Report, we continue to be involved in various legal matters. The 2005 Annual Report should be read in conjunction with this report in order to understand the other material nuclear and operational matters without significant changes since our disclosure in the 2005 Annual Report. See disclosure below for significant matters and changes in status subsequent to the disclosure made in our 2005 Annual Report.

ENVIRONMENTAL

Federal EPA Complaint and Notice of Violation

The Federal EPA and a number of states alleged 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 court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications occurred at our generating units over a 20-year period. A bench trial on the liability issues was held during July 2005. Briefing has concluded. In June 2006, the judge stayed the liability decision pending the issuance of a decision by the U.S. Supreme Court in the Duke Energy case. A bench trial on remedy issues, if necessary, is scheduled to begin four months after the U.S. Supreme Court decision is issued.

Under the CAA, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components or other repairs needed for the reliable, safe and efficient operation of the plant. 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, 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 one case. The Federal EPA issued a final rule that would exclude activities similar to those challenged in these cases from NSR as “routine replacements.” In March 2006, the Court of Appeals for the District of Columbia Circuit issued a decision vacating the rule. The Federal EPA filed a petition for rehearing in that case, which the Court denied. The Federal EPA also recently proposed a rule that would define “emissions increases” in a way that would exclude most of the challenged activities from NSR.

We are unable to estimate the loss or range of loss related to any contingent liability we might have for civil penalties under the CAA proceedings. We are also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. If we do not prevail, we believe we can recover any capital and operating costs of additional pollution control equipment that may be required through regulated rates and market prices of 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.

SWEPCo Notice of Enforcement and Notice of Citizen Suit

In July 2004, two special interest groups, Sierra Club and Public Citizen, issued a notice of intent to commence a citizen suit under the CAA for alleged violations of various permit conditions in permits issued to several SWEPCo generating plants. In March 2005, the special interest groups filed a complaint in Federal District Court for the Eastern District of Texas alleging violations of the CAA at the Welsh Plant. SWEPCo filed a response to the complaint in May 2005. Other preliminary motions have been filed and are pending before the Court.

In July 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.

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, financial condition or cash flows.

Carbon Dioxide (CO2) Public Nuisance Claims

In July 2004, attorneys general from eight states and the corporation counsel for 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. That same day, the Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint in the same court against the same defendants. The actions alleged that CO2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts associated with global warming and sought injunctive relief in the form of specific emission reduction commitments from the defendants. In September 2004, the defendants, including AEP and AEPSC, filed a motion to dismiss the lawsuits. In September 2005, the lawsuits were dismissed. The trial court’s dismissal was appealed to the Second Circuit Court of Appeals. Briefing and oral argument have been completed. We believe the actions are without merit and intend to defend against the claims.

Ontario Litigation

In June 2005, we, along with nineteen nonaffiliated utilities, were named as defendants in a lawsuit filed in the Superior Court of Justice in Ontario, Canada. We have not been served with the lawsuit. The time limit for serving the defendants expired, but the case has not been dismissed. The defendants are alleged to own or operate coal-fired electric generating stations in various states that, through negligence in design, management, maintenance and operation, emitted NOX, SO2 and particulate matter that harmed the residents of Ontario. The lawsuit seeks class action designation and damages of approximately $49 billion, with continuing damages of $4 billion annually. The lawsuit also seeks $1 billion in punitive damages. We believe we have meritorious defenses to this action and intend to defend against it.

OPERATIONAL

Power Generation Facility and TEM Litigation

We have agreements with Juniper Capital L.P. (Juniper) under which Juniper constructed and financed a merchant power generation facility (Facility) near Plaquemine, Louisiana and leased the Facility to us. We subleased the Facility to the Dow Chemical Company (Dow). The Facility is a Dow-operated “qualifying cogeneration facility” for purposes of PURPA.
 
Juniper is a nonaffiliated limited partnership, formed to construct or otherwise acquire real and personal property for lease to third parties, to manage financial assets and to undertake other activities related to asset financing. Juniper arranged to finance the Facility. The Facility is collateral for Juniper’s debt financing. Due to the treatment of the Facility as a financing of an owned asset, we recognized all of Juniper’s funded obligations as a liability. Upon expiration of the lease, our actual cash obligation could range from $0 to $415 million based on the fair value of the assets at that time. However, if we default under the Juniper lease, our maximum cash payment could be as much as $525 million. Because we report Juniper’s funded obligations totaling $525 million related to the Facility on our Condensed Consolidated Balance Sheets, the fair value of the liability for our guarantee (the $415 million payment discussed above) is not separately reported.

In August 2006, we reached an agreement with Dow to sell the Facility to them. We expect the sale to close during the fourth quarter of 2006 following receipt of federal regulatory approvals. Upon closing, we will repay our recorded $525 million lease financing obligation, which is included in Long-term Debt Due Within One Year on our Condensed Consolidated Balance Sheet at September 30, 2006. The approved sale resulted in a third quarter pretax impairment of approximately $209 million (see Note 8).

Dow uses a portion of the energy produced by the Facility and sells the excess energy. OPCo agreed to purchase up to approximately 800 MW of such excess energy from Dow for a 20-year term. Because the Facility is a major steam supply for Dow, Dow is expected to operate the Facility at certain minimum levels, and OPCo is obligated to purchase the energy generated at those minimum operating levels (approximately 270 MW). OPCo sells the purchased energy at market prices in the Entergy sub-region of the Southeastern Electric Reliability Council market.

OPCo agreed to sell up to approximately 800 MW of energy to TEM for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA), at a price that is currently in excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming. Commercial operation for purposes of the PPA began April 2, 2004.

In September 2003, TEM and AEP separately filed declaratory judgment actions in the U.S. 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 April 2004, OPCo gave notice to TEM that OPCo (a) was suspending performance of its obligations under the PPA; (b) would seek a declaration from the District Court that the PPA was terminated; and (c) would pursue TEM and SUEZ-TRACTEBEL S.A. under the guaranty, seeking damages and the full termination payment value of the PPA.

A bench trial was conducted in March and April 2005. In August 2005, a federal judge ruled that TEM breached the contract and awarded us damages of $123 million plus prejudgment interest. In August 2005, both parties filed motions with the trial court seeking reconsideration of the judgment. We asked the court to modify the judgment to (a) award a termination payment to us under the terms of the PPA; (b) grant our attorneys’ fees; and (c) render judgment against SUEZ-TRACTEBEL S.A. on the guaranty. TEM sought reduction of the damages awarded by the court for replacement electric power products made available by OPCo under the PPA. In January 2006, the trial judge granted our motion for reconsideration concerning TEM’s parent guaranty and increased our judgment against TEM to $173 million plus prejudgment interest, and denied the remaining motions for reconsideration. In March 2006, the trial judge amended the January 2006 order eliminating the additional $50 million damage award.

In September 2005, TEM posted a letter of credit for $142 million as security pending appeal of the judgment. Both parties have filed Notices of Appeal with the United States Court of Appeals for the Second Circuit. Oral argument is scheduled for December 2006. If the PPA is deemed terminated or found unenforceable by the court ultimately deciding the case, we could be adversely affected to the extent we are unable to find other purchasers of the power with similar contractual terms (if our sale of the Facility to Dow does not close) and to the extent we do not fully recover the claimed termination value damages from TEM.
 
Enron Bankruptcy

In connection with our 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 July 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 reservoir. In December 2003, the Texas state trial 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 filed a motion to have the case assigned to the judge who heard the case originally and that motion was granted. HPL intends to continue to defend against BOA’s claims.

In October 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 reservoir 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 reservoir 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.

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 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 (see Note 8).

In June and July 2006, we held mediation discussions with BOA and Enron concerning these gas disputes. No further discussions are scheduled at this time. 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 the fourth quarter of 2002 and the first quarter of 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 July 2006, the Court entered judgment denying plaintiff’s motion for class certification and dismissing all claims without prejudice. In August 2006, plaintiff filed a notice of appeal to the United States Court of Appeals for the Sixth Circuit. Briefing of this appeal is scheduled for completion in December 2006.

Natural Gas Markets Lawsuits

In November 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 have been 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 had been transferred to the United States District Court for the District of Nevada but subsequently remanded to California state court. In April 2005, the judge in Nevada dismissed one of the remaining cases in which AEP was a defendant on the basis of the filed rate doctrine and in December 2005, the judge dismissed two additional cases on the same ground. Plaintiffs in these cases appealed the decisions. We will continue to defend each case where an AEP company is a defendant.

Cornerstone Lawsuit

In the third quarter of 2003, Cornerstone Propane Partners filed an action in the United States District Court for the Southern District of New York against forty companies, including AEP and AEPES, seeking class certification and alleging unspecified damages from claimed price manipulation of natural gas futures and options on the NYMEX from January 2000 through December 2002. Thereafter, two similar actions were filed in the same court against a number of companies, including AEP and AEPES, making essentially the same claims as Cornerstone Propane Partners and also seeking class certification. These cases were consolidated. In January 2004, plaintiffs filed an amended consolidated complaint. The defendants filed a motion to dismiss the complaint which the Court denied. In October 2005, the Court granted the plaintiffs motion for class certification. We intend to continue to defend against these claims.

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 because the market for power was allegedly dysfunctional at the time such contracts were executed. The ALJ rejected the Nevada utilities’ complaint, held that the markets for future delivery were not dysfunctional, and that the Nevada utilities failed to demonstrate that the public interest required changes be made to the contracts. In June 2003, the FERC issued an order affirming the ALJ’s decision. The Nevada utilities’ request for a rehearing was denied. The Nevada utilities’ appeal of the FERC order is pending before the U.S. Court of Appeals for the Ninth Circuit. Management is unable to predict the outcome of this proceeding and its impact on future results of operations and cash flows.

         6. 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 September 30, 2006, the maximum future payments for all the LOCs are approximately $34 million with maturities ranging from October 2006 to July 2007.

GUARANTEES OF THIRD-PARTY OBLIGATIONS

SWEPCo

In connection with reducing the cost of the lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCo agreed, under certain conditions, to assume the capital lease obligations and term loan payments of the mining contractor, Sabine Mining Company (Sabine). If Sabine defaults under any of these agreements, SWEPCo’s total future maximum payment exposure is approximately $68 million with maturity dates ranging from February 2007 to February 2012.

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. This guarantee ends upon depletion of reserves and final reclamation is completed. At September 30, 2006, we estimate the reserves will be depleted in 2029 with final reclamation completed by 2036. We estimate the cost for final reclamation during the period 2029 through 2036 at approximately $39 million.

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. Prior to September 30, 2006, we entered into several sale agreements. The status of certain sales agreements is discussed in Note 8. These sale agreements include indemnifications with a maximum exposure related to the collective purchase price, which is approximately $2.1 billion (approximately $1 billion relates to the BOA litigation, see “Enron Bankruptcy” section of Note 5). 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 September 30, 2006, the maximum potential loss for these lease agreements was approximately $54 million ($35 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.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under the return-and-sale option discussed above will equal at least the 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 September 30, 2006, 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 structure.

         7. COMPANY-WIDE STAFFING AND BUDGET REVIEW

As a result of a company-wide staffing and budget review in the second quarter of 2005, we identified approximately 500 positions for elimination. Pretax severance benefits expense of $24 million and $4 million was recorded (primarily in Maintenance and Other Operation within the Utility Operations segment) in the second and third quarters of 2005, respectively.

The following table shows the accrual as of December 31, 2005 (reflected primarily in Current Liabilities - Other on our Condensed Consolidated Balance Sheets) and the activity during the first nine months of 2006, which eliminated the accrual as of June 30, 2006:

   
Amount
(in millions)
 
Accrual at December 31, 2005
 
$
12
 
Less: Total Payments
   
8
 
Less: Accrual Adjustments
   
4
 
Accrual at September 30, 2006
 
$
-
 
 
   The favorable accrual adjustments were recorded primarily in Maintenance and Other Operation on our Condensed Consolidated Statements of Operations.

         8. ACQUISITIONS, DISPOSITIONS, DISCONTINUED OPERATIONS, ASSETS HELD FOR SALE AND ASSET IMPAIRMENTS

ACQUISITIONS

2005

Waterford Plant (Utility Operations segment)

In May 2005, CSPCo signed a purchase and sale agreement with Public Service Enterprise Group Waterford Energy LLC for the purchase of an 821 MW plant in Waterford, Ohio. This transaction was completed in September 2005 for $218 million and the assumption of liabilities of approximately $2 million.

DISPOSITIONS

2006

Compresion Bajio S de R.L. de C.V. (Investments - Other segment)

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 received an indicative offer for Bajio in September 2005, which resulted in a pretax other-than-temporary impairment charge of approximately $7 million. The impairment amount is classified in Investment Value Losses on our Condensed Consolidated Statements of Operations. We completed the sale in February 2006 for approximately $29 million with no effect on our 2006 results of operations.
 
2005

Houston Pipe Line Company LP (HPL) (Investments - Gas Operations segment)

During 2005, we sold our interest in HPL, 30 billion cubic feet (BCF) of working gas and working capital for approximately $1 billion, subject to a working capital and inventory true-up adjustment. Although the assets were legally transferred, it is not possible to determine all costs associated with the transfer until the Bank of America (BOA) litigation is resolved. Accordingly, we recorded the excess of the sales price over the carrying cost of the net assets transferred as a deferred gain of $379 million as of September 30, 2006 and December 31, 2005, which is reflected in Deferred Credits and Other on our Condensed Consolidated Balance Sheets. We provided an indemnity to the purchaser in an amount up to the purchase price for damages, if any, arising from litigation with BOA and a potential resulting inability to use the cushion gas (see “Enron Bankruptcy” section of Note 5). The HPL operations did not meet the criteria to be shown as discontinued operations due to continuing involvement associated with various contractual obligations. Significant continuing involvement includes cash flows from long-term gas contracts with the buyer through 2008 and the cushion gas arrangement. In addition, we continue holding forward gas contracts, with expirations through 2011, not sold with the gas pipeline and storage assets.  We manage the commodity price risk associated with these forward gas contracts to limit our price risk exposure principally by entering into equal and offsetting contracts.  For the nine months ended September 30, 2006, the change in the mark-to-market value of these positions was less than $100,000.

Texas REPs (Utility Operations segment)

In December 2002, we sold two of our Texas REPs to Centrica, a UK-based provider of retail energy. The sales price was $146 million plus certain other payments including an earnings-sharing mechanism (ESM) for AEP and Centrica to share in the earnings of the sold business for the years 2003 through 2006. The method of calculating the annual earnings-sharing amount was included in the Purchase and Sales Agreement and was amended through a series of agreements that AEP and Centrica entered in March 2005. Also in March 2005, we received payments related to the ESM of $45 million and $70 million for 2003 and 2004, respectively, resulting in a pretax gain of $112 million in 2005. In March 2006, we received a payment of $70 million related to the ESM for 2005. The ESM payment for 2006 is contingent on Centrica’s future operating results and is contractually capped at $20 million. The payments are reflected in Gain/Loss on Disposition of Assets, Net on our Condensed Consolidated Statements of Operations.

DISCONTINUED OPERATIONS

Certain of our operations were determined to be discontinued operations and have been classified as such for all periods presented. Results of operations of these businesses have been classified as shown in the following table (in millions):
 

Three Months ended September 30, 2006 and 2005:
 
   
SEEBOARD (a)
 
U.K. Generation (b)
 
Total
 
2006 Revenue
 
$
-
 
$
-
 
$
-
 
2006 Pretax Income
   
-
   
-
   
-
 
2006 Earnings, Net of Tax
   
-
   
-
   
-
 
                     
2005 Revenue
 
$
13
 
$
-
 
$
13
 
2005 Pretax Income
   
13
   
-
   
13
 
2005 Earnings, Net of Tax
   
20
   
2
   
22
 
 
Nine Months ended September 30, 2006 and 2005:
 
   SEEBOARD (a)  
U.K.
Generation(c)
 
Total
 
2006 Revenue
 
$
-
 
$
-
 
$
-
 
2006 Pretax Income
   
-
   
9
   
9
 
2006 Earnings, Net of Tax
   
-
   
6
   
6
 
                     
2005 Revenue (Expense)
 
$
13
 
$
(8
)
$
5
 
2005 Pretax Income (Loss)
   
13
   
(8
)
 
5
 
2005 Earnings (Loss), Net of Tax
   
29
   
(3
)
 
26
 
 
(a)
The amounts relate to purchase price true-up adjustments and tax adjustments from the sale of SEEBOARD.
(b)
The amount relates to a tax adjustment from the sale.
(c)
The 2006 amounts relate to a release of accrued liabilities for the London office lease and tax adjustments from the sale. Amounts in 2005 relate to purchase price true-up adjustments and tax adjustments from the sale.

There were no cash flows used for or provided by operating, investing or financing activities related to our discontinued operations for the nine months ended September 30, 2006 and 2005.

ASSETS HELD FOR SALE AND ASSET IMPAIRMENTS

Texas Plants - Oklaunion Power Station (Utility Operations segment)

In January 2004, we signed an agreement to sell TCC’s 7.81% share of Oklaunion Power Station for approximately $43 million (subject to closing adjustments) to Golden Spread Electric Cooperative, Inc. (Golden Spread), subject to a right of first refusal by the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsville (the nonaffiliated co-owners). By May 2004, we received notice from the nonaffiliated co-owners announcing their decision to exercise their right of first refusal with terms similar to the original agreement. In June 2004 and September 2004, we entered into sales agreements with both of the nonaffiliated co-owners for the sale of TCC’s 7.81% ownership of the Oklaunion Power Station. Golden Spread challenged these agreements in State District Court in Dallas County. Golden Spread alleges that the Public Utilities Board of the City of Brownsville exceeded its legal authority and that the Oklahoma Municipal Power Authority did not exercise its right of first refusal in a timely manner. Golden Spread requested that the court declare the nonaffiliated co-owners’ exercise of their rights of first refusal void. The court entered a judgment in favor of Golden Spread in October 2005. TCC and the nonaffiliated co-owners filed an appeal to the Court of Appeals for the Fifth District at Dallas. In May 2006, the Court of Appeals for the Fifth District at Dallas reversed the trial court’s judgment in favor of Golden Spread and held that the City of Brownsville properly exercised its right of first refusal to acquire TCC’s share of Oklaunion. Golden Spread requested a rehearing in the matter, and its petition was denied. Golden Spread then appealed to the Supreme Court of Texas and in August 2006, the court requested a response from the Oklahoma Municipal Power Authority, the Public Utilities Board of the City of Brownsville and us. Responses were due October 27, 2006. We cannot predict when these issues will be resolved. We do not expect the sale to have a significant effect on the terms of the future results of operations. TCC’s assets related to the Oklaunion Power Station are classified as Assets Held for Sale on our Condensed Consolidated Balance Sheets at September 30, 2006 and December 31, 2005. 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.

Power Generation Facility (Investments - Other segment)

In August 2006, we reached an agreement to sell our Plaquemine Cogeneration Facility (the Facility) to Dow Chemical Company (Dow) for $64 million. We expect the sale to close in the fourth quarter of 2006. We recorded a pretax impairment of $209 million ($136 million, net of tax) in the third quarter of 2006 based on the terms of the agreement to sell the Facility to Dow. We recorded the impairment in Asset Impairments and Other Related Charges on our Condensed Consolidated Statements of Operations. We classified the Facility’s assets as Assets Held for Sale on our Condensed Consolidated Balance Sheet at September 30, 2006. The Facility does not meet the criteria for discontinued operations reporting.

In addition to the cash proceeds, the sale agreement allows us to participate in gross margin sharing on the Facility for five years. Dow will reduce an existing below-current-market long-term power supply contract with us in Texas by 50 MW, and we retain the right to any judgment paid by TEM for breaching the original PPA, as discussed in Note 5.

Conesville Units 1 and 2 (Utility Operations segment)

In the third quarter of 2005, following an extensive review of the commercial viability of CSPCo’s Conesville Units 1 and 2, management committed to a plan to retire these units before the end of their previously estimated useful lives. As a result, Conesville Units 1 and 2 were considered retired as of the third quarter of 2005.

We recognized a pretax charge of approximately $39 million in the third quarter of 2005 related to our decision to retire the units. We classified the impairment amount in Asset Impairments and Other Related Charges on our Condensed Consolidated Statements of Operations.

Assets Held for Sale at September 30, 2006 and December 31, 2005 are as follows:
 

September 30, 2006
 
Texas Plants
 
Power Generation Facility
 
Total
 
Assets:
 
(in millions)
 
Other Current Assets
 
$
2
 
$
-
 
$
2
 
Property, Plant and Equipment, Net
   
44
   
64
   
108
 
Total Assets Held for Sale
 
$
46
 
$
64
 
$
110
 
 
 
December 31, 2005
 
Texas Plants
 
Assets:
 
(in millions)
 
Other Current Assets
 
$
1
 
Property, Plant and Equipment, Net
   
43
 
Total Assets Held for Sale
 
$
44
 

 
         9.  BENEFIT PLANS

Components of Net Periodic Benefit Cost

The following table provides the components of our net periodic benefit cost for the following plans for the three and nine months ended September 30, 2006 and 2005:

   
Pension Plans
 
Other Postretirement
Benefit Plans
 
Three Months Ended September 30, 2006 and 2005:
 
2006
 
2005
 
2006
 
2005
 
   
(in millions)
 
Service Cost
 
$
23
 
$
23
 
$
10
 
$
10
 
Interest Cost
   
57
   
57
   
26
   
26
 
Expected Return on Plan Assets
   
(82
)
 
(77
)
 
(24
)
 
(23
)
Amortization of Transition (Asset) Obligation
   
-
   
(1
)
 
7
   
6
 
Amortization of Net Actuarial Loss
   
20
   
13
   
5
   
5
 
Net Periodic Benefit Cost
 
$
18
 
$
15
 
$
24
 
$
24
 
 

   
Pension Plans
 
Other Postretirement
Benefit Plans
 
Nine Months Ended September 30, 2006 and 2005:
 
2006
 
2005
 
2006
 
2005
 
   
(in millions)
 
Service Cost
 
$
71
 
$
69
 
$
30
 
$
31
 
Interest Cost
   
171
   
169
   
76
   
79
 
Expected Return on Plan Assets
   
(248
)
 
(232
)
 
(70
)
 
(68
)
Amortization of Transition (Asset) Obligation
   
-
   
(1
)
 
21
   
20
 
Amortization of Net Actuarial Loss
   
59
   
40
   
15
   
19
 
Net Periodic Benefit Cost
 
$
53
 
$
45
 
$
72
 
$
81
 


        10. STOCK-BASED COMPENSATION

As previously approved by shareholder vote, the Amended and Restated American Electric Power System Long-Term Incentive Plan (the Plan) authorizes the use of 19,200,000 shares of AEP common stock for various types of stock-based compensation awards, including stock option awards, to key employees. A maximum of 9,000,000 shares may be used under this plan for full value share awards, which include performance units, restricted shares and restricted stock units. The Board of Directors and shareholders both adopted the original Plan in 2000 and the amended and restated version in 2005.  We have not granted options as part of our regular stock-based compensation program since 2003.  However, we have used stock options in limited circumstances totaling 149,000 options in 2004, 10,000 options in 2005 and none during 2006.  The following sections provide further information regarding each type of stock-based compensation award the Board of Directors has granted.

We adopted SFAS 123R, effective January 1, 2006. See the SFAS 123 (revised 2004) “Share-Based Payment” section of Note 2 for additional information.

Stock Options

For all stock options previously granted, the exercise price equaled or exceeded the market price of AEP’s common stock on the date of grant. Historically the Board of Directors has granted stock options with a ten-year term that generally vest, subject to the participant’s continued employment, in approximately equal 1/3 increments on January 1st of the year following the first, second and third anniversary of the grant date. Compensation cost for stock options is recorded over the vesting period based on the fair value on the grant date. The Plan does not specify a maximum contractual term for stock options.

CSW maintained a stock option plan prior to the merger with AEP in 2000. Effective with the merger, all CSW stock options outstanding were converted into AEP stock options at an exchange ratio of one CSW stock option for 0.6 of an AEP stock option. The exercise price for each CSW stock option was adjusted for the exchange ratio. Outstanding CSW stock options will continue in effect until all options are exercised, cancelled, expired or forfeited. Under the CSW stock option plan, the option price was equal to the fair market value of the stock on the grant date. All CSW options fully vested upon the completion of the merger and expire 10 years after their original grant date.

The Board of Directors did not award any stock options during the nine months ended September 30, 2006.

The total fair value of stock options vested and the total intrinsic value of options exercised during the nine months ended September 30, 2006 was $3.7 million and $2.3 million, respectively. Intrinsic value is calculated as market price at exercise date less the option exercise price.
 
A summary of AEP stock option transactions during the nine months ended September 30, 2006 is as follows:
 

   
Options
 
Weighted Average Exercise Price
 
   
(in thousands)
 
Outstanding at January 1, 2006
   
6,222
 
$
34.16
 
Granted
   
-
   
-
 
Exercised/Converted
   
(369
)
 
30.17
 
Expired
   
-
   
-
 
Forfeited
   
(209
)
 
41.62
 
Outstanding at September 30, 2006
   
5,644
   
34.15
 
               
Exercisable at September 30, 2006
   
5,384
 
$
34.41
 
 
The following table summarizes information about AEP stock options outstanding at September 30, 2006.

 Options Outstanding
2006 Range of
Exercise Prices
 
 Number
Exercisable
 
 Weighted
Average
Remaining
Life
 
Weighted
Average
Exercise Price
 
Aggregate
Intrinsic
Value
 
   
 (in thousands)
 
 (in years)
      
(in thousands)
 
$25.73 - $27.95
   
1,359
   
5.9
 
$
27.38
 
$
12,220
 
$30.76 - $38.65
   
3,917
   
3.2
   
35.44
   
3,665
 
$43.79 - $49.00
   
368
   
4.6
   
45.43
   
-
 
     
5,644
   
4.0
   
34.15
 
$
15,885
 

The following table summarizes information about AEP stock options exercisable at September 30, 2006.

 Options Exercisable
2006 Range of
Exercise Prices
 
 Number
Exercisable
 
 Weighted
Average
Remaining
Life
 
Weighted
Average
Exercise Price
 
Aggregate
Intrinsic
Value
 
   
 (in thousands)
 
 (in years)
      
(in thousands)
 
$25.73 - $27.95
   
1,158
   
5.7
 
$
27.29
 
$
10,519
 
$30.76 - $35.63
   
3,858
   
3.2
   
35.49
   
3,386
 
$43.79 - $49.00
   
368
   
4.6
   
45.43
   
-
 
     
5,384
   
3.8
   
34.41
 
$
13,905
 

The proceeds received from exercised stock options are included in common stock and paid-in capital. For options issued through December 31, 2005, the grant date fair value of each option award was estimated using a Black-Scholes option-pricing model with weighted average assumptions. Expected volatilities are estimated using the historical monthly volatility of our common stock for the 36-month period prior to each grant. A seven-year average expected term is also assumed. The risk-free rate is the yield for U.S. Treasury securities with a remaining life equal to the expected seven-year term of AEP stock options on the grant date.

Performance Units

Our performance units are equal in value to an equivalent number of shares of AEP common stock. The number of performance units held is multiplied by a performance score to determine the actual number of performance units realized. The performance score is determined at the end of the performance period based on performance measure(s) established for each grant at the beginning of the performance period by the Human Resources Committee of the Board of Directors (HR Committee) and can range from 0 percent to 200 percent. Performance units are typically paid in cash at the end of a three-year performance and vesting period, unless they are needed to satisfy a participant’s stock ownership requirement, in which case they are mandatorily deferred as phantom stock units (AEP Career Shares) until after the end of the participant’s AEP career. AEP Career Shares have a value equivalent to the market value of an equal number of AEP common shares and are generally paid in cash after the participant’s termination of employment. Amounts equivalent to cash dividends on both performance units and AEP Career Shares accrue as additional units. The compensation cost for performance units is recorded over the vesting period and the liability for both the performance units and AEP Career Shares is adjusted for changes in value. The vesting period of all performance units is three years.

Our Board of Directors awarded performance units and reinvested dividends on outstanding performance units and AEP Career Shares for the nine months ended September 30, 2006 as follows:

Performance Units
      
Awarded Units (in thousands)
 
 864
 
Unit Fair Value at Grant Date
 
$
37.36
 
Vesting Period (years)
   
3
 

Performance Units and AEP Career Shares
(Reinvested Dividends Portion)
      
Awarded Units (in thousands)
 
 91
 
Weighted Average Grant Date Fair Value
 
$
35.37
 
Vesting Period (years) (a)
   
3
 

(a)
Vesting Period (years) range from 0 to 3 years. The Vesting Period of the reinvested dividends is equal to the remaining life of the related performance units and AEP Career Shares.

In January 2006, the HR Committee certified a performance score of 49% for performance units originally granted for the 2003 through 2005 performance period. As a result, 108,486 performance units were earned. Of this amount 33,296 were mandatorily deferred as AEP Career Shares, 4,360 were voluntarily deferred into the Incentive Compensation Deferral Program and the remainder were paid in cash.

The cash payouts for the nine months ended September 30, 2006 were $2.6 million for performance units and $1.0 million for AEP Career Share distributions.

The performance unit scores for all open performance periods are dependent on two equally-weighted performance measures: three-year total shareholder return measured relative to the S&P Utilities Index and three-year cumulative earnings per share measured relative to a board-approved target.  The value of each performance unit earned equals the average closing price of AEP common stock for the last 20 days of the performance period.

The fair value of performance unit awards is based on the estimated performance score and the current 20-day average closing price of AEP common stock at the date of valuation.

Restricted Shares and Restricted Stock Units

Our Board of Directors granted 300,000 restricted shares to the Chairman, President and CEO on January 2, 2004 upon the commencement of his AEP employment. Of these restricted shares, 50,000 vested on January 1, 2005 and 50,000 vested on January 1, 2006. The remaining 200,000 restricted shares vest, subject to his continued employment, in approximately equal thirds on November 30, 2009, 2010 and 2011. Compensation cost is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of shares granted by the grant date market price. The maximum term for these restricted shares is eight years. The Board of Directors has not granted other restricted shares. Dividends on our restricted shares are paid in cash.

Our Board of Directors may also grant restricted stock units, which generally vest, subject to the participant’s continued employment, over at least three years in approximately equal annual increments on the anniversaries of the grant date. Amounts equivalent to dividends paid on AEP shares accrue as additional restricted stock units that vest on the last vesting date associated with the underlying units. Compensation cost is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of units granted by the grant date market price. The maximum contractual term of these restricted stock units is six years.

In January 2006, our Board of Directors also granted restricted stock units with performance vesting conditions to certain employees who are integral to our project to design and build an IGCC power plant. Twenty percent of these awards vest on each of the first three anniversaries of the grant date. An additional 20% vest on the date the IGCC plant achieves commercial operations. The remaining 20% vest one year after the IGCC plant achieves commercial operations, subject to achievement of plant availability targets.

Our Board of Directors awarded 47,050 restricted stock units, including units awarded for dividends, with a weighted average grant date fair value of $35.58 per unit, for the nine months ended September 30, 2006.

The total fair value and total intrinsic value of restricted shares and restricted stock units vested during the nine months ended September 30, 2006 was $3.9 million and $4.6 million, respectively.

A summary of the status of our nonvested restricted shares and restricted stock units as of September 30, 2006, and changes during the nine months ended September 30, 2006 are as follows:
 

Nonvested Restricted Shares and Restricted Stock Units
 
Shares/Units
 
Weighted Average Grant Date Fair Value
 
 
 
(in thousands)
      
Nonvested at January 1, 2006
   
497
 
$
32.19
 
Granted
   
47
   
35.58
 
Vested
   
(127
)
 
30.56
 
Forfeited
   
(22
)
 
35.52
 
Nonvested at September 30, 2006
   
395
   
32.93
 
 

The total aggregate intrinsic value of nonvested restricted shares and restricted stock units as of September 30, 2006 was $14.4 million and the weighted average remaining contractual life was 3.03 years.

Share-based Compensation Plans

Compensation cost, the actual tax benefit realized for the tax deductions from compensation cost for share-based payment arrangements recognized in income and total compensation cost capitalized in relation to the cost of an asset for the nine months ended September 30, 2006 were as follows:

Share-based Compensation Plans
 
(in thousands)
 
Compensation Cost for Share-based Payment Arrangements (a)
 
$
16,671
 
Actual Tax Benefit Realized
   
5,835
 
Total Compensation Cost Capitalized
   
3,746
 

(a)
Compensation cost for share-based payment arrangements is included in Maintenance and Other Operation on our Condensed Consolidated Statements of Operations.

During the nine months ended September 30, 2006, there were no significant modifications affecting any of our share-based payment arrangements.

As of September 30, 2006, there was $49.1 million of total unrecognized compensation cost related to unvested share-based compensation arrangements granted under the Plan. Unrecognized compensation cost related to the performance units and AEP Career Shares will change as the liability is revalued each period and forfeitures for all award types are realized. Our unrecognized compensation cost will be recognized over a weighted-average period of 1.57 years.

Cash received from stock options exercised and actual tax benefit realized for the tax deductions from stock options exercised during the nine months ended September 30, 2006 was $11.1 million and $0.8 million, respectively.

Our practice is to use authorized but unissued shares to fulfill share commitments for stock option exercises and restricted stock unit vesting. Although we do not currently anticipate any changes to this practice, we could use reacquired shares, shares acquired in the open market specifically for distribution under the Plan or any combination thereof for this purpose. The number of new shares issued to fulfill vesting restricted stock units is generally reduced, at the participant’s election, to offset AEP’s tax withholding obligation.

         11. INCOME TAXES

In the second quarter of 2006, the Texas state legislature replaced the existing franchise/income tax with a gross margin tax at a 1% rate for electric utilities. Overall, the new law reduces Texas income tax rates and is effective January 1, 2007. The new gross margin tax is income-based for purposes of the application of SFAS 109 “Accounting for Income Taxes.” Based on the new law, we reviewed deferred tax liabilities with consideration given to the rate changes and changes to the allowed deductible items with temporary differences. As a result, in the second quarter of 2006 we recorded a net reduction to Deferred Income Taxes on the Condensed Consolidated Balance Sheet of $48 million of which $2 million was credited to Income Tax Expense and $46 million credited to Regulatory Assets based upon the related rate-making treatment.

        12. BUSINESS SEGMENTS

As outlined in our 2005 Annual Report, our business strategy and the core of our business are to focus on domestic electric utility operations. Our previous decision to no longer pursue business interests outside of our domestic core utility assets led us to divest such noncore assets. Consequently, the significance of our three Investments segments has declined.

Our 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.

Investments - Gas Operations

·
Gas pipeline and storage services.
·
Gas marketing and risk management activities.
·
We disposed of our gas pipeline and storage assets in 2005 with the sale of HPL (see “Dispositions” section of Note 8).

Investments - UK Operations 

·
International generation of electricity for sale to wholesale customers.
·
Coal procurement and transportation to our plants.
·
We classified UK Operations as Discontinued Operations during 2003 and sold them in 2004.

Investments - Other

·
Bulk commodity barging operations, wind farms, IPPs and other energy supply-related businesses.

The tables below present segment income statement information for the three and nine months ended September 30, 2006 and 2005 and balance sheet information as of September 30, 2006 and December 31, 2005. These amounts include certain estimates and allocations where necessary. Prior year amounts have been reclassified to conform to the current year’s presentation.


       
Investments
             
   
Utility Operations
 
Gas Operations
 
UK Operations
 
Other
 
All Other (a)
 
Reconciling Adjustments
 
Consolidated
 
   
(in millions)
 
Three Months Ended
                                    
September 30, 2006
                                    
Revenues from:
                                    
External Customers
 
$
3,485
 
$
(47
)
$
-
 
$
156
 
$
-
 
$
-
 
$
3,594
 
Other Operating Segments
   
(44
)
 
51
   
-
   
4
   
1
   
(12
)
 
-
 
Total Revenues
 
$
3,441
 
$
4
 
$
-
 
$
160
 
$
1
 
$
(12
)
$
3,594
 
                                         
Net Income (Loss)
 
$
379
 
$
(3
)
$
-
 
$
(109
)
$
(2
)
$
-
 
$
265
 

       
Investments
             
   
Utility Operations
 
Gas Operations
 
UK Operations
 
Other
 
All Other (a)
 
Reconciling Adjustments
 
Consolidated
 
   
(in millions)
 
Three Months Ended
                                    
September 30, 2005
                                    
Revenues from:
                                    
External Customers
 
$
3,152
 
$
73
 
$
-
 
$
103
 
$
-
 
$
-
 
$
3,328
 
Other Operating Segments
   
85
   
(77
)
 
-
   
3
   
1
   
(12
)
 
-
 
Total Revenues
 
$
3,237
 
$
(4
)
$
-
 
$
106
 
$
1
 
$
(12
)
$
3,328
 
                                         
Income (Loss) Before Discontinued
  Operations
 
$
352
 
$
(10
)
$
-
 
$
28
 
$
(5
)
$
-
 
$
365
 
Discontinued Operations, Net of Tax
   
-
   
-
   
2
   
20
   
-
   
-
   
22
 
Net Income (Loss)
 
$
352
 
$
(10
)
$
2
 
$
48
 
$
(5
)
$
-
 
$
387
 

       
Investments
             
   
Utility Operations
 
Gas Operations
 
UK Operations
 
Other
 
All Other (a)
 
Reconciling Adjustments
 
Consolidated
 
   
(in millions)
 
Nine Months Ended
                                    
September 30, 2006
                                    
Revenues from:
                                    
External Customers
 
$
9,282
 
$
(80
)
$
-
 
$
436
 
$
-
 
$
-
 
$
9,638
 
Other Operating Segments
   
(73
)
 
89
   
-
   
9
   
2
   
(27
)
 
-
 
Total Revenues
 
$
9,209
 
$
9
 
$
-
 
$
445
 
$
2
 
$
(27
)
$
9,638
 
                                         
Income (Loss) Before Discontinued
  Operations
 
$
904
 
$
(2
)
$
-
 
$
(80
)
$
(7
)
$
-
 
$
815
 
Discontinued Operations, Net of Tax
   
-
   
-
   
6
   
-
   
-
   
-
   
6
 
Net Income (Loss)
 
$
904
 
$
(2
)
$
6
 
$
(80
)
$
(7
)
$
-
 
$
821
 


       
Investments
             
   
Utility Operations
 
Gas Operations
 
UK Operations
 
Other
 
All Other (a)
 
Reconciling Adjustments
 
Consolidated
 
   
(in millions)
 
Nine Months Ended
                                    
September 30, 2005
                                    
Revenues from:
                                    
External Customers
 
$
8,437
 
$
449
 
$
-
 
$
326
 
$
-
 
$
-
 
$
9,212
 
Other Operating Segments
   
186
   
(167
)
 
-
   
12
   
2
   
(33
)
 
-
 
Total Revenues
 
$
8,623
 
$
282
 
$
-
 
$
338
 
$
2
 
$
(33
)
$
9,212
 
                                         
Income (Loss) Before Discontinued Operations
 
$
952
 
$
(2
)
$
-
 
$
32
 
$
(45
)
$
-
 
$
937
 
Discontinued Operations, Net of Tax
   
-
   
-
   
(3
)
 
29
   
-
   
-
   
26
 
Net Income (Loss)
 
$
952
 
$
(2
)
$
(3
)
$
61
 
$
(45
)
$
-
 
$
963
 
 

         
Investments
               
  
 
   
Utility Operations
   
Gas Operations
 
 
UK Operations
 
 
Other
   
All Other (b)
   
Reconciling Adjustments (b)
   
Consolidated
 
   
(in millions)
 
As of September 30, 2006
                                                       
Total Property, Plant and Equipment
 
$
40,397
   
$
1
   
$
-
   
$
567
   
$
3
   
$
-
   
$
40,968
 
Accumulated Depreciation and Amortization
   
15,014
     
-
     
-
     
130
     
2
     
-
     
15,146
 
Total Property, Plant and Equipment - Net
 
$
25,383
   
$
1
   
$
-
   
$
437
   
$
1
   
$
-
   
$
25,822
 
                                                         
Total Assets
 
$
35,185
   
$
591
(c)  
$
639
(d)  
$
72
   
$
10,372
   
$
(10,474
)
 
$
36,385
 
Assets Held for Sale
   
46
     
-
     
-
     
64
     
-
     
-
     
110
 
 
 
         
Investments
               
  
 
   
Utility Operations
   
Gas Operations
 
 
UK Operations
 
 
Other
   
All Other (b)
   
Reconciling Adjustments (b)
   
Consolidated
 
 
   
 (in millions)
 
As of December 31, 2005
                                                       
Total Property, Plant and Equipment
 
$
38,283
   
$
2
   
$
-
   
$
833
   
$
3
   
$
-
   
$
39,121
 
Accumulated Depreciation and Amortization
   
14,723
     
1
     
-
     
112
     
1
     
-
     
14,837
 
Total Property, Plant and Equipment - Net
 
$
23,560
   
$
1
   
$
-
   
$
721
   
$
2
   
$
-
   
$
24,284
 
                                                         
Total Assets
 
$
34,339
   
$
1,199
(e)  
$
632
(f)  
$
509
   
$
9,463
   
$
(9,970
)
 
$
36,172
 
Assets Held for Sale
   
44
     
-
     
-
     
-
     
-
     
-
     
44
 
 
 
(a)
All Other includes the parent company’s guarantee revenue, interest income and expense, as well as other nonallocated costs.
(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 (included in All Other) in subsidiary companies.
(c)
Total Assets of $591 million for the Investments-Gas Operations segment include $321 million in affiliated accounts receivable related to the corporate borrowing program and risk management contracts that are eliminated in consolidation. The majority of the remaining $270 million in assets represents third party risk management contracts, margin deposits and accounts receivable.
(d)
Total Assets of $639 million for the Investments-UK Operations segment include $625 million in affiliated accounts receivable related mainly to federal income taxes that are eliminated in consolidation. The majority of the remaining $14 million in assets represents cash equivalents.
(e)
Total Assets of $1.2 billion for the Investments-Gas Operations segment include $429 million in affiliated accounts receivable related to the corporate borrowing program and risk management contracts that are eliminated in consolidation. The majority of the remaining $770 million in assets represents third party risk management contracts, margin deposits, and accounts receivable.
(f)
Total Assets of $632 million for the Investments-UK Operations segment include $613 million in affiliated accounts receivable related to federal income taxes that are eliminated in consolidation. The majority of the remaining $19 million in assets represents cash equivalents and value-added tax receivables.

        13.   FINANCING ACTIVITIES

Long-term Debt

Our outstanding long-term debt is as follows:

   
September 30,
 
December 31,
 
Type of Debt
 
2006
 
2005
 
   
(in millions)
 
             
Pollution Control Bonds
 
$
2,051
 
$
1,935
 
Senior Unsecured Notes
   
8,827
   
8,226
 
First Mortgage Bonds
   
96
   
196
 
Defeased First Mortgage Bonds (a)
   
26
   
26
 
Notes Payable
   
872
   
904
 
Securitization Bonds
   
596
   
648
 
Notes Payable To Trust
   
113
   
113
 
Other Long-Term Debt (b)
   
247
   
236
 
Unamortized Discount (net)
   
(65
)
 
(58
)
Total Long-term Debt Outstanding
   
12,763
   
12,226
 
Less Portion Due Within One Year
   
1,789
   
1,153
 
Long-term Portion
 
$
10,974
 
$
11,073
 

(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 $18 million at both September 30, 2006 and December 31, 2005. Trust fund assets related to this obligation of $2 million are included in Other Temporary Cash Investments at both September 30, 2006 and December 31, 2005 and $21 million is included in Other Noncurrent Assets in the Condensed Consolidated Balance Sheets at both September 30, 2006 and December 31, 2005. 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 September 30, 2006 and December 31, 2005. Trust fund assets related to this obligation of $9 million and $1 million at September 30, 2006 and December 31, 2005, respectively, are included in Other Temporary Cash Investments and $0 and $8 million are included in Other Noncurrent Assets in the Condensed Consolidated Balance Sheets at September 30, 2006 and December 31, 2005, respectively. 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 of $270 million and $264 million related to this obligation are included in Spent Nuclear Fuel and Decommissioning Trusts in the Condensed Consolidated Balance Sheets at September 30, 2006 and December 31, 2005, respectively.
 
