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