q210aep10q.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, 2010
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. has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes
X
 
No
   

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 have submitted electronically and posted on the AEP corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes
   
No
   

Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of ‘large accelerated filer,’ ‘accelerated filer’ and ‘smaller reporting company’ in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
X
 
Accelerated filer
   
           
Non-accelerated filer
   
Smaller reporting company
   

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, non-accelerated filers or smaller reporting companies.  See the definitions of ‘large accelerated filer,’ ‘accelerated filer’ and ‘smaller reporting company’ in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer
   
Accelerated filer
   
           
Non-accelerated filer
X
 
Smaller reporting company
   

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 and Indiana Michigan Power Company 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 29, 2010
       
American Electric Power Company, Inc.
   
479,437,027
     
($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, 2010

   
Page
Glossary of Terms
 
i
     
Forward-Looking Information
 
iv
     
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
 
1
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
19
 
Condensed Consolidated Financial Statements
 
23
 
Index to Condensed Notes to Condensed Consolidated Financial Statements
 
28
       
Appalachian Power Company and Subsidiaries:
   
 
Management’s Financial Discussion and Analysis
 
81
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
88
 
Condensed Consolidated Financial Statements
 
89
 
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
94
       
Columbus Southern Power Company and Subsidiaries:
   
 
Management’s Narrative Financial Discussion and Analysis
 
96
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
98
 
Condensed Consolidated Financial Statements
 
99
 
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
104
       
Indiana Michigan Power Company and Subsidiaries:
   
 
Management’s Narrative Financial Discussion and Analysis
 
106
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
109
 
Condensed Consolidated Financial Statements
 
110
 
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
115
       
Ohio Power Company Consolidated:
   
 
Management’s Financial Discussion and Analysis
 
117
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
123
 
Condensed Consolidated Financial Statements
 
124
 
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
129
       
Public Service Company of Oklahoma:
   
 
Management’s Financial Discussion and Analysis
 
131
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
135
 
Condensed Financial Statements
 
136
 
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
141
       
Southwestern Electric Power Company Consolidated:
   
 
Management’s Financial Discussion and Analysis
 
143
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
149
 
Condensed Consolidated Financial Statements
 
150
 
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
155

 
 

 

       
Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
156
       
Combined Management’s Discussion and Analysis of Registrant Subsidiaries
 
224
       
Controls and Procedures
 
232
         
Part II.  OTHER INFORMATION
   
     
 
Item 1.
Legal Proceedings
 
233
 
Item 1A.
Risk Factors
 
233
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
 
235
 
Item 5.
Other Information
 
236
 
Item 6.
Exhibits:
 
236
         
Exhibit 10
   
         
Exhibit 12
   
         
Exhibit 31(a)
   
         
Exhibit 31(b)
   
         
Exhibit 32(a)
   
         
Exhibit 32(b)
   
               
SIGNATURE
   
237

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

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 electric utility companies.
AEP East companies
 
APCo, CSPCo, I&M, KPCo and OPCo.
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.
AEP System or the System
 
American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP West companies
 
PSO, SWEPCo, TCC and TNC.
AEPSC
 
American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC
 
Allowance for Funds Used During Construction.
AOCI
 
Accumulated Other Comprehensive Income.
APCo
 
Appalachian Power Company, an AEP electric utility subsidiary.
APSC
 
Arkansas Public Service Commission.
ASU
 
Accounting Standard Update.
CAA
 
Clean Air Act.
CLECO
 
Central Louisiana Electric Company, a nonaffiliated utility company.
CO2
 
Carbon Dioxide and other greenhouse gases.
Cook Plant
 
Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M.
CSPCo
 
Columbus Southern Power Company, an AEP electric utility subsidiary.
CTC
 
Competition Transition Charge.
CWIP
 
Construction Work in Progress.
DETM
 
Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
DHLC
 
Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
E&R
 
Environmental compliance and transmission and distribution system reliability.
EIS
 
Energy Insurance Services, Inc., a nonaffiliated captive insurance company.
ERCOT
 
Electric Reliability Council of Texas.
ESP
 
Electric Security Plans, filed with the PUCO, pursuant to the Ohio Amendments.
ETT
 
Electric Transmission Texas, LLC, an equity interest joint venture between AEP Utilities, Inc. and MidAmerican Energy Holdings Company Texas Transco, LLC formed to own and operate electric transmission facilities in ERCOT.
FAC
 
Fuel Adjustment Clause.
FASB
 
Financial Accounting Standards Board.
Federal EPA
 
United States Environmental Protection Agency.
FERC
 
Federal Energy Regulatory Commission.
FGD
 
Flue Gas Desulfurization or Scrubbers.
FTR
 
Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP
 
Accounting Principles Generally Accepted in the United States of America.

 
i

 

Term
 
Meaning
     
I&M
 
Indiana Michigan Power Company, an AEP electric utility subsidiary.
IGCC
 
Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
Interconnection Agreement
 
Agreement, dated July 6, 1951, as amended, by and among APCo, CSPCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants.
IRS
 
Internal Revenue Service.
IURC
 
Indiana Utility Regulatory Commission.
KGPCo
 
Kingsport Power Company, an AEP electric utility subsidiary.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
KPSC
 
Kentucky Public Service Commission.
kV
 
Kilovolt.
KWH
 
Kilowatthour.
LPSC
 
Louisiana Public Service Commission.
MISO
 
Midwest Independent Transmission System Operator.
MLR
 
Member load ratio, the method used to allocate AEP Power Pool transactions to its members.
MMBtu
 
Million British Thermal Units.
MPSC
 
Michigan Public Service Commission.
MTM
 
Mark-to-Market.
MW
 
Megawatt.
MWH
 
Megawatthour.
NEIL
 
Nuclear Electric Insurance Limited.
NOx
 
Nitrogen oxide.
Nonutility Money Pool
 
AEP’s Nonutility Money Pool.
NSR
 
New Source Review.
OCC
 
Corporation Commission of the State of Oklahoma.
OPCo
 
Ohio Power Company, an AEP electric utility subsidiary.
OPEB
 
Other Postretirement Benefit Plans.
OTC
 
Over the counter.
OVEC
 
Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PJM
 
Pennsylvania – New Jersey – Maryland regional transmission organization.
PM
 
Particulate Matter.
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 and SWEPCo.
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.
Sabine
 
Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity.

 
ii

 

Term
 
Meaning
     
SIA
 
System Integration Agreement.
SNF
 
Spent Nuclear Fuel.
SO2
 
Sulfur Dioxide.
SPP
 
Southwest Power Pool.
Stall Unit
 
J. Lamar Stall Unit at Arsenal Hill Plant.
SWEPCo
 
Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC
 
AEP Texas Central Company, an AEP electric utility subsidiary.
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.
Turk Plant
 
John W. Turk, Jr. Plant.
Utility Money Pool
 
AEP System’s Utility Money Pool.
VIE
 
Variable Interest Entity.
Virginia SCC
 
Virginia State Corporation Commission.
WPCo
 
Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC
 
Public Service Commission of West Virginia.

 
iii

 
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:

·
The economic climate and growth in, or contraction within, our service territory and changes in market demand and demographic patterns.
·
Inflationary or deflationary interest rate trends.
·
Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.
·
The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
·
Electric load, customer growth and the impact of retail competition.
·
Weather conditions, including storms, and our ability to recover significant storm restoration costs through applicable rate mechanisms.
·
Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·
Availability of necessary generating capacity and the performance of our generating plants.
·
Our ability to recover I&M’s Donald C. Cook Nuclear Plant Unit 1 restoration costs through warranty, insurance and the regulatory process.
·
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, including the Turk Plant, and transmission line facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are cancelled) through applicable rate cases or competitive rates.
·
New legislation, litigation and government regulation, including oversight of energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation and cost recovery of our plants.
·
Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions (including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance).
·
Resolution of litigation (including our dispute with Bank of America).
·
Our ability to constrain operation and maintenance costs.
·
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, coal, nuclear fuel and other energy-related commodities.
·
Changes in utility regulation, including the implementation of ESPs and related regulation in Ohio and the allocation of costs within regional transmission organizations, including PJM and SPP.
·
Accounting pronouncements periodically issued by accounting standard-setting bodies.
·
The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans and nuclear decommissioning trust and the impact on future funding requirements.
·
Prices and demand 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.
·
Our ability to recover through rates the remaining unrecovered investment, if any, in generating units that may be retired before the end of their previously projected useful lives.