Long-term debt issued, retired and principal payments made during the first nine months of 2006 are shown in the tables below.
 
Company
 
Type of Debt
 
Principal Amount
 
Interest Rate
 
Due Date
 
       
(in millions)
 
(%)
     
Issuances:
                 
APCo
 
Pollution Control Bonds
 
$
50
 
Variable
 
2036
 
APCo
 
Senior Unsecured Notes
   
250
 
5.55
 
2011
 
APCo
 
Senior Unsecured Notes
   
250
 
6.375
 
2036
 
I&M
 
Pollution Control Bonds
   
50
 
Variable
 
2025
 
OPCo
 
Pollution Control Bonds
   
65
 
Variable
 
2036
 
OPCo
 
Senior Unsecured Notes
   
350
 
6.00
 
2016
 
PSO
 
Senior Unsecured Notes
   
150
 
6.15
 
2016
 
SWEPCo
 
Pollution Control Bonds
   
82
 
Variable
 
2018
 
Total Issuances
     
$
1,247
(a)
       
 
The above borrowing arrangements do not contain guarantees, collateral or dividend restrictions.

(a)
Amount indicated on statement of cash flows of $1,229 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:
                 
AEP
 
Senior Unsecured Notes
 
$
396
 
6.125
 
2006
 
APCo
 
First Mortgage Bonds
   
100
 
6.80
 
2006
 
I&M
 
Pollution Control Bonds
   
50
 
6.55
 
2025
 
OPCo
 
Notes Payable
   
4
 
6.81
 
2008
 
OPCo
 
Notes Payable
   
7
 
6.27
 
2009
 
SWEPCo
 
Notes Payable
   
5
 
4.47
 
2011
 
SWEPCo
 
Notes Payable
   
2
 
Variable
 
2008
 
SWEPCo
 
Pollution Control Bonds
   
82
 
6.10
 
2018
 
TCC
 
Securitization Bonds
   
52
 
5.01
 
2010
 
Non-Registrant:
                   
AEP subsidiaries
 
Notes Payable
   
9
 
Variable
 
2017
 
CSW Energy, Inc.
 
Notes Payable
   
4
 
5.88
 
2011
 
Total Retirements and Principal
 Payments
     
$
711
         

In October 2006, TCC issued $1.74 billion in securitization bonds as follows:

Principal
 
Interest
 
Scheduled Final
Amount
 
Rate
 
Payment Date
 
(in millions)
 
(%)
   
           
$
217
 
4.98
 
2010
 
341
 
4.98
 
2013
 
250
 
5.09
 
2015
 
437
 
5.17
 
2018
 
495
 
5.3063
 
2020

The proceeds will be used to retire TCC debt and equity, which are no longer needed to support stranded costs.

In October 2006, I&M had a required remarketing of $65 million of 2.625% pollution control bonds, which were converted from a three-year fixed rate mode to an auction rate mode.

In November 2006, APCo had a required remarketing of $30 million of 2.80% pollution control bonds, which were converted from a three-year fixed rate mode to an auction rate mode.

In November 2006, APCo issued $17.5 million of variable rate pollution control bonds and retired $17.5 million, 2.70% pollution control bonds due in 2007.

In November 2006, $100.6 million of pollution control bonds were put back to TCC on the put date of November 1, 2006. TCC intends to hold these bonds for reissuance at a later date.

Credit Facilities

In April 2006, we amended the terms and increased the size of our credit facilities from $2.7 billion to $3 billion. The amended facilities are structured as two $1.5 billion credit facilities, with an option in each to issue up to $200 million as letters of credit, expiring separately in March 2010 and April 2011. We also terminated an existing $200 million letter of credit facility.
 
 







 
 
 
 
AEP GENERATING COMPANY


 

 

 


















AEP GENERATING COMPANY
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

As co-owner of the Rockport Plant, we engage in the generation and wholesale sale of electric power to two affiliates, I&M and KPCo, under long-term agreements. I&M is the operator and co-owner of the Rockport Plant.

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. 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. We divide costs of operating the plant between the co-owners.

Results of Operations

Net Income was unchanged for the third quarter of 2006 compared with the third quarter of 2005. Net Income increased $0.6 million for the nine months ended September 30, 2006 compared with the nine months ended September 30, 2005. 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 which is calculated and adjusted monthly.

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income
(in millions)

Third Quarter of 2005
       
$
2.2
 
               
Change in Gross Margin:
             
Wholesale Sales
         
0.2
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(0.7
)
     
Taxes Other Than Income Taxes
   
0.7
       
Interest Expense
   
(0.1
)
     
Total Change in Operating Expenses and Other
         
(0.1
)
               
Income Tax Expense
         
(0.1
)
               
Third Quarter of 2006
       
$
2.2
 

Gross Margin, defined as Operating Revenues less Fuel for Electric Generation, increased $0.2 million primarily due to recovery of higher expenses.

Other Operation and Maintenance expenses increased primarily due to increased costs at the Rockport Plant for steam plant operation and maintenance of structures.

Taxes Other Than Income Taxes decreased primarily due to lower real and personal property taxes as the prior year accrual was adjusted to the actual amount paid.
 
Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to
Nine Months Ended September 30, 2006 Net Income
(in millions)

Nine Months Ended September 30, 2005
       
$
6.8
 
               
Changes in Gross Margin:
             
Wholesale Sales
         
3.2
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(2.0
)
     
Taxes Other Than Income Taxes
   
0.7
       
Interest Expense
   
(0.3
)
     
Total Change in Operating Expenses and Other
         
(1.6
)
               
Income Tax Expense
         
(1.0
)
               
Nine Months Ended September 30, 2006
       
$
7.4
 

Gross Margin, defined as Operating Revenues less Fuel for Electric Generation, increased $3.2 million primarily due to recovery of higher expenses and higher returns earned on plant and capital investment.

Other Operation and Maintenance expenses increased $2.0 million primarily due to increased maintenance cost at the Rockport Plant during a planned outage in 2006 and credits allocated to us in February 2005 from the cancellation and settlement of corporate owned life insurance policies.

Taxes Other Than Income Taxes decreased $0.7 million primarily due to lower real and personal property taxes as the prior year accrual was adjusted to the actual amount paid.

Income Taxes

Income Tax Expense increased $1.0 million primarily due to an increase in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis.

Off-Balance Sheet Arrangements

In prior years, we entered into an off-balance sheet arrangement for the lease of Rockport Plant Unit 2. Our current guidelines restrict the use of off-balance sheet financing entities or structures to allow only traditional operating lease arrangements. Our off-balance sheet arrangement has not changed significantly since year-end. For complete information on our off-balance sheet arrangement see “Off-balance Sheet Arrangements” in the “Management’s Narrative Financial Discussion and Analysis” section of our 2005 Annual Report.

Summary Obligation Information

A summary of our contractual obligations is included in our 2005 Annual Report and has not changed significantly from year-end.

Significant Factors

In July 2006, we remarketed $45 million of pollution control bonds at a rate of 4.15% compared to a previous rate of 4.05% until July 14, 2011, the next remarketing date.

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 2005 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.
 



AEP GENERATING COMPANY
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2006 and 2005
(Unaudited)
(in thousands)

   
Three Months Ended
 
Nine Months Ended
 
   
2006
 
2005
 
2006
 
2005
 
                     
OPERATING REVENUES
 
$
74,756
 
$
69,640
 
$
230,102
 
$
201,268
 
                           
EXPENSES
                         
Fuel for Electric Generation
   
42,354
   
37,403
   
131,402
   
105,771
 
Rent - Rockport Plant Unit 2
   
17,070
   
17,070
   
51,212
   
51,212
 
Other Operation
   
3,381
   
2,803
   
9,598
   
8,376
 
Maintenance
   
2,522
   
2,421
   
7,238
   
6,411
 
Depreciation and Amortization
   
5,951
   
5,956
   
17,858
   
17,901
 
Taxes Other Than Income Taxes
   
368
   
1,074
   
2,466
   
3,149
 
TOTAL
   
71,646
   
66,727
   
219,774
   
192,820
 
                           
OPERATING INCOME
   
3,110
   
2,913
   
10,328
   
8,448
 
                           
Other Income (Expense):
                         
Interest Income
   
-
   
-
   
-
   
24
 
Allowance for Equity Funds Used During Construction
   
-
   
-
   
24
   
60
 
Interest Expense
   
(774
)
 
(652
)
 
(2,137
)
 
(1,848
)
                           
INCOME BEFORE INCOME TAXES
   
2,336
   
2,261
   
8,215
   
6,684
 
Income Tax Expense (Credit)
   
117
   
22
   
848
   
(144
)
                           
NET INCOME
 
$
2,219
 
$
2,239
 
$
7,367
 
$
6,828
 

CONDENSED STATEMENTS OF RETAINED EARNINGS
For the Three and Nine Months Ended September 30, 2006 and 2005
(Unaudited)
(in thousands)

   
Three Months Ended
 
Nine Months Ended
 
   
2006
 
2005
 
2006
 
2005
 
                     
BALANCE AT BEGINNING OF PERIOD
 
$
27,176
 
$
26,947
 
$
26,038
 
$
24,237
 
                           
Net Income
   
2,219
   
2,239
   
7,367
   
6,828
 
                           
Cash Dividends Declared
   
-
   
3,015
   
4,010
   
4,894
 
                           
BALANCE AT END OF PERIOD
 
$
29,395
 
$
26,171
 
$
29,395
 
$
26,171
 

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
September 30, 2006 and December 31, 2005
(Unaudited)
(in thousands)

   
2006
 
2005
 
CURRENT ASSETS
           
Accounts Receivable - Affiliated Companies
 
$
24,356
 
$
29,671
 
Fuel
   
24,139
   
14,897
 
Materials and Supplies
   
7,913
   
7,017
 
Accrued Tax Benefits
   
2,009
   
2,074
 
Prepayments and Other
   
105
   
9
 
TOTAL
   
58,522
   
53,668
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric - Production
   
686,025
   
684,721
 
Other
   
2,385
   
2,369
 
Construction Work in Progress
   
11,391
   
12,252
 
Total
   
699,801
   
699,342
 
Accumulated Depreciation and Amortization
   
393,529
   
382,925
 
TOTAL - NET
   
306,272
   
316,417
 
               
Noncurrent Assets
   
7,738
   
6,618
 
               
TOTAL ASSETS
 
$
372,532
 
$
376,703
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



AEP GENERATING COMPANY
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY
September 30, 2006 and December 31, 2005
(Unaudited)

   
2006
 
2005
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
 
$
14,938
 
$
35,131
 
Accounts Payable:
             
General
   
1,311
   
926
 
Affiliated Companies
   
21,018
   
22,161
 
Long-term Debt Due Within One Year
   
-
   
44,828
 
Accrued Taxes
   
5,880
   
3,055
 
Accrued Rent - Rockport Plant Unit 2
   
23,427
   
4,963
 
Other
   
805
   
1,228
 
TOTAL
   
67,379
   
112,292
 
               
NONCURRENT LIABILITIES
             
Long-term Debt
   
44,835
   
-
 
Deferred Income Taxes
   
20,852
   
23,617
 
Asset Retirement Obligations
   
1,399
   
1,370
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
82,331
   
82,689
 
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2
   
90,155
   
94,333
 
Obligations Under Capital Leases
   
11,752
   
11,930
 
TOTAL
   
251,324
   
213,939
 
               
TOTAL LIABILITIES
   
318,703
   
326,231
 
               
Commitments and Contingencies (Note 5)
             
               
COMMON SHAREHOLDER’S EQUITY
             
Common Stock - $1,000 Par Value Per Share 
  Authorized and Outstanding - 1,000 Shares
   
1,000
   
1,000
 
Paid-in Capital
   
23,434
   
23,434
 
Retained Earnings
   
29,395
   
26,038
 
TOTAL
   
53,829
   
50,472
 
               
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY
 
$
372,532
 
$
376,703
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



AEP GENERATING COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
OPERATING ACTIVITIES
           
Net Income
 
$
7,367
 
$
6,828
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
17,858
   
17,901
 
Deferred Income Taxes
   
(3,468
)
 
(3,539
)
Deferred Investment Tax Credits
   
(2,482
)
 
(2,501
)
Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2
   
(4,178
)
 
(4,178
)
Deferred Property Taxes
   
(893
)
 
(1,010
)
Changes in Other Noncurrent Assets
   
(2,885
)
 
(1,736
)
Changes in Other Noncurrent Liabilities
   
2,776
   
2,201
 
Changes in Components of Working Capital:
             
Accounts Receivable
   
5,315
   
(2,469
)
Fuel, Materials and Supplies
   
(10,138
)
 
4,278
 
Accounts Payable
   
(758
)
 
(1,188
)
Accrued Taxes, Net
   
2,890
   
(2,982
)
Rent Accrued - Rockport Plant Unit 2
   
18,464
   
18,464
 
Other Current Assets
   
(96
)
 
(17
)
Other Current Liabilities
   
(423
)
 
(363
)
Net Cash Flows From Operating Activities
   
29,349
   
29,689
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(4,978
)
 
(9,041
)
               
FINANCING ACTIVITIES
             
Change in Advances from Affiliates, Net
   
(20,193
)
 
(15,601
)
Principal Payments for Capital Lease Obligations
   
(168
)
 
(153
)
Dividends Paid
   
(4,010
)
 
(4,894
)
Net Cash Flows Used For Financing Activities
   
(24,371
)
 
(20,648
)
               
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
 
$
2,413
 
$
2,104
 
Net Cash Paid for Income Taxes
   
6,037
   
11,025
 
Noncash Acquisitions Under Capital Leases
   
78
   
31
 

   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 and Contingencies
Note 5
Guarantees
Note 6
Company-wide Staffing and Budget Review
Note 7
Business Segments
Note 11
Financing Activities
Note 12
 







 
 
 
 

 


AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 







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

Allocation Agreement between AEP East companies and AEP West companies

Under the Texas Restructuring Legislation, we are completing the final stage of exiting the generation business and have ceased serving retail load. Based on the corporate separation and generation divestiture activities underway, the nature of our business is no longer compatible with our participation in the CSW Operating Agreement and the SIA since these agreements involve the coordinated planning and operation of power supply facilities. Accordingly, on behalf of the AEP East companies and the AEP West companies, AEPSC filed with the FERC to remove us from those agreements. The FERC approved the filing in March 2006. The SIA includes a methodology for sharing trading and marketing margins among the AEP East companies and the AEP West companies. Our sharing of margins ceased effective May 1, 2006, which affects our future results of operations and cash flows. We will continue to have margin and collateral deposits, risk management assets and liabilities and trading gains or losses to the extent that we have contracts dedicated specifically to us. As of September 30, 2006, we have no dedicated contracts.

Results of Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income
(in millions)

Third Quarter of 2005
       
$
40
 
               
Changes in Gross Margin:
             
Texas Supply
   
(4
)
     
Texas Wires
   
(1
)
     
Off-system Sales
   
(18
)
     
Transmission Revenues
   
(3
)
     
Other
   
(3
)
     
Total Change in Gross Margin
         
(29
)
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
1
       
Carrying Costs Income
   
10
       
Other Income
   
(7
)
     
Interest Expense
   
(11
)
     
Total Change in Operating Expenses and Other
         
(7
)
               
Income Tax Expense
         
13
 
               
Third Quarter of 2006
       
$
17
 

Net Income decreased $23 million to $17 million in 2006. The key drivers of the decrease were a $29 million decrease in Gross Margin and a $7 million increase in Operating Expenses and Other, partially offset by a reduction in Income Tax Expense of $13 million. We substantially exited the generation market with the sale of STP in May 2005.

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

·
Texas Supply margins decreased $4 million primarily due to lower nonaffiliated sales of $3 million.
·
Margins from Off-system Sales decreased $18 million due to an $11 million decrease in margin sharing under the SIA (no current margin sharing under the CSW Operating Agreement and the SIA) and a $7 million decrease in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
·
Transmission Revenues decreased $3 million primarily due to lower ERCOT transmission rates and reduced affiliated transmission fees resulting from the elimination of the affiliated OATT in 2005.
·
Other revenues decreased $3 million primarily due to lower securitization revenues of $3 million. Securitization revenues 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.

Operating Expenses and Other changed between years as follows:

·
Carrying Costs Income increased $10 million primarily due to a negative adjustment of $8 million made in the third quarter of 2005 related to our True-up Proceeding orders received from the PUCT.
·
Other Income decreased $7 million primarily due to interest income recorded in the prior year related to the 2005 Texas Court of Appeals order (see “Texas Restructuring - Excess Earnings” section of Note 4).
·
Interest Expense increased $11 million primarily due to a $9 million increase in accrued interest related to the Texas competition transition charge liability (See “Texas Restructuring - CTC Proceeding for Other True-up Items” section of Note 4).

Income Taxes

The decrease in Income Tax Expense of $13 million is primarily due to a decrease in pretax book income.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to
Nine Months Ended September 30, 2006 Net Income
(in millions)

Nine Months Ended September 30, 2005
       
$
70
 
               
Changes in Gross Margin:
             
Texas Supply
   
(78
)
     
Texas Wires
   
14
       
Off-system Sales
   
(21
)
     
Transmission Revenues
   
(12
)
     
Other
   
(9
)
     
Total Change in Gross Margin
         
(106
)
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
50
       
Depreciation and Amortization
   
(6
)
     
Taxes Other Than Income Taxes
   
6
       
Carrying Costs Income
   
35
       
Other Income
   
(13
)
     
Interest Expense
   
(8
)
     
Total Change in Operating Expenses and Other
         
64
 
               
Income Tax Expense
         
10
 
               
Nine Months Ended September 30, 2006
       
$
38
 

Net Income decreased $32 million to $38 million in 2006. The key driver of the decrease was a $106 million decrease in Gross Margin, partially offset by a reduction in Other Operation and Maintenance expenses of $50 million and increased Carrying Costs Income of $35 million. We substantially exited the generation market with the sale of STP in May 2005.

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

·
Texas Supply margins decreased $78 million primarily due to the sale of STP, which resulted in lower nonaffiliated sales of $101 million and a $6 million provision for refund primarily due to the fuel reconciliation adjustment in 2005. These decreases were partially offset by lower fuel and purchased power expenses of $30 million.
·
Texas Wires revenues increased $14 million primarily due to favorable prices and a five percent increase in degree days.
·
Margins from Off-system Sales decreased $21 million due to a $15 million decrease in margin sharing under the SIA and a $6 million decrease in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
·
Transmission Revenues decreased $12 million primarily due to lower ERCOT transmission rates and reduced affiliated transmission fees resulting from the elimination of the affiliated OATT in 2005.
·
Other revenues decreased $9 million primarily due to lower third party construction project revenues of $4 million related to work performed for the Lower Colorado River Authority and reduced securitization revenues of $6 million. Securitization revenues 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.

Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expenses decreased $50 million primarily due to a $12 million decrease in plant operations, a $14 million decrease in plant maintenance, a $6 million decrease in administrative and general expenses and the absence of $7 million in accretion expense all related to the sale of STP. An additional $4 million decrease resulted from lower expenses related to construction activities performed for third parties, primarily the Lower Colorado River Authority.
·
Depreciation and Amortization expense increased $6 million primarily related to the refund and amortization of excess earnings credits in 2005 partially offset by the recovery and amortization of securitized assets.
·
Taxes Other Than Income Taxes decreased $6 million primarily due to lower property-related taxes as a result of the sale of STP in 2005 and the favorable settlement of a state use tax audit in 2006.
·
Carrying Costs Income increased $35 million primarily due to negative adjustments of $29 million and $8 million made in the first and third quarters of 2005, respectively, related to our True-up Proceeding orders received from the PUCT.
·
Other Income decreased $13 million primarily due to interest income recorded in the prior year related to the 2005 Texas Court of Appeals order (See “Texas Restructuring - Excess Earnings” section of Note 4).
·
Interest Expense increased $8 million primarily due to a $12 million increase in accrued interest related to the Texas CTC liability (see “Texas Restructuring - CTC Proceeding for Other True-up Items” section of Note 4) partially offset by a $2 million decrease in interest expense associated with securitization revenues.

Income Taxes

The decrease in Income Tax Expense of $10 million is primarily due to a decrease in pretax book income, offset in part by tax reserve adjustments, a decrease in the amortization of investment tax credits due to the sale in May 2005 of STP and a decrease in consolidated tax savings from AEP.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Our current ratings are as follows:
 
 
Moody’s
 
S&P
 
Fitch
           
First Mortgage Bonds
Baa1
 
BBB
 
A
Senior Unsecured Debt
Baa2
 
BBB
 
A-

Cash Flow

Cash flows for the nine months ended September 30, 2006 and 2005 were as follows:

   
2006
 
2005
 
   
(in thousands)
 
Cash and Cash Equivalents at Beginning of Period
 
$
-
 
$
26
 
Net Cash Flows From (Used For):
             
Operating Activities
   
137,471
   
(95,431
)
Investing Activities
   
(197,269
)
 
293,461
 
Financing Activities
   
59,803
   
(198,053
)
Net Increase (Decrease) in Cash and Cash Equivalents
   
5
   
(23
)
Cash and Cash Equivalents at End of Period
 
$
5
 
$
3
 

Operating Activities

Net Cash Flows From Operating Activities were $137 million during the first nine months of 2006. We produced Net Income of $38 million during the period and incurred noncash items of $111 million for Depreciation and Amortization and $(65) million for Carrying Costs on Stranded Cost Recovery. 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 most significant are decreases in Accounts Receivable, Net partially offset by a decrease in Accounts Payable. Accounts Receivable, Net decreased $159 million primarily due to cash received for the retail clawback of $61 million and 2005 storm restoration performed for nonaffiliated companies of $12 million. In addition, our removal from the SIA and CSW Operating Agreement effective May 1, 2006 resulted in fewer energy-related receivables. Accounts Payable decreased $108 million primarily due to lower energy-related transactions resulting from our removal from the SIA and CSW Operating Agreement.

Net Cash Flows Used For Operating Activities were $95 million during the first nine months of 2005. We produced income of $70 million during the period including noncash expense items of $105 million for Depreciation and Amortization and $(63) million for Deferred Income Taxes. 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 these asset and liability accounts relate to a number of items; the most significant is a decrease in Accrued Taxes, Net. Accrued Taxes, Net decreased $111 million primarily as a result of taxes remitted to the government related to prior year and current year tax accruals.

Investing Activities

Net Cash Flows Used For Investing Activities in 2006 were $197 million primarily due to $203 million of Construction Expenditures focused mainly on improved service reliability projects for transmission and distribution systems. For the remainder of 2006, we expect $83 million in Construction Expenditures.

Net Cash Flows From Investing Activities in 2005 were $293 million primarily due to $314 million of net proceeds from the sale of the STP nuclear plant and a reduction in Other Cash Deposits, Net of $93 million primarily for the retirement of defeased first mortgage bonds of $66 million. These cash inflows were partially offset by cash used for construction expenditures of $109 million related to projects for transmission and distribution service reliability.

Financing Activities

Net Cash Flows From Financing Activities in 2006 were $60 million primarily due to the issuance of $195 million of affiliated notes with AEP. This increase in long-term debt was partially offset by a decrease in Advances from Affiliates, Net of $82 million and the retirement of $52 million of securitization bonds.

Net Cash Flows Used for Financing Activities in 2005 were $198 million primarily due to the payments of dividends of $150 million and the retirement of long-term debt of $486 million, including $66 million of bonds that were defeased in 2004. This was partially offset by an issuance of new debt of $427 million, including $150 million of affiliated long-term debt.

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2006 were:

Issuances

   
Principal
Amount
 
Interest
 
Due
Type of Debt
   
Rate
 
Date
     
(in thousands)
 
(%)
   
               
Notes Payable - Affiliated
 
$
125,000
 
5.14
 
2007
Notes Payable - Affiliated
   
70,000
 
5.86
 
2007

Retirements

   
Principal
Amount
 
Interest
 
Due
Type of Debt
   
Rate
 
Date
     
(in thousands)
 
(%)
   
               
Securitization Bonds
 
$
52,265
 
5.01
 
2010

In October 2006 TCC issued $1.74 billion in securitization bonds, as follows:

Principal
 
Interest
 
Scheduled Final
Amount
 
Rate
 
Payment Date
 
(in thousands)
 
(%)
   
           
$
217,000
 
4.98
 
2010
 
341,000
 
4.98
 
2013
 
250,000
 
5.09
 
2015
 
437,000
 
5.17
 
2018
 
494,700
 
5.3063
 
2020

The proceeds will generally be used to retire TCC debt and equity, which are no longer needed to support stranded costs.

In October 2006, we retired $345 million in intercompany notes payable as follows:

Principal
Amount
 
Interest
 
Due
 
Rate
 
Date
 
(in thousands)
 
(%)
   
           
$
150,000
 
4.58
 
2007
 
125,000
 
5.14
 
2007
 
70,000
 
5.86
 
2007

In November 2006, $100.6 million of pollution control bonds were put back to TCC on the put date of November 1, 2006. TCC intends to hold these bonds for reissuance at a later date.

In October 2006, we also paid a special dividend of $585 million to AEP.

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.

We will use proceeds received from the securitization to pay down a portion of our equity and debt and to pay any necessary accelerated refunds related to the CTC (discussed below under Texas Restructuring).

Summary Obligation Information

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

Significant Factors

Texas Restructuring

In June 2006, we filed to implement a CTC refund of $357 million for our other true-up items over eight years. The differences between the components of our Recorded Net Regulatory Liabilities - Other True-up Items as of September 30, 2006 (including interest) and our Net CTC Refund Proposed are detailed below:

   
(in millions)
 
Wholesale Capacity Auction True-up
 
$
61
 
Carrying Costs on Wholesale Capacity Auction True-up
   
31
 
Retail Clawback including Carrying Costs
   
(65
)
Deferred Over-recovered Fuel Balance
   
(184
)
Retrospective ADFIT Benefit
   
(77
)
Other
   
(4
)
Recorded Net Regulatory Liabilities - Other True-up Items
   
(238
)
Unrecorded Prospective ADFIT Benefit
   
(240
)
Gross CTC Refund Proposed
   
(478
)
FERC Jurisdictional Fuel Refund Deferral
   
16
 
ADITC and EDFIT Benefit Refund Deferral
   
98
 
Net CTC Refund Proposed, After Deferrals
   
(364
)
True-up Proceeding Expense Surcharge
   
7
 
Net CTC Refund Proposed, After Deferrals and Expenses
 
$
(357
)

In September 2006, the PUCT approved an interim CTC that was implemented on October 12, 2006, the same day that we began billing customers for the securitization bonds. The interim CTC will refund the entire retail clawback of $65 million (including carrying costs) to residential customers by the end of 2006. The CTC refund to the other customer classes during the interim period will be as proposed by us, with the exception of the large industrials, who will not receive any fuel refunds during the interim period.

At an October 2006 open meeting, the PUCT announced oral decisions regarding the CTC refund. A final written order is expected in late November or early December of this year. In its decision, the PUCT confirmed that TCC can use securitization bond proceeds to make the CTC refund. The PUCT’s decision was to continue the interim CTC through December 2006 to complete the refund of the retail clawback over three months. Beginning in January 2007, the Deferred Over-recovered Fuel Balance will be refunded over six months with the large industrial customers receiving their entire refund in January 2007. Starting in July 2007, the remaining CTC items will be refunded over one year, except that the PUCT agreed with our request to defer the refund of the ADITC and EDFIT Benefit Refund Deferral and the FERC Jurisdictional Fuel Refund Deferral (see table above). The PUCT will decide those issues and related amounts in another proceeding.

Municipal customers and other intervenors appealed the PUCT orders seeking to further reduce our true-up recoveries. If we determine, as a result of future PUCT orders or appeal court rulings, that it is probable we cannot recover a portion of our recorded net true-up regulatory asset and we are able to estimate the amount of a resultant impairment, we would record a provision for such amount which would have an adverse effect on future results of operations, cash flows and possibly financial condition. We appealed the PUCT orders seeking relief in both state and federal court where we believe the PUCT’s rulings are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law.  The significant items appealed by TCC are:

·
the PUCT ruled that TCC did not comply with the statute and PUCT rules regarding the auction of 15% of its Texas jurisdictional installed capacity,
·
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 gas units with the sale of its coal unit,
·
and two federal matters regarding the allocation of off-system sales related to fuel recoveries and the potential tax normalization violation.
 
These appeals could take years to resolve and could result in material effects on future results of operations. If the PUCT rejects our deferral proposal and a normalization violation occurs, future results of operations and cash flows could be adversely affected by the recapture of $104 million of our ADITC and the loss of future accelerated tax depreciation election. The estimated future impact on earnings of the Texas Restructuring as of September 30, 2006, exclusive of a possible normalization violation and any effects of appeal litigation, over the 14-year securitization net recovery period assuming the PUCT approves our CTC filing, including the interim refund, is detailed below:

   
(in millions)
 
ADITC and EDFIT Benefits Reducing Securitization
 
$
98
 
ADFIT Benefit Applied to Reduce 2002 Securitization of Regulatory Assets
   
(60
)
Securitization Settlement
   
(77
)
Unrecorded Prospective ADFIT Benefit Increasing the CTC Refund
   
(240
)
Unrecorded Equity Carrying Costs Recognized as Collected
   
224
 
Future Interest Payable on Proposed CTC Refund
   
(19
)
Deferred Fuel - Federal Jurisdictional Issue
   
16
 
Net Adverse Earnings Impact Over 14 Years
 
$
(58
)

If the PUCT changes its oral decision regarding the proposed CTC deferral and the two contingent federal matters are refunded to customers, the future adverse impact on results of operations over the next 14 years will increase to $181 million. This potential adverse impact on results of operations over the next 14 years would be more than offset by the annual cost of money benefit from the $2.2 billion in net proceeds that resulted from the sale of bonds in connection with the initial regulatory asset securitization in 2002 of $797 million and from the $1.74 billion sale of securitization bonds in October 2006 less the proposed $357 million CTC refund over the next eight years.

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, Note 6 - Customer Choice and Industry Restructuring and Note 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters, Note 4 - Customer Choice and Industry Restructuring and Note 5 - Commitments 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 2005 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.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. 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

Our MTM Risk Management Contract Net Assets are zero as of September 30, 2006. For further explanation, see “Allocation Agreement between AEP East companies and AEP West companies” section of this Management’s Financial Discussion and Analysis.

The following table summarizes the reasons for changes in our total MTM value as compared to December 31, 2005.
 
MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2006
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005
 
$
5,426
 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
   
(1,175
)
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
   
-
 
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts
   
-
 
Changes in Fair Value Due to Market Fluctuations During the Period (b)
   
(3,868
)
Changes Due to SIA and CSW Operating Agreement (c)
   
(383
)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)
   
-
 
Total MTM Risk Management Contract Net Assets
   
-
 
Net Cash Flow Hedge Contracts
   
-
 
Total MTM Risk Management Contract Net Assets at September 30, 2006
 
$
-
 

(a)
Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)
Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)
See “Allocation Agreement between AEP East companies and AEP West companies” section of this Management’s Financial Discussion and Analysis.
(d)
“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

Our MTM Risk Management Contracts Net Assets are zero as of September 30, 2006. Therefore, there is no maturity and source of fair value to report.

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

As a result of changes made to the Allocation Agreement between AEP East companies and AEP West companies in the second quarter of 2006, we are no longer exposed to market fluctuations in energy commodity prices. Therefore, we have no contracts designated as cash flow hedges on our September 30, 2006 Condensed Consolidated Balance Sheet.

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, 2005 to September 30, 2006. 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
Nine Months Ended September 30, 2006
(in thousands)
   
Power
 
Beginning Balance in AOCI December 31, 2005
 
$
(224
)
Changes in Fair Value
   
-
 
Impact Due to Changes in SIA (a)
   
218
 
Reclassifications from AOCI to Net Income for Cash Flow
   Hedges Settled
   
6
 
Ending Balance in AOCI September 30, 2006
 
$
-
 

(a)
See “Allocation Agreement between AEP East companies and AEP West companies” section of this Management’s Financial Discussion and Analysis.

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 September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

Nine Months Ended
September 30, 2006
       
Twelve Months Ended
December 31, 2005
(in thousands)
       
(in thousands)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
$-
 
$11
 
$2
 
$-
       
$111
 
$184
 
$88
 
$32

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 $70 million and $93 million at September 30, 2006 and December 31, 2005, 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 and Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
Three Months Ended
 
Nine Months Ended
 
   
2006
 
2005
 
2006
 
2005
 
REVENUES
                   
Electric Generation, Transmission and Distribution
 
$
162,902
 
$
192,932
 
$
435,801
 
$
559,822
 
Sales to AEP Affiliates
   
1,559
   
2,528
   
4,703
   
12,794
 
Other - Nonaffiliated
   
9,462
   
7,905
   
30,196
   
34,432
 
TOTAL
   
173,923
   
203,365
   
470,700
   
607,048
 
                           
EXPENSES
                         
Fuel and Other Consumables for Electric Generation
   
2,006
   
1,915
   
4,728
   
12,047
 
Purchased Electricity for Resale
   
725
   
1,691
   
3,557
   
27,057
 
Other Operation
   
61,057
   
64,408
   
183,241
   
221,741
 
Maintenance
   
10,679
   
8,782
   
27,255
   
38,254
 
Depreciation and Amortization
   
40,298
   
40,342
   
110,848
   
105,062
 
Taxes Other Than Income Taxes
   
23,387
   
22,828
   
60,421
   
66,282
 
TOTAL
   
138,152
   
139,966
   
390,050
   
470,443
 
                           
OPERATING INCOME
   
35,771
   
63,399
   
80,650
   
136,605
 
                           
Other Income (Expense):
                         
Interest Income
   
560
   
8,295
   
1,592
   
15,722
 
Carrying Costs Income
   
25,443
   
15,349
   
65,279
   
30,146
 
Allowance for Equity Funds Used During Construction
   
667
   
(59
)
 
1,671
   
641
 
Interest Expense
   
(36,746
)
 
(25,374
)
 
(93,401
)
 
(85,095
)
                           
INCOME BEFORE INCOME TAXES
   
25,695
   
61,610
   
55,791
   
98,019
 
                           
Income Tax Expense
   
8,460
   
21,134
   
17,808
   
28,038
 
                           
NET INCOME
   
17,235
   
40,476
   
37,983
   
69,981
 
                           
Preferred Stock Dividend Requirements
   
60
   
60
   
181
   
181
 
                           
EARNINGS APPLICABLE TO COMMON STOCK
 
$
17,175
 
$
40,416
 
$
37,802
 
$
69,800
 

      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 (LOSS)
For the Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
                            
DECEMBER 31, 2004
 
$
55,292
 
$
132,606
 
$
1,084,904
 
$
(4,159
)
$
1,268,643
 
                                 
Common Stock Dividends
               
(150,000
)
       
(150,000
)
Preferred Stock Dividends
               
(181
)
       
(181
)
TOTAL
                           
1,118,462
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Income (Loss), Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $1,626
                     
(3,021
)
 
(3,021
)
Minimum Pension Liability, Net of Tax of $0
                     
3,810
   
3,810
 
NET INCOME
               
69,981
         
69,981
 
TOTAL COMPREHENSIVE INCOME
                           
70,770
 
                                 
SEPTEMBER 30, 2005
 
$
55,292
 
$
132,606
 
$
1,004,704
 
$
(3,370
)
$
1,189,232
 
                                 
DECEMBER 31, 2005
 
$
55,292
 
$
132,606
 
$
760,884
 
$
(1,152
)
$
947,630
 
                                 
Preferred Stock Dividends
               
(181
)
       
(181
)
TOTAL
                           
947,449
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Income, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $121
                     
224
   
224
 
NET INCOME
               
37,983
         
37,983
 
TOTAL COMPREHENSIVE INCOME
                           
38,207
 
                                 
SEPTEMBER 30, 2006
 
$
55,292
 
$
132,606
 
$
798,686
 
$
(928
)
$
985,656
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2006 and December 31, 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
5
 
$
-
 
Other Cash Deposits
   
41,728
   
66,153
 
Advances to Affiliates
   
25,304
   
-
 
Accounts Receivable:
             
Customers
   
65,875
   
209,957
 
Affiliated Companies
   
8,633
   
23,486
 
Accrued Unbilled Revenues
   
25,350
   
25,606
 
Allowance for Uncollectible Accounts
   
(217
)
 
(143
)
  Total Accounts Receivable
   
99,641
   
258,906
 
Unbilled Construction Costs
   
6,352
   
19,440
 
Materials and Supplies
   
24,995
   
13,897
 
Risk Management Assets
   
-
   
14,311
 
Prepayments and Other
   
5,645
   
5,231
 
TOTAL
   
203,670
   
377,938
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Transmission
   
900,774
   
817,351
 
Distribution
   
1,559,593
   
1,476,683
 
Other
   
232,023
   
233,361
 
Construction Work in Progress
   
126,418
   
129,800
 
Total
   
2,818,808
   
2,657,195
 
Accumulated Depreciation and Amortization
   
637,517
   
636,078
 
TOTAL - NET
   
2,181,291
   
2,021,117
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
1,710,352
   
1,688,787
 
Securitized Transition Assets
   
557,520
   
593,401
 
Long-term Risk Management Assets
   
-
   
11,609
 
Employee Benefits and Pension Assets
   
112,594
   
114,733
 
Deferred Charges and Other
   
57,276
   
53,011
 
TOTAL
   
2,437,742
   
2,461,541
 
               
Assets Held for Sale - Texas Generation Plants
   
45,863
   
44,316
 
               
TOTAL ASSETS
 
$
4,868,566
 
$
4,904,912
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2006 and December 31, 2005
(Unaudited)

   
2006
 
2005
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
 
$
-
 
$
82,080
 
Accounts Payable:
             
General
   
20,889
   
82,666
 
Affiliated Companies
   
18,160
   
65,574
 
Long-term Debt Due Within One Year - Nonaffiliated
   
153,364
   
152,900
 
Long-term Debt Due Within One Year - Affiliated
   
345,000
   
-
 
Risk Management Liabilities
   
-
   
13,024
 
Accrued Taxes
   
74,887
   
54,566
 
Accrued Interest
   
16,011
   
32,497
 
Other
   
32,500
   
45,927
 
TOTAL
   
660,811
   
529,234
 
               
NONCURRENT LIABILITIES
             
Long-term Debt - Nonaffiliated
   
1,498,031
   
1,550,596
 
Long-term Debt - Affiliated
   
-
   
150,000
 
Long-term Risk Management Liabilities
   
-
   
7,857
 
Deferred Income Taxes
   
1,014,840
   
1,048,372
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
684,566
   
652,143
 
Deferred Credits and Other
   
18,723
   
13,140
 
TOTAL
   
3,216,160
   
3,422,108
 
               
TOTAL LIABILITIES
   
3,876,971
   
3,951,342
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
5,939
   
5,940
 
               
Commitments and Contingencies (Note 5)
             
               
COMMON SHAREHOLDER’S EQUITY
             
Common Stock - $25 Par Value 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
   
798,686
   
760,884
 
Accumulated Other Comprehensive Income (Loss)
   
(928
)
 
(1,152
)
TOTAL
   
985,656
   
947,630
 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 
$
4,868,566
 
$
4,904,912
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
OPERATING ACTIVITIES
           
Net Income
 
$
37,983
 
$
69,981
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
110,848
   
105,062
 
Accretion of Asset Retirement Obligations
   
55
   
7,549
 
Deferred Income Taxes
   
5,770
   
(63,426
)
Carrying Costs on Stranded Cost Recovery
   
(65,279
)
 
(30,146
)
Mark-to-Market of Risk Management Contracts
   
5,426
   
(1,139
)
Over/Under Fuel Recovery
   
7,225
   
(2,000
)
Deferred Property Taxes
   
(8,296
)
 
(7,600
)
Change in Other Noncurrent Assets
   
17,653
   
(9,777
)
Change in Other Noncurrent Liabilities
   
(17,249
)
 
(1,390
)
Changes in Components of Working Capital:
             
Accounts Receivable, Net
   
159,265
   
(22,504
)
Fuel, Materials and Supplies
   
(11,508
)
 
(1,763
)
Accounts Payable
   
(107,505
)
 
(10,533
)
Customer Deposits
   
(6,461
)
 
12,844
 
Accrued Taxes, Net
   
16,387
   
(110,975
)
Accrued Interest
   
(16,486
)
 
(24,495
)
Other Current Assets
   
16,611
   
(13,709
)
Other Current Liabilities
   
(6,968
)
 
8,590
 
Net Cash Flows From (Used For) Operating Activities
   
137,471
   
(95,431
)
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(203,116
)
 
(109,372
)
Change in Other Cash Deposits, Net
   
25,068
   
93,427
 
Change in Advances to Affiliates, Net
   
(25,304
)
 
-
 
Purchases of Investment Securities
   
-
   
(154,364
)
Sales of Investment Securities
   
-
   
149,804
 
Proceeds from Sale of Assets
   
6,083
   
313,966
 
Net Cash Flows From (Used For) Investing Activities
   
(197,269
)
 
293,461
 
               
FINANCING ACTIVITIES
             
Issuance of Long-term Debt - Nonaffiliated
   
-
   
276,663
 
Issuance of Long-term Debt - Affiliated
   
195,000
   
150,000
 
Change in Advances from Affiliates, Net
   
(82,080
)
 
11,814
 
Retirement of Long-term Debt
   
(52,265
)
 
(486,007
)
Retirement of Preferred Stock
   
(1
)
 
-
 
Principal Payments for Capital Lease Obligations
   
(670
)
 
(342
)
Dividends Paid on Common Stock
   
-
   
(150,000
)
Dividends Paid on Cumulative Preferred Stock
   
(181
)
 
(181
)
Net Cash Flows From (Used For) Financing Activities
   
59,803
   
(198,053
)
               
Net Increase (Decrease) in Cash and Cash Equivalents
   
5
   
(23
)
Cash and Cash Equivalents at Beginning of Period
   
-
   
26
 
Cash and Cash Equivalents at End of Period
 
$
5
 
$
3
 
               
SUPPLEMENTAL DISCLOSURE
             
Cash Paid for Interest, Net of Capitalized Amounts
 
$
93,165
 
$
95,066
 
Net Cash Paid (Received) for Income Taxes
   
(2,764
)
 
207,079
 
Noncash Acquisitions Under Capital Leases
   
3,282
   
277
 
Construction Expenditures Included in Accounts Payable at September 30,
   
9,351
   
8,797
 

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
Customer Choice and Industry Restructuring
Note 4
Commitments and Contingencies
Note 5
Guarantees
Note 6
Company-wide Staffing and Budget Review
Note 7
Acquisitions, Assets Held for Sale and Asset Impairments
Note 8
Benefit Plans
Note 9
Income Taxes
Note 10
Business Segments
Note 11
Financing Activities
Note 12






 
 
 

 





 
 
AEP TEXAS NORTH COMPANY AND SUBSIDIARY
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 







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

Allocation Agreement between AEP East companies and AEP West companies

Under the Texas Restructuring Legislation, we are completing the final stage of exiting the generation business and have ceased serving retail load. Based on the corporate separation and generation divestiture activities underway, the nature of our business is no longer compatible with our participation in the CSW Operating Agreement and the SIA since these agreements involve the coordinated planning and operation of power supply facilities. Accordingly, on behalf of the AEP East companies and the AEP West companies, AEPSC filed with the FERC to remove us from those agreements. The FERC approved the filing in March 2006. The SIA includes a methodology for sharing trading and marketing margins among the AEP East companies and the AEP West companies. Our sharing of margins ceased effective May 1, 2006, which affects our future results of operations and cash flows. We will continue to have margin and collateral deposits, risk management assets and liabilities and trading gains or losses to the extent that we have contracts dedicated specifically to us.

