q110aep10q.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 March 31, 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 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
   
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
April 29, 2010
       
American Electric Power Company, Inc.
   
                            478,873,651
     
($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
March 31, 2010

Glossary of Terms
 
Forward-Looking Information
 
Part I. FINANCIAL INFORMATION
   
 
Items 1, 2 and 3 - Financial Statements, Management’s Financial Discussion and Analysis and Quantitative and Qualitative Disclosures About Risk Management Activities:
American Electric Power Company, Inc. and Subsidiary Companies:
 
Management’s Financial Discussion and Analysis of Results of Operations
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
Condensed Consolidated Financial Statements
 
Index to Condensed Notes to Condensed Consolidated Financial Statements
   
Appalachian Power Company and Subsidiaries:
 
Management’s Financial Discussion and Analysis
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
Condensed Consolidated Financial Statements
 
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
   
Columbus Southern Power Company and Subsidiaries:
 
Management’s Narrative Financial Discussion and Analysis
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
Condensed Consolidated Financial Statements
 
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
   
Indiana Michigan Power Company and Subsidiaries:
 
Management’s Narrative Financial Discussion and Analysis
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
Condensed Consolidated Financial Statements
 
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
   
Ohio Power Company Consolidated:
 
 
Management’s Financial Discussion and Analysis
 
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
 
Condensed Consolidated Financial Statements
 
 
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
     
Public Service Company of Oklahoma:
 
 
Management’s Narrative Financial Discussion and Analysis
 
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
 
Condensed Financial Statements
 
 
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
     
Southwestern Electric Power Company Consolidated:
 
 
Management’s Financial Discussion and Analysis
 
 
Quantitative and Qualitative Disclosures About Risk Management Activities
 
 
Condensed Consolidated Financial Statements
 
 
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
     
Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries
 
     
Combined Management’s Discussion and Analysis of Registrant Subsidiaries
 
     
Controls and Procedures
 
       
Part II.  OTHER INFORMATION
 
   
 
Item 1.
Legal Proceedings
 
 
Item 1A.
Risk Factors
 
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
 
 
Item 5.
Other Information
 
 
Item 6.
Exhibits:
 
         
Exhibit 10
 
         
Exhibit 12
 
         
Exhibit 31(a)
 
         
Exhibit 31(b)
 
         
Exhibit 32(a)
 
         
Exhibit 32(b)
 
             
SIGNATURE
   

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

 
 

 

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

Term
 
Meaning

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&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 distribution subsidiary.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
KPSC
 
Kentucky Public Service Commission.
kV
 
Kilovolt.
KWH
 
Kilowatthour.
LPSC
 
Louisiana Public Service Commission.
MISO
 
Midwest Independent Transmission System Operator.
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.
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 distribution subsidiary.
WVPSC
 
Public Service Commission of West Virginia.

 
 

 
FORWARD-LOOKING INFORMATION

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

·
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 and customer growth.
·
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 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.

 
 

 

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

EXECUTIVE OVERVIEW

Economic Conditions

In comparing first quarter 2010 results to the prior year, retail margins increased due to rate increases in various jurisdictions and higher residential demand for electricity as a result of favorable weather.  Additionally, margins from off-system sales increased in 2010 primarily due to higher physical sales in our eastern region reflecting favorable generation availability.  These margins were partially offset by lower commercial KWH sales due to continued weaknesses in the economy and lower industrial KWH sales due to reduced operations by several of our largest industrial customers.
 
Company-wide Staffing and Budget Review

Due to the continued slow recovery in the U.S. economy and a corresponding negative impact on energy consumption, we are currently conducting initiatives to achieve workforce reductions and significantly reduce other operation and maintenance spending.  Achieving these goals will involve identifying process improvements, streamlining organizational designs and developing other efficiencies that can deliver additional sustainable savings.

Regulatory Activity

Our significant 2010 rate proceedings include:

Kentucky – In December 2009, KPCo filed a base rate case with the KPSC to increase base revenues by $124 million annually based on an 11.75% return on common equity.  In April 2010, the Kentucky Industrial Utility Customers recommended an annual base revenue increase of no more than $41 million.  New rates are expected to become effective in July 2010.
 
Michigan – In January 2010, I&M filed for a $63 million increase in annual Michigan base rates based on an 11.75% return on common equity.  I&M can request interim rates, subject to refund, after six months.  The MPSC must issue a final order within one year.
 
Ohio – Ohio law requires the PUCO to determine, following the end of each year of the ESP, if rate adjustments included in the ESP resulted in significantly excessive earnings.  If the rate adjustments, in the aggregate, result in significantly excessive earnings, the excess amount would be returned to customers.  The PUCO’s decision determining a methodology is not expected to be finalized until a filing is made by CSPCo and OPCo in 2010 related to 2009 earnings and the PUCO issues an order thereon.  As a result, CSPCo and OPCo are unable to determine whether they will be required to return any of their Ohio revenues to customers.
 
Oklahoma – In 2009, the OCC approved PSO’s Capital Reliability Rider (CRR) filing which requires PSO to file a base rate case no later than July 2010.
 
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 2009, APCo filed a generation and distribution base rate increase with the Virginia SCC of $154 million annually based on a 13.35% return on common equity.  The Virginia SCC staff and intervenors have recommended revenue increases ranging from $33 million to $94 million.  Interim rates, subject to refund, became effective in December 2009 but were discontinued in February 2010 when Virginia newly enacted legislation suspended the collection of interim rates.  The Virginia SCC is required to issue a final order no later than July 2010 with new rates effective August 2010.
 
