q207aep10q.htm
 

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 June 30, 2007
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____

Commission
 
Registrant, State of Incorporation,
 
I.R.S. Employer
File Number
 
Address of Principal Executive Offices, and Telephone Number
 
Identification No.
         
1-3525
 
AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation)
 
13-4922640
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
1-6543
 
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 Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company, are large accelerated filers, accelerated filers, or non-accelerated filers.  See definition of ‘accelerated filer and large accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check One)
 
Large accelerated filer                                               Accelerated filer                                             Non-accelerated filer     X  
 
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act).
Yes       
No   X  

Columbus Southern Power Company, Indiana Michigan 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
July 31, 2007
       
American Electric Power Company, Inc.
   
399,203,993
     
($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)
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
June 30, 2007

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

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


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

Term
 
Meaning

ADITC
 
Accumulated Deferred Investment Tax Credits.
AEGCo
 
AEP Generating Company, an AEP electric utility subsidiary.
AEP or Parent
 
American Electric Power Company, Inc.
AEP Consolidated
 
AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit
 
AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated domestic electric utility companies.
AEP East companies
 
APCo, CSPCo, I&M, KPCo and OPCo.
AEP System or the System
 
American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP System Power Pool or AEP
  Power Pool
 
Members are APCo, CSPCo, I&M, KPCo and OPCo.  The Pool shares the generation, cost of generation and resultant wholesale off-system sales of the member companies.
AEPEP
 
AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, asset management and commercial and industrial sales in the deregulated Texas market.
AEPSC
 
American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AEP West companies
 
PSO, SWEPCo, TCC and TNC.
AFUDC
 
Allowance for Funds Used During Construction.
ALJ
 
Administrative Law Judge.
AOCI
 
Accumulated Other Comprehensive Income (Loss).
APCo
 
Appalachian Power Company, an AEP electric utility subsidiary.
ARO
 
Asset Retirement Obligations.
CAA
 
Clean Air Act.
CO2
 
Carbon Dioxide.
Cook Plant
 
Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo
 
Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW
 
Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CTC
 
Competition Transition Charge.
DETM
 
Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
E&R
 
Environmental compliance and transmission and distribution system reliability.
ECAR
 
East Central Area Reliability Council.
EDFIT
 
Excess Deferred Federal Income Taxes.
EITF
 
Financial Accounting Standards Board’s Emerging Issues Task Force.
ERCOT
 
Electric Reliability Council of Texas.
FASB
 
Financial Accounting Standards Board.
Federal EPA
 
United States Environmental Protection Agency.
FERC
 
Federal Energy Regulatory Commission.
FIN
 
FASB Interpretation No.
FIN 46
 
FIN 46, “Consolidation of Variable Interest Entities.”
FIN 48
 
FIN 48, “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1 “Definition of Settlement in FASB Interpretation No. 48.”
GAAP
 
Accounting Principles Generally Accepted in the United States of America.
HPL
 
Houston Pipeline Company, a former AEP subsidiary.
IGCC
 
Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
IPP
 
Independent Power Producer.
IRS
 
Internal Revenue Service.
IURC
 
Indiana Utility Regulatory Commission.
I&M
 
Indiana Michigan Power Company, an AEP electric utility subsidiary.
JMG
 
JMG Funding LP.
KGPCo
 
Kingsport Power Company, an AEP electric distribution subsidiary.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
KPSC
 
Kentucky Public Service Commission.
kV
 
Kilovolt.
KWH
 
Kilowatthour.
LPSC
 
Louisiana Public Service Commission.
MTM
 
Mark-to-Market.
MW
 
Megawatt.
MWH
 
Megawatthour.
NOx
 
Nitrogen oxide.
Nonutility Money Pool
 
AEP System’s Nonutility Money Pool.
NRC
 
Nuclear Regulatory Commission.
NSR
 
New Source Review.
NYMEX
 
New York Mercantile Exchange.
OATT
 
Open Access Transmission Tariff.
OCC
 
Corporation Commission of the State of Oklahoma.
OPCo
 
Ohio Power Company, an AEP electric utility subsidiary.
OTC
 
Over the counter.
OVEC
 
Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PJM
 
Pennsylvania – New Jersey – Maryland regional transmission organization.
PSO
 
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO
 
Public Utilities Commission of Ohio.
PUCT
 
Public Utility Commission of Texas.
Registrant Subsidiaries
 
AEP subsidiaries which are SEC registrants; APCo, CSPCo, I&M, OPCo, PSO, SWEPCo.
REP
 
Texas Retail Electric Provider.
Risk Management Contracts
 
Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
 
A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned by AEGCo and I&M.
RTO
 
Regional Transmission Organization.
S&P
 
Standard and Poor’s.
SEC
 
United States Securities and Exchange Commission.
SECA
 
Seams Elimination Cost Allocation.
SFAS
 
Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board.
SFAS 71
 
Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation.”
SFAS 133
 
Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.”
SFAS 157
 
Statement of Financial Accounting Standards No. 157, “Fair Value Measurements.”
SFAS 158
 
Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.”
SFAS 159
 
Statement of Financial Accounting Standards No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.”
SIA
 
System Integration Agreement.
SO2
 
Sulfur Dioxide.
SPP
 
Southwest Power Pool.
Sweeny
 
Sweeny Cogeneration Limited Partnership, owner and operator of a four unit, 480 MW gas-fired generation facility, owned 50% by AEP.
SWEPCo
 
Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC
 
AEP Texas Central Company, an AEP electric utility subsidiary.
TEM
 
SUEZ Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing, Inc.).
Texas Restructuring Legislation
 
Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC
 
AEP Texas North Company, an AEP electric utility subsidiary.
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.
·
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 the potential for new legislation in Ohio and membership in and integration into regional transmission organizations.
·
Accounting pronouncements periodically issued by accounting standard-setting bodies.
·
The performance of our pension and other postretirement benefit plans.
·
Prices for power that we generate and sell at wholesale.
·
Changes in technology, particularly with respect to new, developing or alternative sources of generation.
·
Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events.


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



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

EXECUTIVE OVERVIEW

Regulatory Activity

The status of base rate filings ongoing or finalized this quarter with implemented rates are:

Operating
Company
 
Jurisdiction
 
Revised Annual  Rate Increase Request
 
Implemented Annual Rate Increase
 
Effective Date of Rate Increase
 
       
(in millions)
     
APCo
 
Virginia
 
$
198
(a)
$
24
(a)
October 2006
 
OPCo
 
Ohio
   
8
   
8
(b)
May 2007
 
CSPCo
 
Ohio
   
24
   
24
(b)
May 2007
 
TCC
 
Texas
   
81
   
70
(b)
June 2007
 
TNC
 
Texas
   
25
   
14
 
June 2007
 
PSO
 
Oklahoma
   
50
   
9
(b)
July 2007
 

(a)
The difference between the requested and implemented amounts of annual rate increase is partially offset by approximately $35 million of incremental E&R costs which APCo anticipates to file for recovery through the E&R surcharge mechanism in 2008.  APCo also requested a net $50 million reduction, beginning September 1, 2007, in credits to customers for off-system sales margins as part of its July 2007 fuel clause filing under the new re-regulation legislation.
(b)
Rate increase is presently subject to refund.  Proceeding is on-going.

In Virginia, APCo filed the following non-base rate requests in July 2007 with the Virginia SCC:

Operating
Company
 
Jurisdiction
 
Cost Type
 
Request
 
Projected Date of Rate Increase
           
(in millions)
   
APCo
 
Virginia
 
Incremental E&R
 
$
60
 
December 2007
APCo
 
Virginia
 
Fuel, Off-system Sales
   
33
 
September 2007

West Virginia IGCC

In June 2007, APCo filed testimony with the WVPSC supporting construction of a 629 MW IGCC plant adjacent to APCo’s existing Mountaineer Generating Station in Mason County, WV.   APCo requested pre-approval of a surcharge rate mechanism to provide for the timely recovery of both the ongoing finance costs of the project during the construction period as well as the capital and operating costs and a return on equity once the facility is placed into commercial operation.  In July 2007, APCo filed a request with the Virginia SCC to recover an estimated $45 million in financing costs on projected IGCC construction work in progress including pre-construction development design and planning costs from July 1, 2007 through December 31, 2009.  If APCo receives all necessary approvals, the plant could be completed as early as mid-2012 for an estimated cost of $2.2 billion.

Indiana Depreciation Study

In June 2007, the IURC approved a settlement agreement allowing I&M to implement reduced book depreciation rates upon the filing by I&M of a general rate petition.  On June 19, 2007, I&M filed its rate petition to be effective on July 1, 2007.  The settlement agreement will result in a reduction of book depreciation expense of $37 million primarily related to the Cook Plant license extension for the period from June 19, 2007 to December 31, 2007, which was offset by a $5 million regulatory liability, recorded in June 2007, to provide for an agreed-upon fuel credit.  I&M expects new base rates including the reduced depreciation to become effective in late 2008 or early 2009.
 