AEP Texas North Generation Company, LLC

In the third quarter of 2006, we created a new wholly-owned subsidiary, AEP Texas North Generation Company, LLC (TNGC). Following the creation of this subsidiary, we transferred all of our mothballed generation assets and related liabilities to this new subsidiary, substantially completing the business separation requirement of the Texas Restructuring Legislation. Subsequently, TNGC became a participant in the Nonutility Money Pool. The creation of TNGC did not have a significant impact on our results of operations or financial condition.

Results of Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income
(in millions)

Third Quarter of 2005
       
$
22
 
               
Changes in Gross Margin:
             
Texas Supply
   
(12
)
     
Texas Wires
   
(1
)
     
Off-system Sales
   
(10
)
     
Transmission Revenues
   
1
       
Total Change in Gross Margin
         
(22
)
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
         
1
 
               
Income Tax Expense
         
7
 
               
Third Quarter of 2006
       
$
8
 

Net Income decreased $14 million to $8 million in 2006 primarily due to a decrease in Gross Margin of $22 million, partially offset by a reduction in Income Tax Expense of $7 million.

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

·
Texas Supply margins decreased $12 million primarily due to a $28 million decrease in dedicated energy and capacity sales, offset by $16 million of lower fuel and purchased power costs. This decrease in Texas Supply margins was affected by market conditions within ERCOT.
·
Margins from Off-system Sales decreased $10 million due to a $5 million decrease in margin sharing under the SIA (no current margin sharing under the CSW Operating Agreement and the SIA) and a $5 million decrease in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

Income Taxes

The decrease in Income Tax Expense of $7 million is primarily due to a decrease in pretax book income.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to
Nine Months Ended September 30, 2006 Net Income
(in millions)

Nine Months Ended September 30, 2005
       
$
42
 
               
Changes in Gross Margin:
             
Texas Supply
   
(29
)
     
Texas Wires
   
(2
)
     
Off-system Sales
   
(11
)
     
Transmission Revenues
   
(5
)
     
Other
   
(39
)
     
Total Change in Gross Margin
         
(86
)
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
38
       
Interest Expense
   
1
       
Total Change in Operating Expenses and Other
         
39
 
               
Income Tax Expense
         
17
 
               
Nine Months Ended September 30, 2006
       
$
12
 

Net Income decreased $30 million to $12 million in 2006 primarily due to a decrease in Gross Margin of $86 million partially offset by a reduction in Other Operation and Maintenance expenses of $38 million and a reduction in Income Tax Expense of $17 million.

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

·
Texas Supply margins decreased $29 million primarily due to a $58 million decrease in dedicated energy and capacity sales, offset by $28 million of lower fuel and purchased power costs. This decrease in Texas Supply margins was affected by market conditions within ERCOT.
·
Margins from Off-system Sales decreased $11 million due to a $6 million decrease in margin sharing under the SIA and a $5 million decrease in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
·
Transmission Revenues decreased $5 million primarily due to reduced affiliated transmission fees resulting from the elimination of the affiliated OATT in 2005.
·
Other revenues decreased $39 million primarily resulting from the completion of certain third party construction projects 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 $38 million primarily due to lower expenses related to the completion of certain third party construction projects related to work performed for the Lower Colorado River Authority.

Income Taxes

The decrease in Income Tax Expense of $17 million is primarily due to a decrease in pretax book income.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook, except for Fitch which has us on a negative outlook. Our current ratings are as follows:

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

Financing Activity

There were no long-term debt issuances or retirements during the first nine months of 2006.

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, TNC participates in the Utility Money Pool and TNGC participates in the Nonutility Money Pool, both of which provide access to AEP’s liquidity.

Summary Obligation Information

A summary of our contractual obligations is included in our 2005 Annual Report and has not changed significantly from year-end except for Energy and Capacity Purchase Contracts. We exited both the SIA and CSW Operating Agreement, eliminating our future obligation for Energy and Capacity Purchase Contracts. See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

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, Note 6 - Customer Choice and Industry Restructuring and Note 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters, Note 4 - Customer Choice and Industry Restructuring and Note 5 - Commitments 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 2005 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.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. 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 September 30, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of September 30, 2006
(in thousands)

   
MTM Risk Management Contracts
 
Cash Flow Hedges
 
Total
 
Current Assets
 
$
-
 
$
-
 
$
-
 
Noncurrent Assets
   
-
   
-
   
-
 
Total MTM Derivative Contract Assets
   
-
   
-
   
-
 
                     
Current Liabilities
   
(2,138
)
 
-
   
(2,138
)
Noncurrent Liabilities
   
-
   
(2,057
)
 
(2,057
)
Total MTM Derivative Contract Liabilities
   
(2,138
)
 
(2,057
)
 
(4,195
)
                     
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
(2,138
)
$
(2,057
)
$
(4,195
)

MTM Risk Management Contract Net Assets (Liabilities)
Nine Months Ended September 30, 2006
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005
 
$
2,698
 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
   
(585
)
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)
   
(3,437
)
Changes Due to SIA and CSW Operating Agreement (c)
   
(814
)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)
   
-
 
Total MTM Risk Management Contract Net Assets (Liabilities)
   
(2,138
)
Net Cash Flow Hedge Contracts
   
(2,057
)
Total MTM Risk Management Contract Net Assets (Liabilities) at September 30, 2006
 
$
(4,195
)

(a)
Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)
Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)
See “Allocation Agreement between AEP East companies and AEP West companies” section of this Management’s Financial Discussion and Analysis.
(d)
“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

   
Remainder
2006
 
2007
 
2008
 
2009
 
2010
 
After
2010
 
Total
 
Prices Actively Quoted - Exchange Traded Contracts
 
$
-
 
$
-
 
$
-
 
$
-
 
$
-
 
$
-
 
$
-
 
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)
   
(2,138
)
 
-
   
-
   
-
   
-
   
-
   
(2,138
)
Prices Based on Models and Other Valuation Methods (b)
   
-
   
-
   
-
   
-
   
-
   
-
   
-
 
Total
 
$
(2,138
)
$
-
 
$
-
 
$
-
 
$
-
 
$
-
 
$
(2,138
)

(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.

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 employ various commodity instruments to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

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, 2005 to September 30, 2006. 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
Nine Months Ended September 30, 2006
(in thousands)
   
Power
 
Beginning Balance in AOCI December 31, 2005
 
$
(111
)
Changes in Fair Value
   
(1,337
)
Impact Due to Change in SIA (a)
   
98
 
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled
   
13
 
Ending Balance in AOCI September 30, 2006
 
$
(1,337
)

(a)
See “Allocation Agreement between AEP East companies and AEP West companies” section of this Management’s Financial Discussion and Analysis.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is zero.

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 September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

Nine Months Ended
September 30, 2006
       
Twelve Months Ended
December 31, 2005
(in thousands)
       
(in thousands)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
$-
 
$23
 
$4
 
$-
       
$55
 
$92
 
$44
 
$16

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 $11 million and $13 million at September 30, 2006 and December 31, 2005, 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 and Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
Three Months Ended
 
Nine Months Ended
 
   
2006
 
2005
 
2006
 
2005
 
REVENUES
                   
Electric Generation, Transmission and Distribution
 
$
79,805
 
$
111,107
 
$
219,681
 
$
280,195
 
Sales to AEP Affiliates
   
7,711
   
13,019
   
25,596
   
37,189
 
Other
   
246
   
1,971
   
149
   
42,324
 
TOTAL
   
87,762
   
126,097
   
245,426
   
359,708
 
                           
EXPENSES
                         
Fuel and Other Consumables for Electric Generation
   
14,016
   
13,433
   
33,175
   
37,772
 
Purchased Electricity for Resale
   
14,606
   
34,425
   
60,343
   
88,367
 
Purchased Electricity from AEP Affiliates
   
2,436
   
1
   
3,978
   
23
 
Other Operation
   
19,003
   
18,878
   
59,192
   
97,135
 
Maintenance
   
5,088
   
5,954
   
15,505
   
15,093
 
Depreciation and Amortization
   
10,767
   
10,435
   
31,172
   
30,952
 
Taxes Other Than Income Taxes
   
5,478
   
6,047
   
16,874
   
17,465
 
TOTAL
   
71,394
   
89,173
   
220,239
   
286,807
 
                           
OPERATING INCOME
   
16,368
   
36,924
   
25,187
   
72,901
 
                           
Other Income (Expense):
                         
Interest Income
   
203
   
890
   
542
   
1,688
 
Allowance for Equity Funds Used During Construction
   
146
   
137
   
636
   
366
 
Interest Expense
   
(4,472
)
 
(4,931
)
 
(13,351
)
 
(14,784
)
                           
INCOME BEFORE INCOME TAXES
   
12,245
   
33,020
   
13,014
   
60,171
 
                           
Income Tax Expense
   
3,799
   
10,716
   
1,326
   
18,469
 
                           
NET INCOME
   
8,446
   
22,304
   
11,688
   
41,702
 
                           
Preferred Stock Dividend Requirements
   
26
   
26
   
78
   
78
 
Gain on Reacquired Preferred Stock
   
-
   
-
   
2
   
-
 
                           
EARNINGS APPLICABLE TO COMMON STOCK
 
$
8,420
 
$
22,278
 
$
11,612
 
$
41,624
 

      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 (LOSS)
For the Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2004
 
$
137,214
 
$
2,351
 
$
170,984
 
$
(128
)
$
310,421
 
                                 
Common Stock Dividends
               
(20,827
)
       
(20,827
)
Preferred Stock Dividends
               
(78
)
       
(78
)
TOTAL
                           
289,516
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $698
                     
(1,296
)
 
(1,296
)
NET INCOME
               
41,702
         
41,702
 
TOTAL COMPREHENSIVE INCOME
                           
40,406
 
                                 
SEPTEMBER 30, 2005
 
$
137,214
 
$
2,351
 
$
191,781
 
$
(1,424
)
$
329,922
 
                                 
DECEMBER 31, 2005
 
$
137,214
 
$
2,351
 
$
174,858
 
$
(504
)
$
313,919
 
                                 
Common Stock Dividends
               
(12,750
)
       
(12,750
)
Preferred Stock Dividends
               
(78
)
       
(78
)
Gain on Reacquired Preferred Stock
               
2
         
2
 
TOTAL
                           
301,093
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $660
                     
(1,226
)
 
(1,226
)
NET INCOME
               
11,688
         
11,688
 
TOTAL COMPREHENSIVE INCOME
                           
10,462
 
                                 
SEPTEMBER 30, 2006
 
$
137,214
 
$
2,351
 
$
173,720
 
$
(1,730
)
$
311,555
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



AEP TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2006 and December 31, 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
-
 
$
-
 
Other Cash Deposits
   
9,087
   
1,432
 
Advances to Affiliates
   
4,383
   
34,286
 
Accounts Receivable:
             
Customers
   
23,367
   
77,678
 
Affiliated Companies
   
11,910
   
26,149
 
Accrued Unbilled Revenues
   
2,567
   
5,016
 
Allowance for Uncollectible Accounts
   
(24
)
 
(18
)
Total Accounts Receivable
   
37,820
   
108,825
 
Fuel
   
5,528
   
2,636
 
Materials and Supplies
   
8,459
   
6,858
 
Risk Management Assets
   
-
   
7,114
 
Prepayments and Other
   
1,537
   
3,772
 
TOTAL
   
66,814
   
164,923
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
290,391
   
288,934
 
Transmission
   
324,724
   
289,029
 
Distribution
   
507,307
   
492,878
 
Other
   
165,403
   
167,849
 
Construction Work in Progress
   
31,991
   
46,424
 
Total
   
1,319,816
   
1,285,114
 
Accumulated Depreciation and Amortization
   
486,131
   
478,519
 
TOTAL - NET
   
833,685
   
806,595
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
8,920
   
9,787
 
Long-term Risk Management Assets
   
-
   
5,772
 
Employee Benefits and Pension Assets
   
45,409
   
46,289
 
Deferred Charges and Other
   
7,153
   
10,468
 
TOTAL
   
61,482
   
72,316
 
               
TOTAL ASSETS
 
$
961,981
 
$
1,043,834
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




AEP TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2006 and December 31, 2005
(Unaudited)

   
2006
 
2005
 
CURRENT LIABILITIES
 
(in thousands)
 
Accounts Payable:
             
General
 
$
9,151
 
$
19,739
 
Affiliated Companies
   
27,854
   
84,923
 
Long-term Debt Due Within One Year - Nonaffiliated
   
8,151
   
-
 
Risk Management Liabilities
   
2,138
   
6,475
 
Accrued Taxes
   
29,458
   
21,212
 
Other
   
11,203
   
21,050
 
TOTAL
   
87,955
   
153,399
 
               
NONCURRENT LIABILITIES
             
Long-term Debt - Nonaffiliated
   
268,762
   
276,845
 
Long-term Risk Management Liabilities
   
2,057
   
3,906
 
Deferred Income Taxes
   
123,991
   
132,335
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
143,506
   
139,732
 
Deferred Credits and Other
   
21,806
   
21,341
 
TOTAL
   
560,122
   
574,159
 
               
TOTAL LIABILITIES
   
648,077
   
727,558
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
2,349
   
2,357
 
               
Commitments and Contingencies (Note 5)
             
               
COMMON SHAREHOLDER’S EQUITY
             
Common Stock - $25 Par Value 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
   
173,720
   
174,858
 
Accumulated Other Comprehensive Income (Loss)
   
(1,730
)
 
(504
)
TOTAL
   
311,555
   
313,919
 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 
$
961,981
 
$
1,043,834
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



AEP TEXAS NORTH COMPANY AND SUBSIDIARY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
OPERATING ACTIVITIES
           
Net Income
 
$
11,688
 
$
41,702
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
31,172
   
30,952
 
Deferred Income Taxes
   
(4,667
)
 
(313
)
Mark-to-Market of Risk Management Contracts
   
4,836
   
(452
)
Deferred Property Taxes
   
(4,359
)
 
(4,072
)
Change in Other Noncurrent Assets
   
(5,173
)
 
(1,109
)
Change in Other Noncurrent Liabilities
   
(630
)
 
(71
)
Changes in Components of Working Capital:
             
Accounts Receivable, Net
   
71,005
   
9,366
 
Fuel, Materials and Supplies
   
(4,493
)
 
922
 
Accounts Payable
   
(66,653
)
 
16,834
 
Customer Deposits
   
(3,571
)
 
5,471
 
Accrued Taxes, Net
   
7,984
   
(10,097
)
Other Current Assets
   
2,496
   
11,189
 
Other Current Liabilities
   
(5,304
)
 
(551
)
Net Cash Flows From Operating Activities
   
34,331
   
99,771
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(52,366
)
 
(44,865
)
Change in Other Cash Deposits, Net
   
979
   
1,508
 
Change In Advances to Affiliates, Net
   
29,903
   
(36,147
)
Proceeds from Sale of Assets
   
250
   
1,033
 
Net Cash Flows Used For Investing Activities
   
(21,234
)
 
(78,471
)
               
FINANCING ACTIVITIES
             
Retirement of Preferred Stock
   
(6
)
 
-
 
Principal Payments for Capital Lease Obligations
   
(263
)
 
(180
)
Dividends Paid on Common Stock
   
(12,750
)
 
(20,827
)
Dividends Paid on Cumulative Preferred Stock
   
(78
)
 
(78
)
Net Cash Flows Used For Financing Activities
   
(13,097
)
 
(21,085
)
               
Net Increase in Cash and Cash Equivalents
   
-
   
215
 
Cash and Cash Equivalents at Beginning of Period
   
-
   
-
 
Cash and Cash Equivalents at End of Period
 
$
-
 
$
215
 
               
SUPPLEMENTAL DISCLOSURE
             
Cash Paid for Interest, Net of Capitalized Amounts
 
$
13,988
 
$
15,192
 
Net Cash Paid (Received) for Income Taxes
   
(252
)
 
30,486
 
Noncash Acquisitions Under Capital Leases
   
1,178
   
193
 
Construction Expenditures Included in Accounts Payable at September 30,
   
2,155
   
2,289
 

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
Customer Choice and Industry Restructuring
Note 4
Commitments and Contingencies
Note 5
Guarantees
Note 6
Company-wide Staffing and Budget Review
Note 7
Benefit Plans
Note 9
Income Taxes
Note 10
Business Segments
Note 11
Financing Activities
Note 12





 
 
 
 

 




APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 






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


Results of Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income
(in millions)

Third Quarter of 2005
       
$
37
 
               
Changes in Gross Margin:
             
Retail Margins
   
(23
)
     
Off-system Sales
   
33
       
Transmission Revenues
   
(10
)
     
Other
   
16
       
Total Change in Gross Margin
         
16
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
6
       
Depreciation and Amortization
   
(11
)
     
Carrying Costs Income (Expense)
   
(29
)
     
Other Income
   
7
       
Interest Expense
   
(2
)
     
Total Change in Operating Expenses and Other
         
(29
)
               
Income Tax Expense
         
7
 
               
Third Quarter of 2006
       
$
31
 

Net Income decreased $6 million to $31 million in 2006. The key driver of the decrease was a $29 million net increase in Operating Expenses and Other offset by a net increase in Gross Margin of $16 million and a $7 million decrease in Income Tax Expense.

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 decreased $23 million in comparison to 2005 primarily due to:
 
·
a $28 million decrease related to an increase in sharing of off-system sales margins with retail customers due to higher off-system sales. This sharing mechanism was reinstated in West Virginia effective July 1, 2006 in conjunction with our West Virginia rate case. Retail Margins further decreased due to;
 
·
a $13 million decrease in revenues related to financial transmission rights, net of congestion, primarily due to fewer transmission constraints in the PJM market partially offset by;
 
·
a $19 million increase in fuel recovery caused by the activation of the West Virginia fuel clause in July 2006.
·
Off-system Sales increased $33 million primarily due to $19 million increase in physical sales margins and an $18 million increase from lower sharing of off-system sales margins under the SIA slightly offset by a $3 million decrease in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
·
Transmission Revenues decreased $10 million primarily due to the elimination of SECA revenues as of April 1, 2006. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 3.
·
Other revenue increased $16 million primarily due to a write off of previously deferred gains on sales of allowances associated with the Virginia Environmental and Reliability Costs (E&R) case. See “APCo Virginia Environmental and Reliability Costs” section of Note 3.
 
Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expenses decreased $6 million mainly due to a decrease in expenses associated with the Transmission Equalization Agreement with the addition of the Wyoming-Jacksons Ferry 765 kV line, which was energized and placed in service in June 2006. This decrease was partially offset by a write off of deferred maintenance expenses associated with the E&R case. See “APCo Virginia Environmental and Reliability Costs” section of Note 3.
·
Depreciation and Amortization expenses increased $11 million primarily due to a write off of previously deferred depreciation expenses associated with the E&R case. See “APCo Virginia Environmental and Reliability Costs” section of Note 3.
·
Carrying Costs Income (Expense) decreased $29 million primarily due to a write off of previously recorded carrying costs income associated with the E&R case. See “APCo Virginia Environmental and Reliability Costs” section of Note 3.
·
Other Income increased $7 million primarily due to interest income related to an increase in Advances to Affiliates and an increase in allowance for funds during construction (AFUDC).

Income Taxes

The decrease in Income Tax Expense of $7 million is primarily due to a decrease in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis, offset in part by an increase in state income taxes.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to
Nine Months Ended September 30, 2006 Net Income
(in millions)

Nine Months Ended September 30, 2005
       
$
108
 
               
Changes in Gross Margin:
             
Retail Margins
   
12
       
Off-system Sales
   
34
       
Transmission Revenues
   
(27
)
     
Other
   
15
       
Total Change in Gross Margin
         
34
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
9
       
Depreciation and Amortization
   
(11
)
     
Taxes Other Than Income Taxes
   
1
       
Carrying Costs Income (Expense)
   
(19
)
     
Other Income
   
12
       
Interest Expense
   
(13
)
     
Total Change in Operating Expenses and Other
         
(21
)
               
Income Tax Expense
         
(7
)
               
Nine Months Ended September 30, 2006
       
$
114
 

Net Income increased $6 million to $114 million in 2006. The key driver of the increase was a $34 million net increase in Gross Margin offset by a $21 million net increase in Operating Expenses and Other and a $7 million increase in Income Tax Expense.

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 $12 million in comparison to 2005 primarily due to:
 
·
a $16 million increase in retail revenues primarily related to two new industrial customers;
 
·
a $14 million reduction in capacity settlement payments under the Interconnection Agreement due to our lower member load ratio (MLR) share and our increased generation capacity and;
 
·
an $11 million increase in revenues related to financial transmission rights, net of congestion. The increase in financial transmission rights revenue is due to improved management of price risk related to serving retail load under current transmission constraints. Retail Margin increases were partially offset by;
 
 · 
 a $28 million decrease related to an increase in sharing of off-system sales margins with retail customers due to higher off-system sales.  This sharing mechanism was reinstated in West Virginia effective July 1, 2006 in conjunction with our West Virginia rate case.
·
Off-system Sales increased $34 million primarily due to $42 million increase in physical sales margins and a $22 million increase from lower sharing of off-system sales margins under the SIA offset by a $30 million decrease in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
·
Transmission Revenues decreased $27 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $5 million for potential SECA refunds pending settlement negotiations with various intervenors. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 3.
·
Other revenue increased $15 million primarily due to a write off of previously deferred gains on sales of allowances associated with the E&R case and higher gains on sales of allowances. See “APCo Virginia Environmental and Reliability Costs” section of Note 3.

 Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expenses decreased $9 million mainly due to a decrease in expenses associated with the Transmission Equalization Agreement with the addition of the Wyoming-Jacksons Ferry 765 kV line, which was energized and placed in service in June 2006, partially offset by a write off of previously deferred maintenance expenses associated with the E&R case. See “APCo Virginia Environmental and Reliability Costs” section of Note 3.
·
Depreciation and Amortization expenses increased $11 million primarily due to a write off of previously deferred depreciation expenses associated with the E&R case. See “APCo Virginia Environmental and Reliability Costs” section of Note 3.
·
Carrying Costs Income (Expense) decreased $19 million primarily due to write off of previously recorded carrying costs income associated with the E&R case. See “APCo Virginia Environmental and Reliability Costs” section of Note 3.
·
Other Income increased $12 million primarily due to interest income related to an increase in Advances to Affiliates and an increase in AFUDC.
·
Interest Expense increased $13 million primarily due to long-term debt issuances in 2006, partially offset by an increase in allowance for borrowed funds used during construction and a write off of previously deferred AFUDC associated with the E&R case. See “APCo Virginia Environmental and Reliability Costs” section of Note 3.

Income Taxes

The increase in Income Tax Expense of $7 million is primarily due to an increase in pretax book income and state income taxes offset in part by changes in certain book/tax differences accounted for on a flow-through basis.

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 nine months ended September 30, 2006 and 2005 were as follows:

   
2006
 
2005
 
   
(in thousands)
 
Cash and Cash Equivalents at Beginning of Period
 
$
1,741
 
$
1,543
 
Net Cash Flows From (Used For):
             
Operating Activities
   
436,795
   
180,504
 
Investing Activities
   
(725,650
)
 
(479,420
)
Financing Activities
   
288,363
   
298,938
 
Net Increase (Decrease) in Cash and Cash Equivalents
   
(492
)
 
22
 
Cash and Cash Equivalents at End of Period
 
$
1,249
 
$
1,565
 

Operating Activities

Net Cash Flows From Operating Activities were $437 million in 2006. We produced Net Income of $114 million during the period and a noncash expense item of $158 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 had no significant items.

Net Cash Flows From Operating Activities were $181 million in 2005. We produced Net Income of $108 million during the period and a noncash expense item of $147 million for Depreciation and Amortization partially offset by Pension Contributions to Qualified Plan Trusts of $60 million. The other changes in assets and liabilities represent items that had a prior 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 had no significant items.

Investing Activities

Net Cash Flows Used For Investing Activities during 2006 and 2005 primarily reflect our construction expenditures of $633 million and $422 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 and 2005, capital projects for transmission expenditures primarily relate to the Wyoming-Jacksons Ferry 765 kV line placed in service in June 2006. Environmental upgrades include the flue gas desulphurization (FGD) projects at the Amos and Mountaineer Plants. For the remainder of 2006, we expect $300 million of construction expenditures. In addition, we invested $94 million and $68 million into the Utility Money Pool in 2006 and 2005, respectively.

Financing Activities

Net Cash Flows From Financing Activities were $288 million in 2006. We issued $500 million in Senior Unsecured Notes and $50 million in Pollution Control Bonds. We also retired a First Mortgage Bond of $100 million. We repaid short-term borrowings from the Utility Money Pool of $194 million. In addition, we received funds of $68 million related to a long-term coal purchase contract amended in March 2006, partially offset by repayments of $18 million. See “Coal Contract Amendment” within “Significant Factors” for additional information.

Net Cash Flows From Financing Activities were $299 million in 2005. We issued four Senior Unsecured Notes totaling $850 million. We also issued Notes Payable - Affiliates of $100 million and received a capital contribution from our parent of $150 million. We retired $450 million of Senior Unsecured Notes and three First Mortgage Bonds totaling $125 million. In addition, we repaid $211 million of advances from the Utility Money Pool.

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2006 were:

Issuances

   
Principal
Amount
 
Interest
 
Due
Type of Debt
   
Rate
 
Date
     
(in thousands)
 
(%)
   
               
Senior Unsecured Notes
 
$
250,000
 
5.55
 
2011
Senior Unsecured Notes
   
250,000
 
6.375
 
2036
Pollution Control Bonds
   
50,275
 
Variable
 
2036

Retirements

   
Principal
Amount
 
Interest
 
Due
Type of Debt
   
Rate
 
Date
     
(in thousands)
 
(%)
   
               
First Mortgage Bonds
 
$
100,000
 
6.80
 
2006
Other Debt
   
8
 
13.718
 
2026


In November 2006, we issued $17.5 million of variable rate Pollution Control Bonds and retired $17.5 million, 2.70% pollution control bonds due in 2007.

In November 2006, we had a required remarketing of $30 million of 2.80% Pollution Control Bonds, which were converted from a three-year fixed rate mode to an auction rate mode.

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 2005 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed above.

Significant Factors

Coal Contract Amendment

We negotiated an amendment to a nonderivative coal contract that was assigned to a new owner of a coal supplier to which we were contractually obligated. The amended contract includes adjustments in the quantity related to the shortfall of tons in prior years, escalated tonnage deliveries in 2006 and a pricing change related to future coal deliveries. In March 2006, the new owner agreed to pay us $80 million for the settlement, release and amendment of the original contract. With respect to prior years’ undelivered coal, the new owner paid us $12 million for the shortfall tons. With respect to deliveries of coal in 2006-2007, the third party paid us the remaining $68 million for the agreed upon price increase.

The receipt of funds reduces the risk that the third party will short future deliveries. However, if they fail to deliver, we are not contractually obligated to repay any portion of the settlement payment. Our net coal price will not materially change from the original contract price as a result of the $68 million payment that we received for future coal deliveries through 2007.

Since there are no further requirements related to the liquidation of the shortfall tons, we recognized the $12 million shortfall payment in the first quarter of 2006. We recorded a $5 million reduction in Regulatory Assets on our Condensed Consolidated Balance Sheet and recorded the remaining $7 million as a reduction to Fuel and Other Consumables for Electric Generation on our Condensed Consolidated Statement of Income. We recorded the $68 million payment within Deferred Credits and Other on our Condensed Consolidated Balance Sheet. To the extent tons are received, payment of the higher contracted price per ton will effectively result in a repayment of funds to the coal supplier.

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, Note 6 - Customer Choice and Industry Restructuring and Note 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters and Note 5 - Commitments 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 2005 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.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. 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 September 30, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of September 30, 2006
(in thousands)

   
MTM Risk Management Contracts
 
Cash Flow &
Fair Value Hedges
 
DETM Assignment (a)
 
Total
 
Current Assets
 
$
85,654
 
$
7,481
 
$
-
 
$
93,135
 
Noncurrent Assets
   
107,705
   
510
   
-
   
108,215
 
Total MTM Derivative Contract Assets
   
193,359
   
7,991
   
-
   
201,350
 
                           
Current Liabilities
   
(64,432
)
 
(1,979
)
 
(1,881
)
 
(68,292
)
Noncurrent Liabilities
   
(70,002
)
 
(699
)
 
(9,138
)
 
(79,839
)
Total MTM Derivative Contract Liabilities
   
(134,434
)
 
(2,678
)
 
(11,019
)
 
(148,131
)
                           
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
58,925
 
$
5,313
 
$
(11,019
)
$
53,219
 

(a)
See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.


MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2006
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005
 
$
56,407
 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
   
(6,079
)
Fair Value of New Contracts at Inception When Entered During the Period (a)
   
121
 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period
   
(315
)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts
   
316
 
Changes in Fair Value Due to Market Fluctuations During the Period (b)
   
6,107
 
Changes due to SIA Agreement (c)
   
(6,533
)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)
   
8,901
 
Total MTM Risk Management Contract Net Assets
   
58,925
 
Net Cash Flow & Fair Value Hedge Contracts
   
5,313
 
DETM Assignment (e)
   
(11,019
)
Total MTM Risk Management Contract Net Assets at September 30, 2006
 
$
53,219
 

(a)
Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)
Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)
See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
(d)
“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.
(e)
See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 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 giving an indication of when these MTM amounts will settle and generate cash.


Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2006
(in thousands)

   
Remainder
2006
 
2007
 
2008
 
2009
 
2010
 
After
2010
 
Total
 
Prices Actively Quoted - Exchange Traded Contracts
 
$
1,794
 
$
12,885
 
$
4,663
 
$
-
 
$
-
 
$
-
 
$
19,342
 
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)
   
4,076
   
11,246
   
4,922
   
7,304
   
-
   
-
   
27,548
 
Prices Based on Models and Other Valuation Methods (b)
   
(43
)
 
(4,690
)
 
1,149
   
4,648
   
8,331
   
2,640
   
12,035
 
Total
 
$
5,827
 
$
19,441
 
$
10,734
 
$
11,952
 
$
8,331
 
$
2,640
 
$
58,925
 

(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.

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 employ various commodity instruments to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

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

We employ forward contracts as cash flow hedges to lock-in prices on certain transactions which have been 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, 2005 to September 30, 2006. 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
Nine Months Ended September 30, 2006
(in thousands)
   
Power
 
Foreign
Currency
 
Interest
Rate
 
Total
 
Beginning Balance in AOCI December 31, 2005
 
$
(1,480
)
$
(171
)
$
(14,770
)
$
(16,421
)
Changes in Fair Value
   
4,482
   
-
   
4,951
   
9,433
 
Impact due to Changes in SIA (a)
   
(442
)
 
-
   
-
   
(442
)
Reclassifications from AOCI to Net Income for Cash Flow
  Hedges Settled
   
2,261
   
5
   
1,757
   
4,023
 
Ending Balance in AOCI September 30, 2006
 
$
4,821
 
$
(166
)
$
(8,062
)
$
(3,407
)

(a)
See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $2,919 thousand gain.

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 September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

Nine Months Ended
September 30, 2006
       
Twelve Months Ended
December 31, 2005
(in thousands)
       
(in thousands)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
$655
 
$1,915
 
$683
 
$365
       
$732
 
$1,216
 
$579
 
$209

The High VaR for the nine months ended September 30, 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 $141 million and $142 million at September 30, 2006 and December 31, 2005, 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 and Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
Three Months Ended
 
Nine Months Ended
 
   
2006
 
2005
 
2006
 
2005
 
REVENUES
                   
Electric Generation, Transmission and Distribution
 
$
588,684
 
$
468,558
 
$
1,612,735
 
$
1,380,928
 
Sales to AEP Affiliates
   
57,177
   
99,551
   
177,557
   
237,648
 
Other
   
2,740
   
2,013
   
7,338
   
6,343
 
TOTAL
   
648,601
   
570,122
   
1,797,630
   
1,624,919
 
                           
EXPENSES
                         
Fuel and Other Consumables for Electric Generation
   
184,275
   
161,154
   
506,368
   
402,057
 
Purchased Electricity for Resale
   
41,027
   
24,217
   
98,622
   
79,182
 
Purchased Electricity from AEP Affiliates
   
130,826
   
108,008
   
356,682
   
341,994
 
Other Operation
   
63,259
   
78,421
   
210,914
   
228,916
 
Maintenance
   
53,874
   
44,865
   
138,381
   
129,321
 
Depreciation and Amortization
   
61,160
   
50,284
   
157,518
   
146,734
 
Taxes Other Than Income Taxes
   
24,464
   
23,696
   
70,355
   
71,127
 
TOTAL
   
558,885
   
490,645
   
1,538,840
   
1,399,331
 
                           
OPERATING INCOME
   
89,716
   
79,477
   
258,790
   
225,588
 
                           
Other Income (Expense):
                         
Interest Income
   
2,463
   
662
   
6,228
   
1,667
 
Carrying Costs Income (Expense)
   
(27,316
)
 
1,255
   
(13,532
)
 
5,320
 
Allowance for Equity Funds Used During Construction
   
6,748
   
1,791
   
13,307
   
6,559
 
Interest Expense
   
(27,103
)
 
(24,976
)
 
(89,024
)
 
(76,320
)
                           
INCOME BEFORE INCOME TAXES
   
44,508
   
58,209
   
175,769
   
162,814
 
                           
Income Tax Expense
   
13,972
   
20,837
   
61,992
   
54,557
 
                           
NET INCOME
   
30,536
   
37,372
   
113,777
   
108,257
 
                           
Preferred Stock Dividend Requirements Including Capital Stock Expense and Other
   
238
   
238
   
714
   
1,940
 
                           
EARNINGS APPLICABLE TO COMMON STOCK
 
$
30,298
 
$
37,134
 
$
113,063
 
$
106,317
 
 
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 Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
                            
DECEMBER 31, 2004
 
$
260,458
 
$
722,314
 
$
508,618
 
$
(81,672
)
$
1,409,718
 
                                 
Capital Contribution From Parent
         
150,000
               
150,000
 
Preferred Stock Dividends
               
(600
)
       
(600
)
Capital Stock Expense and Other
         
2,485
   
(1,340
)
       
1,145
 
TOTAL
                           
1,560,263
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $8,340
                     
(15,490
)
 
(15,490
)
NET INCOME
               
108,257
         
108,257
 
TOTAL COMPREHENSIVE INCOME
                           
92,767
 
                                 
SEPTEMBER 30, 2005
 
$
260,458
 
$
874,799
 
$
614,935
 
$
(97,162
)
$
1,653,030
 
                                 
DECEMBER 31, 2005
 
$
260,458
 
$
924,837
 
$
635,016
 
$
(16,610
)
$
1,803,701
 
                                 
Common Stock Dividends
               
(7,500
)
       
(7,500
)
Preferred Stock Dividends
               
(600
)
       
(600
)
Capital Stock Expense and Other
         
118
   
(114
)
       
4
 
TOTAL
                           
1,795,605
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Income, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $7,007
                     
13,014
   
13,014
 
NET INCOME
               
113,777
         
113,777
 
TOTAL COMPREHENSIVE INCOME
                           
126,791
 
                                 
SEPTEMBER 30, 2006
 
$
260,458
 
$
924,955
 
$
740,579
 
$
(3,596
)
$
1,922,396
 

   See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2006 and December 31, 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
1,249
 
$
1,741
 
Advances to Affiliates
   
93,764
   
-
 
Accounts Receivable:
             
Customers
   
165,193
   
141,810
 
Affiliated Companies
   
126,586
   
153,453
 
Accrued Unbilled Revenues
   
29,073
   
51,201
 
Miscellaneous
   
4,326
   
527
 
Allowance for Uncollectible Accounts
   
(4,415
)
 
(1,805
)
  Total Accounts Receivable
   
320,763
   
345,186
 
Fuel
   
61,892
   
64,657
 
Materials and Supplies
   
54,286
   
54,967
 
Risk Management Assets
   
93,135
   
132,247
 
Accrued Tax Benefits
   
3,470
   
32,979
 
Regulatory Asset for Under-Recovered Fuel Costs
   
34,028
   
30,697
 
Prepayments and Other
   
13,230
   
44,432
 
TOTAL
   
675,817
   
706,906
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
2,836,442
   
2,798,157
 
Transmission
   
1,595,963
   
1,266,855
 
Distribution
   
2,218,402
   
2,141,153
 
Other
   
336,999
   
323,158
 
Construction Work in Progress
   
784,644
   
647,638
 
Total
   
7,772,450
   
7,176,961
 
Accumulated Depreciation and Amortization
   
2,458,665
   
2,524,855
 
TOTAL - NET
   
5,313,785
   
4,652,106
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
419,891
   
457,294
 
Long-term Risk Management Assets
   
108,215
   
176,231
 
Deferred Charges and Other
   
237,113
   
261,556
 
TOTAL
   
765,219
   
895,081
 
               
TOTAL ASSETS
 
$
6,754,821
 
$
6,254,093
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2006 and December 31, 2005
(Unaudited)

   
2006
 
2005
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
 
$
-
 
$
194,133
 
Accounts Payable:
             
General
   
274,165
   
230,570
 
Affiliated Companies
   
113,461
   
85,941
 
Long-term Debt Due Within One Year - Nonaffiliated
   
141,696
   
146,999
 
Risk Management Liabilities
   
68,292
   
121,165
 
Customer Deposits
   
56,263
   
79,854
 
Accrued Taxes
   
63,395
   
49,833
 
Accrued Interest
   
59,394
   
28,614
 
Other
   
86,917
   
80,132
 
TOTAL
   
863,583
   
1,017,241
 
               
NONCURRENT LIABILITIES
             
Long-term Debt - Nonaffiliated
   
2,356,175
   
1,904,379
 
Long-term Debt - Affiliated
   
100,000
   
100,000
 
Long-term Risk Management Liabilities
   
79,839
   
147,117
 
Deferred Income Taxes
   
937,835
   
952,497
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
315,346
   
201,230
 
Deferred Credits and Other
   
161,884
   
110,144
 
TOTAL
   
3,951,079
   
3,415,367
 
               
TOTAL LIABILITIES
   
4,814,662
   
4,432,608
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
17,763
   
17,784
 
               
Commitments and Contingencies (Note 5)
             
               
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
   
924,955
   
924,837
 
Retained Earnings
   
740,579
   
635,016
 
Accumulated Other Comprehensive Income (Loss)
   
(3,596
)
 
(16,610
)
TOTAL
   
1,922,396
   
1,803,701
 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 
$
6,754,821
 
$
6,254,093
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
OPERATING ACTIVITIES
           
Net Income
 
$
113,777
 
$
108,257
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
157,518
   
146,734
 
Deferred Income Taxes
   
(7,753
)
 
25,103
 
Carrying Costs (Income) Expense
   
13,532
   
(5,320
)
Mark-to-Market of Risk Management Contracts
   
(3,817
)
 
(21,412
)
Pension Contributions to Qualified Plan Trusts
   
-
   
(59,812
)
Over/Under Fuel Recovery, Net
   
830
   
(21,001
)
Change in Other Noncurrent Assets
   
8,466
   
361
 
Change in Other Noncurrent Liabilities
   
20,187
   
(10,306
)
Changes in Components of Working Capital:
             
Accounts Receivable, Net
   
24,423
   
2,899
 
Fuel, Materials and Supplies
   
3,446
   
(7,467
)
Margin Deposits
   
27,103
   
(38,634
)
Accounts Payable
   
22,063
   
54,994
 
Customer Deposits
   
(23,591
)
 
52,302
 
Accrued Taxes, Net
   
43,071
   
(39,022
)
Accrued Interest
   
30,780
   
15,467
 
Other Current Assets
   
4,972
   
(20,482
)
Other Current Liabilities
   
1,788
   
(2,157
)
Net Cash Flows From Operating Activities
   
436,795
   
180,504
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(633,164
)
 
(421,544
)
Change in Other Cash Deposits, Net
   
(873
)
 
(24
)
Change in Advances to Affiliates, Net
   
(93,764
)
 
(67,532
)
Proceeds from Sales of Assets
   
2,151
   
9,680
 
Net Cash Flows Used For Investing Activities
   
(725,650
)
 
(479,420
)
               
FINANCING ACTIVITIES
             
Capital Contributions from Parent
   
-
   
150,000
 
Issuance of Long-term Debt - Nonaffiliated
   
544,364
   
840,469
 
Issuance of Long-term Debt - Affiliated
   
-
   
100,000
 
Change in Advances from Affiliates, Net
   
(194,133
)
 
(211,060
)
Retirement of Long-term Debt - Nonaffiliated
   
(100,008
)
 
(575,007
)
Retirement of Preferred Stock
   
(16
)
 
-
 
Principal Payments for Capital Lease Obligations
   
(4,008
)
 
(4,864
)
Funds From Amended Coal Contract, Net
   
50,264
   
-
 
Dividends Paid on Common Stock
   
(7,500
)
 
-
 
Dividends Paid on Cumulative Preferred Stock
   
(600
)
 
(600
)
Net Cash Flows From Financing Activities
   
288,363
   
298,938
 
               
Net Increase (Decrease) in Cash and Cash Equivalents
   
(492
)
 
22
 
Cash and Cash Equivalents at Beginning of Period
   
1,741
   
1,543
 
Cash and Cash Equivalents at End of Period
 
$
1,249
 
$
1,565
 
               
SUPPLEMENTAL DISCLOSURE
             
Cash Paid for Interest, Net of Capitalized Amounts
 
$
51,537
 
$
56,253
 
Net Cash Paid for Income Taxes
   
12,047
   
61,514
 
Noncash Acquisitions Under Capital Leases
   
2,598
   
1,087
 
Construction Expenditures Included in Accounts Payable at September 30,
   
131,692
   
54,380
 

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 and Contingencies
Note 5
Guarantees
Note 6
Company-wide Staffing and Budget Review
Note 7
Benefit Plans
Note 9
Business Segments
Note 11
Financing Activities
Note 12






 
 
 
 

 




COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 







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


Results of Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income
(in millions)

Third Quarter of 2005
       
$
34
 
               
Changes in Gross Margin:
             
Retail Margins
   
36
       
Off-system Sales
   
20
       
Transmission Revenues
   
(6
)
     
Other
   
(2
)
     
Total Change in Gross Margin
         
48
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(2
)
     
Depreciation and Amortization
   
(14
)
     
Asset Impairments and Other Related Charges
   
39
       
Taxes Other Than Income Taxes
   
5
       
Carrying Costs Income
   
(1
)
     
Interest Expense
   
(2
)
     
Total Change in Operating Expenses and Other
         
25
 
               
Income Tax Expense
         
(23
)
               
Third Quarter of 2006
       
$
84
 

Net Income increased $50 million to $84 million in 2006. The key drivers of the increase were a $48 million increase in Gross Margin and a $39 million asset impairment of units 1 and 2 at our Conesville Plant in 2005, partially offset by a $23 million increase in Income Tax Expense and a $14 million increase in Depreciation and Amortization.