West Virginia – APCo provided notice to the WVPSC that it intends to file a base rate case during 2010.
 
2010 Health Care Legislation

The Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act (Health Care Acts) were enacted in March 2010.  The Health Care Acts amend tax rules so that the portion of employer health care costs that are reimbursed by the Medicare Part D prescription drug subsidy will no longer be deductible by the employer for federal income tax purposes effective for years beginning after December 31, 2012.  Because of the loss of the future tax deduction, a reduction in the deferred tax asset related to the nondeductible OPEB liabilities accrued to date was recorded in March 2010.  This reduction did not materially affect our cash flows or financial condition.  For the three months ended March 31, 2010, deferred tax assets decreased $56 million, partially offset by recording net tax regulatory assets of $35 million in our jurisdictions with regulated operations, resulting in a decrease in net income of $21 million.

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 annually 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.

The table below presents our consolidated Net Income by segment for the three months ended March 31, 2010 and 2009.
 
 
Three Months Ended March 31,
 
 
2010
 
2009
 
 
(in millions)
 
Utility Operations
  $ 344     $ 346  
AEP River Operations
    3       11  
Generation and Marketing
    10       24  
All Other (a)
    (11 )     (18 )
Net Income
  $ 346     $ 363  

(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.

AEP CONSOLIDATED

First Quarter of 2010 Compared to First Quarter of 2009

Net Income in 2010 decreased $17 million compared to 2009 primarily due to the impact of OPEB taxes recorded in the first quarter of 2010 related to the tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.

Average basic shares outstanding increased to 478 million in 2010 from 407 million in 2009 primarily due to the issuance of 69 million shares of AEP common stock in April 2009.  Actual shares outstanding were 479 million as of March 31, 2010.

Our results of operations are discussed below by operating segment.

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
 
   
March 31,
 
   
2010
   
2009
 
   
(in millions)
 
Revenues
  $ 3,426     $ 3,267  
Fuel and Purchased Power
    1,247       1,196  
Gross Margin
    2,179       2,071  
Depreciation and Amortization
    398       373  
Other Operating Expenses
    1,040       994  
Operating Income
    741       704  
Other Income, Net
    43       30  
Interest Expense
    235       220  
Income Tax Expense
    205       168  
                 
Net Income
  $ 344     $ 346  

Summary of KWH Energy Sales for Utility Operations
For the Three Months Ended March 31, 2010 and 2009

Energy/Delivery Summary
 
 
2010
   
2009
 
   
(in millions of KWH)
 
Retail:
           
Residential
    17,774       16,371  
Commercial
    11,475       11,610  
Industrial
    13,381       13,522  
Miscellaneous
    713       719  
Total Retail (a)
    43,343       42,222  
                 
Wholesale
    8,137       6,774  
                 
Total KWHs
    51,480       48,996  

(a)
Includes energy delivered to customers served by AEP’s Texas Wires Companies.

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 Months Ended March 31, 2010 and 2009

   
2010
   
2009
 
   
(in degree days)
 
Eastern Region
           
Actual – Heating (a)
    1,900       1,820  
Normal – Heating (b)
    1,741       1,791  
                 
Actual – Cooling (c)
    -       5  
Normal – Cooling (b)
    3       3  
                 
Western Region
               
Actual – Heating (a)
    759       513  
Normal – Heating (b)
    574       579  
                 
Actual – Cooling (d)
    20       99  
Normal – Cooling (b)
    58       56  

(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.

 
 

 
First Quarter of 2010 Compared to First Quarter of 2009

Reconciliation of First Quarter 2009 to First Quarter of 2010
Net Income from Utility Operations
(in millions)

First Quarter of 2009
        $ 346  
               
Changes in Gross Margin:
             
Retail Margins
    169          
Off-system Sales
    12          
Transmission Revenues
    10          
Other Revenues
    (83 )        
Total Change in Gross Margin
            108  
                 
Total Expenses and Other:
               
Other Operation and Maintenance
    (37 )        
Depreciation and Amortization
    (25 )        
Taxes Other Than Income Taxes
    (9 )        
Interest and Investment Income
    (3 )        
Carrying Costs Income
    5          
Allowance for Equity Funds Used During Construction
    8          
Interest Expense
    (15 )        
Equity Earnings of Unconsolidated Subsidiaries
    3          
Total Expenses and Other
            (73 )
                 
Income Tax Expense
            (37 )
                 
First Quarter of 2010
          $ 344  

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 $169 million primarily due to the following:
 
·
A $52 million increase related to an increase in interim rates in Virginia and the recovery of E&R costs in Virginia and construction financing costs in West Virginia, a $31 million increase related to the PUCO’s approval of our Ohio ESPs, a $12 million net rate increase for I&M, an $11 million increase in base rates in Oklahoma and $22 million of rate increases in our other jurisdictions.
 
·
A $38 million increase in weather-related usage primarily due to a 4% increase in heating degree days in our eastern region and a 48% increase in heating degree days in our western 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 shutdown.  This increase in fuel margins was offset by a corresponding decrease in Other Revenues as discussed below.
 