AEP and its Registrant Subsidiaries expressly disclaim any obligation to update any forward-looking information.

 
iv

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

EXECUTIVE OVERVIEW

Economic Conditions

Retail margins increased during the first six months of 2010 due to successful rate proceedings in various jurisdictions and higher residential and commercial demand for electricity as a result of favorable weather throughout AEP’s service territory.  In comparison to the recessionary lows of 2009, industrial sales increased 9% in the second quarter and 4% during the first six months of 2010.

Due to the continued slow recovery in the U.S. economy and a corresponding negative impact on energy consumption, we implemented cost reduction initiatives in the second quarter of 2010 to reduce our workforce by 11.5% and reduce other operation and maintenance spending.  Achieving these goals involved identifying process improvements, streamlining organizational designs and developing other efficiencies that will deliver additional sustainable savings.  In the second quarter of 2010, we recorded $293 million of expense related to these cost reduction initiatives.
 
Regulatory Activity

Our significant 2010 rate proceedings include:

Kentucky – In June 2010, the KPSC approved a $64 million annual increase in base rates based on a 10.5% return on common equity.  New rates became effective with the first billing cycle of July 2010.
 
Michigan – In January 2010, I&M filed for a $63 million increase in annual base rates based on an 11.75% return on common equity.  In the August billing cycle, I&M, with MPSC authorization, will implement a $44 million interim rate increase, subject to refund with interest.
 
Oklahoma – In July 2010, PSO filed for an $82 million increase in annual base rates, including $30 million that is currently being recovered through a rider.  The requested increase is based on an 11.5% return on common equity.  PSO also requested that new rates become effective no later than July 2011.
 
Texas – In April 2010, a settlement was approved by the PUCT to increase SWEPCo’s base rates by approximately $15 million annually, effective May 2010, including a return on equity of 10.33%.  The settlement agreement also allows SWEPCo a $10 million one-year surcharge rider to recover additional vegetation management costs that SWEPCo must spend within two years.
 
Virginia – In July 2010, the Virginia SCC ordered an annual increase in revenues of $62 million based on a 10.53% return on equity.  The order disallowed future recovery of $54 million of costs related to the Mountaineer Carbon Capture and Storage Project and allowed the deferral of approximately $25 million of incremental storm expenses incurred in 2009.  As a result, APCo recorded a pretax loss of $29 million in the second quarter of 2010.  In July 2010, APCo filed a petition with the Virginia SCC for reconsideration of the order as it relates to the Mountaineer Carbon Capture and Storage Project.
 
West Virginia – In May 2010, APCo and WPCo filed a request with the WVPSC to increase annual base rates by $156 million based on an 11.75% return on common equity to be effective March 2011.  A decision from the WVPSC is expected no later than March 2011.

 
1

 
Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW coal unit in Arkansas, which is expected to be in service in 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility.  SWEPCo’s share of construction costs is currently estimated to cost $1.3 billion, excluding AFUDC, plus an additional $131 million for transmission, excluding AFUDC.  The APSC, LPSC and PUCT approved SWEPCo’s original application to build the Turk Plant.  Various proceedings are pending that challenge the Turk Plant’s construction and its approved air and wetlands permits.  In July 2010, the Arkansas Court of Appeals issued a decision remanding all transmission line CECPN appeals to the APSC.  As a result, a stay was not ordered and construction continues on the affected transmission lines.  
 
In June 2010, the Arkansas Supreme Court denied motions for rehearing filed by the APSC and SWEPCo related to the reversal of the APSC’s earlier grant of a CECPN for SWEPCo’s 88 MW Arkansas portion of the Turk Plant.  As a result, in June 2010, SWEPCo filed notice with the APSC of its intent to proceed with construction of the Turk Plant but that SWEPCo no longer intends to pursue a CECPN to seek recovery of its Arkansas portion of Turk Plant Costs in Arkansas retail rates.
 
In July 2010, the Hempstead County Hunting Club filed a complaint with the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of Interior and the U.S. Fish and Wildlife Service seeking an injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws.
 
Management expects that SWEPCo will ultimately be able to complete construction of the Turk Plant and related transmission facilities and place those facilities in service.  However, if SWEPCo is unable to complete the Turk Plant construction and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.

RESULTS OF OPERATIONS

SEGMENTS

Our reportable 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.

AEP River Operations
 
·
Commercial barging operations that transport coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.

Generation and Marketing
 
·
Wind farms and marketing and risk management activities primarily in ERCOT.

 
2

 
The table below presents our consolidated Income Before Extraordinary Loss by segment for the three and six months ended June 30, 2010 and 2009.

 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2010
 
2009
 
2010
 
2009
 
 
(in millions)
 
Utility Operations
  $ 132     $ 327     $ 476     $ 673  
AEP River Operations
    (1 )     1       2       12  
Generation and Marketing
    7       4       17       28  
All Other (a)
    (1 )     (10 )     (12 )     (28 )
Income Before Extraordinary Loss
  $ 137     $ 322     $ 483     $ 685  

(a)
While not considered a business segment, All Other includes:
 
·
Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense, and other nonallocated costs.
 
·
Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005.  These contracts are financial derivatives which gradually settle and completely expire in 2011.
 
·
Revenue sharing related to the Plaquemine Cogeneration Facility.

AEP CONSOLIDATED

Second Quarter of 2010 Compared to Second Quarter of 2009

Income Before Extraordinary Loss in 2010 decreased $185 million compared to 2009 due to $185 million of charges incurred (net of tax) in the second quarter of 2010 related to the cost reduction initiatives.

Average basic shares outstanding increased to 479 million in 2010 from 472 million in 2009.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Income Before Extraordinary Loss in 2010 decreased $202 million compared to 2009 primarily due to $185 million of charges incurred (net of tax) in the second quarter of 2010 related to the cost reduction initiatives.

Average basic shares outstanding increased to 479 million in 2010 from 440 million in 2009 primarily due to the April 2009 issuance of 69 million shares of AEP common stock.  Actual shares outstanding were 479 million as of June 30, 2010.

Our results of operations are discussed below by operating segment.
 
3

 
UTILITY OPERATIONS

We believe that a discussion of the results from our Utility Operations segment on a gross margin basis is most appropriate in order to further understand the key drivers of the segment.  Gross margin represents utility operating revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances and purchased power.