Indiana Rate Cap

Effective July 1, 2007, I&M’s rate cap ended for both base and fuel rates.  I&M’s fuel factor increased effective with July 2007 billings to recover the full projected cost of fuel.  I&M will resume deferring through revenues any under/over-recovered fuel costs for future recovery/refund.

SWEPCo Fuel Reconciliation – Texas

In June 2007, an ALJ issued a Proposal for Decision recommending a $17 million disallowance in SWEPCo's Texas fuel reconciliation proceeding.  Results of operations for the second quarter were adversely affected by $25 million as a result of reflecting the ALJ’s decision.  In July 2007, the PUCT orally affirmed the ALJ report.  A final order is expected in the third quarter of 2007.

Virginia Restructuring

In April 2007, the Virginia legislature re-regulated electric utilities’ generation/supply rates on a cost basis effective July 1, 2007.  We recorded an extraordinary pretax reduction in APCo’s earnings of $118 million ($79 million, net of tax) from reapplication of SFAS 71 regulatory accounting in the second quarter of 2007 as a result of the new re-regulation legislation.

Investment Activity

In the second quarter of 2007, we completed the purchase of the 480 MW Darby Electric Generation Station for $102 million and the purchase of the 1,096 MW Lawrenceburg Generating Station for $325 million.

RESULTS OF OPERATIONS

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

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

MEMCO Operations
·
Barging operations that annually transport approximately 34 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi rivers.  Approximately 35% of the barging operations relates to the transportation of coal, 30% relates to agricultural products, 18% relates to steel and 17% relates to other commodities.

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

The table below presents our consolidated Income Before Discontinued Operations and Extraordinary Loss for the three and six months ended June 30, 2007 and 2006.  We reclassified prior year amounts to conform to the current year’s segment presentation.
   
Three Months Ended June 30,
   
Six Months Ended June 30,
 
   
2007
   
2006
   
2007
   
2006
 
   
(in millions)
 
Utility Operations
  $
238
    $
159
    $
491
    $
524
 
MEMCO Operations
   
7
     
14
     
22
     
35
 
Generation and Marketing
   
15
     
2
     
14
     
6
 
All Other (a)
    (3 )     (3 )    
1
      (15 )
Income Before Discontinued Operations
  and Extraordinary Loss
  $
257
    $
172
    $
528
    $
550
 

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

Second Quarter of 2007 Compared to Second Quarter of 2006

Income Before Discontinued Operations and Extraordinary Loss in 2007 increased $85 million compared to 2006 primarily due to an increase in Utility Operations segment earnings of $79 million.  The increase in Utility Operations segment earnings primarily relates to higher retail margins mostly due to rate increases and favorable weather and increased margins from off-system sales.

Average basic shares outstanding increased to 399 million in 2007 from 394 million in 2006 primarily due to the issuance of shares under our incentive compensation plans.  Actual shares outstanding were 399 million as of June 30, 2007.

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

Income Before Discontinued Operations and Extraordinary Loss in 2007 decreased $22 million compared to 2006 primarily due to a decrease in Utility Operations segment earnings of $33 million.  The decrease in Utility Operations segment earnings primarily relates to higher operation and maintenance expenses, higher regulatory amortization expense and lower earnings-sharing payments from Centrica received in March 2007 representing the last payment of the earnings-sharing agreement.  These decreases in earnings were partially offset by rate increases and favorable weather.

Average basic shares outstanding increased to 398 million in 2007 from 394 million in 2006 primarily due to the issuance of shares under our incentive compensation plans.  Actual shares outstanding were 399 million as of June 30, 2007.

Utility Operations

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

Utility Operations Income Summary
For the Three and Six Months Ended June 30, 2007 and 2006

   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2007
   
2006
   
2007
   
2006
 
   
(in millions)
 
Revenues
  $
2,954
    $
2,796
    $
5,987
    $
5,762
 
Fuel and Purchased Power
   
1,109
     
1,123
     
2,228
     
2,249
 
Gross Margin
   
1,845
     
1,673
     
3,759
     
3,513
 
Depreciation and Amortization
   
365
     
346
     
748
     
686
 
Other Operating Expenses
   
957
     
983
     
1,948
     
1,819
 
Operating Income
   
523
     
344
     
1,063
     
1,008
 
Other Income, Net
   
27
     
44
     
45
     
85
 
Interest Charges and Preferred Stock Dividend   Requirements
   
207
     
161
     
386
     
315
 
Income Tax Expense
   
105
     
68
     
231
     
254
 
Income Before Discontinued Operations and
  Extraordinary Loss
  $
238
    $
159
    $
491
    $
524
 
 

Summary of Selected Sales and Weather Data
For Utility Operations
For the Three and Six Months Ended June 30, 2007 and 2006

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
Energy/Delivery Summary
2007
 
2006
 
2007
 
2006
 
 
(in millions of KWH)
Energy
                       
Retail:
                       
 
Residential
 
10,127
   
9,590
   
24,267
   
22,528
 
 
Commercial
 
10,227
   
9,440
   
19,586
   
18,349
 
 
Industrial
 
14,848
   
13,716
   
28,413
   
26,937
 
 
Miscellaneous
 
632
   
655
   
1,245
   
1,274
 
Total Retail
 
35,834
   
33,401
   
73,511
   
69,088
 
                         
Wholesale
 
9,376
   
10,822
   
18,154
   
21,667
 
                         
Delivery
                       
Texas Wires – Energy delivered to customers served
  by AEP’s Texas Wires Companies
 
6,746
   
6,915
   
12,577
   
12,461
 
Total KWHs
 
51,956
   
51,138
   
104,242
   
103,216
 

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.

Summary of Heating and Cooling Degree Days for Utility Operations
For the Three and Six Months Ended June 30, 2007 and 2006

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
2007
 
2006
 
2007
 
2006
 
 
(in degree days)
Weather Summary
                       
Eastern Region
                       
Actual – Heating (a)
 
222
   
107
   
2,039
   
1,563
 
Normal – Heating (b)
 
174
   
175
   
1,966
   
1,992
 
                         
Actual – Cooling (c)
 
367
   
228
   
382
   
229
 
Normal – Cooling (b)
 
275
   
279
   
278
   
282
 
                         
Western Region (d)
                       
Actual – Heating (a)
 
92
   
5
   
994
   
663
 
Normal – Heating (b)
 
33
   
33
   
991
   
1,005
 
                         
Actual – Cooling (c)
 
622
   
815
   
678
   
858
 
Normal – Cooling (b)
 
656
   
652
   
674
   
669
 

(a)
Eastern region and western region heating degree days are calculated on a 55 degree temperature base.
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
(c)
Eastern region and western region cooling degree days are calculated on a 65 degree temperature base.
(d)
Western region statistics represent PSO/SWEPCo customer base only.
 
Second Quarter of 2007 Compared to Second Quarter of 2006

Reconciliation of Second Quarter of 2006 to Second Quarter of 2007
Income from Utility Operations Before Discontinued Operations and Extraordinary Loss
(in millions)

Second Quarter of 2006
        $
159
 
               
Changes in Gross Margin:
             
Retail Margins
   
72
         
Off-system Sales
   
52
         
Transmission Revenues
   
22
         
Other Revenues
   
26
         
Total Change in Gross Margin
           
172
 
                 
Changes in Operating Expenses and Other:
               
Other Operation and Maintenance
   
26
         
Depreciation and Amortization
    (19 )        
Carrying Costs Income
    (17 )        
Interest and Other Charges
    (46 )        
Total Change in Operating Expenses and Other
            (56 )
                 
Income Tax Expense
            (37 )
                 
Second Quarter of 2007
          $
238
 

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss increased $79 million to $238 million in 2007.  The key drivers of the increase were a $172 million increase in Gross Margin partially offset by a $56 million increase in Operating Expenses and Other and a $37 million increase in Income Tax Expense.

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

·
Retail Margins increased $72 million primarily due to the following:
 
·
A $36 million increase related to new rates implemented in our Ohio jurisdictions as approved by the PUCO in our RSP’s.
 
·
A $36 million increase related to increased residential and commercial usage and customer growth.
 
·
A $24 million increase related to Ormet, a new industrial customer in Ohio.  See “Ormet” section of Note 3.
 
·
A $19 million increase related to increased sales to municipal, cooperative and other customers primarily resulting from new power supply contracts.
 
·
A $26 million increase in usage related to weather.  As compared to the prior year, our eastern region experienced a 61% increase in cooling degree days partially offset by a 24% decrease in cooling degree days in our western region.
 