·
These increases were offset by a $37 million decrease in non-weather usage due to reduced operations by several significant industrial customers, reduced usage by commercial customers due to difficult economic conditions and the termination of an I&M unit power agreement.
·
Margins from Off-system Sales increased $12 million primarily due to higher physical sales volumes in our eastern region reflecting favorable generation availability.
·
Transmission Revenues increased $10 million primarily due to increased revenues in the ERCOT, PJM and SPP regions.
·
Other Revenues decreased $83 million primarily due to the Cook Plant accidental outage insurance proceeds of $54 million in the first quarter of 2009.  I&M reduced customer bills by approximately $20 million in the first quarter of 2009 for the cost of replacement power during the outage period.  This decrease in revenues 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 $19 million.

Total Expenses and Other and Income Tax Expense changed between years as follows:

·
Other Operation and Maintenance expenses increased $37 million primarily due to the following:
 
·
A $26 million increase in demand side management, energy efficiency and vegetation management programs.
 
·
A $23 million increase in transmission expenses, including base transmission work, RTO fees and transmission service expenses.
 
·
A $19 million increase in system improvements, reliability and other distribution expenses.
 
·
A $14 million increase in administrative and general expenses primarily for employee benefits.
 
·
A $5 million increase in plant outage and other plant operating and maintenance expenses.
 
These increases were partially offset by:
 
·
A $35 million decrease in storm expenses.
 
·
A $15 million decrease in low income assistance programs and other customer accounts expense.
·
Depreciation and Amortization increased $25 million primarily due to new environmental improvements placed in service and other increases in depreciable property balances.
·
Taxes Other Than Income Taxes increased $9 million primarily due to increases in property and other taxes.
·
Allowance for Equity Funds Used During Construction increased $8 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 $15 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 increased $37 million primarily due to the increase in pretax book income, the regulatory accounting treatment of state income taxes and the tax treatment associated with the future reimbursement of Medicare Part D prescription drug benefits.

AEP RIVER OPERATIONS

First Quarter of 2010 Compared to First Quarter of 2009

Net Income from our AEP River Operations segment decreased from $11 million in 2009 to $3 million in 2010 primarily due to reduced grain loadings, higher fuel and other operating expenses and the recording of a gain on the sale of two older towboats in 2009.

GENERATION AND MARKETING

First Quarter of 2010 Compared to First Quarter of 2009

Net Income from our Generation and Marketing segment decreased from $24 million in 2009 to $10 million in 2010 primarily due to reduced inception gains from ERCOT marketing activities partially offset by improved plant performance and hedging activities on our generation assets.

ALL OTHER

First Quarter of 2010 Compared to First Quarter of 2009

Net Loss from All Other decreased from a loss of $18 million in 2009 to a loss of $11 million in 2010 due to lower Parent related expenses.

AEP SYSTEM INCOME TAXES

First Quarter of 2010 Compared to First Quarter of 2009

Income Tax Expense increased $28 million in the first quarter of 2010 primarily due to 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.  During the first quarter of 2010, we maintained our strong financial condition as reflected by our long-term debt issuances of $658 million primarily to fund our construction program and refinance debt maturities.

DEBT AND EQUITY CAPITALIZATION
   
March 31, 2010
 
December 31, 2009
   
($ in millions)
Long-term Debt, including amounts due within one year
 
$
17,534 
 
54.8%
 
$
17,498 
 
56.8%
Short-term Debt
   
1,063 
 
3.3   
   
126 
 
0.4   
Total Debt
   
18,597 
 
58.1   
   
17,624 
 
57.2   
Preferred Stock of Subsidiaries
   
61 
 
0.2   
   
61 
 
0.2   
AEP Common Equity
   
13,324 
 
41.7   
   
13,140 
 
42.6   
                     
Total Debt and Equity Capitalization
 
$
31,982 
 
100.0%
 
$
30,825 
 
100.0%

Our ratio of debt to total capital increased from 57.2% to 58.1% in the first quarter of 2010 primarily due to an increase in short-term debt of $651 million as a result of a change in an accounting standard applicable to our sale of receivables agreement and an increase of $280 million in commercial paper outstanding.

Approximately $1.1 billion of our $18 billion of outstanding long-term debt will mature during the remaining three quarters of 2010, excluding payments due for securitization bonds which we recover directly from ratepayers.  In 2009, OPCo issued $500 million of 5.375% senior unsecured notes which we used in April 2010 to pay $400 million of OPCo’s senior unsecured notes at maturity.  We issued $658 million of long-term debt during the first quarter of 2010.  We believe that our projected cash flows from operating activities are sufficient to support our ongoing operations.

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 March 31, 2010, we had $3.6 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 March 31, 2010, our available liquidity was approximately $3.3 billion as illustrated in the table below:

   
Amount
 
Maturity
   
(in millions)
   
Commercial Paper Backup:
       
Revolving Credit Facility
  $ 1,500  
March 2011
Revolving Credit Facility
    1,454  
April 2012
Revolving Credit Facility
    627  
April 2011
Total
    3,581    
Cash and Cash Equivalents
    818    
Total Liquidity Sources
    4,399    
Less:  AEP Commercial Paper Outstanding
    399    
          Letters of Credit Issued
    652    
           
Net Available Liquidity
  $ 3,348    

We have credit facilities totaling $3.6 billion, of which two $1.5 billion credit facilities support our commercial paper program.  The two $1.5 billion credit facilities allow for the issuance of up to $750 million as letters of credit under each credit facility.  We also have a $627 million credit facility which can be utilized for letters of credit or draws.

It is our intent to renew the March 2011 facility.  We are currently reviewing our options related to the April 2011 facility.