 
 
Three Months Ended
   
Six Months Ended
 
 
 
June 30,
   
June 30,
 
 
 
2010
   
2009
   
2010
   
2009
 
 
 
(in millions)
 
Revenues
  $ 3,211     $ 3,056     $ 6,637     $ 6,323  
Fuel and Purchased Power
    1,110       996       2,357       2,192  
Gross Margin
    2,101       2,060       4,280       4,131  
Depreciation and Amortization
    394       388       792       761  
Other Operating Expenses
    1,314       993       2,354       1,987  
Operating Income
    393       679       1,134       1,383  
Other Income, Net
    42       25       85       55  
Interest Expense
    237       227       472       447  
Income Tax Expense
    66       150       271       318  
Income Before Extraordinary Loss
  $ 132     $ 327     $ 476     $ 673  

Summary of KWH Energy Sales for Utility Operations
For the Three and Six Months Ended June 30, 2010 and 2009
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
June 30,
 
June 30,
Energy/Delivery Summary
2010 
 
2009
 
2010 
2009 
 
(in millions of KWH)
Retail:
 
 
 
 
 
 
 
Residential
 12,659 
 
 
 12,391 
 
 30,433 
 28,762 
Commercial
 13,002 
 
 
 12,595 
 
 24,476 
 24,205 
Industrial
 14,662 
 
 
 13,400 
 
 28,044 
 26,922 
Miscellaneous
 783 
 
 
 771 
 
 1,495 
 1,490 
Total Retail (a)
 41,106 
 
 
 39,157 
 
 84,448 
 81,379 
 
 
 
 
 
 
 
 
Wholesale
 7,019 
 
 
 7,166 
 
 15,156 
 13,943 
 
 
 
 
 
 
 
 
Total KWHs
 48,125 
 
 
 46,323 
 
 99,604 
 95,322 
 
 
 
 
 
 
 
 
(a) Includes energy delivered to customers served by AEP's Texas Wires Companies.

 
4

 
Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.  In general, degree day changes in our eastern region have a larger effect on net income than changes in our western region due to the relative size of the two regions and the number of customers within each region.

 
Summary of Heating and Cooling Degree Days for Utility Operations
 
For the Three and Six Months Ended June 30, 2010 and 2009
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
 
June 30,
June 30,
 
 
 
2010 
 
2009 
 
2010 
 
2009 
 
 
 
(in degree days)
 
Eastern Region
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 75 
 
 
 156 
 
 
 1,975 
 
 
 1,977 
 
Normal - Heating (b)
 
 170 
 
 
 171 
 
 
 1,911 
 
 
 1,962 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 434 
 
 
 300 
 
 
 434 
 
 
 305 
 
Normal - Cooling (b)
 
 289 
 
 
 286 
 
 
 293 
 
 
 290 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Western Region
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 5 
 
 
 27 
 
 
 764 
 
 
 540 
 
Normal - Heating (b)
 
 21 
 
 
 21 
 
 
 595 
 
 
 600 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (d)
 
 866 
 
 
 861 
 
 
 886 
 
 
 960 
 
Normal - Cooling (b)
 
 757 
 
 
 756 
 
 
 815 
 
 
 812 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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 cooling degree days are calculated on a 65 degree temperature base.
 
(d)
Western Region cooling degree days are calculated on a 65 degree temperature base for PSO/SWEPCo and a 70 degree temperature base for TCC/TNC.

 
5

 

Second Quarter of 2010 Compared to Second Quarter of 2009
 
 
 
 
 
Reconciliation of Second Quarter of 2009 to Second Quarter of 2010
 
Income from Utility Operations Before Extraordinary Loss
 
(in millions)
 
 
 
 
 
Second Quarter of 2009
  $ 327  
 
       
Changes in Gross Margin:
       
Retail Margins
    115  
Off-system Sales
    (12 )
Transmission Revenues
    (2 )
Other Revenues
    (60 )
Total Change in Gross Margin
    41  
 
       
Total Expenses and Other:
       
Other Operation and Maintenance
    (307 )
Depreciation and Amortization
    (6 )
Taxes Other Than Income Taxes
    (14 )
Interest and Investment Income
    11  
Carrying Costs Income
    7  
Allowance for Equity Funds Used During Construction
    (1 )
Interest Expense
    (10 )
Total Expenses and Other
    (320 )
 
       
Income Tax Expense
    84  
 
       
Second Quarter of 2010
  $ 132  

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

·
Retail Margins increased $115 million primarily due to the following:
 
·
A $22 million increase in the recovery of E&R costs in Virginia, construction financing costs in West Virginia and costs related to the Transmission Rate Adjustment Clause in Virginia, a $13 million increase in the recovery of advanced metering costs in Texas and a $13 million net increase in rates in our other jurisdictions.  These increases in retail margins had corresponding offsets of $26 million related to cost recovery riders/trackers that were recognized in the other gross margin/other expense line items below.
 
·
A $34 million increase in weather-related usage primarily due to a 45% increase in cooling degree days in our eastern region.
 
·
A $20 million increase in fuel margins due to higher fuel and purchased power costs recorded in 2009 related to the Cook Plant Unit 1 (Unit 1) shutdown.  This increase in fuel margins was offset by a corresponding decrease in Other Revenues as discussed below.
 
These increases were partially offset by:
 
·
A $9 million decrease due to the termination of an I&M unit power agreement.
·
Margins from Off-system Sales decreased $12 million primarily due to lower trading and marketing margins, partially offset by higher physical sales volumes.
·
Other Revenues decreased $60 million primarily due to the Cook Plant accidental outage insurance proceeds of $46 million, which ended when Unit 1 returned to service in December 2009.  I&M reduced customer bills by approximately $20 million in the second quarter of 2009 for the cost of replacement power resulting from the Unit 1 outage.  This decrease in insurance proceeds was offset by a corresponding increase in Retail Margins as discussed above.

 
6

 
Total Expenses and Other and Income Taxes changed between years as follows:

·
Other Operation and Maintenance expenses increased $307 million primarily due to the following:
 
·
A $278 million increase due to expenses related to the cost reduction initiatives in the second quarter of 2010.
 
·
A $54 million increase due to the write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Project as denied for recovery by the Virginia SCC.
 
·
A $27 million increase in demand side management, energy efficiency, vegetation management programs and other costs which have associated cost recovery riders/trackers that were recognized in retail revenues.
 
These increases were partially offset by:
 
·
A $25 million decrease due to the deferral of 2009 storm costs as allowed by the Virginia SCC.
 
·
A $14 million decrease in plant outage and other plant operating and maintenance expenses.
·
Depreciation and Amortization increased $6 million primarily due to new environmental improvements placed in service and other increases in depreciable property balances.
·
Taxes Other Than Income Taxes increased $14 million primarily due to the employer portion of payroll taxes incurred related to the cost reduction initiatives in the second quarter of 2010.
·
Interest and Investment Income increased $11 million primarily due to the second quarter 2009 write-off of other-than-temporary losses related to equity investments made by EIS.
·
Carrying Costs Income increased $7 million primarily due to increased environmental deferrals in Virginia and a higher under-recovered fuel balance for OPCo.
·
Interest Expense increased $10 million primarily due to an increase in long-term debt.
·
Income Tax Expense decreased $84 million primarily due to a decrease in pretax book income.