These increases were partially offset by:
 
·
A $38 million net decrease related to the APCo Virginia base rate case which includes a second quarter 2007 provision for revenue refund as a result of the final order offset by the new rates implemented.  See “Virginia Base Rate Case” section of Note 3.
 
·
A $25 million decrease due to a second quarter 2007 provision related to a SWEPCo Texas fuel reconciliation proceeding.  See “SWEPCo Fuel Reconciliation – Texas” section of Note 3.
 
·
A $21 million decrease in financial transmission rights revenue, net of congestion, primarily due to fewer transmission constraints within the PJM market.
·
Margins from Off-system Sales increased $52 million primarily due to higher power prices in the east and stronger trading margins offset by higher internal load and lower generation availability.
·
Transmission Revenues increased $22 million primarily due to a provision recorded in the second quarter of 2006 related to potential SECA refunds.  See “Transmission Rate Proceedings at the FERC” section of Note 3.
·
Other Revenues increased $26 million primarily due to higher securitization revenue at TCC resulting from the $1.7 billion securitization in October 2006.  Securitization revenue represents amounts collected to recover securitization bond principal and interest payments related to TCC’s securitized transition assets and are fully offset by amortization and interest expenses.

Utility Operating Expenses and Other and Income Taxes changed between years as follows:

·
Other Operation and Maintenance expenses decreased $26 million primarily due to reduced expenses for storm restoration and lower administrative and general expenses.
·
Depreciation and Amortization expense increased $19 million primarily due to increased Ohio regulatory asset amortization related to recovery of IGCC pre-construction costs, increased Texas amortization of the securitized transition assets and higher depreciable property balances, offset by adjustments related to implementation of the final order in the APCo Virginia base rate case.
·
Carrying Costs Income decreased $17 million because TCC started recovering stranded costs in October 2006, thus eliminating future TCC carrying costs income.
·
Interest and Other Charges increased $46 million primarily due to additional debt issued in the fourth quarter of 2006 including TCC securitization bonds.
·
Income Tax Expense increased $37 million due to an increase in pretax income.

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

Reconciliation of Six Months Ended June 30, 2006 to Six Months Ended June 30, 2007
Income from Utility Operations Before Discontinued Operations and Extraordinary Loss
(in millions)
Six Months Ended June 30, 2006
        $
524
 
               
Changes in Gross Margin:
             
Retail Margins
   
210
         
Off-system Sales
   
11
         
Transmission Revenues
    (8 )        
Other Revenues
   
33
         
Total Change in Gross Margin
           
246
 
                 
Changes in Operating Expenses and Other:
               
Other Operation and Maintenance
    (85 )        
Gain on Dispositions of Assets, Net
    (47 )        
Depreciation and Amortization
    (62 )        
Taxes Other Than Income Taxes
   
3
         
Carrying Costs Income
    (39 )        
Other Income, Net
    (1 )        
Interest and Other Charges
    (71 )        
Total Change in Operating Expenses and Other
            (302 )
                 
Income Tax Expense
           
23
 
                 
Six Months Ended June 30, 2007
          $
491
 

Income from Utility Operations Before Discontinued Operations and Extraordinary Loss decreased $33 million to $491 million in 2007.  The key driver of the decrease was a $302 million increase in Operating Expenses and Other, offset by a $246 million increase in Gross Margin and a $23 million decrease in Income Tax Expense.

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

·
Retail Margins increased $210 million primarily due to the following:
 
·
A $71 million increase related to new rates implemented in our Ohio jurisdictions as approved by the PUCO in our RSPs and a $20 million increase related to new rates implemented in other east jurisdictions of Kentucky, West Virginia and Virginia.
 
·
A $70 million increase related to increased residential and commercial usage and customer growth.
 
·
A $66 million increase in usage related to weather.  As compared to the prior year, our eastern region and western region experienced 30% and 50% increases, respectively, in heating degree days.  Also, our eastern region experienced a 67% increase in cooling degree days which was offset by a 21% decrease in cooling degree days in our western region.
 
·
A $37 million increase related to Ormet, a new industrial customer in Ohio.  See “Ormet” section of Note 3.
 
These increases were partially offset by:
 
·
A $48 million decrease in financial transmission rights revenue, net of congestion, primarily due to fewer transmission constraints within the PJM market.
 
·
A $25 million decrease due to a second quarter 2007 provision related to a SWEPCo Texas fuel reconciliation proceeding.  See “SWEPCo Fuel Reconciliation – Texas” section of Note 3.
·
Margins from Off-system Sales increased $11 million primarily due to higher power prices in the east and stronger trading margins offset by higher internal load and lower generation availability.
·
Transmission Revenues decreased $8 million primarily due to the elimination of SECA revenues as of April 1, 2006 offset by a provision recorded in the second quarter of 2006 related to potential SECA refunds.  See  “Transmission Rate Proceedings at the FERC” section of Note 3.
·
Other Revenues increased $33 million primarily due to higher securitization revenue at TCC resulting from the $1.7 billion securitization in October 2006.  Securitization revenue represents amounts collected to recover securitization bond principal and interest payments related to TCC’s securitized transition assets and are fully offset by amortization and interest expenses.

Utility Operating Expenses and Other and Income Taxes changed between years as follows:

·
Other Operation and Maintenance expenses increased $85 million primarily due to increases in generation expenses related to plant outages, base operations and removal costs and distribution expenses associated with service reliability and storm restoration primarily in Oklahoma.
·
Gain on Disposition of Assets, Net decreased $47 million primarily related to the earnings sharing agreement with Centrica from the sale of our REPs in 2002.  In 2006, we received $70 million from Centrica for earnings sharing and in 2007 we received $20 million as the earnings sharing agreement ended.
·
Depreciation and Amortization expense increased $62 million primarily due to increased Ohio regulatory asset amortization related to recovery of IGCC pre-construction costs, increased Texas amortization of the securitized transition assets and higher depreciable property balances.
·
Carrying Costs Income decreased $39 million because TCC started recovering stranded costs in October 2006, thus eliminating future TCC carrying costs income.
·
Interest and Other Charges increased $71 million primarily due to additional debt issued in the fourth quarter of 2006 including TCC securitization bonds.
·
Income Tax Expense decreased $23 million due to a decrease in pretax income.

MEMCO Operations

Second Quarter of 2007 Compared to Second Quarter of 2006

Income Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations segment decreased from $14 million in 2006 to $7 million in 2007.  While MEMCO operated 15% more barges in the second quarter of 2007 than the same period in 2006, freight revenues remained flat as spot market freight demand remained weaker than in 2006, primarily related to reduced steel and cement imports.  Operating expenses were up 11% over the same period in 2006 mainly due to the increased fleet size, increased fuel costs and wage increases for towboat crews.

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

Income Before Discontinued Operations and Extraordinary Loss from our MEMCO Operations segment decreased from $35 million in 2006 to $22 million in 2007.  MEMCO operated approximately 16% more barges in the first six months of 2007 than 2006, however, revenue remained flat as reduced imports, primarily steel and cement continued to depress freight rates and reduce northbound loadings.  Operating expenses were up for the first six months of 2007 compared to 2006 primarily due to the cost of the increased fleet size, fuel and wage increases.

Generation and Marketing

Second Quarter of 2007 Compared to Second Quarter of 2006

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment increased from $2 million in 2006 to $15 million in 2007.  The increase primarily relates to favorable marketing contracts with municipalities and cooperatives in ERCOT.  Net revenues for our Generation and Marketing segment increased primarily due to certain existing ERCOT energy contracts which were transferred from our Utility Operations segment on January 1, 2007.

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment increased from $6 million in 2006 to $14 million in 2007.  The increase primarily relates to favorable marketing contracts with municipalities and cooperatives in ERCOT.  Net revenues for our Generation and Marketing segment increased primarily due to certain existing ERCOT energy contracts which were transferred from our Utility Operations segment on January 1, 2007.

All Other

Second Quarter of 2007 Compared to Second Quarter of 2006

Loss Before Discontinued Operations and Extraordinary Loss from All Other was essentially flat at $3 million.

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

Income Before Discontinued Operations and Extraordinary Loss from All Other increased from a $15 million loss in 2006 to income of $1 million in 2007.  In 2006, we had after-tax losses of $8 million from operation of the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006.  In 2007, we had an after-tax gain of $10 million on the sale of investment securities.

AEP System Income Taxes

Income Tax Expense increased $36 million in the second quarter of 2007 compared to the second quarter of 2006 primarily due to an increase in pretax book income.

Income Tax Expense decreased $23 million for the six-month period ended June 30, 2007 compared to the six-month period ended June 30, 2006 primarily due to a decrease in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis.