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 the first quarter of 2010 was $429 million.  The weighted-average interest rate for our commercial paper during 2010 was 0.32%.

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 March 31, 2010, this contractually-defined percentage was 54.5%.  Nonperformance of these covenants could result in an event of default under these credit agreements.  At March 31, 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 any facility if a material adverse change occurs.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders.  At March 31, 2010, we had not exceeded those authorized limits.

Dividend Policy and Restrictions

We have declared common stock dividends payable in cash in each quarter since July 1910, representing 400 consecutive quarters.  The Board of Directors declared a quarterly dividend of $0.42 per share in April 2010.  Future dividends may vary depending upon our profit levels, operating cash flows and capital requirements, as well as financial and other business conditions existing at the time.  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, financial condition or limit any dividend payments in the foreseeable future.

Credit Ratings

Our credit ratings as of March 31, 2010 were as follows:

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

In 2010, Moody’s:

·
Changed its rating outlook for AEP to stable from negative.

In 2010, Fitch:

·
Changed its rating outlook for TCC to stable from negative.

Downgrades in our credit ratings by one of the rating agencies listed above could increase our borrowing costs.

CASH FLOW

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

 
Three Months Ended
 
 
March 31,
 
 
2010
 
2009
 
 
(in millions)
 
Cash and Cash Equivalents at Beginning of Period
  $ 490     $ 411  
Net Cash Flows from Operating Activities
    2       317  
Net Cash Flows Used for Investing Activities
    (430 )     (727 )
Net Cash Flows from Financing Activities
    756       709  
Net Increase in Cash and Cash Equivalents
    328       299  
Cash and Cash Equivalents at End of Period
  $ 818     $ 710  

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

Operating Activities
 
Three Months Ended
 
 
March 31,
 
 
2010
 
2009
 
 
(in millions)
 
Net Income
  $ 346     $ 363  
Depreciation and Amortization
    408       382  
Other
    (752 )     (428 )
Net Cash Flows from Operating Activities
  $ 2     $ 317  

Net Cash Flows from Operating Activities were $2 million in 2010 consisting primarily of Net Income of $346 million, $408 million of noncash Depreciation and Amortization offset by $752 million in Other.  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 in Ohio and West Virginia and the favorable impact of decreases in fuel inventory and tax receivables.  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 $317 million in 2009 consisting primarily of Net Income of $363 million and $382 million of noncash Depreciation and Amortization.  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 the negative impact on cash of an increase in coal inventory reflecting decreased customer demand for electricity and an increase in under-recovered fuel primarily in Ohio and West Virginia.

Investing Activities
 
Three Months Ended
 
 
March 31,
 
 
2010
 
2009
 
 
(in millions)
 
Construction Expenditures
  $ (609 )   $ (897 )
Proceeds from Sales of Assets
    139       172  
Other
    40       (2 )
Net Cash Flows Used for Investing Activities
  $ (430 )   $ (727 )

Net Cash Flows Used for Investing Activities were $430 million in 2010 primarily due to Construction Expenditures for new generation investment, environmental and distribution.  Proceeds from Sales of Assets in 2010 includes $135 million for sales of Texas transmission assets to ETT.

Net Cash Flows Used for Investing Activities were $727 million in 2009 primarily due to Construction Expenditures for our new generation, environmental and distribution investment plan.  Proceeds from Sales of Assets in 2009 includes $104 million relating to the sale of a portion of Turk Plant to joint owners as planned.

Financing Activities
 
Three Months Ended
 
 
March 31,
 
 
2010
 
2009
 
 
(in millions)
 
Issuance of Common Stock, Net
  $ 26     $ 48  
Issuance/Retirement of Debt, Net
    952       854  
Dividends Paid on Common Stock
    (197 )     (169 )
Other
    (25 )     (24 )
Net Cash Flows from Financing Activities
  $ 756     $ 709  

Net Cash Flows from Financing Activities were $756 million in 2010.  Our net debt issuances were $296 million. The net issuances included issuances of $500 million of senior unsecured notes and $158 million of pollution control bonds, a $280 million increase in commercial paper outstanding and retirements of $490 million of senior unsecured notes, $86 million of securitization bonds and $54 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 $197 million.

Net Cash Flows from Financing Activities in 2009 were $709 million.  Our net debt issuances were $854 million. The net issuances included issuances of $825 million of senior unsecured notes and $134 million of pollution control bonds and retirements of $84 million of securitization bonds.  We paid common stock dividends of $169 million.

The following financing activities occurred or are expected to occur during 2010:

·
In April 2010, OPCo retired $400 million of its outstanding Senior Unsecured Notes.
·
We will refinance an additional $700 million of the remaining long-term debt that will mature in 2010.

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:
 
March 31,
2010
 
December 31,
2009
 
 
(in millions)
AEP Credit Accounts Receivable Purchase Commitments
  $ -     $ 631  
Rockport Plant Unit 2 Future Minimum Lease Payments
    1,920       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.

SIGNIFICANT FACTORS

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.  In addition, an order is expected from the PUCO related to the SEET methodology.  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.  The Texas District Court and the Texas Court of Appeals recommended the PUCT decision be modified on various issues which could have a favorable or unfavorable impact on TCC. After a ruling 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 a 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, APCo requested recovery of and a return on its estimated increased Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion.  The Virginia Attorney General and the Virginia SCC staff have recommended in the pending Virginia base rate case that no recovery be allowed for the project.  APCo plans to seek recovery of the West Virginia jurisdictional costs in its next West Virginia base rate filing which is expected to be filed in the second quarter of 2010.  If APCo cannot recover all of its 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, with SWEPCo’s share estimated to cost $1.3 billion, excluding AFUDC.  Notices of appeal are outstanding at the Arkansas Supreme Court and the Circuit Court of Hempstead County, Arkansas.  Complaints 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.