 
7

 

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009
 
 
 
 
 
Reconciliation of Six Months Ended June 30, 2009 to Six Months Ended June 30, 2010
Income from Utility Operations Before Extraordinary Loss
(in millions)
 
 
 
 
 
Six Months Ended June 30, 2009
 
$
 673 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
Retail Margins
 
 
 283 
 
Off-system Sales
 
 
 1 
 
Transmission Revenues
 
 
 8 
 
Other Revenues
 
 
 (143)
 
Total Change in Gross Margin
 
 
 149 
 
 
 
 
 
 
Total Expenses and Other:
 
 
 
 
Other Operation and Maintenance
 
 
 (344)
 
Depreciation and Amortization
 
 
 (31)
 
Taxes Other Than Income Taxes
 
 
 (23)
 
Interest and Investment Income
 
 
 8 
 
Carrying Costs Income
 
 
 12 
 
Allowance for Equity Funds Used During Construction
 
 
 7 
 
Interest Expense
 
 
 (25)
 
Equity Earnings of Unconsolidated Subsidiaries
 
 
 3 
 
Total Expenses and Other
 
 
 (393)
 
 
 
 
 
 
Income Tax Expense
 
 
 47 
 
 
 
 
 
 
Six Months Ended June 30, 2010
 
$
 476 
 

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

·
Retail Margins increased $283 million primarily due to the following:
 
·
A $75 million increase in the recovery of E&R costs in Virginia, construction financing costs in West Virginia and costs related to the Transmission Rate Adjustment Clause in Virginia, a $25 million increase in the recovery of advanced metering costs in Texas, a $19 million rate increase in Oklahoma, a $17 million net rate increase for I&M, a $13 million net increase in rates for SWEPCo and a $27 million net increase in rates in our other jurisdictions.  These increases in retail margins had corresponding offsets of $64 million related to cost recovery riders/trackers that were recognized in the other gross margin/other expense line items below.
 
·
A $71 million increase in weather-related usage primarily due to a 43% increase in cooling degree days in our eastern region and a 41% increase in heating degree days in our western region.
 
·
A $42 million increase in fuel margins due to higher fuel and purchased power costs recorded in 2009 related to the Unit 1 shutdown.  This increase in fuel margins was offset by a corresponding decrease in Other Revenues as discussed below.
 
These increases were partially offset by:
 
·
A $17 million decrease due to the termination of an I&M unit power agreement.
·
Transmission Revenues increased $8 million primarily due to increased revenues in the ERCOT, PJM and SPP regions.
·
Other Revenues decreased $143 million primarily due to the Cook Plant accidental outage insurance proceeds of $99 million which ended when Unit 1 returned to service in December 2009.  I&M reduced customer bills by approximately $42 million in the first six months of 2009 for the cost of replacement power resulting from the Unit 1 outage.  This decrease in insurance proceeds was offset by a corresponding increase in Retail Margins as discussed above.  Other Revenues also decreased due to lower gains on sales of emission allowances of $23 million.

 
8

 
Total Expenses and Other and Income Taxes changed between years as follows:

·
Other Operation and Maintenance expenses increased $344 million primarily due to the following:
 
·
A $278 million increase due to expenses related to the cost reduction initiatives in the second quarter of 2010.
 
·
A $72 million increase in demand side management, energy efficiency, vegetation management programs and other costs which have associated cost recovery riders/trackers that were recognized in retail revenues.
 
·
 
A $54 million increase due to the write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Project as denied for recovery by the Virginia SCC.
 
These increases were partially offset by:
 
·
A $59 million decrease in storm expenses including the deferral of $25 million of 2009 storm costs as allowed by the Virginia SCC.
·
Depreciation and Amortization increased $31 million primarily due to new environmental improvements placed in service and other increases in depreciable property balances.
·
Taxes Other Than Income Taxes increased $23 million primarily due to the employer portion of payroll taxes incurred related to the cost reduction initiatives in the second quarter of 2010 and higher franchise and property taxes.
·
Interest and Investment Income increased $8 million primarily due to the second quarter 2009 write-off of other-than-temporary losses related to equity investments made by EIS.
·
Carrying Costs Income increased $12 million primarily due to increased environmental deferrals in Virginia and a higher under-recovered fuel balance for OPCo.
·
Allowance for Equity Funds Used During Construction increased $7 million related to construction projects at SWEPCo’s Turk Plant and Stall Unit and the reapplication of “Regulated Operations” accounting guidance for the generation portion of SWEPCo’s Texas retail jurisdiction effective the second quarter of 2009.
·
Interest Expense increased $25 million primarily due to an increase in long-term debt and a decrease in the debt component of AFUDC due to lower CWIP balances at APCo, CSPCo and OPCo.
·
Income Tax Expense decreased $47 million primarily due to a decrease in pretax book income, partially offset by the regulatory accounting treatment of state income taxes, other book/tax differences which are accounted for on a flow-through basis and the tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.

AEP RIVER OPERATIONS

Second Quarter of 2010 Compared to Second Quarter of 2009

Income Before Extraordinary Loss from our AEP River Operations segment decreased from income of $1 million in 2009 to a loss of $1 million in 2010 primarily due to expenses related to the cost reduction initiatives, increased interest expense on new long-term debt and increased lease expense on new barge leases.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Income Before Extraordinary Loss from our AEP River Operations segment decreased from $12 million in 2009 to $2 million in 2010 primarily due to reduced grain loadings, higher fuel and other operating expenses, expenses related to the cost reduction initiatives, interest expense on increased long-term debt, increased lease expense on new barge leases and a gain on the sale of two older towboats in 2009.

GENERATION AND MARKETING

Second Quarter of 2010 Compared to Second Quarter of 2009

Income Before Extraordinary Loss from our Generation and Marketing segment increased from $4 million in 2009 to $7 million in 2010 primarily due to favorable marketing contracts in ERCOT and increased income from our wind farm operations.
 
9

 
Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Income Before Extraordinary Loss from our Generation and Marketing segment decreased from $28 million in 2009 to $17 million in 2010 primarily due to reduced inception gains from ERCOT marketing activities partially offset by improved plant performance, hedging activities on our generation assets and increased income from our wind farm operations.

ALL OTHER

Second Quarter of 2010 Compared to Second Quarter of 2009

Income Before Extraordinary Loss from All Other increased from a loss of $10 million in 2009 to a loss of $1 million in 2010 primarily due to $16 million in pretax gains ($10 million, net of tax) on the sale of our remaining 138,000 shares of Intercontinental Exchange, Inc. (ICE) in the second quarter of 2010.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Income Before Extraordinary Loss from All Other increased from a loss of $28 million in 2009 to a loss of $12 million in 2010 due to $16 million in pretax gains ($10 million, net of tax) on the sale of our remaining 138,000 shares of ICE in the second quarter of 2010.

AEP SYSTEM INCOME TAXES

Second Quarter of 2010 Compared to Second Quarter of 2009

Income Tax Expense decreased $83 million in comparison to 2009 primarily due to a decrease in pretax book income.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Income Tax Expense decreased $55 million in comparison to 2009 primarily due to a decrease in pretax book income, partially offset by the regulatory accounting treatment of state income taxes, other book/tax differences which are accounted for on a flow-through basis and the tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.

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, 2010
   
December 31, 2009
 
 
 
($ in millions)
 
Long-term Debt, including amounts due within one year
  $ 17,348       53.9 %   $ 17,498       56.8 %
Short-term Debt
    1,473       4.6       126       0.4  
Total Debt
    18,821       58.5       17,624       57.2  
Preferred Stock of Subsidiaries
    60       0.2       61       0.2  
AEP Common Equity
    13,269       41.3       13,140       42.6  
Noncontrolling Interests
    1       -       -       -  
 
                               
Total Debt and Equity Capitalization
  $ 32,151       100.0 %   $ 30,825       100.0 %

Our ratio of debt-to-total capital increased from 57.2% in 2009 to 58.5% in 2010 primarily due to an increase in short-term debt of $677 million as a result of a change in an accounting standard applicable to our sale of receivables agreement and an increase of $668 million in commercial paper outstanding.
 