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

·
Retail Margins were $36 million higher than the prior period primarily due to Rate Stabilization Plan (RSP) and Transition Regulatory Asset rate increases effective January 1, 2006 as well as the addition of Monongahela Power’s Ohio customers on December 31, 2005, partially offset by an increase in delivered fuel costs.
·
Off-system Sales increased $20 million primarily due to $13 million increase in physical sales margins and a $10 million increase from lower sharing of off-system sales margins under the SIA. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
·
Transmission Revenues decreased $6 million primarily due to the elimination of SECA revenues as of April 1, 2006. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 3.

Operating Expenses and Other changed between years as follows:

·
Depreciation and Amortization expense increased $14 million due to the increase in the amortization of regulatory assets and a greater depreciable base resulting primarily from the acquisitions of the Waterford Plant and Monongahela Power’s Ohio assets in late 2005.
·
Asset Impairments and Other Related Charges of $39 million were recorded last year due to the 2005 retirement of units 1 and 2 at our Conesville Plant.
·
Taxes Other Than Income Taxes decreased $5 million due to favorable accrual adjustments to property taxes in 2006 and unfavorable accrual adjustments in 2005 partially offset by the increase in property taxes associated with the Waterford and Monongahela asset additions.

Income Tax

The increase of $23 million in Income Tax Expense is primarily due to an increase in pretax book income offset in part by a decrease in state income taxes.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to
Nine Months Ended September 30, 2006 Net Income
(in millions)

Nine Months Ended September 30, 2005
       
$
116
 
               
Changes in Gross Margin:
             
Retail Margins
   
93
       
Off-system Sales
   
29
       
Transmission Revenues
   
(13
)
     
Other
   
6
       
Total Change in Gross Margin
         
115
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(19
)
     
Depreciation and Amortization
   
(41
)
     
Asset Impairments and Other Related Charges
   
39
       
Taxes Other Than Income Taxes
   
(7
)
     
Carrying Costs Income
   
(6
)
     
Interest Expense
   
(8
)
     
Total Change in Operating Expenses and Other
         
(42
)
               
Income Tax Expense
         
(21
)
               
Nine Months Ended September 30, 2006
       
$
168
 

Net Income increased $52 million to $168 million in 2006. The key drivers of the increase were a $115 million increase in Gross Margin and a $39 million asset impairment of units 1 and 2 at our Conesville Plant in 2005, partially offset by a $41 million increase in Depreciation and Amortization, a $19 million increase in Other Operation and Maintenance and a $21 million increase 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 emission allowances, and purchased power, were as follows:

·
Retail Margins increased $93 million primarily due to the RSP and Transition Regulatory Asset rate increases effective January 1, 2006, lower capacity settlement costs, and the addition of Monongahela Power’s Ohio customers on December 31, 2005, partially offset by an increase in delivered fuel costs.
·
Off-system Sales increased $29 million due to $30 million increase in physical sales margins and a $12 million increase from lower sharing of off-system sales margins under the SIA offset by a decrease in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
·
Transmission Revenues decreased $13 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $3 million recorded in 2006 related to potential SECA refunds pending settlement negotiations with various intervenors. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 3.
·
Other revenues increased $6 million primarily due to higher gains on sales of emission allowances.

Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance increased $19 million due to an increase in PJM administrative fees, an increase in transmission expenses related to the AEP Transmission Equalization Agreement, favorable adjustments in the prior year related to the corporate owned life insurance policy and increased expenses related to factored receivables and uncollectible accounts. The increases were partially offset by the recognition of a regulatory asset related to recent PUCO orders regarding distribution service reliability and restoration costs. 
·
Depreciation and Amortization expense increased $41 million primarily due to the increase in the amortization of regulatory assets and a greater depreciable base resulting primarily from the acquisitions of the Waterford Plant and Monongahela Power’s Ohio assets. In addition, the 2005 RSP order resulted in a reversal of unused shopping credits of $18 million offset by the establishment of a $7 million regulatory liability to benefit low-income customers and for economic development.
·
Asset Impairments and Other Related Charges in the amount of $39 million were recorded last year due to the 2005 retirement of units 1 and 2 at our Conesville Plant.
·
Taxes Other Than Income Taxes increased $7 million due to the increase in property taxes associated with the Waterford and Monongahela asset additions partially offset by accrual adjustments to property taxes that were favorable in 2006 and unfavorable in 2005.
·
Carrying Costs Income decreased $6 million primarily due to the completion of deferrals of carrying costs on environmental capital expenditures from 2004 and 2005 that are now recovered during 2006 through 2008 according to the RSP.
·
Interest Expense increased $8 million primarily due to a new long-term debt issuance during the fourth quarter of 2005.

Income Tax

The increase of $21 million in Income Tax Expense is primarily due to an increase in pretax book income offset in part by a decrease in 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
 
A-

Financing Activity

There were no long-term debt issuances or retirements during the first nine months of 2006.

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 2005 Annual Report and has not changed significantly from year-end.

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, Note 6 - Customer Choice and Industry Restructuring and Note 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters, Note 4 - Customer Choice and Industry Restructuring and Note 5 - Commitments 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 2005 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.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. 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 September 30, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of September 30, 2006
(in thousands)

   
MTM Risk Management Contracts
 
Cash Flow Hedges
 
DETM Assignment (a)
 
Total
 
Current Assets
 
$
53,028
 
$
4,782
 
$
-
 
$
57,810
 
Noncurrent Assets
   
68,304
   
326
   
-
   
68,630
 
Total MTM Derivative Contract Assets
   
121,332
   
5,108
   
-
   
126,440
 
                           
Current Liabilities
   
(39,606
)
 
(743
)
 
(1,202
)
 
(41,551
)
Noncurrent Liabilities
   
(44,001
)
 
(8
)
 
(5,841
)
 
(49,850
)
Total MTM Derivative Contract Liabilities
   
(83,607
)
 
(751
)
 
(7,043
)
 
(91,401
)
                           
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
37,725
 
$
4,357
 
$
(7,043
)
$
35,039
 

(a)
See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.
 
MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2006
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005
 
$
33,322
 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
   
(5,405
)
Fair Value of New Contracts at Inception When Entered During the Period (a)
   
146
 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period
   
(138
)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts
   
381
 
Changes in Fair Value Due to Market Fluctuations During the Period (b)
   
12,996
 
Changes Due to SIA (c)
   
(3,864
)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)
   
287
 
Total MTM Risk Management Contract Net Assets
   
37,725
 
Net Cash Flow Hedge Contracts
   
4,357
 
DETM Assignment (e)
   
(7,043
)
Total MTM Risk Management Contract Net Assets at September 30, 2006
 
$
35,039
 

(a)
Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)
Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)
See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
(d)
“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.
(e)
See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 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 giving an indication of when these MTM amounts will settle and generate cash.

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2006
(in thousands)

   
Remainder
2006
 
2007
 
2008
 
2009
 
2010
 
After
2010
 
Total
Prices Actively Quoted - Exchange Traded Contracts
 
$
1,146
 
$
8,236
 
$
2,981
 
$
-
 
$
-
 
$
-
 
$
12,363
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)
   
2,425
   
6,394
   
3,095
   
4,669
   
-
   
-
   
16,583
Prices Based on Models and Other Valuation Methods (b)
   
4
   
(2,247
)
 
1,039
   
2,971
   
5,324
   
1,688
   
8,779
Total
 
$
3,575
 
$
12,383
 
$
7,115
 
$
7,640
 
$
5,324
 
$
1,688
 
$
37,725

(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.

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 employ various commodity instruments to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

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, 2005 to September 30, 2006. 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
Nine Months Ended September 30, 2006
(in thousands)

   
Power
 
Beginning Balance in AOCI December 31, 2005
 
$
(859
)
Changes in Fair Value
   
2,853
 
Impact due to Changes in SIA (a)
   
(261
)
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled
   
1,348
 
Ending Balance in AOCI September 30, 2006
 
$
3,081
 

(a)
See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $2,875 thousand gain.

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 September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

Nine Months Ended
September 30, 2006
       
Twelve Months Ended
December 31, 2005
(in thousands)
       
(in thousands)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
$418
 
$1,224
 
$414
 
$233
       
$424
 
$705
 
$335
 
$121

The High VaR for the nine months ended September 30, 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 $64 million and $86 million at September 30, 2006 and December 31, 2005, 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 consolidated results of operations or financial position.



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
Three Months Ended
 
Nine Months Ended
 
   
2006
 
2005
 
2006
 
2005
 
REVENUES
                   
Electric Generation, Transmission and Distribution
 
$
513,643
 
$
406,525
 
$
1,321,422
 
$
1,074,099
 
Sales to AEP Affiliates
   
24,806
   
46,698
   
60,337
   
103,939
 
Other
   
1,449
   
1,345
   
4,016
   
3,653
 
TOTAL
   
539,898
   
454,568
   
1,385,775
   
1,181,691
 
                           
EXPENSES
                         
Fuel and Other Consumables for Electric Generation
   
90,510
   
72,550
   
231,543
   
191,188
 
Purchased Electricity for Resale
   
35,449
   
9,016
   
87,902
   
26,922
 
Purchased Electricity from AEP Affiliates
   
102,669
   
109,274
   
272,334
   
284,221
 
Other Operation
   
66,195
   
56,276
   
180,022
   
152,833
 
Maintenance
   
14,704
   
21,863
   
56,140
   
63,947
 
Asset Impairments and Other Related Charges
   
-
   
39,109
   
-
   
39,109
 
Depreciation and Amortization
   
51,149
   
37,454
   
143,495
   
102,985
 
Taxes Other Than Income Taxes
   
38,586
   
43,422
   
119,875
   
112,657
 
TOTAL
   
399,262
   
388,964
   
1,091,311
   
973,862
 
                           
OPERATING INCOME
   
140,636
   
65,604
   
294,464
   
207,829
 
                           
Other Income (Expense):
                         
Interest Income
   
989
   
1,038
   
1,919
   
2,666
 
Carrying Costs Income
   
1,046
   
1,800
   
3,082
   
8,716
 
Allowance for Equity Funds Used During Construction
   
659
   
229
   
1,466
   
1,036
 
Interest Expense
   
(15,813
)
 
(13,508
)
 
(50,247
)
 
(42,089
)
                           
INCOME BEFORE INCOME TAXES
   
127,517
   
55,163
   
250,684
   
178,158
 
                           
Income Tax Expense
   
43,496
   
20,938
   
83,064
   
61,814
 
                           
NET INCOME      84,021      34,225      167,620      116,344  
                           
Capital Stock Expense
   
39
   
254
   
118
   
2,366
 
                           
EARNINGS APPLICABLE TO COMMON STOCK    83,982   $  33,971   $  167,502   $  113,978  

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 Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2004
 
$
41,026
 
$
577,415
 
$
341,025
 
$
(60,816
)
$
898,650
 
                                 
Common Stock Dividends
               
(85,500
)
       
(85,500
)
Capital Stock Expense and Other
         
2,366
   
(2,366
)
       
-
 
TOTAL
                           
813,150
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $3,655
                     
(6,789
)
 
(6,789
)
NET INCOME
               
116,344
         
116,344
 
TOTAL COMPREHENSIVE INCOME
                           
109,555
 
                                 
SEPTEMBER 30, 2005
 
$
41,026
 
$
579,781
 
$
369,503
 
$
(67,605
)
$
922,705
 
                                 
DECEMBER 31, 2005
 
$
41,026
 
$
580,035
 
$
361,365
 
$
(880
)
$
981,546
 
                                 
Common Stock Dividends
               
(67,500
)
       
(67,500
)
Capital Stock Expense
         
118
   
(118
)
       
-
 
TOTAL
                           
914,046
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Income, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $2,121
                     
3,940
   
3,940
 
NET INCOME
               
167,620
         
167,620
 
TOTAL COMPREHENSIVE INCOME
                           
171,560
 
                                 
SEPTEMBER 30, 2006
 
$
41,026
 
$
580,153
 
$
461,367
 
$
3,060
 
$
1,085,606
 

   See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2006 and December 31, 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
1,251
 
$
940
 
Advances to Affiliates
   
60,417
   
-
 
Accounts Receivable:
             
Customers
   
54,517
   
43,143
 
Affiliated Companies
   
51,218
   
67,694
 
Accrued Unbilled Revenues
   
15,687
   
10,086
 
Miscellaneous
   
5,185
   
2,012
 
Allowance for Uncollectible Accounts
   
(1,380
)
 
(1,082
)
  Total Accounts Receivable
   
125,227
   
121,853
 
Fuel
   
33,556
   
28,579
 
Materials and Supplies
   
30,742
   
27,519
 
Emission Allowances
   
7,070
   
20,181
 
Risk Management Assets
   
57,810
   
76,507
 
Accrued Tax Benefits
   
-
   
36,838
 
Prepayments and Other
   
11,284
   
23,546
 
TOTAL
   
327,357
   
335,963
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
1,889,414
   
1,874,652
 
Transmission
   
478,513
   
457,937
 
Distribution
   
1,451,842
   
1,380,722
 
Other
   
191,599
   
184,096
 
Construction Work in Progress
   
224,854
   
129,246
 
Total
   
4,236,222
   
4,026,653
 
Accumulated Depreciation and Amortization
   
1,589,465
   
1,500,858
 
TOTAL - NET
   
2,646,757
   
2,525,795
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
216,339
   
231,599
 
Long-term Risk Management Assets
   
68,630
   
101,512
 
Deferred Charges and Other
   
187,915
   
237,925
 
TOTAL
   
472,884
   
571,036
 
               
TOTAL ASSETS
 
$
3,446,998
 
$
3,432,794
 

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
September 30, 2006 and December 31, 2005
(Unaudited)

   
2006
 
2005
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
 
$
-
 
$
17,609
 
Accounts Payable:
             
General
   
104,090
   
59,134
 
Affiliated Companies
   
57,910
   
59,399
 
Risk Management Liabilities
   
41,551
   
69,036
 
Customer Deposits
   
32,448
   
47,013
 
Accrued Taxes
   
111,910
   
157,729
 
Other
   
47,351
   
50,229
 
TOTAL
   
395,260
   
460,149
 
               
NONCURRENT LIABILITIES
             
Long-term Debt - Nonaffiliated
   
1,097,222
   
1,096,920
 
Long-term Debt - Affiliated
   
100,000
   
100,000
 
Long-term Risk Management Liabilities
   
49,850
   
84,291
 
Deferred Income Taxes
   
494,805
   
498,232
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
177,801
   
165,344
 
Deferred Credits and Other
   
46,454
   
46,312
 
TOTAL
   
1,966,132
   
1,991,099
 
               
TOTAL LIABILITIES
   
2,361,392
   
2,451,248
 
               
Commitments and Contingencies (Note 5)
             
               
COMMON SHAREHOLDER’S EQUITY
             
Common Stock - No Par Value Per Share:
             
Authorized - 24,000,000 Shares
             
Outstanding - 16,410,426 Shares
   
41,026
   
41,026
 
Paid-in Capital
   
580,153
   
580,035
 
Retained Earnings
   
461,367
   
361,365
 
Accumulated Other Comprehensive Income (Loss)
   
3,060
   
(880
)
TOTAL
   
1,085,606
   
981,546
 
               
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY
 
$
3,446,998
 
$
3,432,794
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
OPERATING ACTIVITIES
           
Net Income
 
$
167,620
 
$
116,344
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
143,495
   
102,985
 
Deferred Income Taxes
   
(5,097
)
 
(9,441
)
Asset Impairments and Other Related Charges
   
-
   
39,109
 
Carrying Costs Income
   
(3,082
)
 
(8,716
)
Mark-to-Market of Risk Management Contracts
   
(4,502
)
 
(12,767
)
Pension Contributions to Qualified Plan Trusts
   
-
   
(37,832
)
Deferred Property Taxes
   
49,518
   
47,640
 
Change in Other Noncurrent Assets
   
(24,297
)
 
(24,839
)
Change in Other Noncurrent Liabilities
   
11,752
   
14,747
 
Changes in Components of Working Capital:
             
Accounts Receivable, Net
   
(3,374
)
 
(7,748
)
Fuel, Materials and Supplies
   
(8,200
)
 
8,611
 
Accounts Payable
   
31,765
   
2,215
 
Customer Deposits
   
(14,565
)
 
30,760
 
Accrued Taxes, Net
   
(8,981
)
 
(94,788
)
Other Current Assets
   
26,838
   
(14,809
)
Other Current Liabilities
   
(2,878
)
 
(10,471
)
Net Cash Flows From Operating Activities
   
356,012
   
141,000
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(207,875
)
 
(118,222
)
Change in Advances to Affiliates, Net
   
(60,417
)
 
141,550
 
Purchase of Waterford Plant
   
-
   
(218,356
)
Other
   
8
   
4,639
 
Net Cash Flows Used For Investing Activities
   
(268,284
)
 
(190,389
)
               
FINANCING ACTIVITIES
             
Change in Advances from Affiliates, Net
   
(17,609
)
 
138,541
 
Principal Payments for Capital Lease Obligations
   
(2,308
)
 
(2,642
)
Dividends Paid on Common Stock
   
(67,500
)
 
(85,500
)
Net Cash Flows From (Used For) Financing Activities
   
(87,417
)
 
50,399
 
               
Net Increase (Decrease) in Cash and Cash Equivalents
   
311
   
1,010
 
Cash and Cash Equivalents at Beginning of Period
   
940
   
58
 
Cash and Cash Equivalents at End of Period
 
$
1,251
 
$
1,068
 
               
SUPPLEMENTARY INFORMATION
             
Cash Paid for Interest, Net of Capitalized Amounts
 
$
52,958
 
$
50,095
 
Net Cash Paid for Income Taxes
   
35,561
   
109,382
 
Noncash Acquisitions Under Capital Leases
   
2,130
   
520
 
Construction Expenditures Included in Accounts Payable at September 30,
   
22,955
   
4,974
 
Assumption of Liabilities in Connection with Waterford Plant Acquisition
   
-
   
2,295
 

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 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
Customer Choice and Industry Restructuring
Note 4
Commitments and Contingencies
Note 5
Guarantees
Note 6
Company-wide Staffing and Budget Review
Note 7
Acquisitions, Assets Held for Sale and Asset Impairments
Note 8
Benefit Plans
Note 9
Business Segments
Note 11
Financing Activities
Note 12






 
 
 
 
 

 

INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
 
 
 
 
 
 
 
 

 







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

Results of Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income
(in millions)

Third Quarter of 2005
       
$
53
 
               
Changes in Gross Margin:
             
Retail Margins
   
(44
)
     
Off-system Sales (a)
   
34
       
Transmission Revenues
   
(4
)
     
Other
   
2
       
Total Change in Gross Margin
         
(12
)
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(17
)
     
Depreciation and Amortization
   
(5
)
     
Other Income (Expense)
   
3
       
Interest Expense
   
(1
)
     
Total Change in Operating Expenses and Other
         
(20
)
               
Income Tax Expense
         
14
 
               
Third Quarter of 2006
       
$
35
 

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

Net Income decreased $18 million to $35 million in 2006. The key drivers of the decrease were a $12 million decrease in Gross Margin and a $17 million increase in Other Operation and Maintenance expenses, partially offset by a $14 million decrease in Income Tax Expense.

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 $44 million primarily due to lower fuel recovery as fuel cost increases could not be recovered due to the Indiana fuel cap and a reduction in capacity revenues of $22 million under the Interconnection Agreement. Capacity revenues declined due to our new peak demand in July 2006 and our affiliates’ addition of generating capacity in 2005.
·
Off-system Sales increased $34 million primarily due to the addition of new municipal contracts including new rates and increased demand beginning January 2006, a $13 million increase in physical sales margins and a $10 million increase from lower sharing of off-system sales margins under the SIA. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
·
Transmission Revenues decreased $4 million primarily due to the elimination of SECA revenues as of April 1, 2006. At this time, we have a pending proposal with the FERC to replace SECA revenues. 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 $17 million primarily due to the abandonment of digital turbine control equipment at the Cook Plant.
·
Depreciation and Amortization increased $5 million primarily due to higher expense related to capital additions.

Income Taxes

Income Tax Expense decreased $14 million primarily due to a decrease in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to
Nine Months Ended September 30, 2006 Net Income
(in millions)

Nine Months Ended September 30, 2005
       
$
128
 
               
Changes in Gross Margin:
             
Retail Margins
   
(55
)
     
Off-system Sales (a)
   
63
       
Transmission Revenues
   
(11
)
     
Other
   
11
       
Total Change in Gross Margin
         
8
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(12
)
     
Depreciation and Amortization
   
(9
)
     
Taxes Other Than Income Taxes
   
(3
)
     
Other Income (Expense)
   
4
       
Interest Expense
   
(4
)
     
Total Change in Operating Expenses and Other
         
(24
)
               
Income Tax Expense
         
9
 
               
Nine Months Ended September 30, 2006
       
$
121
 

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

Net Income decreased $7 million to $121 million in 2006. The key driver of the decrease was a $12 million increase in Other Operation and Maintenance expenses, partially offset by a $9 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 decreased $55 million primarily due to lower fuel recovery as fuel cost increases could not be recovered due to the Indiana fuel cap and a reduction in capacity settlement revenues of $27 million under the Interconnection Agreement. Capacity revenues declined due to our new peak demand in July 2006 and our affiliates’ addition of generating capacity in 2005.
·
Off-system Sales increased $63 million primarily due to the addition of new municipal contracts including new rates and increased demand beginning January 2006, a $33 million increase in physical sales margins and a $12 million increase from lower sharing of off-system sales margins under the SIA, offset by a $12 million decrease in margins from reduced optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
·
Transmission Revenues decreased $11 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a $3 million provision for potential SECA refunds pending settlement negotiations with various intervenors. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 3.
·
Other revenues increased $11 million primarily due to increased River Transportation Division (RTD) revenues for barging coal and gains on sales of emission allowances. Related expenses which offset the RTD revenue increase 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 $12 million primarily due to the abandonment of digital turbine control equipment at the Cook Plant and an increase in RTD expenses.
·
Depreciation and Amortization increased $9 million primarily due to higher expense related to capital additions.

Income Taxes

Income Tax Expense decreased $9 million primarily due to a decrease in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings, unchanged since the first quarter of 2003, are as follows:

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

Cash Flow

Cash flows for the nine months ended September 30, 2006 and 2005 were as follows:

   
2006
 
2005
 
   
(in thousands)
 
             
Cash and Cash Equivalents at Beginning of Period
 
$
854
 
$
511
 
Net Cash Flows From (Used For):
             
Operating Activities
   
456,313
   
276,523
 
Investing Activities
   
(355,252
)
 
(238,875
)
Financing Activities
   
(101,209
)
 
(37,428
)
Net Increase (Decrease) in Cash and Cash Equivalents
   
(148
)
 
220
 
Cash and Cash Equivalents at End of Period
 
$
706
 
$
731
 

Operating Activities

Net Cash Flows From Operating Activities were $456 million in 2006. We produced Net Income of $121 million during the period and a noncash expense item of $137 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 most significant are increases related to accounts receivable, accounts payable and accrued taxes. We collected receivables from our affiliates related to power sales, settled litigation and emission allowances. Accounts payable and accrued taxes increased related to timing of payments.

Net Cash Flows From Operating Activities were $277 million in 2005. We produced Net Income of $128 million during the period and a noncash expense item of $128 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 most significant relates to a $86 million change in accrued taxes reflecting taxes paid during 2005. We also contributed $46 million to our pension trust.
 
Investing Activities

Net Cash Flows Used For Investing Activities during 2006 and 2005 primarily reflect our construction expenditures of $241 million and $190 million and acquisition of nuclear fuel of $73 million and $28 million, respectively. Construction expenditures for the nuclear plant and transmission and distribution assets are to upgrade or replace equipment and improve reliability. We also invested in capital projects to improve air quality and water intake systems. For the remainder of 2006, we expect Construction Expenditures of approximately $90 million.

Financing Activities

Net Cash Flows Used For Financing Activities were $101 million in 2006. We used cash from operations to repay $66 million of Advances from Affiliates and pay $30 million of common stock dividends. We also refinanced a series of pollution control bonds.

Net Cash Flows Used For Financing Activities were $37 million in 2005. We retired $61 million of preferred stock and paid $52 million of common stock dividends, partially offset by the increase in Advances from Affiliates of $81 million.

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2006 were:

Issuances

   
Principal
Amount
 
Interest
 
Due
Type of Debt
   
Rate
 
Date
     
(in thousands)
 
(%)
   
               
Pollution Control Bonds
 
$
50,000
 
Variable
 
2025

Retirements

   
Principal
Amount Paid
 
Interest
 
Due
Type of Debt
   
Rate
 
Date
     
(in thousands)
 
(%)
   
               
Pollution Control Bonds
 
$
50,000
 
6.55
 
2025

In October 2006, we had a required remarketing of $65 million of 2.625% pollution control bonds, which were converted from a three-year fixed rate mode to an auction rate mode.

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.

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 allow only traditional operating lease arrangements and sales of customer accounts receivable that are entered in the normal course of business. Our off-balance sheet arrangements have not changed significantly since year-end. For complete information on our off-balance sheet arrangements including the lease of Rockport Plant Unit 2 see “Off-balance Sheet Arrangements” in the “Management’s Financial Discussion and Analysis” section of our 2005 Annual Report.
 
Summary Obligation Information 

A summary of our contractual obligations is included in our 2005 Annual Report and has not changed significantly from year-end.

Significant Factors

Cook Plant Outage

In September 2006, Cook Plant Unit 1 began a regular refueling outage. This outage includes the replacement of major components, including the reactor vessel head. Installation of capital projects exceeding $100 million will be completed during this outage and were included in our capital forecast. The improvements and replacement of major components should increase unit capacity and efficiency.  We expect to restart Cook Plant Unit 1 during early November 2006 as planned. We refueled Cook Plant Unit 2 during March and April 2006 and plan to replace its vessel head during its next refueling outage in the fall of 2007.

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, Note 6 - Customer Choice and Industry Restructuring and Note 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters and Note 5 - Commitments 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 2005 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.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. 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 September 30, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of September 30, 2006
(in thousands)

   
MTM Risk Management Contracts
 
Cash Flow &
Fair Value Hedges
 
DETM Assignment (a)
 
Total
 
Current Assets
 
$
55,747
 
$
5,010
 
$
-
 
$
60,757
 
Noncurrent Assets
   
71,650
   
342
   
-
   
71,992
 
Total MTM Derivative Contract Assets
   
127,397
   
5,352
   
-
   
132,749
 
                           
Current Liabilities
   
(42,116
)
 
(15,586
)
 
(1,259
)
 
(58,961
)
Noncurrent Liabilities
   
(46,349
)
 
(8
)
 
(6,120
)
 
(52,477
)
Total MTM Derivative Contract Liabilities
   
(88,465
)
 
(15,594
)
 
(7,379
)
 
(111,438
)
                           
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
38,932
 
$
(10,242
)
$
(7,379
)
$
21,311
 

(a)
See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.


MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2006
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005
 
$
33,932
 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
   
(538
)
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
   
(137
)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts
   
-
 
Changes in Fair Value Due to Market Fluctuations During the Period (b)
   
(310
)
Changes Due to SIA (c)
   
(3,940
)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)
   
9,925
 
Total MTM Risk Management Contract Net Assets
   
38,932
 
Net Cash Flow & Fair Value Hedge Contracts
   
(10,242
)
DETM Assignment (e)
   
(7,379
)
Total MTM Risk Management Contract Net Assets at September 30, 2006
 
$
21,311
 

(a)
Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)
Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)
See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
(d)
“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in our Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(e)
See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 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 giving an indication of when these MTM amounts will settle and generate cash.


Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2006
(in thousands)

   
Remainder 2006
 
2007
 
2008
 
2009
 
2010
 
After
2010
 
Total
 
Prices Actively Quoted - Exchange Traded Contracts
 
$
1,202
 
$
8,629
 
$
3,123
 
$
-
 
$
-
 
$
-
 
$
12,954
 
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)
   
2,395
   
6,585
   
3,260
   
4,892
   
-
   
-
   
17,132
 
Prices Based on Models and Other Valuation Methods (b)
   
-
   
(2,602
)
 
988
   
3,113
   
5,579
   
1,768
   
8,846
 
Total
 
$
3,597
 
$
12,612
 
$
7,371
 
$
8,005
 
$
5,579
 
$
1,768
 
$
38,932
 

(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.

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 employ various commodity instruments to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

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

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, 2005 to September 30, 2006. 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
Nine Months Ended September 30, 2006
(in thousands)

   
Power
 
Interest Rate
 
Total
 
Beginning Balance in AOCI December 31, 2005
 
$
(877
)
$
(2,590
)
$
(3,467
)
Changes in Fair Value
   
2,978
   
(9,382
)
 
(6,404
)
Impact due to Changes in SIA (a)
   
(267
)
 
-
   
(267
)
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled
   
1,394
   
241
   
1,635
 
Ending Balance in AOCI September 30, 2006
 
$
3,228
 
$
(11,731
)
$
(8,503
)

(a)
See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $2,120 thousand gain.

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 September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

Nine Months Ended
September 30, 2006
       
Twelve Months Ended
December 31, 2005
(in thousands)
       
(in thousands)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
$438
 
$1,283
 
$427
 
$242
       
$433
 
$720
 
$343
 
$124

The High VaR for the nine months ended September 30, 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 $69 million and $55 million at September 30, 2006 and December 31, 2005, 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 and Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
Three Months Ended
 
Nine Months Ended
 
   
2006
 
2005
 
2006
 
2005
 
REVENUES
                   
Electric Generation, Transmission and Distribution
 
$
449,259
 
$
391,361
 
$
1,224,609
 
$
1,095,621
 
Sales to AEP Affiliates
   
54,793
   
103,141
   
223,728
   
277,223
 
Other - Affiliated
   
12,903
   
11,745
   
37,838
   
34,215
 
Other - Nonaffiliated
   
8,580
   
8,832
   
24,593
   
23,139
 
TOTAL
   
525,535
   
515,079
   
1,510,768
   
1,430,198
 
                           
EXPENSES
                         
Fuel and Other Consumables for Electric Generation
   
98,135
   
93,557
   
283,734
   
253,255
 
Purchased Electricity for Resale
   
20,450
   
11,784
   
46,993
   
35,786
 
Purchased Electricity from AEP Affiliates
   
92,052
   
82,763
   
259,304
   
228,756
 
Other Operation
   
125,170
   
122,927
   
357,882
   
343,239
 
Maintenance
   
56,960
   
42,300
   
142,531
   
144,988
 
Depreciation and Amortization
   
47,895
   
42,726
   
136,681
   
127,695
 
Taxes Other Than Income Taxes
   
18,472
   
18,268
   
56,343
   
53,246
 
TOTAL
   
459,134
   
414,325
   
1,283,468
   
1,186,965
 
                           
OPERATING INCOME
   
66,401
   
100,754
   
227,300
   
243,233
 
                           
Other Income (Expense):
                         
Interest Income
   
1,102
   
586
   
2,459
   
1,437
 
Allowance for Equity Funds Used During Construction
   
2,517
   
563
   
5,881
   
3,252
 
Interest Expense
   
(17,228
)
 
(16,343
)
 
(52,663
)
 
(48,427
)
                           
INCOME BEFORE INCOME TAXES
   
52,792
   
85,560
   
182,977
   
199,495
 
                           
Income Tax Expense
   
18,231
   
32,548
   
62,013
   
71,221
 
                           
NET INCOME
   
34,561
   
53,012
   
120,964
   
128,274
 
                           
Preferred Stock Dividend Requirements including Capital Stock Expense
   
85
   
86
   
255
   
311
 
                           
EARNINGS APPLICABLE TO COMMON STOCK
 
$
34,476
 
$
52,926
 
$
120,709
 
$
127,963
 

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 Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2004
 
$
56,584
 
$
858,835
 
$
221,330
 
$
(45,251
)
$
1,091,498
 
                                 
Common Stock Dividends
               
(52,000
)
       
(52,000
)
Preferred Stock Dividends
               
(255
)
       
(255
)
Capital Stock Expense and Other
         
2,455
   
(56
)
       
2,399
 
TOTAL
                           
1,041,642
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $2,900
                     
(5,385
)
 
(5,385
)
NET INCOME
               
128,274
         
128,274
 
TOTAL COMPREHENSIVE INCOME
                           
122,889
 
                                 
SEPTEMBER 30, 2005
 
$
56,584
 
$
861,290
 
$
297,293
 
$
(50,636
)
$
1,164,531
 
                                 
DECEMBER 31, 2005
 
$
56,584
 
$
861,290
 
$
305,787
 
$
(3,569
)
$
1,220,092
 
                                 
Common Stock Dividends
               
(30,000
)
       
(30,000
)
Preferred Stock Dividends
               
(255
)
       
(255
)
TOTAL
                           
1,189,837
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $2,712
                     
(5,036
)
 
(5,036
)
NET INCOME
               
120,964
         
120,964
 
TOTAL COMPREHENSIVE INCOME
                           
115,928
 
                                 
SEPTEMBER 30, 2006
 
$
56,584
 
$
861,290
 
$
396,496
 
$
(8,605
)
$
1,305,765
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2006 and December 31, 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
706
 
$
854
 
Accounts Receivable:
             
Customers
   
72,718
   
62,614
 
Affiliated Companies
   
80,334
   
127,981
 
Miscellaneous
   
2,463
   
1,982
 
Allowance for Uncollectible Accounts
   
(1,204
)
 
(898
)
Total Accounts Receivable
   
154,311
   
191,679
 
Fuel
   
38,531
   
25,894
 
Materials and Supplies
   
126,067
   
118,039
 
Risk Management Assets
   
60,757
   
78,134
 
Accrued Tax Benefits
   
16,951
   
51,846
 
Margin Deposits
   
1,258
   
17,115
 
Prepayments and Other
   
9,072
   
14,188
 
TOTAL
   
407,653
   
497,749
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
3,217,437
   
3,128,078
 
Transmission
   
1,041,725
   
1,028,496
 
Distribution
   
1,084,530
   
1,029,498
 
Other (including nuclear fuel and coal mining)
   
523,502
   
465,130
 
Construction Work in Progress
   
283,714
   
311,080
 
Total
   
6,150,908
   
5,962,282
 
Accumulated Depreciation, Depletion and Amortization
   
2,909,705
   
2,822,558
 
TOTAL - NET
   
3,241,203
   
3,139,724
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
217,070
   
222,686
 
Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds
   
1,191,142
   
1,133,567
 
Long-term Risk Management Assets
   
71,992
   
103,645
 
Deferred Charges and Other
   
144,890
   
164,938
 
TOTAL
   
1,625,094
   
1,624,836
 
               
TOTAL ASSETS
 
$
5,273,950
 
$
5,262,309
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2006 and December 31, 2005
(Unaudited)

   
2006
 
2005
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
 
$
27,616
 
$
93,702
 
Accounts Payable:
             
General
   
137,157
   
139,334
 
Affiliated Companies
   
59,163
   
60,324
 
Long-term Debt Due Within One Year
   
349,627
   
364,469
 
Risk Management Liabilities
   
58,961
   
71,032
 
Customer Deposits
   
34,943
   
49,258
 
Accrued Taxes
   
49,964
   
56,567
 
Other
   
138,352
   
112,839
 
TOTAL
   
855,783
   
947,525
 
               
NONCURRENT LIABILITIES
             
Long-term Debt
   
1,104,274
   
1,080,471
 
Long-term Risk Management Liabilities
   
52,477
   
86,159
 
Deferred Income Taxes
   
336,194
   
335,264
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
714,663
   
710,015
 
Asset Retirement Obligations
   
774,061
   
737,959
 
Deferred Credits and Other
   
122,651
   
136,740
 
TOTAL
   
3,104,320
   
3,086,608
 
               
TOTAL LIABILITIES
   
3,960,103
   
4,034,133
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
8,082
   
8,084
 
               
Commitments and Contingencies (Note 5)
             
               
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
   
396,496
   
305,787
 
Accumulated Other Comprehensive Income (Loss)
   
(8,605
)
 
(3,569
)
TOTAL
   
1,305,765
   
1,220,092
 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 
$
5,273,950
 
$
5,262,309
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
OPERATING ACTIVITIES
           
Net Income
 
$
120,964
 
$
128,274
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
136,681
   
127,695
 
Accretion of Asset Retirement Obligations
   
36,309
   
35,742
 
Deferred Income Taxes
   
7,734
   
2,269
 
Deferred Investment Tax Credits
   
(5,460
)
 
(5,496
)
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net
   
(20,673
)
 
10,506
 
Amortization of Nuclear Fuel
   
37,839
   
41,613
 
Mark-to-Market of Risk Management Contracts
   
(4,915
)
 
(11,275
)
Pension Contributions to Qualified Plan Trusts
   
-
   
(46,051
)
Deferred Property Taxes
   
10,854
   
9,814
 
Change in Other Noncurrent Assets
   
25,260
   
11,650
 
Change in Other Noncurrent Liabilities
   
5,071
   
13,961
 
Changes in Components of Working Capital:
             
Accounts Receivable, Net
   
37,368
   
14,441
 
Fuel, Materials and Supplies
   
(20,665
)
 
4,303
 
Accounts Payable
   
29,483
   
4,065
 
Accrued Taxes, Net
   
28,292
   
(85,750
)
Customer Deposits
   
(14,315
)
 
28,233
 
Accrued Interest
   
11,534
   
10,358
 
Rent Accrued - Rockport Plant Unit 2
   
18,464
   
18,464
 
Other Current Assets
   
20,997
   
(36,068
)
Other Current Liabilities
   
(4,509
)
 
(225
)
Net Cash Flows From Operating Activities
   
456,313
   
276,523
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(240,806
)
 
(190,171
)
Change in Advances to Affiliates, Net
   
-
   
5,093
 
Purchases of Investment Securities
   
(559,803
)
 
(473,802
)
Sales of Investment Securities
   
517,017
   
434,639
 
Acquisitions of Nuclear Fuel
   
(72,614
)
 
(28,188
)
Proceeds from Sales of Assets
   
954
   
13,554
 
Net Cash Flows Used For Investing Activities
   
(355,252
)
 
(238,875
)
               
FINANCING ACTIVITIES
             
Issuance of Long-term Debt
   
49,745
   
-
 
Change in Advances from Affiliates, Net
   
(66,086
)
 
81,101
 
Retirement of Long-term Debt
   
(50,000
)
 
-
 
Retirement of Cumulative Preferred Stock
   
(1
)
 
(61,445
)
Principal Payments for Capital Lease Obligations
   
(4,612
)
 
(4,829
)
Dividends Paid on Common Stock
   
(30,000
)
 
(52,000
)
Dividends Paid on Cumulative Preferred Stock
   
(255
)
 
(255
)
Net Cash Flows Used For Financing Activities
   
(101,209
)
 
(37,428
)
               
Net Increase (Decrease) in Cash and Cash Equivalents
   
(148
)
 
220
 
Cash and Cash Equivalents at Beginning of Period
   
854
   
511
 
Cash and Cash Equivalents at End of Period
 
$
706
 
$
731
 
               
SUPPLEMENTAL DISCLOSURE
             
Cash Paid for Interest, Net of Capitalized Amounts
 
$
37,708
 
$
34,999
 
Net Cash Paid for Income Taxes
   
20,180
   
149,058
 
Noncash Acquisitions Under Capital Leases
   
4,359
   
1,465
 
Construction Expenditures Included in Accounts Payable at September 30,
   
29,755
   
25,008
 

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 and Contingencies
Note 5
Guarantees
Note 6
Company-wide Staffing and Budget Review
Note 7
Benefit Plans
Note 9
Business Segments
Note 11
Financing Activities
Note 12
   






 

 
 
 

 


KENTUCKY POWER COMPANY
 
 
 
 
 
 
 
 
 
 
 
 




KENTUCKY POWER COMPANY
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income
(in millions)

Third Quarter of 2005
       
$
8
 
               
Changes in Gross Margin:
             
Retail Margins
   
1
       
Off-system Sales
   
8
       
Transmission Revenues
   
(3
)
     
Total Change in Gross Margin
         
6
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(3
)
     
Taxes Other Than Income Taxes
   
1
       
Total Change in Operating Expenses and Other
         
(2
)
               
Income Tax Expense
         
(2
)
               
Third Quarter of 2006
       
$
10
 

Net Income increased $2 million to $10 million in 2006. The key driver of the increase was a $6 million increase in Gross Margin.

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 $1 million primarily due to $12 million of rate relief from the March 2006 approval of the settlement agreement in our base rate case. The rate increase was partially offset by the effect of:
 
·
a 23% decrease in cooling degree days as a result of mild weather on residential and commercial sales,
 
·
a decrease in financial transmission rights revenue, net of congestion, primarily due to fewer transmission constraints in the PJM market and
 
·
increased capacity charges due to changes in the relative peak demands and generating capacity of the AEP Power Pool members.
·
Off-system Sales increased $8 million due to $4 million increase in physical sales margins and a $4 million increase from lower sharing of off-system sales margins under the SIA. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
·
Transmission Revenues decreased $3 million primarily due to the elimination of SECA revenues as of April 1, 2006. At this time, we have a pending proposal with the FERC to replace SECA revenues. 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 $3 million primarily due to maintenance of overhead lines.
 
Income Taxes

The increase in Income Tax Expense of $2 million is primarily due to an increase in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to
Nine Months Ended September 30, 2006 Net Income
(in millions)

Nine Months Ended September 30, 2005
       
$
20
 
               
Changes in Gross Margin:
             
Retail Margins
   
8
       
Off-system Sales
   
9
       
Transmission Revenues
   
(6
)
     
Other
   
3
       
Total Change in Gross Margin
         
14
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(4
)
     
Depreciation and Amortization
   
(1
)
     
Total Change in Operating Expenses and Other
         
(5
)
               
Income Tax Expense
         
(4
)
               
Nine Months Ended September 30, 2006
       
$
25
 
               

Net Income increased $5 million to $25 million in 2006. The key driver of the increase was a $14 million increase in Gross Margin, partially offset by a $5 million increase in Operating Expenses and Other.

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 $8 million primarily due to rate relief from the March 2006 approval of the settlement agreement in our base rate case as well as favorable financial transmission rights revenue, net of congestion. The above was partially offset by increased capacity charges due to changes in the relative peak demands and generating capacity of the AEP Power Pool members.
·
Off-system Sales increased $9 million primarily due to $10 million increase in physical sales margins and a $5 million increase from lower sharing of off-system sales margins under the SIA offset by a $5 million decrease in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
·
Transmission Revenues decreased $6 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $1 million recorded in 2006 related to potential SECA refunds pending settlement negotiations with various intervenors. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 3.
·
Other revenues increased $3 million primarily due to a $3 million unfavorable adjustment of the Demand Side Management Program regulatory asset in March 2005.

Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expenses increased $4 million primarily due to maintenance of overhead lines.

Income Taxes

The increase in Income Tax Expense of $4 million is primarily due to an increase in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis.

Financial Condition

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

Financing Activities

Long-term debt issuances and retirements during the first nine months of 2006 were:

Issuances

None

Retirements

   
Principal
 
Interest
 
Due
Type of Debt
 
Amount
 
Rate
 
Date
   
(in thousands)
 
(%)
   
               
Notes Payable-Affiliated
 
$
40,000
 
6.501
 
2006

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 2005 Annual Report and has not changed significantly from year-end.