Company-wide Staffing and Budget Review

In April 2010, we began initiatives to decrease both labor and non-labor expenditures with a goal of achieving significant reductions in operation and maintenance expenses.  One initiative is to offer a one-time voluntary severance program.  Participating employees will receive two weeks of base pay for every year of service.  It is anticipated that more than 2,000 employees will accept voluntary severances and terminate employment no later than May 2010.  The second simultaneous initiative will involve all business units and departments to identify process improvements, streamlined organizational designs and other efficiencies that can deliver additional lasting savings.  There is the potential that actions taken as a result of this effort could lead to some involuntary separations.  Affected employees would receive the same severance package as those who volunteered.

We expect to record a charge to expense in the second quarter of 2010 related to these initiatives.   At this time, we are unable to predict the impact of these initiatives on net income, cash flows and financial condition.

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.  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 and 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 environmental control requirements.  The most significant source is the CAA’s requirements to reduce emissions of SO2, NOx and PM from fossil fuel-fired power plants.

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.

Global Warming

While comprehensive economy-wide regulation of CO2 emissions might be achieved through new 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 approved in April 2010 for new motor vehicles are awaiting publication.  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 is expected to finalize 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 in 2010.  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.  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.

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 of our states have passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements (including Ohio, Michigan, Texas and Virginia).  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 the First Quarter of 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.

 
 

 
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.

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)
Three Months Ended March 31, 2010
(in millions)
 
 
Utility Operations
 
Generation
and
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
 
(24)
   
(6)
   
   
(28)
Fair Value of New Contracts at Inception When Entered During the Period (a)
 
   
   
   
13 
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)
 
   
   
   
14 
Changes in Fair Value Allocated to Regulated Jurisdictions (d)
 
25 
   
   
   
25 
Total MTM Risk Management Contract Net Assets (Liabilities) at March 31, 2010
$
147 
 
$
152
 
$
(1)
   
298 
Cash Flow Hedge Contracts
                   
(4)
Collateral Deposits
                   
134 
Total MTM Derivative Contract Net Assets at March 31, 2010
                 
$
428 

(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.

Credit Risk

We limit credit risk in our wholesale marketing and trading activities by assessing creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness 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 March 31, 2010, our credit exposure net of collateral to sub investment grade counterparties was approximately 9.4%, 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 March 31, 2010, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:

Counterparty Credit Quality
 
Exposure Before Credit Collateral
   
Credit Collateral
   
Net Exposure
   
Number of Counterparties >10% of
Net Exposure
   
Net Exposure
of Counterparties >10%
 
   
(in millions, except number of counterparties)
 
Investment Grade
  $ 858     $ 76     $ 782       2     $ 227  
Split Rating
    5       -       5       1       5  
Noninvestment Grade
    1       -       1       2       1  
No External Ratings:
                                       
Internal Investment Grade
    127       1       126       3       77  
Internal Noninvestment Grade
    105       12       93       3       78  
Total as of March 31, 2010
  $ 1,096     $ 89     $ 1,007       11     $ 388  
                                         
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 March 31, 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

Three Months Ended
       
Twelve Months Ended
March 31, 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.

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 for both March 31, 2010 and December 31, 2009, the estimated EaR on our debt portfolio for the following twelve months was $4 million.
 
 

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three Months Ended March 31, 2010 and 2009
(in millions, except per-share and share amounts)
(Unaudited)

REVENUES
 
2010
   
2009
 
Utility Operations
  $ 3,406     $ 3,267  
Other Revenues
    163       191  
TOTAL REVENUES
    3,569       3,458  
EXPENSES
               
Fuel and Other Consumables Used for Electric Generation
    1,014       929  
Purchased Electricity for Resale
    238       295  
Other Operation
    673       610  
Maintenance
    271       295  
Depreciation and Amortization
    408       382  
Taxes Other Than Income Taxes
    207       197  
TOTAL EXPENSES
    2,811       2,708  
                 
OPERATING INCOME
    758       750  
                 
Other Income (Expense):
               
Interest and Investment Income
    3       5  
Carrying Costs Income
    14       9  
Allowance for Equity Funds Used During Construction
    24       16  
Interest Expense
    (250 )     (238 )
                 
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS
    549       542  
                 
Income Tax Expense
    207       179  
Equity Earnings of Unconsolidated Subsidiaries
    4       -  
                 
NET INCOME
    346       363  
                 
Less:  Net Income Attributable to Noncontrolling Interests
    1       2  
                 
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS
    345       361  
                 
Less: Preferred Stock Dividend Requirements of Subsidiaries
    1       1  
                 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
  $ 344     $ 360  
                 
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING
    478,429,535       406,826,606  
                 
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
  $ 0.72     $ 0.89  
                 
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING
    478,844,632       407,381,954  
                 
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
  $ 0.72     $ 0.89  
                 
CASH DIVIDENDS PAID PER SHARE
  $ 0.41     $ 0.41  

See Condensed Notes to Condensed Consolidated Financial Statements.