10

 
LIQUIDITY

Liquidity, or access to cash, is an important factor in determining our financial stability.  We believe we have adequate liquidity under our existing credit facilities.  At June 30, 2010, we had $3.4 billion in aggregate credit facility commitments to support our operations.  Additional liquidity is available from cash from operations and a sale of receivables agreement.  We are committed to maintaining adequate liquidity.  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 long-term debt, sale-leaseback or leasing agreements or common stock.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments.  At June 30, 2010, our available liquidity was approximately $2.9 billion as illustrated in the table below:

 
 
 
Amount
 
Maturity
 
 
 
(in millions)
 
 
Commercial Paper Backup:
 
 
 
 
 
 
Revolving Credit Facility
 
$
 1,454 
 
April 2012
 
Revolving Credit Facility
 
 
 1,500 
 
June 2013
Revolving Credit Facility
 
 
 478 
 
April 2011
Total
 
 
 3,432 
 
 
Cash and Cash Equivalents
 
 
 838 
 
 
Total Liquidity Sources
 
 
 4,270 
 
 
Less:
AEP Commercial Paper Outstanding
 
 
 787 
 
 
 
Letters of Credit Issued
 
 
 626 
 
 
 
 
 
 
 
 
 
Net Available Liquidity
 
$
 2,857 
 
 
 
 
 
 
 
 
 

We have credit facilities totaling $3.4 billion, of which two $1.5 billion credit facilities support our commercial paper program.  One of the $1.5 billion credit facilities allows for the issuance of up to $750 million as letters of credit.  In June 2010, we canceled a facility that was scheduled to mature in March 2011.  We also entered a new $1.5 billion credit facility in June 2010, which matures in 2013, that allows for the issuance of up to $600 million as letters of credit.  In June 2010, we reduced the credit facility that matures in April 2011 from $627 million to $478 million which can be utilized for letters of credit or draws.

We use our commercial paper program to meet the short-term borrowing needs of our subsidiaries.  The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries.  In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons.  The maximum amount of commercial paper outstanding during 2010 was $802 million.  The weighted-average interest rate for our commercial paper during 2010 was 0.42%.

Securitized Accounts Receivables

In July 2010, we renewed our receivables securitization agreement.  The agreement provides a commitment of $750 million from bank conduits to purchase receivables.  A commitment of $375 million expires in July 2011 and the remaining commitment of $375 million expires in July 2013.
 
11

 
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, 2010, this contractually-defined percentage was 54.8%.  Nonperformance under these covenants could result in an event of default under these credit agreements.  At June 30, 2010, 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 in a majority of our non-exchange traded commodity contracts which would permit the lenders and counterparties to declare the outstanding amounts payable.  However, a default under our non-exchange traded commodity contracts does not cause an event of default under our revolving credit agreements.

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

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders.  At June 30, 2010, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

The Board of Directors declared a quarterly dividend of $0.42 per share in July 2010.  Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements, as well as financial and other business conditions existing at the time.  Our income derives from our common stock equity in the earnings of our utility subsidiaries.  Various financing arrangements, charter provisions and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends. We have the option to defer interest payments on the AEP Junior Subordinated Debentures for one or more periods of up to 10 consecutive years per period.  During any period in which we defer interest payments, we may not declare or pay any dividends or distributions on, or redeem, repurchase or acquire, our common stock.  We believe that these restrictions will not have a material effect on our cash flows or financial condition or limit any dividend payments in the foreseeable future.

Credit Ratings

Our access to the commercial paper market may depend on our credit ratings.  In addition, downgrades in our credit ratings by one of the rating agencies could increase our borrowing costs.
 
CASH FLOW

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

 
Six Months Ended
 
 
June 30,
 
 
2010
 
2009
 
 
(in millions)
 
Cash and Cash Equivalents at Beginning of Period
  $ 490     $ 411  
Net Cash Flows from Operating Activities
    582       857  
Net Cash Flows Used for Investing Activities
    (992 )     (1,478 )
Net Cash Flows from Financing Activities
    758       568  
Net Increase (Decrease) in Cash and Cash Equivalents
    348       (53 )
Cash and Cash Equivalents at End of Period
  $ 838     $ 358  

 
12

 
Cash from operations and short-term borrowings provides working capital and allows us to meet other short-term cash needs.

Operating Activities
 
 
 
   
 
 
 
Six Months Ended
 
 
June 30,
 
 
2010
 
2009
 
 
(in millions)
 
Net Income
  $ 483     $ 680  
Depreciation and Amortization
    813       779  
Other
    (714 )     (602 )
Net Cash Flows from Operating Activities
  $ 582     $ 857  

Net Cash Flows from Operating Activities were $582 million in 2010 consisting primarily of Net Income of $483 million and $813 million of noncash Depreciation and Amortization.  Other includes a $656 million increase in securitized receivables under the application of new accounting guidance for “Transfers and Servicing” related to our sale of receivables agreement.  Other changes 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.  Significant changes in other items include an increase in under-recovered fuel primarily due to the deferral of fuel under the FAC in Ohio and higher fuel costs in Oklahoma, accrued tax benefits and the favorable impact of a decrease in fuel inventory.  Deferred Income Taxes increased primarily due to the American Recovery and Reinvestment Act of 2009 extending bonus depreciation provisions, a change in tax accounting method and an increase in tax versus book temporary differences from operations.

Net Cash Flows from Operating Activities were $857 million in 2009 consisting primarily of Net Income of $680 million and $779 million of noncash Depreciation and Amortization.  Other represents 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.  Significant changes in other items include the negative impact on cash of an increase in coal inventory reflecting decreased customer demand for electricity as the result of the economic slowdown and an increase in under-recovered fuel primarily due to the deferral of fuel costs in Ohio as a fuel clause was reactivated in 2009.
 
Investing Activities
 
 
 
   
 
 
 
Six Months Ended
 
 
June 30,
 
 
2010
 
2009
 
 
(in millions)
 
Construction Expenditures
  $ (1,104 )   $ (1,547 )
Acquisitions of Nuclear Fuel
    (41 )     (152 )
Proceeds from Sales of Assets
    147       240  
Other
    6       (19 )
Net Cash Flows Used for Investing Activities
  $ (992 )   $ (1,478 )

Net Cash Flows Used for Investing Activities were $992 million in 2010 primarily due to Construction Expenditures for new generation, environmental and distribution investments.  Proceeds from Sales of Assets in 2010 include $135 million for sales of Texas transmission assets to ETT.

Net Cash Flows Used for Investing Activities were $1.5 billion in 2009 primarily due to Construction Expenditures for our new generation, environmental and distribution investments.  Proceeds from Sales of Assets in 2009 include $104 million relating to the sale of a portion of Turk Plant to joint owners and $92 million for sales of transmission assets in Texas to ETT.
 