Significant Factors

Big Sandy Plant Scrubber

Completion of construction of a scrubber at our Big Sandy Plant was previously scheduled for 2010. We suspended the project in the second quarter of 2006 after a generation engineering evaluation determined that there was a substantially higher estimated capital cost due to increases in labor and material costs, refinements of preliminary costs estimates and an increase in cost per ton of removed SO2. We currently estimate the project to have an in-service date of 2020.  Management continues to review its emission compliance plans given changing market conditions and the evolving legistative and regulatory environment. 

We transferred the total project expenditures of $16 million during the second quarter of 2006 from Construction Work in Progress to Deferred Charges and Other on our Condensed Balance Sheet. If management does not resume the project, the balance of incurred expenditures would negatively impact future earnings unless a regulatory asset could be established due to probable recovery through rates.
 
Our 2006 estimated construction expenditures of $100 million, as reported in Note 7 - Commitments and Contingencies in our 2005 Annual Report, has been revised to $54 million due to the delay of the project.

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 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters and Note 5 - Commitments 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 2005 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.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. 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 balance sheet as of September 30, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to
Condensed Balance Sheet
As of September 30, 2006
(in thousands)

   
MTM Risk Management Contracts
 
Cash Flow &
Fair Value Hedges
 
DETM Assignment (a)
 
Total
 
Current Assets
 
$
19,926
 
$
1,916
 
$
-
 
$
21,842
 
Noncurrent Assets
   
25,640
   
122
   
-
   
25,762
 
Total MTM Derivative Contract Assets
   
45,566
   
2,038
   
-
   
47,604
 
                           
Current Liabilities
   
(14,945
)
 
(1,156
)
 
(451
)
 
(16,552
)
Noncurrent Liabilities
   
(16,550
)
 
(2
)
 
(2,192
)
 
(18,744
)
Total MTM Derivative Contract Liabilities
   
(31,495
)
 
(1,158
)
 
(2,643
)
 
(35,296
)
                           
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
14,071
 
$
880
 
$
(2,643
)
$
12,308
 

(a)
See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.

 
MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2006
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005
 
$
13,518
 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
   
32
 
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
   
(70
)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts
   
-
 
Changes in Fair Value Due to Market Fluctuations During the Period (b)
   
(462
)
Changes Due to SIA (c)
   
(1,565
)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)
   
2,618
 
Total MTM Risk Management Contract Net Assets
   
14,071
 
Net Cash Flow & Fair Value Hedge Contracts
   
880
 
DETM Assignment (e)
   
(2,643
)
Total MTM Risk Management Contract Net Assets at September 30, 2006
 
$
12,308
 

(a)
Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)
Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)
See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
(d)
“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(e)
See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 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 giving an indication of when these MTM amounts will settle and generate cash.


Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2006
(in thousands)

   
Remainder
2006
 
2007
 
2008
 
2009
 
2010
 
After
2010
 
Total
 
Prices Actively Quoted - Exchange Traded Contracts
 
$
430
 
$
3,090
 
$
1,118
 
$
-
 
$
-
 
$
-
 
$
4,638
 
Prices Provided by Other External Sources - OTC Broker Quotes (a)
   
905
   
2,379
   
1,164
   
1,752
   
-
   
-
   
6,200
 
Prices Based on Models and Other Valuation Methods (b)
   
1
   
(885
)
 
372
   
1,114
   
1,998
   
633
   
3,233
 
Total
 
$
1,336
 
$
4,584
 
$
2,654
 
$
2,866
 
$
1,998
 
$
633
 
$
14,071
 

(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.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed 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 employ various commodity instruments to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

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

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Balance Sheets and the reasons for the changes from December 31, 2005 to September 30, 2006. 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
Nine Months Ended September 30, 2006
(in thousands)

   
Power
 
Interest Rate
 
Total
 
Beginning Balance in AOCI December 31, 2005
 
$
(352
)
$
158
 
$
(194
)
Changes in Fair Value
   
1,072
   
-
   
1,072
 
Impact Due to Changes in SIA (a)
   
(106
)
 
-
   
(106
)
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled
   
543
   
(66
)
 
477
 
Ending Balance in AOCI September 30, 2006
 
$
1,157
 
$
92
 
$
1,249
 

(a)
See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $1,164 thousand gain.

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 September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

Nine Months Ended
September 30, 2006
       
Twelve Months Ended
December 31, 2005
(in thousands)
       
(in thousands)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
$157
 
$459
 
$164
 
$87
       
$174
 
$289
 
$138
 
$50

The High VaR for the nine months ended September 30, 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 $11 million and $13 million at September 30, 2006 and December 31, 2005, 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 and Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
Three Months Ended
 
Nine Months Ended
 
   
2006
 
2005
 
2006
 
2005
 
REVENUES
                   
Electric Generation, Transmission and Distribution
 
$
138,554
 
$
120,321
 
$
397,248
 
$
337,912
 
Sales to AEP Affiliates
   
13,466
   
23,341
   
41,543
   
55,598
 
Other
   
299
   
334
   
678
   
1,255
 
TOTAL
   
152,319
   
143,996
   
439,469
   
394,765
 
                           
EXPENSES
                         
Fuel and Other Consumables for Electric Generation
   
39,580
   
43,603
   
115,336
   
104,271
 
Purchased Electricity for Resale
   
3,974
   
1,563
   
6,938
   
5,473
 
Purchased Electricity from AEP Affiliates
   
48,755
   
45,300
   
149,204
   
131,049
 
Other Operation
   
15,176
   
14,352
   
42,662
   
42,549
 
Maintenance
   
9,607
   
7,180
   
26,041
   
21,578
 
Depreciation and Amortization
   
11,574
   
11,318
   
34,603
   
33,695
 
Taxes Other Than Income Taxes
   
1,807
   
2,457
   
6,761
   
7,101
 
TOTAL
   
130,473
   
125,773
   
381,545
   
345,716
 
                           
OPERATING INCOME
   
21,846
   
18,223
   
57,924
   
49,049
 
                           
Other Income (Expense):
                         
Interest Income
   
159
   
189
   
518
   
456
 
Allowance for Equity Funds Used During Construction
   
236
   
37
   
249
   
209
 
Interest Expense
   
(6,581
)
 
(7,227
)
 
(21,317
)
 
(21,665
)
                           
INCOME BEFORE INCOME TAXES
   
15,660
   
11,222
   
37,374
   
28,049
 
                           
Income Tax Expense
   
5,791
   
3,495
   
12,624
   
7,991
 
                           
NET INCOME
 
$
9,869
 
$
7,727
 
$
24,750
 
$
20,058
 
 
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 Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
Common
Stock
 
 Paid-in
Capital
 
Retained Earnings
 
Accumulated Other
Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2004
 
$
50,450
 
$
208,750
 
$
70,555
 
$
(8,775
)
$
320,980
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $1,534
                     
(2,848
)
 
(2,848
)
NET INCOME
               
20,058
         
20,058
 
TOTAL COMPREHENSIVE INCOME
                           
17,210
 
                                 
SEPTEMBER 30, 2005
 
$
50,450
 
$
208,750
 
$
90,613
 
$
(11,623
)
$
338,190
 
                                 
DECEMBER 31, 2005
 
$
50,450
 
$
208,750
 
$
88,864
 
$
(223
)
$
347,841
 
                                 
Common Stock Dividends
               
(10,000
)
       
(10,000
)
TOTAL
                           
337,841
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Income, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $777
                     
1,443
   
1,443
 
NET INCOME
               
24,750
         
24,750
 
TOTAL COMPREHENSIVE INCOME
                           
26,193
 
                                 
SEPTEMBER 30, 2006
 
$
50,450
 
$
208,750
 
$
103,614
 
$
1,220
 
$
364,034
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



KENTUCKY POWER COMPANY
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2006 and December 31, 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
479
 
$
526
 
Accounts Receivable:
             
Customers
   
23,776
   
26,533
 
Affiliated Companies
   
14,337
   
23,525
 
Accrued Unbilled Revenues
   
1,004
   
6,311
 
Miscellaneous
   
554
   
35
 
Allowance for Uncollectible Accounts
   
(253
)
 
(147
)
  Total Accounts Receivable
   
39,418
   
56,257
 
Fuel
   
10,780
   
8,490
 
Materials and Supplies
   
8,854
   
10,181
 
Risk Management Assets
   
21,842
   
31,437
 
Accrued Tax Benefits
   
2,535
   
6,598
 
Margin Deposits
   
453
   
6,895
 
Prepayments and Other
   
1,955
   
6,324
 
TOTAL
   
86,316
   
126,708
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
477,777
   
472,575
 
Transmission
   
391,671
   
386,945
 
Distribution
   
470,606
   
456,063
 
Other
   
60,607
   
63,382
 
Construction Work in Progress
   
30,436
   
35,461
 
Total
   
1,431,097
   
1,414,426
 
Accumulated Depreciation and Amortization
   
438,023
   
425,817
 
TOTAL - NET
   
993,074
   
988,609
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
111,089
   
117,432
 
Long-term Risk Management Assets
   
25,762
   
41,810
 
Deferred Charges and Other
   
54,607
   
45,467
 
TOTAL
   
191,458
   
204,709
 
               
TOTAL ASSETS
 
$
1,270,848
 
$
1,320,026
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



KENTUCKY POWER COMPANY
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY
September 30, 2006 and December 31, 2005
(Unaudited)

   
2006
 
2005
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
 
$
24,507
 
$
6,040
 
Accounts Payable:
             
General
   
31,118
   
32,454
 
Affiliated Companies
   
18,045
   
29,326
 
Long-term Debt Due Within One Year - Nonaffiliated
   
124,123
   
-
 
Long-term Debt Due Within One Year - Affiliated
   
-
   
39,771
 
Risk Management Liabilities
   
16,552
   
28,770
 
Customer Deposits
   
15,849
   
21,643
 
Accrued Taxes
   
9,322
   
8,805
 
Accrued Interest
   
9,897
   
7,428
 
Other
   
15,967
   
14,096
 
TOTAL
   
265,380
   
188,333
 
               
NONCURRENT LIABILITIES
             
Long-term Debt - Nonaffiliated
   
302,861
   
427,219
 
Long-term Debt - Affiliated
   
20,000
   
20,000
 
Long-term Risk Management Liabilities
   
18,744
   
35,302
 
Deferred Income Taxes
   
240,423
   
234,719
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
50,500
   
56,794
 
Deferred Credits and Other
   
8,906
   
9,818
 
TOTAL
   
641,434
   
783,852
 
               
TOTAL LIABILITIES
   
906,814
   
972,185
 
               
Commitments and Contingencies (Note 5)
             
               
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
   
103,614
   
88,864
 
Accumulated Other Comprehensive Income (Loss)
   
1,220
   
(223
)
TOTAL
   
364,034
   
347,841
 
               
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY
 
$
1,270,848
 
$
1,320,026
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



KENTUCKY POWER COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
OPERATING ACTIVITIES
           
Net Income
 
$
24,750
 
$
20,058
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
34,603
   
33,695
 
Deferred Income Taxes
   
2,742
   
1,836
 
Mark-to-Market of Risk Management Contracts
   
(842
)
 
(5,204
)
Pension Contributions to Qualified Plan Trusts
   
-
   
(9,137
)
Over/Under Fuel Recovery
   
3,608
   
(4,453
)
Change in Other Noncurrent Assets
   
5,666
   
(4
)
Change in Other Noncurrent Liabilities
   
2,629
   
10,333
 
Changes in Components of Working Capital:
             
Accounts Receivable, Net
   
16,839
   
(2,592
)
Fuel, Materials and Supplies
   
(963
)
 
(4,200
)
Accounts Payable
   
(8,149
)
 
12,876
 
Customer Deposits
   
(5,794
)
 
12,776
 
Accrued Taxes, Net
   
4,580
   
(553
)
Other Current Assets
   
7,726
   
(14,231
)
Other Current Liabilities
   
3,819
   
2,297
 
Net Cash Flows From Operating Activities
   
91,214
   
53,497
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(59,264
)
 
(38,837
)
Change in Advances to Affiliates, Net
   
-
   
6,486
 
Other
   
465
   
191
 
Net Cash Flows Used For Investing Activities
   
(58,799
)
 
(32,160
)
               
FINANCING ACTIVITIES
             
Change in Advances from Affiliates, Net
   
18,467
   
-
 
Retirement of Long-term Debt - Affiliated
   
(40,000
)
 
(20,000
)
Principal Payments for Capital Lease Obligations
   
(929
)
 
(1,122
)
Dividends Paid on Common Stock
   
(10,000
)
 
-
 
Net Cash Flows Used For Financing Activities
   
(32,462
)
 
(21,122
)
               
Net Increase (Decrease) in Cash and Cash Equivalents
   
(47
)
 
215
 
Cash and Cash Equivalents at Beginning of Period
   
526
   
132
 
Cash and Cash Equivalents at End of Period
 
$
479
 
$
347
 
               
SUPPLEMENTARY INFORMATION
             
Cash Paid for Interest, Net of Capitalized Amounts
 
$
18,242
 
$
17,250
 
Net Cash Paid for Income Taxes
   
4,573
   
7,466
 
Noncash Acquisitions Under Capital Leases
   
551
   
273
 
Construction Expenditures Included in Accounts Payable at September 30,
   
2,085
   
1,386
 

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 and Contingencies
Note 5
Guarantees
Note 6
Company-wide Staffing and Budget Review
Note 7
Benefit Plans
Note 9
Business Segments
Note 11
Financing Activities
Note 12











 
 

 



OHIO POWER COMPANY CONSOLIDATED
 
 
 
 
 
 
 
 

 



OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS


Results of Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income
(in millions)

Third Quarter of 2005
       
$
56
 
               
Changes in Gross Margin:
             
Retail Margins
   
47
       
Off-system Sales
   
23
       
Transmission Revenues
   
(9
)
     
Other
   
(7
)
     
Total Change in Gross Margin
         
54
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(5
)
     
Depreciation and Amortization
   
(9
)
     
Taxes Other Than Income Taxes
   
6
       
Other Income
   
(1
)
     
Carrying Costs Income
   
(6
)
     
Interest Expense
   
4
       
Total Change in Operating Expenses and Other
         
(11
)
               
Income Tax Expense
         
(16
)
               
Third Quarter of 2006
       
$
83
 

Net Income increased $27 million to $83 million in 2006. The key driver of the increase was a $54 million increase in Gross Margin offset by a $16 million increase in Income Tax Expense and an $11 million increase in Operating Expenses and Other.

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

·
Retail Margins were $47 million higher than the prior period primarily due to the Rate Stabilization Plan (RSP) rate increase effective January 1, 2006, favorable capacity settlements, and lower consumable expenses. These increases were partially offset by lower residential revenue due to mild weather and lower industrial revenue due to the transfer of a significant customer to an affiliate.
·
Off-system Sales increased $23 million primarily due to $19 million increase in physical sales margins and a $14 million increase from lower sharing of off-system sales margins under the SIA offset by a $10 million decrease in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
·
Transmission Revenues decreased $9 million primarily due to the elimination of SECA revenues as of April 1, 2006. At this time, we have a pending proposal with the FERC to replace SECA revenues.  See the “Transmission Rate Proceedings at the FERC” section of Note 3.
·
Other revenue decreased $7 million primarily due to the expiration of a contract to sell supplemental demand to Buckeye Power and a decrease in rental revenue.
 
Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expense increased $5 million partially due to an increase in maintenance from planned and forced outages at the Muskingum and Sporn plants related to major turbine overhaul and boiler tube inspections and repairs. The increase was partially offset by the recognition of a regulatory asset related to recent PUCO orders regarding distribution service reliability and restoration costs.
·
Depreciation and Amortization increased $9 million due to increased amortization of regulatory assets and a greater depreciable base in electric utility plant.
·
Taxes Other Than Income Taxes decreased $6 million primarily due an adjustment in 2005 to true-up 2004 and 2005 property taxes.
·
Carrying Costs Income decreased $6 million primarily due to the completion of deferrals of the environmental carrying costs from 2004 and 2005 that are now being recovered during 2006 through 2008 according to the RSP.

Income Taxes

The increase in Income Tax Expense of $16 million is primarily due to an increase in pretax book income.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to
Nine Months Ended September 30, 2006 Net Income
(in millions)

Nine Months Ended September 30, 2005
       
$
227
 
               
Changes in Gross Margin:
             
Retail Margins
   
42
       
Off-system Sales
   
29
       
Transmission Revenues
   
(19
)
     
Other
   
4
       
Total Change in Gross Margin
         
56
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(65
)
     
Depreciation and Amortization
   
(12
)
     
Taxes Other than Income Taxes
   
1
       
Carrying Costs Income
   
(28
)
     
Interest Expense
   
8
       
Total Change in Operating Expenses and Other
         
(96
)
               
Income Tax Expense
         
15
 
               
Nine Months Ended September 30, 2006
       
$
202
 

Net Income decreased $25 million to $202 million in 2006. The key driver of the decrease was a $96 million increase of Operating Expenses and Other offset by a $56 million increase in Gross Margin and a $15 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 emission allowances, and purchased power, were as follows:

·
Retail Margins increased $42 million primarily due to the RSP rate increase effective January 1, 2006, favorable capacity settlements, and lower consumable expenses. The increase is partially offset by lower fuel margins, a decrease in residential revenue due to mild weather and lower industrial revenue due to the transfer of a significant customer to an affiliate.
·
Off-System Sales increased $29 million primarily due to $48 million increase in physical sales margins and a $17 million increase from lower sharing of off-system sales margins under the SIA offset by a $35 million decrease in margins related to optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
·
Transmission Revenues decreased $19 million primarily due to the elimination of SECA revenues as of April 1, 2006 and a provision of $4 million recorded in 2006 related to potential SECA refunds pending settlement negotiations with various intervenors. At this time, we have a pending proposal with the FERC to replace SECA revenues. See the “Transmission Rate Proceedings at the FERC” section of Note 3.
·
Other revenue increased $4 million partially due to an increase in gains on sales of emission allowances.

Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expense increased $65 million primarily due to an increase in maintenance from planned and forced outages at the Gavin, Muskingum River, Kammer, and Sporn plants related to major boiler and turbine overhauls and boiler tube inspections and related removal costs and PJM administrative fees. The increase was partially offset by the recognition of a regulatory asset related to recent PUCO orders regarding distribution service reliabiltiy and restoration costs and major ice storm expenses in the prior year. 
·
Depreciation and Amortization increased $12 million primarily due to increased amortization of regulatory assets and a greater depreciable base in electric utility plant.
·
Carrying Costs Income decreased $28 million primarily due to the completion of deferrals of the environmental carrying costs from 2004 and 2005 that are now being recovered during 2006 through 2008 according to the RSP.
·
Interest Expense decreased $8 million primarily due to an increase in allowance for borrowed funds used during construction partially offset by interest on long-term debt issuances subsequent to September 2005.

Income Taxes

The decrease in Income Tax Expense of $15 million is primarily due to a decrease in pretax book income and state income taxes, offset in part by changes in certain book/tax differences accounted for on a flow-through basis.

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 nine months ended September 30, 2006 and 2005 were as follows:

   
2006
 
2005
 
   
(in thousands)
 
Cash and Cash Equivalents at Beginning of Period
 
$
1,240
 
$
9,337
 
Net Cash Flows From (Used For):
             
Operating Activities
   
476,382
   
319,579
 
Investing Activities
   
(709,752
)
 
(325,415
)
Financing Activities
   
233,455
   
(2,121
)
Net Increase (Decrease) in Cash and Cash Equivalents
   
85
   
(7,957
)
Cash and Cash Equivalents at End of Period
 
$
1,325
 
$
1,380
 

Operating Activities

Net Cash Flows From Operating Activities were $476 million in 2006. We produced Net Income of $202 million during the period and a noncash expense item of $239 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 primarily relates to two items, Accounts Receivable, Net and Accounts Payable. Accounts Receivable, Net decreased $78 million due to the collection of receivables related to power sales to affiliates. Accounts Payable decreased $45 million primarily due to timing differences for payments to affiliates related to emission allowances and the AEP Power Pool.

Net Cash Flows From Operating Activities were $320 million in 2005. We produced Net Income of $227 million during the period and a noncash expense item of $228 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 primarily relates two items, Accrued Taxes and Accounts Payable. Accrued Taxes decreased $115 million due primarily to the payment of 2004 federal income tax liability during 2005 and personal property tax. Accounts Payable increased $58 million, due to higher fuel and allowance acquisition costs not paid at September 30, 2005.

Investing Activities

Net Cash Flows Used For Investing Activities during 2006 and 2005 primarily reflect our Construction Expenditures of $715 million and $460 million, respectively. Construction expenditures are primarily for environmental upgrades, as well as projects to improve service reliability for transmission and distribution for both periods. In 2005, Construction Expenditures of $460 million were partially offset by an increase in Advances to Affiliates, Net. For the remainder of 2006, we expect our Construction Expenditures to be approximately $350 million.

Financing Activities

Net Cash Flows From Financing Activities were $233 million for 2006. We issued $350 million of Senior Unsecured Notes and $65 million of Pollution Control Bonds. We retired Notes Payable-Affiliated of $200 million. We received a capital contribution from our Parent of $70 million.
 
Net Cash Flows Used For Financing Activities were $2 million for 2005. We issued Pollution Control Bonds of $353 million. We retired Pollution Control Bonds of $353 million.
 
Financing Activity

Long-term debt issuances and retirements during the first nine months of 2006 were:

Issuances

     
Principal
 
Interest
 
Due
Type of Debt
   
Amount
 
Rate
 
Date
     
(in thousands)
 
(%)
   
Pollution Control Bonds
 
$
65,000
 
Variable
 
2036
Senior Unsecured Notes
   
350,000
 
6.00
 
2016

Retirements and Principal Payments

     
Principal
 
Interest
 
Due
Type of Debt
   
Amount
 
Rate
 
Date
     
(in thousands)
 
(%)
   
Notes Payable - Nonaffiliated
 
$
4,390
 
6.81
 
2008
Notes Payable - Nonaffiliated
   
6,500
 
6.27
 
2009
Notes Payable - Affiliated
   
200,000
 
3.32
 
2006

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 2005 Annual Report and has not changed significantly from year-end, other than the debt issuances, retirements and principal payments discussed 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, Note 6 - Customer Choice and Industry Restructuring and Note 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters, Note 4 - Customer Choice and Industry Restructuring and Note 5 - Commitments 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.

Muskingum River Project Deferral

Completion of construction of the Muskingum River Unit 5 flue gas desulphurization (FGD) project was previously scheduled for 2008. We suspended the project in the third quarter of 2006 following a review of a new SO2 and mercury compliance plan evaluation, updated coal market information reflecting the contraction of the low sulfur versus high sulfur price differentials and the latest project costs. We currently estimate the project to have an in-service date of 2015.  Management continues to review its emission compliance plans given changing market conditions and the evolving legislative and regulatory environment. 

We transferred the total project expenditures of $35 million from Construction Work in Progress to Deferred Charges and Other on our Condensed Consolidated Balance Sheet. If management does not resume the project, the balance of incurred expenditures would negatively impact future earnings unless a regulatory asset could be established due to probable recovery through rates.

Critical Accounting Estimates

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



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. 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 September 30, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of September 30, 2006
(in thousands)

   
MTM Risk Management Contracts
 
Cash Flow Hedges
 
DETM Assignment (a)
 
Total
 
Current Assets
 
$
66,808
 
$
5,639
 
$
-
 
$
72,447
 
Noncurrent Assets
   
82,034
   
386
   
-
   
82,420
 
Total MTM Derivative Contract Assets
   
148,842
   
6,025
   
-
   
154,867
 
                           
Current Liabilities
   
(55,074
)
 
(881
)
 
(1,425
)
 
(57,380
)
Noncurrent Liabilities
   
(55,004
)
 
(9
)
 
(6,923
)
 
(61,936
)
Total MTM Derivative Contract Liabilities
   
(110,078
)
 
(890
)
 
(8,348
)
 
(119,316
)
                           
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
38,764
 
$
5,135
 
$
(8,348
)
$
35,551
 

(a)
See “Natural Gas Contracts with DETM” section of Note 17 in the 2005 Annual Report.

 
MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2006
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005
 
$
40,894
 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
   
(2,331
)
Fair Value of New Contracts at Inception When Entered During the Period (a)
   
173
 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period
   
(427
)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts
   
451
 
Changes in Fair Value Due to Market Fluctuations During the Period (b)
   
4,664
 
Changes Due to SIA (c)
   
(4,984
)
Changes in Fair Value Allocated to Regulated Jurisdictions (d)
   
324
 
Total MTM Risk Management Contract Net Assets
   
38,764
 
Net Cash Flow Hedge Contracts
   
5,135
 
DETM Assignment (e)
   
(8,348
)
Total MTM Risk Management Contract Net Assets at September 30, 2006
 
$
35,551
 

(a)
Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)
Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)
See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
(d)
“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.
(e)
See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 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 giving an indication of when these MTM amounts will settle and generate cash.

 
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2006
(in thousands)

   
Remainder
2006
 
2007
 
2008
 
2009
 
2010
 
After
2010
 
Total
 
Prices Actively Quoted - Exchange Traded Contracts
 
$
1,359
 
$
9,761
 
$
3,533
 
$
-
 
$
-
 
$
-
 
$
14,653
 
Prices Provided by Other External Sources - OTC Broker Quotes (a)
   
1,850
   
6,345
   
3,856
   
5,534
   
-
   
-
   
17,585
 
Prices Based on Models and Other Valuation Methods (b)
   
(38
)
 
(5,390
)
 
119
   
3,521
   
6,314
   
2,000
   
6,526
 
Total
 
$
3,171
 
$
10,716
 
$
7,508
 
$
9,055
 
$
6,314
 
$
2,000
 
$
38,764
 

(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.

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 employ various commodity instruments to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

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

We employ forward contracts as cash flow hedges to lock-in prices on certain transactions which have been 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, 2005 to September 30, 2006. 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
Nine Months Ended September 30, 2006
(in thousands)
   
Power
 
Foreign
Currency
 
Interest Rate
 
Total
 
Beginning Balance in AOCI December 31, 2005
 
$
(392
)
$
(344
)
$
1,491
 
$
755
 
Changes in Fair Value
   
3,413
   
-
   
2,761
   
6,174
 
Impact due to Change in SIA (a)
   
(337
)
 
-
   
-
   
(337
)
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled
   
950
   
10
   
(497
)
 
463
 
Ending Balance in AOCI September 30, 2006
 
$
3,634
 
$
(334
)
$
3,755
 
$
7,055
 

(a)
See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $4,189 thousand gain.

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 September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

Nine Months Ended
September 30, 2006
       
Twelve Months Ended
December 31, 2005
(in thousands)
       
(in thousands)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
$496
 
$1,451
 
$519
 
$276
       
$583
 
$968
 
$461
 
$166

The High VaR for the nine months ended September 30, 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 $103 million and $111 million at September 30, 2006 and December 31, 2005, 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 and Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
Three Months Ended
 
Nine Months Ended
 
   
2006
 
2005
 
2006
 
2005
 
REVENUES
                   
Electric Generation, Transmission and Distribution
 
$
558,490
 
$
468,795
 
$
1,556,193
 
$
1,413,796
 
Sales to AEP Affiliates
   
198,640
   
204,063
   
502,547
   
544,016
 
Other - Affiliated
   
4,400
   
5,333
   
11,975
   
12,534
 
Other - Nonaffiliated
   
3,378
   
8,949
   
12,806
   
22,947
 
TOTAL
   
764,908
   
687,140
   
2,083,521
   
1,993,293
 
                           
EXPENSES
                         
Fuel and Other Consumables for Electric Generation
   
280,593
   
272,468
   
727,261
   
721,559
 
Purchased Electricity for Resale
   
28,324
   
12,345
   
76,351
   
53,530
 
Purchased Electricity from AEP Affiliates
   
35,423
   
36,012
   
92,086
   
86,723
 
Other Operation
   
100,274
   
93,067
   
286,107
   
238,916
 
Maintenance
   
44,503
   
46,481
   
163,443
   
145,435
 
Depreciation and Amortization
   
82,746
   
73,799
   
239,407
   
227,687
 
Taxes Other Than Income Taxes
   
47,945
   
53,531
   
143,634
   
144,671
 
TOTAL
   
619,808
   
587,703
   
1,728,289
   
1,618,521
 
                           
OPERATING INCOME
   
145,100
   
99,437
   
355,232
   
374,772
 
                           
Other Income (Expense):
                         
Interest Income
   
840
   
930
   
2,072
   
2,402
 
Carrying Costs Income
   
3,502
   
8,882
   
10,336
   
38,431
 
Allowance for Equity Funds Used During Construction
   
755
   
1,952
   
1,891
   
2,684
 
Interest Expense
   
(24,610
)
 
(28,416
)
 
(72,461
)
 
(80,418
)
                           
INCOME BEFORE INCOME TAXES
   
125,587
   
82,785
   
297,070
   
337,871
 
                           
Income Tax Expense
   
42,245
   
26,377
   
95,297
   
110,499
 
                           
NET INCOME
   
83,342
   
56,408
   
201,773
   
227,372
 
                           
Preferred Stock Dividend Requirements including Capital Stock
  Expense and Other Expense
   
183
   
183
   
549
   
723
 
                           
EARNINGS APPLICABLE TO COMMON STOCK
 
$
83,159
 
$
56,225
 
$
201,224
 
$
226,649
 

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 Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2004
 
$
321,201
 
$
462,485
 
$
764,416
 
$
(74,264
)
$
1,473,838
 
                                 
Common Stock Dividends
               
(22,499
)
       
(22,499
)
Preferred Stock Dividends
               
(549
)
       
(549
)
Other
         
4,151
   
(174
)
       
3,977
 
TOTAL
                           
1,454,767
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $4,739
                     
(8,802
)
 
(8,802
)
NET INCOME
               
227,372
         
227,372
 
TOTAL COMPREHENSIVE INCOME
                           
218,570
 
                                 
SEPTEMBER 30, 2005
 
$
321,201
 
$
466,636
 
$
968,566
 
$
(83,066
)
$
1,673,337
 
                                 
DECEMBER 31, 2005
 
$
321,201
 
$
466,637
 
$
979,354
 
$
755
 
$
1,767,947
 
                                 
Capital Contribution From Parent
         
70,000
               
70,000
 
Preferred Stock Dividends
               
(549
)
       
(549
)
Gain on Reacquired Preferred Stock
         
2
               
2
 
TOTAL
                           
1,837,400
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Income, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $3,393
                     
6,300
   
6,300
 
NET INCOME
               
201,773
         
201,773
 
TOTAL COMPREHENSIVE INCOME
                           
208,073
 
                                 
SEPTEMBER 30, 2006
 
$
321,201
 
$
536,639
 
$
1,180,578
 
$
7,055
 
$
2,045,473
 

   See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2006 and December 31, 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
1,325
 
$
1,240
 
Accounts Receivable:
             
Customers
   
107,329
   
125,404
 
Affiliated Companies
   
122,993
   
167,579
 
Accrued Unbilled Revenues
   
13,771
   
14,817
 
Miscellaneous
   
2,313
   
15,644
 
Allowance for Uncollectible Accounts
   
(2,786
)
 
(1,517
)
  Total Accounts Receivable
   
243,620
   
321,927
 
Fuel
   
115,992
   
97,600
 
Materials and Supplies
   
67,920
   
60,937
 
Emission Allowances
   
12,738
   
39,251
 
Risk Management Assets
   
72,447
   
115,020
 
Accrued Tax Benefits
   
1,463
   
39,965
 
Prepayments and Other
   
19,271
   
27,439
 
TOTAL
   
534,776
   
703,379
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
4,388,325
   
4,278,553
 
Transmission
   
1,016,000
   
1,002,255
 
Distribution
   
1,308,532
   
1,258,518
 
Other
   
296,005
   
293,794
 
Construction Work in Progress
   
1,121,259
   
690,168
 
Total
   
8,130,121
   
7,523,288
 
Accumulated Depreciation and Amortization
   
2,805,417
   
2,738,899
 
TOTAL - NET
   
5,324,704
   
4,784,389
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
347,457
   
398,007
 
Long-term Risk Management Assets
   
82,420
   
144,015
 
Deferred Charges and Other
   
276,752
   
300,880
 
TOTAL
   
706,629
   
842,902
 
               
TOTAL ASSETS
 
$
6,566,109
 
$
6,330,670
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2006 and December 31, 2005
(Unaudited)

   
2006
 
2005
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
 
$
48,163
 
$
70,071
 
Accounts Payable:
             
General
   
250,280
   
210,752
 
Affiliated Companies
   
105,916
   
147,470
 
Short-term Debt - Nonaffiliated
   
7,103
   
10,366
 
Long-term Debt Due Within One Year - Nonaffiliated
   
12,354
   
12,354
 
Long-term Debt Due Within One Year - Affiliated
   
-
   
200,000
 
Risk Management Liabilities
   
57,380
   
108,797
 
Customer Deposits
   
28,811
   
51,209
 
Accrued Taxes
   
92,539
   
158,774
 
Other
   
138,777
   
147,778
 
TOTAL
   
741,323
   
1,117,571
 
               
NONCURRENT LIABILITIES
             
Long-term Debt - Nonaffiliated
   
2,186,023
   
1,787,316
 
Long-term Debt - Affiliated
   
200,000
   
200,000
 
Long-term Risk Management Liabilities
   
61,936
   
119,247
 
Deferred Income Taxes
   
972,867
   
987,386
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
182,647
   
168,492
 
Deferred Credits and Other
   
142,616
   
154,770
 
TOTAL
   
3,746,089
   
3,417,211
 
               
TOTAL LIABILITIES
   
4,487,412
   
4,534,782
 
               
Minority Interest
   
16,593
   
11,302
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
16,631
   
16,639
 
               
Commitments and Contingencies (Note 5)
             
               
COMMON SHAREHOLDER’S EQUITY
             
Common Stock - No Par Value Per Share:
             
Authorized - 40,000,000 Shares
             
Outstanding - 27,952,473 Shares
   
321,201
   
321,201
 
Paid-in Capital
   
536,639
   
466,637
 
Retained Earnings
   
1,180,578
   
979,354
 
Accumulated Other Comprehensive Income
   
7,055
   
755
 
TOTAL
   
2,045,473
   
1,767,947
 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 
$
6,566,109
 
$
6,330,670
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
OPERATING ACTIVITIES
           
Net Income
 
$
201,773
 
$
227,372
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
239,407
   
227,687
 
Deferred Income Taxes
   
(18,399
)
 
11,492
 
Carrying Costs Income
   
(10,336
)
 
(38,431
)
Mark-to-Market of Risk Management Contracts
   
668
   
(10,841
)
Pension Contributions to Qualified Plan Trusts
   
-
   
(60,020
)
Deferred Property Taxes
   
54,073
   
47,803
 
Change in Other Noncurrent Assets
   
7,958
   
(12,979
)
Change in Other Noncurrent Liabilities
   
15,923
   
6,746
 
Changes in Components of Working Capital:
             
Accounts Receivable, Net
   
78,307
   
(54,418
)
Fuel, Materials and Supplies
   
(25,375
)
 
(25,840
)
Accounts Payable
   
(44,817
)
 
57,644
 
Accrued Taxes, Net
   
(27,733
)
 
(114,998
)
Other Current Assets
   
36,333
   
28,559
 
Other Current Liabilities
   
(31,400
)
 
29,803
 
Net Cash Flows From Operating Activities
   
476,382
   
319,579
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(715,200
)
 
(460,282
)
Change in Advances to Affiliates, Net
   
-
   
125,971
 
Other
   
5,448
   
8,896
 
Net Cash Flows Used For Investing Activities
   
(709,752
)
 
(325,415
)
               
FINANCING ACTIVITIES
             
Capital Contributions from Parent Company
   
70,000
   
-
 
Issuance of Long-term Debt - Nonaffiliated
   
405,841
   
348,237
 
Change in Short-term Debt, Net - Nonaffiliated
   
(3,264
)
 
(8,133
)
Change in Advances from Affiliates, Net
   
(21,908
)
 
55,508
 
Retirement of Long-term Debt - Nonaffiliated
   
(10,890
)
 
(363,890
)
Retirement of Long-term Debt - Affiliated
   
(200,000
)
 
-
 
Retirement of Preferred Stock
   
(7
)
 
(5,000
)
Principal Payments for Capital Lease Obligations
   
(5,768
)
 
(5,795
)
Dividends Paid on Common Stock
   
-
   
(22,499
)
Dividends Paid on Cumulative Preferred Stock
   
(549
)
 
(549
)
Net Cash Flows From (Used For) Financing Activities
   
233,455
   
(2,121
)
               
Net Increase (Decrease) in Cash and Cash Equivalents
   
85
   
(7,957
)
Cash and Cash Equivalents at Beginning of Period
   
1,240
   
9,337
 
Cash and Cash Equivalents at End of Period
 
$
1,325
 
$
1,380
 
               
SUPPLEMENTARY INFORMATION
             
Cash Paid for Interest, Net of Capitalized Amounts
 
$
71,666
 
$
92,073
 
Net Cash Paid for Income Taxes
   
72,175
   
158,627
 
Noncash Acquisitions Under Capital Leases
   
2,529
   
7,591
 
Construction Expenditures Included in Accounts Payable at September 30,
   
117,638
   
73,895
 

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 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
Customer Choice and Industry Restructuring
Note 4
Commitments and Contingencies
Note 5
Guarantees
Note 6
Company-wide Staffing and Budget Review
Note 7
Benefit Plans
Note 9
Business Segments
Note 11
Financing Activities
Note 12











 

 



PUBLIC SERVICE COMPANY OF OKLAHOMA
 
 
 
 
 
 
 
 

 








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

Allocation Agreement between AEP East companies and AEP West companies

The SIA provides, among other things, for the methodology of sharing trading and marketing margins between the AEP East companies and AEP West companies. In March 2006, the FERC approved AEP’s proposed methodology to be used effective April 1, 2006 and beyond. The approved allocation methodology is based upon the location of the specific trading and marketing activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT generally accruing to the benefit of SWEPCo and us. Previously, the SIA allocation provided for a different method of sharing all such margins between both AEP East companies and AEP West companies. The impact on future results of operations, financial condition and cash flows will depend upon the level of future margins and risk management activity by region.

Results of Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income
(in millions)

Third Quarter of 2005
       
$
49
 
               
Changes in Gross Margin:
             
Retail and Off-system Sales Margins
   
(2
)
     
Transmission Revenues
   
(3
)
     
Total Change in Gross Margin
         
(5
)
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(8
)
     
Depreciation and Amortization
   
(1
)
     
Taxes Other Than Income Taxes
   
6
       
Interest Expense
   
(2
)
     
Total Change in Operating Expenses and Other
         
(5
)
               
Income Tax Expense
         
3
 
               
Third Quarter of 2006
       
$
42
 

Net Income decreased $7 million to $42 million in 2006. The key drivers of the decrease were a $5 million decrease in Gross Margin and a $5 million increase in Operating Expenses and Other, partially offset by a $3 million decrease in Income Tax Expense.

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 and Off-system Sales Margins decreased $2 million primarily due to a $4 million decrease in retail margins resulting from lower sales to industrial customers due to the price mix and an increase in non-recoverable fuel items including an accrual for an unfavorable FERC ruling on an SPP Reactive Power dispute with Calpine, partially offset by an increase in Distribution Vegetation Management (DVM) recovery. The decrease in retail margins was partially offset by a $2 million increase in off-system sales margins, comprised of a $16 million increase in margins from optimization activities partially offset by a $14 million decrease primarily related to lower sharing of off-system sales margins under the SIA. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
·
Transmission Revenues decreased $3 million due to lower point-to-point transmission services within SPP.

Operating Expenses and Other increased between years as follows:

·
Other Operation and Maintenance expenses increased $8 million due to a $6 million increase in distribution maintenance primarily related to increased DVM expenses.
·
Taxes Other Than Income Taxes decreased $6 million due to an adjustment to the provision for state sales and use tax.

Income Taxes

The $3 million decrease in Income Tax Expense is primarily due to the decrease in pretax book income.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to
Nine Months Ended September 30, 2006 Net Income
(in millions)

Nine Months Ended September 30, 2005
       
$
68
 
               
Changes in Gross Margin:
             
Retail and Off-system Sales Margins
   
12
       
Transmission Revenues
   
(1
)
     
Other
   
3
       
Total Change in Gross Margin
         
14
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(35
)
     
Depreciation and Amortization
   
1
       
Taxes Other Than Income Taxes
   
2
       
Interest Expense
   
(5
)
     
Total Change in Operating Expenses and Other
         
(37
)
               
Income Tax Expense
         
6
 
               
Nine Months Ended September 30, 2006
       
$
51
 

Net Income decreased $17 million to $51 million in 2006. The key driver of the decrease was a $37 million increase in Operating Expenses and Other, partially offset by a $14 million increase in Gross Margin and a $6 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 and Off-system Sales Margins increased $12 million primarily due to a $20 million increase in retail margins resulting from a 29% increase in cooling degree days and an increase in DVM recovery, partially offset by an increase in non-recoverable fuel items including an accrual for an unfavorable FERC ruling on an SPP Reactive Power dispute with Calpine. The increase in retail margins was partially offset by an $8 million decrease in off-system sales margins comprised of a $17 million decrease primarily related to lower sharing of off-system sales margins under the SIA, partially offset by a $9 million increase in margins from optimization activities. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
·
Other revenue increased $3 million partially due to a 2006 settlement received from an electric cooperative.

Operating Expenses and Other increased between years as follows:

·
Other Operation and Maintenance expenses increased $35 million due to a $15 million increase in distribution maintenance primarily related to increased DVM expenses, a $7 million increase in forced and scheduled power plant maintenance, a $6 million increase in administration and general expenses, mostly related to increased pension and other postemployment benefits expense, a $5 million increase in expenses related to the factoring of accounts receivable and a $4 million increase in expenses related to power plant operations.
·
Interest Expense increased $5 million primarily due to increased affiliated short-term borrowings during the period and the issuance of long-term debt in 2006.

Income Taxes

The $6 million decrease in Income Tax Expense is primarily due to the decrease in pretax book income, offset in part by tax reserve adjustments.  

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
Baa1
 
BBB
 
A-

Financing Activity

Long-term debt issuances and retirements during the first nine months of 2006 were:

Issuances
   
Principal
Amount
 
Interest
 
Due
Type of Debt
   
Rate
 
Date
     
(in thousands)
 
(%)
   
               
Senior Unsecured Notes
 
$
150,000
 
6.15
 
2016

Retirements
   
Principal
Amount
 
Interest
 
Due
Type of Debt
   
Rate
 
Date
     
(in thousands)
 
(%)
   
               
Notes Payable - Affiliated
 
$
50,000
 
3.35
 
2006

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 2005 Annual Report and has not changed significantly from year-end except for Energy and Capacity Purchase Contracts. We increased our future obligation in Energy and Capacity Purchase Contracts applicable to our optimization and off-system sales activities by approximately $10 million annually due to changes within the SIA and CSW Operating Agreement. See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

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 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters and Note 5 - Commitments 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 September 2005, we sought proposals for new peaking generation to be online in 2008 and in December 2005 we sought proposals for base load generation to be online in 2011. We received proposals and evaluated those proposals meeting the Request for Proposal criteria with oversight from neutral third parties. In March 2006, we announced plans to add 170 MW of peaking generation to our Riverside Station plant in Jenks, Oklahoma where we will construct and operate two 85 MW simple-cycle natural gas combustion turbines. Also in March 2006, we announced plans to add 170 MW of peaking generation to our Southwestern Station plant in Anadarko, Oklahoma where we 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 July 2006, we announced plans to enter a joint venture with Oklahoma Gas and Electric Company (OG&E) where OG&E will construct and operate a new 950 MW coal-fueled electricity generating unit near Red Rock, Oklahoma. We will own 50% of the new unit. Preliminary cost estimates for 100% of the new facility are approximately $1.8 billion. The 2006 through 2008 estimated construction expenditures as disclosed in our 2005 Form 10-K included cost estimates for the peaking additions and the base load facility. These new facilities are subject to regulatory approval from the OCC. We expect to begin construction on all of these additions 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 2005 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension benefits and the impact of new accounting pronouncements.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. 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 balance sheet as of September 30, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.
 