FINANCIAL CONDITION

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

Debt and Equity Capitalization
   
June 30, 2007
   
December 31, 2006
 
   
($ in millions)
 
Long-term Debt, Including Amounts Due Within One Year
  $
14,588
      59.0 %   $
13,698
      59.1 %
Short-term Debt
   
438
     
1.8
     
18
     
0.0
 
Total Debt
   
15,026
     
60.8
     
13,716
     
59.1
 
Common Equity
   
9,656
     
39.0
     
9,412
     
40.6
 
Preferred Stock
   
61
     
0.2
     
61
     
0.3
 
                                 
Total Debt and Equity Capitalization
  $
24,743
      100.0 %   $
23,189
      100.0 %

Our ratio of debt to total capital increased, as planned, from 59.1% to 60.8% in 2007 due to our increased borrowings.
 
Liquidity

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

We manage our liquidity by maintaining adequate external financing commitments.  At June 30, 2007, our available liquidity was approximately $2.7 billion as illustrated in the table below:

     
Amount
 
Maturity
     
(in millions)
   
Commercial Paper Backup:
           
 
Revolving Credit Facility
   
$
1,500
 
March 2011
 
Revolving Credit Facility
     
1,500
 
April 2012
Total
     
3,000
   
Cash and Cash Equivalents
     
172
   
Total Liquidity Sources
     
3,172
   
Less: AEP Commercial Paper Outstanding
     
416
   
 
Letters of Credit Drawn
     
27
   
             
Net Available Liquidity
   
$
2,729
   

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

Debt Covenants and Borrowing Limitations

Our revolving credit agreements contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%.  The method for calculating our outstanding debt and other capital is contractually defined in our revolving credit agreements. At June 30, 2007, this contractually-defined percentage was 56.1%.  Nonperformance of these covenants could result in an event of default under these credit agreements.  At June 30, 2007, we complied with all of the covenants contained in these credit agreements.  In addition, the acceleration of our payment obligations, or the obligations of certain of our major subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million, would cause an event of default under these credit agreements and permit the lenders to declare the outstanding amounts payable.

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

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

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders.  At June 30, 2007, we had not exceeded those authorized limits.

Credit Ratings

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

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

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

Cash Flow

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

   
Six Months Ended
 
   
June 30,
 
   
2007
   
2006
 
   
(in millions)
 
Cash and Cash Equivalents at Beginning of Period
  $
301
    $
401
 
Net Cash Flows From Operating Activities
   
969
     
1,123
 
Net Cash Flows Used For Investing Activities
    (2,127 )    
(1,572
Net Cash Flows From Financing Activities
   
1,029
     
297
 
Net Decrease in Cash and Cash Equivalents
    (129 )    
(152
Cash and Cash Equivalents at End of Period
  $
172
    $
249
 

Cash from operations, combined with a bank-sponsored receivables purchase agreement and short-term borrowings, provides working capital and allows us to meet other short-term cash needs.  We use our corporate borrowing program to meet the short-term borrowing needs of our subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries.  In addition, we also fund, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  As of June 30, 2007, we had credit facilities totaling $3 billion to support our commercial paper program.  The maximum amount of commercial paper outstanding during 2007 was $833 million.  The weighted-average interest rate of our commercial paper for the six months ended June 30, 2007 was 5.40%.  We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding is arranged.  Sources of long-term funding include issuance of common stock or long-term debt and sale-leaseback or leasing agreements.  Utility Money Pool borrowings and external borrowings may not exceed authorized limits under regulatory orders.  See the discussion below for further detail related to the components of our cash flows.

Operating Activities
   
Six Months Ended
 
   
June 30,
 
   
2007
   
2006
 
   
(in millions)
 
Net Income
  $
451
    $
556
 
Less:  Discontinued Operations, Net of Tax
    (2 )     (6 )
Income Before Discontinued Operations
   
449
     
550
 
Noncash Items Included in Earnings
   
938
     
617
 
Changes in Assets and Liabilities
    (418 )     (44 )
Net Cash Flows From Operating Activities
  $
969
    $
1,123
 

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

Net Cash Flows From Operating Activities were $1 billion in 2007. We produced Income Before Discontinued Operations of $449 million adjusted for noncash expense items, primarily depreciation and amortization.  Other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The current period activity in these asset and liability accounts relates to a number of items, the most significant of which relates primarily to the Texas CTC refund of fuel over-recovery.
 
Net Cash Flows From Operating Activities were $1.1 billion in 2006.  We produced Income Before Discontinued Operations of $550 million adjusted for noncash expense items, primarily depreciation and amortization.  In 2005, we initiated fuel proceedings in Oklahoma, Texas, Virginia and Arkansas seeking recovery of our increased fuel costs.  Under-recovered fuel costs decreased due to recovery of higher cost of fuel, especially natural gas.  Other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities.  The current period activity in these asset and liability accounts relates to a number of items; the most significant are a $185 million cash increase from net Accounts Receivable/Accounts Payable due to a lower balance of Customer Accounts Receivable at June 30, 2006 and a $189 million decrease in cash related to customer deposits held for trading activities.

Investing Activities
   
Six Months Ended
 
   
June 30,
 
   
2007
   
2006
 
   
(in millions)
 
Construction Expenditures
  $ (1,823 )   $
(1,611
)
Change in Other Temporary Investments, Net
    (129 )    
3
 
(Purchases)/Sales of Investment Securities, Net
   
208
     
(51
)
Acquisition of Darby and Lawrenceburg Plants
    (427 )    
-
 
Proceeds from Sales of Assets
   
74
     
118
 
Other
    (30 )    
(31
)
Net Cash Flows Used For Investing Activities
  $ (2,127 )   $
(1,572
)

Net Cash Flows Used For Investing Activities were $2.1 billion in 2007 primarily due to Construction Expenditures for our environmental, distribution and new generation investment plan.  We paid $427 million to purchase gas-fired generating units.  In our normal course of business, we purchase investment securities including auction rate securities and variable rate demand notes with cash available for short-term investments.  Also included in Purchases/Sales of Investment Securities, Net are purchases and sales of securities within our nuclear trusts.

Net Cash Flows Used For Investing Activities were $1.6 billion in 2006 primarily due to Construction Expenditures.  Construction Expenditures increased due to our environmental investment plan.

We forecast approximately $1.7 billion of construction expenditures for the remainder of 2007.  Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital.  These construction expenditures will be funded through results of operations and financing activities.

Financing Activities
   
Six Months Ended
 
   
June 30,
 
   
2007
   
2006
 
   
(in millions)
 
Issuance of Common Stock
  $
90
    $
6
 
Issuance/Retirement of Debt, Net
   
1,294
     
552
 
Dividends Paid on Common Stock
    (311 )    
(291
)
Other
    (44 )    
30
 
Net Cash Flows From Financing Activities
  $
1,029
    $
297
 

Net Cash Flows From Financing Activities in 2007 were $1 billion primarily due to issuing $1.1 billion of debt securities including $1 billion of new debt for plant acquisitions and construction and increasing short-term commercial paper borrowings.  We paid common stock dividends of $311 million.  See Note 9 for a complete discussion of long-term debt issuances and retirements.
 
Net Cash Flows From Financing Activities in 2006 were $297 million.  During 2006, we issued $115 million of obligations relating to pollution control bonds, issued $850 million of notes and retired $396 million of notes for a net increase in notes outstanding of $454 million and increased our short-term commercial paper outstanding by $144 million.  The Other amount of $30 million in the above table includes $68 million received from a coal supplier, net of an $8 million repayment, related to a long-term coal purchase contract amended in March 2006.

Our capital investment plans for the remainder of 2007 will require additional funding of approximately $1.5 billion from the capital markets.

Off-balance Sheet Arrangements

Under a limited set of circumstances we enter into off-balance sheet arrangements to accelerate cash collections, reduce operational expenses and spread risk of loss to third parties.  Our current guidelines restrict the use of off-balance sheet financing entities or structures to only allow traditional operating lease arrangements and sales of customer accounts receivable that we enter in the normal course of business.  Our significant off-balance sheet arrangements  are as follows:
   
June 30,
2007
   
December 31,
2006
 
   
(in millions)
 
AEP Credit Accounts Receivable Purchase Commitments
  $
549
    $
536
 
Rockport Plant Unit 2 Future Minimum Lease Payments
   
2,290
     
2,364
 
Railcars Maximum Potential Loss From Lease Agreement
   
30
     
31
 

For complete information on each of these off-balance sheet arrangements see the “Off-balance Sheet Arrangements” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2006 Annual Report.