13

 
Financing Activities
 
 
 
   
 
 
 
Six Months Ended
 
 
June 30,
 
 
2010
 
2009
 
 
(in millions)
 
Issuance of Common Stock, Net
  $ 42     $ 1,688  
Issuance/Retirement of Debt, Net
    1,166       (711 )
Dividends Paid on Common Stock
    (399 )     (364 )
Other
    (51 )     (45 )
Net Cash Flows from Financing Activities
  $ 758     $ 568  

Net Cash Flows from Financing Activities were $758 million in 2010.  Our net debt issuances were $1.2 billion.  The net issuances included issuances of $884 million of notes and $287 million of pollution control bonds, a $668 million increase in commercial paper outstanding and retirements of $1 billion of senior unsecured notes, $86 million of securitization bonds and $183 million of pollution control bonds.  Our short-term debt securitized by receivables increased $656 million under the application of new accounting guidance for “Transfers and Servicing” related to our sale of receivables agreement.  We paid common stock dividends of $399 million.  See Note 11 – Financing Activities for a complete discussion of long-term debt issuances and retirements.

Net Cash Flows from Financing Activities in 2009 were $568 million.  Issuance of Common Stock, Net of $1.7 billion is comprised of our issuance of 69 million shares of common stock with net proceeds of $1.64 billion and additional shares through our dividend reinvestment, employee savings and incentive programs.  Our net debt retirements were $711 million. These retirements included a repayment of $1.75 billion outstanding under our credit facilities primarily from the proceeds of our common stock issuance and issuances of $955 million of senior unsecured notes and $135 million of pollution control bonds.
 
OFF-BALANCE SHEET ARRANGEMENTS

In prior periods, under a limited set of circumstances, we entered into off-balance sheet arrangements for various reasons including accelerating cash collections, reducing operational expenses and spreading risk of loss to third parties.  Our current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements and transfers of customer accounts receivable that we enter in the normal course of business.  The following identifies significant off-balance sheet arrangements:

 
June 30,
 
December 31,
 
 
2010
 
2009
 
 
(in millions)
 
AEP Credit Accounts Receivable Purchase Commitments
  $ -     $ 631  
Rockport Plant Unit 2 Future Minimum Lease Payments
    1,846       1,920  
Railcars Maximum Potential Loss From Lease Agreement
    25       25  

Effective January 1, 2010, we record the receivables and debt related to AEP Credit on our Condensed Consolidated Balance Sheet.  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 2009 Annual Report.

SUMMARY OBLIGATION INFORMATION

A summary of our contractual obligations is included in our 2009 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” above.
 
14

 
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 2009 Annual Report.  The 2009 Annual Report should be read in conjunction with this report in order to understand significant factors which have not materially changed in status since the issuance of our 2009 Annual Report, but may have a material impact on our future net income, cash flows and financial condition.

REGULATORY ISSUES

Ohio Electric Security Plan Filings

During 2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s ESPs which established rates through 2011.  The order also limits rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011.  The order provides a FAC for the three-year period of the ESP.  Several notices of appeal are outstanding at the Supreme Court of Ohio relating to significant issues in the determination of the approved ESP rates.  CSPCo and OPCo will file their significantly excessive earnings test with the PUCO by their September 2010 deadline.  CSPCo and OPCo are unable to determine whether they will be required to return any of their ESP revenues to customers.  See “Ohio Electric Security Plan Filings” section of Note 3.

Cook Plant Unit 1 Fire and Shutdown

In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator. Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $395 million.  Management believes that I&M should recover a significant portion of repair and replacement costs through the turbine vendor’s warranty, insurance and the regulatory process.  I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power.  The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors.  As a result, the replacement of the repaired turbine rotors and other equipment is scheduled for the Unit 1 planned outage in the fall of 2011.  If the ultimate costs of the incident are not covered by warranty, insurance or through the related regulatory process or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.  See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.

Texas Restructuring Appeals

Pursuant to PUCT restructuring orders, TCC securitized net recoverable stranded generation costs of $2.5 billion and is recovering the principal and interest on the securitization bonds through the end of 2020.  TCC also refunded other net true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider under PUCT restructuring orders.  TCC and intervenors appealed the PUCT’s true-up related orders.  After rulings from the Texas District Court and the Texas Court of Appeals, TCC, the PUCT and intervenors filed petitions for review with the Texas Supreme Court.  Review is discretionary and the Texas Supreme Court has not yet determined if it will grant review.  See “Texas Restructuring Appeals” section of Note 3.

Mountaineer Carbon Capture and Storage Project

APCo and ALSTOM Power, Inc. (Alstom), an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009.  APCo also constructed and owns the necessary facilities to store the CO2.  In APCo’s July 2009 Virginia base rate filing and APCo’s May 2010 West Virginia base rate filing, APCo requested recovery of and a return on its estimated increased Virginia and West Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion.  In July 2010, the Virginia SCC issued a base rate order that denied recovery of the Virginia share of the Mountaineer Carbon Capture and Storage Project costs, which resulted in a pretax write-off of approximately $54 million in the second quarter of 2010.  In response to the order, APCo filed with the Virginia SCC a petition for
 
15

 
reconsideration of the order as it relates to the Mountaineer Carbon Capture and Storage Project.  Through June 30, 2010, APCo has recorded a noncurrent regulatory asset of $58 million consisting of $38 million in project costs and $20 million in asset retirement costs.  If APCo cannot recover its remaining investments in and expenses related to the Mountaineer Carbon Capture and Storage project, it would reduce future net income and cash flows and impact financial condition.  See “Mountaineer Carbon Capture and Storage Project” section of Note 3.

Turk Plant

SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in-service in 2012.  SWEPCo owns 73% of the Turk Plant and will operate the completed facility.  The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, plus an additional $131 million for transmission, excluding AFUDC.  SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus an additional $131 million for transmission, excluding AFUDC.  Notices of appeal are outstanding at the Arkansas Court of Appeals and the Circuit Court of Hempstead County, Arkansas.  Matters are also outstanding at the LPSC, the Texas Court of Appeals and the Federal District Court for the Western District of Arkansas.  See “Turk Plant” section of Note 3.

LITIGATION

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be.  We assess the probability of loss for each contingency and accrue a liability for cases that have a probable likelihood of loss if the loss can be estimated.  For details on our regulatory proceedings and 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 2009 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 our net income.

ENVIRONMENTAL ISSUES

We are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements.  We anticipate making additional investments and operational changes.  The most significant sources are the existing and anticipated CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants from fossil fuel-fired power plants and new proposals governing the beneficial use and disposal of coal combustion products.
 
We are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of our nuclear units.  We are also engaged in the development of possible future requirements to reduce CO2 emissions to address concerns about global climate change.  See a complete discussion of these matters in the “Environmental Matters” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2009 Annual Report.

Clean Air Act Transport Rule (Transport Rule)

In July 2010, the Federal EPA issued a proposed rule to replace the Clean Air Interstate Rule (CAIR) that would impose new and more stringent requirements to control SO2 and NOx emissions from fossil fuel-fired electric generating units in 31 states and the District of Columbia.  Each state covered by the Transport Rule is assigned an allowance budget for SO2 and/or NOx.  Limited interstate trading is allowed on a sub-regional basis and intrastate trading is allowed among generating units.  Certain of our western states (Texas, Arkansas and Oklahoma) would be subject to only the seasonal NOx program, with new limits that are proposed to take effect in 2012.  The remainder of the states in which we operate would be subject to seasonal and annual NOx programs and an annual SO2 emissions reduction program that takes effect in two phases.  The first phase becomes effective in 2012 and requires approximately 1 million tons per year more SO2 emission reductions across the region than would have been required under CAIR.  The second phase takes effect in 2014 and reduces emissions by an additional 800,000 tons per year.  The SO2 and NOx programs rely on newly-created allowances rather than relying on the CAIR NOx allowances or the Title IV Acid Rain Program allowances used in the CAIR rule.  The time frames for and
 
16

 
stringency of the additional emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and our electric utility customers, as these features could accelerate unit retirements, increase capital requirements, constrain operations and decrease reliability.  Comments on the proposed rule will be due within 60 days after publication in the Federal Register.