 
 

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY AND
COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 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
 
   
11 
   
37 
                     
48 
Common Stock Dividends
                   
(167)
         
(2)
   
(169)
Preferred Stock Dividend Requirements of Subsidiaries
                   
(1)
               
(1)
Other Changes in Equity
                               
   
SUBTOTAL – EQUITY
                                     
10,589 
                                         
COMPREHENSIVE INCOME
                                       
Other Comprehensive Income (Loss), Net of Taxes:
                                       
Cash Flow Hedges, Net of Tax of $1
                         
         
Securities Available for Sale, Net of Tax of $1
                         
(2)
         
(2)
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $3
                         
         
NET INCOME
                   
361 
         
   
363 
TOTAL COMPREHENSIVE INCOME
                                     
369 
                                         
TOTAL EQUITY – MARCH 31, 2009
 
428 
 
$
2,782 
 
$
4,564 
 
$
4,040 
 
$
(446)
 
$
18 
 
$
10,958 
                                         
TOTAL EQUITY – DECEMBER 31, 2009
 
498 
 
$
3,239 
 
$
5,824 
 
$
4,451 
 
$
(374)
 
$
 
$
13,140 
                                         
Issuance of Common Stock
 
   
   
21
                     
26 
Common Stock Dividends
                   
(196)
         
(1)
   
(197)
Preferred Stock Dividend Requirements of Subsidiaries
                   
(1)
               
(1)
Other Changes in Equity
             
   
(2)
               
SUBTOTAL – EQUITY
                                     
12,968 
                                         
COMPREHENSIVE INCOME
                                       
Other Comprehensive Income, Net of Taxes:
                                       
Cash Flow Hedges, Net of Tax of $2
                         
         
Securities Available for Sale, Net of Tax of $-
                         
         
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $3
                         
         
NET INCOME
                   
345 
         
   
346 
TOTAL COMPREHENSIVE INCOME
                                     
356 
                                         
TOTAL EQUITY – MARCH 31, 2010
 
499 
 
$
3,244 
 
$
5,847 
 
$
4,597 
 
$
(364)
 
$
 
$
13,324 

See Condensed Notes to Condensed Consolidated Financial Statements.


 
 

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2010 and December 31, 2009
(in millions)
(Unaudited)

   
2010
   
2009
 
CURRENT ASSETS
           
Cash and Cash Equivalents
  $ 818     $ 490  
Other Temporary Investments
    238       363  
Accounts Receivable:
               
Customers
    613       492  
Accrued Unbilled Revenues
    116       503  
Pledged Accounts Receivable – AEP Credit
    867       -  
Miscellaneous
    98       92  
Allowance for Uncollectible Accounts
    (38 )     (37 )
Total Accounts Receivable
    1,656       1,050  
Fuel
    984       1,075  
Materials and Supplies
    582       586  
Risk Management Assets
    323       260  
Accrued Tax Benefits
    460       547  
Regulatory Asset for Under-Recovered Fuel Costs
    107       85  
Margin Deposits
    109       89  
Prepayments and Other Current Assets
    239       211  
TOTAL CURRENT ASSETS
    5,516       4,756  
                 
PROPERTY, PLANT AND EQUIPMENT
               
Electric:
               
Production
    23,417       23,045  
Transmission
    8,313       8,315  
Distribution
    13,685       13,549  
Other Property, Plant and Equipment (including coal mining and nuclear fuel)
    3,833       3,744  
Construction Work in Progress
    2,765       3,031  
Total Property, Plant and Equipment
    52,013       51,684  
Accumulated Depreciation and Amortization
    17,487       17,340  
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET
    34,526       34,344  
                 
OTHER NONCURRENT ASSETS
               
Regulatory Assets
    4,683       4,595  
Securitized Transition Assets
    1,865       1,896  
Spent Nuclear Fuel and Decommissioning Trusts
    1,433       1,392  
Goodwill
    76       76  
Long-term Risk Management Assets
    449       343  
Deferred Charges and Other Noncurrent Assets
    1,077       946  
TOTAL OTHER NONCURRENT ASSETS
    9,583       9,248  
                 
TOTAL ASSETS
  $ 49,625     $ 48,348  

See Condensed Notes to Condensed Consolidated Financial Statements.
 
 
 

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
March 31, 2010 and December 31, 2009
(Unaudited)

   
2010
 
2009
CURRENT LIABILITIES
 
(in millions)
Accounts Payable
 
$
954 
 
$
1,158 
Short-term Debt:
           
General
   
412 
   
126 
Securitized Debt for Receivables – AEP Credit
   
651 
   
Total Short-term Debt
   
1,063 
   
126 
Long-term Debt Due Within One Year
   
1,253 
   
1,741 
Risk Management Liabilities
   
151 
   
120 
Customer Deposits
   
261 
   
256 
Accrued Taxes
   
621 
   
632 
Accrued Interest
   
254 
   
287 
Regulatory Liability for Over-Recovered Fuel Costs
   
38 
   
76 
Other Current Liabilities
   
920 
   
931 
TOTAL CURRENT LIABILITIES
   
5,515 
   
5,327 
             
NONCURRENT LIABILITIES
           
Long-term Debt
   
16,281 
   
15,757 
Long-term Risk Management Liabilities
   
193 
   
128 
Deferred Income Taxes
   
6,587 
   
6,420 
Regulatory Liabilities and Deferred Investment Tax Credits
   
3,005 
   
2,909 
Asset Retirement Obligations
   
1,264 
   
1,254 
Employee Benefits and Pension Obligations
   
2,153 
   
2,189 
Deferred Credits and Other Noncurrent Liabilities
   
1,242 
   
1,163 
TOTAL NONCURRENT LIABILITIES
   
30,725 
   
29,820 
             
TOTAL LIABILITIES
   
36,240 
   
35,147 
             
Cumulative Preferred Stock Not Subject to Mandatory Redemption
   
61 
   
61 
             
Rate Matters (Note 3)
           