Summary Obligation Information

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

Other

Texas REPs

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

SIGNIFICANT FACTORS

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

Ohio Restructuring

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

Texas Restructuring

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

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

Municipal customers and other intervenors also appealed the PUCT true-up orders seeking to further reduce TCC’s true-up recoveries.  In March 2007, the Texas District Court judge hearing the various appeals affirmed the PUCT’s April 4, 2006 final true-up order for TCC with two significant exceptions.  The judge determined that the PUCT erred by applying an invalidated rule to determine the carrying cost rate for the true-up of stranded costs.  However, the District Court did not rule that the carrying cost rate was inappropriate.  If the District Court’s ruling on the carrying cost rate is ultimately upheld on appeal and remanded to the PUCT for reconsideration, the PUCT could either confirm the existing weighted average carrying cost (WACC) rate or determine a new rate.  If the PUCT reduces the rate, it could result in a material adverse change to TCC’s recoverable carrying costs, results of operations, cash flows and financial condition.

The District Court judge also determined the PUCT improperly reduced TCC’s net stranded plant costs for commercial unreasonableness.  If upheld on appeal, this ruling could have a materially favorable effect on TCC’s results of operations and cash flows.

TCC, the PUCT and intervenors appealed the District Court rulings to the Court of Appeals.  Management cannot predict the outcome of these proceedings.  If TCC ultimately succeeds in its appeals, it could have a favorable effect on future results of operations, cash flows and financial condition.  If municipal customers and other intervenors succeed in their appeals, or if TCC has a tax normalization violation, it could have a substantial adverse effect on future results of operations, cash flows and financial condition.

SECA Revenue Subject to Refund

The AEP East companies ceased collecting T&O revenues in accordance with FERC orders, and collected SECA rates to mitigate the loss of T&O revenues from December 1, 2004 through March 31, 2006, when SECA rates expired.  Intervenors objected to the SECA rates, raising various issues.  As a result, the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund or surcharge.  The AEP East companies paid SECA rates to other utilities at considerably lesser amounts than collected.  If a refund is ordered, the AEP East companies would also receive refunds related to the SECA rates they paid to third parties.  The AEP East companies recognized gross SECA revenues of $220 million. Approximately $19 million of these recorded SECA revenues billed by PJM were not collected.  The AEP East companies filed a motion with the FERC to force payment of these uncollected SECA billings.

In August 2006, a FERC ALJ issued an initial decision, finding that the rate design for the recovery of SECA charges was flawed and that a large portion of the “lost revenues” reflected in the SECA rates was not recoverable.   The ALJ found that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made.  The ALJ also found that the unpaid SECA rates must be paid in the recommended reduced amount.
 
Since the implementation of SECA rates in December 2004, the AEP East companies recorded approximately $220 million of gross SECA revenues, subject to refund.  In 2006, the AEP East companies provided reserves of $37 million in net refunds for current and future SECA settlements with all of AEP’s SECA customers.  The AEP East companies reached settlements with certain SECA customers related to approximately $69 million of such revenues for a net refund of $3 million.  The AEP East companies are in the process of completing two settlements-in-principle on an additional $36 million of SECA revenues and expect to make net refunds of $4 million when those settlements are approved.  Thus, completed and in-process settlements cover $105 million of SECA revenues and will consume about $7 million of the reserves for refunds, leaving approximately $115 million of contested SECA revenues and $30 million of refund reserves.  If the ALJ’s initial decision were upheld in its entirety, it would disallow approximately $90 million of the AEP East companies’ remaining $115 million of unsettled gross SECA revenues.  Based on recent settlement experience and the expectation that most of the $115 million of unsettled SECA revenues will be settled, management believes that the remaining reserve will be adequate.
 
In September 2006, AEP, together with Exelon Corporation and The Dayton Power and Light Company, filed an extensive post-hearing brief and reply brief noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part.  Management believes that the FERC should reject the initial decision because it contradicts prior related FERC decisions, which are presently subject to rehearing.  Furthermore, management believes the ALJ’s findings on key issues are largely without merit.  As directed by the FERC, management is working to settle the remaining $115 million of unsettled revenues within the remaining reserve balance.  Although management believes it has meritorious arguments and can settle with the remaining customers within the amount provided, management cannot predict the ultimate outcome of ongoing settlement talks and, if necessary, any future FERC proceedings or court appeals.  If the FERC adopts the ALJ’s decision and/or AEP cannot settle a significant portion of the remaining unsettled claims within the amount provided, it will have an adverse effect on future results of operations and cash flows.

Virginia Restructuring

In April 2004, Virginia enacted legislation that amended the Virginia Electric Utility Restructuring Act extending the transition period to market rates for the generation and supply of electricity, including the extension of capped rates, through December 31, 2010.  The legislation provided APCo with specified cost recovery opportunities during the extended capped rate period, including two optional bundled general base rate changes and an opportunity for timely recovery, through a separate rate mechanism, of certain unrecovered incremental environmental and reliability costs incurred on and after July 1, 2004.  Under the amended restructuring law, APCo continues to have an active fuel clause recovery mechanism in Virginia and continues to practice deferred fuel accounting.  Also, under the amended restructuring law, APCo has the right to defer incremental environmental compliance costs and incremental E&R costs for future recovery, to the extent such costs are not being recovered, and amortizes a portion of such deferrals commensurate with their recovery.

In April 2007, the Virginia legislature adopted a comprehensive law providing for the re-regulation of electric utilities’ generation and supply rates.  These amendments shorten the transition period by two years (from 2010 to 2008) after which rates for retail generation and supply will return to a form of cost-based regulation in lieu of market-based rates.  The legislation provides for, among other things, biennial rate reviews beginning in 2009; rate adjustment clauses for the recovery of the costs of (a) transmission services and new transmission investments, (b) demand side management, load management, and energy efficiency programs, (c) renewable energy programs, and (d) environmental retrofit and new generation investments; significant return on equity enhancements for investments in new generation and, subject to Virginia SCC approval, certain environmental retrofits, and a floor on the allowed return on equity based on the average earned return on equities’ of regional vertically integrated electric utilities.  Effective July 1, 2007, the amendments allow utilities to retain a minimum of 25% of the margins from off-system sales with the remaining margins from such sales credited against fuel factor expenses with a true-up to actual.  The legislation also allows APCo to continue to defer and recover incremental environmental and reliability costs incurred through December 31, 2008.  The new re-regulation legislation should result in significant positive effects on APCo’s future earnings and cash flows from the mandated enhanced future returns on equity, the reduction of regulatory lag from the opportunities to adjust base rates on a biennial basis and the new opportunities to request timely recovery of certain new costs not included in base rates.

With the new re-regulation legislation, APCo’s generation business again meets the criteria for application of regulatory accounting principles under SFAS 71.  The extraordinary pretax reduction in APCo’s earnings and shareholder’s equity from reapplication of SFAS 71 regulatory accounting of $118 million ($79 million, net of tax) was recorded in the second quarter of 2007.  This extraordinary net loss primarily relates to the reestablishment of $139 million in net generation-related customer-provided removal costs as a regulatory liability, offset by the restoration of $21 million of deferred state income taxes as a regulatory asset.  In addition, APCo established a regulatory asset of $17 million for qualifying SFAS 158 pension costs of the generation operations that, for ratemaking purposes, are deferred for future recovery under the new law.  AOCI and Deferred Income Taxes increased by $11 million and $6 million, respectively.

New Generation

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

In April 2006, the PUCO issued an order authorizing CSPCo and OPCo to implement Phase 1 of the cost recovery proposal.  In June 2006, the PUCO issued another order approving a tariff to recover Phase 1 pre-construction costs over a period of no more than twelve months effective July 1, 2006.  Through June 30, 2007, CSPCo and OPCo each recorded pre-construction IGCC regulatory assets of $10 million and each collected the entire $12 million approved by the PUCO.  CSPCo and OPCo expect to incur additional pre-construction costs equal to or greater than the $12 million each recovered.  As of June 30, 2007, CSPCo and OPCo have recorded a liability of $2 million each for the over-recovered portion.  The PUCO indicated that if CSPCo and OPCo have not commenced a continuous course of construction of the IGCC plant within five years of the June 2006 PUCO order, all amounts collected for pre-construction costs, associated with items that may be utilized in IGCC projects to be built by AEP at other sites, must be refunded to Ohio ratepayers with interest.  The PUCO deferred ruling on cost recovery for Phases 2 and 3 until further hearings are held.  A date for further rehearings has not been set.

In August 2006, the Ohio Industrial Energy Users, Ohio Consumers’ Counsel, FirstEnergy Solutions and Ohio Energy Group filed four separate appeals of the PUCO’s order in the IGCC proceeding.  The Ohio Supreme Court has scheduled oral arguments for these appeals in October 2007.  Management believes that the PUCO’s authorization to begin collection of Phase 1 rates is lawful.  Management, however, cannot predict the outcome of these appeals.  If the PUCO’s order is found to be unlawful, CSPCo and OPCo could be required to refund Phase 1 cost-related recoveries.