Reconciliation of MTM Risk Management Contracts to
Condensed Balance Sheet
As of September 30, 2006
(in thousands)

                       
                       
   
MTM Risk Management Contracts
 
Cash Flow Hedges
 
DETM
Assignment (a)
 
Total
 
Current Assets
 
$
71,635
 
$
-
 
$
-
 
$
71,635
 
Noncurrent Assets
   
32,354
   
-
   
-
   
32,354
 
Total MTM Derivative Contract Assets
   
103,989
   
-
   
-
   
103,989
 
                           
Current Liabilities
   
(75,244
)
 
-
   
(96
)
 
(75,340
)
Noncurrent Liabilities
   
(22,869
)
 
-
   
(467
)
 
(23,336
)
Total MTM Derivative Contract Liabilities
   
(98,113
)
 
-
   
(563
)
 
(98,676
)
                           
Total MTM Derivative Contract Net Assets
 
$
5,876
 
$
-
 
$
(563
)
$
5,313
 

(a)
Starting in the third quarter of 2006, we were allocated a portion of the DETM assignment based on the FERC- approved methodology of AEP recording trading and marketing margins shared between the AEP East and AEP West companies. See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.
 
MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2006
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005
 
$
14,214
 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
   
817
 
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
   
(386
)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts
   
-
 
Changes in Fair Value Due to Market Fluctuations During the Period (b)
   
148
 
Changes Due to SIA and CSW Operating Agreement (c)
   
10,185
 
Changes in Fair Value Allocated to Regulated Jurisdictions (d)
   
(19,102
)
Total MTM Risk Management Contract Net Assets
   
5,876
 
Net Cash Flow Hedge Contracts
   
-
 
DETM Assignment (e)
   
(563
)
Total MTM Risk Management Contract Net Assets at September 30, 2006
 
$
5,313
 

(a)
Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)
Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)
See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
(d)
“Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Statements of Operations. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(e)
Starting in the third quarter of 2006, we were allocated a portion of the DETM assignment based on the FERC- approved methodology of AEP recording trading margins shared between the AEP East and AEP West companies. See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 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 giving an indication of when these MTM amounts will settle and generate cash.


Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2006
(in thousands)

   
Remainder
2006
 
2007
 
2008
 
2009
 
2010
 
After
2010
 
Total
 
Prices Actively Quoted - Exchange Traded Contracts
 
$
(3,194
)
$
(21,390
)
$
3,101
 
$
(383
)
$
-
 
$
-
 
$
(21,866
)
Prices Provided by Other External Sources - OTC Broker
  Quotes (a)
   
(6,056
)
 
27,924
   
5,533
   
(490
)
 
-
   
-
   
26,911
 
Prices Based on Models and Other Valuation Methods (b)
   
(143
)
 
(216
)
 
(131
)
 
1,313
   
42
   
(34
)
 
831
 
Total
 
$
(9,393
)
$
6,318
 
$
8,503
 
$
440
 
$
42
 
$
(34
)
$
5,876
 

(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.

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed 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 employ various commodity instruments to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

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

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Balance Sheets and the reasons for the changes from December 31, 2005 to September 30, 2006. 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
Nine Months Ended September 30, 2006
(in thousands)

   
Power
 
Interest Rate
 
Total
 
Beginning Balance in AOCI December 31, 2005
 
$
(629
)
$
(483
)
$
(1,112
)
Changes in Fair Value
   
-
   
-
   
-
 
Impact Due to Change in SIA (a)
   
506
   
-
   
506
 
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled
   
123
   
(633
)
 
(510
)
Ending Balance in AOCI September 30, 2006
 
$
-
 
$
(1,116
)
$
(1,116
)

(a)
See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $183 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 September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

Nine Months Ended
September 30, 2006
       
Twelve Months Ended
December 31, 2005
(in thousands)
       
(in thousands)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
$1,175
 
$1,786
 
$647
 
$58
       
$311
 
$517
 
$246
 
$89

The High VaR for the nine months ended September 30, 2006 occurred in the third 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 $36 million and $34 million at September 30, 2006 and December 31, 2005, 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 INCOME
For the Three and Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
Three Months Ended
 
Nine Months Ended
 
   
2006
 
2005
 
2006
 
2005
 
REVENUES
                   
Electric Generation, Transmission and Distribution
 
$
443,593
 
$
415,558
 
$
1,116,507
 
$
937,985
 
Sales to AEP Affiliates
   
14,034
   
16,032
   
40,647
   
32,314
 
Other
   
814
   
1,043
   
3,062
   
2,018
 
TOTAL
   
458,441
   
432,633
   
1,160,216
   
972,317
 
                           
EXPENSES
                         
Fuel and Other Consumables for Electric Generation
   
202,836
   
192,968
   
566,985
   
456,690
 
Purchased Electricity for Resale
   
68,547
   
39,186
   
158,122
   
84,111
 
Purchased Electricity from AEP Affiliates
   
17,706
   
26,643
   
54,817
   
64,877
 
Other Operation
   
40,756
   
40,029
   
117,721
   
107,168
 
Maintenance
   
25,072
   
17,809
   
67,412
   
43,321
 
Depreciation and Amortization
   
22,103
   
20,842
   
64,724
   
65,708
 
Taxes Other Than Income Taxes
   
3,844
   
9,769
   
23,997
   
25,507
 
TOTAL
   
380,864
   
347,246
   
1,053,778
   
847,382
 
                           
OPERATING INCOME
   
77,577
   
85,387
   
106,438
   
124,935
 
                           
Other Income (Expense):
                         
Interest Income
   
828
   
658
   
1,734
   
729
 
Allowance for Equity Funds Used During Construction
   
222
   
206
   
96
   
542
 
Interest Expense
   
(10,954
)
 
(8,677
)
 
(29,723
)
 
(25,173
)
                           
INCOME BEFORE INCOME TAXES
   
67,673
   
77,574
   
78,545
   
101,033
 
                           
Income Tax Expense
   
25,650
   
28,920
   
27,241
   
33,304
 
                           
NET INCOME
   
42,023
   
48,654
   
51,304
   
67,729
 
                           
Preferred Stock Dividend Requirements
   
53
   
53
   
159
   
159
 
                           
EARNINGS APPLICABLE TO COMMON STOCK
 
$
41,970
 
$
48,601
 
$
51,145
 
$
67,570
 

  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 Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2004
 
$
157,230
 
$
230,016
 
$
141,935
 
$
75
 
$
529,256
 
                                 
Common Stock Dividends
               
(27,000
)
       
(27,000
)
Preferred Stock Dividends
               
(159
)
       
(159
)
TOTAL
                           
502,097
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $2,581
                     
(4,794
)
 
(4,794
)
NET INCOME
               
67,729
         
67,729
 
TOTAL COMPREHENSIVE INCOME
                           
62,935
 
                                 
SEPTEMBER 30, 2005
 
$
157,230
 
$
230,016
 
$
182,505
 
$
(4,719
)
$
565,032
 
                                 
DECEMBER 31, 2005
 
$
157,230
 
$
230,016
 
$
162,615
 
$
(1,264
)
$
548,597
 
                                 
Preferred Stock Dividends
               
(159
)
       
(159
)
TOTAL
                           
548,438
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $2
                     
(4
)
 
(4
)
NET INCOME
               
51,304
         
51,304
 
TOTAL COMPREHENSIVE INCOME
                           
51,300
 
                                 
SEPTEMBER 30, 2006
 
$
157,230
 
$
230,016
 
$
213,760
 
$
(1,268
)
$
599,738
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.





PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2006 and December 31, 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
CURRENT ASSETS
      
Cash and Cash Equivalents
 
$
2,277
 
$
1,520
 
Advances to Affiliates
   
43,538
   
-
 
Accounts Receivable:
             
Customers
   
59,153
   
37,740
 
Affiliated Companies
   
54,535
   
73,321
 
Miscellaneous
   
10,105
   
10,501
 
Allowance for Uncollectible Accounts
   
(82
)
 
(240
)
  Total Accounts Receivable
   
123,711
   
121,322
 
Fuel
   
15,301
   
16,431
 
Materials and Supplies
   
46,665
   
38,545
 
Risk Management Assets
   
71,635
   
40,383
 
Accrued Tax Benefits
   
61
   
11,972
 
Regulatory Asset for Under-Recovered Fuel Costs
   
31,794
   
108,732
 
Margin Deposits
   
35,862
   
10,051
 
Prepayments and Other
   
8,058
   
4,236
 
TOTAL
   
378,902
   
353,192
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
1,083,390
   
1,072,928
 
Transmission
   
499,175
   
479,272
 
Distribution
   
1,196,071
   
1,140,535
 
Other
   
239,625
   
211,805
 
Construction Work in Progress
   
82,724
   
90,455
 
Total
   
3,100,985
   
2,994,995
 
Accumulated Depreciation and Amortization
   
1,192,825
   
1,175,858
 
TOTAL - NET
   
1,908,160
   
1,819,137
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
76,543
   
50,723
 
Long-term Risk Management Assets
   
32,354
   
33,566
 
Employee Benefits and Pension Assets
   
79,701
   
82,559
 
Deferred Charges and Other
   
22,372
   
16,287
 
TOTAL
   
210,970
   
183,135
 
               
TOTAL ASSETS
 
$
2,498,032
 
$
2,355,464
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.




PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2006 and December 31, 2005
(Unaudited)

   
2006
 
2005
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
 
$
-
 
$
75,883
 
Accounts Payable:
             
General
   
130,260
   
130,627
 
Affiliated Companies
   
89,834
   
89,786
 
Long-term Debt Due Within One Year - Affiliated
   
-
   
50,000
 
Risk Management Liabilities
   
75,340
   
38,243
 
Customer Deposits
   
51,107
   
53,844
 
Accrued Taxes
   
59,354
   
22,420
 
Other
   
37,793
   
51,548
 
TOTAL
   
443,688
   
512,351
 
               
NONCURRENT LIABILITIES
             
Long-term Debt - Nonaffiliated
   
669,953
   
521,071
 
Long-term Risk Management Liabilities
   
23,336
   
22,582
 
Deferred Income Taxes
   
418,846
   
436,382
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
309,818
   
284,640
 
Deferred Credits and Other
   
27,391
   
24,579
 
TOTAL
   
1,449,344
   
1,289,254
 
               
TOTAL LIABILITIES
   
1,893,032
   
1,801,605
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
5,262
   
5,262
 
               
Commitments and Contingencies (Note 5)
             
               
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
   
230,016
   
230,016
 
Retained Earnings
   
213,760
   
162,615
 
Accumulated Other Comprehensive Income (Loss)
   
(1,268
)
 
(1,264
)
TOTAL
   
599,738
   
548,597
 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 
$
2,498,032
 
$
2,355,464
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
OPERATING ACTIVITIES
           
Net Income
 
$
51,304
 
$
67,729
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
64,724
   
65,708
 
Deferred Income Taxes
   
(18,661
)
 
32,661
 
Mark-to-Market of Risk Management Contracts
   
8,901
   
(2,954
)
Deferred Property Taxes
   
(8,098
)
 
(8,123
)
Change in Other Noncurrent Assets
   
18,186
   
(34,576
)
Change in Other Noncurrent Liabilities
   
(24,838
)
 
26,798
 
Changes in Components of Working Capital:
             
Accounts Receivable, Net
   
(2,389
)
 
(1,687
)
Fuel, Materials and Supplies
   
(6,990
)
 
(3,873
)
Margin Deposits
   
(25,811
)
 
(16,121
)
Accounts Payable
   
1,585
   
69,794
 
Customer Deposits
   
(2,737
)
 
24,404
 
Accrued Taxes, Net
   
48,845
   
480
 
Over/Under Fuel Recovery
   
76,938
   
(81,808
)
Other Current Assets
   
(3,828
)
 
(7,253
)
Other Current Liabilities
   
(13,755
)
 
(6,099
)
Net Cash Flows From Operating Activities
   
163,376
   
125,080
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(140,998
)
 
(87,804
)
Change in Other Cash Deposits, Net
   
6
   
(6
)
Change in Advances to Affiliates, Net
   
(43,538
)
 
-
 
Net Cash Flows Used For Investing Activities
   
(184,530
)
 
(87,810
)
               
FINANCING ACTIVITIES
             
Issuance of Long-term Debt - Nonaffiliated
   
148,747
   
74,405
 
Change in Advances from Affiliates, Net
   
(75,883
)
 
(32,401
)
Retirement of Long-term Debt - Nonaffiliated
   
-
   
(50,000
)
Retirement of Long-term Debt - Affiliated
   
(50,000
)
 
-
 
Principal Payments for Capital Lease Obligations
   
(794
)
 
(483
)
Dividends Paid on Common Stock
   
-
   
(27,000
)
Dividends Paid on Cumulative Preferred Stock
   
(159
)
 
(159
)
Net Cash Flows From (Used For) Financing Activities
   
21,911
   
(35,638
)
               
Net Increase in Cash and Cash Equivalents
   
757
   
1,632
 
Cash and Cash Equivalents at Beginning of Period
   
1,520
   
279
 
Cash and Cash Equivalents at End of Period
 
$
2,277
 
$
1,911
 
               
SUPPLEMENTARY INFORMATION
             
Cash Paid for Interest, Net of Capitalized Amounts
 
$
25,491
 
$
21,954
 
Net Cash Paid for Income Taxes
   
7,471
   
14,241
 
Noncash Acquisitions Under Capital Leases
   
2,639
   
798
 
Construction Expenditures Included in Accounts Payable at September 30,
   
6,591
   
3,482
 

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 and Contingencies
Note 5
Guarantees
Note 6
Company-wide Staffing and Budget Review
Note 7
Benefit Plans
Note 9
Income Taxes
Note 10
Business Segments
Note 11
Financing Activities
Note 12











 
 

 


SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
 
 
 
 
 
 
 
 
 

 








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

Allocation Agreement between AEP East companies and AEP West companies

The SIA provides, among other things, for the methodology of sharing trading and marketing margins between the AEP East companies and AEP West companies. In March 2006, the FERC approved AEP’s proposed methodology to be used effective April 1, 2006 and beyond. The approved allocation methodology is based upon the location of the specific trading and marketing activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT generally accruing to the benefit of PSO and us. Previously, the SIA allocation provided for a different method of sharing all such margins between both AEP East companies and AEP West companies. The impact on future results of operations, financial condition and cash flows will depend upon the level of future margins and risk management activities by region and the status of cost recovery mechanisms by state.

Results of Operations

Third Quarter of 2006 Compared to Third Quarter of 2005

Reconciliation of Third Quarter of 2005 to Third Quarter of 2006 Net Income
(in millions)

Third Quarter of 2005
       
$
50
 
               
Changes in Gross Margin:
             
Retail and Off-system Sales Margins (a)
   
(9
)
     
Transmission Revenues
   
(1
)
     
Other
   
6
       
Total Change in Gross Margin
         
(4
)
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
6
       
Taxes Other Than Income Taxes
   
1
       
Interest Expense
   
(1
)
     
Total Change in Operating Expenses and Other
         
6
 
               
Income Tax Expense
         
(2
)
               
Third Quarter of 2006
       
$
50
 

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

Net Income remained flat in the third quarter of 2006 compared to the third quarter of 2005.

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 and Off-system Sales Margins decreased $9 million primarily due to a $4 million non-recoverable accrual for an unfavorable FERC ruling on an SPP Reactive Power Contract with Calpine as well as an $8 million decrease in off-system sales margins primarily due to lower sharing of off-system sales margins under the SIA. Partially offsetting these decreases was a $3 million increase in wholesale revenues due to higher usage and favorable prices. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
·
Other revenues increased $6 million primarily due to gains on sales of emission allowances.
 
Operating Expenses and Other decreased between years as follows:

·
Other Operation and Maintenance decreased $6 million primarily due to a $3 million decrease in transmission operation expense resulting from favorable changes to the SPP fee structure as well as a $3 million decrease in overhead line maintenance expense primarily related to the absence of 2005 hurricane-related expenses.

Income Taxes

The $2 million increase in Income Tax Expense is primarily due to the increase in pretax book income and state income taxes.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005

Reconciliation of Nine Months Ended September 30, 2005 to
Nine Months Ended September 30, 2006 Net Income
(in millions)

Nine Months Ended September 30, 2005
       
$
81
 
               
Changes in Gross Margin:
             
Retail and Off-system Sales Margins (a)
   
15
       
Transmission Revenues
   
1
       
Other
   
22
       
Total Change in Gross Margin
         
38
 
               
Changes in Operating Expenses and Other:
             
Other Operation and Maintenance
   
(8
)
     
Interest Expense
   
(2
)
     
Total Change in Operating Expenses and Other
         
(10
)
               
Income Tax Expense
         
(13
)
               
Nine Months Ended September 30, 2006
       
$
96
 

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

Net Income increased $15 million to $96 million in 2006. The key driver of the increase was a $38 million increase in Gross Margin, partially offset by a $10 million increase in Operating Expenses and Other and a $13 million increase 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 and Off-system Sales Margins increased $15 million primarily due to a $17 million increase in wholesale margins resulting from higher prices, increased usage and new wholesale contracts, as well as a $15 million increase primarily due to increased wholesale fuel recovery. These increases were partially offset by a $17 million decrease in off-system sales margins primarily due to lower sharing of off-system sales margins under the SIA. See the “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
·
Other revenues increased $22 million primarily due to gains on sales of emission allowances.
 
Operating Expenses and Other changed between years as follows:

·
Other Operation and Maintenance expenses increased $8 million primarily due to a $5 million increase in employee-related expenses, a $3 million increase in mining operations expense resulting from increased production and a $2 million increase in expenses related to the factoring of customer accounts receivable, offset by the absence of $4 million of 2005 hurricane-related expenses.

Income Taxes

The $13 million increase in Income Tax Expense is primarily due to the increase 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 nine months ended September 30, 2006 and 2005 were as follows:

   
2006
 
2005
 
   
(in thousands)
 
Cash and Cash Equivalents at Beginning of Period
 
$
3,049
 
$
3,715
 
Net Cash Flows From (Used For):
             
Operating Activities
   
242,721
   
163,705
 
Investing Activities
   
(186,631
)
 
(67,857
)
Financing Activities
   
(56,343
)
 
(95,759
)
Net Increase (Decrease) in Cash and Cash Equivalents
   
(253
)
 
89
 
Cash and Cash Equivalents at End of Period
 
$
2,796
 
$
3,804
 

Operating Activities

Net Cash Flows From Operating Activities were $243 million in 2006. We produced Net Income of $96 million during the period and noncash expense items of $98 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 $54 million inflow from Accounts Payable was the result of higher energy purchases. The $28 million outflow for Margin Deposits was due to increased trading-related deposits resulting from the amended SIA. In addition, our $64 million inflow related to Over/Under Fuel Recovery was primarily due to the new fuel surcharges effective December 2005 in our Arkansas service territory and in January 2006 in our Texas service territory. The $27 million outflow from Fuel, Materials and Supplies was the result of increased fuel purchases.

Net Cash Flows From Operating Activities were $164 million in 2005. We produced Net Income of $81 million during the period and noncash expense items of $99 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 $42 million inflow from Accounts Payable was due to higher vendor-related payables and increased energy transactions. The $66 million outflow related to Over/Under Fuel Recovery was due to our increasing cumulative under-recovery of rising fuel costs.

Investing Activities

Cash Flows Used For Investing Activities during 2006 and 2005 were $187 million and $68 million, respectively. The cash flows during 2006 were comprised primarily of Construction Expenditures related to projects for improved transmission and distribution service reliability as well as projects related to generation facilities. For the remainder of 2006, we expect $140 million in Construction Expenditures. During 2005, Construction Expenditures were $110 million, also comprised primarily of spending for transmission and distribution service reliability. Additionally, we decreased our Advances to Affiliates by $39 million.

Financing Activities

Cash Flows Used For Financing Activities were $56 million during 2006. We refinanced $82 million of Pollution Control Bonds. Long-term debt retirements were $89 million. In addition, we repaid $28 million to the Utility Money Pool. We also paid $30 million in Common Stock Dividends.

Cash Flows Used For Financing Activities were $96 million during 2005. We issued $150 million of Senior Unsecured Notes for the purpose of funding the July 2005 maturity of our $200 million of Senior Unsecured Notes. We paid $40 million in Common Stock Dividends.

Financing Activity

Long-term debt issuances, retirements and principal payments during the first nine months of 2006 were:

Issuances
   
Principal
Amount
 
Interest
 
Due
Type of Debt
   
Rate
 
Date
     
(in thousands)
 
(%)
   
               
Pollution Control Bonds
 
$
81,700
 
Variable
 
2018

Retirements and Principal Payments

   
Principal
Amount
 
Interest
 
Due
Type of Debt
   
Rate
 
Date
     
(in thousands)
 
(%)
   
               
Notes Payable
 
$
5,039
 
4.47
 
2011
Notes Payable
   
2,250
 
Variable
 
2008
Pollution Control Bonds
   
81,700
 
6.10
 
2018

Liquidity

We have solid investment grade ratings, which provide us ready access to capital markets in order to issue new debt and refinance short-term or 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 2005 Annual Report and has not changed significantly from year-end except for Energy and Capacity Purchase Contracts. We increased our future obligation in Energy and Capacity Purchase Contracts applicable to our optimization and off-system sales activities by approximately $10 million annually due to changes within the SIA and CSW Operating Agreement. See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

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, Note 6 - Customer Choice and Industry Restructuring and Note 7 - Commitments and Contingencies in our 2005 Annual Report. Also, see Note 3 - Rate Matters, Note 4 - Customer Choice and Industry Restructuring and Note 5 - Commitments 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 our 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 our existing Arsenal Hill Power Plant in Shreveport, Louisiana. We also plan to build a new 600 MW base load coal plant in Hempstead County, Arkansas by 2011 to meet the longer-term generation needs of our customers. Preliminary cost estimates for the new facilities are approximately $1.4 billion (this total excludes the related transmission investment). The 2006 through 2008 estimated construction expenditures as disclosed in our 2005 Form 10-K included cost estimates for these new facilities. These new facilities are subject to regulatory approvals from our three state commissions. Construction is expected to begin 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 2005 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.



QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. 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 September 30, 2006 and the reasons for changes in our total MTM value as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of September 30, 2006
(in thousands)

   
MTM Risk Management Contracts
 
Cash Flow Hedges
 
DETM
Assignment (a)
 
Total
 
Current Assets
 
$
84,685
 
$
-
 
$
-
 
$
84,685
 
Noncurrent Assets
   
38,252
   
-
   
-
   
38,252
 
Total MTM Derivative Contract Assets
   
122,937
   
-
   
-
   
122,937
 
                           
Current Liabilities
   
(89,430
)
 
(4,097
)
 
(114
)
 
(93,641
)
Noncurrent Liabilities
   
(27,326
)
 
(28
)
 
(550
)
 
(27,904
)
Total MTM Derivative Contract Liabilities
   
(116,756
)
 
(4,125
)
 
(664
)
 
(121,545
)
                           
Total MTM Derivative Contract Net Assets (Liabilities)
 
$
6,181
 
$
(4,125
)
$
(664
)
$
1,392
 

(a)
Starting in the third quarter of 2006, we were allocated a portion of the DETM assignment based on the FERC- approved methodology of AEP recording trading and marketing margins shared between the AEP East and AEP West companies. See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 Annual Report.
 
MTM Risk Management Contract Net Assets
Nine Months Ended September 30, 2006
(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2005
 
$
16,387
 
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period
   
655
 
Fair Value of New Contracts at Inception When Entered During the Period (a)
   
52
 
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period
   
(452
)
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts
   
139
 
Changes in Fair Value Due to Market Fluctuations During the Period (b)
   
(7,302
)
Changes Due to SIA and CSW Operating Agreement (c)
   
11,900
 
Changes in Fair Value Allocated to Regulated Jurisdictions (d)
   
(15,198
)
Total MTM Risk Management Contract Net Assets
   
6,181
 
Net Cash Flow Hedge Contracts
   
(4,125
)
DETM Assignment (e)
   
(664
)
Total MTM Risk Management Contract Net Assets at September 30, 2006
 
$
1,392
 

(a)
Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)
Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(c)
See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.
(d)
“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.
(e)
Starting in the third quarter of 2006, we were allocated a portion of the DETM assignment based on the FERC- approved methodology of AEP recording trading and marketing margins shared between the AEP East and AEP West companies. See “Natural Gas Contracts with DETM” section of Note 17 of the 2005 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 giving an indication of when these MTM amounts will settle and generate cash.

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2006
(in thousands)

   
Remainder 2006
 
2007
 
2008
 
2009
 
2010
 
After
2010
 
Total
 
Prices Actively Quoted - Exchange Traded Contracts
 
$
(3,762
)
$
(25,203
)
$
3,654
 
$
(451
)
$
-
 
$
-
 
$
(25,762
)
Prices Provided by Other External Sources - OTC Broker Quotes (a)
   
(7,187
)
 
32,724
   
6,546
   
(577
)
 
-
   
-
   
31,506
 
Prices Based on Models and Other Valuation Methods (b)
   
(173
)
 
(636
)
 
(310
)
 
1,546
   
50
   
(40
)
 
437
 
Total
 
$
(11,122
)
$
6,885
 
$
9,890
 
$
518
 
$
50
 
$
(40
)
$
6,181
 

(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.

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 employ various commodity instruments to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

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

We employ forward contracts and collars as cash flow hedges to lock-in prices on certain transactions which have been 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, 2005 to September 30, 2006. 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
Nine Months Ended September 30, 2006
(in thousands)

   
Power
 
Interest Rate
 
Total
 
Beginning Balance in AOCI December 31, 2005
 
$
(736
)
$
(5,116
)
$
(5,852
)
Changes in Fair Value
   
-
   
(2,655
)
 
(2,655
)
Impact due to Change in SIA (a)
   
591
   
-
   
591
 
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled
   
145
   
403
   
548
 
Ending Balance in AOCI September 30, 2006
 
$
-
 
$
(7,368
)
$
(7,368
)

(a)
See “Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement” section of Note 3.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $727 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 September 30, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

Nine Months Ended
September 30, 2006
       
Twelve Months Ended
December 31, 2005
(in thousands)
       
(in thousands)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
$1,385
 
$2,104
 
$758
 
$68
       
$363
 
$604
 
$287
 
$104

The High VaR for the nine months ended September 30, 2006 occurred in the third 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 $21 million and $31 million at September 30, 2006 and December 31, 2005, 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 and Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
Three Months Ended
 
Nine Months Ended
 
   
2006
 
2005
 
2006
 
2005
 
REVENUES
                   
Electric Generation, Transmission and Distribution
 
$
440,542
 
$
459,220
 
$
1,084,185
 
$
1,015,074
 
Sales to AEP Affiliates
   
14,692
   
14,614
   
34,871
   
38,573
 
Other
   
1,466
   
449
   
2,260
   
698
 
TOTAL
   
456,700
   
474,283
   
1,121,316
   
1,054,345
 
                           
EXPENSES
                         
Fuel and Other Consumables for Electric Generation
   
158,992
   
179,904
   
367,924
   
386,719
 
Purchased Electricity for Resale
   
61,816
   
45,194
   
135,918
   
91,377
 
Purchased Electricity from AEP Affiliates
   
18,140
   
27,363
   
58,303
   
55,230
 
Other Operation
   
55,256
   
60,229
   
158,338
   
152,340
 
Maintenance
   
21,120
   
22,353
   
68,008
   
65,713
 
Depreciation and Amortization
   
32,996
   
32,930
   
98,406
   
98,580
 
Taxes Other Than Income Taxes
   
17,107
   
18,175
   
49,254
   
49,725
 
TOTAL
   
365,427
   
386,148
   
936,151
   
899,684
 
                           
OPERATING INCOME
   
91,273
   
88,135
   
185,165
   
154,661
 
                           
Other Income (Expense):
                         
Interest Income
   
822
   
250
   
2,277
   
1,167
 
Allowance for Equity Funds Used During Construction
   
287
   
516
   
400
   
1,849
 
Interest Expense
   
(13,844
)
 
(12,346
)
 
(40,688
)
 
(38,027
)
                           
INCOME BEFORE INCOME TAXES AND MINORITY
  INTEREST EXPENSE
   
78,538
   
76,555
   
147,154
   
119,650
 
                           
Income Tax Expense
   
27,873
   
25,789
   
49,187
   
35,675
 
Minority Interest Expense
   
959
   
1,035
   
2,077
   
2,735
 
                           
NET INCOME
   
49,706
   
49,731
   
95,890
   
81,240
 
                           
Preferred Stock Dividend Requirements
   
57
   
57
   
172
   
172
 
                           
EARNINGS APPLICABLE TO COMMON STOCK
 
$
49,649
 
$
49,674
 
$
95,718
 
$
81,068
 

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 Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
Common Stock
 
Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive Income (Loss)
 
Total
 
DECEMBER 31, 2004
 
$
135,660
 
$
245,003
 
$
389,135
 
$
(1,180
)
$
768,618
 
                                 
Common Stock Dividends
               
(40,000
)
       
(40,000
)
Preferred Stock Dividends
               
(172
)
       
(172
)
TOTAL
                           
728,446
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $4,827
                     
(8,965
)
 
(8,965
)
NET INCOME
               
81,240
         
81,240
 
TOTAL COMPREHENSIVE INCOME
                           
72,275
 
                                 
SEPTEMBER 30, 2005
 
$
135,660
 
$
245,003
 
$
430,203
 
$
(10,145
)
$
800,721
 
                                 
DECEMBER 31, 2005
 
$
135,660
 
$
245,003
 
$
407,844
 
$
(6,129
)
$
782,378
 
                                 
Common Stock Dividends
               
(30,000
)
       
(30,000
)
Preferred Stock Dividends
               
(172
)
       
(172
)
TOTAL
                           
752,206
 
                                 
COMPREHENSIVE INCOME
                               
Other Comprehensive Loss, Net of Taxes:
                               
Cash Flow Hedges, Net of Tax of $817
                     
(1,516
)
 
(1,516
)
NET INCOME
               
95,890
         
95,890
 
TOTAL COMPREHENSIVE INCOME
                           
94,374
 
                                 
SEPTEMBER 30, 2006
 
$
135,660
 
$
245,003
 
$
473,562
 
$
(7,645
)
$
846,580
 

   See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2006 and December 31, 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
CURRENT ASSETS
           
Cash and Cash Equivalents
 
$
2,796
 
$
3,049
 
Advances to Affiliates
   
7,018
   
-
 
Accounts Receivable:
             
Customers
   
65,274
   
47,515
 
Affiliated Companies
   
40,779
   
49,226
 
Miscellaneous
   
8,260
   
7,984
 
Allowance for Uncollectible Accounts
   
(264
)
 
(548
)
  Total Accounts Receivable
   
114,049
   
104,177
 
Fuel
   
58,785
   
40,333
 
Materials and Supplies
   
43,108
   
34,821
 
Risk Management Assets
   
84,685
   
47,319
 
Regulatory Asset for Under-Recovered Fuel Costs
   
-
   
51,387
 
Margin Deposits
   
42,232
   
13,740
 
Prepayments and Other
   
19,129
   
20,270
 
TOTAL
   
371,802
   
315,096
 
               
PROPERTY, PLANT AND EQUIPMENT
             
Electric:
             
Production
   
1,697,764
   
1,660,392
 
Transmission
   
662,009
   
645,297
 
Distribution
   
1,200,577
   
1,153,026
 
Other
   
458,905
   
443,749
 
Construction Work in Progress
   
137,128
   
104,175
 
Total
   
4,156,383
   
4,006,639
 
Accumulated Depreciation and Amortization
   
1,825,110
   
1,776,216
 
TOTAL - NET
   
2,331,273
   
2,230,423
 
               
OTHER NONCURRENT ASSETS
             
Regulatory Assets
   
101,273
   
81,776
 
Long-term Risk Management Assets
   
38,252
   
39,796
 
Employee Benefits and Pension Assets
   
79,770
   
83,330
 
Deferred Charges and Other
   
54,333
   
46,926
 
TOTAL
   
273,628
   
251,828
 
               
TOTAL ASSETS
 
$
2,976,703
 
$
2,797,347
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2006 and December 31, 2005
(Unaudited)

   
 2006
 
2005
 
CURRENT LIABILITIES
 
(in thousands)
 
Advances from Affiliates
 
$
-
 
$
28,210
 
Accounts Payable:
             
General
   
94,188
   
71,138
 
Affiliated Companies
   
82,937
   
53,019
 
Short-term Debt - Nonaffiliated
   
15,676
   
1,394
 
Long-term Debt Due Within One Year - Nonaffiliated
   
108,926
   
15,755
 
Risk Management Liabilities
   
93,641
   
45,098
 
Customer Deposits
   
48,931
   
50,848
 
Accrued Taxes
   
89,311
   
42,799
 
Other
   
79,223
   
82,699
 
TOTAL
   
612,833
   
390,960
 
               
NONCURRENT LIABILITIES
             
Long-term Debt - Nonaffiliated
   
578,575
   
678,886
 
Long-term Debt - Affiliated
   
50,000
   
50,000
 
Long-term Risk Management Liabilities
   
27,904
   
27,083
 
Deferred Income Taxes
   
379,470
   
409,513
 
Regulatory Liabilities and Deferred Investment Tax Credits
   
343,954
   
320,066
 
Deferred Credits and Other
   
131,017
   
131,477
 
TOTAL
   
1,510,920
   
1,617,025
 
               
TOTAL LIABILITIES
   
2,123,753
   
2,007,985
 
               
Minority Interest
   
1,672
   
2,284
 
               
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
4,698
   
4,700
 
               
Commitments and Contingencies (Note 5)
             
               
COMMON SHAREHOLDER’S EQUITY
             
Common Stock - $18 Par Value 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
   
473,562
   
407,844
 
Accumulated Other Comprehensive Income (Loss)
   
(7,645
)
 
(6,129
)
TOTAL
   
846,580
   
782,378
 
               
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
 
$
2,976,703
 
$
2,797,347
 

See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.



SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2006 and 2005
(in thousands)
(Unaudited)

   
2006
 
2005
 
OPERATING ACTIVITIES
           
Net Income
 
$
95,890
 
$
81,240
 
Adjustments for Noncash Items:
             
Depreciation and Amortization
   
98,406
   
98,580
 
Deferred Income Taxes
   
(24,642
)
 
11,552
 
Mark-to-Market of Risk Management Contracts
   
10,870
   
(3,141
)
Deferred Property Taxes
   
(9,438
)
 
(9,579
)
Change in Other Noncurrent Assets
   
20,982
   
(16,262
)
Change in Other Noncurrent Liabilities
   
(33,256
)
 
10,149
 
Changes in Components of Working Capital:
             
Accounts Receivable, Net
   
(9,872
)
 
(3,337
)
Fuel, Materials and Supplies
   
(26,739
)
 
6,254
 
Margin Deposits
   
(28,492
)
 
(18,766
)
Accounts Payable
   
54,264
   
41,775
 
   Customer Deposits     (1,917   26,571  
Accrued Taxes, Net
   
45,514
   
4,655
 
   Over/Under Fuel Recovery, Net     63,862      (66,173
Other Current Assets
   
2,635
   
(3,859
)
Other Current Liabilities
   
(15,346
)
 
4,046
 
Net Cash Flows From Operating Activities
   
242,721
   
163,705
 
               
INVESTING ACTIVITIES
             
Construction Expenditures
   
(179,117
)
 
(110,209
)
Change in Advances to Affiliates, Net
   
(7,018
)
 
39,106
 
Other
   
(496
)
 
3,246
 
Net Cash Flows Used For Investing Activities
   
(186,631
)
 
(67,857
)
               
FINANCING ACTIVITIES
             
Issuance of Long-term Debt - Nonaffiliated
   
80,593
   
154,642
 
Change in Short-term Debt, Net - Nonaffiliated
   
14,282
   
-
 
Change in Advances from Affiliates, Net
   
(28,210
)
 
605
 
Retirement of Long-term Debt - Nonaffiliated
   
(88,989
)
 
(208,122
)
Retirement of Preferred Stock
   
(2
)
 
-
 
Principal Payments for Capital Lease Obligations
   
(3,845
)
 
(2,712
)
Dividends Paid on Common Stock
   
(30,000
)
 
(40,000
)
Dividends Paid on Cumulative Preferred Stock
   
(172
)
 
(172
)
Net Cash Flows Used For Financing Activities
   
(56,343
)
 
(95,759
)
               
Net Increase (Decrease) in Cash and Cash Equivalents
   
(253
)
 
89
 
Cash and Cash Equivalents at Beginning of Period
   
3,049
   
3,715
 
Cash and Cash Equivalents at End of Period
 
$
2,796
 
$
3,804
 
               
SUPPLEMENTARY INFORMATION
             
Cash Paid for Interest, Net of Capitalized Amounts
 
$
37,372
 
$
33,748
 
Net Cash Paid for Income Taxes
   
53,509
   
49,176
 
Noncash Acquisitions Under Capital Leases
   
17,110
   
4,414
 
Construction Expenditures Included in Accounts Payable at September 30,
   
8,924
   
5,075
 

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
Customer Choice and Industry Restructuring
Note 4
Commitments and Contingencies
Note 5
Guarantees
Note 6
Company-wide Staffing and Budget Review
Note 7
Benefit Plans
Note 9
Income Taxes
Note 10
Business Segments
Note 11
Financing Activities
Note 12
 


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.
Customer Choice and Industry Restructuring
CSPCo, OPCo, SWEPCo, TCC, TNC
5.
Commitments and Contingencies
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
6.
Guarantees
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
7.
Company-wide Staffing and Budget Review
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
8.
Acquisitions, Assets Held for Sale and Asset Impairments
CSPCo, TCC
9.
Benefit Plans
APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
10.
Income Taxes
PSO, SWEPCo, TCC, TNC
11.
Business Segments
AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
12.
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 Securities and Exchange Commission (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 and nine months ended September 30, 2006 are not necessarily indicative of results that may be expected for the year ending December 31, 2006. The accompanying condensed financial statements are unaudited and should be read in conjunction with the audited 2005 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 2005 as filed with the SEC on March 1, 2006.

Components of Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss) is included on the condensed balance sheets in the common shareholder’s equity section. The components of Accumulated Other Comprehensive Income (Loss) for Registrant Subsidiaries as of September 30, 2006 and December 31, 2005 are shown in the following table.

   
September 30,
 
December 31,
 
   
2006
 
2005
 
   
(in thousands)
 
Components
           
Cash Flow Hedges:
             
APCo
 
$
(3,407
)
$
(16,421
)
CSPCo
   
3,081
   
(859
)
I&M
   
(8,503
)
 
(3,467
)
KPCo
   
1,249
   
(194
)
OPCo
   
7,055
   
755
 
PSO
   
(1,116
)
 
(1,112
)
SWEPCo
   
(7,368
)
 
(5,852
)
TCC
   
-
   
(224
)
TNC
   
(1,337
)
 
(111
)
               
Minimum Pension Liability:
             
APCo
 
$
(189
)
$
(189
)
CSPCo
   
(21
)
 
(21
)
I&M
   
(102
)
 
(102
)
KPCo
   
(29
)
 
(29
)
PSO
   
(152
)
 
(152
)
SWEPCo
   
(277
)
 
(277
)
TCC
   
(928
)
 
(928
)
TNC
   
(393
)
 
(393
)

Accounting for Asset Retirement Obligations (ARO)

The Registrant Subsidiaries implemented SFAS 143 effective January 1, 2003. SFAS 143 requires entities to record a liability at fair value for any legal obligations for future asset retirements when the related assets are acquired or constructed. Upon establishment of a legal liability, SFAS 143 requires a corresponding ARO asset to be established, which will be depreciated over its useful life. ARO accounting is being followed for regulated and nonregulated property that has a legal obligation related to asset retirement. Upon settlement of an ARO, any difference between the ARO liability and actual costs is recognized as income or expense.

The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets, as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected.

The following is a reconciliation of the September 30, 2006 aggregate carrying amount of ARO for SWEPCo. The changes in components of ARO during 2006 are immaterial for all other Registrant Subsidiaries.

 
 
ARO at
December 31,
2005
 
Accretion Expense
 
Liabilities Incurred
 
Liabilities
Settled
 
Revisions in Cash Flow
Estimates
 
ARO at September 30, 2006
 
   
(in thousands)
 
SWEPCo
 
$
43,077
 
$
1,781
 
$
4,200
 
$
(4,967
)
$
(763
)
$
43,328
 

SWEPCo’s September 30, 2006 and December 31, 2005 aggregate carrying amounts include ARO related to ash ponds, asbestos removal, Sabine Mining Company and Dolet Hills Lignite Company, LLC. The current portion of SWEPCo’s ARO totaling approximately $1 million and $2 million at September 30, 2006 and December 31, 2005, respectively, is included in Other in the Current Liabilities section of SWEPCo’s Condensed Consolidated Balance Sheets.

Related Party Transactions

The amounts of power purchased from Ohio Valley Electric Corporation, which is 43.47 % owned by AEP and CSPCo, were:

   
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
Company
 
2006
 
2005
 
2006
 
2005
 
   
(in thousands)
 
APCo
 
$
19,555
 
$
19,501
 
$
62,209
 
$
54,763
 
CSPCo
   
5,536
   
5,103
   
17,100
   
14,752
 
I&M
   
9,784
   
7,920
   
28,848
   
22,704
 
OPCo
   
19,303
   
16,703
   
58,626
   
47,757
 

CSPCo entered into a ten year Power Purchase Agreement (PPA) with Sweeny, on behalf of the AEP West companies, from January 1, 2005 to December 31, 2014. The PPA is for unit contingent power up to a maximum of 315 MW. The delivery point for the power under the PPA is in TCC’s system. The power is sold in ERCOT. Prior to May 1, 2006, the purchase of Sweeny power and its sale to nonaffiliates were shared among the AEP West companies under the CSW Operating Agreement. After May 1, 2006, the purchases and sales are shared between PSO and SWEPCo. See “Allocation Agreement between AEP East Companies and AEP West Companies and CSW Operating Agreement” section of Note 3. Also see Note 17 of the 2005 Annual Report for a discussion of the CSW Operating Agreement. The purchases from Sweeny were:

   
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
Company
 
2006
 
2005
 
2006
 
2005
 
   
(in thousands)
 
PSO
 
$
13,750
 
$
11,051
 
$
39,886
 
$
31,160
 
SWEPCo
   
16,170
   
13,189
   
46,925
   
27,570
 
TCC
   
-
   
5,548
   
703
   
20,120
 
TNC
   
-
   
8,559
   
4,229
   
19,638
 

Reclassifications

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

The Registrant Subsidiaries’ Statements of Operations were converted from a utility format presentation where only regulated cost-of-service items were reflected in Operating Income to a commercial format presentation where nonutility items are reflected as components of Operating Income.

 
        2. NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of exposure drafts or final pronouncements, we thoroughly review the new accounting literature to determine its relevance, if any, to our business. The following represents a summary of new pronouncements issued or implemented in 2006 that we determined relate to our operations.