Coal Combustion Residual Rule

In June 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at our coal-fired electric generating units.  The rule contains two alternative proposals, one that would impose federal hazardous waste disposal and management standards on these materials and one that would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management.  Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and initiate closure within five years of the issuance of a final rule.

Currently, approximately 40% of the coal ash and other residual products from our generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses.  Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes.  In addition, we currently use surface impoundments and landfills to manage these materials at our generating facilities and will incur significant costs to upgrade or close and replace these existing facilities.  We are currently studying the potential costs associated with this proposal and expect that it will impose significant costs.  We will seek recovery of expenditures for pollution control technologies and associated costs from customers through our regulated rates (in regulated jurisdictions).  We should be able to recover these expenditures through market prices in deregulated jurisdictions.  If not, these costs could adversely affect future net income, cash flows and possibly financial condition.

Global Warming

While comprehensive economy-wide regulation of CO2 emissions might be achieved through new legislation, Congress has yet to enact such legislation.  The Federal EPA continues to take action to regulate CO2 emissions under the existing requirements of the CAA.  The Federal EPA issued a final endangerment finding for CO2 emissions from new motor vehicles in December 2009 and final rules for new motor vehicles in May 2010.  The Federal EPA determined that CO2 emissions from stationary sources will be subject to regulation under the CAA beginning in January 2011 at the earliest and finalized its proposed scheme to streamline and phase-in regulation of stationary source CO2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs.  The Federal EPA is reconsidering whether to include CO2 emissions in a number of stationary source standards, including standards that apply to new and modified electric utility units.

Our fossil fuel-fired generating units are very large sources of CO2 emissions.  If substantial CO2 emission reductions are required, there will be significant increases in capital expenditures and operating costs which would impact the ultimate retirement of older, less-efficient, coal-fired units.  To the extent we install additional controls on our generating plants to limit CO2 emissions and receive regulatory approvals to increase our rates, cost recovery could have a positive effect on future earnings.  Prudently incurred capital investments made by our subsidiaries in rate-regulated jurisdictions to comply with legal requirements and benefit customers are generally included in rate base for recovery and earn a return on investment.  We would expect these principles to apply to investments made to address new environmental requirements.  However, requests for rate increases reflecting these costs can affect us adversely because our regulators could limit the amount or timing of increased costs that we would recover through higher rates.  In addition, to the extent our costs are relatively higher than our competitors’ costs, such as operators of nuclear generation, it could reduce our off-system sales or cause us to lose customers in jurisdictions that permit customers to choose their supplier of generation service.
 
17

 
Several states have adopted programs that directly regulate CO2 emissions from power plants, but none of these programs are currently in effect in states where we have generating facilities.  Certain states, including Ohio, Michigan, Texas and Virginia, passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements.  We are taking steps to comply with these requirements.

Certain groups have filed lawsuits alleging that emissions of CO2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others.  We have been named in pending lawsuits, which we are vigorously defending.  It is not possible to predict the outcome of these lawsuits or their impact on our operations or financial condition.  See “Carbon Dioxide Public Nuisance Claims” and “Alaskan Villages’ Claims” sections of Note 4.

Future federal and state legislation or regulations that mandate limits on the emission of CO2 would result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs.  Excessive costs to comply with future legislation or regulations might force our utility subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets.  As a result, mandatory limits could have a material adverse impact on our net income, cash flows and financial condition.

For detailed information on global warming and the actions we are taking to address potential impacts, see Part I of the 2009 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters – Global Warming” and “Management’s Financial Discussion and Analysis of Results of Operations.”

CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

See the “Critical Accounting Policies and Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2009 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.

NEW ACCOUNTING PRONOUNCEMENTS

New Accounting Pronouncements Adopted During 2010

We adopted ASU 2009-16 “Transfers and Servicing” effective January 1, 2010.  The adoption of this standard resulted in AEP Credit’s transfers of receivables being accounted for as financings with the receivables and short-term debt recorded on our balance sheet.

We adopted the prospective provisions of ASU 2009-17 “Consolidations” effective January 1, 2010.  We no longer consolidate DHLC effective with the adoption of this standard.

See Note 2 for further discussion of accounting pronouncements.

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, we cannot determine the impact on the reporting of our operations and financial position that may result from any such future changes.  The FASB is currently working on several projects including revenue recognition, contingencies, financial instruments, emission allowances, fair value measurements, leases, insurance, hedge accounting, consolidation policy and discontinued operations.  We also expect to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP.  The ultimate pronouncements resulting from these and future projects could have an impact on our future net income and financial position.
 
18

 
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

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

Our Generation and Marketing segment, operating primarily within ERCOT, transacts in wholesale energy trading and marketing contracts.  This segment is exposed to certain market risks as a marketer of wholesale electricity.  These risks include commodity price risk, interest rate risk and credit risk.  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 financial derivatives, which gradually settle and completely expire in 2011.  Our risk objective is to keep these positions generally risk neutral through maturity.

We employ risk management contracts including physical forward purchase and sale contracts and financial forward purchase and sale contracts.  We engage in risk management of electricity, coal, natural gas and emission allowances 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 oversight 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 Executive Vice President - Generation, Chief Financial Officer, Senior Vice President of Commercial Operations and Chief Risk Officer.  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.
 
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The following table summarizes the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2009:

MTM Risk Management Contract Net Assets (Liabilities)
 
Six Months Ended June 30, 2010
 
(in millions)
 
 
 
 
   
Generation
   
 
   
 
 
 
 
Utility
   
and
   
 
   
 
 
 
 
Operations
   
Marketing
   
All Other
   
Total
 
Total MTM Risk Management Contract Net Assets (Liabilities)
 
 
   
 
   
 
   
 
 
at December 31, 2009
  $ 134     $ 147     $ (3 )   $ 278  
(Gain) Loss from Contracts Realized/Settled During the Period and
                               
Entered in a Prior Period
    (39 )     (9 )     3       (45 )
Fair Value of New Contracts at Inception When Entered During the
                               
Period (a)
    8       8       -       16  
Net Option Premiums 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 (b)
    (2 )     (2 )     -       (4 )
Changes in Fair Value Due to Market Fluctuations During the
                               
Period (c)
    10       6       -       16  
Changes in Fair Value Allocated to Regulated Jurisdictions (d)
    22       -       -       22  
Total MTM Risk Management Contract Net Assets
                               
at June 30, 2010
  $ 132     $ 150     $ -       282  
 
                               
Cash Flow Hedge Contracts
                            (2 )
Fair Value Hedge Contracts
                            4  
Collateral Deposits
                            77  
Total MTM Derivative Contract Net Assets at June 30, 2010
                          $ 361  

(a)
Reflects fair value on long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices.  The contract prices are valued against market curves associated with the delivery location and delivery term.  A significant portion of the total volumetric position has been economically hedged.
(b)
Reflects changes in methodology in calculating the credit and discounting liability fair value adjustments.
(c)
Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(d)
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 liabilities/assets.

See Note 8 – Derivatives and Hedging and Note 9 – Fair Value Measurements for additional information related to our risk management contracts.  The following tables and discussion provide information on our credit risk and market volatility risk.
 