Pending the outcome of the Supreme Court litigation, CSPCo and OPCo announced they may delay the start of construction of the IGCC plant.  Recent estimates of the cost to build an IGCC plant are $2.2 billion.  CSPCo and OPCo may need to request an extension to the 5 year start of construction requirement if the commencement of construction is delayed beyond 2011.  In July 2007, CSPCo and OPCo filed a status report with the PUCO referencing APCo’s IGCC West Virginia filing.

In January 2006, APCo filed a petition with the WVPSC requesting its approval of a Certificate of Public Convenience and Necessity (CCN) to construct a 629 MW IGCC plant adjacent to APCo’s existing Mountaineer Generating Station in Mason County, WV.

In June 2007, APCo filed testimony with the WVPSC supporting the requests for a CCN and for pre-approval of a surcharge rate mechanism to provide for the timely recovery of both the ongoing finance costs of the project during the construction period as well as the capital costs, operating costs and a return of equity once the facility is placed into commercial operation.  If APCo receives all necessary approvals, the plant could be completed by mid-2012 at the earliest and currently is expected to cost an estimated $2.2 billion.  In July 2007, the WVPSC staff and intervenors filed to delay the procedural schedule by 90 days.  APCo supported the changes to the procedural schedule.  The statutory decision deadline was revised to March 2008.  In July 2007, the WVPSC approved the revised procedural schedule.  Through June 30, 2007, APCo deferred pre-construction IGCC costs totaling $11 million.  If the plant is not built and these costs are not recoverable, future results of operations and cash flows would be adversely affected.

In July 2007, APCo filed a request with the Virginia SCC to recover, over the twelve months beginning January 1, 2009, a return on projected construction work in progress including development, design and planning costs from July 1, 2007 through December 31, 2009 estimated to be $45 million associated with the IGCC plant to be constructed in West Virginia.  APCo is requesting authorization to defer a return on actual pre-construction costs incurred beginning July 1, 2007 until such costs are recovered, starting January 1, 2009 as required by the new re-regulation legislation.

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.  Plans include the construction of up to 480 MW of simple-cycle natural gas combustion turbine peaking generation in Tontitown, Arkansas and a 480 MW combined-cycle natural gas fired intermediate plant at its existing Arsenal Hill Power Plant in Shreveport, Louisiana.  SWEPCo also plans to build the Turk plant, a new 600 MW base load coal plant, with a 73% ownership share, in Hempstead County, Arkansas by 2011 to meet the long-term generation needs of its customers.  Preliminary cost estimates for SWEPCo’s share of these new facilities are approximately $1.4 billion (this total includes all three plants, but excludes the related transmission investment and AFUDC).  Expenditures related to construction of all of these facilities are expected to total $349 million in 2007.  These new facilities are subject to regulatory approvals from SWEPCo’s three state commissions.  Mattison plant, the peaking generation facility in Tontitown, Arkansas has been approved by all three state commissions.  Mattison plant Units 3 and 4 began commercial operation in July 2007, with the remaining two units scheduled for completion in December 2007.  All four units of the Mattison plant are expected to be completed in advance of the originally planned 2008 commercial operation date.  Construction is expected to begin in the second half of 2007 on the base load facility and in 2008 on the intermediate facility, both upon approval from SWEPCo’s three state commissions.

In September 2005, PSO sought proposals for new peaking generation to be online in 2008, and in December 2005 PSO sought proposals for base load generation to be online in 2011.  PSO received proposals and evaluated those proposals meeting the Request for Proposal criteria with oversight from a neutral third party.  In March 2006, PSO announced plans to add 170 MW of peaking generation to its Riverside Station plant in Jenks, Oklahoma where PSO will construct and operate two 85 MW simple-cycle natural gas combustion turbines.   Also in March 2006, PSO announced plans to add 170 MW of peaking generation to its Southwestern Station plant in Anadarko, Oklahoma where they will construct and operate two 85 MW simple-cycle natural gas combustion turbines.  Construction of all four peaking units began in the second quarter of 2007.  Combined preliminary cost estimates for these additions are approximately $120 million.  In April 2007, the OCC approved a settlement agreement in a matter involving a proposed cogeneration facility, which included a provision regarding these new peaking units.  The settlement agreement provides for recovery of a purchase fee of $35 million, which PSO paid to Lawton Cogeneration, LLC (Lawton) in the second quarter of 2007 to settle the proceeding and for all rights to Lawton’s permits, options and engineering studies for the cogeneration facility.  In April 2007, PSO recorded with OCC approval, the purchase fee as a regulatory asset and will recover it through a rider over a three-year period with a carrying charge of 8.25% beginning in September 2007.  In addition, PSO will recover the traditional costs associated with plant in service of these new peaking units.  Such costs will be recovered through the rider until cost recovery occurs through base rates or formula rates in a subsequent proceeding.  PSO must file a rate case within eighteen months of the beginning of recovery through the rider unless the OCC approves a formula-based rate mechanism that provides for recovery of the peaking units.

In July 2006, PSO announced plans to enter a joint ownership agreement with Oklahoma Gas and Electric Company (OG&E) and Oklahoma Municipal Power Authority (OMPA) where OG&E will construct and operate a new 950 MW coal-fueled electricity generating unit near Red Rock, Oklahoma.  PSO will own 50% of the new unit.  PSO, OG&E and OMPA signed an agreement in February 2007 with Red Rock Power Partners to begin the first phase of the project.  Preliminary cost estimates for 100% of the new facility are approximately $1.8 billion, and the unit is expected to be online no later than the first half of 2012.  This new facility is subject to regulatory approval from the OCC, which is expected later in 2007.  Construction is expected to begin in the second half of 2007.  The Oklahoma Supreme Court is addressing whether the upfront approval process is constitutional.  PSO estimates construction expenditures for all of the new generation projects to be $167 million in 2007.
 
In November 2006, CSPCo agreed to purchase Darby Electric Generating Station (Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light Company, for $102 million and the assumption of liabilities of $2 million.  CSPCo completed the purchase in April 2007.  The Darby plant is located near Mount Sterling, Ohio and is a natural gas, simple cycle power plant with a generating capacity of 480 MW.  The purchase of Darby is an economically efficient way to provide peaking generation to our customers at a cost below that of building a new, comparable plant.

In January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station (Lawrenceburg) from Public Service Enterprise Group (PSEG) for $325 million and the assumption of liabilities of $3 million.  The transaction closed in May 2007.  The Lawrenceburg plant is located in Lawrenceburg, Indiana, adjacent to I&M’s Tanners Creek Plant, and is a natural gas, combined cycle power plant with a generating capacity of 1,096 MW.  AEGCo sells the power to CSPCo under a FERC-approved purchase power contract.

Electric Transmission Texas LLC Joint Venture

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

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

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

In February 2007, ETT filed a proposal with the PUCT that addresses the Competitive Renewable Energy Zone (CREZ) initiative of the Texas Legislature, which outlines opportunities for additional significant investment in transmission assets in Texas. A CREZ hearing was held in June 2007.  We expect an order in August 2007 on the designation of zones and amount of wind generation for each zone, subsequent studies by ERCOT on specific transmission recommendations in late 2007 or early 2008 and selection of transmission construction designees by the PUCT in early 2008.

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

AEP Interstate Project

In January 2006, we filed a proposal with the FERC and PJM to build a new 765 kV 550-mile transmission line from West Virginia to New Jersey.  The 765 kV line is designed to reduce PJM congestion costs by substantially improving west-east transfer capability by approximately 5,000 MW during peak loading conditions and reducing transmission line losses by up to 280 MW.  The project would also enhance reliability of the Eastern transmission grid.  The projected cost for the project, as originally proposed to PJM, is approximately $3 billion.  The project is subject to PJM and state approvals, and FERC approvals of incentive cost recovery mechanisms.

We were the first entity to file with the Department of Energy (DOE) seeking to have the route of a proposed transmission project designated as a National Interest Electric Transmission Corridor (NIETC).  The Energy Policy Act of 2005 provides for NIETC designation for areas experiencing electric energy transmission capacity constraints or congestion that adversely affects consumers.  In August 2006, the DOE issued the “National Interest Electric Transmission Congestion Study.”  In this study, DOE indicated that the mid-Atlantic Coastal area, which the AEP Interstate Project is designed to reinforce, is one of the two most critical congestion areas in the nation.  In April 2007, the DOE included in its draft report the mid-Atlantic Coastal area NIETC which contains the entire proposed 765 kV transmission line.  The DOE expects to issue its final report by the end of 2007.

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

In April 2007, we signed a memorandum of understanding (MOU) with Allegheny Energy Inc. (AYE) to form a joint venture company to build and own certain electric transmission assets within PJM including the first half of the West Virginia – New Jersey line proposed by AEP in January 2006.  Under the terms of the MOU, the joint venture company will build and own approximately 300 miles of transmission lines from AEP’s Amos station to the Maryland border.  The MOU does not include any provisions for the remainder of the AEP Interstate Project proposal from AYE’s Kemptown station to New Jersey.