SFAS 123 (revised 2004) “Share-Based Payment” (SFAS 123R)

In December 2004, the FASB issued SFAS 123R. SFAS 123R requires entities to recognize compensation expense in an amount equal to the fair value of share-based payments granted to employees. The statement eliminates the alternative to use the intrinsic value method of accounting previously available under Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.” The Registrant Subsidiaries recorded insignificant cumulative effects of a change in accounting principle in the first quarter of 2006 for the effects of initially applying the statement, primarily reflected in Other Operation on their financial statements.

In March 2005, the SEC issued Staff Accounting Bulletin (SAB) No. 107, “Share-Based Payment” (SAB 107), which conveys the SEC staff’s views on the interaction between SFAS 123R and certain SEC rules and regulations. SAB 107 also provides the SEC staff’s views regarding the valuation of share-based payment arrangements for public companies. Also, the FASB issued three FASB Staff Positions (FSP) during 2005 and one in February 2006 that provided additional implementation guidance. The Registrant Subsidiaries applied the principles of SAB 107 and the applicable FSPs in conjunction with their adoption of SFAS 123R.

The Registrant Subsidiaries adopted SFAS 123R in the first quarter of 2006 using the modified prospective method. This method requires them to record compensation expense for all awards granted after the time of adoption and recognize the unvested portion of previously granted awards that remain outstanding at the time of adoption as the requisite service is rendered. The compensation cost is based on the grant-date fair value of the equity award. Stock-based compensation expense recognized during the period is based on the value of the portion of share-based payment awards that is ultimately expected to vest during the period. Stock-based compensation expense recognized in the Registrant Subsidiaries’ financial statements for the three and nine months ended September 30, 2006 includes compensation expense for share-based payment awards granted prior to, but not yet vested as of, January 1, 2006 based on the grant date fair value estimated in accordance with the pro forma provisions of SFAS 123 and compensation expense for the share-based payment awards granted subsequent to January 1, 2006 based on the grant date fair value estimated in accordance with the provisions of SFAS 123R. Implementation of SFAS 123R did not materially affect the Registrant Subsidiaries’ results of operations, cash flows or financial condition.

SFAS 157 “Fair Value Measurements”

In September 2006, the FASB issued SFAS 157. SFAS 157 enhances existing guidance for fair value measurement of assets and liabilities as well as instruments measured at fair value that are classified in shareholders’ equity. SFAS 157 defines fair value, establishes a fair value measurement framework and expands fair value disclosures. SFAS 157 emphasizes that fair value is market-based with the highest measurement hierarchy being market prices in active markets. The standard will change current practice and requires fair value measurements be disclosed by hierarchy level. SFAS 157 requires 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 is currently in the process of determining the effect this standard will have on the Registrant Subsidiaries’ financial statements. Although SFAS 157 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. SFAS 157 will be effective for the Registrant Subsidiaries starting January 1, 2008.

SFAS 158 “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”

In September 2006, the FASB issued SFAS 158. SFAS 158 amends previous standards. It requires employers to fully recognize the obligations associated with defined benefit pension, retiree healthcare and other postretirement (OPEB) plans in their balance sheets. Previous standards required an employer to disclose the complete funded status of its plan only in the notes to the financial statements and provided that an employer delay recognition of certain changes in plan assets and obligations that affected the costs of providing benefits resulting in an asset or liability that often differed from the plan’s funded status. SFAS 158 requires a defined benefit pension or postretirement plan sponsor (a) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for the plan’s underfunded status, (b) measure the plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year (with limited exceptions), and (c) recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year but are not recognized as a component of net periodic benefit cost pursuant to SFAS 87, “Employers’ Accounting for Pensions,” or SFAS 106, “Employer’s Accounting for Postretirement Benefits Other Than Pensions.” It also requires an employer to disclose additional information on how delayed recognition of certain changes in the funded status of a defined benefit postretirement plan affects net periodic benefit costs for the next fiscal year.

The effect of SFAS 158 is to adjust AOCI at the end of each year, for both underfunded and overfunded pension and OPEB plans, to an amount equal to the remaining unrecognized SFAS 87 and SFAS 106 deferrals for unamortized actuarial losses or gains, prior service costs, or transition obligations, such that remaining deferred costs result in an AOCI equity reduction and deferred gains result in an AOCI equity addition.

The year-end AOCI measure is volatile based on fluctuating investment returns and discount rates. Favorable changes include higher returns that increase plan assets and higher discount rates that reduce the discounted benefit obligation.

SFAS 158 is effective for initial recognition of a defined benefit postretirement plan and related disclosure for fiscal years ending after December 15, 2006. Management has not completed the process of determining the effect of this standard on the Registrant Subsidiaries’ financial statements, including whether a portion of the adjustment required by SFAS 158 can be deferred as a regulatory asset under SFAS 71.

EITF Issue 06-3 “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)” (EITF 06-3)

In June 2006, the EITF reached a consensus on the income statement presentation of various types of taxes. The scope of this issue includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value added, and some excise taxes. The presentation of taxes within the scope of this issue on either a gross (included in revenues and costs) or a net (excluded from revenues) basis is an accounting policy decision that should be disclosed pursuant to APB Opinion No. 22, “Disclosure of Accounting Policies.” The EITF’s decision on gross/net presentation requires that any such taxes reported on a gross basis be disclosed on an aggregate basis in interim and annual financial statements, for each period for which an income statement is presented, if those amounts are significant.

EITF 06-3 is effective for fiscal years beginning after December 15, 2006. As disclosed in Note 1 of the 2005 Annual Report, the Registrant Subsidiaries act as agents for some state and local governments and collect from customers certain excise taxes levied by those state or local governments on customers. The Registrant Subsidiaries present these taxes on a net basis and do not recognize these taxes as revenues or expenses. Therefore, this issue will not have a material impact on their financial statements.

FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (FIN 48)

In July 2006, the FASB issued FIN 48 which clarifies the application of SFAS 109, “Accounting for Income Taxes.” 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. FIN 48 is effective for fiscal years beginning after December 15, 2006. Management has not completed the process of determining the effect of this interpretation on the financial statements.

SAB No. 108 “Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in the Current Year Financial Statements” (SAB 108)

In September 2006, the SEC staff issued SAB 108. SAB 108 addresses the diversity in practice when quantifying the effect of an error on financial statements. SAB 108 provides guidance on the consideration of the effects of prior year misstatements in quantifying misstatements in current year financial statements. The Registrant Subsidiaries will be required to adopt the provisions of SAB 108 effective December 31, 2006. Management believes that the adoption of SAB 108 will not have a material impact on the financial statements.

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, 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 Rate Matters note within the 2005 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 and cash flows. Rate matters that are not believed to be reasonably likely to affect future results of operations and cash flows are not included in this report or the 2005 Annual Report. The following sections discuss ratemaking developments in 2006 updating the 2005 Annual Report.

APCo Virginia Environmental and Reliability Costs - Affecting APCo

The Virginia Electric Restructuring Act (the statute) includes a provision that permits recovery, during the extended capped rate period ending December 31, 2010, of incremental environmental compliance and transmission and distribution (T&D) system reliability (E&R) costs prudently incurred on and after July 1, 2004. In 2005, APCo filed a request with the Virginia SCC and updated it through supplemental testimony seeking recovery of $21 million of incremental E&R costs incurred from July 2004 through September 2005. Through August 31, 2006, APCo deferred as a regulatory asset $47 million of incremental E&R costs incurred since July 1, 2004 based on a legal opinion that such costs were probable of recovery under the law.

In January 2006, the Virginia SCC staff proposed that APCo be allowed to increase its electric rates at an ongoing level of $20 million to recover current, rather than past, incremental E&R costs. The staff proposal would effectively disallow the recovery of costs incurred prior to the authorization and implementation of new rates, including all incremental E&R costs that were deferred as a regulatory asset. At the E&R hearings, which concluded in March 2006, the staff amended its testimony to recommend a $24 million increase in APCo’s ongoing rates. In September 2006, the Hearing Examiner issued a report recommending adoption of the staff proposal with minor modifications, which would result in (a) an on-going level of E&R cost recovery of $29 million only if the Virginia SCC decides that any rate increase from the base rate case (described below) does not include the $29 million ongoing level of E&R costs, and (b) the disallowance of all previously deferred incremental E&R costs. In the third quarter of 2006, management concluded that the Virginia SCC might not grant recovery of actual incremental E&R costs incurred during the period from July 2004 through September 2006. Accordingly, APCo wrote off all of the E&R regulatory asset, adversely affecting pretax earnings by $36 million, net of the reinstatement of related AFUDC and capitalized interest. Management believes that the staff’s proposal and the Hearing Examiner’s recommendation are contrary to the statute. The Virginia SCC’s final order in this proceeding is pending.

If the Virginia SCC properly implements the statute as interpreted in its October 2005 order and as supported by the Virginia Attorney General’s office in October 2006, APCo should be able to recover all of its incremental E&R costs prudently incurred since July 1, 2004. If the Virginia SCC adopts the Hearing Examiner's findings, based on advice of counsel, APCo will appeal the decision.

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 adjusted annually. APCo also proposed to share the off-system sales margins with the customers with 40% going to reduce rates and 60% being retained by APCo. This resultant 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 revenues of $198 million. The major components of the $225 million 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 October 2, 2006, subject to refund. In October 2006, the Virginia SCC staff filed their direct testimony recommending a base rate increase of $13 million. Other intervenors have recommended base rate increases ranging from $42 million to $112 million. APCo plans to file rebuttal testimony in November 2006. Hearings are scheduled to begin in December 2006. Management is unable to predict the ultimate effect of this filing on APCo’s future revenues, cash flows and financial condition.

APCo West Virginia Rate Case - Affecting APCo

In July 2006, the WVPSC approved the settlement agreement APCo and WPCo reached with the WVPSC staff and intervenors in the West Virginia rate case filed in 2005. The settlement agreement provided for an initial overall increase in APCo’s rates of $40 million effective July 28, 2006 comprised of:

·
A $50 million increase in Expanded Net Energy Cost (ENEC) for fuel, purchased power expenses, off-system sales credits and other energy-related costs;
·
A $21 million special construction surcharge providing recovery of the costs of scrubbers and the Wyoming-Jacksons Ferry 765 kV line to date;
·
A $16 million general base rate reduction resulting predominantly from a reduction in the return on equity to 10.5% and a $9 million reduction in depreciation expense which affects cash flows but not earnings; and
·
A $15 million credit to refund a portion of deferred prior over-recoveries of ENEC recorded in regulatory liabilities on APCo’s Condensed Consolidated Balance Sheets, which will impact cash flows but not earnings.

In addition, the agreement provides a surcharge mechanism that allows APCo to adjust its rates annually for the timely recovery in each of the next three years of the incremental cost of ongoing environmental investments in scrubbers at Mountaineer and John Amos power plants and the costs of the new Wyoming-Jackson Ferry 765 kV line. Although the amount of these annual surcharge increases cannot be determined until the incremental costs are known and reviewed by the WVSPC, management estimates that they will result in an annual increase in APCo’s revenues of $32 million effective July 1, 2007, $13 million effective July 1, 2008 and $16 million effective July 1, 2009.

The settlement further provides for the reinstatement of the ENEC mechanism effective July 1, 2006 with over/under recovery deferral accounting and annual ENEC proceedings to affect annual rate adjustments for changes in fuel and purchased power costs beginning in 2007. The settlement provides for the return to customers of the remaining portion of the prior ENEC regulatory liability plus interest at LIBOR rate on the unrefunded balance in future ENEC proceedings.

I&M Depreciation Study Filing- Affecting I&M

In December 2005, I&M filed a petition with the IURC seeking authorization to revise its book depreciation rates applicable to its electric utility plant in service effective January 1, 2006. Based on a depreciation study included in the filing, I&M recommended a decrease in pretax annual depreciation expense of approximately $69 million on an Indiana jurisdictional basis 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. A public hearing was held in May 2006 and the final brief was filed in June 2006. As proposed by I&M, the book depreciation expense reduction would increase its earnings, but would not impact its cash flows until electric service rates are revised.

An order issued by the IURC on October 19, 2006 does not dispute I&M's revised depreciation accounting rates but, nevertheless, denied I&M’s request to revise its book depreciation rates between base rate cases.  The IURC believes that depreciation rates for an electric utility should not be changed between general rate cases unless it was “absolutely essential” and a direct benefit to customers was shown. I&M has twenty days in which to file for a rehearing or reconsideration. I&M has not yet decided whether it will file for a rehearing or reconsideration or if and when it will file to adjust base rates to reflect the depreciation study.

KPCo Environmental Surcharge Filing - Affecting KPCo

In July 2006, KPCo filed its third annual environmental compliance plan seeking additional annual revenues of $2 million in 2007 and $6 million in 2008. The filing seeks recovery of KPCo’s share of AEP System Power Pool charges for the annual cost of retrofitting pollution control additions to affiliated AEP System east zone power plants. No intervenor testimony was filed in the case. Management expects the KPSC will rule on the filing in early 2007. Management is unable to predict the ultimate effect this filing will have on KPCo’s revenues and results of operations.

KPCo Rate Filing - Affecting KPCo

In March 2006, the KPSC approved the settlement agreement in KPCo’s 2005 base rate case. The approved agreement provides for a $41 million annual increase in revenues effective on March 30, 2006 and the retention of the existing environmental surcharge tariff. No return on equity is specified by the settlement terms except to note that KPCo will use a 10.5% return on equity to calculate the environmental surcharge tariff and AFUDC.

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 18 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 through 2003 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 their 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 their 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.

PSO does not agree with the intervenors’ and the OCC staff’s recommendations and proposals and will defend its position. If the OCC denies recovery of any portion of the $42 million under-recovery of reallocated costs or offsets under-recovered fuel deferrals with additional reallocated off-system sales margins, PSO’s future results of operations and cash flows could be adversely affected. However, if the position taken by the federal court in Texas applies to PSO’s case, the OCC could 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 may file a complaint at the FERC alleging the allocation of off-system sales margins adopted by 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. To date, there has been no claim asserted at the FERC that AEP deviated from the approved allocation methodologies. Management is unable to predict the ultimate effect, if any, of these Oklahoma fuel clause proceedings and any future FERC proceedings on the AEP East companies’ and AEP West companies’ future results of operations, cash flows and financial condition.

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 existed during the year. A hearing was held in August 2006 and management expects a recommendation from the ALJ in the fourth quarter of 2006.

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. The OCC staff indicated that it expects the review process to begin late 2006 or early 2007.

Management cannot predict the outcome of the pending fuel and purchase 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 PSO’s future results of operations and cash flows.

PSO Rate Filing - Affecting PSO

In September 2006, PSO filed a notice of its intent to file in November 2006 a plan to modify the base rates of PSO’s Oklahoma jurisdictional customers with a proposed effective date in the second quarter of 2007.

SWEPCo Louisiana Fuel Inquiry - Affecting SWEPCo

In March 2006, the Louisiana Public Service Commission (LPSC) closed its inquiry into SWEPCo’s fuel and purchased power procurement activities during the period January 1, 2005 through October 31, 2005. The LPSC approved the LPSC staff’s report, which concluded that SWEPCo’s activities were appropriate and did not identify any disallowances or areas for improvement.

SWEPCo PUCT Staff Review of Earnings - Affecting SWEPCo

In October 2005, the staff of the PUCT reported the results of its review of SWEPCo’s year-end 2004 earnings. Based on the staff’s adjustments to the information submitted by SWEPCo, the report indicates that SWEPCo is receiving excess revenues of approximately $15 million. The staff engaged SWEPCo in discussions to reconcile the earnings calculation and to consider possible ways to address the results. After those discussions, the PUCT staff informed SWEPCo in April 2006 that they would not pursue the matter further.

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. In April 2004, at the request of the LPSC, SWEPCo filed updated financial information with a test year ending December 31, 2003. Both filings indicated that SWEPCo’s rates should not be reduced. 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 and the recommended base rate reduction does not include the impact of a proposed consolidated federal income tax adjustment, which, if approved, would increase the proposed rate reduction. SWEPCo filed rebuttal testimony in October 2006 strongly refuting the consultants’ recommendations. Hearings are expected to occur late in the fourth quarter of 2006. A decision is not expected until 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 SWEPCo’s future results of operations and cash flows.

TCC and TNC Rate Filings - Affecting TCC and TNC

In September 2006, TCC and TNC announced that each will file transmission and distribution wires rate cases in Texas in late 2006. Management anticipates requesting an $83 million annual increase for TCC and a $25 million annual increase for TNC. Both requests include the impact of the expiration of the CSW merger savings credits.

ERCOT Price-to-Beat (PTB) Fuel Factor Appeal - Affecting TCC and TNC

Several parties including the Office of Public Utility Counsel and cities served by both TCC and TNC appealed the PUCT’s December 2001 orders establishing initial PTB fuel factors for Mutual Energy CPL and Mutual Energy WTU (TCC’s and TNC’s former affiliated REPs, respectively). In June 2003, the District Court ruled the PUCT record lacked substantial evidence regarding the effect of loss of load due to retail competition on the generation requirements of both Mutual Energy WTU and Mutual Energy CPL and on the PTB rates. In an opinion issued in July 2005, the Texas Court of Appeals reversed the District Court. The cities appealed the appeals court decision to the Supreme Court of Texas, which has ordered full briefing, but has not granted review. Management cannot predict the outcome of further appeals, but a reversal of the favorable court of appeals decision regarding the loss of load issue could result in the issue being returned to the PUCT for further consideration. If that were to happen and if the PUCT orders refunds of PTB revenues, it could adversely impact TCC’s and TNC’s results of operations and cash flows for the portion of the refund applicable to the period of time that they owned the REPs.

RTO Formation/Integration - Affecting APCo, CSPCo, I&M, KPCo and OPCo

In 2005, the FERC approved the amortization of approximately $18 million of deferred RTO formation/integration costs not billed by PJM over 15 years and $17 million of deferred PJM-billed integration costs over 10 years. The total amortization related to such costs was $1 million in both the third quarter of 2006 and 2005. In the first nine months of 2006 and 2005, total amortization related to such costs was $4 million and $3 million, respectively.

The AEP East companies’ deferred unamortized RTO formation/integration costs were as follows:

   
September 30, 2006
 
December 31, 2005
 
   
PJM-Billed Integration Costs
 
Non-PJM Billed Formation/ Integration Costs
 
PJM-Billed Integration Costs
 
Non-PJM Billed Formation/ Integration Costs
 
   
 (in millions)
 
APCo
 
$
3.7
 
$
4.8
 
$
4.1
 
$
4.9
 
CSPCo
   
1.5
   
1.9
   
1.7
   
1.9
 
I&M
   
3.0
   
3.4
   
3.2
   
3.7
 
KPCo
   
0.9
   
1.1
   
1.0
   
1.1
 
OPCo
   
4.3
   
5.0
   
4.7
   
5.1
 

In a December 2005 order, the FERC approved the inclusion of a separate rate in the PJM AEP zone OATT to recover the amortization of deferred RTO formation/integration costs and related carrying costs not billed by PJM of $2 million per year. The AEP East companies will be responsible for paying the majority of the amortized costs assigned by the FERC to the AEP East zone since their internal load is the bulk (about 85%) of the transmission load in the AEP zone. As a result, the AEP East companies will need to recover the 85% through their retail rates.

In May 2006, the FERC approved a settlement that provides for recovery over a ten-year period of the PJM-billed integration costs, including related carrying charges, of AEP, Commonwealth Edison Company (ComEd) and The Dayton Power & Light Company (DP&L) from all present zones of the PJM region, except the Virginia Electric & Power Company (VEPCo) zone. The net result of the settlement is that the AEP East companies will recover approximately 50% of the deferred PJM-billed integration costs from third parties, and will need to recover the remaining 50% through retail rates.

As a result of recently approved rate increases, CSPCo, OPCo and KPCo recover the amortization of RTO formation/integration costs billed to the AEP East companies in Ohio and Kentucky. APCo received approval to include the amortization of RTO formation/integration costs in retail rates in West Virginia effective July 28, 2006. In Virginia, APCo filed a base rate case, which includes recovery of these costs when rates became effective October 2, 2006, subject to refund. In Indiana, I&M is subject to a rate cap until June 30, 2007 and is precluded from recovering its share of the deferred RTO costs until that date or until it can file for a rate increase in Indiana. I&M has not yet filed for recovery in Michigan.

Until I&M can adjust its retail rates in Indiana and Michigan to recover the amortization of its deferred RTO formation/integration costs, its results of operations and cash flows will be adversely affected. If the Virginia, Indiana or Michigan commissions disallow recovery of any portion of the billed amortization of deferred RTO formation/integration costs, it could adversely impact APCo’s and/or I&M’s future results of operations and cash flows. In the event of a disallowance, management would appeal that decision to the appropriate state or federal courts.

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

SECA Revenue Subject to Refund

In accordance with FERC orders, the AEP East companies collected SECA rates to mitigate lost through-and-out transmission service (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 also 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.

The AEP East companies recognized gross SECA revenues as follows:

   
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
   
2006
 
2005
 
2006 (a)
 
2005
 
   
(in millions)
 
APCo
 
$
-
 
$
13.6
 
$
13.4
 
$
39.1
 
CSPCo
   
-
   
7.7
   
7.9
   
20.8
 
I&M
   
-
   
8.0
   
8.1
   
22.5
 
KPCo
   
-
   
3.2
   
3.2
   
9.3
 
OPCo
   
-
   
10.6
   
10.4
   
28.8
 

(a)
Represents revenues through March 31, 2006, when SECA rates expired, and excludes the provision for refund recorded in the second quarter of 2006 discussed below.

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 SECA billings.

A hearing in the SECA case 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 were 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.

Since the implementation of SECA rates in December 2004, the AEP East companies recorded approximately $220 million of gross SECA revenues, subject to refund, and 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. It would also provide refunds of SECA rates paid by the AEP East companies in considerably less significant amounts.

The AEP East companies provided for net refunds, most of which were recorded in the second quarter of 2006 as shown in the following table.
 
   
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
   
2006
 
2005
 
2006
 
2005
 
   
(in thousands)
 
APCo
 
$
-
 
$
0.3
 
$
6.1
 
$
0.7
 
CSPCo
   
-
   
0.2
   
3.4
   
0.4
 
I&M
   
-
   
0.2
   
3.6
   
0.4
 
KPCo
   
-
   
0.1
   
1.4
   
0.2
 
OPCo
   
-
   
0.3
   
4.6
   
0.5
 

AEP, together with Exelon and DP&L, filed an extensive brief noting exceptions to the initial ALJ decision and asking the FERC to reverse the decision in large part. Reply briefs were filed in October 2006. Management believes that the FERC should reject the initial ALJ 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. As a result, the AEP East companies have not provided for a possible refund of SECA rates in excess of current provisions. If the FERC does adopt the ALJ’s recommendations, AEP will appeal the decision to the courts. Although AEP believes it has 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 the AEP East companies’ future results of operations and cash flows.

AEP East Transmission Revenue Requirement and Rates

In December 2005, the FERC approved an uncontested settlement which allowed increases in wholesale transmission OATT rates in three steps: first, beginning retroactively on November 1, 2005, second, beginning on April 1, 2006 when the SECA revenues were eliminated and third, beginning on August 1, 2006 when the new Wyoming-Jacksons Ferry 765 kV line went into service. Management estimates that this rate increase will increase wholesale transmission revenues by $22 million in 2006 and $28 million in 2007.

The Elimination of T&O and SECA Rates and the FERC PJM Regional Transmission Rate Proceeding

In a separate 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 than the AEP/AP proposal.
·
In a 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 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 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 PJM rate design. 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 would be just and reasonable alternatives; however, the judge also found the Postage Stamp rate proposed by the FERC staff to be just and reasonable, and recommended 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 somewhat more revenue for AEP than the AEP/AP proposal, but the phase-in 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. A FERC decision is likely in early to mid-2007.
 
From the elimination of T&O rates in December 2004 through the expiration of SECA rates on March 31, 2006, SECA transition rates failed to fully compensate the AEP East companies for their lost T&O revenues. Effective with the expiration of the SECA transition rates on March 31, 2006, the increase in the AEP East zonal transmission rates applicable to AEP’s internal load and wholesale transmission customers in AEP’s zone was not sufficient to replace the prior T&O revenues or the lower temporary SECA transition rate revenues; however, a favorable outcome in the PJM regional transmission rate proceeding, made retroactive to April 1, 2006 could mitigate a large portion of the shortfall. Full mitigation of the effects of eliminated T&O revenues and the less favorable terminated SECA revenues will require cost recovery through state retail rate proceedings pending any resolution that may result from the above FERC regional transmission rate proceeding. 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 the FERC-approved OATT which 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 yet filed to seek recovery of the lost transmission revenues.

Once approved by the FERC, the favorable impacts of the new regional PJM rate design will flow directly to wholesale customers and to retail customers in West Virginia through the ENEC and to retail customers in Ohio upon PUCO approval of a filing the Ohio companies would make to reflect the new rates. In Kentucky, Indiana, Virginia and Michigan, the additional transmission revenues can be expected to reduce retail rates in future base rate proceedings.
 
Management believes that the AEP/AP proposal of the Postage Stamp proposal combined with the retail rate recovery discussed above would be an effective replacement for the eliminated T&O and SECA rates.
Management is unable to predict whether the FERC will approve either the ALJ’s decision or another regional rate design. The AEP East companies’ future results of operations, cash flows and financial condition would be adversely affected if the approved FERC transmission rates are not sufficient to replace the lost T&O/SECA revenues and the resultant increase in the AEP East companies’ unrecovered transmission costs are not fully recovered in retail rates in Indiana and Michigan.

Calpine Oneta Power, L.P.’s Request at the FERC for Reactive Power Compensation From SPP - Affecting PSO and SWEPCo

In April 2003, Calpine Oneta Power (Calpine), an IPP, filed at the FERC a proposed rate schedule to charge SPP for reactive power from Calpine’s generating facility. The FERC rate schedule included a fixed annual fee of $2 million. PSO, SWEPCO and a small portion of TNC operate in SPP. An ALJ initially ruled against Calpine and management concluded that the likelihood of the FERC awarding Calpine a reactive power capacity rate was remote. In September 2006, the FERC issued its decision reversing the ALJ decision, granting Calpine’s request and requiring Calpine to make a compliance filing within 30 days. PSO’s, SWEPCo’s and TNC’s share of this SPP expense could be approximately 90% of the total amount billed by Calpine. Based on this information, PSO and SWEPCo recorded expense provisions, including interest, of $4 million and $4 million, respectively, in September 2006 for the retroactive reactive power liability. AEP will seek rehearing at the FERC and may appeal the decision if the FERC either denies rehearing or rules in favor of Calpine on rehearing.

Allocation Agreement between AEP East companies and AEP West companies and CSW Operating Agreement - Affecting the AEP East companies and AEP West companies

The SIA provides, among other things, for the methodology of sharing trading and marketing margins between the AEP East companies and AEP West companies. In March 2006, the FERC approved our proposed methodology effective April 1, 2006 and beyond. The approved allocation methodology for the AEP East companies and AEP West companies is based upon the location of the specific trading and marketing activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT generally accruing to the benefit of PSO and SWEPCo. Previously, the SIA allocation provided for a different method of sharing all such margins between both AEP East companies and AEP West companies, which effectively allowed the AEP West companies to share in PJM and MISO regional margins. In February 2006, AEP filed with the FERC to remove TCC and TNC from the SIA and CSW Operating Agreement because they are in the final stages of exiting the generation business and have already ceased serving retail load. The FERC approved the removal of TCC and TNC from the SIA and CSW Operating Agreement effective May 1, 2006. The impact on future results of operations and cash flows will depend upon the level of future margins by region and the status of expanded net energy fuel clause recovery mechanisms and related off-system sales sharing mechanisms by state.

        4. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING

The Customer Choice and Industry Restructuring note in the 2005 Annual Report should be read in conjunction with this report to gain a complete understanding of material customer choice and industry restructuring matters without significant changes since year-end. The following paragraphs discuss significant current events related to customer choice and industry restructuring in those states and updates the 2005 Annual Report.

TEXAS RESTRUCTURING - Affecting TCC, TNC and SWEPCo

In February 2006, the PUCT issued an order in TCC’s $2.4 billion True-up Proceeding, which determined that TCC’s true-up regulatory asset was $1.475 billion including carrying costs through September 2005. In December 2005, TCC adjusted its recorded net true-up regulatory asset to comply with the order. The PUCT issued an order on rehearing in April 2006, which made minor changes to, but otherwise affirmed, the February 2006 order. TCC appealed, seeking additional recovery consistent with the Texas Restructuring Legislation and related rules. Other parties appealed the PUCT’s true-up order claiming it permits TCC to over-recover stranded generation costs and other true-up items.
 
TCC Securitization Proceeding

TCC filed an application in March 2006 requesting recovery through securitization of $1.8 billion of net stranded generation plant costs and related carrying costs through August 31, 2006. The $1.8 billion request did not include TCC’s negative other true-up items, which total $478 million. See “CTC Proceeding for Other True-up Items” section of this note. Intervenors and the PUCT staff filed testimony regarding TCC’s securitization request in April 2006. In May 2006, TCC filed a letter with the PUCT reducing its request by $6 million of current carrying costs and reduced the recorded net recoverable regulatory asset by the recorded debt-related component. In May 2006, TCC and the other parties filed a settlement with the PUCT, which further reduced the securitizable amount by $77 million and settled several issues that would have delayed the sale of the securitization bonds. The PUCT approved the settlement in June 2006 authorizing $1.697 billion including carrying costs through August 31, 2006, the assumed securitization date, plus estimated issuance costs of $23 million, for a total of $1.72 billion. TCC issued its securitization bonds on October 11, 2006 for $1.74 billion, including additional issuance costs and carrying costs to October 11, 2006.

TCC performed a probability of recovery impairment test on its net true-up regulatory asset taking into account the treatment ordered by the PUCT. TCC determined that the projected cash flows from the securitization less the proposed CTC refund would be more than sufficient to recover its recorded net true-up regulatory asset due to the existence of $224 million of unrecorded equity-related carrying costs which are not recorded until collected in regulated rates. As a result, no additional impairment was recorded for the approved reduction in the amount to be securitized. However, the $77 million agreed upon reduction in the securitizable amount will have a negative impact on future earnings.

Consistent with certain prior securitization determinations, the PUCT issued a specific order in the securitization proceeding that calculated a $315 million cost-of-money benefit from true-up related ADFIT through August 2006, of which $75 million ($77 million through September 30, 2006) relates to the recorded benefit prior to the date of securitization and $240 million relates to the unrecorded benefit subsequent to the date of securitization. The PUCT included the $315 million ADFIT-related stranded cost benefit in the CTC refund of $478 million. In June 2006, TCC transferred the effects of the ADFIT on recorded carrying costs from the securitizable asset to the CTC refund, thereby increasing the carrying costs identified to the securitizable assets in the table below.

The differences between the securitization amount ordered by the PUCT of $1.74 billion and the Recorded Securitizable True-up Regulatory Asset of $1.57 billion by component at September 30, 2006 are detailed in the table below:

   
(in millions)
 
Stranded Generation Plant Costs
 
$
974
 
Net Generation-related Regulatory Asset
   
249
 
Excess Earnings
   
(49
)
Recorded Net Stranded Generation Plant Costs
   
1,174
 
Recorded Debt Carrying Costs on Net Stranded Generation Plant Costs
   
400
 
Recorded Securitizable True-up Regulatory Asset
   
1,574
 
Unrecorded But Recoverable Equity Carrying Costs
   
224
 
Unrecorded Estimated October 2006 Debt Carrying Costs
   
3
 
Unrecorded Excess Earnings, Related Carrying Costs and Other
   
53
 
Unrecorded Settlement Reduction
   
(77
)
Reduction for the Present Value of ADITC and EDFIT Benefits
   
(61
)
Approved Securitizable Amount as of October 11, 2006
   
1,716
 
Unrecorded Securitization Bond Issuance Costs
   
24
 
Amount Securitized on October 11, 2006
 
$
1,740
 

Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes

In TCC’s true-up and securitization orders, the PUCT reduced net stranded generation plant costs 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 generating assets. (See Reduction for the Present Value of ADITC and EDFIT Benefits of $61 million in the table above.) TCC testified that the sharing of these tax benefits with customers might be a violation of the Internal Revenue Code’s normalization provisions.
 
TCC filed a request for a private letter ruling from the IRS in June 2005 to determine whether the PUCT’s action would result in a normalization violation. The IRS issued its private letter ruling on May 9, 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. TCC informed the PUCT on May 10, 2006 of the adverse ruling, however, the PUCT did not change its order on rehearing. TCC filed an appeal with the PUCT. As discussed below in the “CTC Proceeding for Other True-up Items” section of this note, TCC proposed, and the PUCT agreed, to defer refunding the amount of the present value of its ADITC and EDFIT benefits through its CTC until this normalization issue is resolved upon the IRS issuance of final normalization regulations.
 
If a normalization violation occurs, it could result in the repayment of TCC’s ADITC on all property, including transmission and distribution property, which approximates $104 million as of September 30, 2006 and also a loss of the 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 through the appeal of the PUCT’s true-up order and through a CTC deferral.

CTC Proceeding for Other True-up Items

In June 2006, TCC filed to implement a negative CTC to refund its other true-up items over eight years. TCC will incur interest expense on the other true-up regulatory liability balances until it is fully refunded. The principal components of the CTC refund liability are an over-recovered fuel balance, the retail clawback and the ADFIT benefit related to TCC’s stranded generation cost, offset by a positive wholesale capacity auction true-up regulatory asset balance.

The differences between the components of TCC’s Recorded Net Regulatory Liabilities - Other True-up Items of $238 million as of September 30, 2006 (including interest expense) and its Net CTC Refund Proposed of $357 million are detailed below:

   
(in millions)
 
Wholesale Capacity Auction True-up
 
$
61
 
Carrying Costs on Wholesale Capacity Auction True-up
   
31
 
Retail Clawback including Carrying Costs
   
(65
)
Deferred Over-recovered Fuel Balance
   
(184
)
Retrospective ADFIT Benefit
   
(77
)
Other
   
(4
)
Recorded Net Regulatory Liabilities - Other True-up Items
   
(238
)
Unrecorded Prospective ADFIT Benefit
   
(240
)
Gross CTC Refund Proposed
   
(478
)
FERC Jurisdictional Fuel Refund Deferral
   
16
 
ADITC and EDFIT Benefit Refund Deferral
   
98
 
Net CTC Refund Proposed, After Deferrals
   
(364
)
True-up Proceeding Expense Surcharge
   
7
 
Net CTC Refund Proposed, After Deferrals and Expenses
 
$
(357
)

TCC requested that a portion of the refund be deferred, pending the outcome of two contingent federal matters related to the refund of $16 million of FERC jurisdictional fuel over-recoveries (discussed below) and $98 million (including carrying costs) related to potential tax normalization violation matters related to the refund of ADITC and EDFIT benefits (discussed above). Under TCC’s proposal, (a) if the two contingent federal matters are resolved consistent with the PUCT’s treatment, TCC will then refund the $16 million and the $98 million plus carrying costs or (b) if these two issues are not resolved consistent with the PUCT’s treatment, the deferred refunds will not be made in order to avoid a normalization violation and the violation of a Federal court order. Management cannot predict the final outcome of this filing.

Although TCC proposed to refund the $357 million over eight years, certain intervenors supported accelerated refunds. In September 2006, the PUCT approved an interim CTC that was implemented on October 12, 2006, the same day that TCC began billing customers for the securitization bonds. The interim CTC will refund the entire retail clawback of $65 million (including carrying costs) to residential customers by the end of 2006. The CTC refund to the other customer classes during the interim period will be as proposed by TCC, with the exception of the large industrials, who will not receive any fuel refunds during the interim period.

At an October 2006 open meeting, the PUCT announced oral decisions regarding the CTC refund. A final written order is expected in late November or early December of this year. In its decision, the PUCT confirmed that TCC can use securitization bond proceeds to make the CTC refund. The PUCT’s decision was to continue the interim CTC through December 2006 to complete the refund of the retail clawback over three months. Beginning in January 2007, the Deferred Over-recovered Fuel Balance will be refunded over six months with the large industrial customers receiving their entire refund in January 2007. Starting in July 2007, the remaining CTC items will be refunded over one year, except that the PUCT agreed with TCC’s request to defer the refund of the ADITC and EDFIT Benefit Refund Deferral and the FERC Jurisdictional Fuel Refund Deferral (see table above). The PUCT will decide those issues and related amounts in another proceeding.

Fuel Balance Recoveries

In September 2005, the Federal District Court, Western District of Texas, issued an order precluding the PUCT from enforcing its ruling in the TNC fuel proceeding regarding the PUCT’s reallocation of off-system sales margins. In August 2006, TCC also received an order from the Federal District Court, Western District of Texas precluding the PUCT from enforcing its ruling regarding the PUCT’s reallocation of off-system sales margins in connection with TCC’s final fuel reconciliation. The favorable Federal District Court order, if upheld on appeal, could result in reductions to the over-recovered fuel principal balances of $8 million for TNC and $14 million ($16 million with carrying costs) for TCC. The PUCT appealed the TCC and TNC Federal Court decision to the United States Court of Appeals for the Fifth Circuit. If the PUCT is unsuccessful in the federal court system, the PUCT may file a complaint at the FERC to address the allocation issue. TCC and TNC are unable to predict if the Federal District Court’s decision will be upheld or whether the PUCT will file a complaint at the FERC. Pending further clarification, TCC and TNC have not reversed their related provisions for fuel over-recovery. If the PUCT or another party were to file a complaint at the FERC that results in the PUCT’s decisions being reinstated, it could result in an adverse effect on results of operations and cash flows for the AEP East companies because an unfavorable FERC ruling may result in a 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 from their customers due to past frozen rates, past inactive fuel clauses and fuel clauses that do not include off-system sales credits.

Carrying Costs on Net True-up Regulatory Assets Impacting Securitization and CTC Proceedings

In TCC’s True-up Proceeding, the PUCT allowed TCC to recover carrying costs at an 11.79% overall pretax weighted average cost of capital rate approved in its unbundled cost of service rate proceeding. The recorded embedded debt component of this carrying cost rate is 8.12%. Through September 30, 2006, TCC recorded $400 million of debt-related carrying costs on stranded generation plant costs included in the securitization proceeding. Equity carrying costs of $224 million related to amounts securitized will be recognized in income as collected. TCC will accrue interest expense until its net CTC refund is fully refunded. The interest expense on the net CTC refund totals $9 million and $11 million for the three and nine months ended September 30, 2006, respectively, and is included in Interest Expense on TCC’s Condensed Consolidated Statements of Income.

In June 2006, the PUCT adopted a proposed rule that prospectively changes the interest rate applied to TCC’s CTC refund balance. TCC anticipates that the rule change will reduce the rate TCC will pay on its CTC balance from 11.79% to 7.47%. TCC anticipates that the change will reduce its annual refund by approximately $8 million. The rule also provides for adjustments to the rate during subsequent rate case proceedings.

TNC True-up Proceeding

TNC filed a CTC proceeding in August 2005 to establish a rate to refund its net true-up regulatory liability. In December 2005, that proceeding was abated, pending a final ruling from TNC’s appeal to the federal court regarding the fuel proceeding (described above). In August 2006, the parties to TNC’s CTC proceeding filed a settlement that recommended implementing an interim refund of the true-up regulatory liability totaling $13 million, net of the amounts at issue in the federal court proceeding, over six months beginning in September 2006. In late August 2006, the PUCT approved the settlement and the net refund began in September 2006. TNC accrues interest expense on the unrefunded balance and will continue to do so until the balance is fully refunded.

Excess Earnings

As noted in the 2005 Annual Report, 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 was unlawful under the Texas Restructuring Legislation. 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. Management is unable to predict the ultimate outcome of these proceedings.

Summary

TCC’s recorded securitizable true-up regulatory asset at September 30, 2006 of $1.57 billion, net of the recorded net regulatory liabilities for other true-up items of $238 million, reflects the PUCT’s orders in TCC’s True-up Proceeding and its securitization proceeding. Barring any future disallowances to TCC’s net recoverable true-up regulatory asset in any subsequent proceedings or court rulings, TCC will amortize its total securitizable true-up regulatory asset commensurate with recovery over the 14-year term of the securitized bonds issued in October 2006. If TCC determines, as a result of future PUCT orders or appeal court rulings, that it is probable TCC cannot recover a portion of its recorded net true-up regulatory asset and TCC is able to estimate the amount of a resultant impairment, it would record a provision for such amount which would have an adverse effect on future results of operations, cash flows and possibly financial condition. Based on advice of Texas rate counsel, TCC appealed the PUCT orders seeking relief in both state and federal court where TCC believes the PUCT’s rulings are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law. Municipal customers and other intervenors also appealed the same PUCT orders seeking to further reduce TCC’s true-up recoveries.
 
Although TCC believes it has meritorious arguments, management cannot predict the ultimate outcome of any future proceedings or court appeals. If TCC succeeds in future appeals, it could have a material favorable effect on TCC’s future results of operations, cash flows and financial condition. If municipal customers and other intervenors succeed in their appeals, or if the PUCT does not approve TCC’s CTC filing as filed and, as a result, causes a normalization violation, it could have a material adverse effect on TCC’s future results of operations, cash flows and financial condition.

Texas Restructuring - SPP

In August 2006, the PUCT adopted a rule delaying customer choice in the SPP area of Texas until no sooner than January 1, 2011. SWEPCo and a small portion of TNC’s business operate in SPP. Approximately 3% of TNC’s operations are located in the SPP territory, with $13 million in net assets 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) and TNC’s customers, facilities and certificated service located in the SPP area to SWEPCo. If this petition is successful, SWEPCo will be AEP’s only subsidiary affected by the delay in the SPP area.

OHIO RESTRUCTURING - Affecting CSPCo and OPCo

Rate Stabilization Plans

In January 2005, the PUCO approved Rate Stabilization Plans (RSPs) for CSPCo and OPCo (the Ohio companies). The approved plans in each of 2006, 2007 and 2008 provide, among other things, for CSPCo and OPCo to raise their generation rates by 3% and 7%, respectively, and provide for possible additional annual generation rate increases of up to an average of 4% per year based on supporting the request for additional revenues for specified costs. CSPCo’s potential for the additional annual 4% generation rate increases is diminished by approximately three-quarters in 2006 and to a lesser extent in 2007 and 2008 due to the power acquisition rider approved by the PUCO in the Monongahela Power service territory acquisition proceeding and the recovery of pre-construction costs for its share of the jointly-owned IGCC plant (see “IGCC Plant” section of this note below). OPCo’s potential for additional annual 4% generation rate increases is diminished in 2006 by approximately one-quarter and to a lesser extent in 2007 due to the recovery of pre-construction costs for its share of the jointly-owned IGCC plant. The RSPs also provide that the Ohio companies can recover in 2006, 2007 and 2008 estimated 2004 and 2005 deferred environmental carrying costs and PJM-related administrative costs and congestion costs net of financial transmission rights (FTR) revenue related to their obligation as the Provider of Last Resort (POLR) in Ohio’s customer choice program. Pretax earnings increased by $10 million and $26 million for CSPCo and $20 million and $58 million for OPCo in the third quarter and first nine months of 2006, respectively, from the RSP rate increases net of the amortization of RSP regulatory assets. These increases also include the recognition of equity carrying costs. As of September 30, 2006, CSPCo’s and OPCo’s unrecognized equity carrying costs from 2004 and 2005, which are recognized over the three-year RSP period, totaled $4 million and $28 million, respectively. As of September 30, 2006, CSPCo’s and OPCo’s unamortized RSP regulatory assets to be recovered through December 31, 2008 were $7 million and $36 million, respectively.