Commitments and Contingencies (Note 4)
           
             
EQUITY
           
Common Stock – Par Value – $6.50 Per Share:
           
 
2010
 
2009
             
Shares Authorized
600,000,000
 
600,000,000
             
Shares Issued
499,133,697
 
498,333,265
             
(20,278,858 shares were held in treasury at March 31, 2010 and December 31, 2009)
   
3,244 
   
3,239 
Paid-in Capital
   
5,847 
   
5,824 
Retained Earnings
   
4,597 
   
4,451 
Accumulated Other Comprehensive Income (Loss)
   
(364)
   
(374)
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY
   
13,324 
   
13,140 
             
Noncontrolling Interests
   
   
             
TOTAL EQUITY
   
13,324 
   
13,140 
             
TOTAL LIABILITIES AND EQUITY
 
$
49,625 
 
$
48,348 

See Condensed Notes to Condensed Consolidated Financial Statements.

 
 

 
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2010 and 2009
(in millions)
(Unaudited)
   
2010
   
2009
 
OPERATING ACTIVITIES
           
Net Income
  $ 346     $ 363  
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
               
Depreciation and Amortization
    408       382  
Deferred Income Taxes
    121       217  
Carrying Costs Income
    (14 )     (9 )
Allowance for Equity Funds Used During Construction
    (24 )     (16 )
Mark-to-Market of Risk Management Contracts
    (69 )     (46 )
Amortization of Nuclear Fuel
    30       13  
Property Taxes
    (53 )     (64 )
Fuel Over/Under-Recovery, Net
    (97 )     (95 )
Change in Other Noncurrent Assets
    (28 )     23  
Change in Other Noncurrent Liabilities
    37       18  
Changes in Certain Components of Working Capital:
               
Accounts Receivable, Net
    (617 )     102  
Fuel, Materials and Supplies
    83       (118 )
Margin Deposits
    (20 )     (39 )
Accounts Payable
    (83 )     3  
Customer Deposits
    5       12  
Accrued Taxes, Net
    80       (57 )
Accrued Interest
    (34 )     (44 )
Other Current Assets
    (14 )     (7 )
Other Current Liabilities
    (55 )     (321 )
Net Cash Flows from Operating Activities
    2       317  
                 
INVESTING ACTIVITIES
               
Construction Expenditures
    (609 )     (897 )
Change in Other Temporary Investments, Net
    82       111  
Purchases of Investment Securities
    (445 )     (179 )
Sales of Investment Securities
    473       158  
Acquisitions of Nuclear Fuel
    (38 )     (76 )
Proceeds from Sales of Assets
    139       172  
Other Investing Activities
    (32 )     (16 )
Net Cash Flows Used for Investing Activities
    (430 )     (727 )
                 
FINANCING ACTIVITIES
               
Issuance of Common Stock
    26       48  
Issuance of Long-term Debt
    652       947  
Borrowings from Revolving Credit Facilities
    24       28  
Change in Short-term Debt, Net
    931       -  
Retirement of Long-term Debt
    (638 )     (93 )
Repayments to Revolving Credit Facilities
    (17 )     (28 )
Principal Payments for Capital Lease Obligations
    (24 )     (23 )
Dividends Paid on Common Stock
    (197 )     (169 )
Dividends Paid on Cumulative Preferred Stock
    (1 )     (1 )
Net Cash Flows from Financing Activities
    756       709  
                 
Net Increase in Cash and Cash Equivalents
    328       299  
Cash and Cash Equivalents at Beginning of Period
    490       411  
Cash and Cash Equivalents at End of Period
  $ 818     $ 710  
                 
SUPPLEMENTARY INFORMATION
               
Cash Paid for Interest, Net of Capitalized Amounts
  $ 271     $ 314  
Net Cash Paid (Received) for Income Taxes
    (2 )     2  
Noncash Acquisitions under Capital Leases
    148       6  
Construction Expenditures Included in Accounts Payable at March 31,
    216       294  
Acquisition of Nuclear Fuel Included in Accounts Payable at March 31,
    3       17  
                 
See Condensed Notes to Condensed Consolidated Financial Statements.
               

 
 

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

 1.
Significant Accounting Matters
 2.
New Accounting Pronouncements
 3.
Rate Matters
 4.
Commitments, Guarantees and Contingencies
 5.
Acquisitions and Dispositions
 6.
Benefit Plans
 7.
Business Segments
 8.
Derivatives and Hedging
 9.
Fair Value Measurements
10.
Income Taxes
11.
Financing Activities
12.
Company-wide Staffing and Budget Review

 
 

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 
1.
SIGNIFICANT ACCOUNTING MATTERS

General

The unaudited condensed consolidated financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC.  Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our net income, financial position and cash flows for the interim periods.  Net income for the three months ended March 31, 2010 is not necessarily indicative of results that may be expected for the year ending December 31, 2010.  The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2009 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 26, 2010.