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Credit Risk

We limit credit risk in our wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis.  We use Moody’s Investors Service, Standard & Poor’s and current market-based qualitative and quantitative data to assess the financial health of counterparties on an ongoing basis.  If an external rating is not available, an internal rating is generated utilizing a quantitative tool developed by Moody’s to estimate probability of default that corresponds to an implied external agency credit rating.

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, 2010, our credit exposure net of collateral to sub investment grade counterparties was approximately 8.0%, 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, 2010, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

 
 
 
Exposure
 
 
 
 
 
Number of
 
Net Exposure
 
 
Before
 
 
Counterparties
of
 
 
Credit
Credit
Net
>10% of
Counterparties
Counterparty Credit Quality
Collateral
Collateral
Exposure
Net Exposure
>10%
 
 
 
(in millions, except number of counterparties)
Investment Grade
 
$
 717 
 
$
 46 
 
$
 671 
 
 
 1 
 
$
 152 
Split Rating
 
 
 4 
 
 
 - 
 
 
 4 
 
 
 1 
 
 
 4 
Noninvestment Grade
 
 
 3 
 
 
 1 
 
 
 2 
 
 
 4 
 
 
 2 
No External Ratings:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Internal Investment Grade
 
 
 145 
 
 
 - 
 
 
 145 
 
 
 3 
 
 
 100 
 
Internal Noninvestment Grade
 
 
 82 
 
 
 11 
 
 
 71 
 
 
 3 
 
 
 63 
Total as of June 30, 2010
 
$
 951 
 
$
 58 
 
$
 893 
 
 
 12 
 
$
 321 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total as of December 31, 2009
 
$
 846 
 
$
 58 
 
$
 788 
 
 
 12 
 
$
 317 

Value at Risk (VaR) Associated with Risk Management Contracts

We use a risk measurement model, which calculates 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, as of June 30, 2010, a near term typical change in commodity prices is not expected to have a material effect on our net income, 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
       
Twelve Months Ended
June 30, 2010
       
December 31, 2009
(in millions)
       
(in millions)
End
 
High
 
Average
 
Low
       
End
 
High
 
Average
 
Low
$1
 
$2
 
$1
 
$-
       
$1
 
$2
 
$1
 
$-

We back-test our VaR results against performance due to actual price movements.  Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.
 
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As our VaR calculation captures recent price movements, we also perform regular stress testing of the portfolio to understand our exposure to extreme price movements.  We employ a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last four years in order to ascertain which historical price movements translated into the largest potential MTM loss.  We then research the underlying positions, price moves and market events that created the most significant exposure and report the findings to the Risk Executive Committee or the CORC as appropriate.

Interest Rate Risk

We utilize an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which AEP’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense.  The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence.  The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months.  As calculated on debt outstanding as of June 30, 2010 and December 31, 2009, the estimated EaR on our debt portfolio for the following twelve months was $3 million and $4 million, respectively.
 
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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
 
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
For the Three and Six Months Ended June 30, 2010 and 2009
 
(in millions, except per-share and share amounts)
 
(Unaudited)
 
 
 
 
   
 
   
 
   
 
 
 
 
Three Months Ended
   
Six Months Ended
 
 
 
2010
   
2009
   
2010
   
2009
 
REVENUES
 
 
   
 
   
 
   
 
 
Utility Operations
  $ 3,186     $ 3,035     $ 6,592     $ 6,302  
Other Revenues
    174       167       337       358  
TOTAL REVENUES
    3,360       3,202       6,929       6,660  
EXPENSES
                               
Fuel and Other Consumables Used for Electric Generation
    895       764       1,909       1,693  
Purchased Electricity for Resale
    227       258       465       553  
Other Operation
    994       638       1,667       1,248  
Maintenance
    243       271       514       566  
Depreciation and Amortization
    405       397       813       779  
Taxes Other Than Income Taxes
    202       192       409       389  
TOTAL EXPENSES
    2,966       2,520       5,777       5,228  
 
                               
OPERATING INCOME
    394       682       1,152       1,432  
 
                               
Other Income (Expense):
                               
Interest and Investment Income (Loss)
    18       (5 )     21       -  
Carrying Costs Income
    19       12       33       21  
Allowance for Equity Funds Used During Construction
    19       20       43       36  
Interest Expense
    (249 )     (240 )     (499 )     (478 )
 
                               
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
    201       469       750       1,011  
 
                               
Income Tax Expense
    65       148       272       327  
Equity Earnings of Unconsolidated Subsidiaries
    1       1       5       1  
 
                               
INCOME BEFORE EXTRAORDINARY LOSS
    137       322       483       685  
 
                               
EXTRAORDINARY LOSS, NET OF TAX
    -       (5 )     -       (5 )
 
                               
NET INCOME
    137       317       483       680  
 
                               
Less:  Net Income Attributable to Noncontrolling Interests
    1       1       2       3  
 
                               
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS
    136       316       481       677  
 
                               
Less: Preferred Stock Dividend Requirements of Subsidiaries
    -       -       1       1  
 
                               
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
  $ 136     $ 316     $ 480     $ 676  
 
                               
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
    479,050,774       472,220,041       478,741,871       439,703,968  
 
                               
BASIC EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
                               
Income Before Extraordinary Loss
  $ 0.28     $ 0.68     $ 1.00     $ 1.55  
Extraordinary Loss, Net of Tax
    -       (0.01 )     -       (0.01 )
 
                               
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
  $ 0.28     $ 0.67     $ 1.00     $ 1.54  
 
                               
 
                               
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING
    479,176,543       472,222,817       479,012,304       439,983,030  
 
                               
DILUTED EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
                               
Income Before Extraordinary Loss
  $ 0.28     $ 0.68     $ 1.00     $ 1.55  
Extraordinary Loss, Net of Tax
    -       (0.01 )     -       (0.01 )
 
                               
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON
                               
SHAREHOLDERS
  $ 0.28     $ 0.67     $ 1.00     $ 1.54  
 
                               
CASH DIVIDENDS PAID PER SHARE
  $ 0.42     $ 0.41     $ 0.83     $ 0.82  
 
                               
See Condensed Notes to Condensed Consolidated Financial Statements.
                               

 
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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
 
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY AND
 
COMPREHENSIVE INCOME (LOSS)
 
For the Six Months Ended June 30, 2010 and 2009
 
(in millions)
 
(Unaudited)
 
 
 
 
 
AEP Common Shareholders
   
 
   
 
 
 
 
Common Stock
   
 
   
 
   
Accumulated
   
 
   
 
 
 
 
 
   
 
   
 
   
 
   
Other
   
 
   
 
 
 
 
 
   
 
   
Paid-in
   
Retained
   
Comprehensive
   
Noncontrolling
   
 
 
 
 
Shares
   
Amount
   
Capital
   
Earnings
   
Income (Loss)
   
Interests
   
Total
 
TOTAL EQUITY – DECEMBER 31, 2008
    426     $ 2,771     $ 4,527     $ 3,847     $ (452 )   $ 17     $ 10,710  
 
                                                       
Issuance of Common Stock
    71       460       1,278                               1,738  
Common Stock Dividends
                            (363 )             (3 )     (366 )
Preferred Stock Dividend Requirements of
                                                       
Subsidiaries
                            (1 )                     (1 )
Other Changes in Equity
                    (50 )                     1       (49 )
SUBTOTAL – EQUITY
                                                    12,032  
 
                                                       
COMPREHENSIVE INCOME
                                                       
Other Comprehensive Income (Loss), Net of
                                                       
Taxes:
                                                       
Cash Flow Hedges, Net of Tax of $9<