In the second quarter of 2005, the Ohio Consumers’ Counsel filed an appeal to the Ohio Supreme Court that challenged the RSPs and also argued that there was no POLR obligation in Ohio and, therefore, CSPCo and OPCo are not entitled to recover any POLR charges. In DP&L’s proceeding, the Ohio Supreme Court concluded that there is a POLR obligation in Ohio, supporting the Ohio companies’ position that they can recover a POLR charge. In an appeal concerning First Energy companies’ RSP, the Ohio Supreme Court held that the PUCO’s decision to eliminate the offer to customers of a price determined through competitive bids was unlawful. In July 2006, the Ohio Supreme Court vacated the PUCO’s RSP order for the Ohio companies, which also did not include a competitive bid process, and remanded the case to the PUCO for further proceedings, not inconsistent with the decision in the appeal of the First Energy companies’ RSP. In August 2006, the PUCO acted on the Ohio companies’ remand case ordering them to file a plan to provide an option for customer participation in the electric market through competitive bids or other reasonable means and also held that the RSP shall remain effective. Accordingly, the Ohio companies continued to collect RSP revenues. In accordance with the PUCO directive, in September 2006, CSPCo and OPCo submitted their proposal to provide additional options for customer participation in the electric market.

In the Ohio companies’ case, the Ohio Supreme Court did not address any other issues that had been raised on appeal, stating that its decision does not preclude the Ohio Consumers’ Counsel from raising those issues in a future appeal. Management believes that the RSP regulatory assets remain probable of recovery and that the Ohio companies will continue to collect RSP revenues.

IGCC Plant

In March 2005, the Ohio companies filed a joint application with the PUCO seeking authority to recover costs related to building and operating a new 600 MW IGCC power plant using clean-coal technology. The application proposed cost recovery associated with the IGCC plant in three phases: 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 projected $1.2 billion cost of the plant 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 the Ohio companies could request in 2006, 2007 and 2008 under their RSPs. As of September 30, 2006, CSPCo and OPCo each deferred $8 million and each recovered $3 million of pre-construction IGCC costs. We are currently recovering the remaining deferred amounts through June 30, 2007.

In April 2006, the PUCO issued an order authorizing the Ohio companies 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. In its June order, the PUCO indicated if the Ohio companies have not commenced continuous construction of the IGCC plant within five years of the order, all charges collected for pre-construction costs, which are assignable to other jurisdictions, must be refunded to Ohio ratepayers with interest. The PUCO deferred ruling on Phases 2 and 3 cost recovery until further hearings are held. No date for a further hearing has been set.

In June 2006, the Industrial Energy Users - Ohio (IEU), an intervenor in the PUCO proceeding, filed a Complaint for Writ of Prohibition at the Ohio Supreme Court to prohibit the use of the PUCO’s authorization by the Ohio companies to enforce the collection of the Phase 1 rates and to prohibit the PUCO from further entertaining any increase in rates for the IGCC project. The Court subsequently granted a PUCO motion to dismiss the Complaint for Writ of Prohibition.

In August 2006, IEU, Ohio Consumers’ Counsel, FirstEnergy Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order in the IGCC proceeding. The Ohio companies believe that the PUCO’s authorization to begin collection of Phase 1 rates is lawful. The Ohio companies, however, cannot predict the outcome of these appeals. If the PUCO’s order is found to be unlawful, the Ohio companies’ future results of operations and cash flows will be adversely affected.

Transmission Rate Filing

In accordance with the RSPs, in December 2005, the PUCO approved the recovery of certain RTO transmission costs through separate transmission cost recovery riders for the Ohio companies. The transmission cost recovery riders are subject to an annual true-up process with over/under recovery mechanisms. In February 2006, the Ohio companies filed a request with the PUCO to incorporate all transmission costs and rates in their transmission cost recovery riders and institute a two-step increase to reflect the increases in the FERC-approved rates. In the filing, the first increase would be effective April 1, 2006 to reflect the Ohio companies’ share of the loss of SECA revenues and the second increase would be effective August 1, 2006 to recover their share of the cost of the new Wyoming-Jacksons Ferry 765 kV line. In May 2006, the PUCO issued an order approving a two-step increase in the transmission cost recovery riders with over/under recovery mechanisms, effective April 1, 2006. The new tariffs were filed with the PUCO and implemented in June 2006.

In October 2006, the Ohio companies filed for initial true-ups under the transmission cost recovery riders’ over/under recovery mechanisms. The filings reflect the refund of regulatory liabilities as of September 30, 2006 of $12 million and $16 million for CSPCo and OPCo, respectively, including carrying charges. These over-recoveries were reflected as part of the new transmission cost recovery rider filed to be effective January 2007. The Ohio companies anticipate the net effect of the new transmission cost recovery riders will result in increased cost recoveries over 2005 levels for CSPCo and OPCo of $27 million and $36 million, respectively, in 2006 and $15 million and $16 million, respectively, in 2007.

Distribution Service Reliability and Restoration Costs 

In December 2003, the Ohio companies entered into a stipulation agreement regarding distribution service reliability. The stipulation agreement covered the years 2004 and 2005 and, among other features, established certain distribution service reliability measures that the Ohio companies were to meet. In July 2006, based on the staff report on service reliability and responses filed by the Ohio companies, the PUCO directed the Ohio companies to earmark $10 million for future measures to improve service reliability without recovery. The PUCO further indicated that it will determine where and how the $10 million will best be applied.

In March 2006, the Ohio companies filed an application with the PUCO to implement tariff riders to recover a portion of previously expensed incremental costs of restoring service disrupted by severe winter storms in December 2004 and January 2005. CSPCo and OPCo each requested recovery of approximately $12 million of such costs, which was approved by the PUCO in August 2006. Effective September 1, 2006, the Ohio companies implemented the storm cost recovery riders, which will continue until they have collected the authorized amounts or one year, whichever is shorter. In September 2006, the Ohio Consumers’ Counsel filed a request for rehearing with the PUCO, which was denied in October 2006.

As a result of the above, in September 2006 CSPCo and OPCo each recorded regulatory assets of $7 million, favorably affecting earnings.

Ormet
 
In June 2006, the PUCO found that South Central Power Company (SCP), a nonaffiliate, was not providing or proposing to provide physically adequate service to Ormet Primary Aluminum Corporation and Ormet Primary Mill Products Corporation (together, Ormet). In October 2006, the PUCO convened a hearing to determine if an electric supplier, other than SCP, should be authorized to serve Ormet’s 520 MW load.

Subsequent to the hearing, the Ohio companies together with Ormet, its employees’ union and certain other interested parties filed a settlement agreement with the PUCO for approval. The settlement agreement provides for the reallocation of the service territories of CSPCo, OPCo and SCP so that Ormet’s Hannibal, Ohio facilities are located in a joint CSPCo/OPCo certified territory effective January 1, 2007. The settlement also provides for the recovery in 2007 and 2008 by CSPCo and OPCo of the difference between $43 per MWH paid by Ormet and a to-be-determined market price submitted by management and reviewed by the PUCO. The recovery is accomplished by the amortization to income 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 RSP. The $43 per MWH price for generation services is above the industrial RSP generation tariff but below current market prices.

Customer Choice Deferrals

As provided in stipulation agreements approved by the PUCO in 2000, the Ohio companies defer customer choice implementation costs and related carrying costs in excess of $20 million each. The agreements provide for the deferral of these costs as regulatory assets until the next distribution base rate cases. Through September 30, 2006, CSPCo and OPCo incurred $48 million and $49 million, respectively, of such costs and, accordingly, deferred $24 million each of such costs for probable future recovery in distribution rates. CSPCo and OPCo have not recorded $4 million and $5 million, respectively, of equity carrying costs, which are not recognized until collected. Pursuant to the RSPs, recovery of these amounts is subject to PUCO review and is deferred until the next distribution rate filing to change rates after the December 31, 2008 end of the RSP period. Management believes that the deferred customer choice implementation costs were prudently incurred to implement customer choice in Ohio and should be recoverable in future distribution rates. If the PUCO determines that any of the deferred costs are unrecoverable, it would have an adverse impact on the Ohio companies’ future results of operations and cash flows.

        5. COMMITMENTS AND CONTINGENCIES

As discussed in the Commitments and Contingencies note within the 2005 Annual Report, certain Registrant Subsidiaries continue to be involved in various legal matters. The 2005 Annual Report should be read in conjunction with this report in order to understand the other material nuclear and operational matters without significant changes since their disclosure in the 2005 Annual Report. See disclosure below for significant matters and changes in status subsequent to the disclosure made in the 2005 Annual Report.

ENVIRONMENTAL

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

The Federal EPA and a number of states alleged 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 court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications occurred at our generating units over a 20-year period. A bench trial on the liability issues was held during July 2005. Briefing has concluded. In June 2006, the judge stayed the liability decision pending the issuance of a decision by the U.S. Supreme Court in the Duke Energy case. A bench trial on remedy issues, if necessary, is scheduled to begin four months after the U.S. Supreme Court decision is issued.

Under the CAA, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components or other repairs needed for the reliable, safe and efficient operation of the plant. 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 one case. The Federal EPA issued a final rule that would exclude activities similar to those challenged in these cases from NSR as “routine replacements.” In March 2006, the Court of Appeals for the District of Columbia Circuit issued a decision vacating the rule. The Federal EPA filed a petition for rehearing in that case, which the Court denied. The Federal EPA also recently proposed a rule that would define “emissions increases” in a way that would exclude most of the challenged activities from NSR.

Management is unable to estimate the loss or range of loss related to any contingent liability 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 July 2004, two special interest groups, Sierra Club and Public Citizen, issued a notice of intent to commence a citizen suit under the CAA for alleged violations of various permit conditions in permits issued to several SWEPCo generating plants. In March 2005, the special interest groups filed a complaint in Federal District Court for the Eastern District of Texas alleging violations of the CAA at Welsh Plant. SWEPCo filed a response to the complaint in May 2005. Other preliminary motions have been filed and are pending before the Court.

In July 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.

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, financial condition or cash flows.

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

In July 2004, attorneys general from eight states and the corporation counsel for 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. That same day, the Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint in the same court against the same defendants. The actions alleged that CO2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts associated with global warming and sought injunctive relief in the form of specific emission reduction commitments from the defendants. In September 2004, the defendants, including AEP and AEPSC, filed a motion to dismiss the lawsuits. In September 2005, the lawsuits were dismissed. The trial court’s dismissal was appealed to the Second Circuit Court of Appeals. Briefing and oral argument have been completed. Management believes the actions are without merit and intends to defend against the claims.

Ontario Litigation - Affecting CSPCo and OPCo

In June 2005, CSPCo, OPCo and nineteen nonaffiliated utilities were named as defendants in a lawsuit filed in the Superior Court of Justice in Ontario, Canada. CSPCo and OPCo have not been served with the lawsuit. The time limit for serving the defendants expired but the case has not been dismissed. The defendants are alleged to own or operate coal-fired electric generating stations in various states that, through negligence in design, management, maintenance and operation, emitted NOX, SO2 and particulate matter that harmed the residents of Ontario. The lawsuit seeks class action designation and damages of approximately $49 billion, with continuing damages of $4 billion annually. The lawsuit also seeks $1 billion in punitive damages. Management believes CSPCo and OPCo have meritorious defenses to this action and intend to defend against it.

OPERATIONAL

Power Generation Facility and TEM Litigation - Affecting OPCo

AEP has agreements with Juniper Capital L.P. (Juniper) under which Juniper constructed and financed a merchant power generation facility (Facility) near Plaquemine, Louisiana and leased the Facility to AEP. AEP subleased the Facility to the Dow Chemical Company (Dow). The Facility is a Dow-operated “qualifying cogeneration facility” for purposes of PURPA. In September 2006, AEP agreed to sell the Facility to Dow.

Dow uses a portion of the energy produced by the Facility and sells the excess energy. OPCo agreed to purchase up to approximately 800 MW of such excess energy from Dow for a 20-year term. Because the Facility is a major steam supply for Dow, Dow is expected to operate the Facility at certain minimum levels, and OPCo is obligated to purchase the energy generated at those minimum operating levels (approximately 270 MW). OPCo sells the purchased energy at market prices in the Entergy sub-region of the Southeastern Electric Reliability Council market.

OPCo agreed to sell up to approximately 800 MW of energy to TEM for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA), at a price that is currently in excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming. Commercial operation for purposes of the PPA began April 2, 2004.

In September 2003, TEM and AEP separately filed declaratory judgment actions in the U.S. District Court for the Southern District of New York. AEP 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 AEP’s breaches. The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) provided a limited guaranty.

In April 2004, OPCo gave notice to TEM that OPCo (a) was suspending performance of its obligations under the PPA; (b) would seek a declaration from the District Court that the PPA was terminated; and (c) would pursue TEM and SUEZ-TRACTEBEL S.A. under the guaranty, seeking damages and the full termination payment value of the PPA.

A bench trial was conducted in March and April 2005. In August 2005, a federal judge ruled that TEM breached the contract and awarded damages to AEP of $123 million plus prejudgment interest. In August 2005, both parties filed motions with the trial court seeking reconsideration of the judgment. AEP asked the court to modify the judgment to (a) award a termination payment to AEP under the terms of the PPA; (b) grant AEP’s attorneys’ fees; and (c) render judgment against SUEZ-TRACTEBEL S.A. on the guaranty. TEM sought reduction of the damages awarded by the court for replacement electric power products made available by OPCo under the PPA. In January 2006, the trial judge granted AEP’s motion for reconsideration concerning TEM’s parent guaranty and increased AEP’s judgment against TEM to $173 million plus prejudgment interest, and denied the remaining motions for reconsideration. In March 2006, the trial judge amended the January 2006 order eliminating the additional $50 million damage award.

In September 2005, TEM posted a letter of credit for $142 million as security pending appeal of the judgment. Both parties have filed Notices of Appeal with the United States Court of Appeals for the Second Circuit. Oral argument is scheduled for December 2006. If the PPA is deemed terminated or found unenforceable by the court ultimately deciding the case, OPCo could be adversely affected to the extent OPCo is unable to find other purchasers of the power with similar contractual terms (if AEP’s sale of the Facility does not close) and to the extent claimed termination value damages are not fully recovered from TEM.

Coal Transportation Dispute - Affecting PSO, TCC and TNC

PSO, TCC, TNC and two nonaffiliated entities, 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 and 2006. 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 January 2006. The arbitration board filed its decision in April 2006, which denied BNSF’s underpayments claim. In May 2006, 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 August 2006, PSO filed its response, to which BNSF filed its reply. Management continues to work toward mitigating the disputed amounts to the extent possible.

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 Nevada utilities' complaint, held that the markets for future delivery were not dysfunctional and that the Nevada utilities failed to demonstrate that the public interest required changes be made to the contracts. In June 2003, the FERC issued an order affirming the ALJ’s decision. The Nevada utilities’ request for a rehearing was denied. The Nevada utilities’ appeal of the FERC order is pending before the U.S. Court of Appeals for the Ninth Circuit. Management is unable to predict the outcome of this proceeding and its impact on future results of operations and cash flows.

COMMITMENTS

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

The Registrant Subsidiaries have substantial construction commitments to support their operations and environmental investments. The following table shows the revised estimated construction expenditures by Registrant Subsidiary for 2006:

   
(in millions)
 
AEGCo
 
$
12
 
APCo
   
928
 
CSPCo
   
319
 
I&M
   
330
 
KPCo
   
54
 
OPCo
   
1,065
 
PSO
   
262
 
SWEPCo
   
315
 
TCC
   
286
 
TNC
   
72
 

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, legal reviews and the ability to access capital.

        6. GUARANTEES

There are certain immaterial liabilities recorded for guarantees in accordance with FIN 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 have entered 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 September 30, 2006, the maximum future payments of the LOCs include $1 million and $4 million for I&M and SWEPCo, respectively, with maturities ranging from December 2006 to March 2007.

SWEPCo

In connection with reducing the cost of the lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCo agreed, under certain conditions, to assume the capital lease obligations and term loan payments of the mining contractor, Sabine Mining Company (Sabine). If Sabine defaults under any of these agreements, SWEPCo’s total future maximum payment exposure is approximately $68 million with maturity dates ranging from February 2007 to February 2012.

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. This guarantee ends upon depletion of reserves and final reclamation is completed. At September 30, 2006, it is estimated the reserves will be depleted in 2029 with final reclamation completed by 2036. The cost for final reclamation during the period 2029 through 2036 is estimated at approximately $39 million.

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 September 30, 2006, TCC entered into sales agreements with a maximum indemnification exposure of $443 million related to the sale price of its generation assets. See “Texas Plants - South Texas Project” and “Texas Plants - TCC and TNC Generation Assets” sections of Note 10 of the 2005 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 September 30, 2006, 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
 
Subsidiary
 
(in millions)
 
APCo
 
$
7
 
CSPCo
   
4
 
I&M
   
5
 
KPCo
   
2
 
OPCo
   
7
 
PSO
   
5
 
SWEPCo
   
5
 
TCC
   
6
 
TNC
   
3
 

     7. COMPANY-WIDE STAFFING AND BUDGET REVIEW

The following table shows the severance benefits expense recorded in 2005 (primarily in Maintenance and Other Operation) resulting from a company-wide staffing and budget review, including the allocation of approximately $19.2 million of severance benefits expense associated with AEPSC employees among the Registrant Subsidiaries. AEGCo has no employees but received allocated expenses.

   
Three Months Ended Sept. 30, 2005
 
Nine Months Ended Sept. 30, 2005
 
Company
 
(in millions)
 
AEGCo
 
$
0.1
 
$
0.3
 
APCo
   
0.6
   
4.5
 
CSPCo
   
0.3
   
2.6
 
I&M
   
0.7
   
4.7
 
KPCo
   
0.4
   
1.1
 
OPCo
   
0.5
   
3.9
 
PSO
   
0.2
   
1.4
 
SWEPCo
   
0.2
   
1.8
 
TCC
   
0.5
   
4.3
 
TNC
   
0.2
   
1.3
 


Remaining accruals, reflected primarily in Current Liabilities - Other, ranged from $8 thousand to $1.1 million as of December 31, 2005, and were settled by June 30, 2006. Payments and accrual adjustments recorded during 2006 were immaterial.

     8. ACQUISITIONS, ASSETS HELD FOR SALE AND ASSET IMPAIRMENTS

ACQUISITIONS

Waterford Plant - Affecting CSPCo

In May 2005, CSPCo signed a purchase and sale agreement with Public Service Enterprise Group Waterford Energy LLC for the purchase of an 821 MW plant in Waterford, Ohio. This transaction was completed in September 2005 for $218 million and the assumption of liabilities of approximately $2 million.

ASSETS HELD FOR SALE

Texas Plants - Oklaunion Power Station - Affecting TCC

In January 2004, TCC signed an agreement to sell its 7.81% share of Oklaunion Power Station for approximately $43 million (subject to closing adjustments) to Golden Spread Electric Cooperative, Inc. (Golden Spread), subject to a right of first refusal by the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsville (the nonaffiliated co-owners). By May 2004, TCC received notice from the nonaffiliated co-owners announcing their decision to exercise their right of first refusal with terms similar to the original agreement. In June 2004 and September 2004, TCC entered into sales agreements with both of the nonaffiliated co-owners for the sale of TCC’s 7.81% ownership of the Oklaunion Power Station. Golden Spread challenged these agreements in State District Court in Dallas County. Golden Spread alleges that the Public Utilities Board of the City of Brownsville exceeded its legal authority and that the Oklahoma Municipal Power Authority did not exercise its right of first refusal in a timely manner. Golden Spread requested that the court declare the nonaffiliated co-owners’ exercise of their rights of first refusal void. The court entered a judgment in favor of Golden Spread in October 2005. TCC and the nonaffiliated co-owners filed an appeal to the Court of Appeals for the Fifth District at Dallas. In May 2006, the Court of Appeals for the Fifth District at Dallas reversed the trial court’s judgment in favor of Golden Spread and held that the City of Brownsville properly exercised its right of first refusal to acquire TCC’s share of Oklaunion. Golden Spread requested a rehearing in the matter, and its petition was denied. Golden Spread then appealed to the Supreme Court of Texas and in August 2006, the court requested a response from TCC, the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsville. Responses were due October 27, 2006. TCC cannot predict when these issues will be resolved. TCC does not expect the sale to have a significant effect on its future results of operations. TCC’s assets related to the Oklaunion Power Station are classified as Assets Held for Sale - Texas Generation Plants on TCC’s Condensed Consolidated Balance Sheets at September 30, 2006 and December 31, 2005. 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.

Assets Held for Sale at September 30, 2006 and December 31, 2005 are as follows:

Texas Plants (TCC)
 
September 30, 2006
 
December 31, 2005
 
Assets:
 
(in millions)
Other Current Assets
 
$
2
 
$
1
 
Property, Plant and Equipment, Net
   
44
   
43
 
Total Assets Held for Sale - Texas Generation Plants
 
$
46
 
$
44
 

ASSET IMPAIRMENTS

Conesville Units 1 and 2 - Affecting CSPCo

In the third quarter of 2005, following an extensive review of the commercial viability of CSPCo’s Conesville Units 1 and 2, CSPCo committed to a plan to retire these units before the end of their previously estimated useful lives. As a result, Conesville Units 1 and 2 were considered retired as of the third quarter of 2005.

CSPCo recognized a pretax charge of approximately $39 million in the third quarter of 2005 related to its decision to retire the units. CSPCo classified the impairment amount in Asset Impairments and Other Related Charges on its Condensed Consolidated Statements of Income.

        9. BENEFIT PLANS

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in AEP sponsored U.S. 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.

The following tables provide the components of AEP’s net periodic benefit cost for the plans for the three and nine months ended September 30, 2006 and 2005:
Three Months Ended September 30, 2006 and 2005:
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
   
2006
 
2005
 
2006
 
2005
 
   
(in millions)
 
Service Cost
 
$
23
 
$
23
 
$
10
 
$
10
 
Interest Cost
   
57
   
57
   
26
   
26
 
Expected Return on Plan Assets
   
(82
)
 
(77
)
 
(24
)
 
(23
)
Amortization of Transition (Asset) Obligation
   
-
   
(1
)
 
7
   
6
 
Amortization of Net Actuarial Loss
   
20
   
13
   
5
   
5
 
Net Periodic Benefit Cost
 
$
18
 
$
15
 
$
24
 
$
24
 

Nine Months Ended September 30, 2006 and 2005:
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
   
2006
 
2005
 
2006
 
2005
 
   
(in millions)
 
Service Cost
 
$
71
 
$
69
 
$
30
 
$
31
 
Interest Cost
   
171
   
169
   
76
   
79
 
Expected Return on Plan Assets
   
(248
)
 
(232
)
 
(70
)
 
(68
)
Amortization of Transition (Asset) Obligation
   
-
   
(1
)
 
21
   
20
 
Amortization of Net Actuarial Loss
   
59
   
40
   
15
   
19
 
Net Periodic Benefit Cost
 
$
53
 
$
45
 
$
72
 
$
81
 

The following table provides the net periodic benefit cost (credit) for the three and nine months ended September 30, 2006 and 2005:

Three Months Ended September 30, 2006 and 2005:
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
   
2006
 
2005
 
2006
 
2005
 
   
(in thousands)
 
APCo
 
$
1,469
 
$
1,848
 
$
4,487
 
$
4,756
 
CSPCo
   
205
   
534
   
1,807
   
1,928
 
I&M
   
2,331
   
2,365
   
2,949
   
3,134
 
KPCo
   
360
   
376
   
512
   
515
 
OPCo
   
823
   
1,206
   
3,395
   
3,353
 
PSO
   
979
   
72
   
1,588
   
1,661
 
SWEPCo
   
1,222
   
364
   
1,578
   
1,642
 
TCC
   
772
   
(219
)
 
1,699
   
1,789
 
TNC
   
326
   
41
   
715
   
784
 

Nine Months Ended September 30, 2006 and 2005:
 
Pension Plans
 
Other Postretirement
Benefit Plans
 
   
2006
 
2005
 
2006
 
2005
 
   
(in thousands)
 
APCo
 
$
4,406
 
$
5,544
 
$
13,465
 
$
15,248
 
CSPCo
   
615
   
1,602
   
5,417
   
6,273
 
I&M
   
6,992
   
7,095
   
8,855
   
10,229
 
KPCo
   
1,076
   
1,128
   
1,538
   
1,689
 
OPCo
   
2,478
   
3,618
   
10,187
   
10,812
 
PSO
   
2,935
   
216
   
4,764
   
5,329
 
SWEPCo
   
3,672
   
1,092
   
4,734
   
5,244
 
TCC
   
2,317
   
(657
)
 
5,091
   
5,732
 
TNC
   
978
   
123
   
2,145
   
2,507
 

        10. INCOME TAXES

In the second quarter of 2006, the Texas state legislature replaced the existing franchise/income tax with a gross margin tax at a 1% rate for electric utilities. Overall, the new law reduces Texas income tax rates and is effective January 1, 2007. The new gross margin tax is income-based for purposes of the application of SFAS 109 “Accounting for Income Taxes.” Based on the new law, management reviewed deferred tax liabilities with consideration given to the rate changes and changes to the allowed deductible items with temporary differences. As a result, in the second quarter of 2006 the following adjustments were recorded (in thousands):
 
Company
 
 Decrease in SFAS 109 Regulatory Asset, Net
 
 
Decrease in State Income Tax Expense
 
 Decrease in Deferred State Income Tax Liabilities
 
TCC
 
$
36,315
 
$
-
 
$
36,315
 
TNC
   
4,801
   
1,265
   
6,066
 
PSO
   
-
   
3,273
   
3,273
 
SWEPCo
   
4,438
   
501
   
4,939
 

        11. 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. 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 bundled cost-based rates and regulatory oversight on the business process, cost structures and operating results.

        12. FINANCING ACTIVITIES 

Long-term Debt

Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2006 were:

Company
 
Type of Debt
 
Principal Amount
 
Interest Rate
 
Due Date
       
(in thousands)
 
(%)
   
Issuances:
                 
APCo
 
Pollution Control Bonds
 
$
50,275
 
Variable
 
2036
APCo
 
Senior Unsecured Notes
   
250,000
 
5.55
 
2011
APCo
 
Senior Unsecured Notes
   
250,000
 
6.375
 
2036
I&M
 
Pollution Control Bonds
   
50,000
 
Variable
 
2025
OPCo
 
Pollution Control Bonds
   
65,000
 
Variable
 
2036
OPCo
 
Senior Unsecured Notes
   
350,000
 
6.00
 
2016
PSO
 
Senior Unsecured Notes
   
150,000
 
6.15
 
2016
SWEPCo
 
Pollution Control Bonds
   
81,700
 
Variable
 
2018


Company
 
Type of Debt
 
Principal Amount
 
Interest Rate
 
Due Date
       
(in thousands)
 
(%)
   
Retirements and Principal Payments:
                 
APCo
 
First Mortgage Bonds
 
$
100,000
 
6.80
 
2006
APCo
 
Other
   
8
 
13.718
 
2026
I&M
 
Pollution Control Bonds
   
50,000
 
6.55
 
2025
OPCo
 
Notes Payable
   
4,390
 
6.81
 
2008
OPCo
 
Notes Payable
   
6,500
 
6.27
 
2009
SWEPCo
 
Notes Payable
   
5,039
 
4.47
 
2011
SWEPCo
 
Notes Payable
   
2,250
 
Variable
 
2008
SWEPCo
 
Pollution Control Bonds
   
81,700
 
6.10
 
2018
TCC
 
Securitization Bonds
   
52,265
 
5.01
 
2010

In addition to the transactions reported in the tables above, the following table lists intercompany issuances and retirements of debt due to AEP:

Company
 
Type of Debt
 
Principal Amount
 
Interest Rate
 
Due Date
       
(in thousands)
 
(%)
   
Issuances:
                 
TCC
 
Notes Payable
 
$
125,000
 
5.14
 
2007
TCC
 
Notes Payable
   
70,000
 
5.86
 
2007
                   
Retirements:
                 
KPCo
 
Notes Payable
   
40,000
 
6.501
 
2006
OPCo
 
Notes Payable
   
200,000
 
3.32
 
2006
PSO
 
Notes Payable
   
50,000
 
3.35
 
2006

In October 2006, TCC issued $1.74 billion in securitization bonds as follows:

Principal
Amount
 
Interest
 
Scheduled Final Payment
 
Rate
 
Date
 
(in thousands)
 
(%)
   
           
$
217,000
 
4.98
 
2010
 
341,000
 
4.98
 
2013
 
250,000
 
5.09
 
2015
 
437,000
 
5.17
 
2018
 
494,700
 
5.3063
 
2020

The proceeds will be used to retire TCC debt and equity, which are no longer needed to support stranded costs.

In October 2006, TCC retired $345 million in intercompany notes payable as follows:

Principal
Amount
 
Interest
 
Due
 
Rate
 
Date
 
(in thousands)
 
(%)
   
           
$
150,000
 
4.58
 
2007
 
125,000
 
5.14
 
2007
 
70,000
 
5.86
 
2007

In October 2006, I&M had a required remarketing of $65 million of 2.625% pollution control bonds, which were converted from a three-year fixed rate mode to an auction rate mode.

In November 2006, APCo had a required remarketing of $30 million of 2.80% pollution control bonds, which were converted from a three-year fixed rate mode to an auction rate mode.

In November 2006, APCo issued $17.5 million of variable rate pollution control bonds and retired $17.5 million, 2.70% pollution control bonds due in 2007.

In November 2006, $100.6 million of pollution control bonds were put back to TCC on the put date of November 1, 2006. TCC intends to hold these bonds for reissuance at a later date.

Lines of Credit - 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 Utility Money Pool participants’ money pool activity and corresponding authorized limits for the nine months ended September 30, 2006 are described in the following table:
 
Company
 
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 September 30, 2006
 
Authorized Short-Term Borrowing Limit
 
   
(in thousands)
 
AEGCo
 
$
58,209
 
$
2,247
 
$
21,005
 
$
2,247
 
$
(14,938
)
$
125,000
 
APCo
   
283,872
   
314,064
   
200,248
   
194,781
   
93,764
   
600,000
 
CSPCo
   
48,337
   
95,977
   
15,133
   
35,929
   
60,417
   
350,000
 
I&M
   
128,071
   
-
   
64,123
   
-
   
(27,616
)
 
500,000
 
KPCo
   
46,156
   
11,993
   
24,285
   
4,384
   
(24,507
)
 
200,000
 
OPCo
   
351,302
   
40,382
   
100,212
   
15,845
   
(48,163
)
 
600,000
 
PSO
   
167,456
   
146,657
   
97,332
   
94,937
   
43,538
   
300,000
 
SWEPCo
   
127,291
   
24,209
   
56,984
   
10,722
   
7,018
   
350,000
 
TCC
   
117,429
   
49,193
   
44,416
   
23,779
   
25,304
   
600,000
 
TNC
   
22,218
   
34,574
   
6,269
   
8,381
   
(9,492
)
 
250,000
 
TNC (a)
   
10
   
13,947
   
8
   
13,834
   
13,875
   
-
 

The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool for the nine months ended September 30, 2006 were 5.41% and 3.63%. The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool for the nine months ended September 30, 2005 were 3.93% and 1.63%. The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2006 and 2005 are summarized for all Registrant Subsidiaries in the following table:

Company
 
Average Interest Rate for Funds Borrowed from the Utility Money Pool for Nine Months Ended
September 30, 2006
 
Average Interest Rate for Funds Borrowed from the Utility Money Pool for Nine Months Ended
September 30, 2005
 
Average Interest Rate for Funds Loaned to the Utility Money Pool for Nine Months Ended
September 30, 2006
 
Average Interest Rate for Funds Loaned to the
Utility Money Pool
for Nine Months Ended September 30, 2005
 
   
(in percentage)
 
AEGCo
   
4.85
   
2.91
   
5.11
   
3.14
 
APCo
   
4.62
   
3.30
   
4.98
   
2.72
 
CSPCo
   
4.73
   
3.92
   
4.63
   
2.76
 
I&M
   
4.81
   
3.25
   
-
   
2.12
 
KPCo
   
4.92
   
3.52
   
4.97
   
2.54
 
OPCo
   
4.83
   
3.67
   
5.12
   
2.40
 
PSO
   
5.02
   
2.62
   
4.36
   
3.52
 
SWEPCo
   
5.01
   
3.64
   
4.36
   
2.60
 
TCC
   
4.79
   
3.07
   
4.71
   
2.43
 
TNC
   
4.81
   
-
   
4.56
   
3.13
 
TNC (a)
   
5.36
   
-
   
5.33
   
-
 

(a)
In the third quarter of 2006, TNC created a new wholly-owned subsidiary, AEP Texas North Generation Company, LLC. Following the creation of this subsidiary, TNC transferred all of its mothballed generation assets and related liabilities to this new subsidiary, effectively completing the business separation requirement of the Texas Restructuring Legislation. Subsequently, AEP Texas North Generation Company, LLC became a participant in the Nonutility Money Pool. For the nine months ended September 30, 2006, the maximum and minimum interest rates for funds either borrowed from or loaned to the Nonutility Money Pool were 5.39% and 5.28% respectively.
 

 

 
COMBINED MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the management’s discussion and analysis of Registrant Subsidiaries. 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 Registrants Subsidiaries section of the 2005 Annual Report should also be read in conjunction with this report.

Construction Expenditures

The Registrant Subsidiaries have substantial construction commitments to support their operations and environmental investments. The following table shows the revised estimated construction expenditures by Registrant Subsidiary for 2006:

   
(in millions)
 
AEGCo
 
$
12
 
APCo
   
928
 
CSPCo
   
319
 
I&M
   
330
 
KPCo
   
54
 
OPCo
   
1,065
 
PSO
   
262
 
SWEPCo
   
315
 
TCC
   
286
 
TNC
   
72
 

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, legal reviews and the ability to access capital.

Environmental Matters

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

·
Requirements under the CAA to reduce emissions of SO2, NOx, particulate matter, and mercury from fossil fuel-fired power plants;
·
Requirements under the Clean Water Act to reduce the impacts of water intake structures on aquatic species at certain power plants; and
·
Possible future requirements to reduce carbon dioxide emissions to address concerns about global climate change.

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.

Environmental Litigation

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

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

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

Management is unable to estimate the loss or range of loss related to any contingent liability 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 yet 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

Beginning in 2006, the Registrant Subsidiaries adopted SFAS No. 123 (revised 2004) Share-Based Payment, on a modified prospective basis, resulting in an insignificant favorable cumulative effect of a change in accounting principle. Including stock-based compensation expense related to employee stock options and other share based awards, did not materially affect the Registrant Subsidiaries’ quarter-over-quarter and year-to-date net income (loss). See Note 2 - New Accounting Pronouncements in the Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries for further discussion.

 

 
CONTROLS AND PROCEDURES

During the third quarter of 2006, 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 September 30, 2006, 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.

There was no 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 third quarter of 2006 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal controls over financial reporting.
 

 

 
PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of material legal proceedings, see Note 5, Commitments and Contingencies, incorporated herein by reference.

Item 1A. Risk Factors

Our Annual Report on Form 10-K for the year ended December 31, 2005 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 2005 Annual Report on Form 10-K.

General Risks of Our Regulated Operations

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

In September 2006, based on a report by the Hearing Examiner in our Virginia Environmental and Reliability costs rate case, we wrote off all of the regulatory asset related to environmental controls, transmission costs (including line construction) and other system reliability work incurred July 2004 through September 2006, adversely affecting pretax earnings by $36 million.

In addition, APCo filed a request with the Virginia SCC in May 2006 seeking an increase in base rates of $225 million to recover increasing costs, including a return on equity of 11.5%. APCo also requested to apply 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. This proposed off-system sales fuel rate credit is projected to be $27 million annually. It would partially offset the $225 million requested increase in base rates for a net increase in revenues of $198 million. In May 2006, the Virginia SCC issued an order placing the full requested base rate increase into effect as of October 2, 2006, subject to refund. In October 2006, the Virginia SCC staff filed their direct testimony recommending a base rate increase of $13 million. Other intervenors have recommended base rate increases ranging from $42 million to $112 million. APCo plans to file rebuttal testimony in November 2006. Hearings are scheduled to begin in December 2006.

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

The West Virginia Public Service Commission approved our pending West Virginia base rate case settlement agreement in July 2006. Therefore, this risk factor is no longer applicable.

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

The Kentucky Public Service Commission approved our pending Kentucky base rate case settlement agreement in March 2006. Therefore, this risk factor is no longer applicable.

The rates that SWEPCo may charge its customers may be reduced. (Applies to SWEPCo)

In October 2005, the staff of the PUCT reported results of its review of SWEPCo’s year-end 2004 earnings. Based upon the staff’s adjustments to the information submitted by SWEPCo, the report indicates that SWEPCo is receiving excess revenues of approximately $15 million. The staff engaged SWEPCo in discussions to reconcile the earnings calculation and consider possible ways to address the results. After those discussions, the PUCT staff informed SWEPCo in April 2006 that they would not pursue the matter further.

Separately, at the time of the CSW merger, SWEPCo agreed to file with the Louisiana Public Service Commission (LPSC) detailed financial information typically utilized in a revenue requirement filing on a periodic basis in order to demonstrate the lack of adverse impact from the merger. The first such filing was in October 2002 and the second was in April 2004. Both filings indicated SWEPCo’s rates should not be reduced. In April 2006, the LPSC and SWEPCo agreed to update the financial information based on a 2005 test year. SWEPCo filed 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, which included a 10% return on equity. The recommended reduction range is subject to SWEPCo validating certain on-going operations and maintenance expense levels and the recommended base rate reduction does not include the impact of a proposed consolidated federal income tax adjustment, which would increase the proposed rate reduction. SWEPCo filed rebuttal testimony in October 2006 strongly refuting the consultants’ recommendations. Hearings are expected to occur late in the fourth quarter of 2006. A decision is not expected until 2007. At this time, management is unable to predict the outcome of this proceeding. If a rate reduction were ultimately ordered, it would adversely impact future results of operations and cash flows.

In a separate matter in March 2006, the LPSC closed its inquiry into SWEPCo’s fuel and purchased power procurement activities during the period January 1, 2005 through October 31, 2005. The LPSC approved the LPSC staff’s report, which concluded that SWEPCo’s activities were appropriate and did not identify any disallowances or areas for improvement.

Risks Related to Owning and Operating Generating Assets and Selling Power

The amount we charge third parties for using our transmission facilities may be reduced and not recovered. (Applies to AEP and AEP’s East zone public utility subsidiaries.)

In July 2003, the FERC issued an order directing PJM and the MISO to make compliance filings for their respective OATTs to eliminate the transaction-based charges for through and out (T&O) transmission service on transactions where the energy is delivered within the proposed MISO and PJM expanded regions (Combined Footprint). 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 SECA transition rates beginning in December 2004 and extending through March 2006. SECA fees of $220 million were collected subject to refund.

A hearing in the SECA case 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 were 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.

We have reached settlements with certain customers related to approximately $70 million of SECA 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. It would also provide refunds of SECA rates paid by the AEP East companies in considerably less significant amounts. Based on the completed settlements, and before the issuance of the ALJ’s initial decision, the AEP East companies provided for $22 million in net refunds, of which $18 million was recorded in the second quarter of 2006 in Utility Operations Revenues on the Condensed Consolidated Statements of Operations.  

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 SECA billings. The FERC has not yet acted on the motion.

Although we believe we 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.

SECA transition rates have not fully compensated AEP for lost T&O revenues. SECA transition rates expired at the end of March 2006, and all transmission costs that would otherwise have been covered by T&O rates in the Combined Footprint are now subject to recovery from native load customers of AEP’s East zone public utility subsidiaries.
 
Management is unable to predict whether the FERC will approve either the ALJ’s decision or when, and if, the effect of the loss of T&O/SECA transmission revenues will be recoverable on a timely basis in each of the AEP East state retail jurisdictions and/or from transmission users within the PJM region.

Risks Relating to State Restructuring

Our Rate Stabilization Plans in Ohio may be modified by the PUCO such that our deferred costs may not be recovered and rates may be reduced. (Applies to AEP, OPCo and CSPCo)

In January 2005, the PUCO approved Rate Stabilization Plans (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. As of September 30, 2006, the unamortized RSP deferrals were $7 million for CSPCo and $36 million for OPCo.

In the second quarter of 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 May 2006, the Ohio Supreme Court remanded the rate stabilization plan of First Energy on the grounds that it failed to provide customers with a competitive bid generation supply option, as contemplated by the restructuring law. In July 2006, the Ohio Supreme Court vacated the PUCO’s RSP order for CSPCo and OPCo, which did not include a competitive process, and remanded the case to the PUCO for further proceedings.

In August 2006, the PUCO acted on the Ohio companies’ remand case ordering them to file a plan to provide an option for customer participation in the electric market through competitive bids or other reasonable means and also held that the RSP shall remain effective. Accordingly, the Ohio companies continued to collect RSP revenues. In the first nine months of 2006, CSPCo and OPCo have collected an additional $89 million and $87 million, respectively, as a result of the RSPs. In accordance with the PUCO directive, in September 2006, CSPCo and OPCo submitted their proposal to provide additional options for customer participation in the electric market.

We are contractually required to operate a power generation facility that may indirectly force us to sell the facility’s excess energy at a loss. (Applies to AEP.)

We have agreed to lease from Juniper Capital L.P. a merchant power generation facility (“Facility”) near Plaquemine, Louisiana. We sublease the Facility to Dow. We operate the Facility for Dow. Dow uses a portion of the energy produced by the Facility and sells the excess power to us. We have agreed to sell up to all of the excess 800 MW to Tractebel at a price that is currently in excess of market. Tractebel alleged that the power purchase agreement was unenforceable. This agreement is now being litigated. A bench trial was conducted in March and April 2005. In August 2005, a federal judge ruled that Tractebel had breached the contract and awarded us damages of $123 million plus prejudgment interest. Both parties have filed appeals. In January 2006, the trial court increased AEP’s judgment against Tractebel to $173 million plus prejudgment interest. In March 2006, the trial judge amended the January 2006 order to eliminate the additional $50 million damage award. If the trial award is reversed or if Tractebel does not pay the judgment, our cash flow will be adversely affected.

In August 2006, we reached an agreement to sell the Facility to Dow for $64 million. We expect the sale to close in November 2006. We recorded a pretax impairment of $209 million ($136 million, net of tax) in the third quarter of 2006 based on our agreement to sell the Facility to Dow. The sale agreement also allows us to participate in gross margin sharing on the Facility for five years. In addition, Dow will reduce an existing below-current-market long-term power supply contract with us in Texas by 50 MW. We also retain the right to any judgment paid by TEM for breaching the original PPA, as discussed above.

If the sale of the Facility to Dow does not close, we will be required to find new purchasers for up to 800 MW. There can be no assurance that the power produced will be sold at prices that will exceed our costs to produce it. If that were the case, as a result of our obligations to Dow, we would be required to operate the Facility at a loss.

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 September 30, 2006 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
 
07/01/06 - 07/31/06
   
-
       
$
-
   
-
 
$
-
 
08/01/06 - 08/31/06
   
12
   
(a
)
 
73.00
   
-
   
-
 
09/01/06 - 09/30/06
   
30
   
(b
)
 
79.75
   
-
   
-
 

(a)
I&M repurchased 12 shares of its 4-1/8% cumulative preferred stock, in a privately-negotiated transaction outside of an announced program.
(b)
APCo repurchased 30 shares of its 4-1/2% 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: November 6, 2006