On June 22, 2007, PJM’s Board authorized the construction of such a major new transmission line to address the reliability and efficiency needs of the PJM system.  PJM has identified a need for a new line as early as 2012.  The line would be 765kV for most of its length and would run approximately 250 miles from AEP’s Amos substation in West Virginia to AYE’s Kemptown station in north central Maryland. AEP and AYE continue to work on finalizing the definitive agreements necessary to construct the line through a joint venture.  The new line has been named the “Potomac-Appalachian Transmission Highline” (PATH) by AEP and AYE and represents the “first leg” of the AEP Interstate Project.  The “second leg”, which would extend the line to New Jersey, is currently under evaluation by PJM.  We expect to execute definitive agreements for the joint venture with AYE in the third quarter of 2007 and anticipate the joint venture will begin activities in the second half of 2007.  The total PATH project is estimated to cost approximately $1.8 billion and AEP’s estimated share will be approximately $600 million.

Litigation

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

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

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

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

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

Environmental Litigation

New Source Review (NSR) Litigation:  In 1999, the Federal EPA, a number of states and certain special interest groups filed complaints alleging that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities including the Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas & Electric Company, Ohio Edison Company, Southern Indiana Gas & Electric Company, Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company and Duke Energy,  modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA.  Several similar complaints were filed in 1999 and thereafter against nonaffiliated utilities including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk.  Several of these cases were resolved through consent decrees.  The alleged modifications at our power plants occurred over a 20-year period.  A bench trial on the liability issues was held during 2005.  In 2006, the judge stayed the liability decision pending the issuance of a decision by the U.S. Supreme Court in the Duke Energy case.

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

Courts that considered whether the activities at issue in these cases are routine maintenance, repair, or replacement, and therefore are excluded from NSR, reached different conclusions.  Similarly, courts that considered whether the activities at issue increased emissions from the power plants reached different results.  Appeals on these and other issues were filed in certain appellate courts, including a petition to appeal to the U.S. Supreme Court that was granted in the Duke Energy case.

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

In addition to providing guidance on the merits of arguments in our NSR proceedings, the U.S. Supreme Court’s issuance of a ruling in the Duke Energy cases has an impact on the timing of our NSR proceedings.  The court indicated an intent to issue a decision on liability issues in the third quarter of 2007.  A bench trial on remedy issues, if necessary, is likely to begin in the second half of 2007.
 
We are unable to estimate the loss or range of loss related to any contingent liability, if any, we might have for civil penalties under the CAA proceedings.  We are also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues to be determined by the court.  If we do not prevail, we believe we can recover any capital and operating costs of additional pollution control equipment that may be required through regulated rates and market prices for electricity.  If we are unable to recover such costs or if material penalties are imposed, it would adversely affect future results of operations, cash flows and possibly financial condition.

Clean Water Act Regulations

In 2004, the Federal EPA issued a final rule requiring all large existing power plants with once-through cooling water systems to meet certain standards to reduce mortality of aquatic organisms pinned against the plant’s cooling water intake screen or entrained in the cooling water.  The standards vary based on the water bodies from which the plants draw their cooling water.  We expected additional capital and operating expenses, which the Federal EPA estimated could be $193 million for our plants.  We undertook site-specific studies and have been evaluating site-specific compliance or mitigation measures that could significantly change these cost estimates.

The rule was challenged in the courts by states, advocacy organizations and industry.  In January 2007, the Second Circuit Court of Appeals issued a decision remanding significant portions of the rule to the Federal EPA.  In July 2007, the Federal EPA suspended the 2004 rule, except for the requirement that permitting agencies develop best professional judgment (BPJ) controls for existing facility cooling water intake structures that reflect the best technology available for minimizing  adverse environmental impact.  The result is that the BPJ control standard for cooling water intake structures in effect prior to the 2004 rule is the applicable standard for permitting agencies pending finalization of revised rules by the Federal EPA.  We cannot predict further action of the Federal EPA or what effect it may have on similar requirements adopted by the states.  We may seek further review or relief from the schedules included in our permits.

Critical Accounting Estimates

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

Adoption of New Accounting Pronouncements

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

 

 
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

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

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

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

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

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

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

The following two tables summarize the various mark-to-market (MTM) positions included on our condensed consolidated balance sheet as of June 30, 2007 and the reasons for changes in our total MTM value included on our condensed consolidated balance sheet as compared to December 31, 2006.

Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
June 30, 2007
(in millions)
   
Utility Operations
   
Generation and
Marketing
   
All Other
   
Sub-Total MTM Risk Management Contracts
   
PLUS: MTM of Cash Flow and Fair Value Hedges
   
Total
 
Current Assets
  $
305
    $
40
    $
83
    $
428
    $
39
    $
467
 
Noncurrent Assets
   
197
     
46
     
98
     
341
     
15
     
356
 
Total Assets
   
502
     
86
     
181
     
769
     
54
     
823
 
                                                 
Current Liabilities
    (215 )     (50 )     (83 )     (348 )     (3 )     (351 )
Noncurrent Liabilities
    (91 )     (11 )     (105 )     (207 )     (1 )     (208 )
Total Liabilities
    (306 )     (61 )     (188 )     (555 )     (4 )     (559 )
                                                 
Total MTMDerivative Contract Net
  Assets (Liabilities)
  $
196
    $
25
    $ (7 )   $
214
    $
50
    $
264
 

MTM Risk Management Contract Net Assets (Liabilities)
Six Months Ended June 30, 2007
(in millions)
   
Utility Operations
   
Generation
and
Marketing
   
All Other
   
Total
 
Total MTM Risk Management Contract Net Assets
   (Liabilities)  at December 31, 2006
  $
236
    $
2
    $ (5 )   $
233
 
(Gain) Loss from Contracts Realized/Settled During   
   the Period and Entered in a Prior Period
    (37 )     (1 )     (1 )     (39 )
Fair Value of New Contracts at Inception When Entered
   During the Period (a)
   
1
     
31
     
-
     
32
 
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
   
-
     
-
     
-
     
-
 
Changes in Fair Value Due to Market Fluctuations During 
   the Period (b)
   
8
      (7 )     (1 )    
-
 
Changes in Fair Value Allocated to Regulated Jurisdictions (c)
    (13 )    
-
     
-
      (13 )
Total MTM Risk Management Contract Net Assets
   (Liabilities) at June 30, 2007
  $
196
    $
25
    $ (7 )    
214
 
Net Cash Flow and Fair Value Hedge Contracts
                           
50
 
Total MTM Risk Management Contract Net Assets at
   June 30, 2007
                          $
264
 

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

The following table presents:

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

Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets (Liabilities)
Fair Value of Contracts as of June 30, 2007
(in millions)
   
Remainder
2007
   
2008
   
2009
   
2010
   
2011
   
After
2011 (c)
   
Total
 
Utility Operations:
                                         
Prices Actively Quoted – Exchange Traded Contracts
  $ (6 )   $ (8 )   $
-
    $
-
    $
-
    $
-
    $ (14 )
Prices Provided by Other External
  Sources – OTC Broker Quotes (a)
   
73
     
56
     
37
     
17
     
-
     
-
     
183
 
Prices Based on Models and Other
  Valuation Methods (b)
    (4 )     (3 )    
8
     
17
     
4
     
5
     
27
 
Total
   
63
     
45
     
45
     
34
     
4
     
5
     
196
 
                                                         
Generation and Marketing:
                                                       
Prices Actively Quoted – Exchange Traded Contracts
    (8 )     (2 )    
2
     
-
     
-
     
-
      (8 )
Prices Provided by Other External
  Sources – OTC Broker Quotes (a)
    (5 )    
8
     
3
     
-
     
-
     
-
     
6
 
Prices Based on Models and Other
  Valuation Methods (b)
   
1
     
2
      (3 )    
6
     
5
     
16
     
27
 
Total
    (12 )    
8
     
2
     
6
     
5
     
16
     
25
 
                                                         
All Other:
                                                       
Prices Actively Quoted – Exchange Traded Contracts
   
2
     
-
     
-
     
-
     
-
     
-
     
2
 
Prices Provided by Other External
  Sources – OTC Broker Quotes (a)
    (1 )    
-
     
-
     
-
     
-
     
-
      (1 )
Prices Based on Models and Other
  Valuation Methods (b)
    (1 )     (1 )     (4 )     (4 )    
2
     
-
      (8 )
Total
   
-
      (1 )     (4 )     (4 )    
2
     
-
      (7 )
                                                         
Total:
                                                       
Prices Actively Quoted – Exchange
  Traded Contracts
    (12 )     (10 )    
2
     
-
     
-
     
-
      (20 )
Prices Provided by Other External
  Sources – OTC Broker Quotes (a)
   
67
     
64
     
40
     
17
     
-
     
-
     
188
 
Prices Based on Models and Other
  Valuation Methods (b)
    (4 )     (2 )    
1
     
19
     
11
     
21
     
46
 
Total
  $
51
    $
52
    $
43
    $
36
    $
11
    $
21
    $
214
 

(a)
Prices Provided by Other External Sources – OTC Broker Quotes reflects information obtained from over-the-counter brokers (OTC), industry services, or multiple-party online platforms.
(b)
Prices Based on Models and Other Valuation Methods is used in the absence of independent 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 including values determinable by other third party transactions.
(c)
There is mark-to-market value of $21 million in individual periods beyond 2011.  $10 million of this mark-to-market value is in 2012, $5 million is in 2013, and $5 million is in 2014, and $1 million for years 2015 through 2017.
 