Variable Interest Entities

The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE.  A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.  Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.”  In determining whether we are the primary beneficiary of a VIE, we consider factors such as equity at risk, the amount of the VIE’s variability we absorb, guarantees of indebtedness, voting rights including kick-out rights, power to direct the VIE and other factors.  We believe that significant assumptions and judgments were applied consistently.  Also, see “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.

We are currently the primary beneficiary of Sabine, DCC Fuel LLC (DCC Fuel), AEP Credit and a protected cell of EIS.  As of January 1, 2010, we are no longer the primary beneficiary of DHLC as defined by new accounting guidance for “Variable Interest Entities.”  In addition, we have not provided material financial or other support to Sabine, DCC Fuel, our protected cell of EIS and AEP Credit that was not previously contractually required.  We hold a significant variable interest in Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series) and DHLC.

Sabine is a mining operator providing mining services to SWEPCo.  SWEPCo has no equity investment in Sabine but is Sabine’s only customer.  SWEPCo guarantees the debt obligations and lease obligations of Sabine.  Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo.  The creditors of Sabine have no recourse to any AEP entity other than SWEPCo.  Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee.  In addition, SWEPCo determines how much coal will be mined for each year.  Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine.  SWEPCo’s total billings from Sabine for the three months ended March 31, 2010 and 2009 were $43 million and $35 million, respectively.  See the tables below for the classification of Sabine’s assets and liabilities on our Condensed Consolidated Balance Sheets.

EIS has multiple protected cells.  Our subsidiaries participate in one protected cell for approximately ten lines of insurance.  Neither AEP nor its subsidiaries have an equity investment of EIS.  The AEP system is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance.  Our subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims.  Based on our control and the structure of the protected cell and EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate its assets and liabilities.  Our insurance premium payments to the protected cell for the three months ended March 31, 2010 and 2009 were $18 million and $17 million, respectively.  See the tables below for the classification of the protected cell’s assets and liabilities on our Condensed Consolidated Balance Sheets.  The amount reported as equity is the protected cell’s policy holders’ surplus.

In September 2009, I&M entered into a nuclear fuel sale and leaseback transaction with DCC Fuel.  DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.  DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions.  DCC Fuel is a single-lessee leasing arrangement with only one asset and is capitalized with all debt.  Payments on the lease will be made semi-annually on April 1 and October 1, beginning in April 2010.  The lease was recorded as a capital lease on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the 48 month lease term.  Based on our control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel.  The capital lease is eliminated upon consolidation.  See the tables below for the classification of DCC Fuel’s assets and liabilities on our Condensed Consolidated Balance Sheets.

AEP Credit is a wholly-owned subsidiary of AEP.  AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements.  AEP provides up to 20% of AEP Credit short-term borrowing needs in excess of third party financings.  Any third party financing of AEP Credit only has recourse to the receivables sold for such financing.  Based on our control of AEP Credit, management has concluded that we are the primary beneficiary and are required to consolidate its assets and liabilities.  See the tables below for the classification of AEP Credit’s assets and liabilities on our Condensed Consolidated Balance Sheets.  See “ASU 2009-17 ‘Consolidation’ ” section of Note 2 for discussion of impact of new accounting guidance effective January 1, 2010.  Also see “Sale of Receivables – AEP Credit” section of Note 14 in the 2009 Annual Report for further information.

DHLC is a wholly-owned subsidiary of SWEPCo.  DHLC is a mining operator that sells 50% of the lignite produced to SWEPCo and 50% to CLECO.  SWEPCo and CLECO share the executive board seats and its voting rights equally.  Each entity guarantees a 50% share of DHLC’s debt.  SWEPCo and CLECO equally approve DHLC’s annual budget.  The creditors of DHLC have no recourse to any AEP entity other than SWEPCo.  As SWEPCo is the sole equity owner of DHLC it receives 100% of the management fee.  Based on the shared control of DHLC’s operations, management concluded as of January 1, 2010 that SWEPCo is no longer the primary beneficiary and is no longer required to consolidate DHLC.  SWEPCo’s total billings from DHLC for the three months ended March 31, 2010 and March 31, 2009 were $13 million and $11 million, respectively.  See the tables below for the classification of DHLC assets and liabilities on our Condensed Consolidated Balance Sheet at December 31, 2009 as well as our investment and maximum exposure as of March 31, 2010.  As of March 31, 2010, DHLC is reported as an equity investment in Deferred Charges and Other Noncurrent Assets on our Condensed Consolidated Balance Sheet.  Also, see “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for discussion of impact of new accounting guidance effective January 1, 2010.

The balances below represent the assets and liabilities of the VIEs that are consolidated.  These balances include intercompany transactions that are eliminated upon consolidation.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
March 31, 2010
(in millions)

   
SWEPCo
Sabine
   
I&M
DCC Fuel
   
Protected Cell
of EIS
   
AEP Credit
 
ASSETS
                       
Current Assets
  $ 51     $ 56     $ 145     $ 844  
Net Property, Plant and Equipment
    146       77       -       -  
Other Noncurrent Assets
    34       49       2       8  
Total Assets
  $ 231     $ 182     $ 147     $ 852  
                                 
LIABILITIES AND EQUITY
                               
Current Liabilities
  $ 35     $ 41     $ 42     $ 808  
Noncurrent Liabilities
    196       141       82       -  
Equity
    -       -       23       44  
Total Liabilities and Equity
  $ 231     $ 182     $ 147     $ 852  


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2009
(in millions)

   
SWEPCo
Sabine
   
SWEPCo