The determination of the point at which a market is no longer supported by independent quotes and therefore considered in the modeled category in the preceding table varies by market.  The following table generally 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 June 30, 2007

Commodity
 
Transaction Class
 
Market/Region
 
Tenor
           
(in Months)
Natural Gas
 
Futures
 
NYMEX / Henry Hub
 
60
             
   
Physical Forwards
 
Gulf Coast, Texas
 
16
             
   
Swaps
 
Northeast, Mid-Continent, Gulf Coast, Texas
 
16
             
   
Exchange Option Volatility
 
NYMEX / Henry Hub
 
12
             
Power
 
Futures
 
AEP East - PJM
 
30
             
   
Physical Forwards
 
AEP East
 
42
             
   
Physical Forwards
 
AEP West
 
18
             
   
Physical Forwards
 
West Coast
 
30
             
   
Peak Power Volatility (Options)
AEP East - Cinergy, PJM
 
12
             
Emissions
 
Credits
 
SO2, NOx
 
30
             
Coal
 
Physical Forwards
 
PRB, NYMEX, CSX
 
30


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

We are exposed to market fluctuations in energy commodity prices impacting our power operations.  We monitor these risks on our future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows.  We do not hedge all commodity price risk.

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

We use forward contracts and collars as cash flow hedges to lock in prices on certain transactions denominated in foreign currencies where deemed necessary.  We do not hedge all foreign currency exposure.
 
The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for changes in cash flow hedges from December 31, 2006 to June 30, 2007.  The following table also indicates what portion of designated, effective hedges are expected to be reclassified into net income in the next 12 months.  Only contracts designated as cash flow hedges are recorded in AOCI.  Therefore, economic hedge contracts which are not designated as effective cash flow hedges are marked-to-market and are included in the previous risk management tables.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
Six Months Ended June 30, 2007
(in millions)
   
Power
   
Interest Rate and
Foreign
Currency
   
Total
 
Beginning Balance in AOCI, December 31, 2006
  $
17
    $ (23 )   $ (6 )
Changes in Fair Value
   
22
     
5
     
27
 
Reclassifications from AOCI to Net Income for
  Cash Flow Hedges Settled
    (13 )    
1
      (12 )
Ending Balance in AOCI, June 30, 2007
  $
26
    $ (17 )   $
9
 
                         
After Tax Portion Expected to be Reclassified
  to Earnings During Next 12 Months
  $
20
    $
-
    $
20
 

Credit Risk

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

We have risk management contracts with numerous counterparties.  Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily.  As of June 30, 2007, our credit exposure net of credit collateral to sub investment grade counterparties was approximately 4.9%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss).  As of June 30, 2007, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable (in millions, except number of counterparties):

Counterparty Credit Quality
 
Exposure Before Credit Collateral
   
Credit Collateral
   
Net Exposure
   
Number of Counterparties>10% of
Net Exposure
   
Net Exposure of Counterparties>10%
 
Investment Grade
  $
723
    $
81
    $
642
     
1
    $
67
 
Split Rating
   
20
     
2
     
18
     
3
     
17
 
Noninvestment Grade
   
30
     
7
     
23
     
1
     
19
 
No External Ratings:
                                       
Internal Investment Grade
   
71
     
-
     
71
     
1
     
30
 
Internal Noninvestment Grade
   
17
     
2
     
15
     
1
     
11
 
Total as of June 30, 2007
  $
861
    $
92
    $
769
     
7
    $
144
 
                                         
Total as of December 31, 2006
  $
998
    $
161
    $
837
     
9
    $
169
 
 
Generation Plant Hedging Information

This table provides information on operating measures regarding the proportion of output of our generation facilities (based on economic availability projections) economically hedged, including both contracts designated as cash flow hedges under SFAS 133 and contracts not designated as cash flow hedges.  This information is forward-looking and provided on a prospective basis through December 31, 2009.  This table is a point-in-time estimate, subject to changes in market conditions and our decisions on how to manage operations and risk.  “Estimated Plant Output Hedged” represents the portion of MWHs of future generation/production, taking into consideration scheduled plant outages, for which we have sales commitments or estimated requirement obligations to customers.

Generation Plant Hedging Information
Estimated Next Three Years
As of June 30, 2007

 
Remainder
       
 
2007
 
2008
 
2009
Estimated Plant Output Hedged
94%
 
90%
 
91%

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 June 30, 2007, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

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

VaR Model

Six Months Ended
June 30, 2007
       
Twelve Months Ended
December 31, 2006
(in millions)
       
(in millions)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
$1
 
$6
 
$2
 
$1
       
$3
 
$10
 
$3
 
$1

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

Interest Rate Risk

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period.  The volatilities and correlations were based on three years of daily prices. The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $912 million at June 30, 2007 and $870 million at December 31, 2006.  We would not expect to liquidate our entire debt portfolio in a one-year holding period.  Therefore, a near term change in interest rates should not materially affect our results of operations, cash flows or financial position.



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Six Months Ended June 30, 2007 and 2006
(in millions, except per-share amounts and shares outstanding)
(Unaudited)
   
Three Months Ended
   
Six Months Ended
 
   
2007
   
2006
   
2007
   
2006
 
REVENUES
                       
Utility Operations
  $
2,818
    $
2,799
    $
5,704
    $
5,781
 
Other
   
328
     
137
     
611
     
263
 
TOTAL
   
3,146
     
2,936
     
6,315
     
6,044
 
                                 
EXPENSES
                               
Fuel and Other Consumables Used for Electric Generation
   
868
     
888
     
1,754
     
1,849
 
Purchased Energy for Resale
   
291
     
237
     
537
     
403
 
Other Operation and Maintenance
   
881
     
896
     
1,819
     
1,717
 
Gain on Disposition of Assets, Net
    (3 )    
-
      (26 )     (68 )
Depreciation and Amortization
   
372
     
354
     
763
     
702
 
Taxes Other Than Income Taxes
   
188
     
190
     
374
     
381
 
TOTAL
   
2,597
     
2,565
     
5,221
     
4,984
 
                                 
OPERATING INCOME
   
549
     
371
     
1,094
     
1,060
 
                                 
Interest and Investment Income
   
8
     
11
     
31
     
19
 
Carrying Costs Income
   
16
     
33
     
24
     
63
 
Allowance For Equity Funds Used During Construction
   
6
     
7
     
14
     
13
 
Gain on Disposition of Equity Investments, Net
   
-
     
-
     
-
     
3
 
                                 
INTEREST AND OTHER CHARGES
                               
Interest Expense
   
213
     
176
     
399
     
344
 
Preferred Stock Dividend Requirements of Subsidiaries
   
-
     
-
     
1
     
1
 
TOTAL
   
213
     
176
     
400
     
345
 
                                 
INCOME BEFORE INCOME TAX EXPENSE, MINORITY
  INTEREST EXPENSE AND EQUITY EARNINGS (LOSS)
   
366
     
246
     
763
     
813
 
                                 
Income Tax Expense
   
108
     
72
     
238
     
261
 
Minority Interest Expense
   
1
     
1
     
2
     
1
 
Equity Earnings (Loss) of Unconsolidated Subsidiaries
   
-
      (1 )    
5
      (1 )
                                 
INCOME BEFORE DISCONTINUED OPERATIONS AND
  EXTRAORDINARY LOSS
   
257
     
172
     
528
     
550
 
                                 
DISCONTINUED OPERATIONS, NET OF TAX
   
2
     
3
     
2
     
6
 
                                 
INCOME BEFORE EXTRAORDINARY LOSS
   
259
     
175
     
530
     
556
 
                                 
EXTRAORDINARY LOSS, NET OF TAX
    (79 )    
-
      (79 )    
-
 
                                 
NET INCOME
  $
180
    $
175
    $
451
    $